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Home My WebLink About208-116(aG( 314f—)O3Q Regg, James B (CED) From: CPF3 Prod Engrs <nl223@conocophillips.com> Sent: Tuesday, September 10, 2019 8:31 PM To: Regg, James B (CED) q/1/ C Cc: NSK Prod Engr Specialist; Valentine, Doug K Subject: 3K-1031-1 Defeated LPP/SSV -- (PTD# 208 -116) ---Returned To Service Mr Regg, The low pressure pilot (LPP) on injection well 3K-1031-1 (PTD# 208-116) was returned to service at approximately 1600 hrs on Tuesday September 10, 2019. At that point we had increased the injection rate to 600 BWPD and the injection pressure was about 300 psig and started rising. Thanks, Kenneth Lloyd Martin/Kaelin Ellis PERA/CPF3 Production Engineers Ph: (907) 659-7871 From: CPF3 Prod Engrs Sent: Sunday, September 08, 2019 5:12 PM To: jim.regg@alaska.gov Cc: NSK Prod Engr Specialist <n1139@conocophillips.com>; Valentine, Doug K <Doug.K.Valentine@conocophillips.com> Subject: 3K -103L1 Defeated LPP/SSV -- (PTD# 208-116) per CO 4066.001 Mr. Regg, (first of four e-mails for the four wells we brought on today) The low pressure pilot (LPP) on injection well 3K -103L1 (PTD# 208-116) is defeated today, Sunday September 8, 2019. 3K -103L1 had been shut in since July 4, 2019 due to the CPF3 Seawater Tank preventing SW injection. We are ramping up injection slowly to the West Sak injectors at DS 3K. 3K -103L1 is currently at wellhead injection pressure of 225 prig and injection rate of approximately 250 bbls of water per day. The LPP and surface safety valves (SSV) have been tagged and their status is recorded in the "Facility Defeated Safety Device Log" where it is referred to as 3K -103B. The AOGCC will be notified when the injection pressure has increased to above 250 psi and is stable, and the LPP/SSV function is returned to normal operation, in accordance with "Administrative Approval No. CO 4066.001". Please let me know if you have any concerns or questions, Thanks, �(u1 3t<-1�3L1 C`�ij Z�;{311b� Regg, James B (CED) From: CPF3 Prod Engrs <nl223@conocophillips.com> Sent: Sunday, September 8, 2019 5:12 PM �Q�C �Ic�/(� To: Regg, James B (CED) t� 7 Cc: NSK Prod Engr Specialist; Valentine, Doug K Subject: 3K-1031-1 Defeated LPP/SSV -- (PTD# 208-116) per CO 4066.001 Mr. Regg, (first of four e-mails for the four wells we brought on today) The low pressure pilot (LPP) on injection well 3K-1031-1 (PTD# 208-116) is defeated today, Sunday September 8, 2019. 3K-1031-1 had been shut in since July 4, 2019 due to the CPF3 Seawater Tank preventing SW injection. We are ramping up injection slowly to the West Sak injectors at DS 3K. 3K-1031-1 is currently at wellhead injection pressure of 225 psig and injection rate of approximately 250 bbls of water per day. The LPP and surface safety valves (SSV) have been tagged and their status is recorded in the "Facility Defeated Safety Device Log" where it is referred to as 3K -303B. The AOGCC will be notified when the injection pressure has increased to above 250 psi and is stable, and the LPP/SSV function is returned to normal operation, in accordance with "Administrative Approval No. CO 4066.001". Please let me know if you have any concerns or questions, Thanks, Kenneth Lloyd Martin/Kaelin Ellis PERA/CPF3 Production Engineers Ph: (907) 659-7871 Pager: (907) 659-7000 pp# 328 1<2cc 3K- Iu5L I Regg, James B (CED) From: CPF3 Prod Engrs <n1223@conocophillips.com> Sent: Tuesday, June 4, 2019 11:22 AM 6141 t 1 To: Regg, James B (CED) Subject: RE: [EXTERNAL]RE: Defeated LPP/SSV on well 3K -103L1 Mr. Regg, 3K-103 and 3K-1031-1 have separate low pressure pilots. Ethan Plunkett / Kenneth Lloyd Martin CPF3 Production Engineer lOffice x7871 I Cell (918) 812-2294 1 Pager x328 I Radio 343 From: Regg, lames B (CED) <jim.regg@alaska.gov> Sent: Tuesday, June 4, 2019 10:56 AM To: CPF3 Prod Engrs <n1223@conocophillips.com> Subject: [EXTERNAL]RE: Defeated LPP/SSV on well 3K-1031-1 Do 3K-103 and 3K -103L1 have separate pilots? Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.re¢¢@alaska.zov. From: CPF3 Prod Engrs <n1223@conocophillips.com> Sent: Friday, May 31, 2019 4:23 PM To: Regg, James B (CED) <iim.regg@alaska.eov> Cc: NSK Well Integrity Supv CPF3 and WNS <n2549@conocophillips.com>; NSK Prod Engr Specialist <n1139@conocophil1ips.com>; NSK Optimization Engr <n2046@conocophillips.com>; NSK West Sak Prod Engr <n1638@conocophillips.Com>; CPF3 Ops Supv <n2070@conocophillips.com>; CPF3 Ops & DOT Pipelines Supt <n1175@conocophi11ips.com>; CPF3 DS Lead Techs <n1105@conocophi1lips.com>; CPF3 Maint Supv <n2069@conocophilllps.com>; Valentine, Doug K <Doug.K.Valentine@conocophillips.com>; Jolley, Liz C <Liz.C.Jollev@conocophillips.com>; Martin, Kenneth Lloyd<K.L.Martin@conocophillips.com>; Plunkett, Ethan T <Ethan.T. Plunkett@conocophillips.com> Subject: RE: Defeated LPP/SSV on well 3K-1031-1 Good afternoon Mr. Regg, The low pressure pilot on injection well 3K-1031-1 (PTD# 208-116) has been returned to normal operation, as of Friday, May 3151, 2019, in accordance with "Administrative Approval No. CO 4068.001" Best regards, Ethan Plunkett / Kenneth Lloyd Martin CPF3 Production Engineer I Office x7871 I Cell (918) 812-2294 1 Pager x328 I Radio 343 From: CPF3 Prod Engrs <n1223@conocophillips.com> Sent: Monday, April 22, 2019 5:11 AM To: iim.ress@alaska.aov Cc: NSK Well Integrity Supv CPF3 and WNS <n2549@conocophillips.com>; NSK Prod Engr Specialist <n1139@conocophillips.com>; NSK Optimization Engr <n2046@conocophiIhps.com>; NSK West Sak Prod Engr <n1638@conocophillips.com>; CPF3 Ops Supv <n2070@conocophillips.com>; CPF3 Ops & DOT Pipelines Supt <n1175@conocophillips.com>; CPF3 DS Lead Techs <n1105@conocophillips.com>; CPF3 Maint Supv <n2069@conocophillips.com>; Valentine, Doug K <Doue.K.Valentine@conocophillips.com>; Jolley, Liz C <Liz.C.Jollev@conocophillips.com>; Martin, Kenneth Lloyd <K.L.Martin@conocophillips.com>; Plunkett, Ethan T <Ethan.T.Plunkett@conocophillips.com> Subject: Defeated LPP/SSV on well 3K-1031-1 Mr. Regg, The low pressure pilot (LPP) on injection well 3K-101-1 (PTD# 208-116) was defeated late Saturday evening, 4/20/2019. 3K-1031-1 had been shut in for 6 days due to a flooding conformance treatment. After the initial treatment setup period, returning the well to injection at a reduced rate to monitor the treatment, the wellhead pressure did not rise high enough to place the low pressure pilot in service. 3K-1031.1 is currently at wellhead injection pressure of 331 psi and injection rate of 700 bbls of water per day. The LPP and surface safety valves (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 250 psi and is stable during scheduled water injection line pigging today, and the LPP/SSV function is returned to normal operation, in accordance with "Administrative Approval No. CO 4068.001". Best regards, Ethan Plunkett / Kenneth Lloyd Martin CPF3 Production Engineer I Office x7871 I Cell (918) 812-2294 1 Pager x328 I Radio 343 ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 'RECEIVED MAV 1 ^ 1. Operations Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing ❑ Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change!/{p��{{oo ved Pro ram Plug for Redrill ❑ erforate New Pool ElRepair Well El Reenter Susp Well El Other: RPP MBE Trtmt 2. Operator Name: ConocoPhillips Alaska, Inc. 4. Well Class Before Work. 5. Permit to Drill Number: Development ❑ Strafigraphic❑ Exploratory ❑ Service 0 208-116 3. Address: P. O. Box 100360, Anchorage, 6. API Number: Alaska 99510 50-029-23392-60-00 7. Property Designafion (Lease Number): 8. Well Name and Number: ADL 25519 KRU 3K -103L1 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Kuparuk River Field / West Sak Oil Pool 11. Present Well Condition Summary: Total Depth measured 12,375 feet Plugs measured None feet true vertical 3,576 feet Junk measured None feet Effective Depth measured 12,334 feet Packer measured 4,589 feet true vertical 3,574 feet true vertical 3,439 feet Casing Length Size MD ND Burst Collapse CONDUCTOR 36 feet 20 80' MD 80' TVD SURFACE 2,497 feet 13 3/8 " 2,540' MD 2217' TVD INTERMEDIATE 4,625 feet 95/81, 4,675' MD 3551' TVD D -SAND LINER 7,673 feet 3 1/2 " 12,336' MD 3574' TVD Perforation depth: Measured depth: 5027-12054 feet True Vertical depth: 3474-3569 feet Tubing (size, grade, measured and true vertical depth) 3.511 L-80 4,703' MD 3,458' TVD Packers and SSSV (type, measured and true vertical depth) PACKER- BAKER 'GT' RETRIEVABLE 4,589' MD 3,439' TVD SSSV -NONE 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing PressureTubing Pressure Prior t0 well operation: Shut -In Subsequent to operation: IN/A - 550 - e 14. Attachments (required Per 20 AAc 25.07Q 25.071, a 25283) 15. Well Class after work: Daily Report of Well Operations 21 Exploratory ❑ Development ❑ Service 21 Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ❑ Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑p WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 318-496 Authorized Name: John Pierce Contact Name: John Peirce Authorized Title: Sr. Wells Engineer Contact Email: John.W.Peirce@cop.com Authorized Signature: � Contact Phone: (907) 265-6471 Dater r �jD4,[ VTL 5-11-111"1 Form 30-404 Revised 4/2017/ri �/-L j �iBDMS t*1 MAY 13 Y019 Submit Original Only ConocoPhillips Alaska, Inc KUP INJ SAK NIPPLE WELLNAME 3K-103SS WELLBORE 3K -103L1 WO: IALTIPLE LATERALS -3K-1.1, S9IyX98 W.00PM Last Tag Vwpmlaerweve tWj Arriga n DCpM mnBl 1 End Dale WNIEore Last Moa By ................ ......._........................................ ..___._____.. _. Last Tag: I IJN-lD,LI lieloSbor NPNOER: Yl.9 NDEa sees Last Rev Reason Anno,almn Enawh Wi Last Motley Rev Reason'. WELL REVIEW 4/22012 31-103L1 losporl Casing Strings crimp Desmip,mn oDlinl thiel rop mRel sol o.pM mMat set Daplh -Dl._ W,/Len(I 10rme Tnp Tn,eaa .-SA LINER 3112 299 4.6632 12,3361 3,5]43 920 L-80 SLHT Liner Details CONDOCTOR, 61..r NominallD Toown) Top BVIN meal Top Incl Pl pend Des Com (in) 4,6632 3,452.0 8019 HANGER RAM Hanger, (above LEM Profile to Top of RAM 6.760 Hanger) 4,665.7 33452.4 80.22 HANGER RAMHadper, (above Collet into LEM Profile) 6750 4,6]0.] 3,4533 8030 HANGER AM Hanger, DD. rid52-1-BS low 6750 NIPPLE. 486.4 Collo,) Pin down Nis WILL be 4670.70' NIPPLE, ant 4,6 8 3,458.0 81.19 XO - Reducing Creep, over- Porand pp, Hydril 521 x 3750 12'Hydril 521 4,704.5 3,4587 81.34 XO - Reducing Crossover 4-112" hyd 521 box z -1l hyd pin 3000 4.71"OD x300"ID Tubing Strings Toeine Dessnptbn sh,np Ma.. m (m) TOP mKel sol DeInx (n.. set Depth (TVD) 6.. tv, DIMd) Daae Top Connmmn SUREACE: 47,0.25002 TUBING D -SAND 3112 2.99 3fi.3 4,703.5 31158.5 9.30 L-80 Completion Details Top(NID) Topmd Nominal lop (.a.) nN., (9 Mm Desoath ID (in)) 363 36.3 0.00 HANGER VE TCO GRAY DUAL TUBING HANGER 3500 4684 4674 7.27 NIPPLE CAMCO'DS' NIPPLE e12.875 PROFILE 2.875 4,282.1 3,357.5 6595 SLEEVE BAKER CMD SLIDING SLEEVE 0412813 PROFILE 2.813 4,5880 3,438.0 ]9.34 PACKER BAKER 'GT DUAL PACKER MANDREL 2.920 4,5890 3,4368 ]9.35 PACKER BAKER 'GT RETRIEVABLE DUAL PACKER 2.920 SLEEVE 4363., 4,592.6 34395 ]9.39 PACKER BAKER' GT' DUAL PACKER MANDREL 2920 wsuPr; 4,at6 4,620.8 3,444.6 ]9.69 NIPPLE CAMCO'D' NIPPLE .1276"NO GO PROFILE 2]50 4,629.1 3,446.1 ]9.78 EXT JOINT BAKER 3.30"'DSM' EXTENTION JT MANDREL 2.992 4,6392 344].8 N.88 SEAL BAKER'RAM'DUAL SEAL MODULE 2.690 4,6]1.6 3,4534 80.31 SEAL ASSY SHROUDED SEAL ASSEMBLY 2.690 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Tap ,NB, Top0VDI (We) Top Incl (°) Des cam Run ..is I. (I.) PACKER: a.5P8.e PACKER: 4.Y9.0 PACKER: 4.5W.p Bobear:4,sm.o 4,7]5➢ 3,46].N 84.48 D -Sand Swell LINER WELLPACKER 4]75',5 ,5 Packers 6760,]330', 7860, BOBS',8630,9260',10060',10]60', 11/15120 B 3500 PACKER: 4,42.6 11040111540' (WATER ACTIVATED) pnKER: 4.9d3.a FISH 13RUBBE IBP RETENTION BANDS LET TMWELL 11102009 0006, NI1PLE:4.RSR perforations & Slots wpplE:4sm.6 snot Dees TOP Irv.) bun (TVD) fihotm Topn,KB) B,mmKB) ads d1KB1 Linked Zones DSR ) Type Co. 5,027.1 5,057.8 34737 3,473.6 AS D. 3K- 111192008 990 SLOTS Alternating solid tEAL:4 [59.3 10311 ospiescreens 5,499.0 5,5296 3,482.2 3,483.2 WS 03K- 11115/2008 99.0 SLOTS Altemaung ,did SEAL: 4,.&7 10311 pipsiscreare DNERBEPLaORE OhERTER: 4 m77<,7s6a INTERMEONTE;'A.4S,43]0 5, 4]2 5.977.8 3,490) 3,491.4 WS 03K- 10311 11/1512(108 990 SLOTS Alternating solid piWscreens ....Y46r. 6°482A 6,513.0 3,487.0 34988 S03K- HOT 111192008 99.0 SLOTS Altemaung solid pixascreens 7,0467 7,0781 3,520.5 35206 WSD, 3K- 1111512008 99.0 SLOTS Altemaung solid 103L1 piphscreens 7,745.0 7,7763 3508.6 3,5067 WS D, 3K- 11/152008 99.0 SLOTS Alternating sold 103L1 pipespreens Ostend reel Pedam: 4,M0 8,3006 8.3320 34984 3,498.6 WS D, 3K- 11/152008 No SLOTS Alternating solid .LOTS;S..1e.0576 103L1 pipebcreens 8,860.1 8,891.5 3,4918 3,492.1 WS D, 3K- 11/152008 99.0 SLOTS Alternating solid 103Li Spe/screens 9.580.6 9,fi120 3.518.2 3,8187 WS D, 3K- 11/152008 990 SLOTS Alternating wild SLOTS; a94z259n6- - 103LI Spe/screens SLOTS 1 e.4e2."Larso� - 10,489.6 10,5210 3,512.9 3,5124 WS 03K- 103L1 11/152008 990 SLOTS Alternating sol pipefsaeens 10.863.1 10894.5 3,513.4 3,514.1 WS D. K- 11/162008 990 SLOTS Allemating Soli TWILL gpelsoeens SLOT&7046.7-7.mill _ 11,2387 1 11,270.0 3,521.0 3,522.4 WS D. - 11,192008 990 SLOTSpt hadogsall SL0Ta.7.745.o7na3� _ 10311 I piPJsaeens 12,022.fi 12,054.0 3,568.6 3,568.9 WS D,K- 11115/2008 99.0 SLOTS temaunp sDl - _ I 10311 pipeepreens SLOTS: a3opea.33z.o-_ -_ Notes: General & Safety End D.IsAnnotation SLOTS;&RON ie.eet s- 12/92008 NOTE MUN-Ltileral Well 3K-103(Ii 3K -10311(D -SAND) wlDual TBG Strings smTs:9seoae.eu.o- _ 111N2009 NOTE: RUBBER IBP RETENTION BANDS LEFT IN B -LAT @ 479]' SLOTS', loespe-In!' �� .LOTS; laress"&1945_ SLOTS, 11 se 7-11Z OSS SLOT8: 1S. rIZOSN. _ 0.69N0 LINER; sees Z, 1$33bl 3K -103L1 RPPG MBE TREATMENT DTTM JOBTYP SUMMARYOPS START 4/14/19 MISC. PUMPED 6644# OF RPPG MIXED IN CAPACISUSTAITY 350 BBLS 2% KCL AS PER DESIGN, GAIN OF 850 PSI WHIP, WELL IS FREEZE PROTECTED. p7 -o zoo -1l � Loepp, Victoria T (DOA) From: Peirce, John W <John.W.Peirce@conocophillips.com> Sent: Tuesday, January 8, 2019 3:01 PM To: Loepp, Victoria T (DOA) Subject: RE: [EXTERNAL]KRU 3K-103L1(PTD 208-116, Sundry 318-496); KRU 3K-105(PTD 212-165, Sundry 318-497) D MBE RPPG Treatment - Proposed Procedure Changes Follow Up Flag: Follow up Flag Status: Flagged Victoria, Thanks for your reply. I'll proceed as you have requested. I'm not sure when we'll pump the job, but hopefully soon if it warms up a bit on the Slope. Pumping conditions are challenging now due to very cold weather, so we may wait for a break to more favorable weather to reduce some operational risk. Regards, John Peirce Sr Wells Engr CPAI Drilling & Wells (907)-265-6471 office From: Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov> Sent: Tuesday, January 8, 2019 1:49 PM To: Peirce, John W <John.W.Peirce @conocophillips.com> Subject: [EXTERNAL]KRU 3K-103L1(PTD 208-116, Sundry 318-496); KRU 3K-105(PTD 212-165, Sundry 318-497) D MBE RPPG Treatment -Proposed Procedure Changes John, The proposed procedural changes are approved. Please include this email approval of the changes with the original approved sundries. Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501 Work: (907)793-1247 Victoria. Loeoo(a)alaska.00v CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are on unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Victoria Loepp at (907)7931247 or Victoria Loeoo@alaska.aov From: Peirce, John W <John.W.Peirce @conocophillips.com> Sent: Tuesday, January 8, 2019 1:17 PM To: Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov> Subject: Re: 3K-1031-1 D MBE RPPG Treatment - Proposed Procedure Changes Hi Victoria, We attempted to prep 3K-1031-1 for the D MBE RPPG Treatment in early December as per 11/9/18 10-403 approvals: #318-496(for 3K-1031-1, and #318-497 for 3K-105, but we had no success getting the well ready for the treatment as per my proposed procedure. See attached work proposal (below) that was on 10-403. We had several set failures with inflatable equipment we attempted to set. We set the IBP twice and also set four inflatable Treating Packers four, but we never managed to get a good pressure test on the IBP and we also had several inflatable Treating Packer set failures as well. After a few days attempting work setting inflatable equipment, we decided to pull Treating Packer and IBP to run a Caliper log that indicated we had several large holes in the 3.5" liner where we had been attempting to set our inflatables. This likely compromised our inflatable set attempts. The 12/11/18 Caliper also showed several dozen other significant holes exist dispersed up and down the 3.5" Liner. This showed that the well can't be treated as we planned, so we decided to suspend CT RPPG treatment plans. Due to current compromised condition of the liner, we decided we should treat the D MBE like we would go about pumping an MBE treatment in a slotted liner completion. Due to all the holes on the liner, 3K-1031-1 liner is now quite similar to a slotted liner. It's safe to say that the ICD's in the liner are no longer able to function as intended. Thus, we will be altering the treatment procedure to pump a fullbore RPPG treatment to D MBE at —6300' RKB. I'm altering the proposed RPPG Treatment procedure to pump the fullbore job. We no longer need to perfthe liner (as previously planned for RPPG treatment) since we have plenty of holes now present in the liner due to suspected corrosion in the liner. Question: Should I submit new 10-403's to perform a fullbore treatment, or can we execute a fullbore treatment under 11/9/18 10-403 Sundry approvals: #318-496 (for 3K-1031-1, and #318-497 for 3K-105 and then report it on 10-404's referencing those approvals? Thanks, John Peirce Sr Wells Engr CPA] Drilling & Wells (907)-265-6471 office Proposed 3K-1031_1 to 3K-105 RPPG Treatment of D MBE 3K-103 Injector has a dual lateral completion design with a dual string Packer, and dual 3-1/2", 9.3#, L-80 tubing strings. 3K-1031_1 is a West Sak D Sand lateral. 3K-103 is a West Sak B Sand lateral. Initial evidence of a possible D MBE from 3K-1031-1 to offset 3K-105 producer arose in Summer 2018 when 3K-105 watercut went from 40% to 85% in a 3 -month period. 3K-1031_1 has 13 inflow control devices (ICD screens). A 9/28 - 9/29/18 IPROF in 3K -103L1 found that the fourth screen down the lateral at 6482 - 6513' RKB took the bulk of total injection in the lateral. Nine other screens below 6513' RKB did not appear to be receiving any significant injection with 1000 BWD entering the lateral during the (PROF. SI warm back passes indicate a D MBE exists at 6300' via the ICD at 6482 - 6513' RKB. We propose sealing the MBE with RPPG: Procedure using 2" OD Coil Tubing: 1. RIH & set a retrievable inflatable Bridge Plug in blank liner at 6613' RKB (target) then POOH. 2. RIH & set retrievable inflatable Treating Packer in blank liner at -6563' RKB (target), then PU CT to 2500 psi to verify good set integrity of IBP at 6613' RKB before RPPG treatment. POOH with retrievable Inflatable Treating Packer. 3. RIH with Perf Gun and then shoot `big hole' perfs in 3.5" Blank Liner at 6300 - 6305' RKB at 6 spf, 60 deg ph, over D MBE to enable RPPG slurry flow through 3.5" liner. POOH with gun. Verify ASF. Pump 55 bbls Diesel FP down Tubing to ensure Diesel is in well above to at least above 6200' RKB before setting Treating Packer in next work step. 4. SI offset 3K-105 producer 12 to 24 hrs before pumping in 3K-1031-1. RIH & set retrievable inflatable Treating Packer in blank liner at 6200' RKB (target) to set Packer 100' above perfs. Pump 100 bbls 2% KCL Brine Pre -Flush at 1 - 2 bpm down CT to verify good injection exists to MBE at -6300' RKB, and to ensure all hydrocarbon contaminants to RPPG are displaced from CT to MBE. When CT is full of Brine, do SRIT at 1, 1.5, 2 bpm down CT. Record CT treating psi at each rate. Pick a constant rate to pump job, and then begin mixing & pumping RPPG Slurry on -the -fly from the Mixing Van down CT as follows: a) RPPG Slurry at steady 0.75 ppg concentration (target) in 2% KCL Brine at steady established rate between 1 to 2 bpm. Continue until CT treating pressure rises, then determine when to call Flush depending on the rate of CT pressure rise observed, then call Flush pumping b) 0.5 bbl 2% KCL Brine Spacer at same steady rate, followed by SD to drop disconnect ball, then c) Resume pumping another 2.5 bbls 2% KCL Brine Spacer at same steady rate to keep Diesel contamination from contacting RPPG tail, followed by d) CT volume of Diesel to displace 2% KCL Brine Spacer to the Treating Packer. When ball lands on seat, disconnect CT from Packer leaving last barrel of RPPG slightly underdisplaced to MBE and check valve on top of treating packer to prevent any up flow (crossflow) through the Packer. Continue pumping the last few bbls of Diesel until CT Diesel FP is completed, then e) SD pumping. RD CTU & Mix Van. MOL. Wait -48 hrs for RPPG to fully cure in the MBE. 5. RIH & pull retrievable inflatable Treating Packer from blank liner at 6200' RKB. 6. RIH with down jet nozzle to perform RPPG cleanout with Diesel to the IBP at -6600' RKB. 7. RIH & pull IBP from blank liner at -6600' RKB. Return 3K-1031-1 to injection. JWP 1/10/2019 I ?A-- I(too Regg, James B (DOA) From: CPF3 Prod Engrs <n1223@conocophillips.com> Sent: Tuesday, April 19, 2016 2:39 PM idler To: Regg, James B (DOA) Cc: NSK Problem Well Supv; NSK Prod Engr Specialist; NSK Optimization Engr; Sullivan, Michael; NSK West Sak Prod Engr; CPF3 Ops Supv; CPF3 Ops & DOT Pipelines Supt; CPF3 DS Lead Techs; CPF3 DS Lead Techs Subject: Return to service of LPP/SSV on well 3K-103L1 Mr. Regg, The L1 side of well 3K-103 (PTD 208-116-0) is now injecting at 384 psig, and the low pressure pilot controlled safety system was placed in service this morning (19-April-16) with a pilot setting of 250 psig. The other tubing string and completion, 3K-103 (PTD 208-115-0), still has the low pressure pilot defeated (and logged and tagged as appropriate), but has only increased in wellhead pressure to 200 psig. The AOGCC will be notified when the injection pressure has increased to above 250 PSIG 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. 9CeivaedA, /� Id Kenneth Lloyd Martin/Toon Changklungdee PERA/CPF3 Production Engineers Ph: (907) 659-7871 SCANNED SEP 2 6 2016 Pager: (907) 659-7000 pp#328 From: CPF3 Prod Engrs Sent: Monday, April 18, 2016 8:43 PM To: Regg,James B (DOA) <jim.regg@alaska.gov> Cc: NSK Problem Well Supv<n1617@conocophillips.com>; NSK Prod Engr Specialis n1139@conocophillips.com>; NSK Optimization Engr<n2046@conocophillips.com>; Sullivan, Michael <Michael.S Ivan • conoco•hilli•s.com>; NSK West Sak Prod Engr<n1638@conocophillips.com>; CPF3 Ops Supv(n2070 • cono ••hilli•s.com) <n2070@conocophillips.com>; CPF3 Ops & DOT Pipelines Supt (n1175 • -onocophillips.com) <n1175@conocophillips.com>; CPF3 Prod Engrs<n1223@conocophi .ps.com>; CPF3 DS Lead Techs <n1105@conocophillips.com>; CPF3 DS Lead Techs<n1105@con.cophillips.com> Subject: Defeated LPP/SSV on well 3K-103D Mr. Regg, The low pressure pilot (LPP) on injection well 3K-1 QZ(PTD#208-115-0, 208-116-0)was defeated 16-Apr-16. The well had been shut in due the repair of the seawater supply line to the drill site and after initial monitoring on the morning of 17- April, the wellhead pressure did not rise high enough to place the low pressure pilot in service. • WELL LOG TRANSMITTAL To: State of Alaska Alaska Oil and Gas Conservation Commission Attn.: Christine Mahnken 333 West 7"' Avenue, Suite 100 Anchorage, Alaska 99501-3539 RE: MWD Formation Evaluation Logs: 3K-103L1 February 25, 2010 AK-MW-0006005291 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Bryan Burinda, Sperry Drilling Services, 6900 Arctic Blvd., Anchorage, AK 99518 3K-103L1 Digital Log Images & LWDG-formatted LIS Data w/verification listing; 1 CD Rom 50-029-23392-60 Please acknowledge receipt by signing and returning/faxing the attached copies 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 Burincl~halliburton.com ~~ ~ ~ t}~ ~r'r.. ~~~'~~~~. ~~r? ~r ~~ 7~i1i' i 5 1 7 Date:..... _, ~ ~ Signed: ..~ ~ _ ~ ;, DATA SUBMITTAL COMPLIANCE REPORT 2/23/2010 Permit to Drill 2081160 Well Name/No. KUPARUK RIV U WSAK 3K-103L1 Operator CONOCOPHILLIPS ALASKA INC API No. 50-029-23392-60-00 MD 12375 TVD 3576 Completion Date 11/19/2008 Completion Status 1WINJ Current Status 1WINJ C Y REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes DATAINFORMATgN Types Electric or Other Logs Run: GR/RES, USIT (data taken from Logs Portion of Master Well Data Maint Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments __--_ Induction/Resistivity 25 Col 120 12375 Open 2/3/2009 MD ROP, DGR, EWR 11- Nov-2008 Log Induction/Resistivity 25 Col 120 3575 Open 2/3/2009 TVD DGR, EWR 11-Nov- ~ 2008 ~~ I`ED C 17563~duction/Resistivity 120 12375 Open 3/2/2009 EWR graphcis in PDS, i EMF and CGM I'Rpt LIS Verification 2506 12375 Open 1/13/2010 LIS Veri,. GR, RPX, RPS, RPM, FET, RPD, ROP ~b C Lis 19150 L'Induction/Resistivity 2506 12375 Open 1/13/2010 LIS Veri,. GR, RPX, RPS, i RPM, FET, RPD, ROP Well Cores/Samples Information: Name ADDITIONAL INFORMATION Well Cored? Y Chips Received? `N#-- Analysis e'Ff-N'- Received? Sample Interval Set Start Stop Sent Received Number Comments Daily History Received? LJ' N Formation Tops N = J DATA SUBMITTAL COMPLIANCE REPORT 2/23/2010 Permit to Drill 2081160 Well Name/No. KUPARUK RIV U WSAK 3K-103L1 Operator CONOCOPHILLIPS ALASKA INC MD 12375 TVD 3576 Completion Date 11/19/2008 Completion Status 1WINJ Current Status 1WINJ Comments: ~ l S rc ~.~ r C r1 ~ ~ ~ t c, r-w,,,yb ~ ~t ~ ~~ c ~ ~~ ~ cAtLuvww. ~+llfl fd~ Compliance Reviewed By: API No. 50-029-23392-60-00 UIC Y Date: ~ 3 '~.~ ~.-~`l O ~ 4 WELL LOG TRANSMITTAL To: State of Alaska January 4, 2010 Alaska Oil and Gas Conservation Commission Attn.: Christine Mahnken 333 West 7"' Avenue, Suite 100 Anchorage, Alaska 99501-3539 RE: MWD Formation Evaluation Logs: 3K-103+L1+PB1+PB2+PB3+PB4+PB5 AK-MW-0006005291 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Bryan Burinda, Sperry Drilling Services, 6900 Arctic Blvd., Anchorage, AK 99518 3K-103+PB1 +PB2+PB3+PB4+PB5 Digital Log Images &LWDG-formatted LIS Data w/verification listing; 1 CD Rom 50-029-23392-00, 70, 71, 72, 73, 74 3K-103 L1 Digital Log Images &LWDG-formatted LIS Data w/verification listing; 1 CD Rom 50-029-23392-60 Please acknowledge receipt by signing and returning/faxing the attached copies of the transmittal letter to the attention of: Speny Drilling Attn: Bryan Burinda 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-273-3536 Fax: 907-273-3535 Bryan.Burinda(a~halliburton.com :~~ ~ ~ -- ,. ~ ~ ~ -' ~:, ~~ _ . vs ~ ~o~ -115 ~9/Y9 ~ v,~ ~o~s-r~~ t ~ r'Sb ,, ~:, =!•. ; Date: ~ Signed: rage 1 of 3 Maunder, Thomas E (DOA) From: CPF3 Prod Engrs [n1223@conocophillips.com] Sent: Thursday, February 05, 2009 3:35 PM To: Maunder, Thomas E (DOA); CPF3 DS Lead Techs Cc: CPF3 Prod Supt; Regg, James B (DOA); NSK Problem Well Supv; NSK Well Integrity Proj Subject: RE: "NE West Sak Injector 3K-108 (208-130)". ~ ®~_ ~~~ ~Q~-~'~`~ Tom, Sorry far any confusion. It was indeed the pifats for both strings; 3K-108 LPP and HPP & 3K-108L1 LPP and NPP that were taken out and then put back into service. You are correct that both the 3k103 and 3k-108 are dual tubing string injectors. Therefore, each string has a HPP and LPP. We will try to be more specific and use the nomenclature as you have described below. Please call or message if you have any questions or need more information. Thank you G~S~ ~~~- ~r~ John Cona-io l Tim Nelson ConocoPhilGps Alaska, Inc. CPF3 Production Engineers Email: N1223@conocophiilips,com Ph. (907) 659-7871 Fax. (907) 659-7806 ~~-11,Co ~-' From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Thursday, February 05, 2009 12:00 PM To: CPF3 DS Lead Techs Cc: CPF3 Prod Engrs; CPF3 Prod Supt; Regg, James B (DOA); NSK Problem Well Supv; NSK Well Integrity Proj Subject: RE: "NE West Sak Injector 3K-108 (208-130)". Wayne, et ai, I have had a chance to review the files. It appears that there are two individual tubing strings here, one for 3K- 108 and the other for 3K-108L1. Were the low pressure pilots defeated for both strings? If that is the case, the messages should have included the information for both strings/valves. This could have also been the case for 3K-103 and 3K-103L1. If you or one of the engineers could provide the information for the pilots that were defeated and then placed back in service for each string, it will be appreciated. Just reply to this message. Equipping these wells with dual strings makes the reporting a bit mare complicated when the pilots are defeated. It seems appropriate where dual strings are involved to make sure that the specific string with the defeated pilot is clearly identified (-108 or 108L1) or send separate messages for each string. Call or message with any questions. I look forward to your reply. Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) Sent: Tuesday, February 03, 2009 4:58 PM 2/13/2009 Page 2 of 3 To: 'CPF3 DS Lead Techs' Cc: CPF3 Prod Engrs; CPF3 Prod Supt Subject: RE: "NE West Sak Injector 3K-108 (208-130)". Wayne, et al, I will have to check the files tomorrow. It appears I have messages regarding both 3K-108 and 3K-103. Tom Maunder, PE AOGCC From: CPF3 DS Lead Techs [mailto:n1105@conocophillips.com] Sent: Tuesday, February 03, 2009 4:41 PM To: Maunder, Thomas E (DOA) Cc: CPF3 Prod Engrs; CPF3 Prod Supt; CPF3 DS Lead Techs Subject: RE: "NE West Sak Injector 3K-108 (208-130)". Tom, 1 hope I am sending this to the correct person; As we don't currently have one of our P.E.'s on the slope, 3K-108 LPP's where satisfied and put back in service 2/03109 ~ 16:30 If I need to do something else pisses let me know. Thank you very much. Wayne Griebel CPF3 DS Lead From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Tuesday, February 03, 2009 3:02 PM To: CPF3 Prod Engrs; Regg, James B (DOA) Cc: NSK Prod Engr Specialist; Targac, Gary; CPF3 Prod Supt; Allsup-Drake, Sharon K; CPF3 DS Lead Techs; NSK Problem Well Supv Subject: RE: Tim, When you send a message such as this, please include a title. Specifically for a well with a defeated safety valve the title should in this case read "NE West Sak injector 3K-108 (208-130)". Thanks in advance. Call or message with any questions. Tom Maunder, PE From: CPF3 Prod Engrs [mailto:nl223@conocophillips.com] Sent: Monday, February 02, 2009 6:32 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: NSK Prod Engr Specialist; Targac, Gary; CPF3 Prod Supt; Allsup-Drake, Sharon K; CPF3 DS Lead Techs; NSK Problem Well Supv Subject: Tom /Jim, This email is to notify the AOGCC that the North East West Sak (NEWS) Injector 3K-108 Low Pressure Pilots (LPP) are defeated as of 2/2/2009. This is in accordance with "Administrative Approval No. CO 406B.001"The LPP and SSV (Surface Safety Valve) have been tagged and recorded on the "Facility Defeated Safety Device Log." The 3K-108 was brought on injection today, 2/02/2009. It is anticipated that injection pressure will increase above 250 psi within a few days. Current injection rate is 640 BWPD at 200 psi injection pressure in the B lateral and 430 BWPD at 235 psi injection pressure in the D lateral. 2/13/2009 • ~ Page 3 of 3 The AOGCC will be notified when the injection pressure has increased above 250 psi and the LPP functions are returned to normal. Tim Nelson /John Condio ConocoPhillips Alaska, Inc. CPF3 Production Engineers Email: N1223@conocophillips.com Ph. (907) 659-7871 Fax. (907) 659-7806 2/13/2009 WELL LOG TRANSMITTAL. To: State of Alaska January 30, 2009 Alaska Oil and Gas Conservation Comm. Attn.: Librarian 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: MWD Formation Evaluation Logs 3K-103+L1+PB1+PB2+PB3+PB4+PBS AK-MW-6005291 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Bryan Burinda, Sperry Drilling Services, 6900 Arctic Blvd., Anchorage, AK 99518 3K-103+L1+PB1+PB2+PB3+PB4+PBS 2" x 5" MD RESISTIVITY & GAMMA RAY Logs: 1 Color Log 50-029-23392-00,60,70,71,72,73,74 2" x 5" TVD RESISTIVITY & GAMMA RAY Logs: 1 Color Log 50-029-23392-00,60,70,71,72,73,74 Digital Log Images 2 CD Rom 50-029-23 392-00,70,71,72,73,74 50-029-23392-60 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry Drilling Services Attn: Bryan Burinda u~ ~ ~~=~ -1 ~~ 6900 Arctic Blvd. Anchorage, Alaska 99518 ~T~- ae~~s`it~ Office: 907-273-3536 Fax: 907-273-3535 Bryan.Burin a@halliburton.com - ~~ f~ __ _ ` Date: ' Signed: ~~ SCo~ `~ 5(,~3 ,~ 3K-103 - Doyon 15 - Current~tus . Page 1 of 4 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Tuesday, January 27, 2009 1:37 PM To: Sale, Julie J Cc: Wharton, Paul K; Downey, Allison; Spenceley, Neil; Machal, Gloria; Davies, Stephen F (DOA); Roby, David S (DOA); McMains, Stephen E (DOA) Subject: RE: 3K-103 (208-115) and 3K-103L1 (208-116) Yes, Julie that is correct. Call or message with any questions.. Tom Maunder, PE AOGCG From: Sale, Julie J [mailto:Julie.J.Sale@conocophillips.com] Sent: Tuesday, January 27, 2009 1:26 PM To: Maunder, Thomas E (DOA) Cc: Wharton, Paul K; Downey, Allison; Spenceley, Neil; Machal, Gloria Subject: RE: 3K-103 (208-115) Thomas, Does this give you the information you are needing from ConocoPhillips? Pro_posed_ Reporting__M ethod On the AOGCC Monthly Injection Report (10-406), we typically report well level injection for multi-laterals because all injection goes through one meter at the surface. In this case we will have separate surface injection meters for each string so we have the ability to report at the wellbore/string level. Julie J. Sale ConocoPhillips Supervisor Revenue and Regulatory Upstream Accounting Alaska 930 G POB / Bartlesvii[e, OK 74004 918-661-3523 (w) /918-9 t 4-3669 (c) 918-662-T 702 (fax) 620-778-4906 (personal-cell] julie.j.sal~conocophillips.com From: Spenceley, Neil Sent: Tuesday, January 27, 2009 11:31 AM To: Maunder, Thomas E (DOA) Cc: Wharton, Paul K; Downey, Allison; Sale, Julie J Subject: RE: 3K-103 (208-115) Tom, As per our conversation we will report the 3K injection volumes as follows: 2/5/2009 3K-103 - Doyon 15 - Current~tus . Page 2 of ~7 7 The well will be split in two (3K-103 and 3K-103L1) to be reported as separate rate streams injecting into the West Sak oil pool. Please let me know if you would like to see it reported differently. Thanks. Neil From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Tuesday, January 27, 2009 8:14 AM To: Spenceley, Neil Subject: FW: 3K-103 (208-115) Here is that message trail. From: Downey, Allison [mailto:Allison.Downey@ConocoPhillips.com] Sent: Tuesday, January 13, 2009 8:47 AM To: Maunder, Thomas E (DOA) Cc: Roby, David S (DOA); Davies, Stephen F (DOA); McMains, Stephen E (DOA); Hartwig, Dennis D; Sale, Julie J Subject: RE: 3K-103 (208-115) Tom, I am working the 3K-103 reporting issue with the Revenue Accounting group. We will have an answer for you soon on how the dual string injection will be reported. The well is not in service yet but is expected to start injection this week. Allison Allison Downey GIS Technical Data Management ConocoPhillips Alaska, Inc. 907-263-4299 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, January 12, 2009 3:00 PM To: Hartwig, Dennis D; Downey, Allison Cc: Roby, David S (DOA); Davies, Stephen F (DOA); McMains, Stephen E (DOA) Subject: RE: 3K-103 (208-115) Dennis, Thanks. We will look forward to Allison's contact. Tom Maunder, PE AOGCC From: Hartwig, Dennis D [mailto:Dennis.D.Hartwig@conocophillips.com] Sent: Monday, January 12, 2009 2:56 PM To: Maunder, Thomas E (DOA) Cc: Roby, David S (DOA); Davies, Stephen F (DOA); McMains, Stephen E (DOA) Subject: RE: 3K-103 (208-115) 2/5/2009 3K-103 - Doyon 15 -Current s!~fus ~ Page 3 of~ ,~ Tom,.. I have farvtitarded on your questions to Allison Downey (Allison.do~~n~ c~ conocophillips.com}. Allison has been tasked with setting up ATDB to store the lateral specific injection data separately as opposed to commingled. I left a phone message for Allison. and vr~ill continue to follow up until. your questions are answered. Regards...Dennis Dennis Hartwig Drilling Engineer Greater Kuparuk Area ConocoPhillips Alaska - ATO-I592 Offiee :907-265-6862 CeII :907-575-7109 Fax :907-265-1535 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, January 12, 2009 1:40 PM To: Hartwig, Dennis D Cc: Roby, David S (DOA); Davies, Stephen F (DOA); McMains, Stephen E (DOA) Subject: RE: 3K-103 (208-115) Thanks Dennis. Also, do you know if the well has been placed in operation? As we have looked into the particulars for this well several questions regarding the injection reporting have come up. To our knowledge, this is the first duaE tubing, multi-lateral well in#o the WS and likely on the slope. l believe there are a few other dual tubing single penetration WS wells. In most cases, neither production nor injection is `credited" to laterals since everything is commingled in the wellbore. That is not the case here where the separate volumes in each string can be determined. I am not sure who would be the one to comment on how the injection volumes would be reported, however it appears that is a question that should be asked_ 1'd appreciate if you could forward this portion of the message on for comment. Call or message with any questions. Tom Maunder, PE AoGCc From: Hartwig, Dennis D [mailto:Dennis.D.Hartwig@conocophillips.com] Sent: Monday, January 12, 2009 12:42 PM To: Maunder, Thomas E (DOA) Subject: RE: 3K-103 (208-115) Tom, I will look rota these issues and get back to you ASAP...Denns Dennis Hartwig Drilling Engineer Greater Kuparuk Area ConocoPhillips Alaska - ATO-I592 Off ce :907-265-6862 2/5/2009 3K-103 - Doyon 15 - Current~tus • Page 1 of 2 Maunder, Thomas E (DOA) From: Hartwig, Dennis D [Dennis.D.Hartwig@conocophillips.com] Sent: Tuesday, January 13, 2009 4:20 PM To: Maunder, Thomas E (DOA) Cc: Alvord, Chip; Regg, James B (DOA); McKeever, Steve; Allsup-Drake, Sharon K Subject: RE: 3K-103 (208-115) Attachments: 3K-103 13.375 Casing Test.pdf; Wellhead Packoff test.ppt; 3K-103 as completed.pdf Tom,. I have reviewed the 3K-103 operations and have addressed your questions below with corresponding numbers to your questions. 1. C1n our daily reports, it was recorded that on September 26, the 13-3/8" casing was tested to 3125 psi. for 30 minutes and over that 30 minutes the pressure bled off 25 psi. The casing test was deemed good. E)ur documented practice is to perform the surface casing test. to 3000 psi for 30 minutes and record same on a chart. While the BOP rating is 5000 psi, it is our practice to test as close to 3000 as possible. However,. slight adjustments with the test pump can result in a testing pressure which is slightly above 3000 psi. After inspecting the charted pressure, (see attached 3K-103 13-3/8'° casing test chart) the chart indicates a test pressure of what I would call between. 3050 to 3025 psi over the duration of the test... The disparity between the report and chart may be due to slight difference in readings between the digital gauge and the chart recorder. 2. For all llv'est Sak wells we set intermediate easing on slips to ensure that the string. is in tension and avoid any leaks that may occur if the buttress thread were in compression. In order to set. slips,.. cut easing and set the Packoff, the wellhead is broken. or nippled down between. the casing head and the tubing head. After installing slips and Packoff, the tubing head connection. is again made up to the easing head. Through a test port the following components are tested; Packoff to well head seal, intermediate casing to Packoff seals-and the flange connection between the tubing head and casing head. This test is conducted at 80%: of intermediate collapse rating. Prior to drilling out the shoe, we again test the casing to 3000 psi which further tests the packaff to casing and pa€koff to wellhead seals. In effect the Packoff and associated seals are the sealing mechanism for the break between the tubing and casing head.. I have attached a diagram which illustrates the break and. testing points. 3. The final completion diagram is attached with all pertinent depths.. I would be happy to run over. an elaborate on any of the items above. Thx...Dennis Dennis Hartwig Drilling Engineer Greater Ituparuk Area ConoeoPhillips Alaska - ATO-1592 Office :907-265-6862 Cell :907-575-7109 Fa.~c :907-265-1535 2/5/2009 3K-103 - Doyon 15 - Curren~tus From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, January 12, 2009 11:49 AM To: Hartwig, Dennis D Cc: Alvord, Chip; Regg, James B (DOA) Subject: RE: 3K-103 (208-115) • Page 2 of 2 Dennis, I have reviewed the completion report from the well and have some questions/observations. 1. On September 26, the 13-3/8" casing was tested. It is stated that the casing was pressured to 3125 psi which is greater than the BOP test pressure of earlier that day. Although the BOP rating was SK, it seems unusual to conduct such a test in excess of the test pressure. Please comment on this. 2. On October 5, after setting the 9-5/8" casing it was necessary to ND to cut the casing, set the slips and install the packoff. Nothing is mentioned in the operations summary about shell testing the BOP to verify the "break". It is noted that the choke line was tested, but not the stack. Please look into this and determine if the stack was shell tested. Provide appropriate documentation. 3. This well and the lateral were completed with dedicated tubing strings. While you have included drawings of 3K-103 and 3K-103L1 and they reflect the individual penetrations, unless one is familiar with the wells, it is not clearly shown that the well is equipped with 2 tubing strings. A drawing similar to that supplied with the permit to drill should be provided with the appropriate depths noted. I look forward to your reply. Please note for item 2, the Commission reserves the right to pursue an enforcement action if the BOP stack was not pressure tested after re-NU. Call or message with any questions. Tom Maunder, PE AOGCC __ ~!l""^ ColnataPhillips IBe'MD-I.e7s"DS Nipple 2008 West Sak Dual Injector System 477'M0.2.e75"DS Nipple with Level 5 Rotating self-Aligning Multilateral (RAMT"") System 12e1' Mo- c6tD sllamg sl..v., } ;° z Lett" ax prone 4292' MD- GLM, Cemco, }•/,° x 1" KBG2-8 West Sa k 133/8" Casing Shoe 3 K-103 2540' MD, 2217' TVD (43 deg) 4588' Md AnlfRotation Clamp Dual Tubing Strings 6810' MD-Adjustable Sub with Rotational Lock 3%" 9.7f1 IBT w/SCC L20, 2.992" ID, 2.967" Drift ~~ 4621' MD- 2.750" D Nipple // 4699' MD- } / ° a y3M' GT Dual Packer ~~ 4817 MD- 2.913" DS Nippla / D-Sand Caning Exh / 6675' MD, 3454' TVD 1839' MQ }y.•' a }y." x 9-510" Dual ~ (80 dagj Seal Modue for RAM Hangar ~ 48BJ' MD- 7" %95/9" RAM Hangar 4„_ ~ .a Equipment Specifications 7" X 9-518" RAM Junction Mainbore Drift: 1.88" lateral Drift: 5.80" RAM Hanger/Seal Bore Diverter OD: 8.375" Overall Length of RAM Junction: 38.3 h Seal Bore Diverter Running Tool: FJD RAM Nanger Running Tool: HRDE 3-'/:" x 3-%" 9-518" Dual Seal Module DSM OD: 7.62" lateral Seal Assembly OD: 3.75" Lateral lD: 2.69" Mainbore Seal Stinger OD: 3.08" Mainbore ID: 2.89" ~~~~ ~~ Baker Oil Tools As Completed ( ' n L r I ~ ~\~~ ~~ D Sad ate a 3-'-," 9.3k Liner with Hytlrll 563 antl Liner Shoe sin r conne~eio^s ..1336' MD, 3574' TW ~: ,. /+n+., M.:.:. a9s. irA ..... MA e~6 ,. M--,,. _. 188 dag) ,...-- 12375' MD, 3 78' TVD (8B de 4899' MD- 4-%" /8" RAM Seal Bore Diverter ISBDI for Seal Module ,q ~ 4720' MQ MLMR Production Anchor 4%" 12.ea IBTM a Hytldl 617 TubinO 4711' MD- 7" % 9-618" MLi Liner Hanger P«ker n4o• Mo- serbore R«eptade 475" ID 4747' M6 Seal AesemMy 1.78" Seal 00 3.e76•'lU 'B' Sand Lateral }Y" 9.1a Liner vnm HYtlM 667 m0 ~ aLHT coon«tlona 12411' MD, 3651' TVD (88 deg) 9-518" Casing Shoe, 40.01, L-80 BTC Linar Shoa 5437' MD, 3551' TVD (88 deg) 12324' MD, 3646' TVD (88 dag). - - - - i d.9 ida: _ - oraN9a w: IOeB Wal yak lb[W Lateral Completion - Inpcbr _ _ ~ Ian TawneY IYMrIe„Na: _thP Me: a p'dovmber 19'", 100a pcwn b: ~ 1 t 1 • STATE OF ALASKA R~~EIV~~ ALASKA OIL AND GAS CONSERVATION COM I 4 ZOOS WELL COMPLETION OR RECOMPLETION ORT AND LOG 1a. WeIlStatus: pil ^ Gas Plugged ^ Abandoned Suspended gi2Ska Oil as 20AAC 25.105 20AAC 25.110 Ancho GINJ ^ WINJ ~ WDSPL ^ WAG ^ Other ^ No. of Completions: I g~lopment ^ Exploratory ^ Service ~ ' Stratigraphic Test ^ 2. Operator Name: ConocoPhillips Alaska, Inc. 5. Date Comp., Susp., orAband.: November 19, 2008 ' 12. Permit to Drill Number: 208-116 / 3. Address: P. O. Box 100360, Anchorage, AK 99510-0360 6. Date Spudded: November 6, 2008 13. API Number: 50-029-23392-60 4a. Location of Well (Governmental Section): Surface: 885' FSL, 314' FWL, Sec. 35, T13N, R09E, UM 7. Date TD Reached: November 11, 2008 14. Well Name and Number. 3K-103L1 Top of Productive Horizon: 248' FSL, 2369' FWL, Sec. 35, T13N, R09E, UM 8. KB (ft above MSL): ' RKB 7 Ground (ft MSL): AMSL33,8~ 5. Field/Pool(s): L Kuparuk River Field Total Depth: 1880' FSL, 550' FEL, Sec. 36, T13N, R09E, UM 9. Plug Back Depth (MD + ND): 12334' MD / 3574' TVD f •~-09' West Sak Oil Pool 4b. Location of Well (State Base Plane Coordinates): Surface: x- 529305 y- 6007879 Zone- 4 10. Total Depth (MD + ND): 12375' MD / 3576' TVD . 16. Property Designation: ALK 25519 TPI: x- 531352 y- 6009460 Zone- 4 Total Depth: x- 538995 - 6008918. Zone- 4 11. SSSV Depth (MD + ND): landing nipple @ 470' MD / 470' ND 17. Land Use Permit: 2555 18. Directional Survey: Yes ^/ No ^ (Submit electronic and printed information per 20 AAC 25.050) 19. Water Depth, if Offshore: N/A (ft MSL) 20. Thickness of Permafrost (TVD): approx. 1638' TVD 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): cap of window @ as75' Y~la GR/RES, USIT ,3~s ~{ ~N~ P2• 22. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH ND HOLE CEMENTING RECORD AMOUNT CASING SIZE WT. PER FT. GRADE TOP BOTTOM TOP BOTTOM SIZE PULLED 20" x 34" 94# 40' 120' 40' 120' 42" 151 sx ASI 13.375" 68# L-80 43' 2540' 43' 2217' 16" 628 sx AS Lite, 156 sx DeepCRETE 9.625" 40# L-80 40' 5437' 40' 3551' 12.25" 430 sx LiteCRETE 3.5" 9.2# L-80 4663' 12336' 3452' 3574' 6.75" 3.5 Reslnject screens 23. Open to production or injection? Yes No / If Yes, list each 24. TUBING RECORD Interval open (MD+ND of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET 5027'-5058' MD 3476'-3475' ND 9581'-9612' MD 3519'-3519' ND 3.5" 4703' 4593' 5499'-5530' MD 3482'-3483' ND 10490'-10521' MD 3513'-3512' ND 5947'-5978' MD 3491'-3486' ND 10863'-10895' MD 3514'-3514' ND 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 6482'-6513' MD 3496'-3498' ND 11238'-11270' MD 3521'-3522' ND DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 7047'-7078' MD 3521'-3520' ND 12023'-12054' MD 3569'-3567' ND 7745'-7776' MD 3509'-3507' ND 8301'-8332' MD 3498'-3499' ND 8860'-8892' MD 3492'-3492' ND 26. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) waiting on facility hook-up 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 / Sidewall Cores Acquired? Yes No / ' If Yes to either question, list formations and intervals cored (MD+ND of top and bottom of each), and summarize lithology and presence of oil, gas or water (Submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. ° ~APLEt'CAPI ) NONE ~.IL~# 1Fj~ r f Form 10-407 Revised 2/2007 CONTINUED ON REVERSE SIDE L ~a~ ~ ~ zoos /' ~. • ~ ~~~ ~~~ c 28. GEOLOGIC MARKERS (List all formations and markers encountered): 29. FORMATION TESTS NAME MD TVD Well tested? ~ Yes / No • If yes, list intervals and formations tested, Pemtafrost -Top ground Surface ground surface briefly summarizing test results. Attach separate sheets to this form, if Permafrost -Bottom 1762' 1638' needed, and submit detailed test information per 20 AAC 25.071. Ugnu C 3200' 2709' Ugnu B 3664' 3032' Ugnu A 3836' 3140' N-sand 4113' 3286' K-13 4155' 3305' West Sak D 4677' 3454' West Sak C 4916' 3496' West Sak B 5378' 3546' N/A Formation at total depth: West Sak D r 30. LIST OF ATTACHMENTS Summary of Daily Operations, Directional Survey 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: -1]gnnjs Hartwig @ 265-6862 y~/r~IL. Printed Name G. C. Alvord Title: Drilling Team Leader ~/ Date `~Z~D~i - I , Signature l~I_ ~_ ~ Phone ~ ~ ~ LD ~ INSTRUCTIONS Sharon Allsu/rDrake 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, Sat 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 ~dtICKU~}l!~{ip5 SURFACE, 0-2,540 GAS seal Bore Droercer, 4SSa-a.]s] sueen, 5,02]-5.058 I RMEDIATE,_ - sire 5,5a]-5,9]8 Screen. 6682-6.513 screen, ] 04] ],0]8 screen, ]7457]]6 Scre 8.301-8.332 Screen, 8,860-8,892 Screen, 9,581-5.812 Scra 10 49U10 521 Screen, 10,863-10.655 Screen, 11,239-11,2]0 Srseen, 12,023-12.054 D SAND LINER, 4,663-12,336 12.3]5 KUP 3K-103L1 Max Angle 8 MD TD Well Attributes _ __ Well Status Protl/Inj Type Incl (°) MD (ftKB) Act Btm (ftKB) Wellbore APINWI Fieltl Name ( INJ SWI 93.83 7,782.21 72,375.0 ~, 500292339260 WEST SAK _ Annotat on End Date KBGrd (ft) Rig Release Date 'Comment H25 (ppm) iDate I SSSV~ NIPPLE '~ 0 7/12008 Last WO- I _ _ _ _ (End Date Annotation Annotation Depth (ftKB) Entl Date - ( Last Tag: Rev Reason: NEW WELL i 12/6/2008 Casin Strin s Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (ND) ... String Wt... Strmg ... String Top Thrd D-SAND LINER 3 712 2.992 4,6.63.2_ 12,336.7 3,574.3 9.20 L-80 SLHT Liner Details .._ ... -_____ _.. ... .... _.. _._ __.. _.._. Top Depth (ND) Top Incl Top (ftKB) ~ (ftKB) (°) Item Description Comment ID (in) 4,663.2 3,451.9 79.97 HANGER RAM Hanger, (above LEM Profile to Top of RAM Hanger) 6.760 4,665.7 3,4524 80.05 HANGER RAM Hanger, (above Collet into LEM Profle) 6.750 4,670.7 3,453.3 80.22 HANGER RAM Hanger, 6.625", 20 ppf, Hydril 521 (Below Collet) Pin down this will 6.750 be 4670.70' 4,699.8 3,457.8 81.19 XO- Reducing Cross over- Ported 6-6/8", 20 ppf, Hydril 521 z 4-1/2" Hyddl 521 3.750 4,704.5 3,458.4 81.34 XO -Reducing Crossover 4-1/2" hyd 521 box x 3-12" hyd 563 pin 4.71" OD x 3.00" 3.000 ID Top Incl Comment lal 13-3/8" x 3-1/2" x 3-1/2" "DS" Nipple w/ 2.875" Profi cker -Dual Baker"GT" Dual Packer Mandrel (3-1/Z" NU lUrd Boz z Pln) [.ys ' -- _ cker -Dual Baker 9-SB" z 3-1/2" "GT" Retnevable Dual Packer (40K Shear Release) 2.92 cker -Dual Baker "GT" Dual Packer Mandrel (3-1/2" NU 10rd Boz z Pin) 2.92 ~PLE 3-1 /2" Camco "D" Nipple w/ 2.75" No-Go Profile (EUE SrdP x B) 2.75 tension Jt Baker 3.38", L-80, "DSM" Extension Joint (3.220" SSDS Boxz Pin) 2.69 al Seal Mod Baker 3.38", L-80, "DSM" Extension Joint Mandrel (3.220" SSDS Box x 2.69 Pin) al Seal Mod ',Baker 7" x 9-5/8" "RAM" Dual Seal Module (Above Collet) 2 69 al Seal Mod ~~~ Baker 7" x 9-SIS" "RAM" Dual Seal Module (Below Collet) 2 69 AL ASSY Shrouded Seal Assembly (Shear Fbrce 14,3501bs.) 2.69 - -_ shot _. ~ ~,-- Btm (TVD) Dens 5,027.1 1 5,057.8 3,475.7 3 474.5 WS D, 3K-103L1 1 11/15/2008 99 0 Screen Alternating solm pipe/screens 5,499.0 1 5,529.6 3,481.6 3 482.8 WS D, 3K-103L1 1 11/152008 99.0 Screen Alternating solid pipe/screens 5,947.2 ~. ; 5,977.8 _ 3,490.8 3 486.3 WS D, 3K-103L7 ~I 11/15/2008 99.0 Screen _.. Alternating solitl pipe/screens 8,482.4 1 6,513.0 3,495.9 3,498.3 WS D, 3K-103L7 ~ 11/15/2008 99.0 Screen Alternating solid pipeJSCreens 7,046.7 7,078.1 3,520.6 3,520 4 WS D, 3K-103L7 11/15/2008 99.0 Screen ~i Alternating solid pipe/screens 7,745.0 7,776.3 3,509.2 3,506.8 WS q 3K-103L7 11/15/20D8 99.0 Screen ( Alternating solid pipe/screens 8,300.6 8,332.0 '' 3498.3 ~ 3,498.6 WS D, 3K-103L7 11/152008 99.0 Screen Alternating solid pipe/screens 8,860.1 8,89 t6 ~i 3,491.7 3 492.1 WS Q 3K-103L7 11/15/2008 99 O' Screen Alternating solid pipe/screens 9,580.6 9,612.0 3,518.5 3,518.8 WS D, 3K-103L1 11/15/2008 ~ ' 99.O~ Screen Alternating solid pipe/screens 10,489.6 10,521.0 3,513.0 3,512 4 WS D, 3K-103L1 11/15/2008 99.0 Screen Alternating solid pipe/screens 10,5631 ' 10,894.5 3,513.5 3,514.1 WS D, 3K-103L1 ' 11/152008 99.0 Screen Alternating solid pipe/screens 11,238.7 11,270.0 3,520.9 3,522.3 WS D, 3K-103L7 11/15/2008 ~. 99.0 Screen Alternating solid pipe/screens 12,022.6 12,054.0 3,568.7 3,566.8 WS D, 3K-103L7 11/152008 990 Screen Alternating solid pipe/screens 7 landrel Details ToP D Pih p _._ _.. -- __.- - __ __ Port .. - __ --_-_ I D (T 1 n OD Valve Latch Size T RO R n ftKB) P ) I (°) Make Mod I (i_nl Sere TvPa TYPe ('ul (P_ l Run D t Comm... 1 L 4,291 6~- .3,360.8 6 7.G8 CAMCO KBG-9-2 If 11Gas Lft SOV INT 0 00 11/1612008 DCK-3 ~ ~ Time Lo s Date From To ` 'bur S. De th E: De th Phase Code' Subcode T Comment 03:15 06:30 3.25 12,410 12,311 COMPZ DRILL CIRC T Pump 25 bbls of LVT, 64 bbls transition spacer, 290 bbls of vis brine, 310 bbls versa out breaker. Pumping @ 5 bpm w/ 870 psi. Rotate 100 rpm w/ 9 to 10k ft Ibs of torque. Reciprocate from 12406' to 12311'. PU wt 185k, SO wt 118k, Rot wt 150k. 06:30 07:00 0.50 12,311 12,311 COMPZ DRILL OWFF T Monitor well. Lossing a little, fluid fallin .Blow down to drive. 07:00 10:45 3.75 12,311 7,168 COMPZ DRILL TRIP T Pull out of the hole on elevators. Monitor displacement on the pill pit. Record PU and slackoff wt's every 10 stands. 10:45 11:00 0.25 7,168. 7,168 COMPZ DRILL PULD T Change handling tools from 5" to 4". 11:00 12:15 1.25 7,168 5,187 COMPZ DRILL TRIP T Continue to pull out of the hole on elevators. Monitor displacement on the pill pit. Record PU and slackoff wt's eve 10 stands. 12:15 14:00 1.75 5,187 5,092 COMPZ DRILL CIRC T Circulate 9.2 ppg brine while reciprocating from 5187' to 5092'. Pumping 5 bpm w/ 350 psi. Rotate 30 rpm w/ 4k ftlbs of torque. PU wt 132k, SO wt 115k, rot wt 125k. Pum ed a total of 402 bbls. 14:00 16:15 2.25 5,092 5,092 COMPZ DRILL OTHR T Clean and clear rig floor. Clean trip tank. Fill tank with brine. 16:15 17:45 1.50 5,092 282 COMPZ DRILL TRIP T Continue to pull out of the hole on elevators. Monitor displacement on the trip tank. Record PU and slackoff wt's eve 10 stands. 17:45 18:00 0.25 282 0 COMPZ DRILL PULD T Lay down BHA #16. 18:00 19:00 1.00 0 0 COMPZ CASING RURD T Rig up to run the 3-1/2"SLHT and Hyd 563 9.2 ppf L-80 screen and, blank liner for the "B" lateral. 19:00 20:00 1.00 0 0 COMPZ CASING OTHR T Verify super slim MWD crossover connections are for ued. 20:00 20:15 0.25 0 0 COMPZ CASING SFTY T Pre job safety meeting on running liner for the "B" lateral. 20:15 00:00 3.75 0 3,390 COMPZ CASING RUNL T Run the 3-1/2" liner per detail. Record PU and SO wt's every 10 jts. to 3390' at midnight. (108 jts in the hole . Averera a losses of 11 b h. 11 /05/2008 Continue to run the liner f/ "B" lateral from 3390' to 12093', start rotating liner in the hole to 12328', orient, drop Baker Oil Tools 1-3l4" ba-I, pump to seat with shoe @ 12325' (TOL @ 4713.26'), set flexlock liner hanger/MLZXP packer, test annulus/packer to 2500 psi f/ 5 min (good test). Pickup 7', then tag with dog sub verifying liner top @ 4713.26'. Pull out of hole to 4565', pump a dry job, pull out /lay down running tools and MWD. Clear floor. Remove backup wrench from top drive to perform preventative maintenance (replace seals on grabbers). Prejob safety meeting on PUlMU Whipstock assembly. Bring tools to the floor. MU whipstock assembl for the "D" lateral. Orient ali nment of anchor with whi stock face. 00:00 02:15 2.25 3,390 6,100 COMPZ CASING RUNL T Continue to run the 3-1 /2" 9.2 ppf L-80 SLHT connection liner per detail from 3390' to 6100'. Record PU and SO wfs every 10 jts. Avererage losses of 11 b h. PageSd of 72 u Time Lo s Date From To' Duc S. De th E. De th Phase Code Subcode T Comment 02:15 02:30 0.25 6,100 6,100 COMPZ CASING RUNL T Make up the crossover to 3-1 /2" hyd 563. Change the crossover on floor safe valve. 02:30 03:30 1.00 6,100 7;494 COMPZ CASING RUNL T Continue to run the 3-1/2" 9.2 ppf L-80 Hyd 563 connection liner per detail from 6100' to 7494'. Record PU and SO wt's every 10 jts. Avererage losses of 11 b h. 03:30 04:15 0.75 7,494 7,583 COMPZ CASING RUNL T Make up Baker MXZXP han er/Packer assembl . 04:15 04:30 0.25 7,583 7,583 COMPZ CASING RUNL T Make up Sperry Sun super slim MWD to liner han er. 04:30 05:00 0.50 7,583 7,620 COMPZ CASING RUNL T Continue to make up Baker liner han er assembl . 05:00 05:15 0.25 7,620 7,620 COMPZ CASING DHEO T Pickup/makeup stand of 5" drillpipe. Shallow pulse test Sperry Sun MWD. Pumping 100 gpm w/ 910 psi- 12%floty- Rotate with 30 rpm and 3k ft Ibs of torque. PU wt 110k, SO wt 94k, Rot wt 110k. 05:15 05:30 0.25 7,620 7,710 COMPZ CASING OTHR T Install stripper rubber. Blow down the top drive. Remove crossover from floor safe valve. 05:30 05:45 0.25. 7,710 8,488 COMPZ CASING RUNL T Trip in the hole with the liner on 5" drill pipe. Average losses 11 bbls per hour. Monitor displacement on the tri tank. 05:45 06:00 0.25 8,488 8,860 COMPZ CASING RUNL P Continue trip in the hole with the liner on 5"drill pipe. Average losses 11 bbls per hour. Monitor displacement on the trip tank. 06:00 08:45 2.75 8,860 12,093 COMPZ CASING RUNL P Continue trip in the hole with the 3-1/2" SLHT &Hyd 563 9.2ppf L-80 screen/blank "B" lateral liner on 5" drill pipe. Average losses 11 bbls per hour. Monitor displacement on the trip tank. Record PU and SO wt's eve 5 stands. 08:45 12:00 3.25 12,093 12,320 COMPZ CASING RUNL P Continue running liner with rotation starting at 12093' to 12320'.. Rotate 50 RPM w/ 8-10k ft Ibs of torque.Pumping 42 gpm w/ 150 psi. PU wt 175k, SO wt 110k, rot wt 150k. 12:00 13:15 1.25 12,320 12,328 COMPZ CASING RUNL P Continue running liner with rotation starting at 12093' to 12320'.. Rotate 50 RPM w/ 8-10k ft Ibs of torque.Pumping 42 gpm w/ 150 psi. PU wt 175k, SO wt 110k, rot wt 150k. 13:15 14:45 1.50 12,328 12,328 COMPZ CASING CIRC P Reciprocate from 12328' to 12308' while pumping 130 gpm with 1200 psi to orient Baker MLZXP liner packer. Oriented packer to 10 deg left of highside. PU wt 175k, SO wt 118k, Rot wt 150k. Page 51 of 72 ~ ~ Time Lo s Date Fram To Dur S: De th E De th Phase -Code ' Subcode T ' Comment 14:45 15:00 0.25 12,328 12,328 COMPZ CASING OTHR P Pull out from 12328' to 12256'. Drop Baker's 1-3/4" ball. Trip back in to 12328'. 15:00 15:30 0.50 12,328 12,325 COMPZ CASING OTHR P With liner shoe @ 12325.43' and 120k on wt indicator--pumping ball down with 118 gpm w/ 980 psi. MWD toolface updates showing 10 deg left of highside. Ball on seat with 572 strokes (57.6 bbls). Continue pumping, pressure up to 1800 psi, slack off 50k on hanger, increase pressure to 4000 psi. Observe packer set @ 2600 psi, then neutralize @ 3200 psi. Bleed off ressure. 15:30 15:45 0.25 12,325 12,325 COMPZ CASING DHEQ P Pressure up backside (Down the kill line with Hydril shut) to test MLZXP packer to 2500 psi for 5 min. Good test. Chart test. 15:45 16:00 0.25 12,325 4,565 COMPZ CASING RUNL P Pickup 7', then slack off and tag with dog sub to verify top of liner @ 4713.26'. Continue to pull out of the hole to 4565'. PU wt 155k, So wt 138k. 16:00 16:15 0.25 4,565 4,565 COMPZ CASING CIRC P Pump a dry job. 18 bbls 9.8 ppg. Blow down the to drive. 16:15 17:45 1.50 4,565 67 COMPZ CASING RUNL P Trip out of the hole with liner running tools. Monitor well on the trip tank. Record PU and SO wt's every 10 stands. 17:45 18:30 0.75 67 0 COMPZ CASING OTHR P Lay down Sperry Sun super slim MWD and Baker liner rennin tools. 18:30 19:00 0.50 0 0 COMPZ CASING OTHR P Clean and clear rig floor. Average of 7 b h losses. 19:00 20:30 1.50 0 0 COMPZ RIGMNT RGRP T Remove backup wrench from top drive. Goal is to repair seals on the rabbet c tinder. 20:30 20:45 0.25 0 0 PROD2 STK OTHR P Pre job safety meeting on picking up Baker whipstock assembly for the "D" lateral. 20:45 21:45 1.00 0 0 PROD2 STK PULD P Bring tools to the rig floor. 21:45 23:30 1.75 0 49 PROD2 STK PULD P Make up Baker milling assembly. Monitor losses to be average 7 bbl er hour. 23:30 00:00 0.50 49 49 PROD2 STK OTHR P Orient helix of anchor with whipstock face. Oriented to be in alignment with face of whipstock. Note: For the day: While circulating lost 56 bbls to the formation. For the trip lost 58 bbls of 9.2 brine. Page 52 of 72 M Tirne Logs -- _ T Comment Dur S Depth E. Depth Phase Code Subcode Date From To 11/06/2008 _ __ 2a hr summary Continue to orient alignment of anchor with whipstock face. continue to makeup BHA, orient MWD to whipstock face (offset 236 deg), upload MWD, continue makeup assembly, shallow pulse test, pre job safety meeting on installing backup wrench on the top drive, install same, trip in the hole with assembly to 4208', MAD pass to 4268', continue trip in the hole to 4713', orient to 7 deg left of high side, latch anchor into collet profile of MLZXP profile (30k down), pull 20k over, set down 42k shear bolt, pickup with no over pull, displace well to OBM @ 4671', SPR's and milling parameters, mill from TOW @ 4675.19' to BOW @ 4692.08', continue to mill to 4722' (30' of 8-1 /2" hole below BOW), work mills through window-OK, circulate hole clean, rig up for formation integrity test, perform test to 13.1 ppg, rig down equipment, trip out with milling assembly to 1792' at midni ht. 00:00 00:30 0.50 49 49 PROD2 STK OTHR P Orient helix of anchor with whipstock face. Oriented to be in alignment with face of whi stock. No offset. 00:30 01:15 0.75 49 103 PROD2 STK PULD P Continue to make up whipstock BHA. 01:15 02:00 0.75 103 134 PROD2 STK PULD P Makeup Sperry Sun MWD. 02:00 02:30 0.50 134 134 PROD2 STK OTHR P Orient MWD with face of whipstock. Offset is 236.35 degrees to face of the whi stock. 02:30 03:00 0.50 134 134 PROD2 STK OTHR P Upload MWD. 03:00 03:30 0.50 134 233 PROD2 STK PULD P Continue to make up milling assembly- install bumper sub and a stand of 5" HWDP. 03:30 04:00 0.50 233 233 PROD2 STK CIRC P Shallow pulse test Sperry Sun MWD. Pumping 650 gpm w/ 1340 si. Good test. Blow down to drive. 04:00 05:15 1.25 233 233 PROD2 RIGMNT RGRP T Pre job safety meeting on installing back-up wrench on the top drive. Install backup to the top drive after re air of tinder seals. 05:15 05:30 0.25 233 509 PROD2 STK TRIP P Continue to makeup BHA assembly- 3 more stands of 5" HWDP. 05:30 06:00 0.50 509 1,367 PROD2 STK TRIP P Trip in the hole with the whipstock for the "D" lateral on 5"drill i e. 06:00 08:30 2.50 1,367 4,208 PROD2 STK TRIP P Continue trip in the hole with the whipstock for the "D" lateral on 5" drill pipe. Fill pipe @ 2888'. Pumping 530 m w/ 1160 si 44% flow out. 08:30 09:15 0.75 4,208 4,268 PROD2 STK TRIP P Mad Pass logging from 4208' to 4268'. Pumping 518 gpm w/ 1200 psi 40% flow out. PU wt 160k, SO wt 142k. 09:15 09:30 0.25 4,268 4,600 PROD2 STK TRIP P Continue trip in the hole with the whipstock for the "D" lateral on 5" drill pipe. Monitor displacement on the tri tank. 09:30 10:00 0.50 4,600 4,713 PROD2 STK TRIP P Continue trip in the hole with the whipstock for the "D" lateral on 5" drill pipe from 4600' to 4713'. Circulating while orienting whipstock to 7 deg left of highside. Pumping 525 gpm w/ 1260 psi. PU wt 160k, SO wt 142k. Page 53 vf,72 ~~.i Time Logs 'i _ _ _ _____ ~ Date From To Dur S Depth E. De th Phase Code Subcode T Comment ___ __ 10:00 10:30 0.50 4,713 4,671 PROD2 STK TRIP P Continue trip in the hole with the whipstock for the "D" lateral on 5" drill pipe from 4713' (top of liner). Observed 10k drag @ 4723' (Seals), continue to 4726'. Set down 30k, Pick up to 180k on weight indicator (20K Overpull-latched in with collet), slack off to 100k to shear bolt holding milling assembly to whipstock (45k bolt was installed). Pickup and observe no overpull to 4671'. PU wt 155k, SO wt 138k, rot wt 145k. _ ~ L ~ Note: After tagging with the whipstock/milling assembly, the liner tally was adjusted to reflect depth of tag (1.73' higher). Casing tally reflects top of liner @ 4711.53' with shoe 12323.7' 10:30 11:30 1.00 4,671 4,671 PROD2 STK CIRC P Displace well to 9.2 ppg OBM. Pumping 465 gpm w/ 1570 psi- 47% flow out. Oil base mud to surface after pumping 371 bbls.. PU wt 155k, SO wt 138k, rot wt 145k. 11:30 11:45 0.25 4,671 4,671 PROD2 STK CIRC P Obtain slow pump rates. Set depth on totco, establish milling arameters. 1:45 12:00 0.25 4,671 4,676 PROD2 STK WPST P Trip in to top of whipstock @ 4675.19'. Mill lug on whipstock and 8-1l2" window for "D" lateral from ~,L ` l ~ ~ ~~ ,.. w ~ `~ TOW @ 4675.19'. Weight on bit 2 to - 4k, 80 rpm, torque off 5k ft Ibs, torque on 6-10k ft Ibs. Pumping 500 m w/ 2110 si, flow out 45% 12:00 18:00 6.00 4,676 4,717 PROD2 STK WPST P Continue to mill window from 4676' to 4717'. Weight on bit 10-12k, 50-60 rpm w/ 5k torque off bottom, 4-8k ft Ibs on bottom. Pumping 350 gpm w/ 960 psi. PU wt 155k, SO wt 140k, Rot wt 145k. 18:00 18:45 0.75 4,717 4,722 PROD2 STK WPST P Continue to mill window from 4717' to 4722'. Weight on bit 10-12k, 50-60 rpm w/ 5k torque off bottom, 4-8k ft Ibs on bottom. Pumping 350 gpm w/ 960 psi. PU wt 155k, SO wt 140k, Rot wt 145k. 18:45 19:15 0.50 4,722 4,722 PROD2 STK CIRC P Work milling assembly thorugh window with and without pumps on. 2-3k dra . 19:15 21:15 2.00 4,722 4,675 PROD2 STK CIRC P Circulate bottom's up @ 4675'. Pumping 444 gpm w/ 1310 psi. Pump a 29 bbls sweep (9.2 ppg/ 127 vis}. Increase rate to 510 gpm w/ 1690 psi. Pumped a total of 1094 bbls. 21:15 21:30 0.25 4,675 4,639 PROD2 DRILL FIT P Stand back a stand. Rig up to perform a formation integrity test to 13.1 Page ~1 ot'2 f • Time Logs _~ Date From To Dur __ S Depth E. De th Phase Code Subcode T Comment _ 21:30 22:15 0.75 4,639 4,639 PROD2 DRILL FIT P Perform FIT with BOP test pump. 9.2 ppg mud 710 psi 3454' TVD @ top of window. FIT to 13.1 .Chart test. 22:15 22:30 0.25 4,639 4,639 PROD2 DRILL FIT P Rig down es mg equipment. 22:30 22:45 0.25 4,639 4,639 PROD2 STK OTHR P Monitor well- static. 22:45 23:00 0.25 4,639 4,266 PROD2 STK TRIP P Pull out of the hole from 4639' to 4266'. Monitor well on the tri tank. 23:00 23:15 0.25 4,266 4,266 PROD2 STK CIRC P Pump a 24 bbl dry job, then blow down the to drive. 23:15 00:00 0.75 4,266 1,792 PROD2 STK TRIP P Continue to pull out of the hole with 8-1/2"millin assembl to 1792' 11 /07/2008 Continue trip out with milling assembly from 1792', lay down milling assembly, mills full guage, download Sperry MWD, clear floor. Pull Vetco/Gray wearbushing, flush stack, install wear bushing. Pre job safety meeting, PU/MU Drilling assembly for "D" lateral, run in to 4615'. Slip and cut 101' of 1-3/8"drilling line, service rig. Continue to trip past whipstock top @ 4675.19' to BOW @ 4692' to 4722'. Directional drill "D" lateral with 6-3/4" Hu hes PDC and S er Sun motor w/ 1.22 de bend from 4722' to 5666'. 00:00 00:30 0.50 1,792 460 PROD2 STK TRIP P Continue to pull out of the hole with 8-1 /2" milling assembly from 1792' to 460'. Hole took proper fill. Monitor well- static. 00:30 01:00 0.50 460 85 PROD2 STK PULD P Lay down BHA. 01:00 01:15 0.25 85 85 PROD2 STK OTHR P Download Sperry Sun MWD. Clean floor. Cleanin its #1, #2 and #5. 01:15 02:00 0.75 85 0 PROD2 STK PULD P Continue to lay down milling BHA. 02:00 02:45 0.75 0 0 PROD2 STK PULD P Clean and clear rig floor of Baker Oil Tools millin a ui ment. 02:45 03:00 0.25 0 0 PROD2 DRILL OTHR P Pull Vetco Gray wear bushing. 03:00 04:00 1.00 0 0 PROD2 DRILL CIRC P Flush stack-pumping 818 gpm w/ 330 si. 04:00 04:30 0.50 0 0 PROD2 DRILL OTHR P Install Vetco Gray wear bushing. 04:30 04:45 0.25 0 0 PROD2 DRILL SFTY P Pre job safety meeting on picking up/ makin u BHA #18. 04:45 06:00 1.25 0 93 PROD2 DRILL PULD P Pickup SperryDrill motor, adjust bend from 1.5 deg to 1.22 deg, PU TM, PWD, Directional, Gamma/Res, stabilizer and float sub. 06:00 08:15 2.25 93 93 PROD2 DRILL PULD P Torque connections to 10k ft Ibs 3-1/2" IF , U load S er Sun MWD. 08:15 08:30 0.25 93 369 PROD2 DRILL TRIP P Continue with BHA #18 (6-3/4" bit, S er Drill motor 1.22 de bend. 08:30 10:00 1.50 369 4,615 PROD2 DRILL TRIP P Trip in the hole w/ BHA #18. Monitor displacement on the trip tank. Record PU and SO wt's every 10 stands. Filled pipe @ 2727' pumping 300 gpm w/ 2410 psi- 36% flow out. Filled pipe @ 4615' pumping 300 gpm w/ 2560 psi- 35% flow out. PU wt 130k, SO wt 115k. 10:00 11:15 1.25 4,615 4,615 PROD2 RIGMNT SVRG P Slip and cut drilling line. Cut 101'. Adjust and inspect brakes. Monitor well on the tri tank. 11:15 12:30 1.25 4,615 4,615 PROD2 RIGMNT SVRG P Service rig, top drive, blocks, drawworks. Page 55 of 72 • • Time Logs __ _ __ _ Date From To Dur S. De th E. D . th Phase Code Subcade T Comment 12:30 13:15 0.75 4,615 4,722 PROD2 DRILL TRIP P __ Trip in past whipstock after orienting to hi h side from 4615' to 4670'. 9 Pumping 300 gpm w/ 2530 psi- 35% flow out. Trip in with out the pumps f/ 4670' to 4713'. Obtain slow pump rates. Orient to highside, then wash to bottom. PU wt 130k, SO wt 115k. 13:15 18:00 4.75 4,722 5,095 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas observed 652 units. 18:00 00:00 6.00 5,095 5,666 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 1082 units. 11 /08/2008 Continue to directional drill "D" lateral with 6-3/4" Hughes PDC and Sperry Sun motor w/ 1.22 deg bend from 5666' to 7908'. 00:00 06:00 6.00 5,666 6,282 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 1515 units. 06:00 12:00 6.00 6,282 6,809 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SpenyDrill w/ 1.22 deg bend motor. Max gas obseved 1317 units. 12:00 18:00 6.00 6,809 7,474 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3l4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 776 units. 18:00 00:00 6.00 7,474 7,908 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 846 units. 11 /09/2008 Continue to directional drill "D" lateral with 6-3/4" Hughes PDC and Sperry Sun motor w/ 1.22 deg bend from 5666' to 7908' to 8140', circ two bottom's up, monitor well, pull out of the hole 37 stands of 5" to 4615', monitor well, change elevators, service rig, ,install 33 stands of 4"drill pipe to 7728', change elevators, install PBL sub after 1st single of 5"drill pipe, run in the hole to 8045', survey, trip to 8120', survey, wash to bottom 8140', continue to drill the "D lateral from 8140' to 9263'. 00:00 03:00 3.00 7,908 8,140 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 846 units. 03:00 04:30 1.50 8,140 8,000 PROD2 DRILL CIRC P Circulate two bottoms up. Recip pipe from 8140' to 8000'. Pumping 315 gpm w. 2870 psi, 34% flow out. Rotate 120 rpm w/ 6k ft Ibs of torque. Pum ed a total of 623 bbls. 04:30 04:45 0.25 8,000 8,045 PROD2 DRILL OWFF P Monitor well- static. 04:45 05:00 0.25 8,045 7,953 PROD2 DRILL CIRC P Obtain slow pump rates. Pump a 26 bbl dry job (11.2 ppg/78 vis). Blow down the to drive. image 56 of 72 ~ • 'Time L©gs Date From To Dur S. De th E. De th Phase Code__ Subcod_e_ _T_ Comment 05:00 07:30 2.50 7,953 4,615 PROD2 DRILL TRIP , P Pull out of the hole 37 stands of 5" drill pipe --objective is to install 33 more stands of 4"drill pipe and the PBL sub above the first single of 5" drill pipe. Record PU and SO wt's every 5 stands. Monitor well on the trip tank. Depth 4615': PU wt 148k, SO wt 120k. 07:30 07:45 0.25 4,615 4,615 PROD2 DRILL OWFF P Monitor well- static. Change elevators to 4". Clean ri floor. 07:45 08:45 1.00 4,615 4,615 PROD2 RIGMNT SVRG P Service top drive, blocks, drawworks. Monitor well on the tri tank. 08:45 09:45 1.00 4,615 7,255 PROD2 DRILL TRIP P Trip in the hole with 28 stands of 4" drill pipe. PU wt 148k, So wt 110k. Record PU and SO wt's every 5 stands. Monitor well on the tri tank. 09:45 10:00 0.25 7,255 7,727 PROD2 DRILL TRIP P Pickup and make up/run in the hole with 5 stands (15 joints) of 4"drill pipe from the pipe shed. Record PU and SO wt's every 5 stands. Monitor well on the tri tank. 10:00 10:15 0.25 PROD2 DRILL OWFF P Monitor well- static. Change elevators to 5". 10:15 10:45 0.50 7,727 7,836 PROD2 DRILL TRIP P Make up first stand of 5"drill pipe. Break first single and install Downhole Devices circulating sub PBL. 10:45 11:00 0.25 7,836 8,045 PROD2 DRILL TRIP P Continue trip in the hole with 5" drill i e. 11:00 11:45 0.75 8,045 8,140 PROD2 DRILL TRIP P At 8045': Acquire deviation survey, mode switch MW. Continue in the hole to 8120', survey, wash and ream to bottom @ 8140'. Pumping 320 m. PU wt 148k, SO wt 110k. 11:45 12:00 0.25 8,140 8,192 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 406 units. 12:00 18:00 6.00 8,192 8,742 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 840 units. 18:00 00:00 6.00 8,742 9,263 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 1105 units. 11/10/2008 Continue to directional drill "D" lateral with 6-3/4" Hughes PDC and Sperry Sun motor w/ 1.22 deg bend from 9263' to 10690', Pump a 40 bbls sweep (11.0 ppg/ 57 vis)-slight increase incuttings, continue to directional drill "D" lateral from 10690' to 11373'. 00:00 06:00 6.00 9,263 9,739 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 1105 units. 06:00 12:00 6.00 9,739 10,392 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 840 units. Rage 57 of 72 `~ Time Logs - -~ .'Date From To Dur S. De th E. De th Phase Code Subcode T Comment 12:00 15:30 3.50 10,392 10,690 PROD2 DRILL DDRL P _ Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 719 units. 15:30 17:15 1.75 10,690 10,690 PROD2 DRILL CIRC P Pump a 40 bbl sweep (11ppg/ 57 vis). Pumping 315 gpm w/ 3390 psi-34% flow out. Rotate 120 rpm w/ 7k ft Ibs of torque. Pumped a total of 710 bbls. Max gas observed 447 units. Obtain slow pump rates. Note: Slight increase in cuttings. ECD's before 11.52 ppg, after 11.37 17:15 18:00 0.75 10,690 10,785 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 389 units. 18:00 00:00 6.00 10,785 11,373 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 920 units. 11/11!2008 Continue to directional drill "D" lateral with 6-3/4" Hughes PDC and Sperry Sun motor w! 1.22 deg bend from 11373' to 11832', circulate to reduce ECD's from 11.9 to 11.5 ppg, continue to directional drill "D" lateral from 11373' to 12375' (TD of "D" lateral), circulate 6 bottom's up @ 320 gpm w/ 3370 psi, open circulation sub (Downhole Devices- PBL), circulate 6 bottom's up @ up to 800 gpm w/ 1750 psi, drop ball and close circulating sub, monitor well- static, pull out of the hole on elevators to 11454', pump a dry job, blow down top drive, continue to ull out of the hole to 10218' midni ht. 00:00 05:30 5.50 11,373 11,832 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 920 units. 05:30 07:00 1.50 11,832 11,832 PROD2 DRILL CIRC P Circulate to reduce ECD's. Pumping 310 gpm w/ 3350 psi.- 34% flow out. Reciprocate from 11802' to 11738'. Rotate 120 rpm w/ 8k ft Ibs of torque. Initial ECD's 11.9 ppg, final 11.5 ppg. Circualted a total of 622 bbls. 07:00 12:00 5.00 11,832 12,278 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 920 units. 12:00 13:00 1.00 12,278 12,375 PROD2 DRILL DDRL P Directional drill "D" lateral with 6-3/4" Hughes PDC and SperryDrill w/ 1.22 deg bend motor. Max gas obseved 920 units. 13:00 19:15 6.25 12,375 12,375 PROD2 DRILL CIRC P Circulate 6 bottom's up. Pumping 320 gpm w/ 3370 psi- 34% flow out. Reciprocate from 12375 to 12305'. Rotate 120 rpm w/ 8000 ft Ibs of torque. Pumped a totatl of 2812 bbls. Max gas observed was 674 units. Monitor well- static. Rage 58 of 72 • A ' Tirite Logs. _ _ Date From To Dur S. De` th E. De th Phase; Gode Subcode T Comment 19:15 19:30 0.25 12,375 12,375 PROD2 DRILL CIRC P Obtain pump parameters. 20 spm 650 psi, 30 spm 850 psi. Drop 2" Torlon ball, then pump down @ 6 bpm w/ 2150 psi- 30% flow out for 575 strokes, slow down to 2bpm w/ 650 psi until ball on seat (600 strokes). Observed the pressure drop from 650 si to 350 si. 19:30 21:15 1.75 12,375 12,375 PROD2 DRILL CIRC P Increase pump rate to 325 gpm w/ 560 psi- 36% flow out, no detection by MWD. Increase rate to 500 gpm w/ 680 psi-44% flow out for one bottom's up~no downhole mud losses observed). Then increased pump rate to 800 gpm w/ 1750 psi- 58%floty out. Reciprocated pipe from 12375' to 12305'. Every 20 minutes the pipe was rotated 50 rpm for 2 to 3 minutes. Circulated a total of 1451 bbls (6 bottom's up from circulating sub. 21:15 21:30 0.25 12,375 12,375 PROD2 DRILL CIRC P Drop (2) 1-3/8" steel balls to close the Downhole Devices PBL sub. Pumped balls down @ 6 bpm w/ 400 psi- 30% flow out for 414 strokes. Observed the pressure increase to 2700 psi, then drop. Increased rate pump rate to 300 gpm w/ 2820 psi-33% flow out. MWD was detectin ulses. 21:30 21:45 0.25 12,375 12,375 PROD2 DRILL OWFF P Monitor well- static. 21:45 22:30 0.75 12,375 11,454 PROD2 DRILL TRIP P Pull 10 stands out of the hole on elevators. Monitor hole fill- proper displacement. PU wt 190k, SO wt 120k. Obtain PU and SO wt's every 5 stands. 22:30 22:45 0.25 11,454 11,454 PROD2 DRILL CIRC P Pump a dryjob. Blow down the top drive. 22:45 00:00 1.25 11,454 10,218 PROD2 DRILL TRIP P Pull out of the hole on elevators. Monitor hole fill- proper displacement. Obtain PU and SO wt's eve 5 stands. 11 /12/2008 Continue to pull out of the hole from 10218' to 7730', Retrieve balls from Downhole Devices PBL circulating sub, lay down same, change handling tools to 4", Continue to pull out of the hole to BHA @ 372'. Lay down drilling BHA including download of Sperry Sun. Clean and clear rig floor. Pickup cleanout BHA to 301', trip in the hole on elevators to 7659', pickup two more joints of 4" drill pipe, install crossover to 5", change handling tools to 5", install (2) string magnets, trip in the hole to TD @ 12375', lay down a single, rotate and reciprocate from 12375' to 12280 while VersaOut breaker is being mixed @ MI mud plant in Deadhorse, um in 320 m w/ 2050 si. l=ags S9 of 72 • • Time Logs _ _ _ Date From To _ Dur S. De th E. De th Phase Code Subcode T Comment 00:00 06:00 6.00 10,218 370 PROD2 _ DRILL TRIP P Continue pulling out of the hole on elevators. Monitor hole on trip tank. Obtain PU and SO wt's every 5 stands in open hole, every 10 stands in casing. Note: Pulled through window good. No overpull. Hole took proper dis lacement. 06:00 07:15 1.25 370 96 PROD2 DRILL PULD P Lay down drilling BHA. 07:15 08:00 0.75 96 96 PROD2 DRILL OTHR P Download MWD. Grease crown, clear and clean floor. 08:00 09:15 1.25 96 0 PROD2 DRILL PULD P Continue to lay down BHA. 09:15 09:30 0.25 0 0 PROD2 DRILL OTHR P Clean and clear rig floor. 09:30 10:30 1.00 0 301 COMPZ DRILL PULD P Pickup/ makeup cleanout BHA. Monitor well on the tri tank. 10:30 13:30 3.00 301 7,659 COMPZ DRILL TRIP P Trip in the hole with 4" drill pipe. PU wt 150k, SO wt 110k 13:30 14:00 0.50 7,659 7,748 COMPZ DRILL PULD P Pickup two joints of 4" drill pipe, makeup the 4" x 5" crossover, change elevators then two string ma nets. 14:00 16:15 2.25 7,748 12,317 COMPZ DRILL TRIP P Continue trip in the hole with 5" drill pipe. Monitor displacement on the trip tank. Fill pipe every 25 stands. Hole took proper dispaaement. PU wt 182K, SO wt 110k. 16:15 16:45 0.50 12,317 12,375 COMPZ DRILL CIRC P Fill pipe, tag bottom 7' deep, lay down a sin le. TD is 12375'. 16:45 00:00 7.25 12,375 12,375 COMPZ DRILL CIRC P While NaCUKCL VersOut breaker w/ 3% Safelube is being mixed at MI Swaco plant in Deadhorse--Circulate 320 gpm w/ 2050 psi- 34% flow out. Rotate 70 rpm w/ 8k ft Ibs of torque. Max as observed was 180 units. 11 /13/2008 Continue to rotate and reciprocate from 12375' to 12280 while VersaOut breaker is being mixed @ MI mud plant in Deadhorse, pumping 320 gpm w/ 2050 psi, displace well to brine with VersaOut Breaker in open hole, monitor well, trip to 7748', lay down (2) string magnets, crossover and (2) jts of 4" drill pipe to 7656', change handling tools, continue pulling 4" drill pipe to 4450', circulate 9.2 ppg brine above window (PH dropped to 3.9 @ BU- then back up to 7.5), monitor well (cleaned 7 Ibs of iron off magnets), pull out of the hole, lay down cleanout BHA, clean floor, pick up/ make up whipstock retieval assembly, run in the hole to 4540', slip and cut drilling line, continue trip to whipstock, wash sloUhook whipstock, circulate bottom's up, pull out of the hole with the whi stock to 3921' midni ht. Losses of 40 bbls /hr. 00:00 03:45 3.75 12,375 12,375 COMPZ DRILL CIRC P While 9.5 ppg, NaCUKCL VersOut breaker w/ 3% Safelube is being mixed at MI Swaco plant in Deadhorse---Continue to circulate 320 gpm w/ 2050 psi- 34% flow out. Rotate 70 rpm w/ 8k ft Ibs of torque. Max gas observed was 180 units, final 13 units. Circulated a total of 4669 bbls. Note: Held prejob safety meeting while circulatin on dis lacement. Page 6Q of 72 Time Logs ____ _ _ S De th E. De th Phase Code Subcode T _C_omment __ Date FromTo Dur 03:45 04:00 _ 0.25 12,375 12,375 COMPZ DRILL CIRC P Flush surface lines with 9.2 ppg brine. Flush bleeder line, kill line, trip tank line with brine. 04:00 06:30 2.50 12,375 12,375 COMPZ DRILL CIRC P Displace well: Pumped 26 bbls 6.8 ppg LVT, then 63 bbl 9.8 ppg Transition spacer, then 292bb1s 9.2 ppg vicosified brine w/ .6%safelube, follow with 334 bbls NACUKCL VersOut Breaker w/ 3%safelube, follow with 73 bbls 9.2 ppg viscosified brine with .6% safelube. Pumped 6 bpm w/ 1490 psi- 30% flow out. Pumped VersOut @ 5 bpm w/ Rotate 70 rpm w/ 8k ft Ibs of torque. PU wt 175k, SO wt 120k, Rot wt 150k. 06:30 06:45 0.25 12,375 12,220 COMPZ DRILL OWFF P Monitor well, make up a single 5" dril Ipipe, rack back a stand. Blow down the to drive. 06:45 09:15 2.50 12,220 7,748 COMPZ DRILL TRIP P Trip out of the hole on elevators with hole opener/ cleanout assembly on elevators. Monitor well on the trip tank. Record PU and SO wt's every 10 stands. 09:15 09:30 0.25 7,748 7,656 COMPZ DRILL PULD P Lay down (2) string magnets, crossover 4" XT 39 x 4-1 /2" IF, (2) 'oints of 4" drill i e. 09:30 09:45 0.25 7,656 7,656 COMPZ DRILL OTHR P Change out handling tools to 4" 09:45 11:30 1.75 7,656 4,450 COMPZ DRILL TRIP P Continue to trip out of the hole with hole opener/ cleanout assembly on elevators. Monitor well on the trip tank. Record PU and SO wt's every 10 stands. 11:30 11:45 0.25 4,450 4,450 COMPZ DRILL OWFF P Monitor well. Prejob safety meeting on circulating 9.2 ppg brine with .6% safelube. 11:45 12:45 1.00 4,453 4,453 COMPZ DRILL CIRC P Circulate 9.2 ppg brine w/ 1.4 safelube.. Pumping 300 gpm w/ 500 psi-31 % flow out. Rotate 30 rpm w/ 2500 ft Ibs of torque. PU wt 130k, SO wt 120k. Note: PH dropped to 3.9 @ bottom's up, then increased to 7.5 shortly after. Loss of 8 bbls whiff circulatin bottom's u . 12:45 13:00 0.25 4,453 4,453 COMPZ DRILL OWFF P onitor well. Cleaned approx 7 pounds of metal shavings from ma nets. 13:00 14:15 1.25 4,453 301 COMPZ DRILL TRIP P Continue tripping out with hole o ener! cleanout assembl . 14:15 15:15 1.00 301 0 COMPZ DRILL PULD P Lay down the hole opener. Monitor well on the trip tank. A total of 18 bbls lost on tri out of the hole. 15:15 15:45 0.50 0 0 COMPZ DRILL OTHR P Clean and clear rig floor. 15:45 17:00 1.25 0 451 COMPZ FISH PULD P Pick up/Make up whipstock retrieval BHA. Remove and clean magnets. Monitor well on the tri tank. Page ffl of 72' * ~ Time Logs Date .From To ^ur S. De th E. De th Phase Code Subcode T Comment 17:00 18:00 1.00 451 2,546 COMPZ FISH TRIP P Trip in the hole with whipstock retrieval BHA. Fill pipe every 20 stands. Monitor well on the tri tank. 18:00 18:15 0.25 2,546 2,546 COMPZ FISH PULD P Change out a joint of 5" drill pipe bad box). 18:15 19:15 1.00 2,546 4,639 COMPZ FISH TRIP P Continue trip in the hole. Proper dis alcement. 19:15 20:45 1.50 4,639 4,639 COMPZ RIGMNT SVRG P Slip and cut drilling line. Monitor well on the trip tank. 1-1/2 to 2 bph losses while cuttin drillin line.. 20:45 21:45 1.00 4,639 4,639 COMPZ RIGMNT SVRG P Service rig ,top drive and blocks. 21:45 22:00 0.25 4,639 4,678 COMPZ FISH TRIP P Trip in the hole. 22:00 22:30 0.50 4,678 4,670 COMPZ FISH FISH P Obtain parameters. PU wt 167k, SO wt 145k. Wash down to slot pumping 420 gpm w/ 1290 psi- 37% flow out . Work pipe from 4678' to 4681'. Rotate hook a quarter turn right, slack off to 4680' and take weight with hook at the bottom of the slot of the whipstock (pumped a total of 110 bbls). Slacked off 15k, picked up with 20k overpull, then falling off to origninal PU wt of 167k. Slacked back off, tagging up again @ slot (4680'), set down 15k. Pick up to 218k (51k overpull), relase MLZXP anchor. Pickup 10' observed fluid fallin in the BOP stack. Fill hole. 22:30 22:45 0.25 4,670 4,587 COMPZ FISH TRIP P Pull out of the hole two stands bottom of whipstock assembly @ 4587' 22:45 23:15 0.50 4,587 4,587 COMPZ FISH CIRC P Circulate bottom's up +. Pumping 500 gpm w/ 1840 psi- 40% flow out. Lost 74 bph while circulating. On bottom's up 20 units of gas. Circulated a total of 367 bbls Bottom's u 240 bbls . 23:15 23:30 0.25 4,587 4,587 COMPZ DRILL OWFF P Monitor well on the trip tank. Losses - _. are +/- 40 b h. 23:30 00:00 0.50 4,587 3,921 COMPZ FISH TRIP Pull out of the hole with whipstock assembly. Monitor well on the trip tank. Losses of 29 bph over calculated displacement. _ Note: At 0030 hrs, losses calculated over 35 minutes while pulling pipe (15 stands) are 25 bph over displacment. Losses @ 0300 hrs 31 b h. &'age'62 0# 72 ! • Time logs Date From To Dur S. De th E. th' Phase Code Subcode T Comment 11 /14/2008 2a hr Summary Continue to pull out of the hole with the whipstock from 3921' to 490', lay down whipstock BHA and whipstock assembly. Bring tools to floor, rig up GBR to run Seal Bore Diverter, pre job safety meeting, Pickup/Make up/ Orient anchor to Seal Bore offset +/-10 deg (Diverter Window is 10 deg right of anchor). Run in the hole with Seal Bore Diverter and running in the hole BHA. Run in the hole on 5"drill pipe to 4728', circulate, continue running in to 4756', snap in with 27k, PU 73k over, test seals on anchor isolating holes in the "B" lateral casing seal bore receptacle to 2500 psi, bleed off to 1000 psi, pickup- released from SealBore Diverter. Circulate bottom's up @ 4653', monitor well- static, Pull out of the hole with running tools, lay down Baker running tools ,boot baskets and magnets. clean floor, rig up to run the 3-1/2" screen/blank liner for the "D" lateral, pre job safety meeting. Pickup/make up/ run in the hole with "D" lateral liner per detail, RIH w/ liner on 5"drill pipe to 8127' @ midnight. Note: Losses of 35-40 bbls /hr after pulling whipstock ("B" lateral now open). Losses quit after setting SealBore Diverter. 00:00 01:30 1.50 3,921 490 COMPZ FISH TRIP P Continue to pull out of the hole with whipstock assembly. Monitor well on the trip tank, the hole took 60 bbls over calculated dis tacement. 01:30 04:30 3.00 490 0 COMPZ FISH PULD P Lay down Bottom hole assembly. Verify orientation of whipstock with the anchor, Verify measurements of whipstock assembly. The tracking of the mills on the whipstock indicated the mills walked right somewhat-Lay down tools from the floor. 04:30 05:15 0.75 0 0 COMPZ CASING PUTS P Pick up tools to the rig floor. Rig up GBR. 05:15 05:30 0.25 0 0 COMPZ CASING SFTY P Pre job safety meeting. 05:30 06:00 0.50 0 0 COMPZ CASING OTHR P Clean connections' on jewelery items of Seal Bore Diverter, for Baker lock. 06:00 06:45 0.75 0 89 COMPZ CASING PUTS P Picku the Seal Bore Diverter per detail. Monitor well on the trip tank- 32 b h losses. 06:45 07:45 1.00 89 89 COMPZ CASING OTHR P Orient the face of the Seal Bore Diverter with the MLHR production Anchor. Offset the SealBore Diverter 10 degrees to the right of the Anchor. Note: The "B" lateral MLZXP packer was oriented to 10 degrees left of highside, the tracking of the mills on the whipstock indicated the mills walked right somewhat- therefore the SealBore was oriented to compensate for the righthand walk by 10 degrees. The Sealbore will be set highside when engagedinto collet of MLZXP. 07:45 08:45 1.00 89 544 COMPZ CASING PUTS P Continue to make up running in the hole BHA. Monitor well on the trip tank- 32 BPH losses. 08:45 10:45 2.00 544 4,728 COMPZ CASING RUNL P Run in the hole with the Seal Bore Diverter on 5" drill pipe. Lost a total of 51 bbls on the trip. PU wt 167k, SO wt 142k. 10:45 11:00 0.25 4,728 4,728 COMPZ CASING CIRC P Establish circulation. Shut down um s. Page 63 bf 72 Time Lags _ - - _ 'Date` From To Dur S: De !h E. Depth Phase Code Subcode T Comment __ _ 11:00 11:15 0.25 4,728 4,756 COMPZ CASING RUNL P Continue to run in the hole. Set down to 115k on the weight indicator (27k set down- collet into the "B" lateral MLZXP packer). Pickup to 240K on the weight indicator (73k overpull), slackoff to 130k on the Wight indicator. Pressure test the seals below the MLHR Production Anchor which are covering the (2) holes in the Casing sealbore receptacle of the "B" lateral- tested against the center of element of the inflatable bridge .plug at 4816' in the "B" lateral to 2500 psi. Bleed the pressure to 1000 psi. Pickup to 160k on the weight indicator, then bleed of the pressure to zero. 11:15 11:30 0.25 4,756 4,653 COMPZ CASING RUNL P Pickup 20'- pulling slick stick of diverter running tool out of the seals of the Seal Bore Diverter. Establish circulation. Continue to pickup an additional 20' while circulating. Slick joint @ 4658'-14' above top of the Seal Bore Diverter. 11:30 12:00 0.50 4,653 4,653 COMPZ CASING CIRC P Circulate bottom's up. Pumping 430 gpm w/ 370 psi- 39% flow out. Pum d a total of 268 bbls. 12:00 12:15 0.25 4,653 4,653 COMPZ CASING OTHR P Monitor well- static. 12:15 13:30 1.25 4,653 455 COMPZ CASING RUNL P Pull out of the hole with running tools. 13:30 14:30 1.00 455 0 COMPZ CASING RURD P Lay down running tools and BHA. Clean ma nets. 14:30 14:45 0.25 0 0 COMPZ CASING OTHR P Clean and clear rig floor. 14:45 15:15 0.50 0 0 COMPZ CASING RURD P Rig up to run the 3-1/2" screen blank "D" lateral liner. Monitoring well on the tri tank. 15:15 15:30 0.25 0 0 COMPZ CASING SFTY P Pre job safety meeting on running liner. 15:30 18:00 2.50 0 3,163 COMPZ CASING RUNL P Run the "D" lateral 3-1/2" 9.2 ppf L-80 SLHT and Hydril 563 screen/blank liner to 3163' (95 jts in the hole . 18:00 22:45 4.75 3,163 7,627 COMPZ CASING RUNL P Continue to run the "D" lateral 3-1/2" 9.2 ppf L-80 SLHT and Hydril 563 screen/blank liner to 3163' (235 jts in the hole). Obtain PU wt's every 15 jts. No obstructions going through window of diverter with shoe 4.98" OD or Freecap swell packers 6.44" OD. Slow down running speed to 40 to 50 ft per minute once liner was in open hole. Loss of 14 bbls of 9.2 ppg brine while runnin in the hole. Page 64 of 72 .Time.Logs ~ -- -- - Date' From To Dur S. Depth E. De th Phase Code Subcode T Comment 22:45 23:30 0.75 7,627 7,672 COMPZ CASING RUNL P Change elevators to 5" dp. Make uo the RAM han er and ort crossover assembl to the 3-1/2" liner. PU wt with all of liner picked up was 120k u ,slackoff wt 100k. 23:30 00:00 0.50 7,672 8,127 COMPZ CASING RUNL P Make up stand with magnets and boot baskets, lay down a single of 5" drill pipe. Run in the hole with the liner on 4 stands of 5" HWDP 11 /15/2008 Continue to RIH on elevators w/ 3-1/2" 9.2 ppf L-80 SLHT/Hyd 563 blank/screen liner for the "D" lateral on 5" drill pipe from 8127' to 11890', rotate from 11890' to 11920' (30'), run on elevators to 12125', rotate from 12125' to 12160' (35'), run in to 12295', wash slot/collet area of the SealBore Diverter with ported sub. Obtain parameters. Confirm depth's-OK, proceed with release of liner --drop 29/32" ball, pressure up, pickup, blow ball seat, pull out of hole leaving a total of 26 stands in the derrick, lay down 5" drill pipe, lay down running tools. Clear floor, lay down 4"drill pipe from derrick. Rig up GBR, pickup/makeup/RIH with 3-1/2" completion tubin to stand back. 111 'oints in the hole midni ht. 00:00 00:15 0.25 8,127 8,220 COMPZ CASING RUNL P Run in the hole with the "D" lateral liner on first stand of 5"drill pipe to 8220'. PU wt 135k, SO wt 115k, Rot wt 125k. Rotate 30 rpm w! 3500 ft Ibs of for ue. 00:15 05:30 5.25 8,220 12,295 COMPZ CASING RUNL P Continue to run the liner on 5" drill pipe to 12295'. Liner was run on elevators except for rotating @ 11890' to 11920' (30') and again rotating @ 12125' to 12160' (35'). Rotate 30 rpm-Rotating wt 150k with torque limit set @ 9000 ft Ibs, torque of 7-8k ft Ibs.. Obtain PU and SO wt's evety 5 stands. Note: Loss of 31 bbls while runnin liner. 05:30 06:00 0.50 12,295 12,336 COMPZ CASING CIRC P Break circulation @ 12295' to 12307 and wash collet slot with ported sub. Pumping 5 bpm w/ 360 psi- 23 flow out.PU wt 185k, SO wt 125k, Rotating wt 155k with 30 rpm and 9k ft Ibs of torque. Slack off locate into collet, set down to 75k on weight indicator. With shoe @ 12336', collet into SealBore Diverter @ 4670.70' (21' in on a single drill pipe). Pickup to 210k and snap out of collet. Set back down to 75k on weight indicator- again 21' in on single of drill pipe. Pickup to 185k (25k overpull @ collet) to verify latched in). Note:Observed bumper sub travel @ 160k PU wt.and 142k slackoff wt, therefore 25k overpull at collet = 185k on weight indicator. Also, 75k overpull = 160k + 75 = 235k on wei ht indicator. Page fs5 of 72' ;Time L©cls Date From To Dur S. Depth E. Depth Phase Code Subcode T Comment _ ___ __ 06:00 07:00 1.00 12,336 4,650 COMPZ CASING CIRC P Break connection and drop Baker 29/32" ball to release runnin tool. Pump down @ 160 gpm w/ 210 psi-19% flow out. Slow the pumps to 110 gpm w/ 120 psi- 14% flow out after purring 500 strokes. Ball on seat after pumping 580 strokes. Pressure up to 3000 psi, bleed to zero. Pull out of the hole with liner running tools to above liner. Pressure up to 4300 psi with test pump to blow ball seat. 07:00 07:15 0.25 4,650 4,650 COMPZ DRILL OWFF P Monitor well- static. 07:15 07:45 0.50 4,650 2,760 COMPZ DRILL TRIP P Pull out of the hole, stand back 5" drill i e. 07:45 09:45 2.00 2,760 492 COMPZ DRILL TRIP P Continue to pull out of the hole, laying down 5"drill pipe. Monitor well on the trip tank. Hole took 4 bbls over calculated. 09:45 11:15 1.50 492 0 COMPZ DRILL PULD P Lay down liner running BHA. Monitor well on the tri tank. 11:15 12:00 0.75 0 0 COMPZ DRILL OWFF P Clean and clear rig floor. of liner running tools. Monitor well on the trip tank. 12:00 13:30 1.50 0 0 COMPZ DRILL PULD P Lay down 6 flex collar, 3 HWDP from derrick. Lay down mist subs for ins ection. 13:30 18:45 5.25 0 0 COMPZ DRILL PULD P Lay down 237 joints (79 stands) of 4" drill i e from the derrick. 18:45 19:15 0.50 0 0 COMPZ RPCOM RURD P Bring tools to the rig floor for 3-1/2" 9.2 ppf L-80 IBT tubing. Unloading 4" drill pipe from pipe shed. Rig up GBR. ton s. 19:15 19:30 0.25 0 0 COMPZ RPCOM SFTY P Pre job safety meeting on picking up tubing, running in the hole, then pull out- stand back on the Off Driller's Side for the main wellbore. 19:30 20:15 0.75 0 0 COMPZ RPCOM PULD P Pick up/ makeup jts # 151 to #156, stand back in the derrick on the off driller's side. These will be stand # 51 and # 52 for the main well bore. 20:15 00:00 3.75 0 3,423 COMPZ RPCOM TRIP P Pickup/makeup/RIH with 3-1 /2 9.2 f L-80 IBT-m. One hundred 111 joints picked up and run in the hole midni ht. 11 /16/2008 Continue to pickup/makeup/RIH with 3-1/2" completion tubing to stand back from 111 joints to 150 jts, bring completion jewery to the floor, POOH stand back tubing on driller's side (Main bore)/ changing seal rings, make up 9 jts RIH, stand back on off driller's side for L1 ("D" lateral), RIH w! 150 jts, POOH stand back on off driller's side ("D" lateral). rig down GBR casing tools. Pull wear bushing, install Vetco Gray test plug, change upper pipe rams (9-5/8") and lower pipe rams (3-1 /2" x 6" variables) to 3-1/2"dual rams for both upper and lower. Rig up, test to 250 psi low and 3000 psi high test 4" floor safety valve to 250 psi low and 3000 psi high, rig down testing equipment, pull test plug. Rig up to run the 3-1/2"dual completion: Remove link tilt from short bales, remove short bales, install long bales, install link tilt on long bales. Install dual elevators test and adjust link tilt for the derrick board. Make up crossovers on two floor safety valves to 3-1/2"IBT. Adjust air lines on the elevators. Function test elevators. Ri down dual elevators and install sin le 't 3-1/2" elevators. Page B6 of 7~ ~ r Time Lags _ .Date From To Dur S De th E. De th Phase Code Subcode T Comment 00:00 01:00 1.00 3,423 4,628 COMPZ RPCOM TRIP P Pickup/makeup/RIH with 3-1/2" 9.2 ppf L-80 IBT-m. Run from 111 joints to 150 joints. Monitor well on the trip tank. Loss of 10 bbls on trip in the hole. 01:00 02:00 1.00 4,628 4,628 COMPZ RPCOM PULD P Rig up floor to pull out of the hole and stand back tubing. Bring completion ewe to the floor. 02:00 04:45 2.75 4,628 0 COMPZ RPCOM TRIP P Pull out of the hole with the 3-1/2" 9.2 ppf L-80 IBT-m tubing. Replace seal rings in the joints. Rack back for the main bore on the off driller's side. Loss of 12 bbls on tri out. 04:45 05:00 0.25 0 279 COMPZ RPCOM PULD P Rig up to pickup/ makeup/RIH with 9 'oints of tubin . 05:00 05:30 0.50 279 0 COMPZ RPCOM TRIP P Pull out of the hole 3 stands and rack on the driller's side for the L1 "D" lateral . 05:30 10:00 4.50 0 4,602 COMPZ RPCOM TRIP P Pickup/makeup/ run in the hole with 150 joints of 3-1/2" 9.2 ppf L-80 IBT-m tubing. Monitor well on the tri tank. 4 bbl loss. 10:00 13:00 3.00 4,602 0 COMPZ RPCOM TRIP P Pull out of the hole with the 3-1/2" 9.2 ppf L-80 IBT-m tubing. Replace seal rings in the joints. Rack back for the L1 ("D" lateral) on the driller's side. 13:00 13:15 0.25 0 0 COMPZ RPCOM RURD P Rig down GBR tools. 13:15 13:45 0.50 0 0 COMPZ WELCTI OTHR P Pull Vetco Gray wear bushing, install test lu . 13:45 15:45 2.00 0 0 COMPZ WELCTI OTHR P Change upper pipe rams from 9-5/8" to 3-1/2" dual rams, change lower ipe rams from 3-1/2" x 6" variables to 3-1/2"dual rams. Keeping hole full under the test plug with charge um . 15:45 16:30 0.75 0 0 COMPZ WELCTL OTHR P Remove 5" test joint. 16:30 17:15 0.75 0 0 COMPZ WELCTI OTHR P Rig up to test upper and lower 3-1/2" dual rams. 17:15 19:30 2.25 0 0 COMPZ WELCTI BOPE P Test upper and lower rams to 250 psi low and 3000 psi high. Hold each test for 5 minutes. Test another 4" floor safety valve to 250 psi and 3000 si hi h, hold each test 5 minutes. 19:30 20:00 0.50 0 0 COMPZ WELCTI OTHR P Rig down testing equipment. Pull the test lu . Page 67 of 7Z ~ r Time Logs Date.. From To Dur S De th E. De th Phase Code Subcode T Comment 20:00 00:00 4.00 0 0 COMPZ RPCOM RURD P Ri u to run the 3-1/2" dual completion. Remove linkage for the link tilt on the top drive. Remove short bales, install long bales. Install link tilt to the long bales. Install dual elevators, adjust link tilt for the derrick board. Makeup two crossovers for the floor safety valves to 3-1/2" IBT. Make a dummy run past the board and rig up the air lines in the derrick for the elevators. Function test elevators. Rig down dual elevators, install single joint elevators. 11/17/2008 Pre job safety meeting on running 3-112" dual completion. ,run completion to collet profile in the Ram hanger @ 4665.67' (by tubing tally 4666.94'). snap in ,set down 10k, snap out with 19k overpull. Pull out of the hole, stand back a stand from each side. Space out. bring pups to the floor, lubricate rig, prepare to freeze protect in the cellar. Claean pits and drip pans. Note: Spaced put from 1400 hrs to 1600 hrs. Alignment guide on hanger was noticed to be not orientated correctly. Hanger taken to Baker machine shop to have another alignment guide milled into the hanger. Hanger back on rig floor @ 2100hrs. Held pre job safety meeting on makeup of Vetco/Gray hanger. Spot 32 bbls of corrosion inhibited brine to the annulus- chased with 50.7 bbls. Make up hanger to main bore, then make up to L1 ("D lateral), install top late on han er midni ht. 00:00 00:30 0.50 0 0 COMPZ RPCOM SFTY P Pre job safety meeting on running dual completion (3-1/2" 9.2 ppf L-80 IBT-m) with Baker RAM Dual Seal Module. 00:30 04:00 3.50 0 125 COMPZ RPCOM RCST P Pickup Baker equipment to the floor and make up to the "GT' Dual Packer. 04:00 05:00 1.00 125 395 COMPZ RPCOM RCST P Run completion out of the derrick-3 stands each side. 05:00 05:15 0.25 395 407 COMPZ RPCOM RCST P Install3-1/2" KBG-2-9 GLM assembly with DCK-3 2000 psi casing to tubing shear valve on the main bore side. Install Baker CMD sliding sleeve assembly with 2.813" rofile on the L-1 side. 05:15 06:00 0.75 407 650 COMPZ RPCOM RCST P Continue to run in the hole with tubing from the derrick. Obtain PU and SO wt's every 6 stands, Balance string every 6 stands. Note: Fluid losses are 5 b h. 06:00 07:00 1.00 650 650 COMPZ RPCOM SFTY P Crew change/Pre job safety meeting on running dual completion (3-1/2" 9.2 ppf L-80 IBT-m) with Baker RAM Dual Seal Module. 07:00 12:00 5.00 650 4,205 COMPZ RPCOM RCST P Run completion from the derrick. Obtain PU and SO wt's every 6 stands, Balance string every 6 stands. 12:00 13:45 1.75 4,205 4,667 COMPZ RPCOM RCST P Continue to run completion from the derrick. Obtain PU and SO wt's every 6 stands, Balance string every 6 stands. Note: Fluid losses 3 to 4 b h. FTaga 88 of 72 • • Time Logs Qate From T© Dur S; D~th E, Depth Phase Code Subcode T Comment ____ 13:45 14:00 0.25 4,679 4,602 COMPZ RPCOM _ RCST P Tagged collet of the Ram Dual Seal Module @ 4666.94' tubing. measurements (4665.67"'D" lateral liner measurements) (1.27' deeper on tubing tally). PU wt 139k, SO wt 121 k. Set down 10k with collet. Pick up with 19k overpull to snap out (158k). Pull out of the hole to space out for the hanger and Dual Seal Module. 14:00 16:00 2.00 4,602 4,654 COMPZ RPCOM HOSO P Obtain measurements for the spaceout. Bring pups to the floor. Make up pups and a single on each side. On the Main well bore- need 73.80'+20'-RKB of 36.31' travel-3.15 pup-1.49' hanger= 52.85'. Will use 2.06' pup, then a 9.84' pup, then a 9.83 pup and a joint above the pups with a length of 31.12' below hanger = 52.85' On L1 side ("D" lateral we need 73.61'+20'travel- RKB of 36.31'- 5.12' pup- 1.49' hanger body = 50.69'. Will use 3.65' pup, then a 7.80' pup, then a 7.80 pup and a joint above the pups with a length of 31.45' below han er = 50.70' 16:00 17:00 1.00 4,654 4,654 COMPZ RIGMNI SVRG P Lubricate rig. 17:00 18:00 1.00 4,654 4,654 COMPZ RPCOM RURD P Rig up in the cellar for pumping freeze protection while Vetco Gray ahnger is being taken to Baker Machine shop for a slot milled for orientation. 18:00 21:00 3.00 4,654 4,654 COMPZ RPCOM WOEQ T Waiting on hanger to be machined at Baker Oil Tools. 21:00 21:15 0.25 4,654 4,654 COMPZ RPCOM SFTY P Pre job safety meeting on making up han er. 21:15 22:30 1.25 4,654 4,654 COMPZ RPCOM CIRC P Pumped 32 bbls of inhibited brine, displace with 50.7 bbls of 9.2 ppg brine to spot in the annulus. Pumpe down the L1, pumping 3 bpm w/ 110 si-14% flow out. 22:30 00:00 1.50 4,654 4,654 COMPZ RPCOM HOSO P Make up pup on main bore hanger, make up pup on L1 hanger, attatch to late to the han er. 11 /18!2008 Run dual tubing string to l'D. Observed RAM Dual Seal Module collet engage Ram hanger. profile on depth and sheared free of the Dual Seal Module with the seal assembly's, tagged and sheared seal assembly shroud, continued to run and land hanger in wellhead. Run in lockdown screws and tested hanger body seals. Installed two way checks and tested upper seals on hanger. Pressure tested seals in the casing seal bore receptacle "B" lateral and seals of the sealbore diverter of "B" lateral and IBP in "B" lateral liner. Attempted to set Baker "GT" packer. Annulus would not hold pressure. Rigged up wireline to check sliding sleeve and "D" lateral tubin .Set lu in mainbore, "B" lateral, tubin and continued attemts to set aaker. Page 69 of 72 • Time Logs -- -- __ -_ T .Comment _ __ Date __ From To Qur S Cte th E. De th Phase Code Subcode 00:00 01:00 1.00 4,654 4,654 C OMPZ RPCOM HOSO r P Finish attatching top plate to the Vetco Gray hanger. Make up landing 'oints. PU wt 140k, SO wt 123k. 01:00 02:00 1.00 4,654 4,691 COMPZ RPCOM HOSO P RIH, observe RAM Dual Seal Module collet engage Ram hanger profile on depth (4665.67' liner tally), pull 10k over, set down 33k and sheared free of the Dual Seal Module with the seal assembly's, continued to come down and tagged and sheared seal assembly shroud (15k down), continued to run 2.5' and land hanger in wellhead 02:00 02:45 0.75 4,691 4,691 COMPZ RPCOM OTHR P Run in lockdown screws, torque 600 ft lbs. Test hanger body seals to 5000 si for 10 minutes. 02:45 04:00 1.25 4,691 4,691 COMPZ RPCOM DHEQ P Pull landing joints, install two way checks. Test upper seals on hanger to 5000 psi for 10 minutes to 5000 psi. Used the blinds and HCR choke line. 04:00 05:00 1.00 4,691 4,691 COMPZ RPCOM OTHR P Drain stack, pull two way check on the main bore. 05:00 05:15 0.25 4,691 4,691 COMPZ RPCOM OTHR P Close blind rams and pressure test the seals which are across the holes in the casing seal bore recepticle "B" lateral and seals of the sealbore diverter of "B" lateral and IBP in "B" lateral liner to 1000 psi. Pressure held 05:15 06:00 0.75 4,691 4,691 COMPZ RPCOM PACK P Continue eressurinq uo to 2500 asi to set the Baker "GT" packer, hold for 15 minutes. Bleed tubing to 1500 psi and attempt to pressure annulus (testing "GT" packer) to 2500. Packer not holdin ressure 06:00 07:00 1.00 4,691 4,691 COMPZ RPCOM PACK T Grease and function valves. Retest acker, no ood not holdin ressure 07:00 07:30 0.50 4,691 4,691 COMPZ RPCOM PACK T Continue trying to set packer. Pressure up to 4000 psi on mainbore then bleed down to 1500 psi. Pump into annulus at 2 bpm to test packer. Could not build pressure. Pumped 5 bbls awa . 07:30 08:30 1.00 4,691 4,691 COMPZ RPCOM PACK T Bleed tubing pressure to 0 psi, drain stack and pull two way check valve from "D" lateral tubin strin . 08:30 08:45 0.25 4,691 4,691 COMPZ RPCOM PACK T Pump 2 bpm down annulus and observed returns coming up-'fF~ru'"D" lateral tubin . 08:45 12:00 3.25 4,691 4,691 COMPZ RPCOM SLKL T Drain stack and make up landing joint to "D" lateral tubing string. Rig down dual elevators and rig up wireline sheave. RIH with wireline to work slidin sleeve. 12:00 12:30 0.50 4,691 4,691 COMPZ RPCOM SLKL T Work sliding sleeve to insure it is closed. Page 70 of 72 • Time L°~ _ _ - - Date _ From To Dur S De~?th E. D~th Ph_a_se Code Subcode T Comment _ 12:30 12:45 0.25 4,691 4,691 COMPZ RPCOM PACK T Attem t to test packer b ~essuring u on annulus, won't hold pressure. POOH with wireline. 12:45 14:45 2.00 4,691 4,691 COMPZ RPCOM SLKL T RIH with plug for D nipple in "D" lateral. Set plug and pressure up to 2500 psi and hold for 15 minutes. Pump down annulus to test packer. no ood still won't hold ressure. 14:45 15:30 0.75 4,691 4,691 COMPZ RPCOM SLKL T POOH with wireline and plug. Rig down wireline. 15:30 16:00 0.50 4,691 4,691 COMPZ WELCTI OTHR T Laydown landing joint and rig up to test BOPE. 16:00 18:45 2.75 4,691 4,691 COMPZ RPCOM SLKL T Pick up landing joint and rig up wireline. RIH with wireline to set plug in DS nipple in mainbore, "B" lateral. Pressure up to 650 psi. POOH with wireline. Plu did not set. 18:45 19:15 0.50 4,691 4,691 COMPZ RPCOM SLKL T Redress slickline plug setting tool. 19:15 21:00 1.75 4,691 4,691 COMPZ RPCOM SLKL T RIH with plug on wireline to DS nipple in mainbore and set plug. POOH, tattle tales indicate lu set. 21:00 00:00 3.00 4,691 4,691 COMPZ RPCOM PACK T Pressure up on mainbore tubing to 2500 si and hold for 30 minutes to set acker. Pump down annulus to test packer. Packer not set, getting returns thru "D" lateral tubing. Continue pressuring mainbore tubing and pumping down annulus. Surge mainbore tubing working pressure to 4000 psi in attempt to set packer. Packer still not settin 11 /19/2008 Set packer and tested. Nipple down BOP stack and nipple up tree. Freeze protect tubing strings and annulus. Set back ressure valves in tubin strip s. Released ri at 22:00. 00:00 01:00 1.00 4,691 4,691 COMPZ RPCOM PACK T Pressure up on mainbore tubing to d hold for 5 minutes >so 4600 psi an _ set packer Pressure up on annulus to psi. Pressure holding. Bleed annulus to 0 psi and tubing to 1500 psi. Pressure up annulus to 2500 psi and hold for 30 minutes. Pressure held. Bleed off annulus then tubin . 01:00 01:30 0.50 0 0 COMPZ RPCOM SLKL T Rig down slickline 01:30 01:45 0.25 0 0 COMPZ RPCOM RURD P Lay down landing joint and blow down lines. 01:45 02:15 0.50 0 0 COMPZ RPCOM OTHR P Install two way check valves. 02:15 02:45 0.50 0 0 COMPZ RPCOM SFTY P PJSM -nipple down BOP stack. 02:45 06:00 3.25 0 0 COMPZ RPCOM NUND P Nipple down BOP stack. 06:00 08:00 2.00 0 0 COMPZ RPCOM NUND P Nipple up tree per Vetco reps. 08:00 08:30 0.50 0 0 COMPZ RPCOM DHEQ P Rig up and test void with 5000 psi for 10 minutes. Good test 08:30 11:00 2.50 0 0 COMPZ RPCOM DHEQ P Rig up and test tree, D-Lat and B-Lat, 250 psi low and 5000 psi high. Good test. Rage 71 of 72 • • Time togs _. __ From To Dur S. Depth E: De th Phase Code Subcode Date T Comment _ 11:00 11:45 0.75 0 0 COMPZ RPCOM OTHR P Pull two way check valves. 11:45 12:00 0.25 0 0 COMPZ RPCOM FRZP P Rig up Little Red for freeze protecting tubin and annulus. 12:00 16:30 4.50 0 0 COMPZ RPCOM FRZP P Shear out valve in mainbore gas lift mandrel and pump 267 bbls of diesel taking returns up mainbore tubing. Initial circulating pressure 600 psi, final circulating pressure 475 psi. Sim ops -lay down 9 stands of tubing from derrick. lay down long bails. 16:30 17:30 1.00 0 0 COMPZ RPCOM FRZP P Rig up Little Red on D-Lat tubing and bullhead 22 bbls of diesel at 2 bpm. Initial injection pressure 1200 psi. Reduce rate to 1.5 bpm. Final injection ressure 900 si. 17:30 21:00 3.50 0 0 COMPZ RPCOM OTHR P Pick up and make up lubricator. Set backpressure valve in B-Lat tubing. Rotate treecap 90 degrees and install BPV in D-Lat tubin .Tested breaks to 5000 psi for 10 minutes. Shut-in tubing pressure B-Lat 250 psi, D-Lat 0 psi. Outer annulus 200 psi, inner annulus 0 psi. Sim ops - re for ri move. 21:00 22:00 1.00 0 0 COMPZ RPCOM OTHR P Clean cellar box, rockwasher and its. Ri Released at 22:00 Pale 72 0# 72 i • ConocoPhillips(Alaska) Inc. Kuparuk River Unit 3K-Pad 3K-103 L1 Permit to Drill: 208-116 API: 50-029-23392-60 -~ Definitive Survey Report 17 December, 2008 Spe~*ry DrfJljng Servia~~ • • ConocoPhillips or its affiliates Definitive Survey Report Company: ConocoPhillips(Alaska) Inc. Local Co-ordinate Reference: We113K-103 (E14) Project: Kuparuk River Unit ND Reference: 3K-103 @ 74.6ft (D15 (33.8+40.82)) Site: 3K-Pad MD Reference: 3K-103 @ 74.6ft (D15 (33.8+40.82)) Well: 3K-103 (E14) North Reference: True Wellbore: 3K-103 L1 Survey Calculation Method: Minimum Curvature Design: 3K-103 L1 Database: EDM Alaska Prod v16 Project Kuparuk River Unit Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor ~WeU 3K-103 (E14) Well Position +N/-S 0.0 ft Northing: 6,007,879.03ft Latitude: 70° 25' 57.374 N +E/-W 0.0 ft Easting: 529,305.30 ft Longitude: 149° 45' 40.019 W Position Uncertainty 0.0 ft Wellhead Elevation: ft Ground Level: 33.8ft - - - Wellbore 3K-103 L1 - -- - Magnetics Model Name Sample Date Declination Dip Angle Flel d Strength j l°) (°1 (nT) ~ BGGM2007 9/15/2008 2257 80.90 57.647 Design 3K-103 L1 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 4,652.4 Vertical Section: Depth From (ND) +N/-S +E/-W Direction (ft) (ft) Ift) (°) 40.8 0.0 0.0 90.00 - - ~ Survey Program Date ~ From To (ft) (ft) Survey (Wellbore) Tool Name Description I Survey Date 50.0 621.0 3K-103P61 SRG (3K-103P61) CB-GYRO-SS Camera based gyro single shot 9/23!2008 1: 672.5 2,862.2 3K-103PB1 MWD Back Corrected 2008- MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC 10/31/2008 2,925.0 4,652.4 3K-103PB3 MWD Back Corrected 2008- MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC 10/31/2008 4,675.2 12,301.6 3K-103L1 MWD (3K-103 L1) MWD+IFR-AK-CAZ-SC MWD+IFR AK CAZ SCC 11/7/2008 1: Survey Map Map Vertical MD Inc Azi ND NDSS +Ni-S +EI-W Northing Easting DLS Section (ft) (°) (°) (ft) (ft) (ft) (ft) (ft) (ft) (°/100') (ft) Survey Tool Name 40.8 0.00 0.00 40.8 -`s3.8 U.0 0.0 6,007,875.0 529,305.3 OA 0.00 UNDEFINED 50.0 0.20 73.45 50.0 -24.6 0.0 0.0 6,007,879.0 529,305.3 2.2 0.02 CB-GYRO-SS (1) 110.0 0.41 199.34 110.0 35.4 -0.2 0.0 6,007,878.9 529,305.3 0.9 0.04 CB-GYRO-SS (1) 170.0 0.46 75.98 170.0 95.4 -0.3 0.2 6,007,878.7 529,305.5 1.3 0.21 CB-GYRO-SS (1) 265.0 3.37 53.09 264.9 190.3 1.5 2.8 6,007,880.5 529,308.1 3.1 2.81 CB-GYRO-SS (1) 354.0 5.18 54.28 353.7 279.1 5.4 8.2 6,007,884.4 529,313.4 2.0 8.16 CB-GYRO-SS (1) 451.0 6.64 60.62 450.2 375.5 10.7 16.6 6,007,889.8 529,321.9 1.6 16.61 CB-GYRO-SS (1) 541.0 9.92 63.78 539.2 464.6 16.7 28.1 6,007,895.8 529,333.3 3.7 28.70 CB-GYRO-SS (1) 621.0 12.00 68.96 617.8 543.1 22.7 42.0 6,007,901.9 529,347.3 2.9 42.04 CB-GYRO-SS (1) 672.5 13.32 65.33 668.0 593.4 27.1 52.4 6,007,906.3 529,357.6 3.0 52.43 MWD+IFR-AK-CAZ-SC (2) 765.5 16.96 64.65 757.8 683.2 37.4 74.4 6,007,916.7 529,379.6 3.9 74.44 MWD+IFR-AK-CAZ-SC (2) 12/17/2008 9:29:09AM Page 2 COMPASS 2003.16 Build 42F • • ConocoPhillips or its affil iates Defi nitive Survey Report Company: ConocoPhillips(Alaska) I nc. Local Co-ordinate Reference: Nell 3K-103 (E14) Project: Kuparuk River Unit ND Refer ence: 3K-103 @ 74.6ft (D15 (33.8+40.82)) Site: 3K-Pad MD Reference: 3K-103 @ 74.6ft (D15 (33.8+40.82)) .Well: 3K-103 (E14) North Reference: True Wellbore: 3K-103 L1 Survey Ca lculation Met hod: Minimu m Curvature Design: 3K-103 L1 Database: EDM Alaska Prod v16 Survey Map Map Vertical MD Inc Azi ND NDSS +N/-5 +E/-W Northing Easting DLS Section (ftl (°) (~) Ift) Ift) Ift) (ft) (ft) (ft) (°11 00') (ft) Survey Tool Name 863.5 18.39 60.86 851.1 776.5 51.0 100.8 6,007,930.4 525,405.5 L5 1W.84 MWD+IFR-AK-CAZ-SC (2) 957.8 20.90 58.49 939.9 865.3 67.1 128.2 6,007,946.6 529,433.2 2.8 128.19 MWD+IFR-AK-CAZ-SC (2) 1,053.8 23.56 54.34 1,028.8 954.2 87.2 158.4 6,007,966.8 529,463.3 3.2 158.38 MWD+IFR-AK-CAZ-SC (2) 1,148.4 22.84 49.94 1,115.8 1,041.2 110.0 187.8 6,007,989.8 529,492.7 2.0 187.81 MWD+IFR-AK-CAZ-SC (2) 1,243.1 24.69 45.02 1,202.4 1,127.8 135.8 215.9 6,008,015.7 529,520.6 2.9 215.86 MWD+IFR-AK-CAZ-SC (2) 1,339.0 27.02 43.45 1,288.7 1,214.1 165.8 245.0 6,008,045.8 529,549.6 2.5 245.03 MWD+IFR-AK-CAZ-SC (2) 1,433.5 31.02 39.31 1,371.4 1,296.8 200.3 275.2 6,008,080.4 529,579.7 4.7 275.23 MWD+IFR-AK-CAZ-SC (2) 1,529.2 33.23 38.66 1,452.4 1,377.8 239.8 307.2 6,008,120.0 529,611.5 2.3 307.22 MWD+IFR-AK-CAZ-SC (2) 1,624.9 37.85 38.27 1,530.2 1,455.6 283.4 341.8 6,008,163.7 529,646.0 4.8 341.80 MWD+IFR-AK-CAZ-SC (2) 1,720.6 38.45 39.07 1,605.5 1,530.9 329.5 378.8 6,008,210.0 529,682.7 0.8 378.77 MWD+IFR-AK-CAZ-SC (2) 1,874.3 38.90 39.88 1,678.7 1,604.0 374.7 416.0 6,008,255.4 529,719.8 0.7 415.99 MWD+IFR-AK-CAZ-SC (2) 1,910.5 39.26 39.69 1,753.4 1,678.7 421.4 454.8 6,008,302.1 529,758.4 0.4 454.80 MWD+IFR-AK-CAZ-SC (2) 2,005.8 40.31 41.17 1,826.6 1,752.0 467.8 494.4 6,008,348.7 529,797.8 1.5 494.36 MWD+IFR-AK-CAZ-SC (2) 2,101.3 41.64 41.34 1,898.7 1,824.1 514.8 535.6 6,008,395.9 529,838.9 1.4 535.64 MWD+IFR-AK-CAZ-SC (2) 2,196.1 43.61 37.77 1,968.4 1,893.8 564.3 576.5 6,008,445.6 529,879.5 3.3 576.48 MWD+IFR-AK-CAZ-SC (2) 2,290.7 42.97 34.08 2,037.3 1,962.7 616.8 614.6 6,008,498.2 529,917.4 2.8 614.55 MWD+IFR-AK-CAZ-SC (2) 2,386.6 44.84 35.12 2,106.4 2,031.8 671.6 652.3 6,008,553.1 529,954.9 2.1 652.30 MWD+IFR-AK-CAZ-SC (2) 2,481.6 43.66 35.54 2,174.4 2,099.8 725.6 690.6 6,008,607.3 529,993.0 1.3 690.64 MWD+IFR-AK-CAZ-SC (2) 2,576.8 42.74 35.94 2,243.8 2,169.2 778.5 728.7 6,008,660.3 530,030.9 1.0 728.70 MWD+IFR-AK-CAZ-SC (2) 2,625.3 41.50 36.29 2,279.8 2,205.2 804.8 747.9 6,008,686.7 530,049.9 2.6 747.89 MWD+IFR-AK-CAZ-SC (2) 2,672.1 40.62 35.91 2,315.1 2,240.4 829.6 766.0 6,008,711.6 530,067.9 2.0 765.96 MWD+IFR-AK-CAZ-SC (2) 2,727.0. 41.13 34.51 2,356.6 2,282.0 859.0 786.7 6,008,741.0 530,088.5 1.9 786.69 MWD+IFR-AK-CAZ-SC (2) 2,766.7 41.29 33.17 2,386.5 2,311.8 880.7 801.3 6,008,762.8 530,103.0 2.3 801.25 MWD+IFR-AK-CAZ-SC (2) 2,862.2 42.54 33.44 2,457.6 2,382.9 934.0 836.3 6,008,816.3 530,137.8 1.3 836.31 MWD+IFR-AK-CAZ-SC (2) 2,925.0 43.74 32.98 2,503.4 2,428.7 970.0 859.8 6,008,852.3 530,161.2 2.0 859.81 MWD+IFR-AK-CAZ-SC (3) 2,983.4 40.73 32.87 2,546.6 2,472.0 1,002.9 881.2 6,008,885.3 530,182.4 5.2 881.15 MWD+IFR-AK-CAZ-SC (3) 3,035.7 40.60 34.12 2,586.3 2,511.7 1,031.3 900.0 6,008,913.8 530,201.1 1.6 899.96 MWD+IFR-AK-CAZ-SC (3) 3,078.6 41.31 34.30 2,618.7 2,544.1 1,054.6 915.8 6,008,937.1 530,216.8 1.7 915.78 MWD+IFR-AK-CAZ-SC (3) 3,129.7 42.18 35.07 2,656.8 2,582.2 1,082.5 935.1 6,008,965.1 530,236.1 2.0 935.11 MWD+IFR-AK-CA2-SC (3) 3,173.5 42.07 34.76 2,689.3 2,614.6 1,106.6 951.9 6,008,989.3 530,252.8 0.5 951.92 MWD+IFR-AK-CAZ-SC (3) 3,223.7 43.23 36.23 2,726.2 2,651.6 1,134.4 971.7 6,009,017.1 530,272.4 3.0 971.70 MWD+IFR-AK-CAZ-SC (3) 3,268.4 43.75 37.35 2,758.6 2,684.0 1,159.0 990.1 6,009,041.8 530,290.8 2.1 990.12 MWD+IFR-AK-CAZ-SC (3) 3,318.6 45.07 39.09 2,794.5 2,719.9 1,186.6 1,011.9 6,009,069.5 530,312.4 3.6 1,011.86 MWD+IFR-AK-CAZ-SC (3) 3,363.5 45.85 40.87 2,826.0 2,751.4 1,211.1 1,032.4 6,009,094.0 530,332.8 3.3 1,032.40 MWD+IFR-AK-CAZ-SC (3) 3,414.1 46.24 44.05 2,861.1 2,786.5 1,237.9 1,057.0 6,009,121.0 530,357.3 4.6 1,056.98 MWD+IFR-AK-CAZ-SC (3) 3,459.3 45.87 45.43 2,892.5 2,817.9 1,261.1 1,079.9 6,009,144.2 530,380.1 2.3 1,079.89 MWD+IFR-AK-CAZ-SC (3) 3,508.6 45.94 47.12 2,926.8 2,852.2 1,285.5 1,105.5 6,009,168.8 530,405.6 2.5 1,105.48 MWD+IFR-AK-CAZ-SC (3) 3,554.1 46.35 49.08 2,958.4 2,883.7 1,307.5 1,129.9 6,009,190.8 530,430.0 3.2 1,129.94 MWD+IFR-AK-CAZ-SC (3) 3,604.0 48.00 51.76 2,992.2 2,917.6 1,330.7 1,158.1 6,009,214.2 530,458.1 5.1 1,158.12 MWD+IFR-AK-CAZ-SC (3) 3,648.8 49.11 53.85 3,021.9 2,947.3 1,351.0 1,184.9 6,009,234.6 530,484.7 4.3 1,184.86 MWD+IFR-AK-CAZ-SC (3) 12/17/2008 9:29:09AM Page 3 COMPASS 2003.16 Build 42F • • ConocoPhillips or its affiliates Definitive Survey Report .Company: ConocoPhillips(Alaska) Ina Local Co-ordinate Reference: We113K-103 (E14) Project: Kupa ruk River Unit ND Reference: 3K-103 @ 74.6ft (D15 (33.8+40.82)) Site: 3K-Pad MD Reference: 3K-103 @ 74.6ft (D15 (33.8+40.82)) Well: 3K-103 (E14) North Reference: True Wellbore: 3K-103 L1 Survey Ca lculation Met hod: Minimum Curvature Design: 3K-103 L1 ....Database: EDM Alaska Prod v16 Survey Map Map Vertical MD Inc Azl ND NDSS +Nf-5 +E/-W Northing Easting DLS Section Ift) (°) (°) (ft) lft) Ift) Ift) (ft) (ft) (° /100'} (ft) Survey 7001 Name 3,701.5 50.92 56.05 3,055.8 2,981.2 1,374.2 1,2-17.9 6,009,257.9 530,517.7 4.7 1,217.94 MWD+IFR-AK-CAZ-SG (3) 3,744.4 50.48 57.62 3,082.9 3,008.3 1,392.4 1,245.7 6,009,276.2 530,545.4 3.0 1,245.72 MWD+IFR-AK-CAZ-SC (3) 3,794.4 51.10 59.30 3,114.6 3,039.9 1,412.7 7,278.8 6,009,296.6 530,578.4 2.9 7,278.75 MWD+IFR-AK-CAZ-SC (3) 3,838.6 52.56 60.86 3,141.8 3,067.2 1,430.0 1,308.8 6,009,314.0 530,608.4 4.3 1,308.83 MWD+IFR-AK-CAZ-SC (3) 3,893.7 54.65 62.71 3,174.5 3,099.9 1,450.9 1,347.9 6,009,335.1 530,647.4 4.7 1,347.91 MWD+IFR-AK-CAZ-SC (3) 3,933.5 56.54 64.14 3,797.0 3,122.4 1,465.6 1,377.3 6,009,349.9 530,676.7 5.6 7,377.29 MWD+IFR-AK-CAZ-SC (3) 3,983.5 58.77 67.62 3,223.8 3,149.2 1,482.8 1,415.8 6,009,367.3 530,715.1 7.4 1,415.82 MWD+IFR-AK-CAZ-SC (3) 4,028.2 60.93 69.77 3,246.3 3,171.6 1,496.9 1,451.9 6,009,381.5 530,751.1 6.4 1,451.87 MWD+IFR-AK-CAZ-SC (3) 4,078.4 62.54 72.12 3,270.0 3,195.4 1,511.3 1,493.7 6,009,396.1 530,792.9 5.2 1,493.66 MWD+IFR-AK-CAZ-SC (3) 4,123.8 62.53 73.97 3,291.0 3,216.4 1,523.1 1,532.2 6,009,408.0 530,831.4 3.6 1,532.20 MWD+IFR-AK-CAZ-SC (3) 4,174.4 63.87 75.80 3,313.8 3,239.2 1,534.8 1,575.8 6,009,419.9 530,874.9 4.2 1,575.82 MWD+IFR-AK-CAZ-SC (3) 4,221.2 65.82 77.82 3,333.7 3,259.0 1,544.5 1,617.0 6,009,429.7 530,916.1 5.7 1,617.00 MWD+IFR-AK-CAZ-SC (3) 4,271.6 67.64 79.77 3,353.6 3,279.0 1,553.5 1,662.5 6,009,438.9 530,961.5 5.1 1,662.46 MWD+IFR-AK-CAZ-SC (3) 4,313.9 68.89 80.68 3,369.2 3,294.6 1,560.7 1,701.1 6,009,445.7 531,000.1 3.6 7,701.13 MWD+IFR-AK-CAZ-SC (3) 4,367.9 71.82 83.24 3,387.4 3,312.8 1,567.3 1,751.5 6,009,453.0 531,050.5 7.0 1,751.54 MWD+IFR-AK-CAZ-SC (3) 4,410.6 73.89 84.71 3,400.0 3,325.4 1,571.5 1,792.1 6,009,457.4 531,097.0 5.9 7,792.05 MWD+IFR-AK-CAZ-SC (3) 4,461.4 76.71 87.08 3,412.9 3,338.3 1,575.0 1,841.1 6,009,461.1 531,140.0 7.1 1,841.11 MWD+IFR-AK-CAZ-SC (3) 4,505.5 78.02 88.98 3,422.5 3,347.9 7,576.5 7,884.0 6,009,462.8 531,183.0 5.2 1,884.05 MWD+IFR-AK-CAZ-SC (3) 4,556.0 78.98 90.82 3,432.6 3,358.0 1,576.6 1,933.5 6,009,463.1 531,232.4 4.0 1,933.53 MWD+IFR-AK-CAZ-SC (3) 4,607.1 79.49 91.25 3,441.0 3,366.4 1,575.8 1,977.8 6,009,462.4 531,276.7 1.5 1,977.82 MWD+IFR-AK-CAZ-SC (3) 4,652.4 80.02 92.20 3,450.7 3,375.5 1,574.3 2,028.3 6,009,461.1 531,327.2 2.1 2,028.27 MWD+IFR-AK-CAZ-SC (3) 4,675.2 80.37 91.95 3,454.0 3,379.4 1,573.5 2,050.8 6,009,460.4 531,349.7 7.9 2,050.76 MWD+IFR-AK-CAZ-SC (4) 4,739.6 82.51 92.72 3,463.6 3,389.0 1,570.9 2,714.4 6,009,458.0 531,413.3 3.5 2,114.42 MWD+IFR-AK-CAZ-SC (4) 4,788.7 85.24 93.30 3,468.9 3,394.2 1,568.3 2,163.1 6,009,455.7 531,462.0 5.7 2,163.12 MWD+IFR-AK-CAZ-SC (4) 4,832.9 86.85 93.82 3,471.9 3,397.3 1,565.6 2,207.1 6,009,453.1 531,506.0 3.8 2,207.10 MWD+IFR-AK-CAZ-SC (4) 4,883.9 88.77 94.42 3,473.8 3,399.2 1,561.9 2,258.0 6,009,449.6 531,556.9 3.9 2,257.97 MWD+IFR-AK-CAZ-SC (4) 4,927.7 89.44 92.54 3,474.5 3,399.9 1,559.2 2,301.7 6,009,447.2 531,600.7 4.6 2,301.73 MWD+IFR-AK-CAZ-SC (4) 4,978.8 91.24 92.90 3,474.2 3,399.6 1,556.8 2,352.8 6,009,444.9 531,651.7 3.6 2,352.75 MWD+IFR-AK-CAZ-SC (4) 5,023.9 90.12 93.36 3,473.7 3,399.1 1,554.4 2,397.8 6,009,442.6 531,696.7 2.7 2,397.76 MWD+IFR-AK-CAZ-SC (4) 5,118.5 90.06 89.89 3,473.5 3,398.9 1,551.7 2,492.3 6,009,440.3 531,791.2 3.7 2,492.29 MWD+IFR-AK-CAZ-SC (4) 5,214.2 88.70 88.26 3,474.6 3,400.0 1,553.2 2,588.0 6,009,442.3 531,886.9 2.2 2,588.02 MWD+IFR-AK-CAZ-SC (4) 5,308.9 89.14 83.99 3,476.4 3,401.7 1,559.6 2,682.5 6,009,449.0 531,981.4 4.5 2,682.47 MWD+IFR-AK-CAZ-SC (4) 5,403.5 87.72 82.64 3,479.0 3,404.3 1,570.6 2,776.4 6,009,460.4 532,075.2 2.7 2,776.39 MWD+IFR-AK-CAZ-SC (4) 5,498.6 88.33 83.21 3,482.2 3,407.6 1,582.3 2,870.7 6,009,472.5 532,169.4 0.9 2,870.66 MWD+IFR-AK-CAZ-SC (4) 5,593.6 88.21 84.54 3,485.1 3,410.5 1,592.5 2,965.1 6,009,483.0 532,263.8 1.4 2,965.08 MWD+IFR-AK-CAZ-SC (4) 5,689.8 88.58 86.86 3,487.8 3,413.2 1,599.7 3,061.0 6,009,490.6 532,359.7 2.4 3,060.98 MWD+IFR-AK-CAZ-SC (4) 5,785.5 88.95 89.50 3,489.9 3,415.2 1,602.7 3,156.6 6,009,494.0 532,455.3 2.8 3,156.60 MWD+IFR-AK-CAZ-SC (4) 5,880.9 90.49 92.51 3,490.3 3,415.7 1,601.0 3,251.9 6,009,492.7 532,550.6 3.5 3,251.94 MWD+IFR-AK-CAZ-SC (4) ~ 5,975.7 88.27 91.58 3,491.4 3,416.7 1,597.7 3,346.6 6,009,489.7 532,645.3 2.5 3,346.64 MWD+IFR-AK-CAZ-SC (4) 6,071.1 87.16 92.44 3,495.2 3,420.5 1,594.3 3,441.9 6,009,486.7 532,740.6 1.5 3,441.93 MWD+IFR-AK-CAZ-SC (4) 12/17/2008 9:29:09AM Page 4 COMPASS 2003.16 Build 42F ConocoPhillips or its affiliates Definitive Survey Report • Company: ConocoPhillips(Alaska) Inc. Local Co-ordinate Reference: We113K-103 (E14) Project: Kupa ruk River Unit ND Reference: 3K-103 @ 74.6ft (D15 (33.8+40.82)) Site: 3K-Pad MD Refere nce: 3K-103 @ 74.6ft (D15 (33.8+40.82)) Well: 3K-103 (E14) North Reference: True Wellbore: 3K-103 L1 Survey Cal culation Met hod: Minimum Curvature Design: 3K-103 L1 .Database: EDM Alaska Prod v16 Survey -- - ~ Map Map Vertical MD Inc Azi ND NDSS +NI-S +E/-W Northing Easting DLS Section Iftl (°) (°) (ft) (ft) (ft) Ift) (ft) (ft) (° 1100') (ft) Survey Tool Name 6,167.3 89.88 92.00 3,497.6 3,423.0 1,590.6 3,538.0 6,009,483.3 532,836.7 2.9 3,538.00 MWD+IFR-AK-GAZ-SG (4) 6,261.5 89.51 88.39 3,498.1 3,423.5 1,590.3 3,632.2 6,009,483.4 532,930.9 3.8 3,632.24 MWD+IFR-AK-CAZ-SC (4) 6,356.4 91.36 86.20 3,497.4 3,422.8 1,594.7 3,727.0 6,009,488.2 533,025.6 3.0 3,726.96 MWD+IFR-AK-CAZ-SC (4) 6,451.2 89.01 85.48 3,497.1 3,422.5 1,601.6 3,821.5 6,009,495.5 533,120.1 2.6 3,821.52 MWD+IFR-AK-CAZ-SC (4) 6,546.3 87.16 85.23 3,500.3 3,425.7 1,609.3 3,916.3 6,009,503.6 533,214.8 2.0 3,916.29 MWD+IFR-AK-CAZ-SC (4) 6,641.6 88.76 90.85 3,503.7 3,429.1 1,612.6 4,011.4 6,009,507.2 533,310.0 6.1 4,011.42 MWD+IFR-AK-CAZ-SC (4) 6,690.0 88.64 93.16 3,504.8 3,430.2 1,610.9 4,059.8 6,009,505.7 533,358.3 4.8 4,059.78 MWD+IFR-AK-CAZ-SC (4) 6,736.1 86.23 93.10 3,506.9 3,432.2 1,608.4 4,105.7 6,009,503.4 533,404.3 5.2 4,105.73 MWD+IFR-AK-CAZ-SC (4) 6,787.6 86.29 93.16 3,510.2 3,435.6 1,605.6 4,157.1 6,009,500.7 533,455.6 0.2 4,157.07 MWD+IFR-AK-CAZ-SC (4) 6,831.6 85.86 93.36 3,513.2 3,438.6 1,603.1 4,200.9 6,009,498.4 533,499.4 1.1 4,200.89 MWD+IFR-AK-CAZ-SC (4) 6,927.3 87.72 93.73 3,518.6 3,444.0 1,597.2 4,296.3 6,009,492.9 533,594.8 2.0 4,296.26 MWD+IFR-AK-CAZ-SC (4) 7,021.5 89.82 91.74 3,520.6 3,446.0 1,592.7 4,390.3 6,009,488.8 533,688.9 3.1 4,390.35 MWD+IFR-AK-CAZ-SC (4) 7,117.0 90.62 90.51 3,520.2 3,445.6 1,590.8 4,485.8 6,009,487.3 533,784.4 1.5 4,485.80 MWD+IFR-AK-CAZ-SC (4) 7,212.2 89.63 90.97 3,520.0 3,445.4 1,589.6 4,580.9 6,009,486.4 533,879.5 1.1 4,580.94 MWD+IFR-AK-CAZ-SC (4) 7,307.5 91.11 89.95 3,519.4 3,444.8 1,588.8 4,676.3 6,009,486.0 533,974.8 1.9 4,676.28 MWD+IFR-AK-CAZ-SC (4) 7,401.9 91.05 89.80 3,517.6 3,443.0 1,589.0 4,770.7 6,009,486.6 534,069.2 0.2 4,770.66 MWD+IFR-AK-CAZ-SC (4) 7,497.6 90.43 89.79 3,516.4 3,441.8 1,589.3 4,866.4 6,009,487.3 534,164.9 0.6 4,866.38 MWD+IFR-AK-CAZ-SC (4) 7,593.1 92.10 88.48 3,514.3 3,439.7 1,590.8 4,961.8 6,009,489.1 534,260.3 2.2 4,961.78 MWD+IFR-AK-CAZ-SC (4) 7,688.3 91.85 87.84 3,511.0 3,436.4 1,593.8 5,056.9 6,009,492.6 534,355.4 0.7 5,056.93 MWD+IFR-AK-CAZ-SC (4) 7,782.2 93.83 86.98 3,506.4 3,431.7 1,598.1 5,150.6 6,009,497.2 534,449.1 2.3 5,150.59 MWD+IFR-AK-CAZ-SC (4) 7,878.7 92.47 88.54 3,501.1 3,426.4 1,601.8 5,246.8 6,009,501.3 534,545.3 2.1 5,246.83 MWD+IFR-AK-CAZ-SC (4) 7,974.3 89.94 91.18 3,499.0 3,424.4 1,602.1 5,342.4 6,009,501.9 534,640.8 3.8 5,342.39 MWD+IFR-AK-CAZ-SC (4) 8,048.2 89.88 89.75 3,499.2 3,424.5 1,601.5 5,416.3 6,009,501.6 534,714.8 1.9 5,416.33 MWD+IFR-AK-CAZ-SC (4) 8,142.8 90.62 89.78 3,498.8 3,424.1 1,601.9 5,510.9 6,009,502.4 534,809.3 0.8 5,510.88 MWD+IFR-AK-CAZ-SC (4) 8,237.7 90.06 91.86 3,498.2 3,423.6 1,600.5 5,605.8 6,009,501.4 534,904.2 2.3 5,605.82 MWD+IFR-AK-CAZ-SC (4) 8,333.7 89.38 93.37 3,498.7 3,424.0 1,596.1 5,701.7 6,009,497.4 535,000.2 1.7 5,701.73 MWD+IFR-AK-CAZ-SC (4) 8,428.8 89.32 95.27 3,499.7 3,425.1 1,589.0 5,796.5 6,009,490.6 535,094.9 2.0 5,796.50 MWD+IFR-AK-CAZ-SC (4) 8,524.6 90.62 98.43 3,499.8 3,425.2 1,577.5 5,891.6 6,009,479.5 535,190.0 3.6 5,891.57 MWD+IFR-AK-CAZ-SC (4) 8,619.2 91.36 100.77 3,498.2 3,423.5 1,561.8 5,984.8 6,009,464.1 535,283.4 2.6 5,984.85 MWD+IFR-AK-CAZ-SC (4) 8,712.8 92.22 100.13 3,495.2 3,420.6 1,544.8 6,076.9 6,009,447.5 535,375.5 1.1 6,076.92 MWD+IFR-AK-CAZ-SC (4) 8,809.6 91.23 99.78 3,492.3 3,417.7 1,528.1 6,172.2 6,009,431.2 535,470.9 1.1 6,172.21 MWD+IFR-AK-CAZ-SC (4) 8,905.0 88.76 99.83 3,492.3 3,417.7 1,511.8 6,266.2 6,009,415.3 535,564.9 2.6 6,266.17 MWD+IFR-AK-CAZ-SC (4) j 9,000.5 87.90 98.92 3,495.1 3,420.5 1,496.3 6,360.3 6,009,400.1 535,659.1 1.3 6,360.31 MWD+IFR-AK-CAZ-SC (4) 9,095.3 89.01 100.83 3,497.7 3,423.0 1,480.0 6,453.7 6,009,384.2 535,752.5 2.3 6,453.69 MWD+IFR-AK-CAZ-SC (4) 9,190.6 88.27 102.68 3,499.9 3,425.3 1,460.6 6,546.9 6,009,365.2 535,845.8 2.1 I 6,546.93 MWD+IFR-AK-CAZ-SC (4) i 9,286.9 86.54 103.15 3,504.3 3,429.7 1,439.1 6,640.7 6,009,344.1 535,939.6 1.9 6,640.71 MWD+IFR-AK-CAZ-SC (4) 9,381.7 87.28 101.36 3,509.4 3,434.8 1,419.0 6,733.2 6,009,324.3 536,032.2 2.0 6,733.23 MWD+IFR-AK-CAZ-SC (4) 9,477.4 86.54 99.71 3,574.6 3,439.9 1,401.5 6,827.2 6,009,307.2 536,126.2 1.9 6,827.18 MWD+IFR-AK-CAZ-SC (4) 9,572.3 89.20 98.84 3,518.1 3,443.5 1,386.2 6,920.8 6,009,292.3 536,219.9 2.9 6,920.82 MWD+IFR-AK-CAZ-SC (4) 9,667.6 89.07 99.05 3,519.5 3,444.9 1,371.4 7,014.9 6,009,277.9 536,314.0 0.3 7,014.87 MWD+IFR-AK-CAZ-SC (4) 12/17/2008 9:29:09AM Page 5 COMPASS 2003.16 Build 42F ConocoPhillips or its affiliates Definitive Survey Report Company: ConocoPhillips(Alaska) Ina Loca) Co-ordinate Reference: We113K-103 (E14) Project: Kuparuk River Unit TVD Reference: 3K-103 @ 74.6ft (D15 (33.8+40.82)) Site: 3K-Pad MD Reference: 3K-103 @ 74.6ft (D15 (33.8+40.82)) Well: 3K-103 (E14) North Reference: True `W611bore: 3K-103 L7 Survey Calculation Method: Minimum Curvature Design: 3K-103 L1 Database: EDM Alaska Prod v16 Survey Map Map Vertical MD Inc Azl TVD TVDSS +Nl-S +E/-W Northing Easting DLS Section (ft) (°) (°) (ft) (ft) (ft) (ft) (ft) (ft) (° 1100') (ft) Survey Tool Name 5,762.7 88.76 99.38 3,521.3 3,446.7 7,356.2 7,108.7 6,009,263.0 536,407.9 0.5 7,108.71 MWD+IFR-AK-CAZ-SC~4) 9,857.3 88.95 98.24 3,523.2 3,448.6 1,341.7 7,202.2 6,009,248.9 536,501.5 1.2 7,202.25 MWD+IFR-AK-CAZ-SC (4) 9,952.7 90.18 96.26 3,523.9 3,449.3 1,329.7 7,296.8 6,009,237.2 536,596.1 2.4 7,296.83 MWD+IFR-AK-CAZ-SC (4) 10,048.2 91.30 96.39 3,522.7 3,448.1 1,319.2 7,391.8 6,009,227.1 536,691.1 1.2 7,391.75 MWD+IFR-AK-CAZ-SC (4) 10,143.5 91.30 95.95 3,520.5 3,445.9 1,308.9 7,486.5 6,009,217.2 536,785.8 0.5 7,486.48 MWD+IFR-AK-CAZ-SC (4) 10,238.3 91.17 95.61 3,518.5 3,443.9 1,299.4 7,580.8 6,009,208.1 536,880.2 0.4 7,580.76 MWD+IFR-AK-CAZ-SC (4) 10,333.8 91.36 92.59 3,516.4 3,441.8 1,292.6 7,676.0 6,009,201.6 536,975.4 3.2 7,676.03 MWD+IFR-AK-CAZ-SC (4) 10,430.1 91.30 97.10 3,514.2 3,439.5 1,284.4 7,771.9 6,009,193.9 537,071.3 4.7 7,771.88 MWD+IFR-AK-CAZ-SC (4) 10,524.0 90.93 97.03 3,512.3 3,437.7 1,272.9 7,865.0 6,009,182.7 537,164.5 0.4 7,865.05 MWD+IFR-AK-CAZ-SC (4) 10,619.0 90.68 96.35 3,511.0 3,436.4 1,261.8 7,959.4 6,009,172.0 537,258.9 0.8 7,959.38 MWD+IFR-AK-CAZ-SC (4) 10,714.5 89.07 96.47 3,511.2 3,436.6 1,251.2 8,054.3 6,009,161.7 537,353.8 1.7 8,054.28 MWD+IFR-AK-CAZ-SC (4) 10,809.6 89.32 96.66 3,512.5 3,437.9 1,240.3 8,148.8 6,009,151.2 537,448.3 0.3 8,148.79 MWD+IFR-AK-CAZ-SC (4) 10,904.4 88.52 98.20 3,514.3 3,439.7 1,228.0 8,242.8 6,009,139.3 537,542.4 1.8 8,242.76 MWD+IFR-AK-CAZ-SC (4) 11,000.1 89.38 99.07 3,516.1 3,441.5 1,213.7 8,337.3 6,009,125.3 537,637.0 1.3 8,337.34 MWD+IFR-AK-CAZ-SC (4) 11,095.3 89.32 99.87 3,517.2 3,442.5 1,198.0 8,431.2 6,009,110.0 537,730.9 0.8 8,431.25 MWD+IFR-AK-CAZ-SC (4) 11,189.5 88.21 98.80 3,519.2 3,444.6 1,182.7 8,524.2 6,009,095.1 537,823.9 1.6 8,524.20 MWD+IFR-AK-CAZ-SC (4) 11,285.4 87.10 99.59 3,523.1 3,448.5 1,167.4 8,618.8 6,009,080.2 537,918.6 1.4 8,618.79 MWD+IFR-AK-CAZ-SC (4) 11,380.9 86.79 100.11 3,528.2 3,453.6 1,151.1 8,712.7 6,009,064.2 538,012.6 0.6 8,712.73 MWD+IFR-AK-CAZ-SC (4) 71,475.6 86.29 99.43 3,533.9 3,459.3 1,135.1 8,805.9 6,009,048.6 538,105.8 0.9 8,805.91 MWD+IFR-AK-CAZ-SC (4) 11,571.1 84.19 99.59 3,541.8 3,467.2 1,119.3 8,899.7 6,009,033.2 538,199.7 2.2 8,899.72 MWD+IFR-AK-CAZ-SC (4) 11,665.9 86.91 98.68 3,549.2 3,474.6 1,104.3 8,993.1 6,009,018.6 538,293.1 3.0 8,993.08 MWD+IFR-AK-CAZ-SC (4) 11,761.1 84.32 97.48 3,556.5 3,481.9 1,091.0 9,087.0 6,009,005.6 538,387.1 3.0 9,087.03 MWD+IFR-AK-CAZ-SC (4) 11,855.9 87.16 101.94 3,563.5 3,488.9 1,075.1 9,180.1 6,008,990.0 538,480.2 5.6 9,180.14 MWD+IFR-AK-CAZ-SC (4) 11,905.9 87.71 101.48 3,565.8 3,491.1 1,064.9 9,229.0 6,008,980.1 538,529.2 1.4 9,229.05 MWD+IFR-AK-CAZ-SC (4) 11,951.3 88.52 99.85 3,567.2 3,492.6 1,056.5 9,273.6 6,008,971.9 538,573.8 4.0 9,273.65 MWD+IFR-AK-CAZ-SC (4) 12,046.2 89.57 98.15 3,568.8 3,494.2 1,041.7 9,367.4 6,008,957.4 538,667.6 2.1 9,367.41 MWD+IFR-AK-CAZ-SC (4) 12,142.4 88.64 95.31 3,570.3 3,495.7 1,030.4 9,462.9 6,008,946.5 538,763.2 3.1 9,462.91 MWD+IFR-AK-CAZ-SC (4) 72,237.4 89.63 97.38 3,571.8 3,497.1 1,019.9 9,557.3 6,008,936.4 538,857.6 2.4 9,557.33 MWD+IFR-AK-CAZ-SC (4) 12,301.6 88.02 97.85 3,573.1 3,498.5 1,011.4 9,621.0 6,008,928.1 538,921.3 2.6 9,620.96 MWD+IFR-AK-CAZ-SC (4) • 12,375.0 88.02 97.85 3,575.6 3,501.0 1,001.4 9,693.6 6,008,918.4 538,993.9. 0.0 9,693.58 PROJECTED to TD 12/17/2008 9:29:09AM Page 6 COMPASS 2003.16 Build 42F • ~ •. a t ~ 1 h p '~J -~, ~ ~ " r ~s ;) ~ ~..`~'-J LJ ~--x ~, 6 ° g~.~~ i 1.-~ aA ALASSA OIL A1QD GA5 CO1~T5ERQATIOI~T COMI~IISSIOI~T Randy Thomas Drilling Team Leader ConocoPhillips Alaska Inc. PO Box 100360 Anchorage, AK 99510-0360 SARAH PAL1N, GOVERNOR 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, 3K-103L 1 ConocoPhillips Alaska Inc. Permit No: 208-116 Surface Location: 885' FSL, 314' FWL, SEC. 35, T13N, R09E, UM Bottomhole Location: 1894' FSL, 551' FEL, SEC. 36, T13N, R09E, UM Dear Mr. Thomas: Enclosed is the approved application for permit to drill the above referenced service well. The permit is for a new wellbore segment of existing well KRU 3K-103, Permit No 208-115, API 50-029-23392-00. Production should continue to be reported as a function of the original API number stated above. This permit to drill does not exempt you from obtaining additional permits or an approval required. by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). Sincerely, ~~~7~.~~ Daniel T. Sea:nount, Jr. S~ Chair DATED this ~ day of July, 2008 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ~r~~.~i~ ~~~- 7 ~ 2CGS ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL ~~~~~~ ~'~ ~ ~~'~~ ~~~~~~• ~C~~~~i~5a~3f3 20 AAC 25.005 ~.: " ',:' ` -;? 1a. Type of Work: Drill ^/ Re-drill ^ Re-entry ^ 1b. Curzent Well Class: Exploratory Development Oil ^ Stratigraphic Test ^ Service Q Development Gas ^ Multiple Zone^ Single Zone ^ 1c. Specify if well is proposed for. Coalbed Methane ^ Gas Hydrates ^ Shale Gas ^ 2. Operator Name: ConocoPhillips Alaska, Inc. 5. Bond: / Blanket Single Well Bond No. 59-52-180 11. Well Name and Number: 3K-103L1 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 12398' ~ TVD: 3565' 12. Field/Pool(s): Kuparuk River Field 4a. Location of Well (Governmental Section): Surface: 885' FSL, 314' FWL, Sec. 35, T13N, R09E, UM 7. Property Designation: ADL 25519 West Sak Oil Pool Top of Productive Horizon: 2486' FSL, 2357' FVVL, Sec. 35, T13N, R09E, UM 8. Land Use Permit: ALK 2555 13. Approximate Spud Date: 9/7/2008 Total Depth: 1894' FSL, 551' FEL, Sec. 36, T13N, R09E, UM 9. Acres in Property: 2560 14. Distance to Nearest Property: 551' 4b. Location of Well (State Base Plane Coordinates): Surface: x- 529305 y- 6007879 Zone- 4 10. KB Elevation 7.3, $ L (Height above GL): feet 15. Distance to Nearest •O el~ thin ool: 3K-30 , 100' @ 4900' MD 16. Deviated wells: Kickoff depth: 4698 • ft. Maximum Hole Angle: 91.6° deg 17. Maximum Anticipated Pressures in psig (see 20 aaC 25.035) Downhole: 1711 psig Surface: 1319 psig 18. Casing Program f i Setting Depth Quantity of Cement Size icat ons Speci Top Bottom c. f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 40" 20" x 34" 94# K-55 Welded 80' 40' 40' 120' 120' 260 cf ArcticCRETE 16" 13.375" 68# L-80 BTC 2529' 40' 40' 2529' 2200' 610 sx AS Lite, 150 sx DeepCRETE 12.25" 9-5/8" 40# L-80 BTCM 5441' 40' 40' 5441' 3546' 480 sx DeepDRETE 6.75" 3.5" 9.3# L-80 Hydrill563 7700' 4698' 3454' 12398' 3565' screens 19 PRESENT WELL CONDITION SUMMARY (To be com pleted for Redrill and Re-Entry Operations) Total Depth MD (tt): Total Depth TVD (ft): Plugs (measured) Effective Depth MD (ff): Effective Depth TVD (ft): Junk (measured) Casing Length Size Cement Volume MD ND Conductor/Structural 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 Q 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Dennis Hartwig @ 265-6862 Printed Name ~ y~- Randy Thomas Title Drilling Team Leader / Signature ~ ~ ~, ~ L ~ Phone Date ~ / f~~.oD ~ ~6 h n A D Commission Use Only Permit to Drill Number: ~g"°' //~ API Number: /~ so- 029 233g2'~o Permit Approval Date: '7+ 3~ .O~ 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 methane, gas hydrates, or gas contained in shales: ~..~~ ~"~ ~~~,~~ ~~` t ~ ~ ~O ~ Samples req'd: Yes ^ No ~ Mud log req'd: Yes ^ No [/7 Other: ~ H2S measures: • Yes ^ No [>~ irectional svy req'd: Yes [~ No ^ ~~ APPROVED BY THE COMMISSION DATE: ,COMMISSIONER Form 10-401 Revised 12/2005 Submit in Duplicate ~_~~ .. r. App~n for Permit to Drill, Well 3K-103 L1 Revision No.0 Saved: 15-Jul-08 Permit It -West Sak Well #3K-103 L1 ~~°~ r.~ +'~ Application for Permit to Drill Document f~1~~cWll M d x i m i x~ V1~11 VQIUE Table of Contents 1. Well Name ................................................................................................................. 2 Re uirements of 20 AAC 25.005 .........................:........... 2 q (f) .................................................................. 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 Lateral Mud Program (MI VersaPro Mineral Oil Base) ........................................................................... 4 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 .................,................................................................... 5 Requirements of 20 AAC 25.005 (c)(11) ................................................................................................ 5 12. Evidence of Bonding ............................................................................................... 5 Requirements of 20 AAC 25.005 (c)(12) ................................................................................................ 5 ORIGINAL 3K-103 L1 PERMIT 1T.doc Page 1 of 7 Printed: 15-Jul-08 Appli~ for Permit to Drill, Well 3K-103 L1 Revision No.O Saved: 15-Jul-08 13. Proposed Drilling Program ..................................................................................... 5 Requirements of 20 AAC 25.005 (c)(13) ................................................................................................ 5 14. Discussion of Mud and Cuttings Disposal and Annular Disposal ....................... 6 Requirements of 20 AAC 25.005 (c)(14) ...................................:............................................................ 6 15. Attachments ............................................................................................................. 7 Attachment) Directional Plan ................................................................................................................ 7 Aftachment 2 Drilling Hazards Summary ..............................................................................................: 7 Attachment 3 Doyon 15 Wesf Sak 3ksi BOP Configuration ........................................................7 Aftachment 4 Well Schematic ............................................................................................................... 7 Aftachment 5 Quarter mile radius Injector effects .....................................................................7 1. Well Name Requirements of 20 AAC 25.005 (1) Each weir must be identified 6y a unique name designated by the operator and. a unique API number assigned by the commission under 20 AAC 25.04(1(6). For a tve/i with multiple wel/branches, each branch must similarly be identified by a unique nan7e and API number 6y adding a suffix to the Warne designated for the well by the operator and to the number assigned to the wefi by the commission. The well for which this Application is submitted will be designated as 3K-103 Ll. 2. Location Summary Requirements of 20 AAC 25.005(c)(2) An application for a Permit to L?rifl must be accompanied 6y each of the fol/owing 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 (AJthe coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at totaf depth, referenced to governmental section lines. (BJ the coordinates of the proposed iocatian of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the tUationai Geodetic Survey in the National Oceanic and Atmospheric Administration,' (C) the proposed depth of the we/I at the top of each objective formation and at total depth; Location at Surface 885' FSL, 314' FWL, Section 35, T13N, R09E ASP Zone 4 NAD 27 Coordinates RKB Elevation 73.8' AMSL • Northings; 6,007,879 Eastings: 529,305' Pad Elevation 33.8' AMSL Location at Top of Productive Interval West Sak "D" Sand 2,486' FSL, 2,357' FWL, Section 35, T13N, R09E ASPZone 4 NAD 27 Coordinates Measured De th, RKB; 4,698' North/ngs: 6,009,488' Eastings: 531,339' Total I/erticalDe th, RKB.• 3,454' Total ~ertica/ De th SS.• 3 379' Location at Total De th 1,894' FSL, 551' FEL, Section 36, T13N, R09E ASPZone 4 NAD v coordinates Measured De th, RKB: 12,398' Northings; 6,008,932' Eastings: 538,994' Total t/erticalDe th RKB: 3,565' Total t/ertica/ De th, SS.- 3,491' and (t7) other information required 6y 20 AAC 2S. 050(6); ~ ~ 3K-103 L1 PERMIT lT.doc . ~ ~ ~ Page 2 of 7 ~ -~ ~ `- Printed: 15-Jul-08 App~n for Permit to Drill, Well 3K-103 L1 Revision No.0 Saved: 15-Jul-08 Requirements of 20 AAC 25.050(b) If a weU is to be r"ntentionally deviated, the application for a Permit to I1ri// (Form i0-401) must (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 2CJ0 feet of any portion of the proposed well; Please see Attachment 1: Directional Plan 3K-103 Li and (Z) for al/ wells within 2Q© feet of the proposed wel/bore (A) list the names of the operators of those we/!s, to the extent that those names are known or dr"scoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) 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 Grill must be accompanied by each of the following items, except for an item a/ready on file with the commission and identified m the application. (3) a diagram and description of the blowout prevention equipment (BC3PE) as required by 2f1 AAC Z5 t735, ZO AAC ~5. C736, or 20 AAC Z5. t137, as applicable; An API 13-5/8" x 5,000 psi BOP stack (RSRRA) will be utilized to drill and complete well 3K-103 Li. For all drilling, casing and liner 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 9-5/8" rams in the lowermost cavity. For the dual 3-1/2" completion operations the stack will be equipped with dual 3-1/2"-rams in the uppermost ram cavity, blind rams in the middle cavity, and dual 3-1/2" rams in the lowermost cavity. A second set of dual 3-1/2" rams is required since the Annular will be ineffective while running dual 3-1/2" strings simultaneously. See attached diagram entitled 'Y~oyon IS West Sak 3ksi B4P Ct~nfiguration"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 9-5/8" OD. Prior to running the dual 3-1/2" completion, a test plug will be installed below the lower most rams, the upper and lower ram cavities will be equipped with dual 3-1/2" rams and tested to 3,000 psi. Please see information on the Doyon Rig 15 blowout prevention equipment placed on file with the Commission. 4. Drilling Hazards Information Requirements of 20 AAC 25.005 (c)(4) An application. for a Permit to ©rill must be accompanied by each of the fo/%wing 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 down/7ote pressure that maybe encountered, criteria used to determine it, and maximum potentia/surface. pressure based on a methane gradient; The expected reservoir pressures in the West Sak sands in the 3K area are 0.48 psi/ft, or 9.0 ppg EMW (equivalent mud weight). 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 ~~D" sand formation is 1,319 psi, calculated thusly: MPSP = (3,565 ft TVD)(0.48 - 0.11 psi/ft) = 1,319 psi (B) data on potential ga_s zones; 3K-103 L1 PERMIT IT.doc Page 3 of 7 Printed: 15-Jul-08 ORIGINAL The well bore is not expected to penetrate any gas zones. Appli~ for Permit to Drill, Well 3K-103 L1 Revision No.O Saved: 15-Jul-08 and (C) data concerning potential causes ofho/e problems such as abnarma/ly geo pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Attachment 2: 3K-103 L1 Drilling Hazards Summary. 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) An app/ication for a Permit to LJriIJ must be accompanied by each of the fo/lowing items, except for an item a/ready on file with the commission and r"dentified in the application; (5) a description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(fJ,• The parent wellbore, 3K-103, will be completed with a 9-5/8" intermediate casing landed in the West Sak B-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. No formation integrity test will be performed in the drilling of the 3K-103 Ll. 6. Casing and Cementing Program Requirements of 20 AAC 25.005(c)(6) An application for a Permit to Dn"ll must be accompanied by each of the following items, except for an item already on file with the. commission and identified in the appiication; (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/Tbg Size Weigh Length MD/TVD MD/TVD OD in in t Ib/ft Grade Connection ft ft ft Cement Pro ram 3-1/2 6-3/4" D Sand 9,3 L-80 Hydril 563 7,700 4698 / 3,454 12,398 / 3,565 Screens - no cement blank with Lateral (3K-103 Ll) & SLHT ResInject screens 7. Diverter System Information Requirements of 20 AAC 25.005(c)(7) An applcation for a Permit to L3ri1/ must be accompanied by each of the fol/owing items, except for an item a/ready on fife with the commission and identifed e'n 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)(Z); No diverter system will be utilized during operations on 3K-103 L1. 8. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(8) An applr`cation for a Permit to Drill must be accompanied by each of the following items, except far an item already on file with the commissr"on and identified in the application; (8) a drilling fluid program, including a diagram and description of the dri!/mg fluid system, as required by 20 AAC 25.033; Drilling will be done with mud having the following properties over the listed intervals: 3K-103 L1 PERMIT IT.doc Page 4 of 7 ~` Printed: 15-Jul-08 -.., ~.J App~n for Permit to Drill, Well 3K-103 L1 Revision No.O Saved: 15-Jul-08 Lateral Mud Program (MI VersaPro, Mineral Oil Base). Value Densit 9.0 - 9.3 Plastic Viscostiy Ib/100 s 15 - 25 Yield Point cP 15 - 20 HTHP Fluid loss (ml/30 min 200 si & 150° <4.0 Oil /Water Ratio 70 / 30 Electrical Stabilit 650-900 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 app/ication; (9) for an exploratory ar stratigraphic test well, a tabulatr"on setting out the depths of predr`cted abnormal/y geo pressured strata as required by 2fl 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 Perrrtit to Drill must be accompanied by each of the fol%wmg items, except for an item a/ready on Erie with the commission and identifed in the application; (10) for an exploratory or stratigraphic test well, a seismic refraction or reflection anal;psis as required by 20 AAC 25. f161(aJ; Not applicable: Application is not for an exploratory or stratigraphic test well. 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 a/ready on fife wih`r the commission and identified in the app/cation.• (11) for a well dri/Ced from an offshore platform, mobr`te bottom-founded structure, jack-up rig, or floating drilling vess% an analysis ofseabed conditions as required by 20 AAC 2s. fl61(b); Not applicable: Application is not for an offshore well. 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) An app/ication for a Permit to Dri/l must be accompanied by each of the fof/owing items, except far an item already on fi/e with the commission and identified in the app/ication: (IZ) evidence showing that the requirements of20 AAC 25.025 {Banding}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 a/ready on file with the commission and identified in the application: ORIGINAL 3K--103 L1 PERMIT IT.doc Page 5 of 7 Printed: 15-Jul-08 Appl~n for Permit to Drill, Well 3K-103 L1 Revision No.0 Saved: 15-Jul-08 The proposed drilling program is listed below. Please refer also to Attachment 3, Well Schematic. Note: Previous operations are covered under the 3K-103 Application for Permit to Drill. 1. Run and set Baker Gent WindowMaster whipstock system, at window point of +/- 4,698' MD / 3,454` TVD, the top of the D sand. 2. Mill 8-1/2" window. POOH. 3. Pick up 6-3/4"drilling assembly with LWD, MWD, PWD and rotary steerable tool. RIH. 4. Drill to TD of B sand lateral at +/- 12,398 MD / 3,565' TVD, as per directional plan. 5. Circulate 4 bottoms up with reciprocation and rotation. Open up PBL circulation sub and circulate 9-5/8" casing clean at increased flowrates for 4 bottoms. Close circ sub & displace to clear weighted brine. Pump out of Hole if necessary. 6. RIH with whipstock retrieval tool. Retrieve whipstock and POOH. 7. RIH and set Baker Seal Bore diverter 8. PU and run 3-1/2" Hydril 563 / SLHT blank liner, ResInject screens and TAM swell packers with Baker Oil Tools RAM Hangar system. 9. Land Baker RAM hanger in Baker seal bore diverter. Release hanger running tool. POOH laying down drill pipe as required. 10. PU 3-1/2" IBTM tubing and rack back in stands in Derrick 11. Install and test dual 3-1/2" RAMS as described above in Section 3. Notify AOGCC 24 hrs before test. 12. PU 3-1/2" Baker dual seal module, dual GT packer and dual 3-1/2" injection completion and RIH to depth. Land tubing. Set BPV 13. Nipple down BOPE, nipple up tree and test. Pull BPV. 14. Freeze protect well. with diesel by pumping into dual 3-1/2" x 9-5/8"annulus, taking returns from tubing and allowing to equalize. (If the schedule and equipment availability allows, the Wells Group will freeze protect the well post rig). 15. Set BPV's and move rig off. 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 mustc be accompanied by each of the fol%YVing items, except for an item atready on fle wr'th the. commission and identified m the application; (14) a genera! description of how the operator plans to dispose of drilling mud and cuttings and a statement of whayther the operator intends to request authorization under 2t1 AAC 25. CI80 for an annular disposal operation m the well.; Waste fluids generated during the drilling process will be disposed of either by pumping authorized fluids into a permitted annulus on 3K 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 3K 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. 3K-103 L1 PERMIT IT.doc Printed: ~5-Ju108 ~~~~#~> App~n for Permit to Drill, Well 3K-103 L1 Revision No.0 Saved: 15-Jul-08 15. Attachments Attachment 1 Directional Plan Attachment 2 Drilling Hazards Summary Attachment 3 Doyon 15 West Sak 3ksi BOP configuration Aftachment 4 Well Schematic Attachment 5 Quarter mile radius Injector effects 3K-103 L1 PERMIT IT.doc Page 7 of 7 Printed: 15-Jul-08 ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 3K Pad Plan 3K-103 (E14) 3K-103 L1 Plan: 3K-103 L1 (wp08) Standard Proposal Report 27 June, 2008 HALl.IBURTt3N Sp®rry OrllHng Ssrvlcss ORIGINAL Project: Kuparuk River Unit WELLDETA[LS: PIan3K-103(E14) NAD1927(NADCONCONUS) AlasAaZone04 Hl~1..L1B1,lRTC3t~f Site: Kuparuk 3K Pad Ground Level: 34.30 Sperry OrflBnp Servia®o Well: Plan 3K-103 (E14) +N/-S +E/-W Northing Fasting Latittude Longitude Slot Wellbore: 3K-103 L1 0.00 0.00 6007879.01 529305.34 70° 25' 57.374 N 149° 45' 40.018 W Design: 3K-103 L1 (wp08) FORMATION TOP DETAILS -1000 TVDPath NDssPath MDPath Formation 1572.70 1498.40 1677.06 T3 1639.00 1564.70 1763.61 Pfrost 1796.68 1722.38 1975.98 K15 2394.39 2320.09 2794.83 T3+800 -500 2779.79 2705.49 3322.82 Ugnu C 3028.05 2953.75 3673.57 Ugnu B 3125.19 3050.89 3827.00 Ugnu A 3247.15 3172.85 4047.39 K 13 3453.70 3379.40 4697.86 W Sak D 0 CASING DETAILS TVD TVDSS MD Size Natne 1000 2200.00 2125.70 2528.52 13-3/8 13 3/8" 3453.71 3379.41 4697.92 9-5/8 9 5/8" TOW 3565.20 3490.90 12398.41 3-1/2 3 1/2" c_ 1500 2000 g 5/8" TOW @ 4698' MD, 3454' ND: 2486' FSL, 2357' FWL - Sec35-T13N-R09E ~~ BHL @ 12398' MD, 3565' ND: 1894' FSL, 551' FEL - Sec36-T13N-R09E ~ ~ i ~ 2500 ~ ~~ i ~ i ~ X500 Ugnu A ~ \ 3000 -`2~ ~ - O ,~ 0 0 0 0 ~ O o 0 0 o p o ~ op -- -RO oo i o 0 0 0 0 ~ o ~ o°° °> ~K13- -- ~ ,~ oo ~°n m o ~ aoo ~ ~ rn ~'-ro ~~ ~~ N ~, rn~ to m m ---------~---- --- --------~- ---'---- --~.°--3K 103----- 3500 -wSakD----- ---- - -- ------------ ~ __ L1(wp08) ~~ ~ o o i o n° o i° o , i ~ i \~\ ~3K-103 (wp08) 9 5/8" TOW i ~ , i i i i 3 1/2" ~ ~ , i i i i 4000 ~ ~ i ' ' ' ~ i i i i i i i i i i i i 3K-103 L1 CP1 (03/05/08) it 3K-103 L1 CP3 (03/05/08) ' 3K-103 L1 CP5 (03/05/08) i i i i i 4500 3K-103 L1 CP2 (03/05/08) 3K-103 L1 CP4 (03/05/08) 3K-103 L1 CP6 (03/05/08) 3K-103 L1 Toe (03/05/08) 5000 ~~ ~I i i i ~ 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 750D 8000 8500 9000 9500 10000 10:,0 Vertical Section at 90.00° (1000 ft/in) ~ ConocoPhillips Ak'151k'} ~~~ Database: EDM 2003.16 Single User Db Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3K Pad Well: Plan 3K-103 (E14) Wellbore: 3K-103 L1 Design: 3K-103 L1 (vrp08) Halliburton -Sperry Standard Proposal Report Local Co-ordinate Reference: Well Plan 3K-103 (E14) TVD Reference: Doyon15 (34.3+40) ~ 74.30ft MD Reference: Doyon15 (34.3+40) @ 74.30ft North Reference: True Survey Calculation Method: Minimum Curvature Project Kuparuk River Unit, North Slope Alaska, United 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 Site Kuparuk 3K Pad Site Position: Northing: 6,008,428.74ft Latitude: 70° 26' 2.780 N ' ° From: Map Easting: 529,306.18ft Longitude: 39.930 W 45 149 ° Position Uncertainty: 0.00 ft Slot Radius: 0" Grid Convergence: 0.23 Well Plan 3K-i03 (E14) Well Position +N/-S 0.00 ft Northing: 6,007,879.01 ft Latitude: 70° 25' 57.374 N +E/-W 0.00 ft Easting: 529,305.34 ft Longitude: 149° 45' 40.018 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 34.30ft Wellbore 3K-103 L1 Magnetics Model Name Sample Date bggm2007 _ 10/15/2007 Design 3K-103 L1 Iwp08) Audit Notes: Declination Dip Angle (°) (°) 17.98 79.80 Version: 8 Phase: PLAN Vertical Section: Depth From (TVD) +N/-S (ft) (ft) 40.00 0.00 Field Strength (nT) 57,264 Tie On Depth: 4,697.90 +E/-W Direction (ft) (°) 0.00 90.00 6/27/2008 11:13:40AM Pa e 2 COMPASS 2003..16 Build 42F ~~ • Halliburton -Sperry ~~ '"~"` Standard Proposal Report Database: EDM 2003.16 Single User Db Local Co-ordinate Reference: Well Plan 3K-103 (E14) Company: ConocoPhillips (Alaska) Inc. -Kup2 ND Reference: Doyonl5 (34.3+40) @ 74.30ft Project: Kuparuk River Unit MD Refere nce: Doyon15 (34.3+40) @ 74.30ft Site: Kuparuk 3K Pad North Reference: True Well: Plan 3K-103 (E14) Survey Cal culation Meth od: Minimum Curvature Wellbore: 3K-103 L1 Design: 3K-103 L1 (wp08) Plan Sections ', Measured Vertical ND Dogleg Build Turn Depth Inclination Azimuth Depth System +N/-S +E/-W Rate Rate Rate Tool Face (ft) (°) (°) (ft) ft (ft) (ft) (°I100ft) {°I100ft) (°1100ft) (°) 4,697.90 80.00 90.01 3,453.71 3,379.41 1,601.15 2,039.89 0.00 0.00 0.00 0.00 4,714.40 82.24 90.01 3,456.25 3,381.95 1,601.14 2,056.19 13.60 13.60 0.00 0.00 4,744.40 82.24 90.01 3,460.30 3,386.00 1,601.14 2,085.92 0.00 0.00 0.00 0.00 4,909.85 90.14 87.54 3,471.28 3,396.98 1,604.68 2,250.82 5.00 4.77 -1.49 -17.42 4,973.30 90.14 87.54 3,471.12 3,396.82 1,607.40 2,314.22 0.00 0.00 0.00 0.00 5,079.49 88.72 90.39 3,472.18 3,397.88 1,609.31 2,420.37 3.00 -1.34 2.68 116.52 6,329.49 88.72 90.39 3,500.10 3,425.80 1,600.71 3,670.03 0.00 0.00 0.00 0.00 6,461.11 90.04 90.40 3,501.53 3,427.23 1,599.80 3,801.63 1.00 1.00 0.01 0.44 7,299.60 90.04 90.40 3,501.00 3,426.70 1,593.89 4,640.11 0.00 0.00 0.00 0.00 7,377.10 91.59 90.39 3,499.90 3,425.60 1,593.35 4,717.59 2.00 2.00 -0.01 -0.43 8,331.09 91.59 90.39 3,473.50 3,399.20 1,586.81 5,671.19 0.00 0.00 0.00 0.00 8,636.94 90.59 99.52 3,467.67 3,393.37 1,560.43 5,975.51 3.00 -0.32 2.98 96.11 9,329.73 90.59 99.52 3,460.50 3,386.20 1,445.90 6,658.74 0.00 0.00 0.00 0.00 9,407.43 88.83 97.99 3,460.89 3,386.59 1,434.08 6,735.53 3.00 -2.27 -1.97 -139.05 10,129.44 88.83 97.99 3,475.60 3,401.30 1,333.77 7,450.38 0.00 0.00 0.00 0.00 10,174.60 89.73 98.12 3,476.17 3,401.87 1,327.44 7,495.10 2.00 1.98 0.28 8.13 11,229.97 89.73 98.12 3,481.20 3,406:90 1,178.46 8,539.89 0.00 0.00 0.00 0.00 11,432.49 83.65 98.06 3,492.89 3,418.59 1,150.02 8,739.96 3.00 -3.00 -0.03 -179.49 11,696.79 83.65 98.06 3,522.12 3,447.82 1,113.18 9,000.04 0.00 0.00 0.00 0.00 11,798.41 86.70 98.07 3,530.66 3,456.36 1,098.98 9,100.29 3.00 3.00 0.01 0.16 12,398.41 86.70 98.07 3,565.20 3,490.90 1,014.89 9,693.36. 0.00 0.00 0.00 0.00 6/27/2008 11:13:40AM Page 3 COMPASS 2003.16 Build 42F ORIGINAL n U Database: EDM 2003.16 Single User Db Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3K Pad Well: Plan 3K-103 (E14) Wellbore: 3K-103 L1 Design: 3K-103 L1 (wp08) Planned Survey Measured Vertical Depth Inclination Azimuth Depth (ft) (°) (°) (ft) Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Map NDss +N/-S +E/-W Northing ft (ft) (ft) lft) Halliburton -Sperry Standard Proposal Report Well Plan 3K-103 (E14) Doyon15 (34.3+40) ~ 74.30ft Doyon15 (34.3+40) @ 74.30ft True Minimum Curvature Map Fasting DLS Vert Section (ft) 3,379.40 4,697.86 80.00 90.01 3,453.70 3,379.40 1,601.15 2,039.85 6,009,488.00 531,338.68 0.00 2,039.85 WSakD 4,697.90 80.00 90.01 3,453.71 3,379.41 1,601.15 2,039.89 6,009,488.00 531,338.72 0.00 2,039.89 9 5/8" TOW @ 4698' MD, 3454' ND: 2486' FSL, 2357 FWL - Sec35-T73N-R09E 4,697.92 80.00 90.01 3,453.71 3,379.41 1,601.15 2,039.91 6,009,488.00 531,338.74 0.00 2,039.91 9 518" TOW 4,700.00 80.29 90.01 3,454.07 3,379.77 1,601.15 2,041.96 6,009,488.01 531,340.79 13.73 2,041.96 4,714.40 82.24 90.01 3,456.25 3,381.95 1,601.14 2,056.19 6,009,488.06 531,355.02 13.60 2,056.19 4,744.40 82.24 90.01 3,460.30 3,386.00 1,601.14 2,085.92 6,009,488.17 531,384.75 0.00 2,085.92 4,800.00 84.90 89.18 3,466.53 3,392.23 1,601.53 2,141.16 6,009,488.78 531,439.98 5.00 2,141.16 4,900.00 89.67 87.69 3,471.26 3,396.96 1,604.27 2,240.98 6,009,491.91 531,539.78 5.00 2,240.98 4,909.85 90.14 87.54 3,471.28 3,396.98 1,604.68 2,250.82 6,009,492.36 531,549.62 5.00 2,250.82 4,973.30 90.14 87.54 3,471.12 3,396.82 1,607.40 2,314.22 6,009,495.32 531,613.00 0.00 2,314.22 5,000.00 89.78 88.26 3,471.14 3,396.84 1,608.37 2,340.90 6,009,496.41 531,639.67 3.00 2,340.90 5,079.49 88.72 90.39 3,472.18 3,397.88 1,609.31 2,420.37 6,009,497.65 531,719.13 3.00 2,420.37 5,100.00 88.72 90.39 3,472.64 3,398.34 1,609.17 2,440.87 6,009,497.59 531,739.63 0.00 2,440.87 5,200.00 88.72 90.39 3,474.87 3,400.57 1,608.48 2,540.84 6,009,497.30 531,839.59 0.00 2,540.84 5,300.00 88.72 90.39 3,477.10 3,402.80 1,607.79 2,640.82 6,009,497.00 531,939.56 0.00 2,640.82 5,400.00 88.72 90.39 3,479.34 3,405.04 1,607.10 2,740.79 6,009,496.71 532,039.52 0.00 2,740.79 5,500.00 88.72 90.39 3,481.57 3,407.27 1,606.42 2,840.76 6,009,496.41 532,139.49 0.00 2,840.76 5,600.00 88.72 90.39 3,483.80 3,409.50 1,605.73 2,940.74 6,009,496.12 532,239.45 0.00 2,940.74 5,700.00 88.72 90.39 3,486.04 3,411.74 1,605.04 3,040.71 6,009,495.82 532,339.42 0.00 3,040.71 5,800.00 88.72 90.39 3,488.27 3,413.97 1,604.35 3,140.68 6,009,495.53 532,439.38 0.00 3,140.68 5,900.00 88.72 90.39 3,490.51 3,416.21 1,603.67 3,240.65 6,009,495.24 532,539.35 0.00 3,240.65 6,000.00 88.72 90.39 3,492.74 3,418.44 1,602.98 3,340.63 6,009,494.94 532,639.31 0.00 3,340.63 6,100.00 88.72 90.39 3,494.97 3,420.67 1,602.29 3,440.60 6,009,494.65 532,739.28 0.00 3,440.60 6,200.00 88.72 90.39 3,497.21 3,422.91 1,601.60 3,540.57 6,009,494.35 532,839.24 0.00 3,540.57 6,300.00 88.72 90.39 3,499.44 3,425.14 1,600.92 3,640.54 6,009,494.06 532,939.21 0.00 3,640.54 6,329.49 88.72 90.39 3,500.10 3,425.80 1,600.71 3,670.03 6,009,493.97 532,968.69 0.00 3,670.03 3K-103 L1 CP1 (03/05!08) 6,400.00 89.43 90.40 3,501.24 3,426.94 1,600.23 3,740.52 6,009,493.76 533,039.18 1.00 3,740.52 6,461.11 90.04 90.40 3,501.53 3,427.23 1,599.80 3,801.63 6,009,493.57 533,100.28 1.00 3,801.63 6,500.00 90.04 90.40 3,501.50 3,427.20 1,599.52 3,840.52 6,009,493.45 533,139.17 0.00 3,840.52 6,600.00 90.04 90.40 3,501.44 3,427.14 1,598.82 3,940.52 6,009,493.14 533,239.16 0.00 3,940.52 6,700.00 90.04 90.40 3,501.38 3,427.08 1,598.11 4,040.52 6,009,492.82 533,339.15 0.00 4,040.52 6,800.00 90.04 90.40 3,501.31 3,427.01 1,597.41 4,140.51 6,009,492.51 533,439.14 0.00 4,140.51 6,900.00 90.04 90.40 3,501.25 3,426.95 1,596.70 4,240.51 6,009,492.20 533,539.13 0.00 4,240.51 7,000.00 90.04 90.40 3,501.19 3,426.89 1,596.00 4,340.51 6,009,491.89 533,639.12 0.00 4;340.51 7,100.00 90.04 90.40 3,501.13 3,426.83 1,595.29 4,440.51 6,009,491.57 533,739.11 0.00 4,440.51 7,200.00 90.04 90.40 3,501.06 3,426.76 1,594.59 4,540.50 6,009,491.26 533,839.09 0.00 4,540.50 7,299.60 90.04 90.40 3,501.00 3,426.70 1,593.89 4,640.11 6,009,490.95 533,938.69 0.00 4,640.11 3K-103 L1 CP2 (03/05/08) 7,300.00 90.04 90.40 3,501.00 3,426.70 1,593.88 4,640.50 6,009,490.95 533,939.08 2.00 4,640.50 7,377.10 91.59 90.39 3,499.90 3,425.60 1,593.35 4,717.59 6,009,490.72 534,016.16 2.00 4,717.59 7,400.00 91.59 90.39 3,499.27 3,424.97 1,593.19 4,740.48 6,009,490.65 534,039.06 0.00 4,740.48 6/27/2008 11:13:40AM 4 COMPASS 2003.16 Build 42F i ~~ ~~ Database: EDM 2003.16 Single User Db Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3K Pad Well: Plan 3K-103 (E14) Wellbore: 3K-103 L1 Design: 3K-103 L1 (wp08) Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Planned Survey Measured Vertical Map Depth Inclination Azimuth Depth TVDss +NI-S +E/_yy Northing (ft) (°) (°) (ft) ft (ft) (ft) (ft) • Halliburton -Sperry Standard Proposal Report Well Plan 3K-103 (E14) Doyonl5 (34.3+40) @ 74.30ft Doyon15(34.3+40) @ 74.30ft True Minimum Curvature Map Fasting DLS Vert Section (ft) 3,422.20 7,500.00 91.59 90.39 3,496.50 3,422.20 1,592.51 4,840.44 6,009,490.36 534,139.01 0.00 4,840.44 7,600.00 91.59 90.39 3,493.73 3,419.43 1,591.82 4,940.40 6,009,490.07 534,238.96 0.00 4,940.40 7,700.00 91.59 90.39 3,490.97 3,416.67 1,591.14 5,040.36 6,009,489.77 534,338.91 0.00 5,040.36 7,800.00 91.59 90.39 3,488.20 3,413.90 1,590.45 5,140.32 6,009,489.48 534,438.86 0.00 5,140.32 7,900.00 91.59 90.39 3,485.43 3,411.13 1,589.77 5,240.28 6,009,489.19 534,538.81 0.00 5,240.28 8,000.00 91.59 90.39 3,482.66 3,408.36 1,589.08 5,340.24 6,009,488.90 534,638.76 0.00 5,340.24 8,100.00 91.59 90.39 3,479.90 3,405.60 1,588.40 5,440.20 6,009,488.61 534,738.71 0.00 5,440.20 8,200.00 91.59 90.39 3,477.13 3,402.83 1,587.71 5,540.15 6,009,488.31 534,838.67 0.00 5,540.15 8,300.00 91.59 90.39 3,474.36 3,400.06 1,587.03 5,640.11 6,009,488.02 534,938.62 0.00 5,640.11 8,331.09 91.59 90.39 3,473.50 3,399.20 1,586.81 5,671.19 6,009,487.93 534,969.69 0.00 5,671.19 3K-103 L1 CP3 (03/05108) 8,400.00 91.36 92.45 3,471.73 3,397.43 1,585.11 5,740.05 6,009,486.50 535,038.55 3.00 5,740.05 8,500.00 91.04 95.43 3,469.63 3,395.33 1,578.24 5,839.78 6,009,480.02 535,138.30 3.00 5,839.78 8,600.00 90.71 98.41 3,468.09 3,393.79 1,566.19 5,939.03 6,009,468.36 535,237.59 3.00 5,939.03 8,636.94 90.59 99.52 3,467.67 3,393.37 1,560.43 5,975.51 6,009,462.75 535,274.09 3.00 5,975.51 8,700.00 90.59 99.52 3,467.02 3,392.72 1,550.01 6,037.71 6,009,452.57 535,336.31 0.00 6,037.71 8,800.00 90.59 99.52 3,465.98 3,391.68 1,533.47 6,136.33 6,009,436.43 535,434.99 0.00 6,136.33 8,900.00 90.59 99.52 3,464.95 3,390.65 1,516.94 6,234.94 6,009,420.28 535,533.66 0.00 6,234.94 9,000.00 90.59 99.52 3,463.91 3,389.61 1,500.41 6,333.56 6,009,404.14 535,632.33 0.00 6,333.56 9,100.00 90.59 99.52 3,462.88 3,388.58 1,483.88 6,432.18 6,009,388.00 535,731.01 0.00 6,432.18 9,200.00 90.59 99.52 3,461.84 3,387.54 1,467.35 6,530.80 6,009,371.86 535,829.68 0.00 6,530.80 9,300.00 90.59 99.52 3,460.81 3,386.51 1,450.82 6,629.42 6,009,355.72 535,928.35 0.00 6,629.42 9,329.73 90.59 99.52 3,460.50 3,386.20 1,445.90 6,658.74 6,009,350.92 535,957.69 0.00 6,658.74 3K-103 L1 CP4 (03/05!08) 9,400.00 89.00 98.13 3,460.75 3,386.45 1,435.12 6,728.17 6,009,340.41 536,027.16 3.00 6,728.17 9,407.43 88.83 97.99 3,460.89 3,386.59 1,434.08 6,735.53 6,009,339.40 536,034.52 3.00 6,735.53 9,500.00 88.83 97.99 3,462.78 3,388.48 1,421.22 6,827.18 6,009,326.90 536,126.21 0.00 6,827.18 9,600.00 88.83 97.99 3,464.81 3,390.51 1,407.33 6,926.19 6,009,313.39 536,225.26 0.00 6,926.19 9,700.00 88.83 97.99 3,466.85 3,392.55 1,393.43 7,025.20 6,009,299.89 536,324.31 0:00 7,025.20 9,800.00 88.83 97.99 3,468.89 3,394.59 1,379.54 7,124.21 6,009,286.39 536,423.37 0.00 7,124.21 9,900.00 88.83 97.99 3,470.93 3,396.63 1,365.65 7,223.22 6,009,272.88 536,522.42 0.00 7,223.22 10,000.00 88.83 97.99 3,472.96 3,398.66 1,351.75 7,322.23 6,009,259.38 536,621.47 0.00 7,322.23 10,100.00 88.83 97.99 3,475.00 3,400.70 1,337.86 7,421.23 6,009,245.88 536,720.53 0.00 7,421.23 10,129.44 88.83 97.99 3,475.60 3,401.30 1,333.77 7,450.38 6,009,241.90 536,749.69 0.00 7,450.38 3K-103 L1 CP5 (03/05/08) 10,174.60 89.73 98.12 3,476.17 3,401.87 1,327.44 7,495.10 6,009,235.75 536,794.42 2.00 7,495.10 10,200.00 89.73 98.12 3,476.29 3,401.99 1,323.86 7,520.24 6,009,232.27 536,819.58 0.00 7,520.24 10,300.00 89.73 98.12 3,476.77 3,402.47 1,309.74 7,619.24 6,009,218.54 536,918.62 0.00 7,619.24 10,400.00 89.73 98.12 3,477.24 3,402.94 1,295.62 7,718.23 6,009,204.81 537,017.66 0.00 7,718.23 10,500.00 89.73 98.12 3,477.72 3,403.42 1,281.51 7,817.23 6,009,191.09 537,116.70 0.00 7,817.23 10,600.00 89.73 98.12 3,478.20 3,403.90 1,267.39 7,916.23 6,009,177.36 537,215.74 0.00 7,916.23 10,700.00 89.73 98.12 3,478.67 3,404.37 1,253.27 8,015.23 6,009,163.63 537,314.79 0.00 8,015.23 10,800.00 89.73 98.12 3,479.15 3,404.85 1,239.16 8,114.22 6,009,149.91 537,413.83 0.00 8,114.22 10,900.00 89.73 98.12 3,479.63 3,405.33 1,225.04 8,213.22 6,009,136.18 537,512.87 0.00 8,213.22 11,000.00 89.73 98.12 3,480.10 3,405.80 1,210.92 8,312.22 6,009,122.45 537,611.91 0.00 8,312.22 6/27/2008 11:13:40AM Page 5 COMPASS 2003.16 Build 42F ORIGINAL ~~L~~ Halliburton -Sperry Standard Proposal Report Database: EDM 2003.16 Single User Db Local Co-ordinate Reference: Well Plan 3K-103 (E14) Company: ConocoPhillips (Alaska) Inc. -Kup2 ND Reference: Doyon15 (34.3+40) @ 74.30ft Project: Kuparuk River Unit MD Reference: Doyonl5 (34.3+40) @ 74.30ft Site: Kuparuk 3K Pad North Reference: True well: Plan 3K-103 (E14) Survey Calculation Method: Minimum Curvature Wellbore: 3K-103 L1 Design: 3K-103 L1 (wp08) Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth NDss +N/S +E/-W Northing Easting DLS Vert Section (ft) (°) (°) (ft) ft (ft} (ft} {ft) (ft) 3,406.28 11,100.00 89.73 98.12 3,480.58 3,406.28 1,196.80 8,411.22 6,009,108.73 537,710.96 0.00 8,411.22 11,200.00 89.73 98.12 3,481.06 3,406.76 1,182.69 8,510.21 6,009,095.00 537,810.00 0.00 8,510.21 11,229.97 89.73 98.12 3,481.20 3,406.90 1,178.46 8,539.89 6,009,090.89 537,839.68 0.00 8,539.89 3K-103 L1 CP6 (03/05108).,. 11,300.00 87.63 98.10 3,482.82 3,408.52 1,168.58 8,609.19 6,009,081.29 537,909.02 3.00 8,609.19 11,400.00 84.63 98.07 3,489.57 3,415.27 1,154.56 8,707.96 6,009,067.65 538,007.83 3.00 8,707.96 11,432.49 83.65 98.06 3,492.89 3,418.59 1,150.02 8,739.96 6,009,063.24 538,039.85 3.00 8,739.96 11,500.00 83.65 98.06 3,500.36 3,426.06 1,140.61 8,806.39 6,009,054.09 538,106.31 0.00 8,806.39 11,600.00 83.65 98.06 3,511.41 3,437.11 1,126.67 8,904.80 6,009,040.54 538,204.76 0.00 8,904.80 11,696.79 83.65 98.06 3,522.12 3,447.82 1,113.18 9,000.04 6,009,027.43 538,300.05 0.00 9,000.04 11,700.00 83.75 98.06 3,522.47 3,448.17 1,112.74 9,003.20 6,009,026.99 538,303.21 3.00 9,003.20 11,798.41 86.70 98.07 3,530.66 3,456.36 1,098.98 9,100.29 6,009,013.62 538,400.34 3.00 9,100.29 11,800.00 86.70 98.07 3,530.75 3,456.45 1,098.76 9,101.86 6,009,013.40 538,401.91 0.00 9,101.86 11,900.00 86.70 98.07 3,536.51 3,462.21 1,084.74 9,200.71 6,008,999.78 538,500.80 0.00 9,200.71 12,000.00 86.70 98.07 3,542.27 3,467.97 1,070.73 9,299.55 6,008,986.15 538,599.69 0.00 9,299.55 12,100.00 86.70 98.07 3,548.02 3,473.72 1,056.71 9,398.40 6,008,972.53 538,698.58 0.00 9,398.40 12,200.00 86.70 98.07 3,553.78 3,479.48 1,042.70 9,497.24 6,008,958.90 538,797.47 0.00 9,497.24 12,300.00 86.70 98.07 3,559.54 3,485.24 1,028.68 9,596.09 6,008,945.28 538,896.36 0.00 9,596.09 12,398.41 86.70 98.07 3,565.20 3,490.90 1,014.89 9,693.36 6,008,931.87 538,993.68 0.00 9,693.36 BHL @ 12398' MD, 3565' ND: 1894' FSL, 551' FEL - Sec36-T73N-i209E - 3 112" - 3K•103 L7 Toe (03/05/08) Targets Target Name - hitlmiss target Dip Angle Dip Dir. ND +N/-S +E/-W Northing Easting -Shape (°) (°) (ft) (ft) (ft) (ft) (ft) 3K-103 L1 CP2 (03/05/08) -1.53 90.40 3,501.00 1,593.89 4,640.11 6,009,490.95 533,938.69 - plan hits target - Point 3K-103 L1 CP4 (03/05/08) 1.08 98.12 3,460.50 1,445.90 6,658.74 6,009,350.92 535,957.69 - plan hits target - Point 3K-103 L1 CP3 (03/05/08) -0.75 98.06 3,473.50 1,586.81 5,671.19 6,009,487.93 534,969.69 - plan hits target - Point 3K-103 L1 CP1 (03/05/08) 0.05 90.40 3,500.10 1,600.71 3,670.03 6,009,493.97 532,968.69 - plan hits target - Point 3K-103 L1 CP5 (03/05/08) 0.29 98.06 3,475.60 1,333.77 7,450.38 6,009,241.90 536,749.69 - plan hits target - Point 3K-103 L1 CP6 (03/05/08) 4.12 98.06 3,481.20 1,178.46 8,539.89 6,009,090.89 537,839.68 - plan hits target - Point 3K-103 L1 Toe (03!05/08) 2.16 98.06 3,565.20 1,014.89 9,693.36 6,008,931.87 538,993.68 - plan hits target - Point 6/27/2008 11:13:40AM Page 6 COMPASS 2003.16 Build 42F ~' _ gg ~ 1 ~~~ Database: EDM 2003.16 Single User Db Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 3K Pad Well: Plan 3K-103 (E14) Wellbore: 3K-103 L1 Design: 3K-103 L1 (wp08) Casing Points Measured Vertical Depth Depth (ft) (ft) 2,528.52 2,200.00 13 3/8" 4,697.92 3,453.71 9 5/8" TOW 12,398.41 3,565.20 31/2" Formations Measured Vertical Depth Depth (ft) (ft) 1,763.61 1,639.00 4,047.39 3,247.15 3,827.00 3,125.19 3,673.57 3,028.05 1,677.06 1,572.70 4,697.86 3,453.70 3,322.82 2,779.79 1,975.98 1,796.68 2,794.83 2,394.39 Plan Annotations Measured Vertical Depth Depth lft) (ft) 4,697.90 3,453.71 12,398.41 3,565.20 Halliburton -Sperry Standard Proposal Report Local Co-ordinate Reference: Well Plan 3K-103 (E14) TVD Reference: Doyon15 (34.3+40) @ 74.30ft MD Reference: Doyon15 (34.3+40) @ 74.30ft North Reference: True Survey Calculation Method: Minimum Curvature Casing Hole Diameter Diameter Name (~~) (~~) 13-3/8 16 9-5/8 12-1/4 3-1/2 6-3/4 Vertical DiP Depth SS pip Direction ft Name Lithology (°) (°) Pfrost 0.00 K 13 0.00 Ugnu A 0.00 Ugnu B 0.00 T3 0.00 W Sak D 0.00 Ugnu C 0.00 K15 0.00 T3+g00 0.00 Local Coordinates +N/-S +E/-W (ft) (ft) Comment 1,601.15 2,039.89 9 5/8" TOW @ 4698' MD, 3454' TVD: 2486' FSL,2357' FWL-Sec35-T13N-R09 1,014.89 9,693.36 BHL @ 12398' MD, 3565' TVD: 1894' FSL, 551' FEL - Sec36-T13N-R09E 6/27/2008 11:13:40AM Page 7 ~~~ COMPASS 2003.16 Bulld 42F ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 3K Pad Plan 3K-103 (E14) 3K-103 L1 3K-103 L1 (wp08) ~rerr~ Drilling ~ierv-ices ~~; Clearance Summary -~ Anticollision Report ~~ 27 June, 2008 Trav. Cylinder North Proximity Scan on Current Survey Data (North Reference) Reference Design: Kuparuk 3K Pad -Plan 3K-103 (E14) - 3K-103 L1 - 3K-103 L1 (wp08) Well Coordinates: 6,007,630.94 N, 1,669,336.72E (70° 25' 56.33" N, 149° 45' 51.30" W) Datum Height: Doyonl5 (34.3+40) ~ 74.30ft Scan Range: 4,697.90 to 12,398.45 ft. Measured Depth. Scan Radius is 1,435.84 ft . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 2003.16 Build: 42F Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 !i A 1..IL N IF'Ir !J R'f C3 IN Sperry ©rilling Services SURVEY PROGRAM ConocoPhillips (Alaska) Inc. -Kup2 I I ANTI-COLLISION SETTINGS Date: 2008-03-OS'I'OO:OU:W Validated: Yes Version: 8 Depth From Depth To Survey/Plan 'T'ool 40.00 1012.00 3K-103 (wp08) (3K-103) CB-GYRO-SS 1012.00 4697.90 3K-103 (wp08) (3K-I03) MWD+IFR-AK CA~SC 4697.90 12397.93 3K-103 Ll (wp08) (3K-103 Ll) MWD+IFR-AK-CA~SC ~~ 0 180 Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Trav. Cylinder North Error Surtace: Elliptical Conic Warning Method: Rules Based so Travelling Cylinder Azimuth (TFO+AZI) ~°J vs Centre to Centre Separation J200 ft/inJ Details: Plan 3K-103 (E14) North American Datum 1983 Alaska Zone 4 J Ground Level: 34.30 +N/-S +EI-W Northing Easting Latittude Longitude Slot 0.00 0.00 6007630.94 1669336.72 70°25'56.328 N 149°45'51.299 W REFERENCE INFORMATION Co-ordinate (NIE) Reference: Well Plan 3K-103 (E14), True North Vertical (TVD) Reference: Doyonl5 (34.3+40) ~ 74.30tt Section (VS) Reference: Slot - (O.OON, O.OOE) Measured Depth Reference: Doyonl5 (34.3+40) @ 74.30tt Calculation Method: Minimum Curvature From Colour To MD 0 262 262 512 512 762 762 1012 1012 1262 1262 1512 1512 _ ._____ . 1762 1762 --- 2012 2012 2262 2262 2512 2512 2762 2762 ------- 3012 3012 4012 4012 5012 5012 6012 6012 7012 7012 8012 8012 9012 9012 10012 10012 11012 11012 12012 12012 - 13012 13012 14012 14012 °------ - 15012 180 p Travelling Cylinder Azimuth (TFO+AZI) ~°~ vs Centre to Centre Separation 150 ft/in) SECTION DETAILS Sec MD Inc Azi 7VD +N/-S +E/-W DLeg TFace VSec Target 1 4697.90 80.00 90.01 3453.70 1601.33 2039.70 0.00 0.00 2039.70 2 4714.40 62.24 90.01 3456.25 1601.32 2056.00 13.60 0.00 2056.00 3 4744.40 82.24 90.01 3460.29 1601.32 2085.73 0.00 0.00 2085.73 4 4910.44 90.16 87.49 3471.29 1604.94 2251.22 5.00 -17.70 2251.22 5 4971.66 90.16 87.49 3471.12 1607.61 2312.39 0.00 0.00 2312.39 6 5079.54 88.72 90.39 3472.18 1609.60 2420.22 3.00 116.39 2420.22 7 6329.54 88.72 90.39 3500.10 1601.01 3669.86 0.00 0.00 3669.88 3K-103 L1 CP1 (03/05/08) 8 6461.15 90.04 90.40 3501.53 1600.10 3801.48 1.00 0.25 3801.48 9 7299.65 90.04 90.40 3501.00 1594.25 4639.95 0.00 0.00 4639.95 3K-103 L7 CP2 (03/05/08) iD 7377.14 91.59 90.39 3489.90 1593.71 4717.44 2.00 -0.42 4717.44 11 8331.13 91.59 90.39 3473.50 1587.25 5671.04 0.00 0.00 5671.04 3K-103 Lt CP3 (03/05/08) 12 8636.99 90.59 99.51 3467.67 1560.89 5975.37 3.00 96.11 5975.37 13 9329.77 90.59 99.51 3460.50 1446.41 6658.60 0.00 0.00 6658.60 3K-103 Li CP4 (03/OS/OB) 14 9407.48 88.83 97.98 3460.89 1434.59 6735.39 3.00 -139.05 6735.39 15 10129.48 88.83 97.98 3475.60 1334.32 7450.25 0.00 0.00 7450.25 3K-103 L1 CPS (03/05/08) 16 10174.65 89.73 98.11 3476.17 1328.00 7494.97 2.00 8.13 7494.97 17 11230.01 89.73 98.11 3481.20 1179.08 8539.76 0.00 0.00 8539.76 3K-1D3 Lt CP6 (03/D5/08) 18 11432.54 83.65 98.05 3492.89 1150.67 8739.85 3.00 •179.43 8739.85 19 11696.83 83.65 98.05 3522.12 1113.88 8999.93 0.00 0.00 8999.93 20 11798.45 86.70 98.07 3530.66 1099.68 9100.18 3.00 0.35 9100.18 21 12398.45 86.70 98.07 3565.20 1015.59 9693.25 0.00 D.00 9693.25 3K-103 L7 Toe (03/05/08) Interpolation Method: MD, interval: 50.00 Depth Range From: 4697.90 To 12398.45 Centre Distance: 1435.84 Reference: Plan: 3K-103 L1 (wp08) (Plan 3K-103 (E14)/3K-103 Q ConocoPhillips (Alaska) Inc. -Kup2 HALLIBURTON Kuparuk River Unit Anticollision Report for Plan 3K-103 (E14) - 3K-103 L1 (wp08) Trav. Cylinder North Proximity Scan on Current Survey Data (North Reference) Reference Design: Kuparuk 3K Pad -Plan 3K-103 (E14) - 3K-103 L1 - 3K-103 L1 (wp08) Scan Range: 4,697.90 to 12,398.45 ft. Measured Depth. Scan Radius is 1,435.84 ft . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Site Name Comparison Well Name - Wellbore Name -Design Kuparuk 3K Pad 3K-03 - 3K-03 - 3K-03 3K-07 - 3K-07 - 3K-07 3K-102 - 3K-102 - 3K-102 _ 3K-102 - 3K-102 - 3K-102 3K-102 - 3K-102L1 - 3K-102L1 3K-102 - 3K-102L1 - 3K-102L1 --- 3K-102 - 3K-102L1 PB1 - 3K-102L1 PB1 3K-102 - 3K-102L1 PB1 - 3K-102L1 P61 -,,...~ 3K-19 - 3K-19 - 3K-19 Z 3K-19 - 3K-19 - Gyro(861) + IFR Projection 3K-20 - 3K-20 - 3K-20 ~' 3K-20 - 3K-20 - 3K-20 6 3K-23 - 3K-23 - 3K-23 3K-24 - 3K-24 - 3K-24 3K-27 - 3K-27 - 3K-27 3K-27 - 3K-27 - 3K-27 3K-30 - 3K-30 - 3K-30 Plan 3K-103 (E14) - 3K-103 - 3K-103 (wp08) Plan 3K-105 (E15) - 3K-105 - 3K-105 wp04 Plan 3K-105 (E15) - 3K-105 - 3K-105 wp04 Plan 3K-105 (E15) - 3K-105 L1 - 3K-E15 L1 (wp03) Plan 3K-105 (E15) - 3K-105 L1 - 3K-E15 L1 (wp03) Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Depth Distance Depth Separation Depth Factor Minimum Separation Warning (ft) (ft) (ft) (ft) ft 4,706.56 211.81 4,706.56 101.97 4,475.00 1.928 Clearance Factor Pass -Major Risk 4,700.00 1,317.34 4,700.00 1,185.85 4,725.00 10.019 Clearance Factor Pass -Major Risk 4,708.39 1,207.11 4,708.39 1,091.72 6,375.00 10.461 Centre Distance Pass -Major Risk 12,232.55 1,246.25 12,232.55 932.67 14,084.00 3.974 Clearance Factor Pass -Major Risk 6,371.01 1,183.84 6,371.01 1,036.76 8,050.00 8.049 Centre Distance Pass -Major Risk 12,227.18 1,249.13 12,227.18 965.47 14,081.00 4.404 Clearance Factor Pass -Major Risk 6,371.01 1,183.84 6,371.01 1,036.76 8,050.00 8.049 Centre Distance Pass -Major Risk 10,600.16 1,253.69 10,600.16 1,003.85 12,456.00 5.018 Clearance Factor Pass -Major Risk 4,697.90 960.66 4,697.90 860.28 4,925.00 9.570 Clearance Factor Pass -Major Risk 4,697.90 964.32 4,697.90 857.43 4,925.00 9.022 Clearance Factor Pass -Major Risk 6,208.48 629.71 6,208.48 505.98 5,350.00 5.089 Centre Distance Pass -Major Risk 6,292.35 632.40 6,292.35 503.34 5,450.00 4.900 Clearance Factor Pass -Major Risk 4,697.90 1,184.98 4,697.90 1,068.27 5,325.00 10.153 Clearance Factor Pass -Major Risk 4,705.37 1,333.12 4,705.37 1,185.75 5,100.00 9.046 Clearance Factor Pass -Major Risk 6,088.58 975.21 6,088.58 828.02 5,275.00 6.626 Centre Distance Pass -Major Risk 6,152.62 975.88 6,152.62 827.29 5,350.00 6.568 Clearance Factor Pass -Major Risk 4,883.39 104.48 4,883.39 55.50 4,625.00 2.133 Clearance Factor Pass -Minor 1/200 4,715.34 1,251.64 4,715.34 1,144.02 4,375.00 11.630 Centre Distance Pass -Major Risk 12,396.64 1,256.73 12,396.64 945.85 11,875.00 4.043 Clearance Factor Pass -Major Risk 7,224.80 1,237.11 7,224.80 1,076.81 6,875.00 7.717 Centre Distance Pass -Major Risk 12,397.74 1,256.26 12,397.74 957.59 11,875.00 4.206 Clearance Factor Pass -Major Risk • • 27 June, 2008 - 16:51 Page 2 of 5 COMPASS ConocoPhillips (Alaska) Inc. -Kup2 ~~~~~~~~~,,,,,~~ Kuparuk River Unit Anticollision Report for Plan 3K-103 (E14) - 3K-103 L1 (wp08) Survev tool Aroaram From To Survey/Plan Survey Tool (ft) (ft) 40.00 1,012.00 CB-GYRO-SS 1,012.00 4,697.90 MWD+IFR-AK-CAZ-SC 4,697.90 12,397.93 3K-103 L1 (wp08) MWD+IFR-AK-CAZ-SC Ellipse error terms are correlated across survey tool tie-on points. • Clearance Factor =Distance Between Profiles / (Distance Between Profiles -Ellipse Separation). II station coordinates were calculated using the Minimum Curvature method. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. 27 June, 2008 - 16:51 Page 3 of 5 COMPASS 3K-1031 Drilling Hazards~ummary (SEE WELL PLAN AND ATTACHMENTS FOR DETAILED DISCUSSION OF THESE RISKS) 6-3/4" Open Hole / 3-1/2" Liner Interval Hazard Risk Level Mitigation Strate Abnormal Reservoir Pressure Low Stripping drills, shut-in drills, increased mud weight. Stuck Pipe Low Good hole cleaning, PWD tools, hole opener runs, decreased mud weight Well Collision Low Regyro critical offset wells to decrease positional uncertainty. Utilize travelling cylinder. plots for collision avoidance. Shut-in critical offset wells while drilling L1 roduction interval. Lost Circulation Moderate Reduced pump rates, mud Theology, LCM program, additional fluid stored on location during completion. Hole Swabbing on Trips Moderate Trip speeds, proper hole filling (use of trip sheets),pumping out, backreaming 3K-103L1 Drilling Hazards Summary.doc ~~ prepared by Dennis Hartwig 7/15/20089:21:09 AM Drill String Valves To be tested to 250 psi and 3,000 psi at initial installation and every 14 days thereafter. 13-5 Annular To be tested to 250 psi and 1,500 psi at initial installation and every 14 days thereafter. 13-5 Double Ram Upper Rams: 3-'/i' to 6" variables To be tested to 250 psi and 3,000 psi at initial installation and every 14 days thereafter. For Dual 3 '/2" completion operations, 3 '/2" dual rams to be installed and tested to 250 psi and 3,000 psi prior to completion run Lower Rams: Blind To be tested to 250 psi and 3,000 psi at initial installation and every 14 days thereafter. Choke and Kill Line Valves ~- To be tested to 250 psi and 3,000 psi at initial installation and every 14 days thereafter. 13-5 Single Ram Rams to fit Intermediate Casing: 7-5/8" or 9-5/8" To be tested to 250 psi and 3,000 psi only before ~_ running casing. For Dual 3-'h" completion operations, 3-'/2" dual rams to be installed and tested to 250 psi and 3,000 psi prior to completion run ~_ Wellhead Valves tested to 3,000 psi upon assembly 13-5 BOP 3K diagram. vsd ConocoPhillips Doyon 15 West Sak 3 ksi Sheet 1 of 1 BOP Configuration prepared by Dennis Hartwig Alaska ~r~rzooa Insulated Conductor: 20" 94# K-55 x 34" 0.312 WT +/- 80' ConocoPhi II ips 2008 West Sak Dual Injector System 2.875" DS Nipple 2.875"DSNipple with Level 5 Rotating self-Aligning Multilateral (RAM ) System GLM, Camco, 3-'/." x 1" KBG2-9 GLM, Camco, 3-%"x1"KBG2-9 West Sak 13-3/8" Casing Shoe 3K-103 2528' MD, 2200' TVD Dual Tubing Strings Rotational Alignment Sub 3-%" 9.3#, L-80, 2.992" ID, 2.867" Drift ~, // 2.812" DB Nipple 3-%" x 9-5/B" GT Dual Packer f D-Sand Casing Exit / 4697' MD, 3454' ND (80 deg) 3-'/," x 3-'/." x 9-5/8" Dual Seal Module for RAM Hanger 7" X 9-518" RAM Hanger ~ ~ _ _ ., 7" X 9-518" RAM Junction Mainbore Drift: 3.68" Lateral Drill: 5.80" RAM HangerlSeal Bore Diverter OD: 8.375" Overall Length of RAM Junction: 38.3 ft Seal Bore Diverter Running Tool: FJD RAM Hanger Running Tool: HRD-E 3 '/:" x 3-'/=' 9-5/8" Dual Seal Module DSM OD: 7.62" Lateral Seal Assembly OD: 3.75" Lateral lD: 2.69" Mainbore Seal Stinger OD: 3.08" Mainbore ID: 2.69" As Planned ®rm~ ~~~ Baker Oil Tools -. ~~ ~ ~ ~~ ~,~ ~ c'~ 'D' Sand Lateral TT~ -- `V~~, 3-'/." 9.3# Liner with Hydril 563 and SLHT connections --`-'~-~~-- Casing Shoe ~ 12398' MD, 3565' TVD , 5/8" RAM Seal Bore Diverter ~ 9 4%" - .. MLHR Production - x (SBD) far Dual Seal Module Anchor 3-%" 12.6# IBTM Tubing Seal Assembly 7" X 9-5/B" MLZXP 4.75" Seal OD " Liner Hanger Packer ID 3.875 '6' Sand Lateral 3-'/:" 9.3# Liner with Hydril 563 and SLHT connections Sealbore Receptacle ~ ~ ~' ap~~ .y Imo' y ~ ~ ~~ L~ ~ ~ ~ 4.75"ID ... Irv, w-.: ^^;._ ~ 1- ~ 1~ 9-518" Casing Shoe, 40 ~0# L-80 BTC Casing Shoe 5441' MD, 3546' TVD (84 deg) 12404' MD, 3611' TVD 8008 West Sak Dual Injector Concept Dravm BY: Revision No.: 8 June 30th, 3008 Dave Bjork • • Cc~na-ca Phillips ConocoPhillips Alaska, Inc. Kuparuk River Unit Kuparuk 3K Pad ~~ Plan: 3K-103 (wp08) 1/4 Mile Pool Scan ~ Sperry Drilling Services Apri128, 2008 U HALLIBURTON Grilling and Formation Evaluation Closest in POOL Closest A roach: Reference Well: 3K-103 w 0 8 Plan ffset W ell: 3K-03 Coords. - Coords. - ASP 3-D ctr-ctr Meas. Subsea ASP N(+)/S(-) NV ( View VS 90° Comments Meas. De th I ncl. An le TRUE Azi. Subsea ND N(+)/S(-) E +)/V1I -) View VS 90°) Comment Distance. De th I ncl. An le TRUE Azi. ND E + - n istance ( 237.59 ft) in POOL POOL Min Distance (4697.9 - 12398.45 (237.59 ft) in POOL MD) to 3K-103 L1 (4697.9 - 12398.45 (wp08) Plan (3359.4 - 1671371 894 2040 MD) to 3K-03 (3359.4 - 3569.2 TVDss) 4318 41.74 62.39 3456.07 6009096.1 1671258 1923.71 3569.2 NDss) 59 23T i~~k ~"` ._ `° 4697.9 80 90.01 3305.097 6009239.8 . . . h Reference Well: 3K-103 w 08 Plan Offset W ell: 3K-07 Closest : A roac Coords. - Coords. - 3-D ctr-ctr Meas. Subsea ASP N(+)/S(-) View VS 90° Comments Meas. De th Incl. An le TRUE Azi. Subsea TVD ASP N(+)/S(-) E + /W - View VS 90° Comments Distance. De th Incl. An le TRUE Azi. TVD E + /W - POOL Min Distance (1238.93 ft) in POOL POOL Min Distance (4679.9 - 12398.45 (1238.93 ft) in POOL MD) to 3K-103 L1 (4679.9 - 12398.45 (wp08) Plan (3359.4 - 1671371 894 2040 MD) to 3K-07 (3359.4 - 3569.2 TVDss) 4225 41.52 94.25 3584.96 6008104 1670963 1626.24 3569.2 NDss) 93 1238 4697.9 80 90.01 3305.097 6009239.8 . . h ference Well: 3K-103 w 08 R Plan Offset W ell: 3K-19 losest : A roac e Coords. - Coords. - ASP 3-D ctr-ctr Meas. Subsea ASP N(+)IS(-) View VS ° Meas. De th An le Incl TRUE Azi Subsea ND N(+)IS(-) E +)/W(-) View VS (90° Comments istance. De th Incl. An le TRUE Azi. ND E(+)/W(-) (90 ) Comments . . in istance (906.94 ft) in POOL POOL Min Distance (4697.9 - 12398.45 (906.94 ft) in POOL MD) to 3K-103 L1 (4697.9 - 12398.45 (wp08) Plan (3359.4 - 1671371 894 2040 MD) to 3K-19 (3359.4 - 3569.2 NDss) 4825 85.73 48.35 3356.87 6010142.1 1671295 1964.42 3569.2 TVDss) 94 906 -~~~ ~~ v 17`r;~ ~'~ 4697.9 80 90.01 3305.097 6009239.8 . . . Offset Well: 3 K-20 losest A roach: Reference Well : 3K-103 w 08 Plan Coords. - Coords. - ASP 3-D ctr-ctr Meas. Subsea ASP N(+)/S(-) View VS ° Meas. D th An le Incl TRUE Azi Subsea ND N(+)IS(-) E + IVV - View VS 90° Comments Distance. De th Incl. An le TRUE Azi. TVD E + /W - 90 Comments e . . m istance (745.57 ft) in POOL POOL Min Distance (4697.9 - 12398.45 (745.57 ft) in POOL MD) to 3K-103 L1 (4697.9 - 12398.45 (wp08) Plan (3359.4 - 1673497 51 4166 MD) to 3K-20 (3359.4 - 3569.2 TVDss) 6075 63.75 67.69 3352.73 6009989.8 1673488 4156.72 3569.2 NDss) 745 57 6825 90.04 90.4 3352.68 6009244.3 . . h ference Well: 3K-103 w 08 R Plan Offset Well: 3K-27 Closes : t A roac e Coords. - Coords. - 3-D ctr-ctr Meas. Subsea ASP N(+)IS(-) View VS ° ents C Meas. De th Incl. An le TRUE Azi. Subsea TVD ASP N(+)/S(-) E + /W - View VS 90° Comments Distance. De th Incl. An le TRUE Azi. ND E + /W - 90 omm L (980.81 ft) in POO POOL Min Distance (4697.9 - 12398.45 (980.81 ft) in POOL MD) to 3K-103 L1 (4697.9 - 12398.45 (wp08) Plan (3359.4 - 90 3 3 9 3341 2 5 6009247 1672547 3216.66 MD) to 3K-27 (3359.4 - 3569.2 NDss) 5020 55.71 88.34 3390.66 6008267.7 1672542 3205.66 3569.2 TVD 980.81 ~=%9.~" ~ a 1.39 587 5 88.72 . . . 4/28/2008 2:33 PM 3K-103 POOL Summa ry Template.xls Closest in POOL Closest A roach: Reference Well: 3K-103 w 08 Plan Offset Well: 3K-30 Coords. - Coords. - ASP ASP 3-D ctr-ctr Distance. Meas. Depth Incl. Angle TRUE Azi. Subsea ND N(+)/S(-) E + /W(-) View VS (90°) Comments Meas. De th Incl. Angle TRUE Azi. Subsea ND N(+)/S(-) E +)/W(-) View VS 90°) Comments P L Min Distance POOL Min Distance (100.31 ft) in POOL \ (100.31 ft) in POOL (4697.9 - 12398.45 (4697.9 - 12398.45 MD) to 3K-103 L1 MD) to 3K-30 (3359.4 (wp08) Plan (3359.4 - 700.31 ~+ci '" ` ° " ° 4900 89.66 87.65 3322.678 6009243.8 1671573 2241.98 - 3569.2 NDss) 4650 52.56 43.56 3349.04 6009340.4 1671567 2235.14 3569.2 NDss) Closest A roach: Reference Well: 3K-103 w 08 Plan Offset Well: 3K-102 Coords. - Coords. - ASP ASP 3-D ctr-ctr ' fence. Meas. De th Incl. An le TRUE Azi. Subsea ND N(+)/S(-) E + /W - View VS 90° Comments Meas. De th Incl. An le TRUE Azi. Subsea ND N(+)/S(-) E + /W - View VS 90° Comments POOL Min Distance POOL Min Distance (1223.67 ft) in POOL (1223.67 ft) in POOL (4697.9 - 12398.45 MD) to 3K-102 (4697.9 - 12398.45 MD) to 3K-103 L1 1223.67 <4~,5E? 5050 89.11 89.6 3323.02 6009249.5 1671722 2391.88 (3359.4 - 3569.2 NDss) 6725 74.65 88.51 3358 6010472.6 1671727 2401.22 (wp08) Plan (3359.4 - 3569.2 NDss) Closest A roach: Reference Well: 3K-103 w 08 Plan Offset Well: 3K-24 Coords. - Coords. - ASP ASP 3-D ctr-ctr Distance. Meas. De th Incl. An le TRUE Azi. Subsea ND N(+)/S(-) E + /W - View VS 90° Comments Meas. De th Incl. An le TRUE Azi. Subsea ND N(+)/S(-) E + /W - View VS 90° Comments POOL Min Distance POOL Min Distance (1143.03 ft) in POOL (1143.03 ft) in POOL (4697.9 - 12398.45 (4697.9 - 12398.45 MD) to 3K-103 L1 MD) to 3K-24 (3359 - (wp08) Plan (3359 - 1143.03 4697.9 80 90.01 3305.097 6009239.8 1671371 2040.894 3569 NDss) 4800 54.43 37.35 3358.08 6010369.1 1671203 1876.47 3569 NDss) Closest A roach: Reference Well: 3K-103 w 08 Plan Offset Well: 3 K-23 Coords. - Coords. - ASP ASP ctr-ctr fence. ~ Meas. De th Incl. An le TRUE Azi. Subsea ND N(+)/S(-) E + AN - View VS 90° Comments Meas. De th Incl. An le TRUE Azi. Subsea ND N(+)/S(-) E + /W - View VS 90° Comments L Min istance POOL Min Distance (695.15 ft) in POOL (695.15 ft) in POOL (4697.9 - 12398.45 (4697.9 - 12398.45 MD) to 3K-103 L1 MD) to 3K-23 (3359.4 (wp08) Plan (3359.4 - 695.15 4697.9 80 90.01 3305.097 6009239.8 1671371 2040.894 - 3569.2 NDss) 4359 42.35 42.42 3493.38 6009515.8 1670762 1429.82 3569.2 NDss) .~ 3K-103 POOL Summary Template.xls 4/28/2008 3:12 PM Project: Kuparuk River Unit Site: Kuparuk 3K Pad Well: Plan 3K-103 (E14) Wellbore: 3K-103 Plan: 3K-103 (wp08) 9000 8$00 7000 ~0 a 5500 w ~ 5000 r + 4500 s i. 4000 3500 0 2000 ~00 -500 -1000 -1500 REFERENCE INFORMATION WELL DETAILS: Plan 3K-103 (EI4) Ca-ordinate (N/E) Reference: Well Plan 3K-103 (E74), True North Ground Level: 34.30 Vertical (fVD) Reference: Mean Sea Level +N/-S +E/-W Northing Easting Latittude Longitude Slot Measured Depth Reference: Doyonl5 (34.3+40) @ 74.30ft 0.00 0.00 6007630.94 1669336.72 70° 25' 56.328 TY49° 45' 51.299 W Calculation Method: Minimum Curvature N~ '~ ~~ (~~ V ~r...e: ~'~ T M Azimuths to True North Magnetic North: 23.08° Magnetic Field Strength:57623.2snT Dip Angle: 80.88° Date: 1 011 5/2 0 0 7 Model: BGGM2007 ~Illlllllllllliiiiiiiiiiiiiiiiiiii~~~~~~~~~l I ~ I i -3000 -2500 -2000 -1500 -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 1500( West(-)/East(+) (1750 ftlin) ~` ConocoPhillips Project: Kuparuk River Unit Site: Kuparuk 3K Pad Well: Plan 3K-103 (E14) Wellbore: 3K-103 Plan: 3K-103 (wp08) [~ 0 500 - -- --- 3000 4-500 REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Plan 3K-103 (E74), True NoRh Vertical (TVD) Reference: Mean Sea Level Measured Depch Reference: Dayonl5 (34.3+40) @ 74.30ft Calculation Method: Minimum Curvature .. _ ~.._.e.~. ~- ~~00/ ! ~/ ... ... ~. ~. ..~ .. . ,. ::::~.. ~~ ~: .~x:::.._.~- _~. t.... } :; ;, ; .. (,~'~ ~: ,-~.~_ r: ~~~ _~..._. . - ~~- s. ~: - ;.- .:_ _. ~.. -- ..._. .._. ,. - ~-....,,,~~ahcu~n WELL DETAILS: Plan 3K-103 (E 14) Ground Level: 34.30 +N/-S +E/-W Northing Eastiog Lalittude Longitude Slot 0.00 0.00 6007630.94 1669336.72 70° 25' 56.323 T-49° 45' S L299 W TRANSMITTAL LETTE/R/CH//E~~ CKLI/ST WELL NAME .~'~G( ~~,- /t~~ PTD# ~i~G~ ' l~~o Developmetrt~ Service Exploratory Strati a hic Test ~' P Non-Conventional Weil~ / J ~ ~ /' ~ ~ ~ r~ FIELD: ,C~r-~.c ~ /~i yC~ POOL: (~ E:~}''~~r4/L U /'/ Circle ppropriate Letter /Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore se ent of existing well ~~~~ ,3i~" ~~ (If last two digits in Permit No. 'l/ API No. SO-~- Zv?3 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 contingept 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 l0' sample intervals throu tar et zones. Non-Conventional please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Comoanv Narael has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Comaanv Name) must contact the Commission to obtain advance approval of such water well testing ro am. Rev: 11112008 WELL PERMIT CHECKLIST Field & Pool Weli Name: KUPARUK RIV U WSAK 3K-103L1 Program SER Well bore see PTDe:2081160 Company CONOCOPHILLIPS ALASKA INC Initial ClasslType SER 1 PEND GeoArea Unft 41160 On1Off Shore 4n Annular Disposal ^ Administration 1 Pe[mitfse attached- - - - - - - - - - - - - - - - - - ~ .. - - - - - - - - - - - - - - - - - - - - - - - - 2 Lgasenumberappropriate--- -- - - - -- -- ---- Yea -- - - -- -- - - - -------- - - -- - - - - -- 3 Uniquawellrtameandnumbe[---- ---------- -- - - --Yea-- -- ---- -- - -- -- 4 Wan located in-ade_finsd~pool_____________________________ -__..__.-Yes-___._- KuPa[ukRiver,Weat$akOilPoo1-49015Q,_govamedbyCO406H______--________-_______.__ 5 W@II located proper dis#ance from drilling unitboundary_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ - - _ _ _ _ CO 4948, Rulg 3; no reskrictans as to well spacing except that no pay shall bg Cpengd in a wail clcsel _ _ _ _ _ _ _ 6 Wflll located proper distance from other wglls_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ - than 500 feet to_anaxternal-property ling where ownership or landownership changes, _ _ _ _ _ - - - - - - _ _ _ 7 Suffcigntaoreage_availeblgin_dnllingunit______________________ ___-_._Yet;_,_.___ illigUismorethan 509ffleifrQmanextemaJPropertyline_.____-.-_________-_______--_______. 8 If-deviated, iswflllborgptat_included. ----- -- --- - - ------ Yea-- ---- - ----- - -- --- ------------- -- - -- -- -- - ------ 9 OpgratoronlyaffeCtgdparq~------ ----- -- ---- -- - -----?'eS-- ---- - ------ -- ------ ----- ---- - -- - - -- -- ---- - ---- 10 Opgratorbas_appropriatebondinforce- --- - - -- -- -- --------Yea..- -- - - - --....- -- ---- -- ------------ -- ~ - ---- - - - --- 11 Pemlitcanbeisauedwlthoutconservationorder__________________ _._._____Yes------- ----------------------------.----.-----.------------------.-____-- Appr Date 12 Peonitcanbalsauedwjtboutadminist[ative_approval---------------- ---------Yes..--._. _------.--.........-----------------------..-_.__-.---.---.---- SFD 711712008 13 Canpertrritbgapprovedbeforgl5-daY-waft--------------------- ------_--Yes------- ------------.---------------------------.-------------------.____-- 14 -Wail Iccated within ergs and strata Authorized by_Injectfon 9[de[ # (put-0# in_comments) (For_ Yes - - ... Area Injection OrderNo~2B - _ _ _ _ _ _ _ ____ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ i5 All weUe within 114_mile area of [eyiew identified (For service well only) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YAS _ . _ _ _ _ 3K-24, 3K 13, 3K-19, 3K-30, 3K-03, 3Kr20, 3K-102, 3K•27, 3K~07 .. - _ _ _ _ . _ _ _ _ - - _ _ _ - . _ - _ . _ _ _ _ 16 Pre-produced injector. durAUon_ofprc-.production less than 3 months- (For sgrv'tce well only) _ _ No_ _ _ - .. _ WeU cleanup only - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - 17 .Konconven,9ascpnformstoA$31:05.039Q.1.A),ill.A-D)- ------ --- --- -- ~ ---- -~------- - ~-- -- - --- ------------ --- ----- --~ --------- Engineering 18 Copducto[string_provided__-.--__--__------------------ -----__.NA..---- C4nductorsekin3K•193 (20$-115).------------------------------.........-------- 19 Su[facecasingRrotgctgaltknoymU$DWs---------------------- ---------J~A------- AllaquifQrsaxempted,40CF~_147.102(b)(3}•---------,------------------------------- 20 CMTVOIadequatetocircutate_onconduCior$surfcsg_______________ ____._---NA___--__ Surfacecasingsetin3K-103,___-____-_.,-______--_- ----------------------- 21 CMT-voladgquate to tie-in_longstri[~g tosurfcsg_____.-....______ __________NA________ Producifon-casing set in3K-103._-__________________...___-._--______--__________ 22 CMT_willcoveraltknownp[oduotiyehorizons--------------------- ----------No-------- $Green.li[>ercompletionplanned.--------.------------.----.-.----.------.---- 23 Casing desgns adequate for C, T, $ & permafrost_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ____ _ __ _ AUl - - _ - _ _ Original well_met design specifications, _ NA for screen )iner._ _ _ _ _ _ . - _ _ _ _ - - _ _ _ - _ , _ - _ _ _ _ _ _ _ _ - 24 Adequate tanka~_or r®sgrye pik _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yea _ _ _ _ _ _ _ Rig equipped with steel pits. Nole$erug pit planrred._ AI(weste_to approved disposal well(s). _ - - _ _ - _ _ _ - _ - 25 If_erg-d[iifhas_at0.403 forAbandonmenibeenaRpfovgd------------- --------.NA ..---- ----..--.------...--------.-.----------------------.------------. 26 AdequAte wellbOre separationptoposed_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yea _ _ _ _ _ _ _ Proximity analysis perfomled, T[a-veling cylipder path calculated, Gyros likely_in surface hole, _ - _ _ - _ _ _ _ . _ - 27 If_divg[ter-required,doesRmeetro9ulatlons_____________________ ______.-NA .-__ -$OPsiackvnllalteady.beinplace,____._.____-__________--_--.--.------___--- Appr Date 26 Drilling fluid program schematic & equip list adequate_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ Yes _ _ - - _ _ _ Maximum expected formation pressurA 9,0_~MW~ MW planned uR to 9,2_ppg in_zona. _ _ _ _ _ - - _ M 713012008 TE 29 BOP1s,-dotheymegtrggulation--------------------------- ----.---Yea---.-- -------------------------.------------------------- 1 `'~ 30 BOP):_press rating appropriate; lest to-(put psis in-comments)- . - _ - - _ _ _ _ _ _ - _ _ Yes _ _ - _ _ _ _ MA$P Calculated at x319 psi, 5K stack arrangement with ~ rams in lower set, 3900.psi_BOP test_planned, _ _ , 31 Choke_manlfoldCOmplie&v~IAPI_Rt?-53(May$4)----------------- ---------Yes------ -------- -- 32 Work willoccu[withoutoperaticnshutdown______________________ _- --Yes-.---- -.----------------------.--.----.-..--.---------------------____-- 33 Is presence Qf H2$ gas probable _ _ _ _ _ _ _ _ _ _ _ _ _ _ ___ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ _ _ - _ _ _ _ He$ is not-reRorted in 3K WS production, H2$ may be present in Ii0 gaaend Ml.. Rig has_sensorsand alarms. _ _ 34 .Mechanical_copdition ofwell~ wtlhin AOR verdied (Foraetvfce well only) _ _ _ _ _ _ _ _ _ _ _ _ _Yes _ _ _ - _ _ Ali 8 proximate Kuparuk_vtelts have surface casing set below W$. _1-new_W$ well. _Ko-issues identified. _ - _ _ _ _ Geology 35 Pem)ikean be issued wlo hydr_ogen_sulfKle measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ - - _ _ _ _ UUial West $ak_servicg well from 3K-Pad, no H2$ currents expected In this podion_ of the West Sak, _ _ _ _ _ 38 Data-presented on poleMial overpreasurezones - - - - - - - - - - - - - - - - - - - - - - - - - - - -Yes - - _ _ - Expected resentoirpressure is 9.0_ppg i:M1Af; will be drilled with 9.3 ppg mud. _ - - - - . - . _ _ . - _ _ _ _ _ _ _ Appr Date 37 Se'tsmicanalyai&ofshallov~9as-zones----------------------- ---___ -- NA__-___ ___-__--___--- SFD 7!1612008 38 Seabed condition surrey-('rf_ off-stto[e) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ -- ---- --- NA- ----- --- - - - - ---------- ---- --- - -- - ---- 39 Contadname/phongforwgakh'-Rro9-ressreports[gxploratorYonlk]-------- ---------NA------ --------------------------------------------------.---.----------- Geologic Date: Engineering Date Public Date West Sak D Sand injector Commissioner. Commissioner: Com loner ~~30 --oB C7 Welt 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 Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. 3k-10311.txt Sperry-Sun Drilling Services LIS Scan Utility $Revision: 3 $ LisLib $Revision: 4 $ Tue Dec 16 10:32:49 2008 Reel Header Service name .............LISTPE Date . ...................08/12/16 Ori 9in ...................STS Reel Name...... ........UNKNOWN continuation Number......01 Previous Reel Name.......UNKNOWN Comments .................STS LIS writing Library. scientific Technical services Tape Header Service name .............LISTPE Date .....................08/12/16 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 MWD/MAD LOGS WELL NAME: 3K-103L1 API NUMBER: 500292339260 OPERATOR: ConocoPhillips Alaska Inc. LOGGING COMPANY: Sperry Drilling Services TAPE CREATION DATE: 15-DEC-08 JOB DATA MWD RUN 2 MWD RUN 5 MWD RUN 16 JOB NUMBER: Mw0006005291 Mw0006005291 Mw0006005291 LOGGING ENGINEER: P. ORTH P. ORTH T. RITCHEY OPERATOR WITNESS: M. THORNTON F. HERBERT G. RIZEK MWD RUN 17 JOB NUMBER: MW0006005291 LOGGING ENGINEER: S. POLAK OPERATOR WITNESS: F. HERBERT SURFACE LOCATION SECTION: 35 TOWNSHIP: 13N RANGE: 9E FNL: FSL: 885 FEL: FWL: 314 Page 1 vac ~o~s- ~ ~~ tatSO i 3k-10311.txt ELEVATION (FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: 74.62 GROUND LEVEL: 33.80 WELL CASING RECORD OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 1ST STRING 12.250 13.375 2540.0 2ND STRING 6.750 9.625 4674.0 3RD STRING PRODUCTION STRING REMARKS: 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. THIS WELLBORE IS A SIDETRACK EXITING THE 3K-103 PB3 WELLBORE BY MEANS OF A WHIPSTOCK, THE TOP OF WHICH WAS AT 4674'MD/3454'TVD, WITHIN. THE MWD RUN 5 INTERVAL. THE WHIPSTOCK WAS POSITIONED, THE WINDOW WAS MILLED, AND A BIT OF RAT HOLE WAS DRILLED DURING MWD RUN 16 - ONLY SROP DATA ARE PRESENTED FOR THIS RUN. 4. MWD RUN 1 WAS DIRECTIONAL ONLY - NO DATA ARE PRESENTED. 5. MWD RUNS 2,5,17 COMPRISED DIRECTIONAL, DUAL GAMMA RAY (DGR) UTIL- IZING GEIGER-MUELLER TUBE DETECTORS, ELECTROMAGNETIC WAVE RESIS- TIVITY PHASE-4 (EWR-P4), DRILL STRING DYNAMICS SENSOR-ROTATING (DDS-R), AND PRESSURE WHILE DRILLING (PWD). MWD RUNS 2,17 ALSO INCLUDED AT-BIT INCLINATION (ABI). 6. MWD DATA ARE CONSIDERED PDC PER E-MAIL FROM JEFFREY HARRISON (CPAI) TO BRYAN BURINDA DATED 03-APR-2008. 7. MWD RUNS 1,2,5,16,17 REPRESENT WELL 3K-103 L1 WITH API#: 50-029- 23392-60. THIS WELL REACHED A TOTAL DEPTH (TD) OF 12375'MD/3575'TVO. 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. Page 2 3k-10311.txt SLIDE = NON-ROTATED INTERVALS REFLECTING BIT DEPTHS. ALL DATA CURVES ARE SMOOTHED TO A STEP OF 0.5 FT, WITH A WINDOW OF 0.6 FT, EXCEPT FOR ROP AND GAMMA RAY, WHICH ARE BOTH SMOOTHED TO A 1.1 FT WINDOW. ALL DATA HAS A GAP FILL OF 5 FT APPLIED. File Header Service name... .......STSLIB.001 service sub Level Name... version Number. ........1.0.0 Date of Generation.......08/12/16 Maximum Physical Record..65535 File Type.. ............LO Previous File Name.......STSLI6.000 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 2506.5 12316.5 RPX 2525.0 12323.5 RPS 2525.0 12323.5 RPM 2525.0 12323.5 FET 2525.0 12323.5 RPD 2525.0 12323.5 RoP 2550.5 12375.0 BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE DEPTH MERGED DATA SOURCE PBU TOOL CODE MWD MWD MWD MWD BIT RUN NO MERGE TOP 2 2506.5 5 2925.5 16 4674.5 17 4720.0 REMARKS: MERGED MAIN PASS. MERGE BASE 2925.0 4674.0 4720.0 12375.0 Data Format specification Record Data Record Type... ..........0 Data specification Block Type.....0 Logging Direction .................DOwn optical log depth units...........Feet Data Reference Point ..............undefined Frame Spacing....... ............60 .11N Max frames per record .............undefined Absent value ......................-999 Depth Units ....................... Page 3 3k-10311.txt Datum Specificat ion Block sub-type...0 Name Service order units Size Nsam Rep Code offset channel DEPT FT 4 1 68 0 1 RPD MWD OHMM 4 1 68 4 2 RPM MWD OHMM 4 1 68 8 3 RPS MWD OHMM 4 1 68 12 4 RPX MWD OHMM 4 1 68 16 5 FET MWD HR 4 1 68 20 6 GR MWD API 4 1 68 24 7 ROP MWD FPH 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 2506.5 12375 7440.75 19738 2506.5 12375 RPD MWD OHMM 0.98 2000 34.9538 19598 2525 12323.5 RPM MWD OHMM 0.52 2000 31.726 19598 2525 12323.5 RPS MWD OHMM 2.2 2000 29.4185 19598 2525 12323.5 RPX MWD OHMM 2.21 2000 29.191 19598 2525 12323.5 FET MWD HR 0.14 91.47 1.14521 19598 2525 12323.5 GR MWD API 12.04 130.55 70.0564 19621 2506.5 12316.5 ROP MWD FPH 0.17 659.49 225.958 19650 2550.5 12375 First Reading For Entire File..........2506.5 Last Reading For Entire File...........12375 File Trailer Service name... .......STSLIB.001 service sub Level Name... version Number. ........1.0.0 Date of Generation.......08/12/16 Maximum Physical Record..65535 File Ty e ................L0 Next Fie Name...........STSLIB.002 Physical EOF File Header Service name... .......STSLIB.002 service sub Level~Name... version Number. ........1.0.0 Date of Generation.......08/12/16 Maximum Physical Record..65535 File Type .. .............LO Previous File Name.......STSLIB.001 comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: FILE SUMMARY header data for each bit run in separate files. 2 .5000 VENDOR TOOL CODE START DEPTH SGRC 2506.5 STOP DEPTH 2925.0 Page 4 3k-10311.txt SEDP 2525.0 2925.0 SEXP 2525.0 2925.0 SEMP 2525.0 2925.0 SFXE 2525.0 2925.0 SESP 2525.0 2925.0 ROP 2550.5 2925.0 $ LOG HEADER DATA DATE LOGGED: 27-SEP-08 SOFTWARE SURFACE SOFTWARE VERSION: Incite DOWNHOLE SOFTWARE VERSION: 74.11 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT): 2925.0 TOP LOG INTERVAL (FT): 2550.0 BOTTOM LOG INTERVAL (FT): 2925.0 BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: 40.6 MAXIMUM ANGLE: 58.7 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER DGR DUAL GAMMA RAY 216261 EWR4 ELECTROMAG. RESIS. 4 230192 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): 12.250 DRILLER'S CASING DEPTH (FT): 2540.0 BOREHOLE CONDITIONS MUD TYPE: Lignosulfanate MUD DENSITY (LB/G): 9.05 MUD VISCOSITY (S): 52.0 MUD PH: 8.5 MUD CHLORIDES (PPM): 200 .FLUID LOSS (C3): 4.5 RESISTIVITY (OHMM) AT TEMPERATURE (DEG F) MUD AT MEASURED TEMPERATURE (MT): 1.900 81.0 MUD AT MAX CIRCULATING TERMPERATURE: 1.480 105.8 MUD FILTRATE AT MT: 5.000 81.0 MUD CAKE AT MT: 1.500 81.0 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 ..............undefined Frame Spacing .....................60 .lIN Page 5 i 3k-10311.txt Max frames per record .............undefined Absent value ... ...................-999 Depth units. .. .. ..... Datum specifica tion Block sub-type...0 Name Service order units size Nsam Rep code offset Channel DEPT FT 4 1 68 0 1 RPD MWD020 OHMM 4 1 68 4 2 RPM MWD020 OHMM 4 1 68 8 3 RPS MWD020 OHMM 4 1 68 12 4 RPX MWD020 OHMM 4 1 68 16 5 FET MWD020 HR 4 1 68 20 6 GR MWD020 API 4 1 68 24 7 ROP MWD020 FPH 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 2506.5 2925 2715.75 838 2506.5 2925 RPD MWD020 OHMM 0.98 2000 25.6799 801 2525 2925 RPM MWD020 OHMM 0.52 31.87 15.9015 801 2525 2925 RPS MWD020 OHMM 2.74 32.59 14.7172 801 2525 2925 RPX MWD020 OHMM 3.09 27.28 11.8377 801 2525 2925 FET MWD020 HR 0.14 62.77 4.76348 801 2525 2925 GR MWD020 API 12.04 101.04 61.0104 838 2506.5 2925 ROP MWD020 FPH 7.71 636.24 297.093 750 2550.5 2925 First Reading For Entire File..........2506.5 Last Reading For Entire File...........2925 File Trailer Service name... .......STSLIB.002 service sub Level Name... version Number. ........1.0.0 Date of Generation.......08/12/16 Maximum Physical Record..65535 File Type........ ......LO Next File Name...........STSLIB.003 Physical EOF File Header Service name... .......STSLIB.003 service sub Level~Name... version Number. ........1.0.0 Date of Generation.......08/12/16 Maximum Physical Record..65535 File Type. ............LO Previous File Name.......STSL26.002 Comment Record FILE HEADER FILE NUMBER: 3 RAW MWD curves and log header data for each bit run in separate files. BIT RUN NUMBER: 5 DEPTH INCREMENT: .5000 Page 6 w r 3k-10311.txt FI LE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH SGRC 2925.5 4674.0 SFXE 2925.5 4674.0 SROP 2925.5 4674.0 SEXP 2925.5 4674.0 SEMP 2925.5 4674.0 SESP 2925.5 4674.0 SEDP 2925.5 4674.0 LOG HEADER DATA DATE LOGGED: 03-OCT-08 SOFTWARE SURFACE SOFTWARE VERSION: Insite DOWNHOLE SOFTWARE VERSION: 74.11 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT): 4674.0 TOP LOG INTERVAL (FT): 2925.0 BOTTOM LOG INTERVAL (FT): 4674.0 BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: 40.6 MAXIMUM ANGLE: 85.5 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER DGR DUAL GAMMA RAY 216261 EWR4 ELECTROMAG. RESIS. 4 230192 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): 12.250 " DRILLER'S CASING DEPTH (FT): 2540.0 BOREHOLE CONDITIONS MUD TYPE: Lignosulfan ate MUD DENSITY (LB/G): 9.10 MUD VISCOSITY (S): 56.0 MUD PH: 10.2 MUD CHLORIDES (PPM): 300 FLUID LOSS (C3): 4.5 RESISTIVITY (OHMM) AT TEMPERATURE (DEG F) MUD AT MEASURED TEMPERATURE (MT): 1.100 73.0 MUD AT MAX CIRCULATING TERMPERATURE: .950 85.6 MUD FILTRATE AT MT: 1.200 73.0 MUD CAKE AT MT: 1.200 73.0 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 Page 7 3k-10311.txt optical log depth units...........Feet 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 RPD MWD050 OHMM 4 1 68 4 2 RPM MWD050 OHMM 4 1 68 8 3 RPS MWD050 OHMM 4 1 68 12 4 RPX MWD050 OHMM 4 1 68 16 5 FET MwD050 HR 4 1 68 20 6 GR MwD050 API 4 1 68 24 7 ROP MWD050 FPH 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 2925.5 4674 3799.75 3498 2925.5 4674 RPD MWD050 OHMM 3.76 841.89 17.6649 3498 2925.5 4674 RPM MwD050 OHMM 3.07 1612.7 17.7105 3498 2925.5 4674 RPS MWD050 OHMM 2.42 104.21 11.9892 3498 2925.5 4674 RPX MWD050 OHMM 2.21 33.49 8.22995 3498 2925.5 4674 FET MWD050 HR 0.36 91.47 1.42153 3498 2925.5 4674 GR MWD050 API 23.44 130.55 76.5735 3498 2925.5 4674 ROP MWD050 FPH 0.39 489.84 182.657 3498 2925.5 4674 First Reading For Entire File..........2925.5 Last Reading For Entire File...........4674 File Trailer service name... .......STSLIB.003 service sub Level~Name... version Number.. ........1.0.0 Date of Generation.......08/12/16 Maximum Physical Record..65535 File Type ................L0 Next File Name...........STSLIB.004 Physical EOF File Header service name... .......STSLIB.004 Service Sub Level Name... version Number. ........1.0.0 Date of Generation.......08/12/16 Maximum Physical Record..65535 ,File Type. ............LO Previous File Name.......STSLIB.003 Comment Record FILE HEADER FILE NUMBER: 4 RAW MWD curves and log header data for each bit run in separate files. Page 8 • 3k-10311.txt BIT RUN NUMBER: 16 DE PTH INCREMENT: .5000 FI LE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH ROP 4674.5 4720.0 $ LOG HEADER DATA DATE LOGGED: 06-NOV-08 SOFTWARE SURFACE SOFTWARE VERSION: Insite DOWNHOLE SOFTWARE VERSION: 74.11 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT): 4720.0 TOP LOG INTERVAL (FT): 4674.0 BOTTOM LOG INTERVAL (FT): 4720.0 BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: 80.0 MAXIMUM ANGLE: 80.0 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER DGR DUAL GAMMA RAY 103770 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): 6.750 DRILLER'S CASING DEPTH (FT): 4674.0 BOREHOLE CONDITIONS MUD TYPE: Mineral Oil Base MUD DENSITY (LB/G): 9.20 MUD VISCOSITY (S): 87.0 MUD PH: .O MUD CHLORIDES (PPM): 34000 FLUID LOSS (C3): 4.5 RESISTIVITY (OHMM) AT TEMPERATURE (DEG F) MUD AT MEASURED TEMPERATURE (MT): .000 .O MUD AT MAX CIRCULATING TERMPERATURE: .000 95.0 MUD FILTRATE AT MT: .000 .O MUD CAKE AT MT: .000 .O 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 ..............undefined Frame Spacing....... ............60 .lIN Max frames per record .............undefined Page 9 3k-10311.txt 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 ROP MWD160 FPH 4 1 68 4 2 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 4674.5 4720 .4697.25 92 4674.5 4720 ROP MWD160 FPH 0.17 237.07 31.0639 92 4674.5 4720 First Reading For Entire File..........4674.5 Last Reading For Entire File...........4720 File Trailer Service name... .......STSLIB.004 Service sub Level Name... version Number. ........1.0.0 Date of Generation.......08/12/16 Maximum Physical Record..65535 File Type ................LO Next File Name...........STSLIB.005 Physical EOF File Header Service name... .......STSL2B.005 service sub Level Name... version Number. ........1.0.0 Date of Generation.......08/12/16 Maximum Physical Record..65535 File Type .. .............LO Previous File Name.......STSLIB.004 comment Record FILE HEADER FILE NUMBER: 5 RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: FILE SUMMARY VENDOR TOOL CODE SEXP SEDP SEMP SGRC SFXE SESP SROP LOG HEADER DATA DATE LOGGED: header data for each bit run in separate files. 17 .5000 START DEPTH 4674.5 4674.5 4674.5 4674.5 4674.5 4674.5 4720.5 STOP DEPTH 12323.5 12323.5 12323.5 12316.5 12323.5 12323.5 12375.0 Page 10 11-NOV-08 • SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: 3k-10311.txt Insite 74.11 Memory 12375.0 4720.0 12375.0 80.4 93.8 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER DGR DUAL GAMMA RAY 151107 EWR4 Electromag Resis. 4 148579 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): 6.750. DRILLER'S CASING DEPTH (FT): 4674.0 BOREHOLE CONDITIONS MUD TYPE: Mineral Oil Base MUD DENSITY (LB/G): 9.20 MUD VISCOSITY (S): 87.0 MUD PH: .O MUD CHLORIDES (PPM): 34000 FLUID LOSS (C3): 4.5 RESISTIVITY (OHMM) AT TEMPERATU RE (DEG F) MUD AT MEASURED TEMPERATURE (MT): .000 .O MUD AT MAX CIRCULATING TERMP ERATURE: .000 120.2 MUD FILTRATE AT MT: .000 .O MUD CAKE AT MT: .000 .O 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 .............. 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 Chan nel DEPT FT 4 1 68 0 1 RPD MWD170 OHMM 4 1 68 4 2 , RPM MWD170 OHMM 4 1 68 8 3 RPS MWD170 OHMM 4 1 68 12 4 Page 11 • 3k-10311.txt RPX MWD170 OHMM 4 1 68 16 5 FET MwD170 HR 4 1 68 20 6 GR MWD170 API 4 1 68 24 7 ROP MWD170 FPH 4 1 68 28 8 First Last Name service unit Min Max Mean Nsam Reading Reading DEPT FT 4674.5 12375 8524.75 15402 4674.5 12375 RPD MwD170 OHMM 1.2 2000 39.3923 15299 4674.5 12323.5 RPM MWD170 OHMM 2.2 2000 35.7591 15299 4674.5 12323.5 RPS MWD170 OHMM 2.2 2000 34.1732 15299 4674.5 12323.5 RPX MWD170 OHMM 6.24 2000 34.8921 15299 4674.5 12323.5 FET MWD170 HR 0.14 40.6 0.892589 15299 4674.5 12323.5 GR MWD170 API 38.29 121.94 69.0609 15285 4674.5 12316.5 ROP MWD170 FPH 1.28 659.49 233.538 15310 4720.5 12375 First Reading For Entire File..........4674.5 Last Reading For Entire File...........12375 File Trailer Service name... .......STSLIB.005 Service Sub Level Name... version Number. ........1.0.0 Date of Generation.......08/12/16 Maximum Physical Record..65535 File Ty e ................Lo Next File Name...........STSLIB.006 Physical EoF Tape Trailer Service name .............LISTPE Date . ...................08/12/16 Origin ...................STS Tape Name. .... ........UNKNOWN continuation Number......01 Next Tape Name...........UNKNOWN Comments .................STS LIS Writing Reel Trailer Service name .............LISTPE Date . ...................08/12/16 Ori9in ...................5T5 Reel Name. .... ........UNKNOWN Continuation Number......01 Next Reel Name...........UNKNOWN Comments .................STS LIS Writing Physical EOF Library. scientific Technical Services Library. scientific Technical services Physical EOF Page 12 End Of LIS File 3k-10311.txt Page 13