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209-079
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Vaughan Alex Cc:Chaudhry Amjad; Regg, James B (OGC) Subject:RE: Eni sundry modification request for PTD: 208-003 ,212-030, 209-079, 208-040 Date:Wednesday, August 17, 2022 3:28:00 PM Alex, Approval is granted for the reduced AOGCC witnessed pressure tests as outlined in your email below, for all 4 wells listed. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Vaughan Alex <Alex.Vaughan@external.eni.com> Sent: Wednesday, August 17, 2022 2:20 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Chaudhry Amjad <Amjad.Chaudhry@eni.com> Subject: Eni sundry modification request for PTD: 208-003 ,212-030, 209-079, 208-040 Bryan, As discussed last week Eni is requesting to reduce the production casing string pressure test after setting the ESP packer from 3500psi to 2500psi. This request is intended to reduce cycle load on the ESP cable penetrator through our tubing hangers. This will have no change to the approved sundry’s obligating Eni to pressure test the production casing string with a casing test packer below to top of cement which occurs in a preceding step of each program. This will affect the following approved sundry’s: ODSN-31 PTD: 208-003 Sundry #: 322-049 ODSN-25 PTD: 212-030 Sundry #: 322-217 ODST-45A PTD: 209-079 Sundry #: 322-250 ODST-39 PTD: 208-040 Sundry #: 322-229 Example affected text from ODST-39: Alex Vaughan Sr. Drilling & Completions Compliance Engineer Eni US Operating Co. Inc. 3700 Centerpoint Dr. Suite 500 Anchorage, AK, 99503 (907) 748-5478 M ------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------- Message for the recipient only, if received in error, please notify the sender and read http://www.eni.com/disclaimer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Completion Equipment MD(ft) TVD(ft) $VetcoGray Tubing Hanger 34 34 %2-7/8" 6.40# L-80 IBT-M Tubing & 2-7/8" HES "NE" TRSV w/ 2.313" Packing Bore 2051 2018 '2-7/8" 6.40# L-80 IBT-M Tubing (2 Joints) (2-7/8" x 1" SLB GLM#3 w/15' Pup Top & Bottom 3365 2941 )2-7/8" 6.40# L-80 IBT-M Tubing *HES "X" Nipple #4 (2.313" ID) 2-7/8" w/15' Pup Top & Bottom 3461 2982 +2-7/8" 6.40# L-80 IBT-M Tubing ,2-7/8" x 1" SLB GLM#2 w/15' Pup Top & Bottom 6128 3792 -2-7/8" 6.40# L-80 IBT-M Tubing (2 Joints) .HES "X" Nipple #3 (2.313" ID) 2-7/8" w/15' Pup Top & Bottom 6222 3820 /2-7/8" 6.40# L-80 IBT-M Tubing 0 2-7/8" x 1" SLB GLM#1 w/15' Pup Top & Bottom 9491 4825 1 2-7/8" 6.40# L-80 IBT-M Tubing (2 Joints) 2 HES "X" Nipple #2 (2.313" ID) 2-7/8" w/15' Pup Top & Bottom 9587 4856 3 2-7/8" 6.40# L-80 IBT-M Tubing (1 Joints) 4 HES 2-7/8" ROC gauge with I-wire to surface w/15' Pup Top & Bottom 9650 4876 5 2-7/8" 6.40# L-80 IBT-M Tubing (1 Joints) 6 Baker Hughes 2-7/8" x 7-5/8" FHL Retrievable Packer 9720 4899 7 2-7/8" 6.40# L-80 IBT-M Tubing (2 Joints) U 2-7/8“ HES Sliding Sleeve w/ ‘X’ Nipple Profile 2.313" I.D. Run in Closed (Sleeve Shifts Down to Open)9790 4920 9 2-7/8" 6.40# L-80 IBT-M Tubing :HES "X" Nipple #1 (2.313" ID) 2-7/8" w/ RHC Plug + 15' Pup Top & Bottom 9856 4940 ;2-7/8" 6.40# L-80 IBT-M Tubing <HES 5.25" Auto Entry Mule Shoe 9902 4954 End of Assembly 9906 4956 No. Lower Completion Equipment MD(ft) TVD(ft) 23 WFT 5.75" ID PBR Tie Back Sleeve 15ft 9891 4951 24 WFT "TSP" Liner Top Pkr w/ Hold Down Slips 5-1/2 20#x 7-5/8 29.70 w/ Vam Top HT Box Down 9907 4956 25 WFT "PHR" Rotating Hyd Set Liner Hanger 5-1/2 20# x 7-5/8 29.70 #w/ 5-1/2 Vam Top HT Pin x Pin XO w/ 5-1/2 Vam Top HT Box x 4-1/2 Hydril 521 Pin 9910 4957 26 WFT 4-1/2 12.60# x 5.75od x 15 Ft "Genesis" Water - Based Swellable Packer w/ 4-1/2 Hydril 521 Box x Pin 11401 5173 27 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11581 5170 28 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11786 5169 29 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11991 5171 30 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12196 5171 31 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12402 5159 32 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12688 5132 33 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13009 5101 34 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13213 5083 35 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13417 5065 36 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13584 5052 37 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13787 5032 38 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13989 5018 39 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14195 5015 40 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14396 5012 41 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14600 5004 42 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14806 5001 43 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15008 5001 44 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15210 5008 45 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15417 5018 46 Ray Oil Tool Silver Bullet Eccentric Float Shoe (PLUGGED) w/ 4-1/2 Hydril 521 15422 5018 End of Assembly 15424 5018 ^ĞĐƵƌŝƚLJtĂƌŶŝŶŐ͗dŚŝƐĞŵĂŝůŽƌŝŐŝŶĂƚĞĚĨƌŽŵŽƵƚƐŝĚĞŽĨƚŚĞŽƌŐĂŶŝnjĂƚŝŽŶ͘ŽŶŽƚĐůŝĐŬ ůŝŶŬƐŽƌŽƉĞŶĂƚƚĂĐŚŵĞŶƚƐƵŶůĞƐƐLJŽƵǀĞƌŝĨŝĞĚƚŚĞƐĞŶĚĞƌŵĂŝůĂĚĚƌĞƐƐĂŶĚŬŶŽǁƚŚĞ ĐŽŶƚĞŶƚŝƐƐĂĨĞ͊ &$87,21 7KLVHPDLORULJLQDWHGIURPRXWVLGHWKH6WDWHRI$ODVNDPDLOV\VWHP'RQRW FOLFNOLQNVRURSHQDWWDFKPHQWVXQOHVV\RXUHFRJQL]HWKHVHQGHUDQGNQRZWKHFRQWHQW LVVDIH )URP &KDXGKU\$PMDG 7R 0F/HOODQ%U\DQ- 2*& 6XEMHFW 5( >(;7(51$/@2'67$ 37' 5:2VXQGU\ 'DWH )ULGD\0D\ $0 $WWDFKPHQWV 2'67$6FKHPDWLF5:23ODQQHGSGI ƌLJĂŶƐŽƌƌLJĨŽƌƚŚĞĚĞůĂLJ͕ƉůĞĂƐĞĨŝŶĚĂƚƚĂĐŚĞĚƉůĂŶŶĞĚƐĐŚĞŵĂƚŝĐĂŶĚŝŶŝƚŝĂůŬŝůůŝŶŐƐƚĞƉƐ͕ƚŚĂŶŬƐ ĂŐĂŝŶ ͻD/ZhEĂďŽƌƐϭϵ ͻ^ůŝĐŬůŝŶĞWƌŽŐƌĂŵ͗KƉƚŝŽŶƚŽƉĞƌĨŽƌŵƉƌĞͲƌŝŐ ͻ^ĞƚĂƚ^ƚĂŶĚŝŶŐǀĂůǀĞŝŶyEŶŝƉƉůĞ ͻWƵůůKsĨƌŽŵ'>Dηϭ ͻ&ůƵŝĚƉĂĐŬƚƵďŝŶŐĂŶĚ/ǁŝƚŚƚƌĞĂƚĞĚͬĨŝůƚĞƌĞĚƐĞĂǁĂƚĞƌ ͻŽŵďŽdĞƐƚdƵďŝŶŐdž/ƚŽϭϬϬϬƉƐŝ ͻ^>Ͳ/ŶƐƚĂůůsŝŶ'>Dηϭ ͻ^>ͲWƵůůĂƚ^ƚĂŶĚŝŶŐǀĂůǀĞ ͻ/ŶƐƚĂůůƚĞƐƚĚĂƌƚ ͻEdƌĞĞͬEhKW ŵũĂĚ &ƌŽŵ͗DĐ>ĞůůĂŶ͕ƌLJĂŶ:;K'ͿфďƌLJĂŶ͘ŵĐůĞůůĂŶΛĂůĂƐŬĂ͘ŐŽǀх ^ĞŶƚ͗dŚƵƌƐĚĂLJ͕DĂLJϭϮ͕ϮϬϮϮϯ͗ϬϯWD dŽ͗ŚĂƵĚŚƌLJŵũĂĚфŵũĂĚ͘ŚĂƵĚŚƌLJΛĞŶŝ͘ĐŽŵх ^ƵďũĞĐƚ͗ yd ZE>K^dͲϰϱ;WdϮϬϵͲϬϳϵͿZtKƐƵŶĚƌLJ ŵũĂĚ͕ ^ŝŶĐĞLJŽƵƉůĂŶƚŽĐŚĂŶŐĞĨƌŽŵĂŐĂƐͲůŝĨƚĞĚĐŽŵƉůĞƚŝŽŶƚŽĂŶ ^WĐŽŵƉůĞƚŝŽŶ͕LJŽƵǁŝůůŶĞĞĚƚŽŝŶĐůƵĚĞ ĂƉƌŽƉŽƐĞĚĚŝĂŐƌĂŵŝŶƚŚĞƐƵŶĚƌLJĂƉƉůŝĐĂƚŝŽŶ͘/ĐĂŶĂƚƚĂĐŚŝƚŝĨLJŽƵƐĞŶĚŝƚƚŽŵĞ͘ dŚĂŶŬƐ 2'67$:HOO&RPSOHWLRQ6FKHPDWLF 3URGXFWLRQ ´+ROH7'DW 0' 79' &RQGXFWRU 3ODQQHG ,QWHUPHGLDWH &DVLQJ / %7&0 # 0' 79' 6XUIDFH&DVLQJ / %7& # 0' 79' 6669 */ */ */ < ;1QLSSOH #-7DERYH(63 &KHPLFDO,QMHFWLRQ9DOYH $QQXODU,QMHFWLRQ # 0' &RQWURO/LQHWR6XUIDFH ´&RQWURO/LQHWRWRSRI VW 6HDO */029 # DERYH(63 */0'*/9#-WEHORZSDFNHU ;QLSSOH #-WEHORZ*/0 [3DFNHUZ3DFNHUYHQWYDOYH # 79' 7569# 79' */0629#-7EHORZ7569 STATE OF ALASKA ALA.OIL AND GAS CONSERVATION COMMOON REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Plug Perforations ❑ Fracture Stimulate 0 Pull Tubing❑ Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate LI Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Wet❑ Other:Nitrogen&CTU 0 2.Operator Caleus Natural Resources Alaska,LLC 4.Well Class Before Work: 5.Permit to Drill Number: Name: Development LI Exploratory 0 209-079 3.Address: 3700 Centerpoint Drive,Suite 500 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-703-20577-01-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 355036 ODST-45A 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): RECEIVED N/A 11.Present Well Condition Summary: OOOguruk-Torok Oil Pool MAY 17201;` Total Depth measured 15,429 feet _ Plugs measured N/A (� CC true vertical 5,018 feet Junk measured N/A feet ase Effective Depth measured 15,424 feet Packer measured See attachment, feet true vertical 5,018 feet Da.3 true vertical See attachment, feet ca.3 Casing Length Size MDTVD Burst Collapse Structural p Conductor 110' 16" 153' 153' N/A N/A Surface 4,931' 10-3/4" 4,973' 3,438' 5,210 psi Intermediate 9,994' P 2,470 psi 7-5/8" 11,377' 5,174' 6,890 psi 4,790 psi Production Liner 5,533' 4-1/2" 15,424' 5,018' 8,430si P 7,500 psi Perforation depth Measured depth See attachment,pg.2 feet True Vertical depth See attachment,pg.2 feet Tubing(size,grade,measured and true vertical depth) 2-7/8",6.40# L-80 IBT-M 9,906'MD 4,956'TVD Packers and SSSV(type,measured and true vertical depth) See attachment,pg.3 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: SCANNED MAY " 5 2017: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 558 692 253 719 435 Subsequent to operation: 137 164 253 1,154 422 14.Attachments(required per 20 AAc 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory ❑ Development P ❑ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Printed and Electronic Fracture Stimulation Data ❑ GSTOR Oil [I] Gas ❑ WDSPL❑ ❑ WINJ ❑ WAG ❑ GINJ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. (Sundry Number or N/A if C.O.Exempt: 317-117 Authorized Name: Rami Jasser Contact Name: Rami Jasser Authorized Title: Senior Staff Completions gineer Contact Email: rami.jasser@caelusenergy.com Authorized Signature: f Date: ,)-s-Z W 7 Contact Phone: 907-343-2182 Form 10-404 Revised 4/20175--,Z..? — /" !! Submit Original Only 710,7V(/7 RBDMS LVMAY 1 9 2017 • • Attachment Pg. 2 AOGCC Form 10-40 Sundry Report Box 11 - Perforation Locations Well:ODST-45a Top(MD) Bottom(MD) Top(TVD) Bottom(TVD) 4-Y2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 11,581 11,586 5,170 5,170 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 11,786 11,791 5,169 5,169 4-Y2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 11,991 11,996 5,171 5,171 4-%2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 12,196 12,200 5,171 5,171 4-%2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2"holes 12,402 12,406 5,159 5,159 4-Y2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 12,688 12,692 5,132 5,132 4-Y2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,009 13,014 5,101 5,101 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,213 13,217 5,083 5,083 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,417 13,422 5,066 5,065 4-%2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,584 13,588 5,052 5,051 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,787 13,792 5,032 5,032 4-%2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,989 13,994 5,018 5,018 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 14,195 14,200 5,015 5,015 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 14,396 14,401 5,012 5,011 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 14,600 14,604 5,004 5,004 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2"holes 14,806 14,810 5,001 5,001 4-%2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 15,008 15,013 5,001 5,001 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 15,210 15,215 5,008 5,008 4-%', 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 15,417 15,422 5,018 5,008 Eccentric Shoe 15,422 15,424 5,018 5,018 • • • Attachment Pg. 3 AOGCC Form 10-404 Sundry Report Box 11 - Packer Locations VOMOMA Well: ODST-45a MD TVD HES "NE" TRSV 2,051 2,018 BHI 2-7/8" FL Retrievable Packer 9,720 4,899 WFT Liner Top Packer 9,907 4,956 WFT Genesis Water-Based Swellable Packer 11,401 5,173 • CAE LLAlaska Summary Report - State Well Name: ODST-45A Ce: ,r�rc;��Ataska Well Name: Contractor: Rig Number: Job Category: Start Date: End Date: Start Depth FootMeters Dens Last Start Date End Date (ftKB) (ft) Mud(Ib/gal) Summary 4/22/2017 4/23/2017 1,311.0 00:00 4/22/17-00:00 4/23/17 *Change out 2"1502 inside reel iron on work reel.Hardline was out of compliance. *Begin spooling 1.75"coiled tubing from shipping reel to work reel. *SLB coiled tubing noticed some significant damage/flat spots on the pipe.Stop spooling and inspect coil. *UT inspection shows a minimum reading of.076"wall thickness.New wall thickness is.143". Notify the Anchorage team. *Discuss plan forward w/Anchorage team. *Contact CH2 for truck support and Peak for crane support in SLB yard. *Continue spooling 1.75"coiled tubing from shipping reel to work reel while inspecting pipe. 4/23/2017 4/24/2017 1,311.0 00:00 4/23/17-00:00 4/24/17 *Continue spooling 1.75"coiled tubing from work reel to shipping reel.While spooling from the work reel to the shipping reel the 1.75"coil split 1/2 way through the circumference of the pipe. This is at 9180'from the tip of the coil. *Discuss plan forward w/Anchorage team. *Secure 1.75"coiled tubing on both spoolers.Install chain clamp on broken pipe. *Load SLB 3rd spooling unit and Caelus damaged reel(empty)on CH2 trirck and back hual to • SLB yard in Deadhorse. *Continue spooling 1.75"coiled tubing from work reel to shipping reel. *Installed a total of 5 chain clamps and 1 welded chain on cracked pipe. 4/24/2017 4/25/2017 1,311.0 00:00 4/24/17-00:00 4/25/17 *Completed spooling bad 1.75"coiled tubing onto shipping reel.Pick reel and load on CH2 trailer to back haul to SLB yard in Deadhorse. *Picked and installed the 2nd 1.75"coiled tubing string off of CH2 trailer and into the yard spooler. *Load the empty flat bed with the bad 1.75"string and empty spool.Back haul to Deadhorse. *SLB Field Engineer rigged up CoilScan equipment to verify pipe is in good condition. *Begin spooling 2nd 1.75"coiled tubing string from shipping reel to work reel while monitoring pipe through SLB CoilScan. *CoilScan reading at 10%ovality on the coiled tubing.Caliper mechanical readings show no sign of ovality.Continue spooling. *Discuss CoilScan results w/Anchorage team.SLB does not have a calibration rod for the CoilScan. *19:10 pm:10,000'of coil left to spool.Good pipe thus far.No anomalies. *Found bad spot on pipe @ 6,450'from end of coil.Wall thickness=.092",should be.134".SLB minimum=.121". *Send pictures to Anchorage team.Discuss plan forward w/Anchorage team&SLB FSM. *Completed spooling 1.75"coiled tubing through CoilScan onto work reel.No more bad spots on pipe after 6,450'. 4/25/2017 4/26/2017 1,311.0 00:00 4/25/17-00:00 4/26/17 *Completed spooling 1.75"coiled tubing from work reel to shipping reel.Cut pipe @ 6,450'and secure pipe to reel.Work reel has 16,400'of good 1.75"coiled tubing spooled on. *Move SLB coil equipment from N-03i over to T-45a and begin rig up activities. *Ops loaded 100 bbls of seawater in flowback tanks A&B.Load 50 bbls of pre-mixed soda ash solution in Tank A.Load 50 bbls of pre-mixed soda ash solution in Tank B. *SLB acid tranports and N2 pump unit arrived on location. *Stab 1.75"coiled tubing through injector head. *LRS set up emergency shower inside well bay#2. *Bleed control line pressure to zero to close TRSV(2nd WC Barrier). *Remove 3-1/8"5M tree cap flange and install SLB BOPS,P-sub,4-1/6"10M x 3-1/8"5M XO, and secondary 3-1/8"5M gate valve on wellhead. *Rig up 2"1502 stand pipe from P-sub to ground iron.Rig up high pressure kelly hose. Page 1/2 Report Printed: 5/5/2017 • CAEE LL Operations Summary Report- State Well Name: ODST-45A Alaska S a Start Depth Foot/Meters Dens Last Start Date End Date (ftKB) (ft) Mud(Ib/gal) Summary 4/26/2017 4/27/2017 1,311.0 00:00 4/26/17-00:00 4/27/17 D *Stab injector head on well and load 1.75"coiled tubing w/38 bbls of diesel. �(�r ), *SLB shell tested PCE and 2"1502 hardline to 250 psi low/4000 psi high. �{ *SLB conducted weekly-B-OP-testing.-Pumpe2i f 1B$ ball throng 5 coiled tubing. Recovered ball.37 bbls of diesel pumped. *Make up Slick BHA=1.75"CTC, 1.75"DBPV, 1.75"2 x 4'stinger with 1.75"JSN.(OAL-10.4') *RIH to 3,980'ctm.Bullhead filtered treated SW down coil into formation @ 1.3 bpm. i.0.5 gallons/100bbI NPS2263 scale inhibiter ii.0.5%by volume NoBlok C iii.0.2ppb Aldicide G iv.0.25ppb BARASCAV D Oxygen Scavenger *At 23:58 pm,Depth:3,980'ctm.Continue bullheading filtered treated SW down coil into formation.WHP-1150 psi,Circ-4000 psi,Rate-1.2 bpm,Volume-220 bbls away. 4/27/2017 4/28/2017 1,311.0 00:00 4/27/17-00:00 4/28/17 (DAD Acid Treatment) *Continue running in hole w/1.75"JSN while laying in slick treated SW.Max Depth Achieved= 15,176'ctm. *Lay in 176 bbls of nitrified DAD acid recipe©1 bpm/350 scfm from 15,176'ctm up to 11,581' ctm as per program.(Ported Pup Intervals). *Max treatment pressures:WHP-1393 psi,Circ-2750 psi. *Depth: 11,581'ctm,flushed 1.75"coiled tubing w/50 bbls of nitrified filtered seawater @ 1 bpm/ 350 scfm. *Freeze protected 1.75"coiled tubing w/35 bbls of diesel while pulling out of hole. *LRS pumped 13 bbls of MEOH down 1.75"coil x tubing annulus. *LRS freeze protected tubing w/20 bbls of diesel. *In lubricator w/BHA and well secured.Blow down 1.75"coiled tubing w/N2 pushing all diesel returns through test header to Ops flow back tanks.. *1900 gallons of total N2 used for the job.300 gallons remaining in N2 pump unit. *Discuss plan forward w/Anchorage team,instructed to rig down SLB coiled tubing. *Unstab injector head and break down BHA.Break down all 2"1502 hardline. *Remove SLB BOP stack,P-sub,and 2"1502 stand pipe from wellhead. *Vetco removed 3-1/8"5M secondary gate valve and installed tree cap flange.(WC Barriers= TRSV&5M Gate Valve) *Ops unloading IA @ 50 psi per hour waiting for gas to turn the corner on the IA. *Ops Flowback Tank Volumes:Tank A=266 bbls,Tank B=258 bbls. 4/28/2017 4/29/2017 1,311.0 00:00 4/28/17-00:00 4/29/17 (DAD Acid Treatment) *SLB completed rig down activities.Move equipment off ODST-45a and stage equipment for CH2 weld repairs to 1.75"coiled tubing. *Ops unloading IA @ 50 psi per hour waiting for gas to turn the corner on the IA. IA=1200 psi. Calculated hydrostatic @ Orifice GLV=1700 psi. *Ops Flowback Tank Volumes:Tank A=266 bbls,Tank B=258 bbls. *14:00 IA=1670 psi.Lift gas turned the corner on IA.WHP climbing *22:00 Ops Flowback Tank Volumes:Tank A=299 bbls,Tank B=312 bbls. 4/29/2017 4/30/2017 1,311.0 00:00 4/28/17-00:00 4/29/17 (DAD Acid Treatment) *Operations flowed 300 bbls of returns to flow back tanks. *Ops taking samples until well is ready for production. *Adjust returns PH 6-7 and pump returns down disposal well utilizing P-6. *Complete well handover from Operations to Wells Group. Page 2/2 Report Printed: 5/5/2017 • S • ODST-45A Well Completion Schematic FINAL 5-9-2016 No. UpperCompletlonEquipment MD(ft) I TVbtft) i 16" A L'etcoGray-ubir:pl- 34 i Conductor B 2-7/8"6.40#L-801BT-r;'-_b7rg 1 C 2.7/8"HES"NE"TRSLw/2.313'F 2018 40,c D 2-7/8"6.404L-80IBT-MTubing(21u ,s E 27/8'x 1"SIB GLM#3w/15'Pup Top&Bottom 3365 2441 F 2-7/8"6.40#L-80IBT-M Tubing ^-J CO GLM#3 G HE5"X"Nipple 44(2313"ID)2-7/8"w/15'F 2982 ti 2-7/8"6.40#L-801BT-M Tubing DV r 2-7/8'x 1'SLB GLM#2w/15'Pup Top&Bottom 6122 3792 )© G i _I 2-7/8"6.40#L-801BT-MTubing(2'c K HES"X"NJpple#3(2.31T ID)2.7 ._ ;:p&Bottom 6222 3820 L 2-7/$'6.40#L-80IF-r% PA 2-7/13'x 1"SLB GLM#1,;,%15 Pup Top&Bottom 9491 4825 N 2-7/8"6.40#L-801 BT-M Tubing(2 J of n is) 0 HES"X"N[pole#2[2.313"ID)2-7/8"w/15'Pup Top&Bottom - 9527 4856 Surface Casing P 2.7/$'6.40#L-80187-M Tubing(1Jaints) . 10-3/4"45.5#L-80 o HES 2-7/8*ROC gauge withI-wlretosurface w/15'PupTop&Bottom 965,7 4876 BTC R 2.7/8"6.40#L-60IBT-MTubing(1Joints) @ 4,973'MD/ s Baker Hughes 2-7/8"x7.5/8"FHL Retrieu able Packer i.,i 77 4899 T 2-7/8'6.40#L-801BT-MTubing(2Joirv) 3,438'TVD 27/8'HESSIIdingSleeve w/'X'N!pole Profile 2.313"I.D.Run In Closed O u [Sleeve Shifts Dawn to Open) - GLM#2 i V 2-7/8"6.40#L-89IBT-tvtTubing DV W HES"X"Nipple#1[2.313"ID)2-7/8"w/RHC Ptug+15'Pup Top&Bottom 9256 X 2-7/$'6.40#L-B0 IBT-M Tubing ®X 0 Y HES 5.25"Auto Entry Mule Shoe S9C2 End o+fAss e,.,b,y 962 449 No. Lowe rCorrell etion Equlpment MD[ft) TVD(tt) 23 WFT5.75"ID PER Tie Back SIe2w.'e 15ft 9931 4951 WFT"TSP"LJnet Top Pkrw/Hold Down Slips 5-1/2 2086 7-5/829.70w/Vam Top 9907 4956 24 13T Box Down WFT"P HR"Rotating 14yd Set Liner Hanger 5.1/2 20#x 7-5/8 29.70 Aha/5-1/2 Vam GLM#1 25 Top HTPin xPin XOw/5-1/2VamTop HTBea x4-1/2Hydrii521Pin 9410 49575/16"OV J WFT4-1/2 12604x 5.75od x15 Ft"Genesis"Water-Based Swe liable Packer w/ 11401 5173 ® x CO 26 41/214ydril 521 Bax x Pin 27 4-1/21260 L-80 Fydri l Pupjt Oft(Ported w/61/2 holes) 11581 5170 _ 28 4-1/21260L-80i-tydrii Pupjt4rt[Ported w/61/2 holes) 11786 5169 O 29 4-1/21260L-801-tydril Pupjt4ft(Ported w/61/2 holes) 11991 5171 — 30 41/21260 L-80 Hydril Pupjt Oft(Ported w/61/2 holes) 12196 5171 31 41/21260 L-60 HydriI Pupjt4ft(Ported w/61/2holes) 12402 5158 2 O 32 4-1/21260 L-89 HydriI Pup jt Oft(Ported w/61/2 holes) 12688 5132 33 41/21260L-80HydriIPup jt4ft(Ported w/61/2 holes) 13003 5101 Q Q I p 34 4-1/21260 L-89 Hydril Pupjt Oft(Ported w/61/2 holes) 13213 5083 35 41/2 1260 L-80 Hydril Pup jt 4ft(Ported w/6 1/2 holes) 13417 5066 El © 36 4-1/21269L-89Hydrii Pup jt4ft(Ported w/6 1/2 holes) 13584 5052 37 4-1/21260L-80Hydril Pup jt4ft(Ported w/6Wholes) 13787 5032 38 41/21269L-80FydrilPup jt4ft(Ported w/61/2 holes) 13989 5018 39 4-1r2.1260L-E0Hydrii Pup jt4ft(Ported w/6 1/2 ho les) 14195 5015 Intermediate 40 41/212 EO1-80HydrilPup jt4ft(Ported w/61/2 holes) 14396 5012 iiii Casing 41 41/212.60L-80Hydril Pup jt4ft(Ported w/6 1/2 holes) 146.50 5004 Q 7-5/8"29.7#L- 42 4-1/21263L-80Hydril Pupjt4ft(Ported w/61/2holes) 14806 5001. / 80 BTC-M 43 4-11212601-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 150178 5001 @ 11,377' MD/ 44 4-1/212E0L-80HydrilPupjt4ft(Ported w/61/2 holes) 15210 5008 5,174'TVD 45 4-1/21160L-8QHydriiPupjt4ft(Ported w/61/2 holes) 15417 Sola 46 RayOiiTod Silver BultetEccentric Float Shoe(PLUGGED)w/4-1/2Hydril 521 15422 5018 th N. £n of Ass&rb4' 19.12-' 5018 o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 \ ► 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 0 :/ a 0 a 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 I 1 J Production 6-1/8"Hole TD at 15,424'MD/5,018'TVD g\��\��y���A THE STATE Alaska Oil and Gas ti ,;-s of T c TA Conservation Commission ft'ritt_== 333 West Seventh Avenue *R., I. GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 of A 5 Fax: 907.276.7542 www.aogcc.alaska.gov Rami Jasser Senior Staff Completions Engineer Caelus Natural Resources Alaska, LLC 3700 Centerpoint Dr., Ste. 500 Anchorage,AK 99503 s m�E�1 , . ` ,'``' Re: Oooguruk Field, Torok Oil Pool, ODST-45A Permit to Drill Number: 209-079 Sundry Number: 317-117 Dear Mr. Jasser: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, p Cathy . Foerster Chair DATED this 22 day of March,2017. RBDMS C- Mi;'R, 2 3 2017 , • 0 RECEIVED STATE OF ALASKA AR 1 7 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION Q1 ,/ Z 7 7C.�C APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ r �� Operations shutdown❑ Suspend ❑ Perforate ❑ PAI?.Other Stimulated Pull Tubing ❑ i Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ 4e-enter Susp Well ❑ Alter Casing ❑ Other:Sedt 0 2.Operator Name: Caelus Natural Resources Alaska,LLC • 4.Current Well Class: 5.Permit to Drill Number: 4-61.1-4-••09.11. Exploratory ❑ Development 0 , 209-079 1 0*I'LL." 3.Address: Stratigraphic ❑ Service ❑ 6.API Number: 3700 Centerpoint Drive Suite 500,Anchorage,AK 99503 50-703-20577-01-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A ODST-45A Will planned perforations require a spacing exception? Yes ❑ No 0 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 355036 . Oooguruk-Torok Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk{MD): 15,429 - 5,018 • 15,424 ' 5,018 • 1,444 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 153' 153' N/A N/A Surface 4,931' 10-3/4" 4,973' 3,438' 5,210 psi 2,470 psi Intermediate 9,994' 7-5/8" 11,377' 5,174' 6,890 psi 4,790 psi Production Liner 5,533' 4-1/2" 15,424' 5,018' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See attachment,pg.2 / See attachment,pg.2 2-7/8",6.40# L-80 IBT-M 9,906'MD Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): See attachment,pg.3 See attachment,pg.2 / 12.Attachments: Proposal Summary ❑ Wellbore schematic U 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development 0 • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 3/29/2017 OIL 0 • WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved Rami Jasser,343-2182 herein will not be deviated from without prior written approval. Contact Email ramijassert icaeluseneray.com Printed Name Rami J-.ser Title Senior Staff Completions Engineer I Signature �"1- Phone 343-2182 Date 2,—R, —22s1l COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3\-7- kk7 Plug Integrity ❑ BOP Test❑ Mechanical Integrity Test ❑ Location Clearance ❑ As,` -1 ,Z.. i i'i Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: / 0 "' Li 0 9 RBDF LL___ [,'" 2 3 2017 / , A PPROVED BY Approved by: / / 9p i� COMMISSIONER THE COMMISSION Date: 3,,z2.-1 7 'K'6 *00- 4f •,/2 7 3- 71-17 Form 10-403 Revised 11/2015 0 n AA ''r� 9 1pt iAs valid for 12 months from a date of approval. Submit Fonn and 1 ������111111 pp Attachments in Duplicate • RECEIVED cAEus® MAR 17 2017 Ener Alaska OGCC Caelus Natural Resources Alaska,LLC 3700 Centerpoint Drive,Suite 500 Anchorage,AK 99503 Tel:(907)277-2700 Fax:(907)343-2190 March 16, 2017 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite #100 Anchorage, AK 99501 RE: ODST-45a Sundry Application to perform a Dynamic Acid Dispersion (DAD) Acid Treatment Ref: PTD 209-0796 Caelus Natural Resources Alaska, LLC. (CNRA) hereby submits an Application for Sundry to inject utilizing coil tubing a DAD acid treatment with N2 across the lateral and across each pre- perforated pup to re-establish production by removing scale and debris. / Please see the proposed plan attachments and supporting documentation. Sincerely, Rami Jasser Ai Senior Staff Completions Engineer Attachments: Form 10-403 Supporting information cc: ODST-45a Well File 0 a Attachment Pg. 2 AOGCC Form 10-403 ,,.. Sundry Application,. Box 11 - Perforation Locations Well:ODST-45a Top(MD) Bottom(MD) Top(TVD) Bottom(TVD) 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 11,581 11,586 5,170 5,170 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2"holes 11,786 11,791 5,169 5,169 4-%2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 11,991 11,996 5,171 5,171 4-Y2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 12,196 12,200 5,171 5,171 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2"holes 12,402 12,406 5,159 5,159 4-%2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 12,688 12,692 5,132 5,132 4-%', 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,009 13,014 5,101 5,101 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,213 13,217 5,083 5,083 4-%2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,417 13,422 5,066 5,065 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,584 13,588 5,052 5,051 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,787 13,792 5,032 5,032 4-%2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,989 13,994 5,018 5,018 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2"holes 14,195 14,200 5,015 5,015 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 14,396 14,401 5,012 5,011 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 14,600 14,604 5,004 5,004 4-%', 12.60#, L-80 Liner -Pup joints ported with 6-1/2"holes 14,806 14,810 5,001 5,001 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 15,008 15,013 5,001 5,001 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 15,210 15,215 5,008 5,008 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 15,417 15,422 5,018 5,008 Eccentric Shoe 15,422 15,424 5,018 5,018 • Attachment Pg. 3 AOGCC Form 10-403 Sundry Application Box 11 - Packer Locations SMR4OEVSMNUMIONEMORMEORPA laggm , Well: ODST-45a MD TVD HES "NE" TRSV 2,051 2,018 BHI 2-7/8" FL Retrievable Packer 9,720 4,899 WFT Liner Top Packer 9,907 4,956 WFT Genesis Water-Based Swellable Packer 11,401 5,173 ODST-45A DAD Aciditeatment-Version 3 • c 0 fl Alaska ODST-45A V3 DAD Acid Treatment Prop # - 926537 GenSub- 6120/401 Prepared: Date: Chad Gueco Wells Supervisor Prepared: Date: Eli Wilson Wells Supervisor Reviewed: Date: Jack Kralick Wells Superintendent Approved: Date: Rami Jasser Sr. Staff Completions Engineer • Page 1 • ODST-45A DAD Acidreatment—Version 3 ODSN-45a CT DAD Acid Treatment Current Conditions: • Well Shut-in since July 2016 due to low productivity. Objectives: • Re-establish production by removing scale and debris in the entire lateral r using coil tubing and injecting DAD acid treatment with N2 including the perforated pups. Max depth reached in the past with coil was 14,827 ft. MD. • Complete ODST-45A treatment during March 22nd to April 12th well work schedule. • Optimize use of RSC and cost by building filtered seawater with additives y described in the procedure for ODST-45A treatment or re-evaluate well work well order. Pre Job Checklist : 1. Prior to rigging up CTU verify with Ops that the IA has gas to the orifice and the orifice check valve is holding pressure. 2. Involve ODS HSE representative in all aspects of the acid treatment and flow back. 4" A),-1 vw,rte. i 4-z-e,• vs 3. Follow SLB PPE & HSE procedures when handling acid z 4. Emergency shower/eye wash station inspected and apf coved by HSE. 5. Containment built for acid transport. 6. Heaters for SLB pre-mixed soda ash transport. 7. Manifold and 2" 1502 hardline has been assembled to enable SLB to pump directly down the TBG as well as to the test header. (2" 1502 flange w/block valve installed on tubing freeze protect drop) 8. Ops Supervisor has designated flow back Tank A and B for acid flow back. 9. Diesel suit case line rigged up to the SLB coil pump. (Well Bay # 2) 10.Ops to add 100 bbls of seawater to each flow back tank (A & B) to "buffer" internal coating on tank. 11.Split the designated 45 bbls pre-mixed Soda Ash solution into both Ops Flow Back Tanks A & B to neutralize acid pre-flow back. 12. 10 bbls of seawater loaded in second compartment of acid transport for post- flush. 13. 15 bbls of MEOH loaded in LRS truck to freeze protect surface lines. 14.PH strips available to test 15% HCL for disposal. 15.Designate a sample catcher from SLB crew when testing pH in flowback tank 16.Sample bottles to test pH. Coiled Tubing Procedure: 1 . MIRU 1 3/4" coil tubing unit and associated equipment. Nipple up 4-1/16" 10k Quad BOP's and required cross-over spools. Page 2 ODST-45A DAD Acidreatment—Version 3 • 2. A crane is needed for lifting operations, verify with crane operator, weight of every component to be lifted during rigging up/rigging down procedures. 3. Conduct Pre Job Safety Meeting (PJSM) in rigging up Coiled Tubing Unit (CTU) along with associated surface equipment. Mitigate all hazards discussed. 4. The Well Work Supervisor, Operations Supervisor, and the Schlumberger Supervisors should all agree to contingencies. 5. High pressure areas should be recognized and posted. Make an "All Call" prior to testing lines alerting personnel to stay away from high pressure. 6. Ensure that the IA and OA pressures are monitored throughout the job. 7. Ensure that all tanks and lines are clean and all fluids filtered before entering the CT pump. NOTE: Ensure the Micro Motion (MM) is calibrated with diesel. 8. Conduct HSE walk through with ODS operator or production supervisor, Schlumberger's CTU supervisor, Caelus Energy Wells Supervisor, on-site environmental coordinator and HSE specialist. Note and mitigate any hazards or concerns. PLs , f��� y Ate z.: . , 413-- NOTE: NOTE: Ensure all materials used for treatment has a SDS sheet in the Op's Cab for quick review. (All NCE's completed) DAD treatment was conducted on this well September 14, 2011 9. Verify OD, ID, length of all tools and that any fishing equipment is available if needed. Ensure that the CTU operator is aware of all restrictions in the well and has a plan to slow down prior to running BHA thru the restrictions. 10. Make Up (MU) BHA for the DAD Acid Treatment. Install roll-on Coiled Tubing Connector and pull test to 10k. Install dual checks, two x 4 ft. 2" straight bar extension (stinger) and 2" jet swirl nozzle. No sharp shoulders on the BHA. 11 . Both the CTU and Well Work Supervisor must pre-approve the jet swirl nozzle. 12. For all BHA items run in the hole dimensions will be measured and posted by Well Work Supervisor and CTU Supervisor in the Op's Cab. • Pick up the required lubricator and stab on well. Line up and pressure test the BOP body to 250/4500psi.,Pressure up on the lubricator to equal the Well Head Pressure (WHP) and open the lower swab valve, Page 3 • ODST-45A DAD AcidSeatment—Version 3 count and record turns. Open the upper swab valve slowly and count and record turns. NOTE: Open bottom valve first and with low pressure differential between wellbore and lubricator, open top valve slowly to reduce any possible erosion of bottom swab valve gate. NOTE: Notify SLB Stimulation 1 day before the treatment and give go ahead to prepare 190 bbl of DAD Acid as per below recipe and load into two (2) acid tubes. NOTE: Weight limit on the ice road is 100,000Ibs maximum. Table 1: 10% DAD acid recipe 10% DAD 190.0 bbl 7,980 Gal Code Purpose Concentration Quantity H010 10% HCI '� 900 gpt 7,182 Gal A026 Xylene / 100 gpt 798 Gal A264 Corrosion Inhibitor 5 gpt 40 Gal F103 Surfactant 15 gpt 120 Gal W054 Non-Emulsifier 5 gpt 40 Gal A255 H2S Scavenger 5 gpt 40 Gal L041 Chelating Agent 50 ppt 399 Lbs L058 Iron Stabilizer 10 ppt 80 Lbs 13. Move in acid tubes, pump unit and Nitrogen unit. Rig-up to pump down CT, test lines to 4,500psi. 14. Perform BOP test per SLB procedure. 15. Make up, pull test and pressure test coiled tubing connector and MHA per SLB and Caelus requirements. Run 1: Acid Stimulation Treatment: 16. Perform PJSM for fill cleanout and pumping acid. 17. Make up BHA for acid wash. CTC, DFCV, stingers, and 2"jet-swirl nozzle. 18. Stab on well, perform pressure tests per SLB procedure. 19. Tag stripper, zero CT depth taking into consideration RKB, ground to stripper and BHA length. 20. Open wellhead and begin RIH. Slow down to < 20 fpm for any restrictions and when entering/ leaving tubing. Complete weight checks every 1,000 ft. 21 . At 4,000ft start pumping Filtered treated Sea Water with friction reducer. Page 4 ' ODST-45A DAD Acidleatment—Version 3 • • Filtered Treated Seawater filtered to sub 20 NTU's prior to the addition of additives. i. 0.5 gallons / 100bb1 NPS2263 scale inhibiter ii. 0.5% by volume NoBlok C iii. 0.2ppb Aldicide G iv. 0.25ppb BARASCAV D Oxygen Scavenger NOTE: Do not add Aldicide G and Barascav D at the same time, doing so will inhibit effectiveness v. Maintain post additives NTU readings below 180 NTU vi. Diesel should be used for freeze protection 22. Continue RIH until maximum depth reached. 23. Close choke, line up acid pump and nitrogen unit to pump down CT and come online with nitrified DAD system down the coil. Pump acid at 1 BPM, Nitrogen at 350-400 scf/min. Reduce rate if Circulating pressure approaches, 4,000 psi or wellhead pressure approaches 1,500psi • Frac pressure: 0.65 psi/ft x 5,000ft TVD = 3,250psi • Hydrostatic pressure: 6.8 ppg x 5,000ft TVD 052 = 1,770 si • Maximum pressure: 3,250psi — 1,770psi 1,480psi fak..0( 24. Start pumping nitrified acid down the CT as per the pump schedule specified in Table 2. i) If CT cannot reach the toe perforated pup at 15,417ft, pump the acid from lock up depth to 15,417ft (2 gal/ft.). ii) Achieve maximum coil depth and shut it back side (coil x production tubing annulus). iii) Begin pumping acid treatment per Table 2. f iv) If injectivity is below 0.5 BPM, let the acid soak for 1/2 hour, and then resume squeezing. v) Upon achieving 500 psi on the coil x production tubing annulus, POOH at 80% of pipe displacement, slow down at each pre perforated pup depth while jetting & reciprocating 3 passes. vi) Slow down POOH speed at the perforated pup depth. Perforated Pup depths are shown in Table 2, and in more detail in the Appendices. Page 5 _ _ ' ODST-45A DAD Acideatment—Version 3 • Table 2: Pumping schedule with CT depth MD Cumulative POOH Fluid Nitrogen (ft) acid volume speed rate rate (bbl) (ft/min) (BPM) (scf/min) 15,417 10 21 1 350 15,210 20 20 1 350 15,008 30 20 1 350 14,806 40 21 1 350 14,600 50 20 1 350 14,396 60 20 1 350 14,195 70 21 1 350 13,989 80 20 1 350 13,787 90 20 1 350 13,584 100 17 1 350 13,417 110 20 1 350 13,213 120 20 1 350 13,009 130 32 1 350 12,688 140 29 1 350 12,402 150 21 1 350 12,196 160 21 1 350 11,991 170 21 1 350 11,786 180 21 1 350 11,581 190 21 1 350 25. Displace CT with nitrified filtered treated Sea Water. • Liquid rate 1 BPM • N2 rate 350 scf/min 26. Load 5 bbl. of Methanol into the IA with LRS. NOTE: Ensure no physical contact with the return fluids. 27. POOH to surface while continuing flow back to Ops flow back tanks. NOTE: Schlumberger to stay rigged up until the well is in production. 28. Produce a minimum of 300 bbls back to Ops flow back tanks. 29. Ops to test produced fluid (normal sample port on flow line) for Ph (5-7 PH level) so as to not upset the CPF 3 primary separator. 30. Ops to add emulsion breaker as necessary. Page 6 ODST-45A DAD Acideatment—Version 3 40 31 . Route returns from test header to production. NOTE: Operations will coordinate the well settings through the entire process. 32. Once well is in production, test the PH in designated Ops flow back tanks. 33. Agitate fluids in tanks and add seawater as needed to stabilize PH (6-7). 34. Once fluid is neutralized, begin disposing of fluids down disposal well utilizing P-6. Take multiple samples to verify PH is in acceptable range. 35. RDMO Schlumberger pump unit. 36. Blow down CT string with N2 if this is the last planned CTU well. 37. Complete well handover from Wells Group to Operations. Page 7 S 4111/ .ODST-45A Well Completion Schematic FINAL 5-9-2016 . . .. No. Upper Completion Equipment MD(ft) TVD(ft) I .. ,. 16" A VetcoGray Tubing Hanger 34 34 A' 1 1 •• .w Conductor B 2-7/8"6.40#L-80 IBT-M Tubing C 2-7/8"HES"NE"TRSV w/2.313"Packing Bore 2051 2018 NJ CO IV: D 2-7/8"6.40#L-80 IBT-M Tubing(2 Joints) E 2-7/8"x 1"SIB GLM#3 w/15'Pup Top&Bottom 3365 2941 .... F 2-7/8"6.40#L-80 IBT-M Tubing •• ... :••'1 - 410 iiii GLM#3 G HES"X"Nipple#4(2.313"ID)2-7/8"w/15'Pup Top&Bottom 3461 2982 H 2-7/8"6.40#L-80 IBT-M Tubing I 2-7/8"x 1"SLB GLM#2 w/15Pup Top&Bottom 6128 3792 la G .]i] J 2-7/8"6.40#L-80 IBT-M Tubing(2 Joints) K HES"X"Nipple#3(2.313"ID)2-7/8"w/15'Pup Top&Bottom 6222 3820 L 2-7/8"6.40#L-80 IBT-M Tubing M 2-7/8"x 1"SLB GLM#1 w/15'Pup Top&Bottom 9491 4825 A 1111. N 2-7/8"6.40#L-80 IBT-M Tubing(2 Joints) 0 HES"X"Nipple#2(2.313"ID)2-7/8"w/15'Pup Top&Bottom 9587 4856 Surface Casing P 2-7/8"6.40#L-80 IBT-M Tubing(1 Joints) 10-3/4"45.5#L-80 a HES 2-7/8"ROC gauge with I-wire to surface w/15'Pup Top&Bottom 9650 4876 BTC R 2-7/8"6.40#1-80 IBT-M Tubing(1 Joints) S Baker Hughes 2-7/8"x 7-5/8"FHL Retrievable Packer 9720 4899 @ 4,973'MD/ T 2-7/8"6.40#L-80 IBT-M Tubing(2 Joints) 3,438'TVD 2-7/8"HES Sliding Sleeve w/'X'Nipple Profile 2.3131.0.Run in Closed U - 4111 (Sleeve Shifts Down to Open) 9790 4920 GLM#2 ..a..„1 V 2-7/8"6.40#L-80 IBT-M Tubing DV W HES"X"Nipple#1(2.31.3''ID)2-7/8"w/RHC Plug+1.5'Pup Top&Bottom 9856 4940 X 2-7/8"6.40#L-80 IBT-M Tubing 12 CO Y HES 5.25"Auto Entry Mule Shoe 9902 4954 End of Assembly 9906 4956 No. Lower Completion Equipment MD(ft) 1VD(ft) 23 WFT 5.75"ID PBR Tie Back Sleeve 15ft 9891 4951 WFT"TSP"Liner Top Pkr w/Hold Down Slips 5-1/220#x 7-5/8 29.70 w/Vam Top 9907 4956 24 HT Box Down WFT"PHR"Rotating Hyd Set Liner Hanger 5-1/2 20#x 7-5/8 29.70#w/5-1/2 yam 9910 4957 GLM#1 - =,-I CO 25 Top HT Pins Pin X0 w/5-1/2 Vam Top HT Box x 4-1/2 Hydril 521 Pin WFT4-1/2 12.60#x 5.75od x 15 Ft"Genesis"Water-Based Swellable Packer w/ 5/16"OV _ 11401 5173 12 0 26 4-1/2 Hydril 521 Box x Pin 27 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 11581 5170 28 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 11786 5169 -II 43 29 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 11991 5171 30 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 12196 5171 31 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 12402 5159 S II 32 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 12688 5132 33 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13009 5101 00i 0 34 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13213 5083 _ 35 4-1/2 12.60 1-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13417 5066 .13 0 36 4-1/2 12.60 1-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13584 5052 37 4-1/212.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13787 5032 38 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13989 5018 39 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 14195 5015 .. ,. ,. Intermediate ,. 40 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 14396 5012 Casing 41 4-1/2 12.60 1-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 14600 5004 7-5/8"29.7#L- 42 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 14806 5001 1] :.:,....." ,, 80 BTC-M 43 4-1/2 12.601-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 15008 5001 : @ 11,377'MD/ 44 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 15210 5008 5,174'TVD 45 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 15417 5018 46 Ray Oil Tool Silver Bullet Eccentric Float Shoe(PLUGGED)w/4-1/2 Hydril 521 15422 5018 ... End of Assembly 15424 5018 ......„, ---------------------------------------I 0 00 0 00 .0 0 oo 0 oo 0o 00 oo -0. oo oo ..0 oo oo oo I o :: ••••• ?,,y o o 0 o 0 0 0 0 0 0 0 0 0 0 0 0 0 o I ..... -.... ..... ,. . . .. ,. , . . •. , . . . . . ." . Production 6-1/8"Hole TD at 15,429'MD/5,018'TVD r;OF• �>/7,sTHE STATE Alaska Oil and Gas s���, ofALASKA Conservation Commission :_- __. ':tt _ 333 West Seventh Avenue z__ " GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 \T1 Main: 907 279.1433 4'‘ALAS. Fax: 907.276 7542 www aogcc alaska.gov scow Rami Jasser Sr. Completions Engineer Caelus Natural Resources Alaska, LLC , °17c1 3700 Centerpoint Drive, Suite 500 Anchorage, AK 99503 Re: Oooguruk Field, Torok Oil Pool, ODST-45A Sundry Number: 315-444 Dear Mr. Jasser: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, C,124 Cathy P.ioerster Chair DATED this 2' y of July, 2015 Encl. STATE OF ALASKA YJrS ?I Z S ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ro --- s. 20 MC 25.280 . " _ " 1.Type of Request: Abandon❑ Plug for Redd' ❑ Perforate New Pool ❑ Repair Well❑ t nange Approved Program ❑ Suspend❑ Plug Perforations ❑ Perforate❑ Pull Tubing Z/ Time Extension ❑ Operations Shutdown❑ Re-enter Susp.Well ❑ Stimulate❑ Alter Casing❑ Other:Swap ESP to Gas Lift • Q 2.Operator Name 4.Current Well Class: 5.Permit to Dnll Number Caelus Natural Resources Alaska,LLC . Exploratory ❑ Development 2 • 209-079 ' 3 Address: 3700 Centerpoint Drive Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,AK 99503 50-703-20577-01-00 7 If perforating: 8 Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool'? N/A / ODST-45A • Will planned perforations require a spacing exception? Yes ❑ No ❑J 9 Property Designation(Lease Number): 10.Field/Pool(s). ADL 355036 Oooguruk-Torok Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft) Effective Depth MD(ft): Effective Depth TVD(ft) Plugs(measured): Junk(measured): 15,429' - 5018' - 15,422' • 5018' • N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 153' 153' N/A N/A Surface 4931' 10-3/4" 4973' 3438' 5210 psi 2470 psi Intermediate 9994' 7-5/8" 11377' 5174' 6890 psi 4790 psi Production Liner 5533' 4-1/2" 9891'-15,424' 4951'-5018' 8430 psi 7500 psi Perforation Depth MD(ft): J Perforation Depth TVD(ft): Tubing Size: Tubing Grade. Tubing MD(ft). See Attachment,pg.2 See Attachment,pg.2 2-7/8",6.4# L-80, IBT-M 9560' Packers and SSSV Type: SSSV; Hydro II Pkr; Packers and SSSV MD(ft)and TVD(ft) 2053'MD/2020'TVD,2688'MD/2551'TVD, Liner Top Pkr;Water Swell Pkr 9910'MD/4957'TVD; 11401'MD/5173'TVD 12.Attachments. Description Summary of Proposal ❑✓ 13.Well Class after proposed work Detailed Operations Program ❑✓ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development❑✓ " Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations. 4/28/2016 Oil ❑✓ • Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Rami Jasser,343-2182 Email rami.iasser(C�caelusenergy.com Printed NameRami Jasser Title Sr.Completions Engineer Signature 17 ;Y'1 Phone Date 343-2182 -1-21-2atS COMMISSION USE ONLY Conditions of approval Notify Commission so that a representative may witness Sundry Number: JL 1..� Plug Integrity ❑ BOP Test [kr Mechanical Integrity Test ❑ Location Clearance ❑ Other: h. g S & �sp m/TS/ar � �� 5 r ) Spacing Exception Required'? Yes ❑ No Subsequent Form Required /0 -L1 U'-I APPROVED BY �7 Approved by c 2% _P r /COMMISSIONER THE COMMISSION Date 7_2_,5z.45- � '( �f ?123// Submit Form and Form 10-403(Rev ed 10/2012) l� I i a d for 12 months from the date of approval. Attach sin Duplicate U' `�� L z' RBDMS� AUG - 2 2015 / /3 c A cs, S Alaska Caelus Natural Resources Alaska,LLC 3700 Centerpoint Drive,Suite 500 Anchorage,AK 99503 Tel:(907)277-2700 Fax:(907)343-2190 July 8, 2015 �® RECEIVED State of Alaska JUL 2 1 2015 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite #100 AOGCC Anchorage, AK 99501 RE: ODST-45a Sundry Application to swap out ESP with Gas Lift Ref: PTD 209-079 Caelus Natural Resources Alaska, LLC. (CNRA) hereby submits an Application for Sundry to swap out the existing 2-7/8" ESP Completion on ODST-45a and replace with a 2-7/8" Gas Lift Completion to aid in cleaning the solids out of the hole and allow concentric coil access for future cleanouts. Please see the proposed plan attachments and supporting documentation. Sincerely, / Rami Jass r Senior Completions Engineer Attachments: Form 10-403 Supporting information cc: ODST-45a Well File Caelus Natural Resources Alaska, LLC ODST-45A Page 2 AOGCC Form 10-403, Application for Sundry Approvals Present Well Condition Summary, Box 11 Perforation Depth (MD/TVD) - Attachment 4-W, 12.60#, L-80 Liner - Pup joints ported with 6-1/2" holes @ depths listed: MD TVD 11,581' - 11,586' 5170' - 5170' 11,786' - 11,791' 5169' - 5169' 11,991' - 11,996' 5171' - 5171' 12,196' - 12,200' 5171' - 5171' 12,402' - 12,406' 5159' - 5159' 12,688' - 12,692' 5132' - 5132' 13,009' - 13,014' 5101' - 5101' 13,213' - 13,217' 5083' - 5083' 13,417' - 13,422' 5066' - 5065' 13,584' - 13,588' 5052' - 5051' 13,787' - 13,792' 5032' - 5032' 13,989' - 13,994' 5018' - 5018' 14,195' - 14,200' 5015' - 5015' 14,396' - 14,401' 5012' - 5011' 14,600' - 14,604' 5004' - 5004' 14,806' - 14,810' 5001' - 5001' 15,008' - 15,013' 5001' - 5001' 15,210' - 15,215' 5008' - 5008' 15,417' - 15,422' 5018' - 5018' GCAEUJS Energy Alaska ODST-45A RWO Program Pull ESP and Install Gas Lift Completion ESP Completion: 9,558' MD / 4,847' TVD FSV Completion: 9,495' MD / 4,827' TVD Planned 2-7/8" Gas Lift String: 9,906' MD / 4,956' TVD AFE# 150035 AOGCC Sundry # TBD Prepared: Date: Rami Jasser: Sr. Staff Completions Engineer Reviewed: Date: Jack Kralick: Wells Superintendent Reviewed: Date: Gary Ross: Operations Superintendent Reviewed: Date: Rob Tirpack: Drilling Manager Approved: Date: Vern Johnson: Alaska Drilling Manager ODST-45A 2015 RWO Program Outline—July 8th, 2015 1 C CAELL En Alaska Work Over Objective: ODST-45A was drilled in the Oooguruk-Torok Pool as an oil producing development well. The original well was drilled in the Oooguruk-Nuiqsut pool(ODSN-45)and later recompleted to the Torok(ODST-45A)on October 30, 2009. A subsequent rig workover was conducted to swap the 4-1/2 inch tubing completion to a 2-7/8 inch ESP completion. Since then ODST-45A had 3 total ESP failures: • First ESP was installed 4/14/2011 and had a run life of 295 days—Failed due to solid production&plugging. • Second ESP was installed 11/2/2012 and had a run life of 118 days—Failed due to solid production& plugging. • Third ESP was installed 7/13/2013 and had a run life of 260 days—Failed due to solid production& plugging. Due to the 3 ESP failures the decision was made to pull the current ESP out of the hole and replace the upper completion string with a 2-7/8"gas lift system.This string will serve as a velocity production string to aid in cleaning out the solids out of the hole+allow concentric coil access for future clean out trips. Current Well Information(Please reference the following schematic): • Measured BHP: 1911 psi(7.3ppg EMW C 5000' TVD) • MASP(based on 0.lpsi/ft gradient): 1411 • Estimated BHT: 135 F • Gas Lift Mandrel Status: o 2-7/8"x 1.5"GLM# 1 @ 9315' MDrkb has a ''/a"orifice valve o 2-7/8"x 1.5"GLM#2 @ 3423' MDrkb has a dummy valve o 2-7/8"x 1.5"GLM#3 @ 2749' MDrkb has a dummy valve o 2-7/8"x 1.5"GLM#4 @ 2625' MDrkb has a dummy valve • Retrievable ESP Feed-Thru Packer set @ 2688' MDrkb ODST-45A 2015 RWO Program Outline—July 8th, 2015 2 C CAEUJS Energy Alaska ODSN-45A Current Well Schematic: Na. upper Completion Equipment MD(tt) TV0(ft) I 1 VetooCray Tubing Harper 34 34 L I ,16"Conductor 2 2-78'8.40rt L-80 BT-M Tubing I 3 HES"HE"TRSSSV 2053 2020 © illil 4 2-7'8"6 4010 L-80 BT-M Tubing 5 2-71$•x/5"Van Oil GLNMe1 w/12 Pup Top 8 Bottom 2625 2506 8 2-78840#L80BTb1Tubing • 7 WFT Hydrow II Packer Y 2688 2561 GLM#4 =.1 © "' 8 2-78'640#L-80BT-MTubrp DV — 9 2-718"x 1.5"Van Oil GLMKS vd15'Pup Top 8 Bottom 2749 2594 / f fpy 10 2-7'$'8.401 L-80 BT-M Tudry g 11 HES"X"Nipple#3 2-7;$'ef1S Pup Top&Bottom 2811 2634 12 2-78'840#L-80BT1.1Tobirp 0 iii 13 2-7/8"x 1.5"Van Oil GLM02 w'18 Pup Top&Bottom 3423 2966 GLM#3 =,,.J iiiii 14 2-71"8401iL-80BT-MTuhirp DV Li 15 HES"X"Nipple s2 2-718"rw1E Pup Top 8 Bottom 3483 2991 18 2-7$'8.400 L40 BT--M Tubing 17 2-7/8"x 1 5"Van Oil GLMM1 w✓12 Pup Top&Bottom 9315 4771 Surface Casing 18 2-78.84010L-80 BT-M Tibirp 0 0 10-3/4"45.5#L-80 19 HES 'X"Nipple Al 2-72"nm412 Pup Top&Bottom 9374 47089 BTC 20 2.78'8.40rt L-80 BT-M Ttbirp @ 4,973'MD/ 21 Auto()NOUS Vale 9495 4827 — 3,438'ND 22 ESP Pimp Ass vnby 9568 4847 GLM#2 �® End a'Assenbiy 9559 4847 DV No. Lower Completion Eauioment MD(fti TVgft) 0 CO 23 W FT PBR Tie Bede Sleeve 1% 9891 4951 24 WFT?SP'Li Top Ptrw'Hold Down Sips51.220rtx7-582970w•Vam Top ? 4950 HT Box Down WFT'PHR"Rotating Hid Sit Line Hangar 51:2 200x 7-58 29 70 taw'5-12 Vam25 9910 4957 Tap HT Pr x Pin)O w'5-12 Vam Top HT Box x 4-1;2 Hydra 521 Pin W FT 41.2 12800 x 5.75od x 15 Ft"Genes s" Water-Based Swdable Packs w. 28 4-12 Hydri 521 Bar x Pin 11401 5173 2 4-12 1280 L-80 Hydra Pipit 4R(Ported w'6 1.'2 holes) 11581 5170 29 4-12 12130 L-80 Hydra Puoit 411(Parted w'61.2 holes) 11786 5159 0 29 4-12 1200 L-80 Hydra Pi jt 411(Ported w'812 holes) 11981 5171 GLM#1 0J30 4-12 12E0 L-80 Hydra Pupjt 4R(Pored w'8 1.2 hoes) 12198 5171 Y."OV 31 4-12 1280 L-80 Hydra Pupjt 4R(Parted w'81:2 hold) 12402 5159 32 4-12 1200 L-80 Hydra Pupjt 4(Ported w'6 1.2 hold) 1288 5132 m 4-'/z"12.60#Hydril 33 4-121200 L-80 Hydra P,pjt 4R(Paled wes'6 1.2 hobs) 13009 5101 0 521 Tubing(Lower 34 4-12 1280 L-80 Hydra Pudt 44(Parted w'6 12 hold) 13213 5083 Completion) 35 4-12 1280 L-80 Hydra Pupjt 41(Parted w'C 12 hold) 13417 5086 38 4-1.2 1280 L-80 Hydra Pupjt 4(Poled w'8 12 hold) 13884 5352 ® 37 4-12 1200 L-80 Hydra PuOt 411(Paned w'8 12 hold) 13787 5032 M38 4-12 1280 L-80 Hydra Pupjt 4(Parted w'8 1.2 hold) 13989 5018 39 4-12 1280 L-80 Hydra Pi t 4R(Parted w'012 hold) 14195 5015 40 4-1.2 1280 L-80 Hydra PuOt 4(Parted w'8 12 hold) 14396 5012 0 41 4-1:2 1280 L-80 Hydra Punt 4R(Parted w'8 12 hold) 14800 5304 Intermediate 42 4.12 1280 L-80 Hydra Punt 4R(Paled w'8 1:2 hold) 14806 5001 43 4-12 1280 L-80 Hydra Punt 4R(Poled w'8 12 hold) 15008 5001 Casing 44 4-1:2 12130 L-80 Hydra Punt 4(Ported w'8 1:2 hold) 15210 5008 7-5/8"29.7#L-80 45 4-12 1280 L-80 Hydra Putat 4(Ported w'(5 1.2 hold) 15417 5018 BTC-M 40 Ray Oil Tool Silo Bullet Eccentric Float Shoe(PLUGGED)w'4 ;2 1Hydil 521 Box 15422 5018 @ 11,377'MD/ Enda'Assenbty 15424 5318 5,174'ND 0 0 :0 0 0 0 •0 0 0 0 0 0 ,0 0 0 0 0 0 0 o • • Aiil.__ ` o c o0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 I I Production 6-1/8"Hole TD at 15,438'MD/5,018'ND ODST-45A 2015 RWO Program Outline—July 8th, 2015 3 CAEUJS Energy Alaska Pre-Rig Work to be completed prior to MIRU of Nabors 19AC: Regarding Fluids: All seawater based fluids injected into the well should be built with the following properties: a. Filtered Treated Seawater filtered to sub 20 NTU's prior to the addition of additives. b. 0.5 gallons/ 100bbl NPS2263 scale inhibiter c. 0.5%by volume NoBlok C d. 0.2ppb Aldicide G e. 0.25ppb BARASCAV D Oxygen Scavenger NOTE: Do not add Aldicide G and Barascav D at the same time,doing so will inhibit effectiveness f. Maintain post additives NTU readings below 180 g. Diesel should be used for freeze protection 1. Perform pre-rig check-list tasks(grease valves and test voids). 2. Shut off gas lift support approximately 1 week prior to MIRU of Nabors 19AC. 3. Add a second swab valve for e-line and slick-line work. o Set and pull BPV as needed for this work. 4. Ensure TRSSSV is in the fully open position. 5. Pull DV from GLM # 3 located below the ESP Feed-Thru Packer to allow IA gas trapper below the packer to bleed out.Bleed IA and tubing as necessary. 6. Fluid pack IA and tubing with kill weight fluid(expecting to use 8.6 ppg Seawater) o Contingency option: RU E-Line and tube punch 10' of the 2.875", 6.5# tubing using 4 SPF tubing punches just below the production packer at 2688' MDrkb. 7. Verify TRSSSV actuation, close and verify, monitor control line pressure. Pressure test TRSSSV from below to 500 psi and hold for 15 minutes.Bleed pressure after successful test. 8. Rig up slick-line to pull the gas lift valve from the GLM#4 at 2625' MDrkb. 9. Freeze protect TxIA to 2000' with diesel. 10. MIT-TxIA to 2000 psi 5c«.C10W CuLpt 2-4"" ,"") 11. Set BPV in the tubing hanger. 12. Pressure test the tree and tubing hanger pack-off void to 5000 psi 13. Suspend the well with the following well control barriers: o 2-7/8"Tubing: • Closed ScSSV pressure test to well pressure from below. • BPV o 2-7/8"x 7-5/8"Annulus: • Pressure tested Tubing hanger pack-off to 5000 psi. 14. Monitor WHP and IAP via operator's daily reading schedule until rig moves on location, Prep surface equipment for rig move. Monitor WHP and IAP via operator's daily reading schedule until rig moves on location, Prep surface equipment for rig move. ODST-45A 2015 RWO Program Outline—July 8th, 2015 4 w� ��. .� C CAEUJS ( * Energy Alaska ODSN-45A Planned Completion Schematic: I i fin. tipper lonpletion Equipment Mad /3/Q1f 1 116" A VetcoGay TWing Hanger 34 34 A 1 ,Conductor 8 2-T8'.8.404L-80I13T-M Tu long 2-78"HES'tIE"TRSV w 2313"Packing Bore 2053 2020 G D 2-7.8"8.400 L-80 B T-M Tubing 12 Joints) E 2-7/8"x 1"SLB GLMM3 vd15'Pup Top&Bottom 2617 7500 F 2-7.8"0.4o0 L-80 6 T-M Tu bins HES"X"Nipple 44(2313"ID)2-7/8'w'15 Pup Top&Bottom 2697 2553 �J © vLM#3 1-4 2,7,8.8.404L-80 6T-M Tubing SOV 2-718'x 1"SLB GLMO2 vh15'Pup Top&Bottom 6155 3800 X G 2-7,8'0.400 L-80 6T-M Tubing i2 Joints) 1K HES"X"Nipple Ila(2313"ID)2-7/8'vv/15 Pup Top&Bog,. 6235 3824 • • L 27'8'6.400 L-80 6T--M Tubing _ M 2.718"x 1"SLB01M01 v#15'Pup Top&Bottom 9523 . 4836 N 2-78"8.40+*L-80 6T-M Tube t 12 Joints) 0 HES'IX"Nipple#2(2313"ID)2-7/8"w/13 Pup Top b 4871 Surface Casing P 2-7'8"840ML-8067-tdTubing{1Joints) 10-3/4"45.5#L- 0 HES 2-7i8"ROC gauge with I-wire to s)rface ve15 Pup Top&Bottom 80 BTC R 2-7.8"5 40*L-80 BT-M Tubing t 1 Joi is) S Baker Hughes 2-7/8'x 7-5/8"FHL Retrievable Packer 4906 @ 4,973'MD/ T 2-7''8'8.40**L-80 6T--M Tubing t2 Joints) 3,438'TVD ,VS"'Sliding Sleeve w/'X'Nipple Profile 2313"I.D.Run in Closed (Sleeve ,,19 0 ' ,*Down to Open) 177 J V -78' 8404L-8067-MTubing '.'.313"ID)2-7/8'vol RIC Plug+15 Pup Top&Bottom 9325 4931 X 78 540 L-806T-M Tubing ®x CO • -y Mule Show 4955 End cl Anon bey 9900 4955 No. lower Co*roletionEquipment ND(ft) :moot) 23 WFT PER Tie Sack Sleeve 15t 9691 4951 WET—TSP.Liner Tog Fkr w:Hold Down Slips 51 2 Mix 7-58 29 70 w Vam Top24 _ 49� HT Bat Down WET"PHR"Rotating Hyd Set Liner Hanger 5-1,2 200 x 7.5 8 29 70§hv'5-1'2 Va m 4957 GLM#1 —JCO Top HTPin xPnJOw5-12VamToo HTBox x4-1:2*Oil521Pin X10 DV WET 4-1.2 1200*x 575od x 15 Ft"'Genes Water-Based Swearable Packer ri. 11401 5173 13 O 4.1..2 Hydril 5521 Box x Pin 27 4-1,2 1280 L-80 Hydril Pupit 41t;Ported w•8 1 2 h-oill 11581 5170 28 4-1/2 1280 L-80 Hydril Pupjt 4t;Paned'V.e 1.2 hales) 11785 5189 Hi © 29 4-1,2 izeo L-80 l-t&il P/pit Olt;Parted w 8 12 hoes'' 11991 5171 30 4.12 12eo L-80 Hvo it Riot Olt;Ported'w'e 1;2 hoes 1219e 5171 S 3' 4-12 1283 L-80 Hydril P/pjt 4t;Parted w e 1.2 holes': 12402 5159 32 4-1,2 12 5-3 L-80 Hydril Puojt 411;Parted w 5 1.2 hoes'. 12588 5132 32 4.1.2 125.3 L-80 Hydril P.1 pit 411;Ported w 5 1/2 holes; 13009 5101 34 4.1'2 1280 L-80 Hydril Pu pit 4t;Ported w 81;2 hoes; 13213 5083 35 4.1,2 1280 L-80 Hydri I Puoit 42;Parted w'C 1.2 holm i 13417 5085 En © 3e 4-12 12 e L-8 Hydric P,pjt 411;Paned w•e 1.2 hoes) 13584 5052 37 41,2 1250 L-80 Hydril Rd*411 Parted a 1,2 holes;, 13787 50.32 38 4-1,2 1280 L-80 Hydril Pi pit 411,'Ported e 8 1.2 hole ) 13989 5018 lii Intermediate 39 4-1.21260 L-80 Hydril P,pit at;Ported w e 1.2 hoes; 14195 5015 Casing40 41,2 1284 L-80 Hydril Put*at;Parted w'a t2 holes' 14398 5012 4t 4-1,2 1260 L-80 Hydril Pupit 411;Parted w..8 1/2 hoes: 14800 5004 :4 7-5/8"29.7#L- 42 4-1,2 1280 L-80 Hydril Pupit Mt w 8 1:2 holm 14805 5001 -'0 ''• 80 BTC-M 43 4-1,2 1250 L-80 Hydric Pipit 411 Ported w•61/2 holes) 15008 5501 @ 11,377 MD/ 44 4-1,2 1280 L-80 Hydril Pipit at(Ported w'a 1:2 hoes) 15210 5008 5,174'TVD 45 4.12 1280 L-80 Hydril Ripit 4t;Parted w 8 1.2 hales) 15417 5018 1 4e Ray Oil Tod Silver Bullet Eccentric Float Shoe;PLUGGED)ri 41,2 Hydril 521 Bur 15422 5018 \ End oIAssenby 15424 5018 � 00 0 00 • 0 0 0 0 0 0 0 0 0 0 0 o o 0 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 I Production 6-1/8"Hole TD at 15,438'MD/5,018'TVD ODST-45A 2015 RWO Program Outline–July 8th, 2015 5 GCAE1JJS Energy Alaska Rig Activity: Kill ODST-45A 1. Hold pre-job meeting a. Confirm handover form has been filled out,reviewed,signed,and received from Operations. b. Ensure adequate kill weight fluid is on location c. Discuss potential well control issues and ensure they are appropriately communicated to rig crew. d. RWO BOPE test cycle is 7 days as per AOGCC regulations. e. Any time in which we are shut in or not actively pulling or running tubular a TIW is required to be stabbed or blind rams are to be closed as necessary. 2. MIRU Nabors 19AC over ODST-45A 3. Lubricate and bleed the 2-7/8"x 7-5/8"IA as required. 4. ND production tree with the following well control barriers in place a. 2-7/8"Tubing: i. Closed TRSSSV pressure test to well pressure from below. ii. BPV b. 2-7/8"x 7-5/8"Annulus: i. Pressure tested tubing hanger pack-off to 5000 psi. 5. Install test dart,NU BOPE&Test 250 psi low/4 si high according to the test pressures outlined in the AOGCC Permit to Drill. 35-tro�+s a. Install 2-7/8"x 5"VBR in lower BOPE ram body. b. Notify the AOGCC Field Representative 48 hours prior to the BOPE Test. 6. Retrieve the test dart and BPV. 7. Bullhead 350 bbls of seawater @ 6 bpm down the tubing. a. This volume represents 150%of the tubing capacity,the IA capacity below the packer,and the 7- 5/8"casing capacity to the 4-1/2"liner top. b. All fluids injected into the well should be filtered treated seawater with scale inhibitor. pp L 8. Monitor well for 30 min and ensure well is dead or on vacuum. Lubricate and bleed the IA as required. l�" is a. Bottom hole pressure model indicates an expected 7.3 ppg EMW. e Rig Activity: POOH with 2-7/8"ESP Completion 1. Hold pre-job meeting a. Weatherford Packer Hand should be on location one day prior to releasing ESP packer. b. Baker Fishing Hand should be on location one day prior to releasing ESP packer. c. Review CentriLift ODST-45A Installation Report. d. Ensure contingency fishing equipment is inventoried and accessible. e. Ensure safety valves with XO's to 2-7/8"tubing are operational and drifted. f. Any time in which we are shut in or not actively pulling or running tubular a TIW is required to be stabbed or blind rams are to be closed as necessary. g. Review NORM monitoring plan with HSE team. 2. Prep rig floor to pull 2-7/8"ESP completion. a. Ensure safety valves with.XO's to 7-71R"tubing are accessible and in the open position. b. Ensure ESP cable cutter is operational and accessible. c. Rig up Halliburton control line spooler post hanger pull. d. Count and maintain Cannon Clamps¬e location of each Cannon Clamp recovered on the tally. 3. Back out lock down screws(BOLDS)and unseat 3-1/2"tubing hanger with use of 4"drillpipe landing joint. 4. Release 2-7/8"x 7-5/8"ESP Feed-Thru packer with a straight pull. a. Packer Shear Release: 33,000 lbs. b. 80%Tensile Limit: 115,000 lbs for 2-7/8"6.5#L-80 IBT-M. ODST-45A 2015 RWO Program Outline—July 8th, 2015 6 GCAEL1JS Energy Alaska i. 165,000 lbs Tensile limit including top drive and block weight. ii. Contact Rig Superintendent if more than 80%is required. 5. Allow ESP packer elements to relax while RU tubing pulling equipment. a. Stroke ESP packer as required to accelerate process. Stroke ESP packer slowly so as to reduce swab force. b. Keep hanger below bottom ram on BOP. 6. Monitor well for 30 min and ensure well is dead or on vacuum. a. If well is flowing bullhead 150%of the IA capacity to 7-5/8"shoe @ 6 bpm down the IA. 6._11""e/'-5 7. Pull hanger to floor and re-establish /4"cpntrolli.ne conneclion_to open the TRSSSV with 4.500 psi. 5 S 8. POOH and LD 2-7/8"ESP completion string as per Oooguruk specific Centrilift 2-7/8"ESP completion string pulling procedure. a. Maintain pressure on TRSSSV to keep it open until it is recovered. b. Inspect 2-7/8"tubing for scale or corrosion and report on WellView. c. Clean all completion equipment at the rig floor with absorbents and WD40. Do not wash down equipment or rig floor with water. d. Fill hole with 150%tubing displacement plus 5 bbl of seawater every half hour. e. If influx is observed stab floor safety valve,space out,close annular and bullhead 1.5 tubing volume to 7-5/8"shoe at 6 bpm. Shut down and monitor well for 30 min. If well continues to flow, continue to bullhead and contact Rig Superintendent to discuss increasing fluid weight. Once well is confirmed dead continue POOH. f. Have ESP cable cutter ready and prepare to cut cable and secure with cannon clamp and duct tape, allowing space for rams to close around tubing. 9. If junk is left in hole contact Rig Superintendent and discuss fishing options. 10. Review clamp band count and compare with original completion. a. Install BOPE junk screen,function rams, flush stack with BOPE flushing tool and retrieve junk screen. b. Discuss fishing options with Drilling Superintendent if necessary. 11. Function blind rams,Clean rig floor and prep to run ESP completion. a. Monitor hole during preparation. b. Continue filling hole with 5 bbl of seawater every half hour. RigActivity: Scraper Cleanout Run 3 P 1. Install 4"rams in lower BOPE ram body. Test 250 psi low/ Opsi high according to the test pressures outlined in the AOGCC Permit to Drill. 2. RIH with scraper,magnet,and mule shoe 100' MD below Baker FH packer setting depth(-8300' MD)on 4" DP and POOH. a. If unable to hold fluid column during RIH fill hole with 5 bbl of 10.1 Brine every half hour. b. Circ 150%DP capacity prior to POOH c. If unable to hold fluid column during POOH fill hole with 150%DP displacement plus 5 bbl of 10.1 ppg Brine every half hour. 3. Close blind ram a. Continue to fill hole with 5 bbl of 10.1 Brine every half hour as required. 4. Function blind rams,Clean rig floor and prep to pull FSV completion. c. Monitor hole during preparation. ODST-45A 2015 RWO Program Outline–July 8th, 2015 7 CAEL1JS Energy Alaska d. A scrapper/magnet run is not required on this well. 7.Z3ai Rig Activity: RIH with 2-7/8"Gas Lift&Packer Completion n4) P' 3 1. Install 2-7/8"x 5"VBR in lower BOPE ram body. Test 250 psi low/ 0 psi high according to the test pressures outlined in the AOGCC Permit to Drill. 2. Hold pre-job meeting a. Caelus Completion Supervisor is responsible for tally at rig site. The Tally is to include: i. Tubing measurement by joint(composite tubing tally is not acceptable) ii. Equipment type, Serial#,Length,OD,ID,Top and bottom connection. b. Caelus Company Man and Completion Supervisor to confirm jewelry installation and location with vender tally. c. CoMan to confirm jewelry installation and location with Caelus RWO Completion Supervisor and record in Wellview. d. Tally is to be emailed to Alex Vaughan once compiled for confirmation. e. Tally is to be confirmed by Nabors Driller during RIH. 3. Confirm zero pressure below blind ram and open ram a. Continue to fill hole with 5 bbl of 10.1 Brine every half hour. 4. PU&RIH up 2-7/8"tubing string as per tally. a. Continue to fill hole with 5 bbl of Brine every half hour. b. Circ/fill 150%tubing volume 1/3 (-4,000'MD)and 2/3 (-8,000' MD)into the way in the hole. ODST-45A 2015 RWO Program Outline—July 8th, 2015 8 êCAEUJS Ener y Alaska An outline of the completion equipment is as follows. This is intended to provide an understanding of the purpose of each piece of the equipment. It is provided as supplemental information along with the completion tally. GE 3-1/2"Tubing Hanger Halliburton TrSSSV • Install at 2,000' TVD. Schlumberger GLM#2 • Install 1 jt below TrSSSV. • Run with Shear valve pinned for 2500 psi. o 1"SDCK-2 Shear Valve,IA to Tubing shear. o 1"SBEK-2C Ported latch for shear valve. • Purpose: Freeze protection circulation point. • Requires: EUE XO pups. Halliburton X-Nipple • Install 1 jt below GLM#2. • Primary Purpose: XX Plug set location for freeze protection circulation. Schlumberger GLM#1 • Install 1 joint above Baker FH packer. • Run with dummy valve installed. o 1"E Dummy. o 1"BK-5 Latch. • Purpose: Lift gas injection location. Baker FH packer • Install at 8,208' MD, 100' MD above 7"X 9-5/8"tie-back slips. ✓ • Pin to 20 klbs shear release. Baker sliding sleeve • Install 1 joint below the FH packer. • Primary Purpose: Allows gas to be bleed from IA on a future RWO. Halliburton XN-Nipple • Install one joint below sliding sleeve. • Run with RHC installed. • Primary Purpose:Required to set packer and is a pressure test location for the 2-7/8"tubing ID with a XXN Plug. ODST-45A 2015 RWO Program Outline—July 8th, 2015 9 CAELLS Energy Alaska Halliburton Self Aligning Mule Shoe • Install inside 4-1/2"x 7"LHP. • Ensure the 2-7/8"IBT-M Box X 4-3/4 8UN-2B Pin XO is built with no more no more than a 30°bevel inside looking up to allow for easy tool passage.No internal square shoulders allowed. Rig Activity: Land 2-7/8"Tubing String 1. RIH with 2-7/8"completion to 20' above 4-1/2"x 7"LHP tie back extension. 2. Record PU and SO weights. 3. Locate the top of the liner,fully insert Self Aligning Mule Shoe assembly into tie-back extension, slack off 40,000 lbs,if achievable,and mark the pipe. 4. Pull out of LHP tie-back extension and space out. a. Space-out-pups should be below Tubing Hanger 3-1/2"IBT-M x 2-7/8"IBT-M XO. b. Confirm FH Packer is 100'MD above 7"X 9-5/8"tie-back slips. 5. With 3-1/2"landing joint and FOSV,land tubing hanger while maintaining 4,500 psi on TrSSSV control line. Once landed,RILDS for Tubing Hanger. Test both the upper and lower Tubing Hanger body seals to 5000psi. a. As long as Self Aligning Mule Shoe assembly is confirmed to be at least 10' into tie-back extension it is not necessary to stack weight on assembly as it is pressure neutral. 6. Hold pre-job meeting a. Double check that the RHC plug was installed in the XN-Nipple. b. Review freeze protection procedures c. Review packer setting procedures 7. Drop ball and rod and displace down to RHC body. a. Run ball and rod on slickline if fluid level of tubing is not at surface. 8. Fill tubing with 10.1 ppg Brine and set Baker FH packer per Baker rep instructions a. Increase tubing pressure to a minimum of 1,000 psi to initiate setting of the FH packer.The hydrostatic pressure of the well will complete the 2600 psi pressure required to set the packer with a 10.1 ppg fluid. 9. Pressure test the tubing and IA to 3 500 psi for 30 min a. A DCR-1 shear out valve pinned to 2500 psi is installed in the upper GLM and requires that pressure testing operations are executed in the following order: • Pressure test the tubing to 3,500 psi for 30 min. • Bleed tubing pressure down to 2,500 psi • Pressure Test 2-7/8"x 7"annulus to 3,500 psi for 30 min. • Bleed tubing pressure down to zero. This will result in shearing the shear-out valve • Pump fluid both directions through the shear-out valve to confirm communication. 10. Install TWC 11. ND BOP's and NU Tree with the following well control barriers in place a. 2-7/8"Tubing: t/ i. Closed TrSSSV ii. TWC b. 2-7/8"x 7"Annulus: i. Pressure tested 2-7/8"x 7"annulus ii. Pressure tested tubing hanger packoff 12. Test X-mas Tree void to 5,000 psi. 13. Remove TWC with rod. 14. Hold post-job meeting ODST-45A 2015 RWO Program Outline—July 8th, 2015 10 GCAEUJS E:nei i Alaska a. Ensure proper handover of well from Drilling to Operations. b. Confirm Well Handover Document has been filled out and received by Operations. 15. RDMO Nabors 19AC a. Baker to supply CoMan, Completions Supervisor, and Alex Vaughan with a digital copy of Tallys, Pressure tests,and Post job report prior to leaving location. b. Halliburton to supply CoMan, Completions Supervisor and Alex Vaughan with a digital copy of post job report, SAMS sheet and/or strap sheets prior to leaving location. c. Schlumberger to supply CoMan,Completions Supervisor and Alex Vaughan with a digital record of strapped GLM's and GLV model's installed in well. Post Rig: Slickline 1. RU slickline on ODST-45a. 2. Hold pre-job meeting. 3. Hold open TrSSSV. 4. Circulate diesel down 2-7/8"x 7"annulus through shearout valve and up 2-7/8"tubing to surface. 5. Pull Ball and Rod. 6. Pull Dummy Valve from lower GLM(GLM#2)and install 5/16"OV. 7. Pull Shearout Valve from upper GLM(GLM#1)and install Dummy Valve. 8. Pull RHC. 9. Function test TrSSSV. 10. RD slickline unit. ODST-45A 2015 RWO Program Outline—July 8th, 2015 11 STATE OF ALASKA ALA.OIL AND GAS CONSERVATION COMMI ION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon H Plug Perforations ❑ Fracture Stimulate i Pull Tubing ✓j Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ Brforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Swap ESP to Gas Lift❑✓ 2.Operator Caelus Natural Resources Alaska,LLC 4.Well Class Before Work: 5.Permit to Drill Number: Name: Development❑✓ Exploratory❑ 209-079 3.Address: 3700 Centerpoint Drive Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-703-20577-01-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 355036 ODST-45a RFCEIVED 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Oooguruk-Torok Oil Pool MAY 12 7111(3 11.Present Well Condition Summary: Total Depth measured 15,429 feet Plugs measured N/A feet OG CC true vertical 5,018 feet Junk measured N/A feet Effective Depth measured 15,424 feet Packer measured See attachment,pg.3 feet true vertical 5,018 feet true vertical See attachment,pg.3 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 153' 153' N/A N/A Surface 4,931' 10-3/4" 4,973' 3,438' 5,210 psi 2,470 psi Intermediate 9,994' 7-5/8" 11,377' 5,174' 6,890 psi 4,790 psi Production Liner 5,533' 4-1/2" 15,424' 5,018''' j, 8,430 psi 7,500 psi Perforation depth Measured depth See attachment,pg.2 feetcl�N�EF) i F �UT True Vertical depth See attachment,pg.2 feet Tubing(size,grade,measured and true vertical depth) 2-7/8",6.40# L-80 IBT-M 9,906'MD 4,956'TVD Packers and SSSV(type,measured and true vertical depth) See attachment,pg.3 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 Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 14.Attachments(required per 20 MC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑ Exploratory Development O Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑✓ Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data H GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 315-444 - Contact Rami Jasser Email rami.iasser(a�caelusenergy.com Printed Name Rami Jasser Title Senior Staff Completions Engineer Signature ,/ /r%" Phone 907-343-2182 Date S-11011(0 2 Form 10-404 Revised 5/20 7:z7 �V 7' !4 S 1^V MAY 1 3 2016 Submit Original Only RBDMS l • • Attachment Pg. 2 AOGCC Form 10-404 Sundry Report Box 11 - Perforation Locations MaltetWORMIS9616641k1MM ',Mel Well:ODST-45a Top(MD) Bottom(MD) Top(TVD) Bottom(TVD) 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 11,581 11,586 5,170 5,170 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 11,786 11,791 5,169 5,169 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 11,991 11,996 5,171 5,171 4-/z", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 12,196 12,200 5,171 5,171 4-/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 12,402 12,406 5,159 5,159 4-/z", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 12,688 12,692 5,132 5,132 4-/z", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,009 13,014 5,101 5,101 4-14", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,213 13,217 5,083 5,083 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,417 13,422 5,066 5,065 4-%", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,584 13,588 5,052 5,051 4-/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,787 13,792 5,032 5,032 4-/z", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 13,989 13,994 5,018 5,018 4-/z", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 14,195 14,200 5,015 5,015 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 14,396 14,401 5,012 5,011 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 14,600 14,604 5,004 5,004 4-'/=", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 14,806 14,810 5,001 5,001 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 15,008 15,013 5,001 5,001 4-/�", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 15,210 15,215 5,008 5,008 4-1/2", 12.60#, L-80 Liner -Pup joints ported with 6-1/2" holes 15,417 15,422 5,018 5,008 Eccentric Shoe 15,422 15,424 5,018 5,018 • • Attachment Pg. 3 `3f:3H: h'" ,"" 'i':"kHEYYz'4.<Akv=NG.. k88CY'Yk 5:'x£"effi:£kms° %f*A8188k 8181'�R�.s* AOGCC Form 10-404 8884 88184 tlM"YtYC< '.A,P44s.,d,,,,..':sd:„{,g2 �.4:R':`fR. 44941 b2=a.::!Ytt?VL N29kP iS. Sundry Report Box 11 - Packer Locations Well: ODST-45a MD TVD HES "NE" TRSV 2,051 2,018 BHI 2-7/8" FL Retrievable Packer 9,720 4,899 WFT Liner Top Packer 9,907 4,956 WFT Genesis Water-Based Swellable Packer 11,401 5,173 • Alaska Operations Summary Report- State Well Name: ODST-45A CG AEU Well Name: ODST-45A Contractor: Rig Number: Job Category: WORKOVER Start Date: 4/17/2016 End Date: Start Depth Foot/Meters Dens Last Start Date End Date (ftKB) (ft) Mud(Ib/gal) Summary 4/17/2016 4/18/2016 15,429.0 8.60 ***Rig accepted on ODST-45A RWO©00:00 on 17 April 2016.*** RDMO ODSN10i RWO. MIRU on ODST-45A RWO.Rig crew R/U per Post Rig Move Checklist. ***Notified AOGCC at 07:04 on 17 April of upcoming BOPE test for 12:00 on 19 April.*** 4/18/2016 4/19/2016 15,429.0 8.55 Complete MIRU on ODST-45A RWO per Post Rig Move Checklist.R/U VG Lubricator&Swab Valve.Vetco Gray pull BPV.Attempt to circulate down Tbg&IA w/o success.Bleed off all pressure&VG set BPV.Prep rig for suspended operations for coil work on ODST-45A.RDMO sub structure f/ODST-45Ato R/U Slb Coil.MIRU Slb Coil Unit. 4/19/2016 4/20/2016 15,429.0 8 55 Finish R/U Sib Coil Unit.Tag Ice&jet @ 625'ctm.Break through 8 bridges. RIH U 4000'.Pump 2 coil tbg volumes.(88b1s) POH U 2,635'.Little Red pump diesel down IA U 2,625'.POH w/coil to surface.Begin Pump 25 bbls of hot diesel down Tbg for freeze protect.Rig crew prep rig to Co" 1 4IRU sub module w/pit module on ODST-45A RWO. 4/20/2016 4/21/2016 15,429.0 8.55 Slb Coil Unit&Little Red finish freeze protect per Well Works.R/D Slb Coil Unit&Little Red.Set BPV via Vetco Gray w/lubricator.MIRU Sub Module U Pit Module on ODST-45A RWO.Rig crew R/U per Post Rig Move Checklist.Pull BPV via Vetco Gray w/lubricator.Bullhead 350 bbls 8.6 ppg filtered/treated SW down Tbg. Monitor well 30 Min.Circulate 115 bbls 8.6 ppg filtered/treated SW down Tbg,taking diesel returns up IA to Ops Flow back Tank.Monitor well 30 Min.Final pressures;Tbg 0 PSI,IA 0 PSI.Well on vacuum.Install BPV via Vetco Gray.Begin N/D Tree wI Vetco Gray Reps. 4/21/2016 4/22/2016 15,429.0 8.60 Vetco Gray N/D tree.Install VG test dart.N/U BOP stack&riser. N/U choke&kill lines. P/U& R/U test equipment. Test BOPE per AOGCC PTD: *Test upper and lower VBR w/2 7/8"&4"test joints to 250/4500. *Test upper and lower IBOP valves to 250 psi low/4500 psi high. *Test annular w/4"test joint to 250 psi low/2500 psi high. *Test all floor valves to 250 psi low/4500 psi high. *Test 15 choke manifold valves to 250 psi low/4500 psi high. *All tests charted and all tests held for 5 min. *All tests performed with 8.6 ppg treated/filtered seawater. *Initial system psi:3000; 1900 after closure;200 psi=26 sec,full pressure 132 sec. ***Notified AOGCC at 07:04 on 17 April of upcoming BOPE test for 12:00 on 19 April.*** ***AOGCC Rep.Brian Bixby witnessed test @ 12:00 on 21 April.*** R/D&L/D BOPE test equipment. R/U Ops line to IA&bleed off gas to Flowback Tank.Vetco Gray remove BPV&Test Dart.R/U GBR 2-7/8"equipment,Centrilift&HES spoolers. Install 4" DP Ldg Jt to pull Hanger.BOLDS.Pull hanger free from Tubing Spool with 180K(73K above completion string weight.)Cycled 20x with 160K PUW(80%)of 2-7/8"tubing tensile limit.Called NAD and Caelus Supt for approval to pull 90%of tubing tensile.Cycled 139x with 175k PUW (90%)of 2-7/8"tubing tensile.Pumped SW down Tbg @ 6 bpm w/returns over intermittent cycles.Sheared packer free with Cycle#160 at 115K on the upstroke.Allow packer elements to relax after shearing packer free with 160K PU/SO cycles. Monitor well 30 minutes.R/U GBR 2 7/8"Tubing Pulling Tools. R/U ESP Cable&Control lines to spools.Pump 4.500 psi to lock open SCSSV&Packer Vent Valve Hyd Lines.POH w/2-7/8"6.5 lb L-80 IBT-M Tbg w/ESP Completion @—90'. 4/22/2016 4/23/2016 15,429.0 8.60 POH w/ 2-7/8"Tbg w/ESP Completion f/9,486'U surface. 4/23/2016 4/24/2016 15,438.0 0.00 8.60 Centrilift L/D ESP Pump&Motor w/performing diagnostics. R/D GBR Tbg Running Tools,& Control Cables.Flush BOP stack w/junk basket installed. Install 6.375"wear bushing.P/U 4"DP from pipe shed&rack back 18 stands.P/U&M/U BUT 6.0"Magnet Cleanout BHA per Baker Rep.TIH w/6"Mag Cleanout BHA w/PIU 254 jts 4"DP from pipe shed.TIH w/18 stds 4"DP from Derrick U 9,891'.Establish circulation with 6 bpm.Tag TOL @ 9891'w/5K Weight(105K). TOH w/6"Mag Cleanout BHA#1 f/9,891't/40'. L/D 6"Mag Cleanout BHA#1 f/40'U surface. 4/24/2016 4/25/2016 15,438.0 0.00 8.60 R/U HES Spools&GBR 2 7/8"Tbg Running Equipment.Remove Wear Bushing w/Vetco Gray. RIH w/2 7/8"6.4 lb L-80 IBT-M Gas Lift Completion U 9,915'.Locate TOL @ 9,891'.(Jt#306) Insert Self Adjust Mule Shoe into Tie Back w/15K down x 2.Prepare to Space Out. Page 1/2 Report Printed: 5/9/2016 • • • • Operations Summary Report - State Well Name: ODST-45A CE CAEUJS Energy Alaska Start Depth FootMeters Dens Last Start Date End Date (ftKB) (ft) Mud(lb/gal) Summary 4/25/2016 4/26/2016 15,438.0 0.00 8.60 Perform Space out w/6.5'above No Go.RIH w/two 3 1/2"jts.M/U Tubing Hanger w/Pup.Land Tubing Hanger w/84K.RILDS.Test hanger seals to 5,000 PSI for 5 min.Good test.Drop 1-5/16" ball and rod.Pressure test tubing to 3,500 PSI for 30 min&chart same.Good test.Bleed tubing down to 2,700 PSI.Pressure test IA to 3500 PSI for 30 min&chart same.Good test.Bleed off V tubing to shear DCK-2 valve.Pump 3 bbls each direction to verify good shear.LID landing joint. \ Vetco Gray Set TWC.Pressure test from below to 2,500 PSI for 5 min.Good test.R/D GBR ' casing equipment,HES spoolers&sheaves. N/D BOP stack.Terminate TRSSSV control lines& lock open.Terminate ROC gauge i-wire.N/U Tree.Pressure test tree void to 5,000 PSI for 10 kt‘,\ min.R/U lubricator&pull TWC.R/U Little Red to IA&Tubing to Ops flow back tank.Pump 115 bbls diesel freeze protect down IA.Allow diesel to U-Tube.Clean well bay,rig down lines.Set Vetco Gray BPV w/lubricator.R/D lubricator.Secure well,all valves closed.Finish Pre-Rig Move checklist.RDMO ODSN-45A RWO.MIRU on ODSK-41 RWO. ***Release from ODST-45A RWO at 23:59 on 25 April 2016.*** ***Notified AOGCC at 0853 hrs on 25 April of upcoming BOPE testl for ODST-41 RWO.*** ***AOGCC Rep.Jeff Jones waived witness of test @ 1707 hrs on 25 April.*** 5/6/2016 5/7/2016 15,438.0 0.00 8.60 00:00 5/6/16-00:00 5/7/16 ***Vetco pulled TWC 5/4/16*** MIRU HES Slickline w/.125 wire. *Set 2-7/8"X-catcher in X-nipple @ 3,461'MD. *Unsuccessful attempt to Pull 1"DCK shear valve from GLM#3 @ 3,365'MD. 5/7/2016 5/8/2016 15,438.0 0.00 8.60 00:00 5/7/16-00:00 5/8/16 *Pulled 1"DCK shear valve from GLM#3 @ 3,365'MD.(3,343'SLM.) *Set 1"DGLV(BK)in GLM#3 @ 3,365'MD.(3,343'SLM.) *Pulled 2-7/8"X-catcher from X-nipple @ 3,461'MD.Catcher empty. *Pulled Ball&Rod from X-nipple @ 9,856'MD. *Pulled 1"DGLV(BK)from GLM#1 @ 9,491'MD. *Set 1"Orifice GLV(5/16",BK)in GLM#1 @ 9,491'MD. *Pulled 2-7/8"RHCM plug from X-nipple @ 9,856'MD. *RDMO HES Slickline.Complete well handover from Wells Group to Operations. Page 2/2 Report Printed: 5/9/2016 S 111 'ODST-45A Well Completion Schematic FINAL 5-9-2016 I No. Upper Completion Equipment MD(ft) TVD(ft) 1 16 A VetcoGray Tubing Hanger 34 34 4.: 1 ,Conductor B 2-7/8"6.40#L-801ST-MTubing C 2-7/8"HES"NE"TRSV w/2.313"Packing Bore 2051 2018 2,.'' G D 2-7/8"6.40#L-80 IBT-M Tubing(2 Joints) • E 2-7/8"x 1"SLB G LM#3 w/15'Pup Top&Bottom 3365 2941 F 2-7/8"6.40#L-80IBT-MTubing • • EGLM#3 G HES"X"Nipple ri4(2.313"ID)2-7/8"w/15'Pup Top&Bottom 3461 2982 H 2-7/8"6.40#L-80IBT-MTubing DV I 2-7/8"x 1"SLB GLM#2 w/15'Pup Top&Bottom 6128 3792 lxl G J 2-7/8"6.408L-80IBT-M Tubing(2 Joints) • K HES"X"Nipple#3(2.313"ID)2-7/8"w/15'Pup Top&Bottom 6222 3820 _ L 2-7/8"6.40#L-801BT-MTubing M 2-7/8"x 1"SLB GLM#1 w/15'Pup Top&Bottom 9491 4825 A , N 2-7/8"6.40#L-80 IBT-MTubing(2 Joints) 0 HES"X"Nipple#2(2.313"ID)2-7/8"w/15'Pup Top&Bottom 9587 4856 Surface Casing P 2-7/8"6.40#L-80 IBT-M Tubing(1 Joints) 10-3/4"45.5#L-80 O HES 2-7/8"ROC gauge with I-wire to surface w/15'Pup Top&Bottom 9650 4876 BTC R 2-7/8"6.40#L-80 IBT-MTubing(1 Joints) @ 4,973' MD/ S Baker Hughes 2-7/8"x 7-5/8"FHL Retrievable Packer 9720 4899 T 2-7/8"6.40#L-80 IBT-MTubing(2 Joints) 3,438'TVD U 2-7/8"HES Sliding Sleeve w/'X'Nipple Profile 2.313"I.D.Run in Closed 9790 4920 (Sleeve Shifts Down to Open) V 2-7/8"6.40#L-80 IBT-M Tubing W HES"X"Nipple#1(2.313"ID)2-7/8"w/RHC Plug+15'Pup Top&Bottom 9856 4940 X 2-7/8"6.40#L-80 IBT-MTubing E R Y HES 5.25"Auto Entry Mule 'e 9902 4954 End of Assembly 9906 4956 No. Lower Completion Equipment MD(ft) TVD(ft) 23 WFT 5.75"ID EBR Tie Back Sleeve 15ft 9891 4951 WFT"TSP"Liner Top Pkr w/Hold Down Slips 5-1/2 20#x 7-5/829.70 w/yam Top 9907 4956 24 HT Box Down WFT"PHR"Rotating HydSet Liner Hanger 5-1/220#x7-5/829.70#w/5-1/2yam 9910 4957 25 Top HT Pin x Pin XO w/5-1/2 Vam Top HT Box x 4-1/2 Hydril 521 Pin J® WFT 4-1/2 12.60#x 5.75od x 15 Ft"Genesis"Water-Based Swellable Packer w/ 11401 5173 TTri O 26 4-1/2 Hydril 521 Box x Pin 27 4-1/212.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 11581 5170 28 4-1/212.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 11786 5169 -I I © 29 4-1/212.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 11991 5171 30 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 12196 5171 31 4-1/212.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 12402 5159 g MI O 32 4-1/212.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 12688 5132 33 4-1/212.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13009 5101 000 0 34 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 13213 5083 35 4-1/212.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13417 5066 COia 36 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 13584 5052 37 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 13787 5032 38 4-1/212.60 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13989 5018 39 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 14195 5015 Intermediate 40 4-1/212.60L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 14396 5012 Casing 41 4-1/212.60L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 14600 5004 O•T� �� 7-5/8"29.7#L- 42 4-1/212.60 L-80 Hydril Pupjt Oft(Ported w/61/2 holes) 14806 5001 .2 V it` 80 BTC-M 43 4-1/212.60 L-80 Hydril Pupjt Oft(Ported w/61/2 holes) 15008 5001 @ 11,377' MD/ 44 4-1/2 12.60 L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 15210 5008 5,174'TVD 45 4-1/212.60L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 15417 5018 46 Ray Oil Tool Silver Bullet Eccentric Float Shoe(PLUGGED)w/4-1/2 Hydril 521 15422 5018 1 \, End of Assembly 15424 5018 14LN -- -----V ------- 0 1 ° 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 ► 0 ° 0 o o o o o o o o o o o o o o o o �:/ o 0 0 o 0 0 0 0 o 0 o 0 o o 0 0 0 o I 1 Production 6-1/8"Hole TD at 15,429'MD/5,018'TVD 0 • Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. fa 07_ 0 7 v Well History File Identifier Organizing (done) Two -sided 1111111111111111111 ❑ Rescan Needed I 11111 RES AN DIGITAL DATA OVERSIZED (Scannable) Color Items: ❑ Diskettes, No. ❑ Maps: V eyscale Items: ❑Other, No/Type: v4ther Items Scannable by /Poor a Large Scanner L o GS Quality Originals: ` W OVERSIZED (Non - Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: BY: (Maria) Date: (0P-Tii , D— /s/ tYl Project Proofing III 11111111011H ! BY: i s Maria) Date: (o/ C 1 J 1_ /s/ MP Scanning Preparation 7 x 30 = 1 b + al = TOTAL PAGES a 3 D- r / (Count does not include cover sheet) yvt BY: r Maria Date: l0 r `5- `a - /s/ Production Scanning 1111111011111 Stage 1 Page Count from Scanned File: a 33 ( Count does include cov sheet) Page Count Matches Number in Scanning Preparation: YES NO BY: geft Date: to i ( S � l ( 9___. /s/ (VI p I Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. 11111111111111 ReScanned IIIIIIIIM 1111 BY: Maria Date: /s/ Comments about this file: Quality Checked I 10/6/2005 Well History File Cover Page.doc RECEIVED • • STATE OF ALASKA AL A OIL AND GAS CONSERVATION COMA ;ION AUG 0 9 2013 REPORT OF SUNDRY WELL OPERATIONS AO ACC 1.Operations Abandon Li Repair Well a Plug Perforations u Perforate u Other U Re-run Upper Completion Performed: Alter Casing ❑ Pull Tubing le Stimulate-Frac ❑ Waiver❑ Time Extension❑ G"Tt'` /FC-a Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Pioneer Natural Resources Alaska, Inc Development 0 Exploratory El 209-079 3.Address: 700 G Street,Suite 600 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99501 50-703-20577-01-00 • 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 355036 ODST-45A • 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Oooguruk-Torok Oil Pool • 11.Present Well Condition Summary: Total Depth measured 15,429 feet • Plugs measured N/A feet true vertical 5018 feet Junk measured N/A feet Effective Depth measured 15,422 feet Packer measured See Below feet true vertical 5018 feet true vertical feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 153' 153' N/A N/A Surface 4931' 10-3/4" 4973' 3438' 5210 psi 2470 psi Intermediate 9994' 7-5/8" 10,050' 5001' 6890 psi 4790 psi Production Liner 5533' 4-1/2" 9891'-15,424' 4951'-5018' 8430 psi 7500 psi Perforation depth Measured depth See Attachment,pg 2 feet True Vertical depth feet Tubing(size,grade,measured and true vertical depth) 2-7/8",6.4# L-80, IBT-M 9560'MD 4847'TVD 'NE TRSV @ 2049' Hydro II Pkr @ 2682' Liner Top Pkr© Water Swell Pkr @ Packers and SSSV(type,measured and true vertical depth) MD/2016'ND MD/2547'TVD 9907'MD/4956'TVD 11,400'MD/5173' ND 12.Stimulation or cement squeeze summary: Intervals treated(measured): ----, , Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 233 287 210 302 340 Subsequent to operation: 379 96 62 890 303 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run Exploratory Development Is - Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil U • Gas a WDSPL u GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 313-296 Prepared By:Kathy Campoamor,343-2183 Contact Alex Vaughan,343-2186 Email alex.yauphant 4--h--xd.com Printed Name Denn's Hartwig Title Sr.Staff Drilling Engineer r '- Signature ` A •..11E'&'7 Phone 343-2174 Date 8/9/2013 r IF T f3 Form 10-404 Revised 10/2012 -- d 'Z( Submit Original Only RBDMS AUG 2 0 20153 do • Pioneer Na.ural Resources Alaska Inc. ODST-45A Page 2 AOGCC Form 10-404, Report of Sundry Well Operations Present Well Condition Summary, Box 11 Perforation Depth (MD/TVD) - Attachment 4-'/2", 12.60#, L-80 Liner - Pup joints ported with 6-1/2" holes @ depths listed: MD ND 11,581' - 11,586' 5170' - 5170' 11,786' - 11,791' 5169' - 5169' 11,991' - 11,996' 5171' - 5171' 12,196' - 12,200' 5171' - 5171' 12,402' - 12,406' 5159' - 5159' 12,688' - 12,692' 5132' - 5132' 13,009' - 13,014' 5101' - 5101' 13,213' - 13,217' 5083' - 5083' 13,417' - 13,422' 5066' - 5065' 13,584' - 13,588' 5052' - 5051' 13,787' - 13,792' 5032' - 5032' 13,989' - 13,994' 5018' - 5018' 14,195' - 14,200' 5015' - 5015' 14,396' - 14,401' 5012' - 5011' 14,600' - 14,604' 5004' - 5004' 14,806' - 14,810' 5001' - 5001' 15,008' - 15,013' 5001' - 5001' 15,210' - 15,215' 5008' - 5008' 15,417' - 15,422' 5018' - 5018' PI 0 N E E R Operations Summary Report - Sta+^ Well Name: ODST-45A NATURAL RESOURCES Well Name: ODST-45A Contractor: NABORS ALASKA DRILLING Rig Number: 19AC Job Category: WORKOVER Start Date: 6/22/2013 End Date: Start Depth Foot/Meters Dens Last Start Date End Date (ftKB) (ft) Mud(Ib/gal) Summary 6/22/2013 6/23/2013 15,429.0 NU production tree,terminate control ESP cable and control lines.Test void and tree to 5000 psi on chart held 10 min--Good test. RD beaver slide,mud lines,and pipe skate.RD all berms, stairs,landings. Rig down lines in HUTZ,PUTZ and breezeway.Disconnect from high line power,and blow down all lines.Move pits and subs from ODSK-14 around the corner to the south well row. Note:AOGCC 48 hr notification of BOP test at 13:30 hrs 06/22/13. 6/23/2013 6/24/2013 15,429.0 6.80 Move pits and subs to ODST-45A,spot and level subs and pits,RU same.RD production choke, and blind flanges from well head.RU 1502 flanges on wellhead.RU secondary kill line to pump down the tubing with rig pumps.Bull head 530 bbls LVT(150%tubing and IA volume)down tubing.Pump down IA thru perfs in 2 7/8"tubing f/2,645' t/2,655'.Bled off tubing to close SSSV and monitor for 15 min--Static.Install BPV in tubing hanger,and test void to 5000 psi-- Unsuccessful.Bleed IA down from 350 psi to 25 psi.Test IA with P-6 to 3500 psi,held 30 min-- Unsuccessful,lost 350 psi in 30 min. 6/24/2013 6/25/2013 15,429.0 6.80 Bleed down IA from 3500 psi to 0 psi.Monitor IA and tubing pressure--both remained static. RU testing equipment and test void to 5000 psi held 10 min--Good test.Swap secondary kill line from tubing to IA.Fluid pack IA with 1.5 bbls diesel.ND production tree.NU drilling riser and BOP stack.Change out air boot on trip nipple and install same.Test BOPE per AOGCC PTA Test upper and lower VBR w/4"&2 7/8" test joint to 250/4500.Test upper and lower IBOP '6D valves to 250 psi low/4500 psi high.Test annular w/2 7/8" test joint to 250 psi low/2500 psi high. Test all floor valves to 250 psi low/4500 psi high.Test 14 choke manifold valves to 250 psi WS low/4500 psi high.All tests charted and all tests held for 5 min.AOGCC Bob Noble waived witness of test at 10:00 hrs on 06/22/2013. 6/25/2013 6/26/2013 15,429.0 6.80 Finish testing BOPE as per AOGCC PTD:Test blind rams to 250 psi low/4500 psi high.All tests charted and all tests held for 5 min.System Pressure 3000 psi,Pressure After Closer 2100 psi, Initial 200 psi attained 20 sec's,Full Pressure attained 1 min 38 sec's. AOGCC Bob Noble waived witness of test at 10:00 hrs on 06/22/2013.Pull blanking plug with 4"landing joint and pull BPV.Install 4"DP landing joint and pull 225k to unseat and.Pull 164k to release packer. RU spools for pulling control lines,and 2 7/8"tubing equipment. Bull head 1.5x tubing volume down tubing.Monitor well-initial IA pressure after bull heading 500 psi.Bleed IA to 0 psi.Tie-in to control lines and ESP cable,LD hanger and landing joint.POOH, laying down 2 7/8"ESP completion f/9,528' t/2 287'. 6/26/2013 6/27/2013 15,429.0 6.80 POOH,laying down 2 7/8"ESP completion f/2,287' t/surface.LD ESP pump and clear floor of same.Install junk screen,function all rams,and flush stack with diverter tool--No junk recovered.PU 7 5/8"casing scraper and TIH f/surface t/3,882'.Circulate 1.5x DP volume. POOH f/3,882' 1/surface--LD 7 5/8"scraper.Remove wear bushing.RU 3 1/2"tubing equipment.MU seal assembly and RIH with 3.5"L-80 9.2#TC-II tubing f/surface t/1,931'. 6/27/2013 6/28/2013 15,429.0 6.80 RIH with 3.5" tubing f/1,931' 1/9,860'. Wash down f/9,860' to No-Go with 25K at 9,916'. Close annular and test IA to 2500 psi,held 10 min--Good test.LD 2 joints f/9,916' 1/9,853' to space out--No pups needed.MU tubing hanger and landing joint.Land tubing at 9,915'.Run in LDS, test upper and lower hanger seals to 5000 psi,held 10 min on chart--Good test.Test IA to 3500 psi held 30 min on chart--Good test.RU slickline unit and test lubricator to 1000 psi--Good test.Run 2.813"XXN plug tag up at 32'&LD same.Land joint running tool ID=2.805". Run 2.80"GR tag up at 32'&LD same. Run 2.66"GR to 40'&LD same.Run 2.78"GR tag up at 32' &LD same.Pull 3 1/2"landing joint and inspect same—inside full of scale.Clean all scale out of landing joint running tool,and rabbit same with 2.80 GR--Good test.MU XXN plug on tool string below landing joint,run tool string in the hole below hanger,MU landing joint and lubricator.RIH and set 2.813"XXN plug at 3,368'. POOH and break off lubricator.Attempt to test tubing to 3500 psi—unsuccessful. Troubleshoot surface equipment- found landing joint was leaking at hanger. RD slickline unit. 6/28/2013 6/29/2013 15,429.0 6.80 RD slickline unit and LD all tools and lubricator. Install 4"DP test landing joint and test 3.5" tubing to 3500 psi held 30 min on chart--Good test.ND BOP stack and drilling riser. NU production tree and test tree and void to 5000 psi each held 10 min on chart--Good test.RD and prep rig for rig move.Rig maintenance while waiting on E-line to finish pre-rig work on ODSN-31.Move pits and subs from ODST-45A to ODSN-31. Rig Released at 24:00 hrs on 06/28/13. Notified AOGCC of 48 hr BOP Test at 09:00 hrs 06/28/13. Page 1/3 Report Printed: 8/8/2013 Pt0 N E E R Operations Summary Report - Sta+° Well Name: ODST-45A NATURAL RESOURCES Start Depth Foot/Meters Dens Last Start Date End Date (ftKB) (ft) Mud(Ib/gal) Summary 7/5/2013 7/6/2013 15,429.0 6.80 Rig accepted on ODST-45A at 00:00 hrs on 07/05/2013. Continue to load 310 jts of 2 7/8"IBT-M tubing into pipeshed.Strap and drift same.Install mousehole. LD 9-DC's and 114 jts of 4"DP from derrick utilizing mousehole. Rig crews assist in RU slickline&lay high pressure lines to assist Wells Group in pumping services on ODST-45A. Connect lines to IA on ODST-45A.Test lines to 2500 psi.Pump down 3 1/2"x 7"IA with 115 bbls LVT w/3 bpm,0 psi taking returns out to flowback tank.Observed returns with 100 bbls ' away. Continue misc rig maintenance while waiting on Wells Group to finish up on ODST-45A. *AOGCC was given notice of upcoming BOP test on 07/05/13 at 06:00 hrs* 7/6/2013 7/7/2013 15,429.0 6.80 Continue to wait on slickline to finish pre rig work on ODST-45A.Blow down high pressure line from rig to IA on ODST-45A and RD same.Prep rig for move from ODSN-31 to ODST-45A.RD beaver slide,mud lines and pipe skate.RD all berms,stairs and landings.RD HUTZ, PUTZ and breezeway.Slickline set XX plug in"X"nipple at3,328'.Slickline set dummy in GLM at 3,263'. Wells Group tested tubing to 2500 psi for 30 charted min.RD slickline off of ODST-45A.VG Rep A' set BPV,Move rig_from ODSN-31 to ODST-45A.RU over well.Check for IA pressure.On vac. %� ND tree.NU BOPE.RU to test BODE. Test BOPE per AOGCC Sundry Approval#313-296: 11/'n *Test upper and lower VBR w/3 1/2"&2 7/8" test joint to 250 psi low/4500 psi high. *Test annular w/2 7/8" test joint to 250 psi low/2500 psi high. *Test all floor valves to 250 psi low/4500 psi high. *Test 14 choke manifold valves to 250 psi low/4500 psi high. *All tests charted and all tests held for 5 min. *AOGCC Rep Jeff Turkington waived witness of test at 14:40 hrs on 07/06/2013. **2 failures:#1:Stem packing on Choke HCR-Rebuild,retest and passed.#2:Kill line 2" Demco.Changed out valve.Retest and passed.** 7/7/2013 7/8/2013 15,429.0 6.80 Complete test BOPE as per AOGCC Sundry Approval#313-296: Pull BPV.PU landing jt w/ TIW valve and pump-in sub. RU slickline with lubricator. RIH with slickline w/pressure equalizing U tool 113,289'.Attempt to equalize pressure. No pressure increase. POOH.Redress slickline tool. RIH with slickline w/pressure equalizing tool 113,289'. Pressure up to 300 psi. POOH.RIH and retrieve XX at 3,286'. Bullhead 130 bbls LVT through perfs. Flow back 18 BBLS to static. Monitor well for 1 hour. POOH w/XX plug to surface.RD slickline. BOLDS and Pull hanger to rig floor. .POOH with 3 1/2"tubing f/9,875' t/Surface. LD Seal Assy and Mule shoe. 7/8/2013 7/9/2013 15,429.0 6.80 RU to RIH w/2-7/8"ESP Completion Tubing. Unload pipe shed of 3 1/2"tubing.Pull ESP cable over sheave. RU 2-7/8"Handling equipment.MU ESP pump/motor assembly t/78'.Bakerlok centralizer below ESP. Install chemical line and I-Wire.RIH w/2-7/8"ESP Completion Tubing f/78' t/996'. Attempt to perform cable conductivity test. Unsuccessful/.POOH f/996' t/78'and troubleshoot ESP cable. Perform cable conductivity test on ESP Motor lead extension cable.No Detection.Motor Lead Extension cable bad. RD ESP Spooling cable trunk and secure trunk above windwalls on rigfloor. 7/9/2013 7/10/2013 15,429.0 6.80 Pull ESP cablle over sheave.Splice connector plug onto ESP cable. Replace Motor Lead Extension cable with new.Test downhole motor pumps.Test conductivity—Good Test.RIH w/2- 7/8"ESP Completion Tubing f/78' t/2,840'.Circulate 2 7/8"tubing volume x 1.5(18 bbls). Perform cable conductivity test every 1,000'. Installing Cannon clamps every other connection, as per Centrilift.Change out ESP cable Spool with new. RIH w/2-7/8"ESP Completion Tubing f/2,840' t/6,795'. Circulate.2 7/8"ESP Completion tubing volume x 1.5(60 bbls). RIH w/2-7/8" ESP Completion Tubing f/6,795' 116,922'.MU WFT Packer @ 6,891'. MU and test Gas Vent Valves. 7/10/2013 7/11/2013 15,429.0 6.80 Re-rig up line to new ESP cable and pull over sheave in derrick.Splice ESP Connectors.Feed thru Packer. RIH w/2-7/8"ESP Completion Tubing f/6,922' 117,525'. Perform cable conductivity test every 1,000'. Maintain 1000 psi on PW and 2500 psi on chemical fine.MU SSSV. RIH w/2-7/8"ESP Completion Tubing f/7,525' 119,517'. Maintaining 4500 psi on TRSSV, 1000 psi on PVV and 2500 psi on Chemical Line. MU VG Hanger @ 9,517'.Test PW, TRSSV&ESP cable.Land hanger at 9,560'. RILDS on wellhead.Test upper and lower hanger seals.Drop 1 5/16"ball&rod—Pressure up and set packer. Test and bleed tubing to shear DCR valve.Pump through DCR to verify shear. Bleed pressure off TRSSV and PW lines. Install TWC. Secure wellhead.ND BOPE. * 289 jnts ran, L-80,6.5#, BTC-M. * 157 cannon clamps,13 2-7/8"single clamps,2 3-1/2"single clamp. * Pump Motor Assy,9 cannon clamps,2 Lassale clamps, 1 splice clamp. Page 2/3 Report Printed: 8/8/2013 P I 0 N E E R Operations Summary Report - Sta*^ Well Name: ODST-45A NATURAL RESOURCES Start Depth Foot/Meters Dens Last Start Date End Date (ftKB) (ft) Mud(1b/gal) Summary 7/11/2013 7/12/2013 15,429.0 6.80 ND BOPE and riser.Perform control line wellhead feed through.Terminate lines.Re-Test control lines to 5000 psi.Good test. Install VG production tree.Test tree&voids to 5000 psi.Close TRSSV.Load 2 7/8"tubing in pipe shed for ODSN-16 RWO.RDMO. AOGCC was given notice of upcoming BOP test on ODSN-16 via AOGCC website at 13:20 hrs on 07/11/13 Rig released from ODST-45A at 24:00 hrs on 07/11/2013 Page 3/3 Report Printed: 8/8/2013 PIONEER Operations Summary Report - Sta+-' Well Name: ODST-45A , • NATURAL RESOURCES Well Name: Contractor: Rig Number: Job Category: Start Date: End Date: Start Depth Foot/Meters Dens Last Start Date End Date (ftKB) (ft) Mud(lb/gal) Summary 7/2/2013 7/3/2013 15,429.0 Finish testing BOP's. Once test is complete,stand down injector head,secure the well for the night.Send SLB crew to bed due to hours worked.Crew back on tour. PJSM with Expro, HES, SLB,and Operations.MU BHA,coil tubing connector 1.900"OD,double check valve 1.75"OD, (2)5'stinger 1.75"OD,down jet nozzle 1.75"OD.MU Lubricator to BOP stack and test same to 250 psi low/4000 psi high.TBG 160 psi, IA-6 psi,OA 48 psi.Test HES N2 lines to 4000 psi while RIH pumping.25 bpm 290 psi pumping diesel.Pumped 20 bbls while RIH t13,815'.Shut down pumping,continue t19,800'.Problem with the hydraulic system on level whined valve while e RIH.Notified SLB mechanics of issues and dispatched to location.At 9800 start pumping 1.5 bpm 3440 psi,WHP 150 psi,30 fUmin,return fluid rate ranged from 1 -2.4 bpm,doing weight (� checks every 200'.At 10,750'made a short trip t19,800'.TIH U12,227'where coil tubing lock up / started occurring.No solids seen during coil tubing clean.SLB mechanics on location to troubleshoot hydraulic system.POOH U11,500'and pumped 102 bbls,pumped a total of 560 bbls till midnight.Expro flow back tank started leaking at the 3"Cam Lok fitting.Circulation was cut short due to leak. 7/3/2013 7/4/2013 15,429.0 POOH at 70 ft/min,pumping.3 bpm 350 psi.SLB mechanics replaced the level whined hydraulic valve on the unit while TOOH.At 9,900' increased rates to.4 bpm 375 psi, 120 ft/min. Shut upper swab valve once pulled up in the lubricator. LD injector head and lubricator.Secure the well-SLB crew houred out. Crew back on tour at 14:00 hrs replace the packing on the injector head.MU BHA-CTC-double check valve-hydraulic disconnect w/.625"ball-circulation sub w/.500"ball-swirl jet nozzle.Drifted HDC w/.500"ball,verify the.625"ball on seat,and through the double check valve.Verify.500"ball on seat in the circulation sub. Coil tubing connector was pulled tested to 15k.MU lubricator and injection head to BOP's and test same to 250 psi low/4000 psi high.PJSM with Expro,HES,SLB,LRS,CH2M,and Operations.Perform a flow test from Expro to Operations disposal tanks. Pump at.6-1.5 bpm after 15 min,the test header pressured up to 110 psi.Shut down operations and troubleshoot the issue.Absorb was found in the drag valve in P 1.Retreive same. 7/4/2013 7/5/2013 15,429.0 Flow test Expro lines from their unit to tanks A.Good flow test.TIH while pumping.25 bpm 330 psi diesel w/NSX,LG 300Mscf/day @ 90 ft/min.Do weight checks every 2,000'.Once past GLM raised LG to 343 Mscf/d. Continue in the hole to 11,000'. Once at 11,000'start pumping N2 at 300scf/min,LG at 350 Mscf/d,WHP 276 psi,pumping at.5 bpm bringing the rate up slowly 1.5 bpm 1650 psi.The returns starting slowing down,brought pump rate to 1 bpm 1123 psi,PU U10,686'pick up weight 11,500 lbs. Trip back U11,000'.Everything leveled out at same rate. Once N2 was at the end of the coil,brought LG to 500 Mscf/d.N2 and pump rate still the same. Start cleaning the wellbore.Returns from the well 1 Mscf/d-fluid 1.2 bbls-WHP 253 psi At 40 ft/min doing weight checks every 200'. No solids in the returns. At 13,221'@ 09:00 hrs. A hydraulic leak was noticed at the injector head.Troubleshoot same.Tried POOH to liner top @ 9,800'. At 12,330'the leak was getting worse. Stop and get manlift to inspect same.Pop-off valve on the hydraulic pump on the injector head is popping each time.Cycled the system. Mechanic enroute to ODS for repairs.CBU 67 bbls,shut down N2 and bring LG up to 800 Mscf/d. Had 2300 gals on the truck when we started,used 1300 gals,leaving 1000 gals on the truck.Continue circulating at 1 bpm 1288 psi,LG 800 Mscf/d WHP 292 psi.Pull up the hole 50' every 30 min.Mechanic on location @ 16:00 hrs. At 12,044'@ 18:00 hrs. Increased LG to 1 million Mscf/d.Returns decreased slow back to 800 Mscf/d.Replaced K-strain hose on injector. POOH.Pumping 3/4 bpm at 300 psi. At 3,250' CTM shut down pumping LG on IA& bleed down to header pressure.Finish out of hole.Close in well.Start blowing down CT through Expro w/bottled N2.Final Tbg 302 psi IA 197 psi OA 51 psi.Total diesel pumped was 1455 bbls. Page 1/2 Report Printed: 8/7/2013 PI 0 N E E R Operations Summary Report - Sta*^ Well Name: ODST-45A NATURAL RESOURCES Start Depth Foot/Meters Dens Last Start Date End Date (ftKB) (ft) Mud(lb/gal) Summary 7/5/2013 7/6/2013 15,429.0 RD coil unit,N2 unit,LRS,and CH2M from well.Complete Post job walk through with all service companies and ACS.Operations completed walk through on the well.RU HES slickline unit.MU BHA,rope socket-5'roller stem 1.875"OD-knuckle joint-5'roller stem 1.875"OD-quick connect-1.75"OD oil jars-quick connect-long stroke spangs.Tool string BHA,quick connect- knuckle joint-2.75"OD centralizer-1.75"bailer.MU lubricator to the wellhead,test same to 1000 psi.TBG 386 psi,IA 0,OA 43 psi.TIH with tools above until deviation of the well is un- passable.At 10,100'. Work the wire to take a sample of the wellbore.Hole angle at this depth is 84 degrees.POOH to inspect tools.At surface with the tools,the bailer had fluid with no solids. Reconfigure tool string BHA-quick connect-knuckle joint-X line running tool-XXN plug.MU to well&PT lubricator.RIH to 3,306'SLM/3,329'MD.Attempt to set XXN-cannot. POOH. LD X-line running tool& XXN plug.MU 3-1/2 Braided line brush. MU to well&PT lubricator.RIH. Work braided line brush at 3,306'SLM/3,329'MD.POOH.LD braided line brush.MU 3-1/2 X-line RT w/2.813 XXN plug.MU to well&PT lubricator.RIH.Set XXN plug at 3,306'SLM/3,329'MD. Shear off.POOH.LD X-line RT.MU 3-1/2 OM-1 K w/ext.w/1-5/8 JDS pulling tool.MU to well &PT lubricator.RIH.Latch&jar free 1.5 x 1/4 screened orfice valve at 3,248'SLM/3,273'MD. POOH.Recovered 1.5 x 1/4 screened orfice valve.Redress KOT w/RK-1 RT w/1.5 DGLV.MU to well&PT lubricator.PJSM w/Nabors.RU line to IA&PT to 2500 psi.Pump 115 bbls LVT taking returns to test header. SD pumping. RD Nabors line to IA. 7/6/2013 7/7/2013 15,429.0 Reconfigure tool string BHA 3.5"OMIK kick over tool w/ext-RK1 running tool- 1.5 DMY valve. Locate in GLM at 3,248'SLM/3,273'MD,shear off.POOH to inspect tools.Once out of hole, DMY valve was in place in the GLM.PJSM with LRS-Operations-CH2M.RU lines to the tubing,pressure test same to 2500 psi for 30 min on a chart.RD LRS-CH2M-HES.PJSM with VG. MU lubricator,bleed tubing to 0 psi,set BPV and RD lubricator. 7/12/2013 7/13/2013 15,429.0 Well shut in.Nabors 19AC is moving.Standby f/drlg handover to OPs.PJSM w/HES slickline, and Nanuq crane operator.Spot equipment.Well handed over from OPs to Well Work at 17:00 hrs.RU to well. MU BHA#1 -Rope socket 1-1/2 od x 1-3/8 FN-Quick Connect 1-1/2 od x 1- 3/8 FN-Weight Bar 1-1/2 od x 1-3/8 FN 5 ft-Quick Connect x 2 1-1/2 od x 1-3/4 FN-Weight Bar 1-1/2 od x 1-3/8 FN 3 ft-Knuckle Jt 1-1/2 od x 1-3/8 FN-Weight Bar 1-1/2 od x 1-3/8 FN 5 ft -Quick Connect x 2 1-1/2 od x 1-3/8 FN-Oil Jar 1-1/2 od x 1-3/8 FN-Quick Connect x 2 Knuckle Jt 1-1/2 od x 1-3/8 FN-Long Stroke Spang Jar 1-1/2 od x 1-3/8 FN-Quick Connect x 2 1-1/2 od x 1-3/8 FN- Swedge 2.300 od x 1-3/8 FN-2""R"Pulling Tool 2.150 od x 1-3/8 FN.PU lubricator&MU to well.PT to 1000 psi.HES pressure 1/4 control line to 5000 psi to open TRSSSV& block in. Current TBG 0 psi-IA 0 psi-OA 40 psi.RIH.Tag& latch ball/rod bar @ 2,782'SLM. 2.313"X"nipple w/RHC-M plug @ 2,810'MD.POOH.LD swedge w/2'"R" pulling tool& ball/rod bar. MU BHA#2-same as above w/2-7/8 OM-1 KOT w/ext 2.250 od x 1-3/8 FN w/1-5/8"JDS"pulling tool 1.850 od x 1.188 FN.MU to well.PT lubricator.RIH.Latch 1.5 DCR SV @ 2,597'SLM/2,625'MD GLM.Jar free.POOH.LD 2-7/8 OM-1 KOT w/pulling tool &1.5 DCR SV.MU BHA#3-2-7/8 OM-1 KOT w/ext.w/ "RK-1"Running tool 1-3/4 od x 1.188 FN w/1.5 DGLV.MU to well.PT lubricator.RIH.Locate&latch @ 2,597'SLM/2625'MD GLM. Shear off,good set.POOH.LD 2-7/8 OM-1 KOT w/ext w/running tool,1.5 DGLV is set in GLM. MU BHA#4-2-7/8"GR"Pulling tool 2.250 od x 1-3/4 FN.MU to well.PT lubricator.RIH.Latch "RHC-M"plug @ 2,787'SLM/2,810'MD"X"nipple.Jar free.POOH.LD 2-7/8"GR"pulling tool w/2.313 "RHC-M"plug.RD HES slickline.Bleed off control line 5000 psi to 0 psi to close TRSSSV.Secure well.Turn well over to OPs. Page 2/2 Report Printed: 8/7/2013 1 P . . P 7�IONEER Current Schematic - State Well Name: ODST-45A NATURAL RESOURCES HORIZONTAL-Sidetrack 1,8/8/2013 7:51:29 PM Well Attributes Vertical schematic(actual) API/UWW Field Name Well Status Total Depth(ftKB) 50-703-20577-01-00 Oooguruk Unit DRILLED 15,429.0 Casing Strings Conductor,153.0ftKB Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ft. Set Depth...Grade Top Thread WVLen(I... 15-1I Conductor 16 14.670 42.7 153.0 153.0 H40 Welded 109.00 Casing Components ® Top(TVD) Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Corn 12-11 1-1 Conductor Shoe 42.7 42.7 16 14.670 i ! Surface,4,973.0ftKB Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ft_. Set Depth...Grade Top Thread "WULen(I... 1T-71 Surface 10 3/4 9.950 38.6 4,973.0 3,434.5 L-80 Buttress 45.50 Thread Casing Components • 3-1 Top(TVD) Item# Item Des Top(ftKB) (ftKB) _ OD(in) ID(in) Corn 1-1 2-1 VG Lndg Jt 38.6 38.6 10 3/4 9.950 2-2 Casing Joints 39.1 39.1 10 3/4 9.950 ■ 12-21 2-3 Tam Port Collar 1,020.0 1,017.9 10 3/4 9.950 ® 2-4 Casing Joints 1,023.0 1,020.8 10 3/4 9.950 574 2-5 Float Collar 4,890.9 3,408.3 10 3/4 9.950 I 2-6 Casing Joints 4,892.6 3,408.8 10 3/4 9.950 15-51 1 2-7 10 3/4"Surface Shoe 4,971.4 3,434.0 10 3/4 9.950 Intermediate,11,377.0ftKB 5-6 :i Casing Description •OD(in) ID(in) Top(ftKB) Set Depth(ft... Set Depth...Grade Top Thread W1./Len(I_. I Intermediate 7 5/8 6.875 34.1 11,377.0 5,403.3 L-80 BTC-M 29.70 �5-71 Casing Components I5-81 Top(TVD) •• 13-2I Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Com 15-91 I 3-1 Casing Joint in emergency 34.1 34.1 7 5/8 6.875 _ slips 15-101 11/ 3-2 Casing Joints 63.6 63.6 7 5/8 6.875 15-111 I 3-3 Super I I Float Collar 11,290.8 5,376.3 7 5/8 6.875 I 3-4 Casing Joints 11,291.8 5,376.6 7 5/8 6.875 15-121 3-5 7 5/8"Intermediate Shoe 11,374.0 5,402.3 7 5/8 6.875 WWT Reamer Float 15-131 I Shoe Production,15,424.0ftKB 15-141 Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ft_ Set Depth...Grade Top Thread VWLen(I... 15-151 I Production 41/2 3.920 9,890.9 15,424.0 5,018.2 L-80 Wedge 12.60 521 15-161 I Casing Components Top(TVD) 15-171 Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Corn WFT 16'PBR tie back 9,890.9 4,951.1 6.38 5.750 15-181 i sleeve 15-191 I 4-2 WFT TSP Liner top packer 9,907.2 4,956.1 6.65 4.750 4-3 WFT PHR Hyd Rotating hgr. 9,910.2 4,957.0 6.7 4.750 15-201 1 15-211 I 4-4 X-O 5.5"Vam Top HT box x 9,913.6 4,958.0 5 3/4 3.920 4.5"Hyd 521 pin 15-221 is 61 4-5 Casing Joints 9,915.1 4,958.5 4 1/2 3.920 • 15-231 I 4-6 Pup jt with Spiraglider 11,394.8 5,173.5 41/2 3.920 15 241 1 2 4 4-7 WFT Genesis 5.75"Water 11,400.5 5,173.4 4 1/2 3.920 swell packer 15-251 I 4-8 Pup jt with Spiraglider 11,417.7 5,173.2 4 1/2 3.920 4-9 Casing Joints 11,421.4 5,173.1 4 1/2 3.920 15-26 I 4-10 4.5"Pert Pup with 6-1/2" 11,581.5 5,169.9 4 1/2 3.920 15-271 I holes 4-11 Casing Joints 11,586.1 5,169.9 4 1/2 3.920 15-281 1 4-12 4.5"Perf Pup with 6-1/2" 11,786.3 5,169.2 4 1/2 3.920 15-291 holes 4-13 Casing Joints 11,791.0 5,169.1 4 1/2 3.920 15-301 NI 4-14 4.5"Perf Pup with 6-1/2" 11,991.3 5,170.7 4 1/2 3.920 15-311 I holes 4-15 Casing Joints 11,996.0 5,170.8 4 1/2 3.920 5-32 Page 1/3 Report Printed: 8/8/2013 __ . . PI 0 N E E R Current Schematic - State Well Name: ODST-45A NATURAL RESOURCES HORIZONTAL-Sidetrack 1,8/8/2013 7:51:31 PM Casing Components schematic(actual) Top(TVD) Vertical schem � � Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Com D 2-4 4-16 4.5"Perf Pup with 6-1/2" 12,195.6 5,170.9 4 1/2 3.920 holes • 12-51 4-17 Casing Joints 12,200.3 5,170.8 4 1/2 3.920 4-18 4.5"Perf Pup with 6-1/2" 12,401.6 5,159.1 4 1/2 3.920 • 12-6I holes 4-19 Casing Joints 12,406.2 5,158.6 4 1/2 3.920 It 12-71 4-20 4.5"Perf Pup with 6-1/2" 12,687.7 5,132.0 4 1/2 3.920 holes 15-321 13-21 4-21 Casing Joints 12,692.3 5,131.6 4 1/2 3.920 4-22 4.5"Perf Pup with 6-1/2" 13,008.8 5,101.5 4 1/2 3.920 15-331 holes 4-23 Casing Joints 13,013.5 5,101.1 4 1/2 3.920 15-341 1 4-24 4.5"Perf Pup with 6-1/2" 13,212.5 5,083.2 4 1/2 3.920 holes 15-351 4-25 Casing Joints 13,217.2 5,082.8 4 1/2 3.920 15-361 I 4-26 4.5"Perf Pup with 6-1/2" 13,417.0 5,065.5 4 1/2 3.920 holes 15-371 4-27 Casing Joints 13,421.6 5,065.1 4 1/2 3.920 4-28 4.5"Perf Pup with 6-1/2" 13,583.5 5,051.9 4 1/2 3.920 15-381 holes ■ 4-29 Casing Joints 13,588.2 5,051.5 4 1/2 3.920 I5 391 I 4-30 4.5"Perf Pup with 6-1/2" 13,787.0 5,031.8 4 1/2 3.920 holes 15-401 4-31 Casing Joints 13,791.6 5,031.3 4 1/2 3.920 5-41 1 4-32 4.5"Perf Pup with 6-1/2" 13,989.2 5,017.6 4 1/2 3.920 holes 5-42 4-33 Casing Joints 13,993.9 5,017.5 4 1/2 3.920 tiiil 4-34 4.5"Perf Pup with 6-1/2" 14,195.2 5,015.4 4 1/2 3.920 15-431 I holes 4-35 Casing Joints 14,199.8 5,015.4 4 1/2 3.920 5-44 <l 4-36 4.5"Perf Pup with 6-1/2" 14,396.5 5,011.8 4 1/2 3.920 holes 15-451 I 4-37 Casing Joints 14,401.1 5,011.6 4 1/2 3.920 4-38 4.5"Perf Pup with 6-1/2" 14,599.7 5,004.2 4 1/2 3.920 5-46 i holes on 4-39 Casing Joints 14,604.4 5,004.1 4 1/2 3.920 15-471 kill 4-40 4.5"Perf Pup with 6-1/2" 14,805.6 5,001.4 4 1/2 3.920 5-48 nii' holes 4-41 Casing Joints 14,810.3 5,001.5 4 1/2 3.920 J 4-42 4.5"Perf Pup with 6-1/2" 15,008.1 5,000.7 4 1/2 3.920 5-49 i111111 t111 holes 15-501 11111` 4-43 Casing Joints 15,012.8 5,000.7 4 1/2 3.920 4-44 4.5"Perf Pup with 6-1/2" 15,210.3 5,007.7 4 1/2 3.920 ® I111( holes 4-45 Casing Joints 15,215.0 5,007.9 4 1/2 3.920 ® 4-46 4.5"Perf Pup with 6-1/2" 15,417.4 5,017.9 4 1/2 3.920 holes ® irl 4-47 4.5"Production Liner Shoe 15,422.1 5,018.1 4 3/4 3.920 Ray Oil Tool Float shoe Plugged 5-54 Tubing Strings Tubing Description Stnng M.. ID(in) Top(ftKB) Set Depth(f... Set Dept...Wt(Iblft) Grade Top Thread ESP Completion 7/5/13 2 7/8 2.441 33.8 9,559.5 4,838.5 6.40 L-80 IBT-M Tubing Components Top(TVD) 4 1 Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Corn 1 4-2 5-1 VG Tubing Hanger 33.8 33.8 2 7/8' 2.441 AEI 1 5-2 Dbl Pin Pup Joint 35.4 35.4 3 1/2 2.992 f 4-3 5-3 3 1/2"B x 2 7/8"pin XO 40.1 40.1 2 7/8 2.441 f 5-4 Tubing 41.5 41.5 2 7/8 2.441 4-4 5-5 Tubing Pup Joint 2,033.8 2,002.7 2 7/8 2.441 II 5-6 "NE"TRSV"X"Profile 2,048.5 2,016.4 4.65 2.313 JI Il 14-51 Page 2/3 Report Printed: 8/8/2013 . 0 . , PIONEER Current Schematic - State Well Name: ODST-45A NATURAL RESOURCES HORIZONTAL-Sidetrack 1,8/8/2013 7:51:34 PM Tubing Components Vertical schematic(actual) Item# _ Item Des Top(ftKB Top(TVD) ) (ftK8) OD(in) ID(in) Corn 4-5 5-7 Tubing Pup Joint 2,053.2 2,020.8 2 7/8 2.441 5-8 Tubing 2,067.9 2,034.4 2 7/8 2.441 5-9 Tubing Pup Joint 2,603.5 2,490.9 2 7/8 2.441 14-61 5-10 GLM#1 w/DCR 2500 psi 2,616.0 2,500.3 5 1/2 2.365 i 1T-71 SV 14-81 5-11 Tubing Pup Joint 2,625.1 2,507.1 2 7/8 2.441 5-12 Tubing 2,636.9 2,515.8 2 7/8 2.441 �4 9I 5-13 Tubing Pup Joint 2,668.2 2,538.7 2 7/8 2.441 • 14-10 5-14 WFT Hydrow II Packer 2,682.2 2,548.8 6.67 2.992 f 14-111 5-15 Tubing Pup Joint 2,688.1 2,553.1 2 7/8 2.441 {4-121 5-16 Tubing 2,692.7 2,556.3 2 7/8 2.441 • 5-17 Tubing Pup Joint 2,724.7 2,578.7 2 7/8 2.441 f14-131 5-18 GLM#2 w/dummy 2,739.3 2,588.8 5 1/2 2.365 • 14-14 5-19 Tubing Pup Joint 2,748.9 2,595.2 2 7/8 2.441 f14-15 5-20 Tubing 2,763.6 2,604.9 2 7/8 2.441 5-21 Tubing Pup Joint 2,794.9 2,625.3 2 7/8 2.441 • 14-161 5-22 "X"Nipple#1 w/RHC-M 2,810.0 2,635.0 3.24 2.313 f14-171 5-23 Tubing Pup Joint 2,810.9 2,635.6 2 7/8 2.441 • 14.181 5-24 Tubing 2,825.6 2,645.0 2 7/8 2.441 1 14-191 5-25 Tubing Pup Joint 3,398.7 2,958.0 2 7/8 2.441 T 5 26 GLM#3 w/dummy 3,413.4 2,964.2 5 1/2 2.365 • 14-20 5-27 Tubing Pup Joint 3,422.9 2,968.2 2 7/8 2.441 f14-211 5-28 Tubing 3,437.5 2,974.3 2 7/8 2.441 • 14-221 5-29 Tubing Pup Joint 3,466.9 2,985.9 2 7/8 2.441 14-23 5-30 X Nipple#2 3,482.1 2,991.7 3.24 2.313 5 31 Tubing Pup Joint 3,483.0 2,992.1 2 7/8 2.441 • 14-241 5-32 Tubing 3,498.1 2,997.6 2 7/8 2.441 } 14-251 5-33 Tubing Pup Joint 9,291.3 4,754.8 2 7/8 2.441 • 14-261 5-34 GLM#4 w/1/4"OV 9,306.0 4,759.3 5 1/2 2.365 5-35 Tubing Pup Joint 9,315.2 4,762.1 2 7/8 2.441 14-271 5 36 Tubing 9,329.9 4,766.7 2 7/8 2.441 • 14-281 5-37 Tubing Pup Joint 9,361.2 4,776.4 2 7/8 2.441 1 14-291 5-38 X Nipple#(3) 9,373.1 4,780.1 3.24 2.313 5-39 Tubing Pup Joint 9,374.0 4,780.4 2 7/8 2.441 • 14-301 5-40 Tubing 9,385.7 4,784.0 2 7/8 2.441 f14-311 5-41 Tubing Pup Joint 9,481.4 4,813.8 2 7/8 2.441 • 14-32 5-42 Auto Diverter Valve 9,491.4 4,816.9 4.65 } 14-33 5-43 Tubing Pup Joint 9,494.7 4,818.0 2 7/8 2.441 5-44 Discharge guage 9,496.7 4,818.6 4 1/2 • 14-34 5-45 Tubing Pup Joint 9,499.3 4,819.4 2 7/8 2.441 5-46 Discharge Head 9,501.3 4,820.1 2 7/8 2.441 • 14-361 5-47 ESP-Pump 9,501.9 4,820.2 4 5-48 Adapter Kit 9,519.4 4,825.8 4 5-49 Gas separator 9,519.6 4,825.8 5.38 • -14-381 5-50 Upper Tandem Seal 9,525.1 4,827.6 5.13 5-51 Lower Tandem Seal 9,532.0 4,829.7 5.13 • 14-401 5-52 ESP-Motor 9,538.9 4,831.9 5.62 5-53 Motor guage 9,555.8 4,837.3 4 1/2 5-54 Centralizer 9,557.6 4,837.8 5.85 • 14-421 • 14-441 . 14-461 14-461 E 14-471 Page 3/3 Report Printed: 8/8/2013 v og • • ��' \ „� THE STATE �i1a is CZI and. Gas of AL KA Witt GOVERNOR SEAN PARNELL 333 West Seventh Avenue ALAS 11J' Anchorage, Alaska 99501 -3572 Main: 907.279.1433 Fax: 907.276.7542 Alex Vaughan SCANNED JUN 2 4 2013 Sr. Drilling Engineer Pioneer Natural Resources Alaska, Inc. O 700 G Street, Suite 600 a07- Anchorage, AK 99501 Re: Oooguruk Field, Torok Oil Pool, ODST -45A Sundry Number: 313 -296 Dear Mr. Vaughan: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this ?9day of June, 2013. Encl. yy • • STATE OF ALASKA �D �' ALASKA OIL AND GAS CONSERVATION COMMISSION DT,S` (or t l APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pod ❑ Repair Well IS Change Approved Program ❑ Suspend ❑ Plug Perforation$ ❑ Perforate ❑ Pull Tubing In Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other Rerun Upper Completion 17 2. Operator Name: 4. Current Well Gass: 5. Permit to Drill Number Pioneer Natural Resources Alaska, Inc. Exploratory ❑ Development p • 209 • 3. Address: 700 G Street, Suite 600 Stratigraphic ❑ Service ❑ 6. API Number Anchorage, AK 99501 50 - 703 - 20577 - 01 - 00. 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? WA ODST -45A Will planned perforations require a spacing exception? Yes ❑ No El 9. Property Designation (Lease Number): 10. Field /Pool(s): ADL 3550364 Oooguruk - Torok Oil Pool. 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 15,429' . 5018'. 15,422' 5018' N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 153' 153' N/A N/A Surface 4931' 10 -3/4" 4973' 3438' 5210 psi 2470 psi Intermediate 9994' 7 -5/8" 10,050' 5001' 6890 psi 4790 psi Production Liner 5533' 4 -1/2" 9891' - 15,424' 4951' - 5018' 8430 psi 7500 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attachment, pg. 2 " See Attachment, pg. 2 2 -7/8 ", 6.4# L -80, IBT -M 9560' Packers and SSSV Type: SSSV; Hydro II Pkr; Packers and SSSV MD (ft) and TVD (ft): 2025' MD/1994' TVD; 2611' MD/2495' TVD; Liner Top Pkr; Water Swell Pkr 9907' MD/4956' TVD; 11,400' MD/5173' TVD 12. Attachments: Description Summary of Proposal El t 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development El • Service ❑ 14. Estimated Date for 1/ 15. Well Status after proposed work: 6/1.812013 Commencing Operations: Oil in . Gas ❑ WDSPL ❑ Suspended 0 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Alex Vaughan, 343 - 2186 Email alex.vaughanc pxd.com Printed Name Alex Vaughan Title Sr. Drilling Engineer Prepared By Kathy Campoamor, 343 - 2183 Signature .— Phone Date 343 -2186 6/12/2013 COMMISSION USE ONLY Conditions of approval: Notify Com lion so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test Er Mechanical Integrity Test ❑ Location Clearance ❑ Other: ff L (5 rst; /30 r - -F RBDMS JUN 2 0 201 Spacing Exception Required? Yes ❑ No Subsequent Form Required: / 0 — yd' V APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: C1/4_,07/ Submit Form and Form 10 -403 (Revised 10/2012) Appro a ® f 2 onths from the date f prove!. Attachmen in Du licate 7 4-67/443 - y e p ��� 4) • , PIONEER ,, . 1 , { NATURAL RESOURCES ALASKA , :' Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, Alaska 99501 Tel: (907) 277 -2700 Fax: (907) 343 -2190 June 12 , 2013 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7 Avenue, Suite #100 Anchorage, AK 99501 RE: ODST -45A Sundry Application to Pull Existing Completion String, Coiled Tubing Clean -out, and Re -run Upper Completion REF: Permit To Drill # 209 -079 Pioneer Natural Resources, Alaska (PNRA) hereby submits an Application For Sundry request to perfrom the following workscope: • Pull the existing 2 -7/8" ESP completion string • Run a temporary 3 -1/2" coiled tubing clean -out string to support CTU work • Cleanout the ODST -45A lateral to point of refusal through the 3 -1/2" cleanout string with a CTU • Pull temporary 3 -1/2" coiled tubing clean -out string • Install replacement 2 -7/8" ESP completion See the proposed plan attachments and supporting documentation. Sincerely, j ✓ Alex Vaughan Senior Drilling Engineer Attachments: Form 10 -403 Supporting information cc: ODST -45A Well File Pioneer R ural Resources Alaska Inc. ODST -45A Page 2 AOGCC Form 10 -403, Application for Sundry Approvals Present Well Condition Summary, Box 11 Perforation Depth (MD/TVD) - Attachment 4 -V ", 12.60 #, L -80 Liner - Pup joints ported with 6 -1/2" holes @ depths listed: MD TVD 11,581' - 11,586' 5170' - 5170' 11,786' - 11,791' 5169' - 5169' 11,991' - 11,996' 5171' - 5171' 12,196' - 12,200' 5171' - 5171' 12,402' - 12,406' 5159' - 5159' 12,688' - 12,692' 5132' - 5132' 13,009' - 13,014' 5101' - 5101' 13,213' - 13,217' 5083' - 5083' 13,417' - 13,422' 5066' - 5065' 13,584' - 13,588' 5052' - 5051' 13,787' - 13,792' 5032' - 5032' 13,989' - 13,994' 5018' - 5018' 14,195' - 14,200' 5015' - 5015' 14,396' - 14,401' 5012' - 5011' 14,600' - 14,604' 5004' - 5004' 14,806' - 14,810' 5001' - 5001' 15,008' - 15,013' 5001' - 5001' 15,210' - 15,215' 5008' - 5008' 15,417' - 15,422' 5018' - 5018' • • PIONEER NATURAL RESOURCES ODST -45A RWO Program Current Completion: 2 -7/8" ESP String at 9,560' MD / 4,847' TVD Planned Coil Cleanout String: 9,891' MD / 4,951' TVD Planned 2 -7/8" ESP Completion: 9,560' MD / 4,847' TVD AFE# TBA, API # 50- 703 - 20577- 00 -00, PTD # 209 -079 AOGCC Sundry # TBA Prepared: Date: Alex Vaughan: Operations Drilling Engineer Reviewed: Date: Tim Crumrine: Sr. Staff Completions Engineer Reviewed: Date: Rob Tirpack: Drilling Superintendent Reviewed: Date: Gary Ross: Operations Superintendent Approved: Date: Vern Johnson: Alaska Drilling Manager ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 1 Program V1 June 12 2013 • • Pre -Riq Work to be completed prior to MIRU of Nabors 19AC: (The following workscope is to be completed as outlined in ODST -45A Well Work Procedure Pre RWO document as written by Tim Crumrine) • All fluids injected into the well should be LVT • Replace any live GLV's above the ESP packer with dummy GLV's • Pull dummy GLV in GLM below packer to provide flow path to remove IA gas below 2 -7/8" x 7 -5/8" Packer • 2 -7/8" x 7 -5/8" annulus a. Fluid pack the 2 -7/8" x 7 -5/8" annulus. Pump a minimum of a 150% annular volume b. Lubricate and bled out gas that migrates to surface in the annulus. c. Pressure test 2 -7/8" x 7 -5/8" annulus to 2,500 psi for 30 min • 2 -7/8" tubing a. Bullhead the 2 -7/8" tubing with a minimum of a 150% tubing volume b. Pressure test 2 -7/8" x 7 -5/8" tubing above the ESP packer to 3,500 psi for 30 min c. Close the TRSV and preform drawdown pressure test • Pressure test tubing hanger pack -off void in well head to 5,000 psi. • Set a BPV in the tubing hanger • Suspended ODST -45A with the following well control barriers: a. 2 -7/8" Tubing: i. Pressure tested tubing above the ESP packer .115 ii. Closed TRSV tested via drawdown test V ie. iii. BPV b. 2 -7/8" x 7 -5/8" Annulus: i. Pressure tested 2 -7/8" x 7 -5/8" ESP Packer (Closed PVV) ii. Pressure tested Tubing hanger packoff Pre -Riq Regulatory: 1. Provide 48 hour notice for the testing of the BOPE. 2. AOGCC mandates 1 week BOPE testing periods during RWO's. 3. Post ODST -45A Approved Sundry # TBA (see program attachments). 4. Read Approved Sundry and ensure that operations are in accordance. ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 2 Program V1 June 12 2013 • • Rig Activity: Kill ODST -45A Current ESP Completion 1. Hold pre job meeting a. Confirm Pre -Rig Workover Checklist has been filled out, reviewed, signed, and received from Operations b. Ensure proper handover of well from Operations c. Ensure adequate LVT is on location d. Discuss potential well control issues and ensure they are appropriately communicated to rig crew. 2. MIRU Nabors 19AC over ODST -45A 3. Lubricate and bleed the 2 -7/8" x 7 -5/8" IA as required 4. ND production tree with the following well control barriers in place a. 2 -7/8" Tubing: i. Pressure tested tubing above the ESP packer ii. Closed TRSV tested via drawdown test iii. BPV b. 2 -7/8" x 7 -5/8" Annulus: i. Tested 2 -7/8" x 7 -5/8" ESP Packer (Closed PVV) ii. Tested Tubing hanger packoff 5. NU BOPE, Install test dart & Test 250 psi low / 4500 psi high according to the test pressures outlined in the AOGCC Permit to Drill. a. Notify the AOGCC Field Representative 48 hours prior to the BOPE Test. b. 2 -7/8 ", 3 -1/2" & 4 -1/2" tubulars will be required 6. Retrieve the blanking plug and BPV 7. Bullhead thru TRSV 150% 2 -7/8" tubing volume -83 bbls of LVT a. All fluids injected into the well should be LVT. 8. Monitor well for 30 min and ensure well is dead or on vacuum. Lubricate and bleed the IA as required. ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 3 Program V1 June 12 2013 • • Rig Activity: POOH with Original 2 -7/8" ESP Completion 1. Hold pre job meeting a. Baker Fishing Hand should be on location one day prior to releasing ESP packer. b. Ensure contingency fishing equipment is inventoried and accessible. (See RWO SID). c. Ensure safety valves with XO's to 2 -7/8" tubing are operational and drifted. 2. Prep rig floor to pull 2 -7/8" ESP completion. a. Ensure safety valves with XO's to 2 -7/8" tubing are accessible and in the open position. b. Ensure ESP cable cutter is operational and accessible. c. RU HAL control line spooler. d. Identify a person to count and maintain Cannon Clamps. Note location of each Cannon Clamp recovered on the tally. e. Inspect 2 -7/8" tubing for scale or corrosion and report on WellView. f. Review NORM monitoring plan with HSE. 3. BOLDS and unseat 3 -1/2" tubing hanger 4. Release 2 -7/8" x 7 -5/8" ESP packer with a straight pull (See RWO SID). a. Anticipated PU String Hook Weight - Above Packer: TBA lbs b. Packer Shear Release: 33,000 lbs c. Anticipated Surface Overpull for Packer Shear Release: TBA lbs d. Anticipated Hook weight for Shear Release: TBA lbs e. Anticipated Hook Weight - Full String after packer release: TBA lbs f. Stretch: TBA ft g. 80% Tensile Limit: 165,000 lbs (See RWO SID) i. 165,000 lbs includes top drive and block weight ii. Contact Rig Superintendent if more than 80% is required 5. Allow ESP packer elements to relax while RU tubing pulling equipment. a. Stroke ESP packer as required to accelerate process. 6. Close annular and bullhead 150% 2 -7/8" x 7 -5/8" annulus volume -543 bbls of LVT 7. Monitor well for 30 min and ensure well is dead or on vacuum. 8. Pull hanger to floor and reestablish %" control line connection to open the TRSV with 4,500 psi 9. POOH and LD 2 -7/8" ESP completion string as per Oooguruk specific Centrilift 2 -7/8" ESP completion string pulling procedure. (See RWO SID) a. Maintain pressure on TRSV to keep it open until it is recovered. b. Clean all completion equipment at the rig floor with absorbs and WD40. Do not use water. c. Fill hole with 150% tubing displacement plus 5 bbl of LVT every half hour. d. If influx is observed stab FOSV, space out, close annular and bullhead 1.5 tubing volume to 7 -5/8" shoe at 6 bpm. Shut down and monitor well for 30 min. If well continues to flow continue to bullhead and contact Rig Superintendent to discuss increasing fluid weight. Once well is confirmed dead continue POOH. e. If junk is left in hole contact Rig Superintendent and discuss fishing options. ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 4 Program V1 June 12 2013 a • 10. Review clamp band count and compare with original completion. a. Install BOPE junk screen, function rams, flush stack with Johnny whacker, and retrieve junk screen. b. Discuss fishing options with Drilling Superintendent if necessary. 11. Close blind rams, Clean rig floor and PU 10,000' of 4" DP. a. Continue filling hole with 5 bbl of LVT every half hour. Riq Activity: Seal Bore Polish Assembly 1. RIH with scraper, magnet, and seal bore polish mill to 4 -1/2" x 7 -5/8" LHP seal bore on 4" DP 9,851' MD a. RIH filling hole with 5 bbl of LVT every half hour 2. Polish seal bore as per Baker rep a. Circ 1.5 DP capacity prior to POOH 3. POOH filling hole with 150% DP displacement plus 5 bbl of LVT every half hour 4. Close blind ram a. Continue to fill hole with 5 bbl of LVT every half hour. ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 5 Program V1 June 12 2013 • • Rig Activity: RIH with 3 -1/2" Coil Tubing Cleanout String 1. Hold pre -job meeting a. Weatherford is responsible for tally at rig site. The Tally is to include: i. Tubing measurement by joint (composite tubing tally is not acceptable) ii. Equipment type, Length, OD, & ID b. CoMan to confirm jewelry installation and location c. Tally is to be emailed to Alex Vaughan once compiled for confirmation. d. Tally is to be confirmed by Nabors Driller during RIH. 2. Confirm zero pressure below blind ram and open ram a. Continue to fill hole with 5 bbl of LVT every half hour. 3. Conduct a pre -job meeting to run 3 -1/2" Coil cleanout string. 4. PU & RIH up 3 -1/2" Coil cleanout string as per tally. a. Continue to fill hole with 5 bbl of LVT every half hour. b. Circ 1.5 tubing volume 1/3 (-3,300' MD) and 2/3 (-6,600' MD) into the way in the hole. An outline of the completion equipment is as follows. This is intended to provide an understanding of the purpose of each piece of the equipment. It is provided as supplemental information along with the provided completion tally. Halliburton X- Nipple • Install at 2,000' TVD • Primary Purpose: Backup location to set XX Plug to pressure test 3 -1/2" tubing. Halliburton Gas Lift Valve • Install at 3,300' MD (61° Inc) • Run with dummy valve installed • Purpose: Lift gas injection location for coil cleanout flow back assistance Halliburton XN- Nipple • Install one joint below GLM • Primary Purpose: Primary pressure test location for the 3 -1/2" tubing ID with a XXN Plug. • Secondary Purpose: Allows installation of junk catcher for GLV swap on GLM Seal Bore Assembly • Purpose: Hydraulic barrier between IA and tubing. ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 6 Program V1 June 12 2013 • • Riq Activity: Land 3 -1/2" Coil Tubing Cleanout Strinq 1. With 3 -1/2" landing joint and FOSV, land tubing hanger & RILDS. Test both the upper and lower Tubing Hanger body seals to 5000psi. 2. RU slickline and set a XXN plug in the XN- nipple. 3. Pressure test tubing to 3,500 psi for 30 min and chart. 4. Pressure test IA to 3,500 psi for 30 min and chart. 5. RD slickline 6. RU Vetco lubricator and Install BPV, RD Vetco 7. ND BOP's and NU Tree 8. Test X -mas Tree void to 5,000 psi. & suspend well with the following well control barriers in place. a. 3 -1/2" Tubing: i. Pressure tested XXN Plug in XN- nipple ii. BPV b. 3 -1/2" x 7 -5/8" Annulus: i. Pressure tested 3 -1/2" x 7 -5/8" annulus. ii. Pressure tested tubing hanger packoff 9. Hold post job meeting a. Ensure proper handover of well from Drilling to Operations. b. Confirm Well Handover Document has been filled out and received by Operations. c. Email copy of the signed Well Handover Document to Kathy Campoamor. 10. RDMO Nabors 19AC a. Weatherford to supply CoMan and Alex Vaughan with a digital copy of Tally, Pressure tests, and Post job report prior to leaving location. b. Halliburton to supply CoMan and Alex Vaughan with a digital copy of post job report, SAMS sheet and /or strap sheets prior to leaving location. ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 7 Program V1 June 12 2013 • • Post Riq: Slickline & Coil Tubing Cleanout 1. RU Vetco lubricator and pull BPV 2. RU slickline 3. Pull dummy GLV from GLM and install live GLV 4. Equalize and pull XXN Plug from XN- nipple 5. RD Slickline and RU CTU. 6. Cleanout ODST -45A with CTU to point of refusal with LVT, N2, and lift gas 7. RD CTU and RU slickline 8. Set XXN Plug in XN- nipple 9. Fluid pack the IA and tubing by circulating down IA through live GLV and up 3 -1/2" tubing 10. Pull live GLV from GLM and install dummy GLV 11. Pressure test tubing to 3,500 psi for 30 min and chart. 12. Pressure test IA to 3,500 psi for 30 min and chart. 13. RD Slickline and RU Vetco lubricator 14. Set BPV and RD Vetco lubricator 11. Suspend well with the following well control barriers in place. a. 3 -1/2" Tubing: i. Pressure tested XXN Plug in XN- nipple ii. BPV b. 3 -1/2" x 7 -5/8" Annulus: i. Pressure tested 3 -1/2" x 7 -5/8" annulus ii. Pressure tested tubing hanger packoff 1. Pre -Riq Regulatory: 1. Provide 48 hour notice for the testing of the BOPE. 2. AOGCC mandates 1 week BOPE testing periods during RWO's. 3. Post ODST -45A Approved Sundry # TBA (see program attachments). 4. Read Approved Sundry and ensure that operations are in accordance. ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 8 Program V1 June 12 2013 • • Rig Activity: Kill ODST -45A 3 -1/2" Coil Cleanout String 1. Hold pre job meeting a. Confirm Pre -Rig Workover Checklist has been filled out, reviewed, signed, and received from Operations b. Ensure proper handover of well from Operations c. Ensure adequate LVT is on location d. Discuss potential well control issues and ensure they are appropriately communicated to rig crew. 2. MIRU Nabors 19AC over ODST -45A 3. Lubricate and bleed the 3 -1/2" x 7 -5/8" IA as required 4. ND production tree with the following well control barriers in place a. 3 -1/2" Tubing: iii. Pressure tested XXN Plug in XN- nipple iv. BPV b. 3 -1/2" x 7 -5/8" Annulus: iii. Pressure tested 3 -1/2" x 7 -5/8" annulus iv. Pressure tested tubing hanger packoff 5. NU BOPE, Install test dart & Test 250 psi low / 4500 psi high according to the test pressures outlined in the AOGCC Permit to Drill. a. Notify the AOGCC Field Representative 48 hours prior to the BOPE Test. 6. RU Vetco lubricator, Retrieve the blanking plug and BPV, RD Vetco lubricator 7. RU slickline lubricator equalize XXN plug in XN- nipple and pull XXN plug. 8. Bullhead 150% 3 -1/2" tubing volume -130 bbls of LVT a. All fluids injected into the well should be LVT. 9. Monitor well for 30 min and ensure well is dead or on vacuum. Lubricate and bleed the IA as required. ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 9 Program V1 June 12 2013 • • Rig Activity: POOH with 3 -1/2" Coil Cleanout String 2. Hold pre job meeting a. Ensure safety valves with XO's to 3 -1/2" tubing are operational and drifted. 3. Prep rig floor to pull 3 -1/2" coil cleanout string. a. Ensure safety valves with XO's to 3 -1/2" tubing are accessible and in the open position. 4. BOLDS and unseat 3 -1/2" tubing hanger 5. Close annular and bullhead 150% 3 -1/2" x 7 -5/8" annulus volume -504 bbls of LVT 6. Monitor well for 30 min and ensure well is dead or on vacuum. 7. POOH and LD 3 -1/2" coil cleanout string a. Clean all completion equipment at the rig floor with absorbs and WD40. Do not use water. b. Fill hole with 150% tubing displacement plus 5 bbl of LVT every half hour. c. If influx is observed stab FOSV, space out, close annular and bullhead 1.5 tubing volume to 7 -5/8" shoe at 6 bpm. Shut down and monitor well for 30 min. If well continues to flow continue to bullhead and contact Rig Superintendent to discuss increasing fluid weight. Once well is confirmed dead continue POOH. d. If junk is left in hole contact Rig Superintendent and discuss fishing options. 8. Close blind rams, Clean rig floor and prep to run ESP completion. a. Continue filling hole with 5 bbl of LVT every half hour. Rig Activity: RIH with 2 -7/8" ESP Completion 5. Hold pre job meeting a. Weatherford is responsible for tally at rig site. The Tally is to include: i. Tubing measurement by joint (composite tubing tally is not acceptable) ii. Equipment type, Length, OD, ID, Drift & Fishing neck iii. Clamp or band location b. CoMan to confirm GV & RHC installation and location c. Tally is to be emailed to Alex Vaughan once compiled for confirmation. d. Tally is to be confirmed by Nabors Driller during RIH. 6. Confirm zero pressure below blind ram and open ram b. Continue to fill hole with 5 bbl of LVT every half hour. 7. Conduct a pre job meeting to run 2 -7/8" ESP completion. a. Review Lessons Learned from previous ESP installations (See RWO SID). b. Review Centrilift ESP running procedure. (See RWO SID) c. Review Weatherford 2 -7/8" x 7 -5/8" ESP packer running procedure. (See RWO SID) 8. PU & RIH up 2 -7/8" ESP completion as per tally. a. Continue to fill hole with 5 bbl of LVT every half hour. b. Baker Lock centralizer below ESP c. Circ 1.5 tubing volume halfway between ESP and packer d. Circ 1.5 tubing volume one joint before picking up the packer ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 10 Program V1 June 12 2013 • • e. Hold 1000 psi on PW during RIH f. Hold 4500 psi on TRSV during RIH An outline of the completion equipment is as follows. This is intended to provide an understanding of the purpose of each piece of the equipment. It is provided as supplemental information along with the provided completion tally. Halliburton Tubing retrievable safety valve • Install at 2,000' TVD • Purpose: 2 -7/8" tubing ID well control safety device Halliburton Gas Lift Valve #1 • Install one joint above X- Nipple #1 • Run with 2,500 psi shear out valve installed • Purpose: Freeze protection of the 2 -7/8" x 7 -5/8" annulus Weatherford Packer • Install at -2,500' MD • Primary Purpose: 2 -7/8" x 7 -5/8" annulus well control safety device • Secondary Purpose: Allows pressure test of the 2 -7/8" x 7 -5/8" annulus • Note: Weatherford packer has a 3800' TVD depth limitation and should be installed no deeper than 2500' MD and above KOP due to experienced difficulties with releasing packer. • Note: Directly below the packer install a backup inline check valve on the %" chemical injection mandrel tubing. This backup check valve is installed directly below the packer for physical protection should the primary %" chemical injection check valve in the chemical injection mandrel below the ESP fail and potentially allow pressure to be communicated to surface through the ESP packer. Halliburton Gas Lift Valve #2 • Install one joint below ESP Packer • Run with dummy GLV installed • Purpose: Allows accumulated gas below the ESP packer to be removed for future RWO's. Halliburton X- Nipple • Install one joint below GLM #2 • Run with RHC plug installed • Primary Purpose: Primary pressure test location for the 2 -7/8" tubing ID. • Secondary Purpose: Allows installation of XX plug as a junk catcher for GLV swap on GLM # 2 Halliburton Gas Lift Valve #3 • Install at 68° Inc • Purpose: Backup gas lift location to GLM #4 Halliburton X- Nipple • Install one joint below GLM #3 • Primary Purpose: Allows installation of XX plug as a junk catcher for GLV swap on GLM # 3 Halliburton Gas Lift Valve #4 • Install 200' TVD above ADV so as to avoid gas overshooting GLM #4 and circulating through the ADV • Run with live %<" OV GLV installed • Purpose: Primary gas lift location as a backup to the ESP ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 11 Program V1 June 12 2013 • • Halliburton X- Nipple • Install one joint below GLM #4 • Primary Purpose: Allows installation of XX plug as a junk catcher for GLV swap on GLM # 4 • Note: A XN- Nipple was not used as the ADV and ESP is below this GLM and is therefore not required. ESP • Install as deep as possible in a location of less than 2° DLS • Purpose: Enhanced fluid lift to surface Chemical Injection Mandrel • Installed directly above ESP centralizer • Purpose: Chemical injection location for scale reduction • Install with a differential pressure check valve of 50 psi through %" tubing and 10,000 psi from below ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 12 Program V1 June 12 2013 • • Rig Activity: Land 2 -7/8" ESP Completion 15. With 3 -1/2" landing joint and FOSV, land tubing hanger while maintaining 4,500psi on control lines and 1000 psi on the gas vent control line. Once landed, RILDS for Tubing Hanger. Test both the upper and lower Tubing Hanger body seals to 5000psi. 16. Hold pre job meeting a. Review freeze protection procedures b. Review packer setting procedures 17. Drop ball and rod and displace down to RHC body. a. Run ball and rod on slickline if fluid level of tubing is not at surface. 18. Fill tubing with LVT set Weatherford GVV packer per Weatherford rep instructions a. A DCR -1 shear out valve pinned to 2500 psi is installed in GLM #1 and requires that pressure testing operations are executed in the following order: b. Slowly increase pressure on the tubing to 3,500 psi (4,000 psi max) and hold for at 30 minutes and chart i. Packer slips engage at 1,500 psi. c. Bleed tubing pressure down to 2,500 psi d. Pressure Test 2 -7/8" x 7 -5/8" annulus to 3,500 psi for 30 min and chart e. Bleed tubing pressure down to zero. i. This will result in shearing the shear -out valve f. Pump fluid both directions through the shear -out valve to confirm communication. 19. Install BPV and blanking plug in tubing hanger. 20. Hold pre job meeting a. Review Lessons Learned from previous ESP installations (See RWO SID). b. Review Centrilift ESP running procedure as it pertains to the wellhead & tree. (See RWO SID). 21. ND BOP's. a. Ensure Vetco Gray personnel are present prior to lifting stack and recovering control lines so as to prevent kinking. b. Note: Centrilift tech to continue to monitor cable conductivity throughout process. 22. Feed control lines thru tree adaptor body, install Vetco Gray Wellhead hydraulic fittings, install needle valve, test control lines 5000psi. Vetco Gray BIW penetrator prepped for THA installation. a. Monitor ESP communications during process. 23. Pull blanking plug 24. NU Vetco Gray Production ESP X -mas Tree (Tubing Head Adaptor w/ ESP port, 3- 1/8 ",5k Vertical valve, & 5 -3/4" Otis Lubricator Adaptor) 25. Test Production X -mas Tree void to 5000psi and bleed off pressure. Test X -mas Tree internals through the 3" Prod Wing Assy. Test the 2" Gas Lift Wing Assembly against shop tested closed inner valve to 5000psi. Once tests are successfully completed, bleed pressure & recover BPV via lubricator. Secure well. 26. Hold post job meeting a. Ensure proper handover of well from Drilling to Operations. ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 13 Program V1 June 12 2013 • • b. Confirm Well Handover Document has been filled out and received by Operations. c. Email copy of the signed Well Handover Document to Kathy Campoamor. 27. RDMO Nabors 19AC a. Centrilift to install ESP pigtail to top of BIW penetrator protruding through the Tubing Head Adaptor while monitoring ESP communications. b. Weatherford to supply CoMan and Alex Vaughan with a digital copy of Tally, Pressure tests, and Post job report prior to leaving location. c. Centrilift and Halliburton to supply CoMan and Alex Vaughan with a digital copy of post job report, SAMS sheet and /or strap sheets prior to leaving location. Post Rig: Slickline 2. RU slickline on ODST -45A 3. Hold pre job meeting 4. RU lubricator and pull BPV 5. Hold open TRSV 6. Circulate diesel down 2 -7/8" x 7 -5/8" annulus through shearout valve and up 2 -7/8" tubing to surface 7. Pull Shearout valve from GLM #1 and install Dummy 8. Pull Ball and Rod 9. Pull RHC 10. Function test TRSV 11. Start up ESP as per Centrilift Procedures ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 14 Program V1 June 12 2013 • • The following information can be found in the RWO Supplemental Information Document (RWO SID). 2 -7/8" Decompletion • As -built Visio schematic • As -built WellView schematic • 2 -7/8" ESP tubing tally • ESP Packer releasing model 3 -1/2" Coil Tubing Cleanout Temporary Completionn • Planned schematic New 2 -7/8" ESP Completion Information • Planned Completion • Centrilift ESP lesson learned (Oooguruk specific) General information • WOOPR • Directional surveys • Reservoir pressure model • Baker standby fishing tool list • Operations to Drilling handover form • Drilling to operation handover form ODST -45A ESP Pull, Coil Cleanout String, Coil Cleanout, Coil Cleanout Sting Pull, & ESP Install 15 Program V1 June 12 2013 • • ODST -45A RWO - ESP Swap Completion Casing Well Head: 10 -3/4 ", 5K, VetcoGray em # Item MD ( ND (ft) s> y A A 1 :) 16" Conductor 153 153 Tree: 3 -1/2 ", 5K, Horizontal B 10 -3/4" 45.5# L -80 BTC, 9.95" ID 4,973 3,438 C 7 -5/8" 29.7# L -80 BTC -M, 6.875" ID (Window) 10,038 4,996 O D 4 -1/2" 12.6# Hydril 521 3.958" ID 15,429 5,018 E 2 -7/8" 6.5# L -80 IBT -M Tubing 9,560 4,847 OA 1 Veto°Gray Tubing Hanger 34 34 2 2 -7/8 HES Wellstar TRSV w/ 2.313" Packing Bore 2,025 1,994 GLM #1 - Vanoil 2 -7/8" x 1 -1/2" w/ DV installed ® 3 (1 joint above top X nipple) 2,528 2,432 4 2 -7/8" XNipple 2.313" 1.0. (1 joint from packer) 2,575 2,468 ��.1 WFT 7 -5/8" x 2 -7/8" Gas Vent Valve Packer 5 (max. ND 2500) 2,626 2,506 GLM #2 - Vanoil 2 -7/8" x 1 -1/2" DV installed ©Z■ 6 (1 joint below packer) 2,668 2,537 GLM #3 - Vanoil 2 -7/8" x 1 -1/2" DV installed . ® 7 (2 joints above X nipple) 9,360 4,785 0 2 -7/8" X Nipple, 2.313" I.D. w/ "RHC -M" Plug with 8 extended neck installed (Max inc. 68 deg) 9,442 4,810 9 Automatic Divert Valve (ADV) 9,490 4,825 10 ESP (Pump, Motor, and Jewelry) 9,500 4,828 CO 11 Chemical Injection Mandrel w/ 3/8" control line to surface 9,553 4,845 End of Assembly 9,560 4,847 O 12 WFT PBR Tie Back Sleeve 155 9,891 4,951 WFT "TSP" Liner Top Pkr w/ Hold Down Slips 5 -1/2 20#x 1 13 7 -5/8 29.70 w/ Vam Top HT Box Down 9,907 4,956 WFT "PHR" Rotating Hyd Set Liner Hanger 5 -1/2 20# x 7- 5/8 29.70 #w / 5 -1/2 Vam Top HT Pin x Pin XO w/ 5 -1/2 14 Vern Top HT Box x 4 -1/2 Hydril 521 Pin 9,910 4,957 WFT 4 -1/2 12.60# x 5.75od x 15 Ft "Genesis" Water - ^� • 15 Based Swellable Packer w/ 4 -1/2 Hydril 521 Box x Pin 11,401 5,173 4 -1/2 12.60 L-80 Hydri Pupjt 45 (Ported w/ 6 1/2 holes) 11,581 5,170 4 -1/2 12.60 L -80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 11,786 5,169 • ® • 4 -1/2 12.60 L -80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 11,991 5,171 © 4 -1/2 12.60 L -80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 12,196 5,171 4 -1/2 12.60 L -80 Hydri Pupjt 45 (Ported w/ 6 1/2 holes) 12,402 5,159 4 -1/2 12.60 L -80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 12,688 5,132 4-1/2 12.60 L -80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 13,009 5,101 4 -1/2 12.60 L -80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 13,213 5,083 ® 4-1/2 12.60 L -80 Hydri Pupjt 45 (Ported w/ 6 1/2 holes) 13,417 5,065 4 -1/2 12.60 L-80 Hydri Pupjt Oft (Ported w/ 6 1/2 holes) 13,584 5,052 O O 1 4 -1/2 12.60 L-80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 13,787 5,032 4 -1/2 12.60 L -80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 13,989 5,018 4 -1/2 12.60 L -80 Hydri Pupjt 45 (Ported w/ 6 1/2 holes) 14,195 5,015 4 -1/2 12.60 L -80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 14,396 5,012 4 -1/2 12.60 L -80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 14,600 5,004 12 O 4 -1/2 12.60 L -80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 14,806 5,001 4 -1/2 12.60 L -80 Hydri Pupjt 45 (Ported w/ 6 1/2 holes) 15,008 5,001 ® • 4 -1/2 12.60 L-80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 15,210 5,008 4 -1/2 12.60 L -80 Hydri Pupjt 4ft (Ported w/ 6 1/2 holes) 15,417 5,018 Ray Oil Tool Silver Bul et Eccentric Float Shoe 15,422 ':0. / 16 (PLUGGED) w/ 4 -1/2 Hydril 521 Box TO 15,429 5,018 V O ( 1i ` 15 ( ` 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 0 1010 Cement Squeeze when well was 00 00 00 00 00 00 00 00 sidetracked - ..„,,,1/4 Estimated Top of Cement @ EZSV 10100' MDrkb / 5017'TVDrkb 10100' MD / Cement above packer: 2.5bb1 / 50' 5017' TVDrkb Cement below packer: 79.5bbI / 1277' to 7 -5/8" shoe + 100' w/ 30% excess bullhead below shoe 7 -5/8 ", 29.7# L -80 BTC -M, 6.875" ID 11377' MDrkb / 5412' 1 TVDrkb P10 N E E R Date: Revision By: Comments 1/31/2011 RBT JAD Proposed ESP Completion 2/23/2011 Proposed ESP Completion ODST -45A TIIIIp�I pE[SI'Ipptt ^� ^pV 9/6/2012 RJJ Proposed ESP Swap + Add Chemical Inj ESP Swap NAIUNI� ICS�UIIbLSf1l71JN1 9/27/12 TWC Added GLM below packer Completion 10/13/12 KLC ESP Change Out RWO ODST- 45A0roposed CT Clean- oaString for RWO Casing Item MD (ft) ND (ft) Well Head: 10 -3/4 ", 5K, VetcoGray 16" Conductor 153 153 Tree: 3 -1/2 ", 5K, Horizontal 10 -3/4" 45.5# L-80 BTC, 9.95" ID 4,973 3,438 7 -5/8" 29.7# L-80 BTC-M, 6.875" ID (Top of Window) 10,038 4,996 ' 4-1/2" 12.6# Hydril 521 3.958" ID 15,424 5,018 • 3 -1/2" 9.2# L -80 TCII Clean -Out String w/ Coiled Tubing: X- Nipple @ —2031' MD /2000' TVD • GLM w/ Dummy Valve @— 3300' MD/2909' TVD alI XN Nipple @ — 3342' MD/2929' TVD 3 -W seal assembly stung into liner hanger packer assembly 1 , , L .,....1..iii 11 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 i 00 00 00 00 00 00 00 00 Date: Revision By: Comments P10 A) E [ n 6/12/13 KLC CT Clean -out String, Proposed ` ` v l I ( \ ODST -45A Proposed CT NAIUR4LflES��RCESAIAS� Clean -out String ODST -4.4 ESP RWO Completiv - Design MD 1VD Well: T45A Baker Hughes 16" Conductor 153 153 Set Depth: 9,560 Halliburton 10 -3/4" 45.5# L -80 BTC, 9.95" I D 4,973 3,438 Weatherford ' ■ 7 -5/8" 29.7 #L -80 BTC -M, 6.875" ID (Window) 10,038 4,996 Vetco Gray 4 -1/2" 12.6# Hydril 521 3.958" ID 15,429 5,018 Length Not Canfirme Tool Description Joints Tool/Joint Cumm. Top of TVD(ustt) Inc('1 DLS Length Length Tool Depth Baker5.85" OD Centralizer 2.00 2 9,558 4,847 71.5 3.4 LIMMEVEBox x 23l8" EUE 8rd 8"ox 1.00 3 9,557 4,846 71.5 3.4 jjjj Mand250 6 9,555 4,846 71.5 3.4 GLI nt 2.00 8 9,553 4,845 71.5 3.4 0.50 8 9,552 4,845 71.5 3.4 Motor Gauge 1.91 10 9,550 4,844 71.5 3.4 Motor 16.80 27 9,533 4,839 71.6 3.4 Lower Tandem Seal 6.90 34 9,526 4,837 71.6 3.4 Upper Tandem Seal 6.90 41 9,519 4,834 71.6 3.4 -) Gas Separator 9,514 4,833 71.7 3.4 Adapter Kit 0.14 5.47 46 6 4 9,514 4,833 71.7 3.4 . 11 Pump 21.50 68 9,492 4,826 71.8 3.4 Bolt on Discharge Head 0.62 68 9,492 4,826 71.8 3.4 2 -7/8" EUE Handling Pup 2.00 70 9,490 4,825 71.8 3.4 Discharge Gauge 2.63 73 9,487 4,824 71.8 3.4 2 -7/8" EUE Handling Pup 2.00 75 9,485 4,824 71.8 3 Auto Dh.erter Vale 3.35 78 9,482 4,823 71.8 3.4 2 -7/8" EUE x IBT -M Handling Pup 10.00 88 9,472 4,820 71.9 3.4 • 2.875" 6.5# L-80 IBT -M Joint 20 31.00 708 8,852 4,629 71.7 0.23 12.00 720 8,840 4,625 71.6 0.23 1.50 722 8,838 4,624 71.6 0.23 12.00 734 8,826 4,621 71.6 0.23 2.875" 6.5# L-80 IBT -M Joint 1 31.00 765 8,795 4,611 71.5 0.65 12.00 777 8,783 4,607 71.4 0.65 8.65 785 8,775 4,605 71.4 0.65 -.I 12.00 797 8,763 4,601 71.3 0.65 2.875" 6.5# L-80 IBT -M Joint 168 31.00 6,005 3,555 3,016 71.1 4.11 III . 12.00 6,017 3,543 3,013 70.7 4.11 1.50 6,019 3,541 3,012 70.6 4.11 12.00 6,031 3,529 3,008 70.1 4.11 2.875" 6.58 L-80 IBT -M Joint 1 31.00 6,062 3,498 2,997 68.4 7.67 12.00 6,074 3,486 2,992 67.5 7.67 8.65 6,083 3,477 2,989 66.8 7.67 12.00 6,095 3,465 2,984 65.9 3.46 2.875" 6.58 L-80 IBT -M Joint 27 31.00 6,932 2,628 2,508 42.3 3.99 12.00 6,944 2,616 2,499 41.8 3.99 1.50 6,945 2,615 2,498 41.8 3.99 12.00 6,957 2,603 2,489 41.3 3.99 2.875" 6.58 L-80 IBT -M Joint 1 31.00 6,988 2,572 2,466 40.0 3.99 -J 12.00 7,000 2,560 2,457 39.6 4.11 .87 x . 0" " U8 Mandrel (Dummy Val 8.67 7,009 2,551 2,450 39.2 4.11 • • 2.875" 6.5# L-80 IBT-M Pup Joint 12.00 7,021 2,539 2,440 38.7 4.11 2.875" 6.5# L -80 IBT -M Joint 1 31.00 7,052 2,508 2,416 37.5 4.11 xoeer coupling and pup joint 4.45 7,056 2,504 2,413 37.4 4.11 WFTHyrow II Packer 4.86 7,061 2,499 2,409 37.2 4.11 0 )4oyer coupling and pup joint 14.27 7,075 2,485 2,398 36.6 4.11 O 0 0 2.875" 6.59 L-80 IBT -M Joint 1 31.00 7,106 2,454 2,372 35.6 3.29 12.00 7,118 2,442 2,363 382 3.29 8.67 7,127 2,433 2,355 34.9 3.29 12.00 7,139 2,421 2,345 34.5 4.69 2.875" 6.5# L-80 IBT -M Joint 10 31.00 7,449 2,111 2,073 24.5 1.56 12.00 7,461 2,099 2,062 24.4 1.56 6.70 7,468 2,092 2,055 24.3 4.52 12.00 7,480 2,080 2,044 23.9 4.52 2.875" 8.58 L -80 IBT -M Joint 66 31.00 9,526 34 - 0.92 9,527 33 3.5" 9.28 L-80 Pup Joint 7.36 9,534 26 Vetco Gray Tubing Hanger 1.54 9,535 25 RKB 34.09 9,570 -10 '....\ ' 00 00 00 00 •• 00 00 00' 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 001 0 01 c - ■■••• Date: Revision By: Comments PIONEER 6/12/2013 Alex Vaughan Planned Design ODST -45A ESP RWO NATURAL RESOURCES ALASKA Completion • • Workover Objectives and Planning Requirements Well Name: I ODST -45A I I Date: 1 12- Jun -13 I I Location: I Oooguruk Drill Site I I Confidential (YIN) I No I I Workover Type 1 RWO I I Exploratory or Development: 1 Development I Well Classification: 1 Producer Prop osed Start Date: 20- Ju -13 II I I AFE Days I NA II AFE Total I NA I Team Members Engineer Contact Info Well Engineer Alex Vaughan Name Alex Vaughan Well Work Phone Office 907 - 343 -2186 Completion Tim Crumrine Phone Cell 907 - 748 -5478 Production Theresa Williams Email alex.vauuhanegxd.com DrIg Super Rob Tirpack DrIg Manager Vern Johnson ( Reason for Workover: ESP Installation I 1. Ensure safety of all personnel involved in Pre -Rig, Rig, and Post Rig Operations. Priorities' 2. Protect environment from all spills /damage related to well operations. 3. Coordinate with Ops to retum well to service within limitations of Rig Schedule 1. Pull ESP, DP Cleanout, Install 3 -1/2" Coil Cleanout String, Coil Cleanout with N2, Install ESP 2. Minimize fluid loss, Primary RWO fluid: LVT, Re- evaluate for ESP install after coil work Objectives: 3. CCOS: GLM w/ dummy cQ3300' MD, ESP: Shear -out GV in GLM #1, OV GLV 200' TVD above ADV 4. CCOS: Flowback thru ExPro, Post ESP Install: Flowback thru PXD test header into flowback tanks 1. Well Control, Excessive fluid loss, Raising reservior pressure Hazards and Concerns 2. Delivery of equipment and tools necessary to perform operation 3. CCOS: 3 -1/2" IA does not pressure test, No options for long term production 4. Last minute schedule changes with minimal planning time The maximum anticipated surface pressure, assuming gas from surface to 7 -5/8" shoe at 10,104' MD / 5,013' TVD is estimated at 1,142 psi with a 0.11 psi/ft gas gradient MASP Reservoir Pressure Estimated BHP after 20 days of shut -in is 1,694 psi (6.5 ppge) at 5013' TVD Coil Cleanout w/ flowback through ExPro, & Pressure survey via slickline Non -Rig Operations: Pull ESP: Set dummy in GLM and fluid pack IA via lubricate and bleed method, Bullhead tubing CCOS: Well will be shut in with XXN Plug at 3,300' MD, BPV, & tested hanger void 1. AOGCC Application for Sundry Approval (10 -403) 2. ODSDW01 -44 Class 1 / Class 2 disposal well approved for disposal Permitting and /or Policy Requirements: 3. Pioneer pre -rig checklist 4. Pioneer well handover form Reservoir Engineering Manager Approval Drilling Manager Approval Operations Manager Approval ODST -45A Torok Shut -in Pressures (ppge) 9. ... aa a a a............ . - -- a.aaar raa -�. ......- ..- �.....0�r.r. F �. ,. -- -.0.--- -r, ..---- TorokInitiai Reservoir Press* -- Seawater, &6 ppge . - - - LVT, 6,8 ppge ISZ 0 T45A, May -Oct 2012 Shut-in , .: 7 Vol daze: 439 MR>gs I �, _ ••..•••• T45A Est "d from W V Ip ......• T45A, Feb-April 2013 Shut -Ir % 6 :. - Voidage: 511 MRBs G la a. ai 0 as - a di • 0 co I 3 0 20 40 60 80 100 120 140 160 180 200 Cumulative Shut In Time, Days 1 • • PIONEER Tubing Tally NATURAL RESOURCES Des: ESP Recomplete, Set Depth: 9,560.0ftKB Well Name: ODST -45A API/UWI Surface Legal Location License/LeaseNumber Field Name State 50- 703 - 20577 -01 -00 2889' FSL, 1176' FEL, Sec 11, T13N, R7E, UM 209-079 Oooguruk Unit ALASKA Well Profile Original KB Ebvation (ft) KB -Ground Dstance (ft) KB- Casing Flange Disance (ft) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 42.70 42.70 Tubing Run Tally Item Des OD (in) Wt (1b/ft) Grade Ref # Run? Len (ft) Centralized? Ext Jewelry Top (ftKB) Cum Len (ft) Tubing 2 7/8 6.40 L -80 Yes 1.90 No 9,558.1 1.90 Tubing 2 7/8 6.40 L -80 Yes 0.99 No 9,557.1 2.89 Tubing 2 7/8 6.40 L -80 Yes 2.56 No 9,554.6 5.45 Tubing 2 7/8 6.40 L -80 Yes 1.88 No 9,552.7 7.33 Tubing 2 7/8 6.40 L -80 Yes 0.61 No 9,552.1 7.94 Tubing 2 7/8 6.40 L -80 Yes 56.46 No 9,495.6 64.40 Tubing 2 7/8 6.40 L -80 Yes 3.35 No 9,492.3 67.75 Tubing 2 7/8 6.40 L -80 Yes 9.97 No 9,482.3 77.72 2 7/8" 2 7/8 6.40 L -80 1 Yes 31.52 No 9,450.8 109.24 Tubing 2 7/8" Pup 2 7/8 6.40 L -80 Yes 5.82 No 9,444.9 115.06 Joint X nipple with 2 7/8 6.40 L -80 Yes 1.28 No 9,443.7 116.34 2.313" profile 2 7/8" Pup 2 7/8 6.40 L -80 Yes 5.81 No 9,437.9 122.15 Joint 2 7/8" 2 7/8 6.40 1-80 2 Yes 30.78 No 9,407.1 152.93 Tubing 2 7/8" 2 7/8 6.40 L -80 3 Yes 30.48 No 9,376.6 183.41 Tubing 2 7/8" Pup 2 7/8 6.40 L -80 Yes 5.82 No 9,370.8 189.23 Joint 2.875" x 1.5" 2 7/8 6.40 L -80 Yes 9.15 No 9,361.6 198.38 GLM w /dummy valve 2 7/8" Pup 2 7/8 6.40 L -80 Yes 5.82 No 9,355.8 204.20 Joint 2 7/8" 2 7/8 6.40 L -80 4 Yes 29.58 No 9,326.2 233.78 Tubing 2 7/8" 2 7/8 6.40 1-80 5 Yes 30.53 No 9,295.7 264.31 Tubing 2 7/8" 2 7/8 6.40 1-80 6 Yes 31.99 No 9,263.7 296.30 Tubing 2 7/8" 2 7/8 6.40 1-80 7 Yes 31.51 No 9,232.2 327.81 Tubing 2 7/8" 2 7/8 6.40 L -80 8 Yes 30.64 No 9,201.6 358.45 Tubing 2 7/8" 2 7/8 6.40 L -80 9 Yes 31.29 No 9,170.3 389.74 Tubing 2 7/8" 2 7/8 6.40 1-80 10 Yes 30.74 No 9,139.5 420.48 Tubing 2 7/8" 2 7/8 6.40 L -80 11 Yes 30.53 No 9,109.0 451.01 Tubing 2 7/8" 2 7/8 6.40 1-80 12 Yes 31.97 No 9,077.0 482.98 Tubing 2 7/8" 2 7/8 6.40 1-80 13 Yes 31.96 No 9,045.1 514.94 Tubing 2 7/8" 2 7/8 6.40 1-80 14 Yes 30.41 No 9,014.7 545.35 Tubing 2 7/8" 2 7/8 6.40 1-80 15 Yes 30.09 No 8,984.6 575.44 Tubing 2 7/8" 2 7/8 6.40 1-80 16 Yes 30.99 No 8,953.6 606.43 Tubing 2 7/8" 2 7/8 6.40 L -80 17 Yes 30.26 No 8,923.3 636.69 Tubing Page 1/12 Report Printed: 6/11/2013 is • PIONEER Tubing Tally NATURAL RESOURCES Des: ESP Recomplete, Set Depth: 9,560.0ftKB Well Name: ODST -45A API /UWM Surface Legal Location LicenseiLease Number Field Name State 50- 703 - 20577 -01 -00 2889' FSL, 1176' FEL, Sec 11, T13N, R7E, UM 209-079 Oooguruk Unit ALASKA Well Profile Original KB Ebvaton (ft) KB- Ground Dstance (ft) KB- Casing Flange Distance (ft KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 42.70 42.70 Tubing Run Tally Item Des OD (in) Wt fib/ft) Grade Ref # Run? Len (ft) Cen ? Ext Amen, Top (RKB) Cum Len (ft) 2 7/8" 2 7/8 6.40 L -80 18 Yes 30.94 No 8,892.4 667.63 Tubing 2 7/8" 2 7/8 6.40 L -80 19 Yes 30.30 No 8,862.1 697.93 Tubing 2 7/8" 2 7/8 6.40 L -80 20 Yes 30.11 No 8,832.0 728.04 Tubing 2 7/8" 2 7/8 6.40 L -80 21 Yes 29.23 No 8,802.7 757.27 Tubing 2 7/8" 2 7/8 6.40 L -80 22 Yes 31.31 No 8,771.4 788.58 Tubing 2 7/8" 2 7/8 6.40 L -80 23 Yes 31.98 No 8,739.4 820.56 Tubing 2 7/8" 2 7/8 6.40 L -80 24 Yes 31.52 No 8,707.9 852.08 Tubing 2 7/8" 2 7/8 6.40 L -80 25 Yes 30.71 No 8,677.2 882.79 Tubing 2 7/8" 2 7/8 6.40 L -80 26 Yes 31.06 No 8,646.2 913.85 Tubing . 2 7/8" 2 7/8 6.40 L -80 27 Yes 29.87 No 8,616.3 943.72 - Tubing 2 7/8" 2 7/8 6.40 L -80 28 Yes 29.04 No 8,587.2 972.76 Tubing 2 7/8" 2 7/8 6.40 L -80 . 29 Yes 32.00 No 8,555.2 1,004.76 Tubing 2 7/8" 2 7/8 6.40 L -80 30 Yes 31.51 No 8,523.7 1,036.27 Tubing 2 7/8" 2 7/8 6.40 L -80 31 Yes 30.67 No 8,493.1 1,066.94 Tubing 2 7/8" 2 7/8 6.40 L -80 32 Yes 30.58 No 8,462.5 1,097.52 Tubing 2 7/8" 2 7/8 6.40 L -80 33 Yes 31.28 No 8,431.2 1,128.80 Tubing 2 7/8" 2 7/8 6.40 L -80 34 Yes 30.15 No 8,401.1 1,158.95 Tubing 2 7/8" 2 7/8 6.40 L -80 35 Yes 31.10 No 8,370.0 1,190.05 Tubing 2 7/8" 2 7/8 6.40 L -80 36 Yes 29.71 No 8,340.2 1,219.76 Tubing 2 7/8" 2 7/8 6.40 L -80 37 Yes 31.44 No 8,308.8 1,251.20 Tubing 2 7/8" 2 7/8 6.40 L -80 38 Yes 29.20 No 8,279.6 1,280.40 Tubing 2 7/8" 2 7/8 6.40 L -80 39 Yes 31.48 No 8,248.1 1,311.88 Tubing 2 7/8" 2 7/8 6.40 L -80 40 Yes 29.80 No 8,218.3 1,341.68 Tubing 2 7/8" 2 7/8 6.40 L -80 41 Yes 31.48 No 8,186.8 1,373.16 Tubing 2 7/8" 2 7/8 6.40 L -80 42 Yes 31.46 No 8,155.4 1,404.62 Tubing 2 7/8" 2 7/8 6.40 L -80 43 Yes 31.95 No 8,123.4 1,436.57 Tubing 2 7/8" 2 7/8 6.40 L -80 44 Yes 29.39 No 8,094.0 1,465.96 Tubing 2 7/8" 2 7/8 6.40 L -80 45 Yes 30.71 No 8,063.3 1,496.67 Tubing 2 7/8" 2 7/8 6.40 L -80 46 Yes 30.98 No 8,032.4 1,527.65 Tubing Page 2/12 Report Printed: 6/11/2013 • ill • PIONEER Tubing Tally NATURAL RESOURCES Des: ESP Recomplete, Set Depth: 9,560.0ftKB Well Name: ODST -45A API /UWI Surface Legal Location LicensedLease Number Field Name State 50- 703 - 20577 -01 -00 2889' FSL, 1176' FEL, Sec 11, T13N, R7E, UM 209-079 Oooguruk Unit ALASKA Well Profile Original KB Ebvation (ft) KB -Ground Dstance (ft) KB- Casing Flange Disance (ft KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 42.70 42.70 Tubing Run Tally Item Des OD (in) Wt (Ib/ft) Grade Ref* Run? Len (It) zed? Ext Jewelry Top (ftKB) Cum Len (ft) 2 7/8" 2 7/8 6.40 L -80 47 Yes 29.50 No 8,002.9 1,557.15 Tubing 2 7/8" 2 7/8 6.40 L -80 48 Yes 28.68 No 7,974.2 1,585.83 Tubing 2 7/8" 2 7/8 6.40 L -80 49 Yes 25.94 No 7,948.2 1,611.77 Tubing 2 7/8" 2 7/8 6.40 L -80 50 Yes 26.10 No 7,922.1 1,637.87 Tubing 2 7/8" 2 7/8 6.40 L -80 51 Yes 26.00 No 7,896.1 1,663.87 Tubing 2 7/8" 2 7/8 6.40 L -80 52 Yes 27.17 No 7,869.0 1,691.04 Tubing 2 7/8" 2 7/8 6.40 L -80 53 Yes 23.03 No 7,845.9 1,714.07 Tubing 2 7/8" 2 7/8 6.40 L -80 54 Yes 30.76 No 7,815.2 1,744.83 Tubing 2 7/8" 2 7/8 6.40 L -80 55 Yes 26.59 No 7,788.6 1,771.42 Tubing 2 7/8" 2 7/8 6.40 L -80 56 Yes 26.38 No 7,762.2 1,797.80 Tubing 2 7/8" 2 7/8 6.40 L -80 57 Yes 26.07 No 7,736.1 1,823.87 Tubing 2 7/8" 2 7/8 6.40 L -80 58 Yes 25.80 No 7,710.3 1,849.67 Tubing 2 7/8" 2 7/8 6.40 L -80 59 Yes 30.22 No 7,680.1 1,879.89 Tubing 2 7/8" 2 7/8 6.40 L -80 60 Yes 30.94 No 7,649.2 1,910.83 Tubing 2 7/8" 2 7/8 6.40 L -80 61 Yes 26.54 No 7,622.6 1,937.37 Tubing 2 7/8" 2 7/8 6.40 L -80 62 Yes 27.11 No 7,595.5 1,964.48 Tubing 2 7/8" 2 7/8 6.40 L -80 63 Yes 24.12 No 7,571.4 1,988.60 Tubing 2 7/8" 2 7/8 6.40 L -80 64 Yes 25.98 No 7,545.4 2,014.58 Tubing 2 7/8" 2 7/8 6.40 L -80 65 Yes 30.99 No 7,514.4 2,045.57 Tubing 2 7/8" 2 7/8 6.40 L -80 66 Yes 30.54 No 7,483.9 2,076.11 Tubing 2 7/8" 2 7/8 6.40 L -80 67 ' Yes 31.97 No 7,451.9 2,108.08 Tubing 2 7/8" 2 7/8 6.40 L -80 68 Yes 30.97 No 7,421.0 2,139.05 Tubing 2 7/8" 2 7/8 6.40 L -80 69 Yes 29.81 No 7,391.1 2,168.86 Tubing 2 7/8" 2 7/8 6.40 L -80 70 Yes 30.38 No 7,360.8 2,199.24 Tubing 2 7/8" 2 7/8 6.40 L -80 .. 71 Yes 29.58 No 7,331.2 2,228.82 Tubing 2 7/8" 2 7/8 6.40 L -80 72 Yes 29.99 No 7,301.2 2,258.81 Tubing 2 7/8" 2 7/8 6.40 L -80 73 Yes 29.14 No 7,272.1 2,287.95 Tubing 2 7/8" 2 7/8 6.40 L -80 74 Yes 30.68 No 7,241.4 2,318.63 Tubing 2 7/8" 2 7/8 6.40 L -80 75 Yes 30.70 No 7,210.7 2,349.33 Tubing Page 3/12 Report Printed: 6/11/2013 • • PIONEER Tubing Tally NATURAL RESOURCES Des: ESP Recomplete, Set Depth: 9,560.0ftKB Well Name: ODST -45A API /UWI Surface Legal Location License/Lease Number Field Name State 50- 703 - 20577 -01 -00 2889' FSL, 1176' FEL, Sec 11, T13N, R7E, UM 209-079 Oooguruk Unit ALASKA Well Profile Original KB Ebvafon (ft) KB -Ground Dstance (ft) KB- Casing Flange Disance (ft) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 42.70 42.70 Tubing Run Tally Item Des OD (in) Wt (lb/ft) Grade Ref# Run? Len (ft) Ext Jewelry Top (ftKB) Cum Len (ft) 2 7/8" 2 7/8 6.40 L -80 76 Yes 28.32 No 7,182.4 2,377.65 Tubing 2 7/8" 2 7/8 6.40 L -80 77 Yes 30.69 No 7,151.7 2,408.34 Tubing 2 7/8" 2 7/8 6.40 L -80 78 Yes 28.62 No 7,123.0 2,436.96 Tubing 2 7/8" 2 7/8 6.40 L -80 79 Yes 28.29 No 7,094.8 2,465.25 Tubing 2 7/8" 2 7/8 6.40 L -80 80 Yes 31.53 No 7,063.2 2,496.78 Tubing 2 7/8" 2 7/8 6.40 L -80 81 Yes 31.06 No 7,032.2 2,527.84 Tubing 2 7/8" 2 7/8 6.40 L -80 82 Yes 30.45 No 7,001.7 2,558.29 Tubing 2 7/8" 2 7/8 6.40 L -80 83 Yes 26.47 No 6,975.2 2,584.76 Tubing 2 7/8" 2 7/8 6.40 L -80 84 Yes 26.21 No 6,949.0 2,610.97 Tubing 2 7/8" 2 7/8 6.40 L -80 85 Yes 25.37 No 6,923.7 2,636.34 Tubing 2 7/8" 2 7/8 6.40 L -80 86 Yes 29.72 No 6,893.9 2,666.06 Tubing 2 7/8" 2 7/8 6.40 L -80 87 Yes 25.56 No 6,868.4 2,691.62 Tubing 2 7/8" 2 7/8 6.40 L -80 88 Yes 27.45 No 6,840.9 2,719.07 Tubing 2 7/8" 2 7/8 6.40 L -80 89 Yes 32.02 No 6,808.9 2,751.09 Tubing 2 7/8" 2 7/8 6.40 L -80 90 Yes 30.27 No 6,778.6 2,781.36 Tubing 2 7/8" 2 7/8 6.40 L -80 91 Yes 31.49 No 6,747.2 2,812.85 Tubing 2 7/8" 2 7/8 6.40 L -80 92 Yes 30.99 No 6,716.2 2,843.84 Tubing 2 7/8" 2 7/8 6.40 L -80 93 Yes 30.27 No 6,685.9 2,874.11 Tubing 2 7/8" 2 7/8 6.40 L -80 94 Yes 29.94 No 6,656.0 2,904.05 Tubing 2 7/8" 2 7/8 6.40 L -80 95 Yes 30.81 No 6,625.1 2,934.86 Tubing 2 7/8" 2 7/8 6.40 L -80 96 Yes 31.49 No 6,593.7 2,966.35 Tubing 2 7/8" 2 7/8 6.40 L -80 97 Yes 31.42 No 6,562.2 2,997.77 Tubing 2 7/8" 2 7/8 6.40 L -80 98 Yes 31.95 No 6,530.3 3,029.72 Tubing 2 7/8" 2 7/8 6.40 L -80 99 Yes 30.59 No 6,499.7 3,060.31 Tubing 2 7/8" 2 7/8 6.40 L -80 100 Yes 31.47 No 6,468.2 3,091.78 Tubing 2 7/8" 2 7/8 6.40 L -80 101 Yes 30.14 No 6,438.1 3,121.92 Tubing 2 7/8" 2 7/8 6.40 L -80 102 Yes 31.48 No 6,406.6 3,153.40 Tubing 2 7/8" 2 7/8 6.40 L -80 103 ' Yes 30.05 No 6,376.6 3,183.45 Tubing 2 7/8" 2 7/8 6.40 L -80 104 Yes 29.99 No 6,346.6 3,213.44 Tubing Page 4/12 Report Printed: 6/11/2013 • 0 PIONEER Tubing Tally NATURAL RESOURCES Des: ESP Recomplete, Set Depth: 9,560.0ftKB Well Name: ODST -45A API /UWI Surface Legal Location License/Lease Number Field Name State 50- 703 - 20577 -01 -00 2889' FSL, 1178' FEL, Sec 11, T13N, R7E, UM 209-079 Oooguruk Unit ALASKA Well Profile Original KB Eavation (ft) KB -Ground Dstance (ft) KB- Casing Flange Distance (ft) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 42.70 42.70 Tubing Run Tally Item Des OD (in) Wt (tb/ft) Grade Ref # Run? Len (ft) Centralized? EM Jeweby Top (ftKS) Cum Len (ft) 2 7/8" 2 7/8 6.40 L -80 105 Yes 31.51 No 6,315.1 3,244.95 Tubing 2 7/8" 2 7/8 6.40 L -80 106 Yes 31.52 No 6,283.5 3,276.47 Tubing 2 7/8" 2 7/8 6.40 L -80 107 Yes 31.51 No 6,252.0 3,307.98 Tubing 2 7/8" 2 7/8 6.40 L -80 108 Yes 30.41 No 6,221.6 3,338.39 Tubing 2 7/8" 2 7/8 6.40 L -80 109 Yes 30.49 No 6,191.1 3,368.88 Tubing 2 7/8" 2 7/8 6.40 L -80 110 Yes 31.51 No 6,159.6 3,400.39 Tubing 2 7/8" 2 7/8 6.40 L -80 111 Yes 29.47 No 6,130.1 3,429.86 Tubing 2 7/8" 2 7/8 6.40 L -80 112 Yes 31.09 No 6,099.1 3,460.95 Tubing 2 7/8" 2 7/8 6.40 L -80 113 Yes 30.24 No 6,068.8 3,491.19 Tubing 2 7/8" 2 7/8 6.40 L -80 114 Yes 31.13 No 6,037.7 3,522.32 Tubing 2 7/8" 2 7/8 6.40 L -80 115 Yes 31.55 No 6,006.1 3,553.87 Tubing 2 7/8" 2 7/8 6.40 L -80 116 Yes 30.48 No 5,975.7 3,584.35 Tubing 2 7/8" 2 7/8 6.40 L -80 117 Yes 31.50 No 5,944.2 3,615.85 Tubing 2 7/8" 2 7/8 6.40 L -80 118 Yes 31.12 No 5,913.0 3,646.97 Tubing 2 7/8" 2 7/8 6.40 L -80 119 Yes 31.49 No 5,881.5 3,678.46 Tubing 2 7/8" 2 7/8 6.40 L -80 120 Yes 30.73 No 5,850.8 3,709.19 Tubing 2 7/8" 2 7/8 6.40 L -80 121 Yes 31.51 No 5,819.3 3,740.70 Tubing 2 7/8" 2 7/8 6.40 L -80 122 Yes 30.18 No 5,789.1 3,770.88 Tubing 2 7/8" 2 7/8 6.40 L -80 123 Yes 31.95 No 5,757.2 3,802.83 Tubing 2 7/8" 2 7/8 6.40 L -80 124 Yes 30.40 No 5,726.8 3,833.23 Tubing 2 7/8" 2 7/8 6.40 L -80 125 Yes 30.56 No 5,696.2 3,863.79 Tubing 2 7/8" 2 7/8 6.40 L -80 126 Yes 29.42 No 5,666.8 3,893.21 Tubing 2 7/8" 2 7/8 6.40 L -80 127 Yes 31.47 No 5,635.3 3,924.68 Tubing 2 7/8" 2 7/8 6.40 L -80 128 Yes 31.29 No 5,604.0 3,955.97 Tubing 2 7/8" 2 7/8 6.40 L -80 129 Yes 30.80 No 5,573.2 3,986.77 Tubing 2 7/8" 2 7/8 6.40 L -80 130 Yes 31.48 No 5,541.8 4,018.25 Tubing 2 7/8" 2 7/8 6.40 L -80 131 Yes 27.34 No 5,514.4 4,045.59 Tubing 2 7/8" 2 7/8 6.40 L -80 132 Yes 31.52 No 5,482.9 4,077.11 Tubing 2 7/8" 2 7/8 6.40 L -80 133 Yes 29.42 No 5,453.5 4,106.53 Tubing Page 5/12 Report Printed: 6/11/2013 • • PIONEER Tubing Tally NATURAL RESOURCES Des: ESP Recomplete, Set Depth: 9,560.0ftKB Well Name: ODST -45A APUUWI Surface Legal Location License/LeaseNumber Field Name State 50- 703 - 20577 -01 -00 2689' FSL, 1176' FEL, Sec 11, T13N, R7E, UM 209-079 Oooguruk Unit ALASKA Well Profile Original KB Ebvalion (ft) KB -Ground Dstance (ft) KB- Casing Flange Disance (ft) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 42.70 42.70 Tubing Run Tally Item Des OD (in) Wt (R /ft) Grade Ref* Run? Len (ft) Centralized? Ext Jewelry Top (ftKB) Gan Len (ft) 2 7/8" 2 7/8 6.40 L -80 134 Yes 30.21 No 5,423.3 4,136.74 Tubing 2 7/8" 2 7/8 6.40 L -80 135 Yes 32.02 No 5,391.2 4,168.76 Tubing 2 7/8" 2 7/8 6.40 L -80 136 Yes 31.51 No 5,359.7 4,200.27 Tubing 2 7/8" 2 7/8 6.40 L -80 137 Yes 31.99 No 5,327.7 4,232.26 Tubing 2 7/8" 2 7/8 6.40 L -80 138 Yes 31.48 No 5,296.3 4,263.74 Tubing 2 7/8" 2 7/8 6.40 L -80 139 Yes 31.72 No 5,264.5 4,295.46 Tubing 2 7/8" 2 7/8 6.40 L -80 140 Yes 31.49 No 5,233.1 4,326.95 Tubing 2 7/8" 2 7/8 6.40 L -80 141 Yes 30.95 No 5,202.1 4,357.90 Tubing 2 7/8" 2 7/8 6.40 L -80 142 Yes 31.28 No 5,170.8 4,389.18 Tubing 2 7/8" 2 7/8 6.40 L -80 143 Yes 31.97 No 5,138.9 4,421.15 Tubing 2 7/8" 2 7/8 6.40 L -80 144 Yes 30.46 No 5,108.4 4,451.61 Tubing 2 7/8" 2 7/8 6.40 L -80 145 Yes 31.98 No 5,076.4 4,483.59 Tubing 2 7/8" 2 7/8 6.40 L -80 146 Yes 31.05 No 5,045.4 4,514.64 Tubing 2 7/8" 2 7/8 6.40 L -80 147 Yes 31.51 No 5,013.9 4,546.15 Tubing 2 7/8" 2 7/8 6.40 L -80 148 Yes 31.48 No 4,982.4 4,577.63 Tubing 2 7/8" 2 7/8 6.40 L -80 149 Yes 31.98 No 4,950.4 4,609.61 Tubing 2 7/8" 2 7/8 6.40 L -80 150 Yes 31.52 No 4,918.9 4,641.13 Tubing 2 7/8" 2 7/8 6.40 L -80 151 Yes 31.49 No 4,887.4 4,672.62 Tubing 2 7/8" 2 7/8 6.40 L -80 152 Yes 31.52 No 4,855.9 4,704.14 Tubing 2 7/8" 2 7/8 6.40 L -80 153 Yes 31.51 No 4,824.4 4,735.65 Tubing 2 7/8" 2 7/8 6.40 L -80 154 Yes 31.96 No 4,792.4 4,767.61 Tubing 2 7/8" 2 7/8 6.40 L -80 155 Yes 31.99 No 4,760.4 4,799.60 Tubing 2 7/8" 2 7/8 6.40 L -80 156 Yes 30.64 No 4,729.8 4,830.24 Tubing 2 7/8" 2 7/8 6.40 L -80 157 Yes 31.49 No 4,698.3 4,861.73 Tubing 2 7/8" 2 7/8 6.40 L -80 158 Yes 31.99 No 4,666.3 4,893.72 Tubing 2 7/8" 2 7/8 6.40 L -80 159 Yes 32.04 No 4,634.2 4,925.76 Tubing 2 7/8" 2 7/8 6.40 L -80 160 Yes 31.27 No 4,603.0 4,957.03 Tubing 2 7/8" 2 7/8 6.40 L -80 161 Yes 29.91 No 4,573.1 4,986.94 Tubing 2 7/8" 2 7/8 6.40 L -80 162 Yes 31.98 No 4,541.1 5,018.92 Tubing Page 6/12 Report Printed: 6/11/2013 • • PIONEER Tubing Tally NATURAL RESOURCES Des: ESP Recomplete, Set Depth: 9,560.0ftKB Well Name: ODST -45A API/UWI Surface Legal Location License,Lease Number Field Name State 50- 703 - 20577 -01 -00 2889' FSL, 1176' FEL, Sec 11, T13N, R7E, UM 209-079 Oooguruk Unit ALASKA Well Profile Original KB Ebvation (ft) KB -Ground Dstance (ft) KB- Casing Flange Disbnce (ft) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 42.70 42.70 Tubing Run Tally Item Des OD (in) Wt lib/ft) Grade Ref # Run? Len (ft) Centralized? Ext Jewelry Top (ftKB) Cum Len (ft) 2 7/8" 2 7/8 6.40 L -80 163 Yes 31.48 No 4,509.6 5,050.40 Tubing 2 7/8" 2 7/8 6.40 L -80 164 Yes 31.29 No 4,478.3 5,081.69 Tubing 2 7/8" 2 7/8 6.40 L -80 165 Yes 31.47 No • 4,446.8 5,113.16 Tubing 2 7/8" 2 7/8 6.40 L -80 166 Yes 31.30 No 4,415.5 5,144.46 Tubing 2 7/8" 2 7/8 6.40 L -80 167 Yes 31.54 No 4,384.0 5,176.00 Tubing 2 7/8" 2 7/8 6.40 L -80 168 Yes 31.06 No 4,352.9 5,207.06 Tubing 2 7/8" 2 7/8 6.40 L -80 169 Yes 30.14 No 4,322.8 5,237.20 Tubing 2 7/8" 2 7/8 6.40 L -80 170 Yes 31.56 No 4,291.2 5,268.76 Tubing 2 7/8" 2 7/8 6.40 L -80 171 Yes 30.89 No 4,260.4 5,299.65 ' Tubing 2 7/8" 2 7/8 6.40 L -80 172 Yes 29.09 No 4,231.3 5,328.74 Tubing 2 7/8" 2 7/8 6.40 L -80 173 Yes 30.48 No 4,200.8 5,359.22 Tubing 2 7/8" 2 7/8 6.40 L -80 174 Yes 31.50 No 4,169.3 5,390.72 Tubing 2 7/8" 2 7/8 6.40 L -80 175 Yes 24.95 No 4,144.3 5,415.67 Tubing 2 7/8" 2 7/8 6.40 L -80 176 Yes 29.34 No 4,115.0 5,445.01 Tubing 2 7/8" 2 7/8 6.40 L -80 177 Yes 31.54 No 4,083.5 5,476.55 Tubing 2 7/8" 2 7/8 6.40 L -80 178 Yes 30.97 No 4,052.5 5,507.52 Tubing 2 7/8" 2 7/8 6.40 L -80 179 Yes 30.10 No 4,022.4 5,537.62 Tubing 2 7/8" 2 7/8 6.40 L -80 180 Yes 30.46 No 3,991.9 5,568.08 Tubing 2 7/8" 2 7/8 6.40 L -80 181 Yes 30.44 No 3,961.5 5,598.52 Tubing , 2 7/8" 2 7/8 6.40 L -80 182 Yes 29.81 No 3,931.7 5,628.33 Tubing 2 7/8" 2 7/8 6.40 L -80 183 Yes 29.67 No 3,902.0 5,658.00 Tubing 2 7/8" 2 7/8 6.40 L -80 184 Yes 29.90 No 3,872.1 5,687.90 Tubing 2 7/8" 2 7/8 6.40 L -80 185 Yes 30.66 No 3,841.4 5,718.56 Tubing 2 7/8" 2 7/8 6.40 L -80 186 Yes 30.16 No 3,811.3 5,748.72 Tubing 2 7/8" 2 7/8 6.40 L -80 187 Yes 30.48 No 3,780.8 5,779.20 Tubing 2 7/8" 2 7/8 6.40 L -80 188 Yes 30.93 No 3,749.9 5,810.13 Tubing 2 7/8" 2 7/8 6.40 L -80 189 Yes 30.19 No 3,719.7 5,840.32 Tubing 2 7/8" 2 7/8 6.40 L -80 190 Yes 30.80 No 3,688.9 5,871.12 Tubing 2 7/8" 2 7/8 6.40 L -80 191' Yes 30.21 No 3,658.7 5,901.33 Tubing Page 7/12 Report Printed: 6/11/2013 • • PIONEER Tubing Tally NATURAL RESOURCES Des: ESP Recomplete, Set Depth: 9,560.0ftKB Well Name: ODST -45A API /UW Surface Legal Location License/Lease Number Field Name State 50 703 - 20577 - 01 - 00 2889' FSL, 1176' FEL, Sec 11, T13N, R7E, UM 209 Oooguruk Unit ALASKA Well Profile Original KB Ebvalion (ft) KB -Ground Dstance (ft) KB- Casing Flange Distance (ft) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 42.70 42.70 Tubing Run Tally Item Des OD (in) Wt (Ib/ft) Grade Ref# Run? Len (ft) Centralized? Ext Jewelry Top (ftKB) Cum Len (ft) 2 7/8" 2 7/8 6.40 L -80 192 Yes 31.03 No 3,627.6 5,932.36 Tubing 2 7/8" 2 7/8 6.40 L -80 193 Yes 31.51 No 3,596.1 5,963.87 Tubing 2 7/8" 2 7/8 6.40 L -80 194 Yes 29.66 No 3,566.5 5,993.53 Tubing 2 7/8" 2 7/8 6.40 L -80 195 Yes 31.14 No 3,535.3 6,024.67 Tubing 2 7/8" 2 7/8 6.40 L -80 196 Yes 29.63 No 3,505.7 6,054.30 Tubing 2 7/8" 2 7/8 6.40 L -80 197 Yes 29.10 No 3,476.6 6,083.40 Tubing 2 7/8" 2 7/8 6.40 L -80 198 Yes 26.06 No 3,450.5 6,109.46 Tubing 2 7/8" 2 7/8 6.40 L -80 199 Yes 26.23 No 3,424.3 6,135.69 Tubing 2 7/8" 2 7/8 6.40 L -80 200 Yes 27.53 No 3,396.8 6,163.22 Tubing 2 7/8" 2 7/8 6.40 L -80 201 Yes 29.78 No 3,367.0 6,193.00 Tubing 2 7/8" 2 7/8 6.40 L -80 202 Yes 28.20 No 3,338.8 6,221.20 Tubing 2 7/8" 2 7/8 6.40 L -80 203 Yes 30.00 No 3,308.8 6,251.20 Tubing 2 7/8" 2 7/8 6.40 L -80 204 Yes 26.43 No 3,282.4 6,277.63 Tubing 2 7/8" 2 7/8 6.40 L -80 205 Yes 30.15 No 3,252.2 6,307.78 Tubing 2 7/8" 2 7/8 6.40 L -80 206 Yes 29.01 No 3,223.2 6,336.79 Tubing 2 7/8" 2 7/8 6.40 L -80 207 Yes 27.26 No 3,196.0 6,364.05 Tubing 2 7/8" 2 7/8 6.40 L -80 208 Yes 25.31 No 3,170.6 6,389.36 Tubing 2 7/8" 2 7/8 6.40 L -80 209 Yes 26.95 No 3,143.7 6,416.31 Tubing 2 7/8" 2 7/8 6.40 L -80 210 Yes 30.46 No 3,113.2 6,446.77 Tubing 2 7/8" 2 7/8 6.40 L -80 211 Yes 26.29 No 3,086.9 6,473.06 Tubing 2 7/8" 2 7/8 6.40 L -80 212 Yes 28.33 No 3,058.6 6,501.39 Tubing 2 7/8" 2 7/8 6.40 L -80 213 Yes 29.23 No 3,029.4 6,530.62 Tubing 2 7/8" 2 7/8 6.40 L -80 214 Yes 31.03 No 2,998.4 6,561.65 Tubing 2 7/8" 2 7/8 6.40 L -80 215 Yes 29.86 No 2,968.5 6,591.51 Tubing 2 7/8" 2 7/8 6.40 L -80 216 Yes 29.79 No 2,938.7 6,621.30 Tubing 2 7/8" 2 7/8 6.40 L -80 217 Yes 25.64 No 2,913.1 6,646.94 Tubing 2 7/8" 2 7/8 6.40 L -80 218 Yes 30.97 No 2,882.1 6,677.91 Tubing 2 7/8" 2 7/8 6.40 L -80 219 Yes 30.83 No 2,851.3 6,708.74 Tubing 2 7/8" 2 7/8 6.40 L -80 220 Yes 29.69 No 2,821.6 6,738.43 Tubing Page 8/12 Report Printed: 6/11/2013 • • PIONEER Tubing Tally NATURAL RESOURCES Des: ESP Recomplete, Set Depth: 9,560.0ftKB Well Name: ODST -45A API /UWI Surface Legal Location License/Lease Number Field Name State 50-703-20577-01 -00 2889' FSL, 1176' FEL, Sec 11, T13N, R7E, UM 209-079 Oooguruk Unit ALASKA Well Profile Original KB Et)vation (ft) KB -Ground Dstance (ft) KB- Casing Flange Dis:nce (ft) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 42.70 42.70 Tubing Run Tally Item Des OD (in) Wt pbtft) Grade Ref # Run? Len (ft) Centralized? Ext Jawehy Top (ftKB) Cum Len (ft) 2 7/8" 2 7/8 6.40 L -80 221 Yes 26.08 No 2,795.5' 6,764.51 Tubing 2 7/8" 2 7/8 6.40 L -80 222 Yes 29.49 No 2,766.0 6,794.00 Tubing 2 7/8" 2 7/8 6.40 L -80 223 Yes 26.18 No 2,739.8 6,820.18 Tubing 2 7/8" 2 7/8 6.40 L -80 224 Yes 29.70 No 2,710.1 6,849.88 Tubing 2 7/8" 2 7/8 6.40 L -80 225 Yes 26.43 No 2,683.7 6,876.31 Tubing 2 7/8" Pup 2 7/8 6.40 L -80 Yes 5.80 No 2,677.9 6,882.11 Joint 2.875" x 1.5" 2 7/8 6.40 L -80 Yes 9.16 No 2,668.7 6,891.27 GLM w /dummy valve 2 7/8" Pup 2 7/8 6.40 L -80 Yes 5.81 No 2,662.9 6,897.08 Joint 2 7/8" 2 7/8 6.40 L -80 226 Yes 25.53 No 2,637.4 6,922.61 Tubing X -O Pup 2 7/8 6.40 L -80 Yes 4.71 No 2,632.7 6,927.32 Joint WFT 2 7/8 6.40 L -80 Yes 4.86 No 2,627.8 6,932.18 Hydrow II Pkr X -O Pup 2 7/8 6.40 L -80 Yes 15.23 No 2,612.6 6,947.41 Joint 2 7/8" 2 7/8 6.40 L -80 227 Yes 29.02 No 2,583.6 6,976.43 Tubing 2 7/8" Pup 2 7/8 6.40 L -80 Yes 5.80 No 2,577.8 6,982.23 Joint X nipple with 2 7/8 6.40 L -80 Yes 1.30 No 2,576.5 6,983.53 2.313" profile 2 7/8" Pup 2 7/8 6.40 L -80 Yes 5.83 No 2,570.6 6,989.36 Joint 2 7/8" 2 7/8 6.40 L -80 228 Yes 25.89 No 2,544.8 7,015.25 Tubing 2 7/8" Pup 2 7/8 6.40 L -80 Yes 5.82 No 2,538.9 7,021.07 Joint 2.875" x 1.5" 2 7/8 6.40 L -80 Yes 9.17 No 2,529.8 7,030.24 GLM w /dummy valve 2 7/8" Pup 2 7/8 6.40 L -80 Yes 5.81 No 2,524.0 7,036.05 Joint 2 7/8" 2 7/8 6.40 L -80 229 Yes 29.98 No 2,494.0 7,066.03 Tubing 2 7/8" 2 7/8 6.40 L -80 230 Yes 26.14 No 2,467.8 7,092.17 Tubing 2 7/8" 2 7/8 6.40 L -80 231 Yes 31.52 No 2,436.3 7,123.69 Tubing 2 7/8" 2 7/8 6.40 L -80 232 Yes 26.31 No 2,410.0 7,150.00 Tubing 2 7/8" 2 7/8 6.40 L -80 233 Yes 26.02 No 2,384.0 7,176.02 Tubing 2 7/8" 2 7/8 6.40 L -80 234 Yes 30.89 No 2,353.1 7,206.91 Tubing 2 7/8" 2 7/8 6.40 L -80 235 Yes 26.39 No 2,326.7 7,233.30 Tubing Page 9/12 Report Printed: 6/11/2013 • • PIONEER Tubing Tally NATURAL RESOURCES Des: ESP Recomplete, Set Depth: 9,560.0ftKB Well Name: ODST -45A API /UWI Surface Legal Location License/LeaseNumber Field Name State 50- 703 - 20577 -01 -00 2889' FSL, 1176' FEL, Sec 11, T13N, R7E, UM 209 -079 Oooguruk Unit ALASKA Well Profile Original KB Etavation (ft) KB- Ground ['stance (ft) KB- Casing Flange Distance (ft) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 42.70 42.70 Tubing Run Tally Bern Des OD (in) Wt ( ) Grade Ref # Run? Len (ft) Centralized? Ext Top (ftKB) Cum Len (ft) 2 7/8" 2 7/8 6.40 L -80 236 Yes 27.10 No 2,299.6 7,260.40 Tubing 2 7/8" 2 7/8 6.40 L -80 237 Yes 27.77 No 2,271.8 7,288.17 Tubing 2 7/8" 2 7/8 6.40 L -80 238 Yes 30.44 No 2,241.4 7,318.61 Tubing 2 7/8" 2 7/8 6.40 L -80 239 Yes 31.99 No 2,209.4 7,350.60 Tubing 2 7/8" 2 7/8 6.40 L -80 240 Yes 27.84 No 2,181.6 7,378.44 Tubing 2 7/8" 2 7/8 6.40 L -80 241 Yes 30.94 No 2,150.6 7,409.38 Tubing 2 7/8" 2 7/8 6.40 L -80 242 Yes 30.95 No 2,119.7 7,440.33 Tubing 2 7/8" 2 7/8 6.40 L -80 243 Yes 29.33 No 2,090.3 7,469.66 Tubing 2 7/8" 2 7/8 6.40 L -80 244 Yes 26.92 No 2,063.4 7,496.58 Tubing 2 7/8" 2 7/8 6.40 L -80 245 Yes 27.78 No 2,035.6 7,524.36 Tubing 2 7/8" Pup 2 7/8 6.40 L -80 Yes 5.81 No 2,029.8 7,530.17 Joint Tubing 2 7/8 6.40 L -80 Yes 4.75 No 2,025.1 7,534.92 Retrievable SSSV 2 7/8" Pup 2 7/8 6.40 L -80 Yes 5.78 No 2,019.3 7,540.70 Joint 2 7/8" 2 7/8 6.40 L -80 246 Yes 27.68 No 1,991.6 7,568.38 Tubing 2 7/8" 2 7/8 6.40 L -80 247 Yes 27.00 No 1,964.6 7,595.38 Tubing 2 7/8" 2 7/8 6.40 L -80 248 Yes 30.26 No 1,934.4 7,625.64 Tubing 2 7/8" 2 7/8 6.40 L -80 249 Yes 30.45 No 1,903.9 7,656.09 Tubing 2 7/8" 2 7/8 6.40 L -80 250 Yes 30.94 No 1,873.0 7,687.03 1 Tubing 2 7/8" 2 7/8 6.40 L -80 251 Yes 28.82 No 1,844.2 7,715.85 Tubing 2 7/8" 2 7/8 6.40 L -80 252 Yes 30.96 No 1,813.2 7,746.81 Tubing 2 7/8" 2 7/8 6.40 L -80 253 Yes 30.14 No 1,783.1 7,776.95 Tubing 2 7/8" 2 7/8 6.40 L -80 254 Yes 30.52 No 1,752.5 7,807.47 Tubing 2 7/8" 2 7/8 6.40 L -80 255 Yes 30.47 No 1,722.1 7,837.94 Tubing 2 7/8" 2 7/8 6.40 L -80 256 Yes 30.48 No 1,691.6 7,868.42 Tubing 2 7/8" 2 7/8 6.40 L -80 257 Yes 30.45 No 1,661.1 7,898.87 Tubing 2 7/8" 2 7/8 6.40 L -80 258 Yes 30.44 No 1,630.7 7,929.31 Tubing 2 7/8" 2 7/8 6.40 L -80 259 Yes 30.53 No 1,600.2 7,959.84 Tubing 2 7/8" 2 7/8 6.40 L -80 260 Yes 30.52 No 1,569.6 7,990.36 Tubing 2 7/8" 2 7/8 6.40 L -80 261 Yes 30.39 No 1,539.3 8,020.75 Tubing Page 10/12 Report Printed: 6/11/2013 • • PIONEER Tubing Tally NATURAL RESOURCES Des: ESP Recomplete, Set Depth: 9,560.0ftKB Well Name: ODST -45A APVUWI Surface Legal Location License/Lease Number Field Name State 50- 703 - 20577 -01 -00 2889' FSL, 1178' FEL, Sec 11, T13N, R7E, UM 209 -079 Oooguruk Unit ALASKA Well Profile Original KB Eavaton (ft) KB -Ground Dstance (ft) KB- Casing Flange Disbnce (ff) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 42.70 42.70 Tubing Run Tally Item Des OD (in) Wt (lb/ft) Grade Ref* Run? Len (B) Centralized? E1d Jemally Top (ftKB) Cum Len (o) 2 7/8" 2 7/8 6.40 L -80 262 Yes 30.97 No 1,508.3 8,051.72 Tubing 2 7/8" 2 7/8 6.40 L -80 263 Yes 30.50 No 1,477.8 8,082.22 Tubing 2 7/8" 2 7/8 6.40 L -80 264 Yes 30.92 No 1,446.9 8,113.14 Tubing 2 7/8" 2 7/8 6.40 L -80 265 Yes 30.98 No 1,415.9 8,144.12 Tubing 2 7/8" 2 7/8 6.40 L -80 266 Yes 30.49 No 1,385.4 8,174.61 Tubing 2 7/8" 2 7/8 6.40 L -80 267 Yes 30.55 No 1,354.8 8,205.16 Tubing 2 7/8" 2 7/8 6.40 L -80 268 Yes 30.22 No 1,324.6 8,235.38 Tubing 2 7/8" 2 7/8 6.40 L -80 269 Yes 30.73 No 1,293.9 8,266.11 Tubing 2 7/8" 2 7/8 6.40 L -80 270 Yes 30.28 No 1,263.6 8,296.39 Tubing 2 7/8" 2 7/8 6.40 L -80 271 Yes 30.96 No 1,232.7 8,327.35 Tubing 2 7/8" 2 7/8 6.40 L -80 272 Yes 30.17 No 1,202.5 8,357.52 Tubing 2 7/8" 2 7/8 6.40 L -80 273 Yes 30.99 No 1,171.5 8,388.51 Tubing 2 7/8" 2 7/8 6.40 L -80 274 Yes 30.49 No 1,141.0 8,419.00 Tubing 2 7/8" 2 7/8 6.40 L -80 275 Yes 28.83 No 1,112.2 8,447.83 Tubing 2 7/8" 2 7/8 6.40 L -80 276 Yes 30.85 No 1,081.3 8,478.68 Tubing 2 7/8" 2 7/8 6.40 L -80 277 Yes 29.88 No 1,051.4 8,508.56 Tubing 2 7/8" 2 7/8 6.40 L -80 278 Yes 30.46 No 1,021.0 8,539.02 Tubing 2 7/8" 2 7/8 6.40 L -80 279 Yes 31.52 No 989.5 8,570.54 Tubing 2 7/8" 2 7/8 6.40 L -80 280 Yes 30.81 No 958.7 8,601.35 Tubing 2 7/8" 2 7/8 6.40 L -80 281 Yes 31.02 No 927.6 8,632.37 Tubing 2 7/8" 2 7/8 6.40 L -80 282 Yes 31.50 No 896.1 8,663.87 Tubing 2 7/8" 2 7/8 6.40 L -80 283 Yes 31.52 No 864.6 8,695.39 Tubing 2 7/8" 2 7/8 6.40 L -80 284 Yes 30.91 No 833.7 8,726.30 Tubing 2 7/8" 2 7/8 6.40 L -80 285 Yes 30.89 No 802.8 8,757.19 Tubing 2 7/8" 2 7/8 6.40 L -80 286 Yes 30.13 No 772.7 8,787.32 Tubing 2 7/8" 2 7/8 6.40 L -80 287 Yes 30.48 No 742.2 8,817.80 Tubing 2 7/8" 2 7/8 6.40 L -80 288 Yes 30.53 No 711.7 8,848.33 Tubing 2 7/8" 2 7/8 6.40 L -80 289 Yes 26.43 No 685.2 8,874.76 Tubing 2 7/8" 2 7/8 6.40 L -80 290 Yes 29.08 No 656.2 8,903.84 Tubing Page 11/12 Report Printed: 6/11/2013 • • PIONEER Tubing Tally NATURAL RESOURCES Des: ESP Recomplete, Set Depth: 9,560.0ftKB Well Name: ODST -45A API /UWI Surface Legal Location License/Lease Number Field Name State ' 50- 703 - 20577 -01 -00 2889' FSL, 1176' FEL, Sec 11, T13N, R7E, UM 209-079 Oooguruk Unit ALASKA Well Profile Original KB Ebvaton (ft) KB -Ground Dstance (ft) KB- Casing Flange Disence (ft) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 42.70 42.70 Tubing Run Tally Item Des OD (In) Wt Qb/ft) Grade Ref # Run? Len (ft) Centralized? Ext Jewelry Top MKS) Cum Len (B) 2 7/8" 2 7/8 6.40 L -80 291 Yes 29.70 No 626.5 8,933.54 Tubing 2 7/8" 2 7/8 6.40 L -80 292 Yes 25.86 No 600.6 8,959.40 Tubing 2 7/8" 2 7/8 6.40 L -80 293 Yes 27.90 No 572.7 8,987.30 Tubing 2 7/8" 2 7/8 6.40 L -80 29.4 Yes 30.90 No 541.8 9,018.20 Tubing 2 7/8" 2 7/8 6.40 L -80 295 Yes 30.41 No 511.4 9,048.61 Tubing 2 7/8" 2 7/8 6.40 L -80 296 Yes 30.86 No 480.5 9,079.47 Tubing 2 7/8" 2 7/8 6.40 L -80 297 Yes 30.75 No 449.8 9,110.22 Tubing 2 7/8" 2 7/8 6.40 L -80 298 Yes 26.50 No 423.3 9,136.72 Tubing 2 7/8" 2 7/8 6.40 L -80 299 Yes 31.10 No 392.2 9,167.82 Tubing 2 7/8" 2 7/8 6.40 L -80 300 Yes 31.52 No 360.7 9,199.34 Tubing 2 7/8" 2 7/8 6.40 L -80 301 Yes 31.50 No 329.2 9,230.84 Tubing 2 7/8" 2 7/8 6.40 L -80 302 Yes 31.52 No 297.6 9,262.36 Tubing 2 7/8" 2 7/8 6.40 L -80 303 Yes 31.49 No 266.2 9,293.85 Tubing 2 7/8" 2 7/8 6.40 L -80 304 Yes 27.49 No 238.7 9,321.34 Tubing 2 7/8" 2 7/8 6.40 L -80 305 Yes 31.53 No 207.1 9,352.87 Tubing 2 7/8" 2 7/8 6.40 L -80 306 Yes 31.54 No 175.6 9,384.41 Tubing 2 7/8" 2 7/8 6.40 L -80 307 Yes 24.36 No 151.2 9,408.77 Tubing 2 7/8" 2 7/8 6.40 L -80 308 Yes 31.53 No 119.7 9,440.30 Tubing 2 7/8" 2 7/8 6.40 L -80 309 Yes 27.32 No 92.4 9,467.62 Tubing 2 7/8" 2 7/8 6.40 L -80 310 Yes 27.04 No 65.3 9,494.66 Tubing 2 7/8" 2 7/8 6.40 L -80 311 Yes 23.27 No 42.1 9,517.93 Tubing X -O Pup 2 7/8 6.40 L -80 Yes 0.92 No 41.1 9,518.85 Joint 3 1/2" Pup 2 7/8 6.40 L -80 Yes 7.36 No 33.8 9,526.21 Joint VG tubing 2 7/8 6.40 L -80 Yes 1.54 No 32.2 9,527.75 hanger Page 12/12 Report Printed: 6/11/2013 • • Well Planning - Pioneer - Oooguruk Oooguruk Development Oooguruk Drill Site ODSN -45A Permit to Drill: 2090790 API: 507032057701 Sperry Drilling Services Definitive Survey Report 03 November, 2009 HALLIBURTON Sperry Drilling Services 1 • • Halliburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co-ordinate Reference: Well ODSN -45A - Slot ODS-45 Project: Oooguruk Development TVD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 © 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference:. True Wellbore: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Project Oooguruk Development Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well ODSN -45A - Slot ODS-45 Well Position +N /-S 0.00 ft Northing: 6,031,005.53 ft Latitude: 70° 29' 44.804 N +E / -W 0.00 ft Easting: 469,821.86 ft Longitude: 150° 14' 48.349 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 13.50ft Wellbore ODSN -45A Magnetics Model Name Sample Date Declination Dip Angle Field Strength ( ( (nT) IGRF200510 10/2/2009 22.10 80.81 57,749 Design ODSN -45A Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 10,035.40 Vertical Section: Depth From (TVD) +N{{}}/ -S +EI-W Direction (ft) (ft) (ft) ( 42.70 0.00 0.00 290.00 Survey Program Date 11/3/2009 From To (ft) (ft) Survey (Welibore) Tool Name Description Survey Date 50.00 533.00 ODSN -45i 1N13 PB1 Gyro (ODSN -45i IN SR- Gyro -SS Fixed:v2:surtace readout gyro single shot 1/13/2009 t 533.00 10,035.40 ODSN -45i 1N13 PB1 MWD (ODSN -45i Ifs MWD +IFR2 +MS +sag Fixed:v2:IIFR dec & 3 -axis correction + sag 1/13/2009 1: 10,049.98 10,191.98 ODSN -45A Gyro (ODSN -45A) NS- Gyro -MS Fixed:v2:North- seeking gyro multishot 10/3/2009 1: 10,259.91 15,393.08 ODSN -45A MWD (ODSN -45A) MWD +IFR2 +MS +sag Fixed:v2:IIFR dec & 3 -axis correction + sag 10/4/2009 1: Survey Map Map Vertical MD Inc Azi TVD TVDSS +N /-S +E/-W Northing Eng DLS Section (ft) (°) ( (ft) (ft) (ft) (R) (ft) (ft) (°Moo') (ft) Survey Tool Name 42.70 0.00 0.00 42.70 -13.50 0.00 0.00 6,031,005.53 469,821.86 0.00 0.00 UNDEFINED 50.00 0.30 141.13 50.00 -6.20 -0.01 0.01 6,031,005.52 469,821.87 4.11 -0.02 SR- Gyro-SS (1) 100.00 0.30 191.03 100.00 43.80 -0.25 0.07 6,031,005.28 469,821.93 0.51 -0.15 SR- Gyro-SS (1) 168.00 0.50 165.94 168.00 111.80 -0.71 0.11 6,031,004.82 469,821.96 0.38 -0.34 SR- Gyro-SS (1) 197.00 0.48 148.51 197.00 140.80 -0.93 0.20 6,031,004.60 469,822.06 0.52 -0.51 SR- Gyro-SS (1) 228.00 0.59 198.76 228.00 171.80 -1.20 0.22 6,031,004.33 469,822.07 1.50 -0.61 SR- Gyro -SS (1) 258.00 0.58 166.67 257.99 201.79 -1.49 0.20 6,031,004.04 469,822.06 1.08 -0.70 SR- Gyro-SS (1) 288.00 0.68 167.36 287.99 231.79 -1.81 0.28 6,031,003.72 469,822.13 0.33 -0.88 SR- Gyro-SS (1) 321.00 0.98 173.11 320.99 264.79 -2.28 0.35 6,031,003.25 469,822.20 0.94 -1.11 SR- Gyro-SS (1) 351.00 1.08 175.74 350.98 294.78 -2.82 0.41 6,031,002.71 469,822.25 0.37 -1.35 SR- Gyro-SS (1) 382.00 1.32 178.28 381.98 325.78 -3.47 0.44 6,031,002.06 469,822.28 0.79 -1.60 SR- Gyro -SS (1) 11/3/2009 2:48:59PM Page 2 COMPASS 2003.16 Build 71 • • Halliburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -45A - Slot ODS-45 Project: Oooguruk Development TVD Reference: 42.7' + 13.5 © 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 © 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference: True Wellbore: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +EI -W Northing Easting DLS Section (ft) ( (°) (ft) (ft) (ft) (ft) (ft) (ft) ( °l100') (ft) Survey Tool Name 413.00 1.75 179.15 412.96 356.77 -4.30 0.46 6,031,001.23 469,822.30 1.39 -1.90 SR- Gyro-SS (1) 443.00 2.13 178.74 442.95 386.75 -5.31 0.47 6,031,000.22 469,822.31 1.27 -2.26 SR- Gyro -SS(1) 533.00 2.88 180.19 532.86 476.66 -9.25 0.50 6,030,996.28 469,822.33 0.84 -3.64 SR- Gyro-SS (1) 575.40 2.94 174.16 575.21 519.01 -11.39 0.61 6,030,994.14 469,822.42 0.74 -4.47 MWD +IFR2 +MS +sag (2) 670.40 3.91 162.96 670.04 613.84 -16.91 1.81 6,030,988.61 469,823.60 1.24 -7.48 MWD +IFR2 +MS +sag (2) 764.70 5.03 162.67 764.05 707.85 -23.93 3.98 6,030,981.58 469,825.74 1.19 -11.93 MWD +IFR2 +MS +sag (2) 859.30 5.77 161.44 858.23 802.03 -32.40 6.73 6,030,973.10 469,828.46 0.79 -17.41 MWD +IFR2 +MS +sag (2) 954.90 5.70 160.56 953.35 897.15 -41.43 9.84 6,030,964.06 469,831.53 0.12 -23.42 MWD +IFR2 +MS +sag (2) 1,049.20 7.62 163.09 1,047.01 990.81 -51.83 13.22 6,030,953.65 469,834.87 2.06 -30.15 MWD +IFR2 +MS +sag (2) 1,143.50 8.56 164.80 1,140.37 1,084.17 -64.59 16.88 6,030,940.88 469,838.47 1.03 -37.95 MWD +IFR2 +MS +sag (2) 1,238.70 9.80 165.71 1,234.35 1,178.15 -79.28 20.73 6,030,926.18 469,842.27 1.31 -46.60 MWD +IFR2 +MS +sag (2) 1,334.70 11.30 167.74 1,328.72 1,272.52 -96.39 24.75 6,030,909.05 469,846.21 1.61 -56.22 MWD +IFR2 +MS +sag (2) 1,428.60 13.21 170.21 1,420.48 1,364.28 - 115.95 28.53 6,030,889.48 469,849.91 2.11 -66.46 MWD +IFR2 +MS +sag (2) 1,523.55 12.76 171.01 1,513.00 1,456.80 - 137.00 32.01 6,030,868.42 469,853.31 0.51 -76.94 MWD +IFR2 +MS +sag (2) 1,618.50 13.98 172.54 1,605.37 1,549.17 - 158.73 35.14 6,030,846.68 469,856.35 1.34 -87.31 MWD +IFR2 +MS +sag (2) 1,712.90 14.83 172.59 1,696.81 1,640.61 - 182.01 38.18 6,030,823.38 469,859.29 0.90 -98.13 MWD +IFR2 +MS +sag (2) 1,808.20 16.36 172.06 1,788.59 1,732.39 - 207.40 41.60 6,030,797.98 469,862.62 1.61 - 110.03 MWD +IFR2 +MS +sag (2) 1,902.60 18.07 178.03 1,878.77 1,822.57 - 235.21 43.94 6,030,770.17 469,864.84 2.60 - 121.74 MWD +IFR2 +MS +sag (2) 1,999.40 21.10 181.35 1,969.96 1,913.76 - 267.64 44.05 6,030,737.74 469,864.82 3.33 - 132.93 MWD +IFR2 +MS +sag (2) 2,093.80 24.37 188.46 2,057.03 2,000.83 - 303.91 40.78 6,030,701.49 469,861.40 4.52 - 142.26 MWD +IFR2 +MS +sag (2) 2,187.50 25.30 191.15 2,142.07 2,085.87 - 342.67 34.07 6,030,662.76 469,854.53 1.56 - 149.21 MWD +IFR2 +MS +sag (2) 2,282.30 28.06 195.13 2,226.77 2,170.57 - 384.08 24.33 6,030,621.39 469,844.62 3.47 - 154.22 MWD +IFR2 +MS +sag (2) 2,326.00 29.70 195.74 2,265.04 2,208.84 - 404.43 18.71 6,030,601.07 469,838.92 3.81 - 155.90 MWD +IFR2 +MS +sag (2) 2,377.20 32.48 198.82 2,308.88 2,252.68 - 429.65 10.83 6,030,575.88 469,830.94 6.25 - 157.13 MWD +IFR2 +MS +sag (2) 2,424.00 34.60 199.84 2,347.89 2,291.69 - 454.05 2.26 6,030,551.52 469,822.28 4.69 - 157.42 MWD +IFR2 +MS +sag (2) 2,472.50 36.16 200.43 2,387.43 2,331.23 - 480.41 -7.40 6,030,525.20 469,812.51 3.29 - 157.35 MWD +IFR2 +MS +sag (2) 2,566.59 39.82 202.47 2,461.58 2,405.38 - 534.29 -28.62 6,030,471.41 469,791.08 4.11 - 155.85 MWD +IFR2 +MS +sag (2) 2,659.39 43.52 202.62 2,530.89 2,474.69 - 591.26 -52.27 6,030,414.55 469,767.19 3.99 - 153.10 MWD +IFR2 +MS +sag (2) 2,698.99 44.79 203.91 2,559.30 2,503.10 - 616.60 -63.17 6,030,389.25 469,756.19 3.93 - 151.53 MWD +IFR2 +MS +sag (2) 2,752.29 48.34 205.85 2,595.94 2,539.74 - 651.69 -79.47 6,030,354.23 469,739.76 7.17 - 148.22 MWD +IFR2 +MS +sag (2) 2,805.09 49.84 207.14 2,630.52 2,574.32 - 687.40 -97.27 6,030,318.60 469,721.81 3.39 - 143.70 MWD +IFR2 +MS +sag (2) 2,848.99 51.64 207.46 2,658.30 2,602.10 - 717.61 - 112.86 6,030,288.46 469,706.10 4.14 - 139.38 MWD +IFR2 +MS +sag (2) 2,943.19 53.16 207.96 2,715.77 2,659.57 - 783.68 - 147.57 6,030,222.54 469,671.13 1.67 - 129.36 MWD +IFR2 +MS +sag (2) 3,040.19 55.15 209.57 2,772.57 2,716.37 - 852.59 - 185.41 6,030,153.79 469,633.00 2.45 - 117.37 MWD +IFR2 +MS +sag (2) 3,133.79 57.80 210.63 2,824.27 2,768.07 - 920.08 - 224.55 6,030,086.46 469,593.60 2.98 - 103.68 MWD +IFR2 +MS +sag (2) 3,229.59 59.33 210.06 2,874.23 2,818.03 - 990.62 - 265.84 6,030,016.09 469,552.02 1.68 -89.00 MWD +IFR2 +MS +sag (2) 3,323.39 61.07 209.65 2,920.84 2,864.64 - 1,061.21 - 306.36 6,029,945.67 469,511.23 1.89 -75.07 MWD +IFR2 +MS +sag (2) 3,417.39 64.24 210.67 2,964.02 2,907.82 - 1,133.39 - 348.31 6,029,873.68 469,468.99 3.51 -60.34 MWD +IFR2 +MS +sag (2) 3,465.29 65.89 210.86 2,984.21 2,928.01 - 1,170.71 - 370.53 6,029,836.45 469,446.62 3.46 -52.22 MWD +IFR2 +MS +sag (2) 3,512.29 69.49 210.64 3,002.05 2,945.85 - 1,208.07 - 392.76 6,029,799.18 469,424.24 7.67 -44.12 MWD +IFR2 +MS +sag (2) 11/3/2009 2:48:59PM Page 3 COMPASS 2003.16 Build 71 i • Halliburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co -ordinate Reference: Well ODSN -45A - Slot ODS -45 Project Oooguruk Development TVD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 © 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference: True Weilbore: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E/ -W Northing Easting DLS Section (ft) ( ( (ft) (ft) (ft) (ft) (ft) (ft) ( °1100') (ft) Survey Tool Name 3,559.99 71.29 209.81 3,018.06 2,961.86 - 1,246.90 - 415.37 6,029,760.45 469,401.47 4.11 -36.14 MWD +IFR2 +MS +sag (2) 3,607.69 73.43 210.51 3,032.51 2,976.31 - 1,286.20 - 438.21 6,029,721.25 469,378.48 4.70 -28.12 MWD +IFR2 +MS +sag (2) 3,700.79 73.49 209.15 3,059.02 3,002.82 - 1,363.62 - 482.60 6,029,644.02 469,333.77 1.40 -12.89 MWD +IFR2 +MS +sag (2) 3,797.59 75.67 213.26 3,084.76 3,028.56 - 1,443.40 - 530.95 6,029,564.44 469,285.11 4.67 5.26 MWD +IFR2 +MS +sag (2) 3,892.09 75.67 212.88 3,108.15 3,051.95 - 1,520.13 - 580.91 6,029,487.92 469,234.84 0.39 25.96 MWD +IFR2 +MS +sag (2) 3,986.89 74.92 215.00 3,132.22 3,076.02 - 1,596.19 - 632.10 6,029,412.07 469,183.35 2.30 48.05 MWD +IFR2 +MS +sag (2) 4,081.09 74.82 216.86 3,156.81 3,100.61 - 1,669.82 - 685.46 6,029,338.67 469,129.70 1.91 73.01 MWD +IFR2 +MS +sag (2) 4,175.99 73.20 216.32 3,182.95 3,126.75 - 1,743.07 - 739.84 6,029,265.65 469,075.03 1.79 99.05 MWD +IFR2 +MS +sag (2) 4,268.49 72.50 218.38 3,210.23 3,154.03 - 1,813.33 - 793.45 6,029,195.62 469,021.13 2.26 125.41 MWD +IFR2 +MS +sag (2) 4,365.09 71.06 219.72 3,240.43 3,184.23 - 1,884.59 - 851.25 6,029,124.60 468,963.05 1.99 155.35 MWD +IFR2 +MS +sag (2) 4,458.59 70.94 218.34 3,270.87 3,214.67 - 1,953.26 - 906.92 6,029,056.16 468,907.10 1.40 184.18 MWD +IFR2 +MS +sag (2) 4,554.79 70.77 219.77 3,302.43 3,246.23 - 2,023.83 - 964.18 6,028,985.83 468,849.57 1.42 213.84 MWD +IFR2 +MS +sag (2) 4,648.49 71.10 218.30 3,333.03 3,276.83 - 2,092.62 - 1,019.95 6,028,917.28 468,793.52 1.52 242.73 MWD +IFR2 +MS +sag (2) 4,744.59 71.00 217.70 3,364.24 3,308.04 - 2,164.24 - 1,075.91 6,028,845.89 468,737.28 0.60 270.81 MWD +IFR2 +MS +sag (2) 4,839.59 70.69 218.10 3,395.41 3,339.21 - 2,235.05 - 1,131.04 6,028,775.31 468,681.87 0.51 298.39 MWD +IFR2 +MS +sag (2) 4,931.39 71.44 218.07 3,425.20 3,369.00 - 2,303.40 - 1,184.60 6,028,707.19 468,628.04 0.82 325.35 MWD +IFR2 +MS +sag (2) 5,012.77 71.57 218.31 3,451.02 3,394.82 - 2,364.05 - 1,232.31 6,028,646.73 468,580.08 0.32 349.44 MWD +IFR2 +MS +sag (2) 5,105.27 70.97 217.33 3,480.72 3,424.52 - 2,433.25 - 1,286.03 6,028,577.76 468,526.09 1.19 376.25 MWD +IFR2 +MS +sag (2) 5,202.47 70.78 216.37 3,512.57 3,456.37 - 2,506.74 - 1,341.10 6,028,504.50 468,470.72 0.95 402.87 MWD +IFR2 +MS +sag (2) 5,292.26 71.43 216.16 3,541.64 3,485.44 - 2,575.23 - 1,391.35 6,028,436.22 468,420.20 0.76 426.66 MWD +IFR2 +MS +sag (2) 5,393.87 72.60 214.62 3,573.02 3,516.82 - 2,654.02 - 1,447.32 6,028,357.67 468,363.92 1.84 452.31 MWD +IFR2 +MS +sag (2) 5,489.91 72.80 213.99 3,601.58 3,545.38 - 2,729.76 - 1,499.00 6,028,282.14 468,311.94 0.66 474.96 MWD +IFR2 +MS +sag (2) 5,577.52 72.79 214.00 3,627.49 3,571.29 - 2,799.15 - 1,545.79 6,028,212.96 468,264.87 0.02 495.20 MWD +IFR2 +MS +sag (2) 5,673.74 72.92 213.93 3,655.86 3,599.66 - 2,875.41 - 1,597.16 6,028,136.92 468,213.20 0.15 517.39 MWD +IFR2 +MS +sag (2) 5,773.16 72.72 211.84 3,685.23 3,629.03 - 2,955.16 - 1,648.73 6,028,057.38 468,161.31 2.02 538.57 MWD +IFR2 +MS +sag (2) 5,868.29 72.53 210.72 3,713.63 3,657.43 - 3,032.75 - 1,695.87 6,027,979.99 468,113.87 1.14 556.33 MWD +IFR2 +MS +sag (2) 5,962.54 72.20 211.00 3,742.19 3,685.99 - 3,109.86 - 1,741.94 6,027,903.08 468,067.48 0.45 573.25 MWD +IFR2 +MS +sag (2) 6,057.34 72.53 212.72 3,770.91 3,714.71 - 3,186.59 - 1,789.62 6,027,826.55 468,019.49 1.76 591.82 MWD +IFR2 +MS +sag (2) 6,151.53 72.92 211.27 3,798.88 3,742.68 - 3,262.86 - 1,837.28 6,027,750.47 467,971.53 1.53 610.51 MWD +IFR2 +MS +sag (2) 6,247.50 72.48 211.27 3,827.42 3,771.22 - 3,341.18 - 1,884.84 6,027,672.36 467,923.66 0.46 628.42 MWD +IFR2 +MS +sag (2) 6,340.48 72.26 212.99 3,855.58 3,799.38 - 3,416.22 - 1,931.96 6,027,597.52 467,876.24 1.78 647.04 MWD +IFR2 +MS +sag (2) 6,434.78 72.46 211.57 3,884.16 3,827.96 - 3,492.19 - 1,979.96 6,027,521.75 467,827.94 1.45 666.15 MWD +IFR2 +MS +sag (2) 6,529.17 72.54 211.31 3,912.54 3,856.34 - 3,569.00 - 2,026.91 6,027 ,445 .14 467,780.68 0.28 684.00 MWD +IFR2 +MS +sag (2) 6,623.98 72.35 212.08 3,941.14 3,884.94 - 3,645.91 - 2,074.40 6,027 ,368 .43 467,732.88 0.80 702.33 MWD +IFR2 +MS +sag (2) 6,720.34 71.83 213.74 3,970.78 3,914.58 - 3,722.88 - 2,124.22 6,027,291.67 467,682.76 1.73 722.81 MWD +IFR2 +MS +sag (2) 6,814.39 71.76 214.87 4,000.16 3,943.96 - 3,796.68 - 2,174.57 6,027,218.08 467,632.11 1.14 744.88 MWD +IFR2 +MS +sag (2) 6,908.91 71.70 215.49 4,029.79 3,973.59 - 3,870.05 - 2,226.28 6,027,144.94 467,580.11 0.63 768.39 MWD +IFR2 +MS +sag (2) 7,004.56 71.68 215.84 4,059.84 4,003.64 - 3,943.82 - 2,279.22 6,027,071.38 467,526.87 0.35 792.90 MWD +IFR2 +MS +sag (2) 7,100.29 72.01 215.80 4,089.67 4,033.47 - 4,017.58 - 2,332.46 6,026,997.85 467,473.34 0.35 817.70 MWD +IFR2 +MS +sag (2) 7,193.34 72.53 215.54 4,118.01 4,061.81 - 4,089.58 - 2,384.14 6,026,926.07 467,421.37 0.62 841.64 MWD +IFR2 +MS +sag (2) 11/3/2009 2:48:59PM Page 4 COMPASS 2003.16 Build 71 Halliburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -45A - Slot ODS-45 Project: Oooguruk Development TVD Reference: 42.7' + 13.5 © 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Well: ODSN - 45A North Reference: True Wellbore: ODSN - 45A Survey Calculation Method: Minimum Curvature Design: ODSN - 45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical MD Inc Azi TVD TVDSS +N1S +E! -W Northing Easting DLS Section (ft) ( °) (°) (ft) (ft) (ft) (ft) (ft) (ft) ( (ft) Survey Tool Name 7,288.68 72.40 215.89 4,146.73 4,090.53 - 4,163.39 - 2,437.21 6,026,852.48 467,368.01 0.38 866.26 MWD +IFR2 +MS +sag (2) 7,382.88 72.80 215.45 4,174.90 4,118.70 - 4,236.42 - 2,489.63 6,026,779.67 467,315.30 0.62 890.54 MWD +IFR2 +MS +sag (2) 7,477.84 72.16 214.78 4,203.49 4,147.29 - 4,310.49 - 2,541.71 6,026,705.82 467,262.92 0.95 914.16 MWD +IFR2 +MS +sag (2) 7,572.90 71.77 214.65 4,232.92 4,176.72 - 4,384.80 - 2,593.20 6,026,631.73 467,211.14 0.43 937.12 MWD +IFR2 +MS +sag (2) 7,667.48 71.96 215.11 4,262.36 4,206.16 - 4,458.53 - 2,644.60 6,026,558.21 467,159.45 0.50 960.20 MWD +IFR2 +MS +sag (2) 7,758.38 72.02 214.91 4,290.46 4,234.26 - 4,529.34 - 2,694.19 6,026,487.62 467,109.57 0.22 982.59 MWD +IFR2 +MS +sag (2) 7,857.09 72.14 214.91 4,320.84 4,264.64 - 4,606.36 - 2,747.94 6,026,410.82 467,055.51 0.12 1,006.75 MWD +IFR2 +MS +sag (2) 7,951.52 72.13 214.87 4,349.80 4,293.60 - 4,680.08 - 2,799.35 6,026,337.32 467,003.81 0.04 1,029.85 MWD +IFR2 +MS +sag (2) 8,047.26 72.73 214.89 4,378.70 4,322.50 - 4,754.95 - 2,851.55 6,026,262.66 466,951.32 0.63 1,053.29 MWD +IFR2 +MS +sag (2) 8,142.02 72.86 213.92 4,406.73 4,350.53 - 4,829.64 - 2,902.69 6,026,188.19 466,899.87 0.99 1,075.81 MWD +IFR2 +MS +sag (2) 8,235.56 72.73 214.08 4,434.40 4,378.20 - 4,903.71 - 2,952.66 6,026,114.33 466,849.61 0.21 1,097.42 MWD +IFR2 +MS +sag (2) 8,330.90 72.86 213.75 4,462.60 4,406.40 - 4,979.29 - 3,003.47 6,026,038.96 466,798.50 0.36 1,119.32 MWD +IFR2 +MS +sag (2) 8,425.38 72.21 213.89 4,490.96 4,434.76 - 5,054.17 - 3,053.64 6,025,964.30 466,748.04 0.70 1,140.85 MWD +IFR2 +MS +sag (2) 8,520.57 71.03 214.65 4,520.97 4,464.77 - 5,128.82 - 3,104.50 6,025,889.86 466,696.87 1.45 1,163.12 MWD +IFR2 +MS +sag (2) 8,614.82 70.45 215.43 4,552.06 4,495.86 - 5,201.67 - 3,155.58 6,025,817.23 466,645.50 0.99 1,186.20 MWD +IFR2 +MS +sag (2) 8,707.23 70.97 215.11 4,582.59 4,526.39 - 5,272.88 - 3,205.95 6,025,746.23 466,594.85 0.65 1,209.17 MWD +IFR2 +MS +sag (2) 8,802.23 71.56 214.91 4,613.10 4,556.90 - 5,346.56 - 3,257.56 6,025,672.76 466,542.94 0.65 1,232.47 MWD +IFR2 +MS +sag (2) 8,897.27 71.76 215.01 4,643.01 4,586.81 - 5,420.50 - 3,309.25 6,025,599.05 466,490.96 0.23 1,255.76 MWD +IFR2 +MS +sag (2) 8,992.31 71.70 215.37 4,672.80 4,616.60 - 5,494.25 - 3,361.26 6,025,525.51 466,438.65 0.37 1,279.41 MWD +IFR2 +MS +sag (2) 9,087.70 72.40 214.07 4,702.20 4,646.00 - 5,568.84 - 3,412.95 6,025,451.14 466,386.67 1.49 1,302.46 MWD +IFR2 +MS +sag (2) 9,182.27 72.66 214.32 4,730.59 4,674.39 - 5,643.45 - 3,463.64 6,025,376.74 466,335.68 0.37 1,324.58 MWD +IFR2 +MS +sag (2) 9,276.95 72.27 212.54 4,759.12 4,702.92 - 5,718.79 - 3,513.38 6,025,301.61 466,285.64 1.84 1,345.55 MWD +IFR2 +MS +sag (2) 9,371.44 71.83 212.53 4,788.24 4,732.04 - 5,794.58 - 3,561.72 6,025,226.03 466,237.00 0.47 1,365.06 MWD +IFR2 +MS +sag (2) 9,466.39 71.88 213.38 4,817.81 4,761.61 - 5,870.29 - 3,610.81 6,025,150.53 466,187.61 0.85 1,385.29 MWD +IFR2 +MS +sag (2) 9,561.41 71.43 216.75 4,847.72 4,791.52 - 5,944.10 - 3,662.61 6,025,076.94 466,135.52 3.40 1,408.73 MWD +IFR2 +MS +sag (2) 9,656.14 70.96 220.58 4,878.27 4,822.07 - 6,014.10 - 3,718.62 6,025,007.17 466,079.23 3.86 1,437.41 MWD +IFR2 +MS +sag (2) 9,750.60 72.00 222.51 4,908.28 4,852.08 - 6,081.13 - 3,778.02 6,024,940.39 466,019.56 2.23 1,470.31 MWD +IFR2 +MS +sag (2) 9,845.48 72.39 225.50 4,937.29 4,881.10 - 6,146.09 - 3,840.77 6,024,875.69 465,956.55 3.03 1,507.05 MWD +IFR2 +MS +sag (2) 9,940.31 72.08 228.44 4,966.23 4,910.03 - 6,207.71 - 3,906.77 6,024,814.34 465,890.31 2.97 1,548.00 MWD +IFR2 +MS +sag (2) 10,035.40 70.98 231.76 4,996.37 4,940.17 - 6,265.56 - 3,975.95 6,024,756.78 465,820.90 3.51 1,593.22 MWD +IFR2 +MS +sag (2) 10,049.98 70.97 232.37 5,001.12 4,944.92 - 6,274.04 - 3,986.82 6,024,748.35 465,810.00 3.96 1,600.54 NS- Gyro-MS (3) 10,104.98 84.74 237.65 5,012.67 4,956.47 - 6,304.73 - 4,030.78 6,024,717.84 465,765.92 26.73 1,631.35 NS- Gyro-MS (3) 10,191.98 84.62 241.67 5,020.74 4,964.54 - 6,348.48 - 4,105.53 6,024,674.40 465,691.00 4.60 1,686.63 NS- Gyro-MS (3) 10,259.91 84.25 246.20 5,027.33 4,971.13 - 6,378.18 - 4,166.25 6,024,644.95 465,630.17 6.66 1,733.53 MWD +IFR2 +MS +sag (4) 10,306.57 83.51 248.83 5,032.31 4,976.11 - 6,395.92 - 4,209.11 6,024,627.38 465,587.24 5.82 1,767.73 MWD +IFR2 +MS +sag (4) 10,356.69 82.24 252.28 5,038.53 4,982.33 - 6,412.47 - 4,256.00 6,024,611.02 465,540.29 7.29 1,806.13 MWD +IFR2 +MS +sag (4) 10,402.89 80.50 256.64 5,045.46 4,989.26 - 6,424.71 - 4,299.99 6,024,598.96 465,496.25 10.06 1,843.29 MWD +IFR2 +MS +sag (4) 10,452.16 79.12 261.21 5,054.18 4,997.98 - 6,434.03 - 4,347.56 6,024,589.84 465,448.64 9.55 1,884.81 MWD +IFR2 +MS +sag (4) 10,499.52 78.81 264.76 5,063.25 5,007.05 - 6,439.71 - 4,393.69 6,024,584.35 465,402.50 7.39 1,926.21 MWD +IFR2 +MS +sag (4) 10,549.42 79.15 268.20 5,072.79 5,016.59 - 6,442.71 - 4,442.57 6,024,581.54 465,353.61 6.80 1,971.11 MWD +IFR2 +MS +sag (4) 11/32009 2:48:59PM Page 5 COMPASS 2003.16 Build 71 • • Halliburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -45A - Slot ODS-45 Project: Oooguruk Development TVD Reference: 42.7 + 13.5 @ 56.20ft (Nabors 19 AC) Seta: Oooguruk Drill Site MD Reference: 42.T + 13.5 @ 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference: True Wellbore: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section (ft) ( °) (°) (ft) (ft) (ft) (ft) (ft) (ft) ( °/100') (ft) Survey Tool Name 10,596.90 79.90 271.70 5,081.43 5,025.23 - 6,442.75 - 4,489.25 6,024,581.69 465,306.94 7.42 2,014.97 MWD +IFR2 +MS +sag (4) 10,646.00 80.10 275.72 5,089.95 5,033.75 - 6,439.62 - 4,537.49 6,024,585.02 465,258.71 8.07 2,061.37 MWD +IFR2 +MS +sag (4) 10,692.11 79.72 278.83 5,098.03 5,041.83 - 6,433.87 - 4,582.52 6,024,590.95 465,213.71 6.69 2,105.64 MWD +IFR2 +MS +sag (4) 10,741.83 79.16 282.40 5,107.15 5,050.95 - 6,424.87 - 4,630.55 6,024,600.14 465,165.72 7.15 2,153.86 MWD +IFR2 +MS +sag (4) 10,838.48 79.83 288.06 5,124.78 5,068.58 - 6,399.92 - 4,722.20 6,024,625.47 465,074.18 5.80 2,248.52 MWD +IFR2 +MS +sag (4) 10,935.46 82.65 293.08 5,139.56 5,083.36 - 6,366.24 - 4,811.90 6,024,659.51 464,984.64 5.88 2,344.32 MWD +IFR2 +MS +sag (4) 11,032.19 84.12 298.09 5,150.71 5,094.51 - 6,324.75 - 4,898.53 6,024,701.34 464,898.18 5.36 2,439.92 MWD +IFR2 +MS +sag (4) 11,127.72 85.25 304.59 5,159.57 5,103.37 - 6,275.30 - 4,979.72 6,024,751.11 464,817.20 6.88 2,533.12 MWD +IFR2 +MS +sag (4) 11,224.34 85.01 312.68 5,167.79 5,111.59 - 6,215.25 - 5,054.86 6,024,811.47 464,742.31 8.35 2,624.27 MWD +IFR2 +MS +sag (4) 11,275.22 86.50 316.47 5,171.55 5,115.35 - 6,179.64 - 5,090.99 6,024,847.22 464,706.33 7.98 2,670.41 MWD +IFR2 +MS +sag (4) 11,344.46 90.00 318.36 5,173.67 5,117.47 - 6,128.70 - 5,137.81 6,024,898.35 464,659.72 5.74 2,731.83 MWD +IFR2 +MS +sag (4) 11,440.98 91.24 320.71 5,172.62 5,116.42 - 6,055.28 - 5,200.44 6,024,972.01 464,597.39 2.75 2,815.79 MWD +IFR2 +MS +sag (4) 11,478.97 91.23 320.47 5,171.80 5,115.60 - 6,025.93 - 5,224.56 6,025 , 001.45 464,573.40 0.63 2,848.49 MWD +IFR2 +MS +sag (4) 11,532.05 91.17 317.88 5,170.69 5,114.49 - 5,985.78 - 5,259.25 6,025,041.74 464,538.88 4.88 2,894.82 MWD +IFR2 +MS +sag (4) 11,630.25 90.49 320.13 5,169.27 5,113.07 - 5,911.67 - 5,323.66 6,025,116.10 464,474.78 2.39 2,980.69 MWD +IFR2 +MS +sag (4) 11,726.86 89.75 320.30 5,169.07 5,112.87 - 5,837.43 - 5,385.48 6,025,190.58 464,413.27 0.79 3,064.17 MWD +IFR2 +MS +sag (4) 11,823.02 90.56 320.56 5,168.81 5,112.61 - 5,763.31 - 5,446.73 6,025,264.95 464,352.32 0.88 3,147.09 MWD +IFR2 +MS +sag (4) 11,920.83 88.76 320.36 5,169.39 5,113.19 - 5,687.88 - 5,508.99 6,025,340.62 464,290.37 1.85 3,231.39 MWD +IFR2 +MS +sag (4) 12,016.50 89.38 321.88 5,170.94 5,114.74 - 5,613.42 - 5,569.04 6,025,415.32 464,230.63 1.72 3,313.28 MWD +IFR2 +MS +sag (4) 12,113.06 90.19 323.01 5,171.30 5,115.10 - 5,536.87 - 5,627.89 6,025 ,492 .09 464,172.10 1.44 3,394.76 MWD +IFR2 +MS +sag (4) 12,209.55 90.62 322.25 5,170.62 5,114.42 - 5,460.19 - 5,686.45 6,025,569.01 464,113.85 0.90 3,476.02 MWD +IFR2 +MS +sag (4) 12,304.26 93.77 320.94 5,166.99 5,110.79 - 5,386.04 - 5,745.24 6,025,643.39 464,055.38 3.60 3,556.62 MWD +IFR2 +MS +sag (4) 12,401.69 95.69 320.55 5,158.96 5,102.76 - 5,310.86 - 5,806.67 6,025,718.81 463,994.25 2.01 3,640.07 MWD +IFR2 +MS +sag (4) 12,498.15 95.43 319.48 5,149.61 5,093.41 - 5,237.30 - 5,868.36 6,025,792.62 463,932.86 1.14 3,723.20 MWD +IFR2 +MS +sag (4) 12,594.55 95.44 320.11 5,140.48 5,084.28 - 5,164.00 - 5,930.32 6,025,866.16 463,871.21 0.65 3,806.49 MWD +IFR2 +MS +sag (4) 12,691.27 95.12 319.87 5,131.58 5,075.38 - 5,090.23 - 5,992.24 6,025,940.17 463,809.60 0.41 3,889.90 MWD +IFR2 +MS +sag (4) 12,788.04 95.87 320.32 5,122.32 5,066.12 - 5,016.34 - 6,054.03 6,026,014.30 463,748.11 0.90 3,973.24 MWD +IFR2 +MS +sag (4) 12,884.40 95.55 320.07 5,112.73 5,056.53 - 4,942.68 - 6,115.41 6,026,088.20 463,687.04 0.42 4,056.11 MWD +IFR2 +MS +sag (4) 12,980.93 94.94 320.09 5,103.90 5,047.70 - 4,868.96 - 6,177.10 6,026,162.17 463,625.66 0.63 4,139.29 MWD +IFR2 +MS +sag (4) 13,080.50 95.69 321.17 5,094.68 5,038.48 - 4,792.32 - 6,239.99 6,026,239.06 463,563.09 1.32 4,224.60 MWD +IFR2 +MS +sag (4) 13,173.65 94.63 320.42 5,086.30 5,030.10 - 4,720.43 - 6,298.63 6,026,311.17 463,504.75 1.39 4,304.29 MWD +IFR2 +MS +sag (4) 13,271.18 95.19 321.05 5,077.96 5,021.76 - 4,645.20 - 6,360.13 6,026,386.65 463,443.56 0.86 4,387.81 MWD +IFR2 +MS +sag (4) 13,367.56 94.93 320.41 5,069.45 5,013.25 - 4,570.87 - 6,420.89 6,026,461.21 463,383.10 0.71 4,470.34 MWD +IFR2 +MS +sag (4) 13,463.74 94.14 318.43 5,061.85 5,005.65 - 4,498.06 - 6,483.26 6,026,534.27 463,321.03 2.21 4,553.85 MWD +IFR2 +MS +sag (4) 13,560.24 95.25 317.88 5,053.95 4,997.75 - 4,426.41 - 6,547.42 6,026,606.17 463,257.17 1.28 4,638.64 MWD +IFR2 +MS +sag (4) 13,657.42 95.43 318.94 5,044.91 4,988.71 - 4,354.05 - 6,611.65 6,026,678.79 463,193.25 1.10 4,723.74 MWD +IFR2 +MS +sag (4) 13,753.72 96.24 318.56 5,035.12 4,978.92 - 4,282.02 - 6,674.81 6,026,751.06 463,130.38 0.93 4,807.73 MWD +IFR2 +MS +sag (4) 13,848.13 94.44 319.00 5,026.33 4,970.13 - 4,211.32 - 6,736.75 6,026,822.01 463,068.74 1.96 4,890.12 MWD +IFR2 +MS +sag (4) 13,945.88 93.46 319.70 5,019.60 4,963.40 - 4,137.33 - 6,800.28 6,026,896.24 463,005.52 1.23 4,975.12 MWD +IFR2 +MS +sag (4) 14,042.44 90.24 319.55 5,016.48 4,960.28 - 4,063.82 - 6,862.79 6,026,970.00 462,943.31 3.34 5,059.00 MWD +IFR2 +MS +sag (4) 11/3/2009 2:48:59PM Page 6 COMPASS 2003.16 Build 71 • • Halliburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co-ordinate Reference: Well ODSN -45A - Slot ODS-45 Project: Oooguruk Development TVD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 © 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference: True Welibore: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical MD Inc AzI TVD TVDSS +NI-S +EI -W Northing Easting DLS Section (ft) ( ( (tt) (ft) (ft) (ft) (ft) (It) ( °M00') (ft) Survey Tool Name 14,138.64 90.56 319.39 5,015.81 4,959.61 - 3,990.70 - 6,925.30 6,027,043.37 462,881.10 0.37 5,142.75 MWD +IFR2 +MS +sag (4) 14,235.40 90.25 319.05 5,015.12 4,958.92 - 3,917.44 - 6,988.50 6,027,116.88 462,818.21 0.48 5,227.20 MWD +IFR2 +MS +sag (4) 14,331.88 91.49 319.22 5,013.66 4,957.46 - 3,844.48 - 7,051.61 6,027,190.08 462,755.40 1.30 5,311.46 MWD +IFR2 +MS +sag (4) 14,428.93 92.23 319.66 5,010.51 4,954.31 - 3,770.79 - 7,114.68 6,027,264.02 462,692.63 0.89 5,395.93 MWD +IFR2 +MS +sag (4) 14,525.20 92.10 319.53 5,006.87 4,950.67 - 3,697.54 - 7,177.04 6,027,337.52 462,630.58 0.19 5,479.58 MWD +IFR2 +MS +sag (4) 14,621.70 92.10 319.40 5,003.34 4,947.14 - 3,624.25 - 7,239.72 6,027,411.06 462,568.21 0.13 5,563.54 MWD +IFR2 +MS +sag (4) 14,715.37 90.61 320.11 5,001.12 4,944.92 - 3,552.77 - 7,300.21 6,027,482.77 462,508.01 1.76 5,644.84 MWD +IFR2 +MS +sag (4) 14,813.48 89.01 321.39 5,001.45 4,945.25 - 3,476.80 - 7,362.28 6,027,558.99 462,446.25 2.09 5,729.15 MWD +IFR2 +MS +sag (4) 14,909.63 90.93 322.51 5,001.50 4,945.30 - 3,401.09 - 7,421.54 6,027,634.93 462,387.31 2.31 5,810.73 MWD +IFR2 +MS +sag (4) 15,007.07 90.12 320.67 5,000.60 4,944.40 - 3,324.74 - 7,482.07 6,027,711.51 462,327.09 2.06 5,893.72 MWD +IFR2 +MS +sag (4) 15,103.49 87.52 320.30 5,002.59 4,946.39 - 3,250.38 - 7,543.41 6,027,786.12 462,266.07 2.72 5,976.79 MWD +IFR2 +MS +sag (4) 15,200.31 87.16 320.06 5,007.08 4,950.88 - 3,176.10 - 7,605.34 6,027,860.64 462,204.44 0.45 6,060.39 MWD +IFR2 +MS +sag (4) 15,296.62 87.10 320.66 5,011.91 4,955.71 - 3,102.03 - 7,666.70 6,027,934.96 462,143.39 0.63 6,143.39 MWD +IFR2 +MS +sag (4) 15,393.08 87.28 319.99 5,016.63 4,960.43 - 3,027.88 - 7,728.21 6,028,009.35 462,082.18 0.72 6,226.55 MWD +IFR2 +MS +sag (4) 15,428.97 87.28 319.99 5,018.34 4,962.14 - 3,000.42 - 7,751.26 6,028,036.90 462,059.25 0.00 6,257.60 PROJECTED to TD 11/3/2009 2:48:59PM Page 7 COMPASS 2003.16 Build 71 • • Attachment 1 Operations to Drilling Rig Workover Checklist Well Name: Job Description: Wellsite Supervisor: Date: Wellsite Supervisor Completes Well killed? Y or N Freeze Protected? Y or N Fluid Type Used SIWHP psi TBG IA P psi Fluid Est Depth Pumped Vol IA OA P psi Type (TVD) (bbls) Tubing IA OA Bottom Hole Pressure Well Hanger Seal /Voids Tested? psi Test PSI (mark interface(s) on diagram) Time Date Date Valves Greased? Y or N Date Lockdown Screws Functioned? Y or N Date BPV Installed? Y or N Date Valves or Plugs Installed (SOV, OV, Dmy, X, XN, etc) Type Depth (TVD) Minimum ID Type Width (in) Depth (TVD) Operations Completes (Initial and Date) Initials Date Press and Temp Sensors Removed Flow /Injection Line Depressured Flow /Injection Line Removed or Blinded Lift Gas Line Depressured Lift Gas Line Removed or Blinded Pressure left on: SSSV Control Line (open or closed) Packer Vent Valve (open or closed) Control Lines Removed Any known communication Tbg x IA IA x OA Other After completing document, scan and put electronic file in well folder • • Oooguruk Drill Site Well oobgu Handover Form PIONEER To Drilling Well Name Producer New Well To Production API # Injector Workover To Well Work PTD# Sidetrack Completion Date AFE Number DIRECTIONAL INFORMATION DOWNHOLE INFORMATION Original RKB KOP Drillers TD PBTD ?op of fill or Junk Date Tagged Max angle to XN / at XN d@ Hole Angle lTD WELL INFORMATION DOWNHOLE PLUGS SITP IAP OAP BHP / Depth / Date / Inst. (X or comment) BPV Installed 2 Way Check Well Bore Section: Description details Weight (ppg) Top (MD) Bottom (MD) Downhole Plug IA VR Plug OA VR Plug Other Other CASING / TUBING DATA Size Top Bottom Wt. Grade Connection Coated? (X) Remarks Conductor Surface Intermediate 1 Intermediate 2 Liner Tubing PERFORATION or SLOTTED LINER INFORMATION (All Active Intervals) Top Bottom SPF/SLOT SIZE Gun Type / Charge / Orientation 1 Date KNOWN Communication (X for known comm) Tbg X IA IA X OA Other T Note: All boxes checked require additional comments below COMPLETION INFORMATION (Use default or pick list) Depth (Top) Item Manufacturer Type / Model Valve Size Latch Length O.D. I.D. Comments: WELLHEAD EQUIPMENT DETAIL Wellhead OA Valve type (Manufacturer / Model / Type / Pressure Ratng) IA Valve type Tree Tree Cap Connection (Manufacturer / Model / Type / Pressure Rating) Tubing Hanger Connection Packoff Assembly Barrier: I NewJX) 1 Replaced (X) Test Pressure j 1 T Mechanical Wellborn section Test Pressure Pass? (YIN) State Witness(X) Comments Integrity Tubing Tests Prod Annulus Surf Annulus 1 1 Cmt Shoe (YM) 1 ADDED DETAIL OR GENERAL COMMENTS Comments: 1. Is the Well Cellar Clean? Yes or No Comments: 2. Are the Wellhead and Tree Clean? Yes or No Comments: 3. Is the Welibay Clean of All Residual Drilling Equipment? Yes or No Commends: 4. Are the Well Bay Hatch and Slicldine Hatch Covers in Place? Yes or No Comments: 5. Who FZ Protected Outer Annulus? Fluid Type? Volume? Date? 6. Who FZ Protected Inner Annulus? Fluid Type? Volume? Date? 7. Who FZ Protected Tubing? Fluid Type? Volume? Date? 8. Are there plugs/sleeves in the well? Yes Type of Plug? Depth? Jewelry? 9. Are there plugs/sleeves in the well? No Type of Plug? Depth? Jewelry? 10. Is there a DH gauge in the well? Yes Type Gauge? Pressure? Temperature? Final Wellbore Review on DATE in TIME: Position: Dria Site Larder Well Work Sup, Completion Emir. Dnding Sept: Other: Other: Odrer. Other Participant: OPERATIONS Drilling Representative: Title: Drill Ste Leader Date HANDOVER Operations Representative: Title: Operations Date: G HYDRIL ANNULAR (5K) - OK, LATCHED HYDRIL 4 4i STUD /FIANCE CONNECTIONS APPROX WEIGHT = 8,200 LBS • II II I ' HY RIL HYDRIL SINGLE RAM "'St N _ ', i 3 '3 APPROX WEIGHT = 6,000 CONNECTIONS r l 1 MI5I157 / .- " I HYDRIL SINGLE RAM I I _ W H RIL I 2 1 1 STUD /STUD CONNECTIONS 2 APPROX WEIGHT = 6,000 LBS / 3" 50001 HCR VALVE - C` " 5000/ NCR VALVE 3" CHOKE UNE— _■I■ i■i i ■m 2" KILL UNE MUD CROSS ■ / . ,} , ♦ r I'� 0 24 FLANGE /FL4NGE CONNECTIONS MI �, — APPROX WEIGHT = 1,800 LBS U 3" 50001 GTE VALVE iG� mug° 3" 5000/ G4TE VALVE SWING L RADIUS — HY ©RIL HYDRIL SINGLE RAM 44 - 5/8" -- FLANGE/STUD CONNECTIONS I O I i 2 APPROX WEIGHT = 6,000 LBS • I I + HYDRIL 11 " 5, 0O0PSI BOP STACK 95 PLAN VIEW HYDRIL 11 " 5,O00PSI BOP STACK ELEVATION y �� lial 6fM.. WI if f N In III La Nabo Mbar. Nowto Miry Ix rs yors AID 2 585 C Sind Sdb 7100 �■W■■IM■■■wO Mchoroy" Mho 0603-2,38 OD7- 761000 now MG 19-AC TILE BOP STACK MIN 91. 11 ", 5,000P9I zni o■[ «7 r 7 rearm /EYE ILES FEB IS M e". sa IB1L110P_S WK I OF 1 • RECOMMENDED PRACTICES BAAWIES Running an ESP Completion with 2 -7/8" tubing Issue Date: February 2008 Revision Date: April 02, 2013 SCOPE & BACKGROUND Electric Submersible Pumps (ESP) are a commonly utilized form of artificial lift. The standard practice is for a drilling rig to drill and case the well and then move off. A workover rig then moves on to perforate, stimulate, and complete the well. At Oooguruk, the drilling rig will handle all of these procedures. This recommended practice covers running an ESP completion. PREPARATION AND HANDLING PRECAUTION A pre job safety /planning meeting will be held prior to running the pump and at any crew change to ensure good communication between all parties on location. A Baker Hughes representative will be on the rig floor at all times during the running of the ESP and will be responsible for ensuring that cable is kept free when setting the slips. Bring cable, motor oil and pump equipment into a heated location at least 48 hours prior to running. Handle ESP assemblies in original shipping boxes until ready to PU to floor. Do not allow any cable or pigtails to stick out of spooling shed until ready to run to the rig floor if temperature is below 30 °F. Do not allow cable to drag in dirt or gravel or across rough edges while TIH. Lay plywood between the cable spooler and the rig to protect cable from dragging. Verify rig is centered over hole. ESP power cable will be damaged if rig is off center of hole. Exercise extreme caution when bringing motor and pump up to rig floor to avoid jarring or bending equipment. Do not handle cable spool with forks or slings in direct contact with the cable. RUNNING PROCEDURE A Baker Hughes A representative shall be on the rig floor at all times during the running of the ESP Verify the size and horse power of ESP motor as per proposed program for the well. Verify that the length of motor lead flat cable will place the splice on the handling pup above the discharge assembly. A Baker Hughes rep shall be on the rig floor at all times during the running of the ESP. 1. Install ESP cable in the spooling unit. The completion will be run with a new motor lead extension, seal section and motor. On rig workovers it may be permissible to use an existing pump and/or cable - Baker Hughes representative will advise. Pump assembly is as follows - refer to ESP Assembly Schematic with well plan for details: Version 2.1 This document is the property of Baker Hughas and the information contained herein is Page 1 of 9 Running an ESP Completion confidential and may not be distributed, either in part or in whole, nor communicated to any competitor or potential competitor of Baker Hughes Inc. C2012 • • vise RECOMMENDED PRACTICES BAKER HUGHES • CENTRALIZER • MOTOR GAUGE UNIT • MOTOR • TANDEM SEAL SECTION • PUMP INTAKE /GAS SEPARATOR • PUMP(S) • DISCHARGE HEAD • DISCHARGE GAUGE UNIT • AUTO DIVERTER VALVE 2. Confirm spooling unit is aligned to provide a straight pull on the cable, and to provide operator clear view. Spooler to be spotted far enough back from the rig to allow adequate slack in the cable (i.e. able to see the entire derrick). 2.1. Confirm Baker Hughes technician has reviewed operation of unit with operator and has signed operator off as qualified on Baker Hughes check off sheet. 2.2. Confirm sheave is 54" in diameter. Confirm safety cable is attached to sheave. Normal running height shall not exceed 40' above floor. The flat MLE cable should be hand fed to the floor and the round cable tied off at the floor until the flat round splice is secured to the tubing to minimise stress on the flat/round splice Note: The MLE is to be connected to the ESP motor and secured to the ESP equipment prior to splicing it to the round cable. In preparation of the splice the round cable should be brought over the sheave and secure with rope in such a way that it cannot be pulled back over. The cable should remain secured until after the splice is completed and the round cable is secured to the tubing with a Cannon clamp at the next tubing collar. If a Gator Splice connector is being used, a gator splice clamp should be placed over the connector. Note: Pothead/Motor Lead Extension Handling: • Do not bend the motor lead near the base of the pothead. • Never bend the motor lead sideways. This causes relative movement of the conductors. • Never allow the pothead pins to be pushed into the pothead. • Never pull directly on a pothead, especially when unreeling or running over a sheave. Pull on the cable at least 1' away. • Do not apply tension to the motor lead during installation. Have it and the cable above it completely banded prior to applying any cable tension. • Use small sheave for MLE 3. Record the dimensions and nameplate of each piece of equipment prior to RIH. 4. Pick up the ESP motor with attached MGU and centralizer. 5. Attach MGU TEC connection 6. Slowly lower the motor assembly into the well and lower lifting clamp onto the wellhead slips. Assemble the tandem seals to motor assembly. Line up assembly alignment marks at the seal. 6.1. Service the seal and the motor as per standard servicing procedures outlined in the Technical Service Manual. 7. Attach pump intake or gas separator Version 2.1 This document is the property of Baker Hughes and the information contained herein is Page 2 of 9 Running an ESP Completion confidential and may not be distributed either in part or in whole, nor communicated to any competitor or potential competitor of Baker Hughes Inc. © 2012 • • war RECOMMENDED PRACTICES �K� 8. Attach pump(s). 8.1. When running 4" pumps, secure MLE to pump housing using 4000- B- 03PG1.40 clamps. Do not use protectolizers with 4" pumps. 8.2. When running 5" pumps, secure MLE to pumps using protectolizers. Do not use pump housing clamps on 5" pumps. The running OD of the MLE flat cable clamps over Baker Hughes 538 series ESP is 6.23 ". This design has been tested and is NOT approved for install. Additionally, no 1 '/4 Stainless Steel Bands are to be used on the pump sections. 9. Attach Discharge Assembly 10. Perform TEC wire splice to discharge gauge unit. 11. Secure MLE to 2" handling pup joints using 2875 -C -03 clamps. Note: It is absolutely essential that all clamps and bands used to install the ESP cable be counted and reported accurately so that there can be no confusion concerning the number in the well if the completion needs to be pulled in the future. A count of all clamps, bands, and protectolizers used should be recorded on the running tally and any deviations from the original ESP schematic should be noted. Note: The hole shall be covered at all times when cable bands or clamps are being installed. Exercise caution to insure slips will not be set on either the ESP or cable. Damage to the cable will require that the installation is stopped and the cable repaired. Assign one man on the rig floor to be responsible for watching the cable when lowering into well HAND SLIPS. HAND SLIPS shall be used while RIH with ESP assembly to minimize the risk of cable damage. 12. A Customer representative shall witness free rotation of completely assembled ESP unit on rig floor. 13. Confirm again that all serial numbers and equipment clamp numbers have been recorded before TIH. 14. Perform round to flat cable splice as per equipment diagram. 15. Confirm gauge readings. 16. RIH the ESP with Baker Hughes #1 round CELR cable and 2 -7/8" tubing. Go in hole no faster than 1 joint per minute (1800 ft/hr). Verbal acknowledgement between driller and spooler operator is required each time the completion is moved. Ensure ESP cable is properly placed on the minor OD of each GLM. Refer to "Correct placement of ESP cable alongside GLM.doc" for details. 17. If distance from MLE splice to packer is greater than —7000', a taped cable splice or gator splice must be performed before reaching the packer. Splice location to be determined by Baker Hughes personnel based on available cable quantities on reels. Land splice at the middle of a joint. 18. Install packer feed thru and cable connectors: After the packer is in place and feed through is installed the round cable should be secured with rope so that it cannot be pulled back over the sheave prior to cutting the cable. The cable should remain secure until after the connection to the packer feed through has been made and a Cannon clamp has been installed at the next tubing collar above the packer. 19. Check the conductivity of the electric cable and downhole gauge readings every 2,000' and every new splice while running in hole. Use a Cannon cable clamp on every other joint on the round cable, use the Version 2.1 This document is the property of Baker Hugs and the information contained herein is Page 3 of 9 Running an ESP Completion confidential and may not be distributed, either in part or in whole, nor communicated to any competitor or potential competitor of Baker Hughes Inc. ©2012 ID • MIN BAKER RECOMMENDED PRACTICES HUMES half 2 -7/8" clamp (2875- C -24P) on the GLM pup. Space out the ESP at the setting depth as per completion diagram. Monitor the trip tank for proper hole fill while running the completion. Notes: • Review and mark on the directional survey areas where the dogleg is more than 6 °. Reduce RIH rate as the ESP assembly passes through these sections. The ESP assembly must be placed in the wellbore at less than 3° /100' DLS to prevent ESP failure. Baker Hughes recommends placing the ESP at less than 2° /100' DLS for optimal performance. • Exercise caution when TIH to avoid sudden starts and stops which may damage ESP cable, especially while setting the slips or spider. 20. Space out the ESP to proposed setting depth as per program. Install the Cable extension on the ESP penetrator. Record the readings using Commissioner during the landing of the tubing hanger, the setting of the packer assembly and the pressure testing of the IA. Land tubing with extreme care to minimize damaging the ESP penetrator, pigtail and alignment pin. Run in lock down screws. Test tubing hanger. A The ESP penetrator can be damaged when the tubing hanger is landed. ND BOPs and NU lock down flange, tubing head adapter, and tree. Pressure test tubing head adapter and tree. Use umbilical cord to continuously check run in hole panel readings until after packer is set. Note: Hold safety meeting with crews to review proper procedure for nippling down the bell nipple. To prevent injuries, it must not be removed by hand. 21. Pull TWC with lubricator. If cost effective, salvage (via circulation) as much of clean brine as possible for next rig workover. To prevent bringing fines into the tubing, do not reverse. Do not exceed 3,000 psi as it may damage the ESP. 22. Freeze protect the well with diesel to 2,000 -ft TVD by circulating (or bullheading if needed) diesel down tubing annulus. Do not exceed 3,000 psi surface pressure. Also bullhead diesel down tubing. Set BPV and close all valves. Note: Calculate the actual volume of diesel for freeze protection based on measured depth corresponding to 2,000 -ft TVD. 23. Make a final check and record ESP conductivity phase to phase and phase to ground for all three phases at the hanger penetrator. Confirm the balanced conductivity by Baker Hughes field representative. 24. Confirm that the Baker Hughes ESP Checklist has been completed. Version 2.1 This document is the property of Baker Hughes and the information contained herein is Page 4 of 9 Running an ESP Completion confidential and may not be distributed, either in part or in whole, nor communicated to any competitor or potential competitor of Baker Hughes Inc. 02012 • S Mil RECOMMENDED PRACTICES liAMIES a Ensure appropriate checklists are rnmpleted. Version 2.1 This document is the property of Baker Hughes and the information contained herein is Page 5 of 9 Running an ESP Completion confidential and may not be distributed, either in part or in whole, nor communicated to any competitor or potential competitor of Baker Hughes Inc. 02012 • • EMI RECOMMENDED PRACTICES NIMES 000GURUK ESP CHECKLIST RUNNING THE ESP ASSEMBLY PART 1 OF 3 WELL • BAKER HUGHES REP (INITIAL ITEMS AS THEY ARE COMPLETED) Confirm spooler operator is qualified to operate spooler. Baker Hughes representative witness final cleanout returns prior to installing ESP. All ESP equipment inspected, serial numbers and models confirmed as being correct and proper for this well prior to rigging up. Safety /planning meeting held with rig crew at beginning of job describing all work and safety procedures to be followed. Confirm the flat/round splice is across the ESP handling pup between two couplings. Review all ESP handling procedures and precautions for moving equipment around location with rig crews. Review all ESP handling procedures and precautions for moving equipment in the pipe shed and up to the floor with rig crew. All cable and equipment visually inspected and approved when TIH. Confirm motor dielectric oil is in new. Confirm gauge is operational and resistivity readings are proper. Check height of motor shaft = ". Verify with gauge CO203410401. Confirm within acceptable limits. Measure shaft extension for upper seal and confirm acceptable. Verify with gauge CO201670101 Shaft Extension = " Acceptable Limits = Confirm free rotation of ESP unit as a completely assembled unit. Version 2.1 This document is the property of Baker Hughes and the information contained herein is Page 6 of 9 Running an ESP Completion confidential and may not be distributed, either in part or in whole, nor communicated to any competitor or potential competitor of Baker Hughes Inc. ©2012 • Milli BAKER RECOMMENDED PRACTICES HUMES Parts Installed #On Floor # Installed # Remaining • • Baker Hughes representative will note the location of any installed materials. NOTES Version 2.1 This document is the property of Baker Hughes and the information contained herein is Page 7 of 9 Running an ESP Completion confidential and may not be distributed, either in part or in whole, nor communicated to any competitor or potential competitor of Baker Hughes Inc. ©2012 • • EMI BAKER RECOMMENDED PRACTICES MOM 000GURUK ESP CHECKLIST RUNNING THE ESP ASSEMBLY PART 2 OF 3 WELL BAKER HUGHES REP INITIAL ITEMS AS THEY ARE COMPLETED) Instruct rig crews on proper banding procedures. Number flat electrical cable clamps run = Number round electrical cable clamps run = Number cable bands run = Phase resistivities checked at the motor pothead and recorded on Baker Hughes running report. Phase resistivities checked after the flat/round splice and recorded on Baker Hughes running report. Phase resistivities checked every 2,000' minimum while TIH and after each electrical connection. Confirm the ESP setting depth is correct before landing the tubing hanger. Phase resistivities checked before the hanger penetrator pigtail and recorded on Baker Hughes running report. Phase resistivities checked above the hanger and recorded on Baker Hughes running report. Phase resistivities checked when the hanger is landed and recorded on Baker Hughes running report. Final resistivity check after tree is RU and tested, prior to RD. Confirm Baker Hughes running report is completely filled out and is legible. Give this form to PNRA Rig Supervisor when completed. Date: Comments: Version 2.1 This document is the property of Baker Hughes and the information contained herein is Page 8 of 9 Running an ESP Completion confidential and may not be distributed, either in part or in whole, nor communicated to any competitor or potential competitor of Baker Hughes Inc. 02012 • • Eau RECOMMENDED PRACTICES BAMES 000GURUK ESP CHECKLIST RUNNING THE ESP ASSEMBLY WELL: Send original of the following reports to Well Files: Baker Hughes running report Baker Hughes Checklist Date: Baker Hughes Rep: Comments: Version 2.1 This document is the property of Baker Hughas and the information contained herein is Page 9 of 9 Running an ESP Completion confidential and may not be distributed, either in part or in whole, nor commumcated to any competitor or potential competitor of Baker Hughes Inc. 0 2012 • • INSTALLATION ISSUES Well Category Install Date Prgtains Cause Lessons Learned / Solution K -33 4/25/2008 Flawless Install N-40 Packer Vent Valve 7/25/2008 Cable Armor Damage Damaged POOH for Packer Vent Valve Failure K-41 Clamp, DLS 1/3/2009 MLE Damage @ 2300' Over drift 5.38" pump housing Do not run pump clamps on pumps clamps. Clamp running OD was over 20' 6.23 ". A 5.23 degree dogleg at failure depth. N -31 Clamp, slips 8/18/2009 MLE Damage @ Surface' 5.13" clamps caught in slips Do not catch clamps in slips N -37 Packer, tension 11/30/2009 Packer Connector Parted @ Pull from cable caused it to come Change in install procedure to tie off Surface apart. connector N -36 12/2/2009 Flawless Install K -14 Lower Connector? 3/4/2010 Electrical failure before start TBD- suspected connector assembly, Use umbilical cord and test readings up, Rig on different well manufacture or design flaw every 30 min until startup. Do not when problem discovered move rig away from well until ESP is started N -31 (2) 4/5/2010 Flawless Install N -16 Packer 8/3/2010 MLE Damage POOH @ After Packer failure, 5.38" clamps Do not run 5.38" clamps in 7" casing 12000' parted MLE. Clamp running OD was 6.23" N -16 Lower Connector 8/6/2010 Lower WH Connector Improper BIW Lower Connector Recertify technicians with BIW Failure after packer set Assembly Connector N -16 Packer Pentrator, 0-ring 8/10/2010 Packer Connecter Failure @ 0-rings cut on lip seal causing leak, Store connectors indoors to avoid 2500' extreme temperature caused Orings extreme temperature changes to dry out and become brittle N -16 Packer Pentrator 8/11/2010 Packer Connector Failure @ 1000' of cable packer connector Use tarp to cover splicing area to 2500' tested wet. 1 leg of packer lower ensure rain will not disturb making up connector grounded connectors K-41 (2) 8/23/2010 Flawless Install N -17 Cable, GLM 10/21/2010 Cable Failure at Gas Lift Cable was placed on thick side of Procedures for proper GLM cable Mandrel 3987'. DLS 0.58. GLM and was crushed RIH installation sent out. K -33 (2) Clamp 3/24/2011 Lost Comms with DGU Christolizer had been twisted RIH Attempt to limit rotation and attempt to 4000' and parted TEC wire and damaged land mle on upper side of esp in the MLE. Cable put on wrong side of lateral. Put cable on minor OD of GLM. SS bands tom off. GLM's. Do no use SS bands. K -33 (2) ADV 3/24/2011 ADV came unbucked Pins sheared and ADV bucked loose, ADV sent to Pumptools for analysis did not cause damage but had to make up new upper ESP assembly K-41 (3) Lower Connector 4/6/2011 Electrical failure at wellhead Crack in BIW Lower connector PEEK Sent to BIW for manufacture analysis. lower connector @ surface insulator found BIW will change edge curvature to reduce likelihood of crack formation when subject to stress. K-41 (3) Cable, GLM 4/7/2011 Armor Damaged at GLM @ Cable placed on wrong side of GLM Sent out GLM cable installation 6940'. DLS 1.38. procedures • • INSTALLATION ISSUES w l ,_„ _ Install Date Problems Cause Lessons Learned / Solution T 4/13/2011 Flawless Install N -18 5/13/2011 Flawless Install K -13 Clamp 10/7/2011 Chnstolizer clamp damaged Loose casing joints, clamps missing Use a clamp with a longer profile. ESP assembly bevel. Quality check pans during fit testing. K -13 Clamp 10/7/2011 Lost Comms with DGU Loosened christolizer crimped tech Replace christolizers. Ensure clamps wire. are fastened securely before RIH. In restricted or high dogleg areas, reduce ESP RIH rate. Measure all clamps with OD tape to make sure they are fully tightened and under drift. T -45A (2) Slips 10/9/2012 Air slips damaged cable just ESP cable and the 3 control lines Use hand slips instead of airslips to above the packer were not properly secured when minimize the risk of equipment airslips were engaged. damage. III Completion &NEER - Fishing Tool List • • 5/24/13 9:22 AM Initials of Update Person St -By Tools f/ 7" 26# Casing Updating Date QTY ITEM Weight Lengt Wdth CONTACT PHONE NO. Baker Fishing Tools Ibs ft ft Tools Overshots, Upper /Lower Extensions, Over -Size Glides 5 3/4" Bowen Series 150 Overshot 2 Bowen 5 3/4" Overshot, 3 1/2" IF Box 2 Bowen 5 3/4" Upper Extension, Box x Pin 1 Bowen 5 3/4" Lower Extension, Box x Pin Hollow Mill Inserts: for 5 314" Bowen OverShot 1 3 1/2" ID Hollow Mill Insert (3 1/2" pipe body) Grapples, Controls, Packoffs: for 5 3/4" Bowen Overshot 2 3 1/2" Grapple, 1 4 3/4" Grapple w/ Control 2 2 7/8" Grapple w/ Control 1 3 1/4" Grapple w/ Control 1 3 3/8" Grapple w/ Control 1 4 1/4" Grapple w/ Control Parts 1 Stop Ring for 5 3/4" Overshot JARS 1 Lubricated Bumper Jar- 43/4" OD x 2 " ID - 3 1/2" IF BxP 1 Hyd Fishing Jar - 4 3/4" OD x2 "ID -31/2" IF B x P 1 Accelerator /Intensifier Jar - 4 3/4" 00 x 2" ID - 3 1/2" IF 8 x P Junk Mills / Dress Off mills 1 6 -1/8" SOD Junk Mill, 3 1/2" Reg Pin X -Overs 1 X -Over, 3 1/2" IF Pin x DC Conn Box 1 X -Over, DC Conn Pin x 3 1/2" IF Box 1 Pump -out Sub, w/ 3 1/2" IF Box x Pin Spears & Grapples 1 Ito Spear 1 Spear Ext. 2 Spear Grapple f/ 4 1/2 Tubing 2 Wreline Rope Spear w/ 31/2 IF Box 1 Wreline Rope Spear Stop Sub 5 7/8 to 6 -1/8" OD Well Dynamics Packer Mill Over Equipment 1 Boot Baskets, 4.750" OD, 3 1/2" Reg Box x Pin 1 Downhole Inline Magnets, 4 3/4" OD, 3 1/2" IF Box x Pin 1 Bit Sub 3 1/2 Reg x 3 1/2 IF 1 5 3/4 Globe Basket 3 1/2 Reg Conn. 1 7" Ultra -Clean Casing Scraperwl 3 1/2 Conn. NOTE: Primary VACS BHAs to have 4 1/2" XTM 50 pup /1 (from Allis Chalmers) for handling Page 1 Prepared by: James Sonnier 6 Standby Fishing Pkg.] • • MAJOR O.D.: 5.500" SWAGE MINOR O.D.: 4.593" ` mm , CONNECTION O.D.: 3.625" ORIENTING SLEEVE WEIGHT: 6.4# MINIMUM I.D.: 2.365" DRIFT I.D.: 2.347" OVERALL LENGTH: 108" CONNECTION(S): TYPE: OVAL MATERIAL: 4130 80 KSI INTERNAL YIELD PRESSURE: 6,000 PSI EXTERNAL YIELD PRESSURE: 4,000 PSI BODY YIELD STRENGTH: 250,000 LBF -0- BODY PIPE BRINELL: 217 -235 ROCKWELL C: 18 -22 KICKOVER TOOL: KOT -2, OM -1 RUNNING TOOL: RK -1 '-..4--- POCKET PULLING TOOL: 1 -5/8 JDS LATCH: RK, RKP VALVE: 1.5" O.D. 1.556" SEAL BORE 1.494" SEAL BORE I NO .4 40 IFF 'EriON S • - le DESCRIPTION 2.8 FO -2 SWAGE MANDREL ASSEMBLY SCALE SHT OF DWG NO N/A 1 1 2112S101 • • Page 1 of 1 HALLIBURTON September 19, 2012 Engineering Data Sheet EQUIPMENT MATERIAL NO.: 100005672 LN 2.313 X 9CR BLNK PART NUMBER: 11X23160 -A DESIGN SPECIFICATIONS LOCK PROFILE X SIZE 2.313 MAXIMUM OD 3.240 inch LENGTH 14.60 inch MATERIAL 9CR-1M0 SERVICE H2S SERVICE REMARKS H2S AND /OR CO2 SERVICE BASED ON CUSTOMER DEFINED, WELL SPECIFIC CONDITIONS. APPLICATIONS MUST BE REVIEWED FOR SPECIFIC ENVIRONMENTAL COMPATIBILITY MEETS MATERIAL SERVICE REQUIREMENTS OF NACE MR -01 -75 TOP THREAD BLANK BOTTOM THREAD BLANK CONNECTION TYPE BLANK (END) (Unless specified, Dim - inches, pres -psi, weight -Ibs, temp -deg F) NOTE: Values of pressure, force and operating depths presented above are based upon empirical data and theoretical calculations. These values will vary within accepted engineering limits due to variations in material strength, dimensional tolerances and actual installed conditions. NOTE: Haliburton makes no warranty, either expressed or implied, as to the accuracy of the data or of any calculation or opinion expressed herein. Halliburton, Dallas, Texas, U.S.A. • • Page 1 of 3 HALLI BURTON September 19, 2012 Engineering Data Sheet EQUIPMENT MATERIAL NO.: 102066106 TRSV,NE,4.65 2.313,H2S,5K PART NUMBER: 478LXE11 DESIGN SPECIFICATIONS VALVE MODEL NE CLOSURE TYPE FLAPPER SIZE 2 7/8 LOCK PROFILE X MINIMUM INSIDE DIAMETER WITHOUT PACKING BORE 2.350 inch TOP SEAL BORE ID- MINIMUM 2.313 inch BOTTOM SEAL BORE ID- MINIMUM 2.313 inch MAXIMUM OD 4.65 inch LENGTH 62.95 inch MATERIAL 9CR -1 MO /410 STAINLESS STEEL/17 -4 PH STAINLESS STEEL SERVICE H2S SERVICE REMARKS H2S SERVICE BASED ON CUSTOMER DEFINED, WELL SPECIFIC CONDITIONS. APPLICATIONS MUST BE REVIEWED FOR SPECIFIC ENVIRONMENTAL COMPATIBILITY. MEETS MATERIAL SERVICE REQUIREMENTS OF NACE MR0175 /ISO 15156 TOP THREAD 2 7/8 -6.40 DB BOTTOM THREAD 2 7/8 -6.40 DB CONNECTION TYPE BOX -PIN PRESSURE RATING 5000 pounds /sq. inch BURST PRESSURE 11541 pounds /sq. inch API COLLAPSE PRESSURE AT AMBIENT 9155 pounds /sq. inch API COLLAPSE PRESSURE AT MAX TEMPERATURE RATING 8225 pounds /sq. inch EXTERNAL PRESSURE RATING 5000 pounds /sq. inch TENSILE WITH WORK PRESS, WITHOUT TBG THD, AT AMBIENT, 144 pound CALC /1000 TENSILE WITHOUT WORK PRESS, WITHOUT TBG THD, AT 209 pound AMBIENT, CALC /1000 TENSILE WITH WORK PRESS, WITHOUT TBG THD, AT MAX 117 pound TEMPERATURE RATING, CALC /1000 TENSILE WITHOUT WORK PRESS, WITHOUT TBG THD, AT MAX 182 pound TEMPERATURE RATING, CALC /1000 TEMPERATURE RATING 40 TO 300 Deg. F MAXIMUM FULL OPEN PRESSURE 2000 pounds /sq. inch • • Page 2 of 3 MINIMUM CLOSING PRESSURE 875 pounds /sq. inch PISTON DISPLACEMENT VOLUME .66 cu. inch EQUALIZING FEATURE YES MAXIMUM PRESSURE DIFFERENTIAL AT VALVE OPENING 5000 pounds /sq. inch CONTROL LINE PRESSURE TO EQUALIZE AT PRESSURE RATING 4000 pounds /sq. inch CONTROL LINE CONNECTION 7/16 -20 HIF HIF KIT 101085853 (93F1499) LOCKOUT TYPE NE COMMUNICATION TYPE NE LOCKOUT TOOL, PERMANENT 101597423 (42L0X23107) LOCKOUT TOOL REMARKS LOCKOUT ONLY, NO COMMUNICATION PRESSURE TO LOCK OUT 2000 pounds /sq. inch EXERCISE TOOL 101060088 (42TL252) COMMUNICATION TOOL 101328568 (42CTX23101) INSTALLATION EXTENSION PENDING WIRELINE REPLACEMENT VALVE 120056522 (22FXE23112) RUNNING /PULLING PRONG EXTENSION PENDING ISOLATION ASSEMBLY LOCK MANDREL TYPE 2.313 X ISOLATION ASSEMBLY EQUALIZING VALVE TYPE 2.313 XO ISOLATION ASSEMBLY EXTENSION MANDREL PENDING ISOLATION SLEEVE 101073451 (78D2219) ISOLATION SLEEVE 0-RING 100006603 (91QV1328 -H) SPECIAL FEATURE EXERCISE PROFILE SEAT INSERT INSTALLATION TOOL 101281950 (83M2057) SEAT INSERT TORQUE -MIN 1800 foot pound BODY TORQUE 1900 foot pound SHOULDER BOLT TORQUE 90 inch pound SPRING COMPRESSION TOOL 101673426 (83M2681), 101678655 (83M2682) DRIFT BAR 101088123 (81R104) DRIFT BAR OUTSIDE DIAMETER 2.303 inch DRIFT BAR LENGTH 24.00 inch TEST FIXTURE -BOX END 101905249 (81T24475), 101090611 (81T12199), 101090612 (81T12200) TEST FIXTURE -PIN END 101905250 (81T24476), 101090610 (81T12198),101090612 (81T12200) API /ISO TYPE SCTRSV MEETS QUALITY REQUIREMENTS API -Q1 /ISO 9001 MEETS INDUSTRY SPECIFICATION(S) API 14A/ISO 10432 API /ISO SPECIFICATION EDITION ELEVENTH API /ISO VALIDATION LEVEUSERVICE CLASS 1,3S API /ISO VALIDATION DATE 08 -12 -11 API /ISO VALIDATION METHOD VARIATION • • Page 3 of 3 API /ISO VALIDATION REFERENCE 78001213 OPERATING ENVELOPE 478LXE11 BDMI/TECHNICAL OPERATIONS MANUAL 478LXE11 (END) (Unless specified, Dim -inches, pros -psl, weighMbs, temp -dog F) NOTE: Values of pressure, force and operating depths presented above are based upon empirical data and theoretical calculations. These values will vary within accepted engineering limits due to variations in material strength, dimensional tolerances and actual installed conditions. NOTE: Halliburton makes no warranty, either expressed or implied, as to the accuracy of the data or of any calculation or opinion expressed herein. Halliburton, Dallas, Texas, U.S.A. • • HALLIBURTON CHEMICAL INJECTION SUB, 2.313" 2 7/8" 6.5 API -EU, P -P, ALLOY, H2S Design Specifications SAP Part Number: 195065 11 ( Legacy Part Number: N/A Name Value z TYPE XXO SIZE 2 7/8" = LENGTH 29.87" CONNECTION 2 7 /8- 6.50API -EUE PIN -PIN NIPPLE PROFILE X 4 MATERIAL ALLOY SEAL BORE ID-MIN 2.313" MAXIMUM ECCENTRIC OD 3.973" TENSILE STRENGTH 144,960 pound EXTERNAL TEST PRESSURE 8,932 PSI INTERNAL TEST PRESSURE 8,453 PSI SERVICE STD /H2S TEMPERATURE 40:325 Deg. F MEETS REQUIREMENTS OF NACE MR -01 -75 I ; d, 1 . molmor I I II 1111111 i • • Page 1 of 1 HALLIBURTON May 23, 2013 Engineering Data Sheet 9 g EQUIPMENT MATERIAL NO.: 101052771 HYDR CONTRL LINE,1/4,.049,3000,316L PART NUMBER: 22SXX31300 DESIGN SPECIFICATIONS TUBING MATERIAL 316L STAINLESS STEEL TUBING TYPE U G PE WELDED AND SUNK TUBING OUTSIDE DIAMETER .25 inch TUBING WALL THICKNESS .049 inch LENGTH 3000 foot FITTING MATERIAL 316L STAINLESS STEEL CONNECTION 1/4 TBG X 1/8 MP PRESSURE RATING 17000 pounds /sq. inch TEST PRESSURE 18000 pounds /sq. inch SPOOL -OFF DEVICE 7 X 20 X 36 (END) (Unless specified, Dim - inches, pros -psi, weight-Ibs, temp -deg F) NOTE: Values of pressure, force and operating depths presented above are based upon empirical data and theoretical calculations. These values will vary within accepted engineering limits due to variations in material strength, dimensional tolerances and actual installed conditions. NOTE: Halliburton makes no warranty, either expressed or implied, as to the accuracy of the data or of any calculation or opinion expressed herein. Halliburton, Dallas, Texas, U.S.A. 1 / (24.88) (18.239) O D (11.869) © 0 0 © 0 A••••-. • 0 2.434) - -- - - -- 1 ---------------- / \ 1 I / `\ (3.250) / I ` \ MAIN JEW_ 4jJ / / / / / C i ,/ (010.9161 � V / ( 1 250) 952.953) r rn"."-:.--". -------------------------- ---- -- - --------- - --- -- 02.960) ( ........ �14.625) � � j / \--OFFSET i (3.125 -6TP1 MCA ) A J� � (3-1/2 OD 9.2 PPF 4 / 2 \/ �� MOD BUTTRESS BOX ) (3 H -BPV) A-••----I B SECTION A-A q re(t((tr 4 1110 r , „it SCALE 1/4 Cievetco Vetco Gray ^ ASSEMBLY / SWE //\ MARKING LOCATION. TUBING HGR, M9-233, OFFSET, A 9 1/01KAR 10 -3/4 X 3 -1/2, 3 -1/2 OD 9.2 PPF A MOD BUTTRESS 90X BIM, 3.725 -6TPI MCA I. DIMENSIONS ARE IN INCHES. 6. 1960 JOX TOP, 3H -BPV, W /HORIZONTAL OUTLET, NOTES: J.HWAHG 741 ,14-06 BIW FEEDTHRU MANDREL AND LOWER E�y7 CONNECTOR, W13-CONTROL LINES Q � G ..... Ti , Xi . X148570 -I Imo 1a1 8 I Pro /I MODEL PARAMS REV VER - 5 REL LEVEL: - Released BRANCH:- main 3 I 2 I " / Pro /I DRAWING PARAMS REV.VER: - 1.5 REL LEVEL: - Released BRANCH:- main ! MODEL NAME - H148570 -I I PRIM • • Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Friday, June 14, 2013 1:57 PM To: 'Vaughan, Alex' Cc: Campoamor, Kathy Subject: RE: Oooguruk ESP Packer Info Alex, Thanks... makes more sense now. Still unsure about where the gas vent valve is located . Assume it is above packer in the 2 nd dual string outlet =? Do you have eng. Drawings of the PVV? Guy Schwartz Senior Petroleum Engineer AOGCC 907 - 444 -3433 cell 907 - 793 -1226 office From: Vaughan, Alex [mailto:Alex.Vaughan(pxd.com] Sent: Friday, June 14, 2013 11:48 AM To: Schwartz, Guy L (DOA) Cc: Campoamor, Kathy Subject: Oooguruk ESP Packer Info Guy, As requested please find technical information for the ESP packers we are using on our wells attached. Alex Vaughan Senior Drilling Engineer PIONEER NATURAL RESOURCES 907.343.2186 (office) 907.748.5478 (mobile) Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e -mail and delete the message and any attachments. 1 • aocl -d7 - Oooguruk Recommended Running Procedure — - Production Well (Weatherford Hydrow -II c/w ESP Gas Vent Valve) - Overview: The Weatherford Hydrow -II packer has been utilized for Oooguruk to provide electric feed through, chemical injection, and safety valve controlled annulus gas venting. The packer is hydraulically set and will shear release. It has been purpose built with softer packing elements to set at lower temperatures, a high strength production string for maximum tensile rating, and eccentric systems to allow the use of high amperage ESP cable feed through and a gas venting valve. The packer is made up on a sub assy of 2 -7/8" pup joints. After it is picked up and made up to the production tubing in the well the ESP cable is cut to length, fed thru the packer from the lower end, and terminated at a PFT connector. Next, the chemical injection line and safety valve control lines are made up and the packer is run to depth. 1) A 2 -7/8" x 2.313" `X' landing nipple must be installed in the tubing string below the packer. This will be used for setting a slick line plug to pressure up against to hydraulically setting the packer. The plug body may be run in place in the nipple and the packer set using a welded ball rod. Alternatively, the plug may be set on wireline after the packer is on depth. Operator preference as to how the plug is set. 2) Pick up the Hydrow -II packer assy. and make up to 2 -7/8" tubing in well. Be especially careful not to damage the slip sections of the packer or bend the ESP Gas Vent Valve spacer tube. Inspect the packer assy. for any damage. 3) Record serial numbers of packer and ESP Gas Vent Valves. Note: The packer sub assy as delivered to location is ready to run. It has been pressure tested, drifted, and is shear pinned for setting and releasing. Included with this procedure is the shop caliper sheet for the assy. Confirm the match of serial numbers. 4) Following PFS (Power Feed -Thru Systems & Connectors LLC) procedure cut ESP cable to length. 5) Feed ESP cable in well thru packer. 6) Lower packer to allow comfortable work height. 7) Feed ESP cable thru PFS receptacle, dope the receptacle pin end and make up to 1.900" box in top of packer. 8) Place tarp around packer to catch dropped parts. 9) PFS to make detachable connector connections at top of packer and on end of ESP cable to surface. Attach connectors and test as per procedure. 10) MU SwageLock connectors to top of packer using Teflon tape on NPT pin ends. The chemical injection side of the packer is 1 /2" NPT box up and the ESP Gas vent Valve is 1 A" NPT box up. 11) Connect chemical injection line to tube fitting as per SwageLock instructions (attached pg 58 -59). A back check valve would also be recommended. 12) Connect safety valve control line to tube fitting on ESP Gas Vent Valve as per SwageLock instructions (attached pg 58 -59). Loosen tube fitting and bleed air from control line. Re- tighten tube fitting. Following rig pressure testing safety guidelines pressure test safety valve control line to 4000 psi. (5000 psi max.) to • • cycle Gas Vent Valve and test tube connection for leaks. Bleed off pressure. The valve will cycle closed.PT to 3500 from below.RJH w/ GVV in closed position. 13) RIH w/ 1000 psi on GVV control line. 14) With all connections made, pick up tubing and band ESP cable to bottom of packer. 15) Lower packer to comfortable work height and thoroughly band ESP cable, ESP Gas Vent Valve, safety valve control line, and chemical injection line to the production tubing. Be careful to avoid banding across vent slots in ESP Gas Vent Valve. 16) RIHW production tubing installing control line lamps at a prudent running speed, (60 ft/min). Note: The ESP Gas Vent Valve does not need to be open at any time during running and setting. 17) Install (HAL) Halliburton 2 -7/8" tubing mounted surface controlled sub surface safety valve as per Hal procedure. 18) RIHW remaining 2 -7/8" tubing. 19) PU tubing hanger and terminate all control lines and ESP surface connections. 20) Land tubing hanger in well head and secure hold down anchor pins. 21) Pump into chemical injection port to confirm unrestricted chemical flow. 22) Pressure up on safety valve control lines and note bleed back volumes to confirm stroke of safety valves down hole. The ESP Gas Vent Valve has a stroke of 2.64" and uses 13.27 cc of hydraulic fluid to fully stroke open / closed. Confirm volume change of HAL valve. 23) Test well head ESP feed thru. 24) Set back pressure valve in tubing hanger and pressure test top of tubing hanger as per procedure. 25) ND BOP's and NU well head. 26) Pressure test wellhead as per procedure. 27) RU back pressure valve pulling tool and pull back pressure valve as per procedure. 28) Pressure up on HAL tubing mounted safety valve as per HAL procedure to fully open it. Maintain pressure until packer test is complete and slick line plug is retrieved. 29) RU & reverse circulate diesel freeze blanket and displace annulus to calculated depth. Hold back pressure on annulus as required to maintain freeze blanket in place. 30) If a plug body is installed in the `X' nipple drop the welded ball rod. If not installed, RU and run slick line plug and land in `X' nipple. 31) Set packer. Slowly increase tubing pressure to 3500 psi (4000 max) and hold for at least 15 minutes. 32) Bleed off tubing pressure and RU to pressure test annulus. Note: be sure that the ESP Gas Vent Valve is closed at this time. 33) Bleed freeze blanket circulating pressure off of annulus. This will be a slight negative pressure test. 34) Pressure test annulus to 1500 psi and hold for 30 minutes or as per procedure. 35) RU slick line and retrieve welded ball rod and plug body from `X' nipple. • • 36) If desired HAL safety valve and ESP Gas Vent Valve can be left in open or closed position. 37) Releasing pkr,straight PU on tbg to tbg weight + pkr shear to shear release loose.Allow ackin elements to relax 30 min. P g e st eax Prepared by: Scott Williamson Weatherford — Denver, CO 4 -22 -08 720 946 1368 (office) 303 877 9700 (cell) • • ^.. INDEX NO. 200 UNIT NO. 907 -72 PN. 01129139 Weatherford® DATE 31 -Auq -2010 Revision 1.0 Hydrow IIA -P Hydraulic -Set Dual - String Production Packer pup The Weatherford Hydrow IIA -P is a dual- string, hydraulic -set, double -grip retrievable production packer. The Hydrow IIA -P is an ideal submersible pump packer, and is also available with additional bores for ESP cable, chemical- injection lines, control lines, and well- monitoring devices. The Hydrow IIA -P has a patented sequential upper -slip releasing system that is designed t a to release each slip individually to reduce the pull required to release the packer. The angles on the slips, cone, and upper -slip body results in release forces that allows the penetration of the slips to be released smoothly from the casing. Features • Patented upper -slip releasing system • Tension force to release packer is easily adjusted before running • All components locked to prevent preset • Release shear pins not affected by differential pressures • Short and compact, ideal for doglegs and deviated wells • Setting cylinder below elements eliminates all of the critical o -rings after setting Benefits • Straight -pull release • Can be pressure- tested on location • Mechanical upper slips • Multiple bores available • No hydraulic hold -down buttons • Cost effective • Can be easily modified into a Hydrow II -ASL or Hydrow 11 -AJL • Available with a wide variety of accessories Applications • Multiple -zone isolation • High - volume instrumented applications • Monitoring, gas venting, chemical injection, and hydraulic -line access • Deviated and horizontal wells • Submersible pump installations Weatherford products and services are subject to Weatherd's starms and condions. Packer Systems 1 of 10 For mare information concernin the full the of Weatherford rfo products and ndard serv please co your authorized Weatherford representative. Unless noted otherwise, trademarks and servicemarks noted herein are the property of Weatherford. © 2010. Weatherford. All rights reserved. • • V* INDEX NO. 200 UNIT NO. 907 -72 PN. 01129139 Weatherford® DATE 31- Aug -2010 Revision 1.0 SPECIFICATION GUIDE PRODUCT NUMBER 01129139 ENGLISH METRIC CASING SIZE (IN. /mm) 7.000 177,80 CASING WEIGHT RANGE (IN. /mm) 17.0 - 29.0 25,30 - 43,15 PACKER MAXIMUM O.D. (IN. /mm) 6.000 152,40 PRESSURE RATING (PSI/bar) 5,000 344,74 PACKING ELEMENT 70 -50 -70 NITRILE TEMPERATURE RATING ( °F 1°C) 40 - 150 I 4,44 - 65,56 SETTING MANDREL LONG STRING SET LONG STRING TOP THREAD CONNECTION 2 -7/8" (6.4 LB /FT.) NEW VAM BOX BOTTOM THREAD CONNECTION 2 -7/8" (6.4 LB /FT.) NEW VAM PIN MINIMUM I.D. (IN. /mm) 2.360 I 59,94 SHORT STRING TOP THREAD CONNECTION 1.900" NU 10 RD BOX BOTTOM THREAD CONNECTION 1.900" EU 10 RD PIN MINIMUM I.D. (IN. /mm) 1.500 I 38,10 VENT MANDREL (QTY -2 -) TOP THREAD CONNECTION 1/2 " -14 NPT BOX BOTTOM THREAD CONNECTION 1/2 " -14 NPT PIN MINIMUM I.D. (IN. /mm) 0.490 I 12,45 Packer Systems Weatherforoducts and ser e subject to Weatherford's standnd condi ions. 2 of 10 For more inf or con the ar full line of Weatherford products and ard terms services, a please contact your authorized Weatherford representative. Unless noted otherease, trademarks and servicemarks noted herein are the property of Weatherford. Cl 2010. Weatherford. All rights reserved. • itV INDEX NO 200 UNIT NO. 907 -72 PN. 01129139 Weatherford® DATE Revision 31 -Aug -2010 1.0 CAUTION: Before starting work, ensure all personal protection equipment is available and being used. Evaluate job site to ensure work can be completed safely. All safety procedures are to be observed. PRE -RUN INSPECTION 1. Inspect all slips and packing elements for cut, cracks and shipping damage. Replace any damaged parts. 2. Ensure all torque screws and shear screws are installed. 3. Verify packing elements do not extend above O.D. of upper cone and setting mandrel. PRECAUTIONS AND HANDLING 1. Do not lift tool at packing element or slip locations. 2. If both strings are run simultaneously, allow at least 30 minutes for the packer to equalize thermally before setting. 3. Do not allow the packer to be more than 10,000 lb. mechanically out of balance, short string to long string, prior to setting. This could cause the packer to set improperly due to mechanical loading forces. SETTING PROCEDURE Run the packer in the well slowly (maximum of 60 ft. in 30 seconds is recommended). Temporarily plug the long string below the packer and apply (2,500 -PSI minimum / 4,000 -PSI maximum) differential in the tubing at the packer and hold the pressure for at least 10 minutes. The packer should now be fully set and can be pressure tested if desired. RELEASING PROCEDURE The Hydrow II -AP packer is released by a straight pick up on the long string. The shear release value is adjustable in 5,500 lb. increments up to 49,500 lb. This packer comes with six screws, 33,000 -lb. OPERATION When tubing pressure is applied to the packer, the inlet port allows pressure differential to be present in the setting chamber. This differential forces the setting mandrel to separate from the setting cylinder, shearing the setting shear screws. The setting cylinder is forced down, which shears the lower slip body shear screws and sets the lower slips. The setting mandrel is forced up, which shears the upper slip body shear screws, and sets the upper slips and packs off the elements. Any relative motion between the setting cylinder and the setting mandrel is held in place by the locking nut, which will ratchet in only one direction. With a pressure differential from above, the force is transferred through the outer components of the packer and is supported by the lower slips. STORAGE Store in a cool dry place out of direct sunlight. Wrap slip cages and packing elements with bubble wrap or cardboard and tape in place. Install thread protection on all upper and lower connections. Wrap packer with wax coated pump wrap to prevent corrosion for extended storage. Weatherfo products and se are subject to etherfords ' sandrms nd co Packer Systems 3 of I For. more info rmation concerning rvices the full fine of Weathe products t and ard serv e please contact your authorized Weatherford representative. Unless noted otherwise, trademarks and servicemarks noted herein are the property of Weatherford. ® 2010. Weatherford. All rights reserved. • • INDEX NO. 200 UNIT NO. 907 -72 PN. 01129139 ® DATE 31- Aug -2010 Weatheilord® Revision 1.0 ASSEMBLY T 0 1. Place top connection (1) in the vise. 2. Install upper slip body (3) on top connection (1). 3. Install upper slips (4) and slip springs (5) in upper slip body (3). Hold ,) r I' in place with key stock or pencils. ; ) ' Iq © 11 11 o 4. Install long string mandrel (28) in top connection (1). iP I I /I I -0 5. Install short string mandrel (30) in top connection (1). 1 ® 6. Install vent mandrels (2) in top connection (1). Lubricate O.D. of 1 ® O mandrels (2, 28 & 30). 1' 1 I v e °(() 7. Install o -rings (9, 10 & 11) in upper cone (8). 1 '' O 8. Install upper cone (8) onto mandrels (2, 28, & 30). Align torque -. 'NI* screws holes in upper cone with slots in upper slip body (3). 9. Install torque screws (6) in upper cone (8). I- o 1 10. Install shear screws (7) in upper slip body (3) and slots in upper ' 1 cone (8). t I 0 0 11. Install packing elements (12 & 14) and rubber spacers (13) on 1 1 1 as O ma (2, 28, & 30). 1 11 12. Install o -rings (9, 10 & 11) in setting mandrel (17). Place setting i 4D mandrel on bench with threads facing up. 13. Install o -ring (16) in setting cylinder (18). !; 14. Install setting cylinder (18) on setting mandrel (17). . ID 15. Install locking nut (19) on setting mandrel (17). 1 [MAKE SURE LOCKING NUT IS TURNED IN PROPER 0 j I II DIRECTION. SEE DWG A & B, PAGE 6.] 1 MI 2 16. Install o -rings (9, 10, 11, & 20) in lower cone (21). ' p o p 17. Install lower cone (21) in setting cylinder (18) and tighten. Align long � � ( ' _ p and short string mandrel holes in setting mandrel (17) with holes in a► ''+ E PD lower cone (21). 15 1 18. Install setting shear screws (15) in setting cylinder (18). 19. Install setting mandrel subassembly (15 thru 21) onto mandrels (2, 28 & 30). 20. Install pick -up ring (24) in groove of long string mandrel (28). 21. Install lower slip body DO NOT , I I (23) on lower slip body ca P( 25 . L (25). I I j TIGHTEN.] 22. Install shear sleeve (27) in lower slip body cap (25). �' 0 23. Install lower slips (22) and slip springs (5) in lower slip body (23). j 24. Install lower slip body (23) onto mandrels (2, 28 & 30). Align slots in a o 1? II lower slip body with torque screw holes in lower cone (21). 0 25. Install torque screws (6) in lower cone (21). 26. Install shear screws (7) in lower slip body (23) and slots in lower , cone (21). , 27. Install setting shear screws (26) in shear sleeve (27). [MAKE SURE III SETTING SHEAR SCREWS (26) ARE IN SLOTS IN LONG STRING MANDREL (28).] 1. 28. Install crossover (29) on long string mandrel (28). 29. Install change -over sub (31) on short string mandrel (30). , D tio Weatherford products and services are subject to Weatherrord's standard terms and conditions. Packer Systems 4 of 10 For more information concerning the full hne of Weatherford produ and services, plea contact your authorized Weatherford representative. Unless noted otherwise, trademarks and servicemerks noted herein are the property of Weatherford. © 2010. Weatherford. All rights reserved • • IV INDEX NO. 200 UNIT NO. 907 -72 PN. 01129139 Weatherford® DATE Revision 31 Auq 2010 1.0 DISASSEMBLY I 0 1. Place top connection (1) in the vise. 2. Remove change -over sub (31) from short string mandrel (30). .1 0 M 3. Remove crossover (29) from long string mandrel (28). ill I ►( O r 4. Remove releasing shear screws (26) from shear sleeve (27). x 0 0 5. Remo torque screws (6) and shear screws (7) from lower slip body (23). it Vi O 6. Remove lo slip body (23) subassembly from mandrels (2, 28 & 30). I I . 2 7. Remove slips (22) and slip springs (5) from lower slip body (23). 1 - 4 I iI8. Remove shear sleeve (27) from lower slip body cap (25). . ,p 9. Remove lower slip body cap (25) from lower slip body (23). OD 10. Remove pick -up ring (24) from long string mandrel (28) y I 1 4 0 {use snap ring pliers }. 11. Remove setting mandrel subassembly (15 through 21) from mandrels os• I 1 4 12. Remove lower cone (21) from setting cylinder (18). ' Z c °,1) 13. Remove o -rings (9, 10, 11 & 20) from lower cone (21). Y, . '�. 14. Remove setting shear screws (15) from setting cylinder (18). 1 0 15. Rotate setting mandrel (17) to remove it from locking nut (19) and remove setting mandrel from setting cylinder (18). 16. Remove lock nut (19) from setting cylinder (18). 17. Remove o -ring (16) from setting cylinder (18). _ - ;1 iD 18. Remove o -rings (9, 10 & 11) from setting mandrel (17). 1 -- I ° i 19. Remove packing elements (12 & 14) and rubber spacers (13) from mandrels ( If 0 � (2 28 & 30). It c{► 20. Remove torque screws (6) and shear screws (7) from upper slip body (3). 0 O 21. Remove upper cone (8) from mandrels (2, 28 & 30). h� 22. Remove o -rings (9, 10 & 11) from upper cone (8). ?' 1 j1 A 23. Remove vent mandrels (2) from top connection (1). DO NOT WRENCH ON I� I 0 SEAL SURFACE OF MANDRELS (2, 28 & 30). j 24. Remove short string mandrel (30) from top connection (1). 25. Remove long string mandrel (28) from top connection (1). 26. Remove upper slips (4) and slip springs (5) from upper slip body (3). 27. Remove upper slip body (3) from top connection (1). r i L 28. Clean and inspect all parts. 29. Replace any worn or damaged parts. 081' 4 i 3D to i r + Weatherford products services are subjec to Weatherf stanrd erms and conditions. Packer Systems 5 of 10 For nrore info rmation conce rning the full line o f Weatherford produ cts a ser plea contact your authorized Weatherford representative. Unless noted otherwise, trademarks and servicemarks noted herein are the property of Weatherford. ® 2010. Weatherford. All rights reserved • • 4W INDEX NO. 200 UNIT NO. 907 -72 PN. 01129139 Weatherford® DATE 31-Aug-2010 Revision 31 Aug 2010 1.0 SHEAR SCREW GUIDE NO. OF RELEASE SHEAR MAX. NUMBER OF LOWER SCREWS INSTALLED SLIP BODY SHEAR SCREWS 9 (49,500 LB.) 4 8 (44,000 LB.) 4 7 (38,500 LB.) 4 6 (33,000 LB.) 3 5 (27,500 LB.) 2 LESS THAN 5 RELEASE SCREWS IS NOT RECOMMENDED NOTE: This packer comes with six release shear screws. DWG. A - LOCK NUT INSTALLATION - DWG. B - LOCK NUT SPLIT 0 0 i Weatherfo prode sect to Weathd's dard rms conditions. Packer Systems 6 of t For more in formation ucts conce rning servics the full are line ubj of Weatherford ertor products stan and serv please con act your authorized Weatherford representative. Unless noted otherwise, trademarks and servicemarks noted herein are the property of Weatherford. © 2010. Weatherford. All rights reserved. • • INDEX NO. 200 UNIT NO. 907 -72 PN. 01129139 Weatherford DATE 31- Aug -2010 Revision 1.0 DIMENSIONAL DATA L _ DIMENSIONS (INIrnm) E G PRODUCT a NUMBER A B C D E F 82.75 75.184 59.179 21.179 8.272 2.370 01129139 2101.85 1909.67 1503.15 537.95 210.11 60.20 U H o PRODUCT DIMENSIONS (IN. /mm) H NUMBER G H J K M N 1.690 6.000 2.360 1.500 2.386 1.589 01129139 42.93 152.40 59.94 38.10 60.60 40.36 H a K L H A I� e E o H 1 j M ___ N l L ._ sutyect to Weatherford's standard terms and conditions. Packer Systems 7 of 10 For more Weatherford information products con and ceming services the are full line of Weatherford prod and services, please cooled your authorized Weatherford representative. Unless n oted otherwise, trademarks and servicemarks noted herein are the property of Weatherford. t) 2010. Weatherford. All fights reserved. • • INDEX NO. 200 UNIT NO. 907 -72 PN. 01129139 Weatherford® DATE 31-Aug-2010 Revision 31 Aug 2010 1.0 -r. t: IIIMIN PARTS LIST — 1 o ITEM 7.000" 1,... �SI 11 NO. DESCRIPTION 17.0 - 29.0 -- r 01129139 �� 1 TOP CONNECTION 01129106 I p 0 2 VENT MANDREL 00168486 (2) I� � 3 UPPER SLIP BODY 00158531 p e © 4 UPPER SLIP 00157056 (4) I d I 10 5 SLIP SPRING* 00158685 (16) ��1 O 6 TORQUE SCREW* 7/16 -20 x 7/8" 00158720 (4) I j ' 7 SHEAR SCREW* 3/8-16 X7/16" 00150992 (8) i � 1I ) a 8 UPPER CONE 00168213 ` 9 O -RING* #233 90D NBR 00767370 (3) (~ 10 O -RING* 12225 90D NBR 00767363 (3) , , :I 0 c r 0 1 1 O -RING* #118 90D NBR 00767229 (6) j w 7 40 12 PACKING ELEMENT* 70D NBR 00167033 (2) I 1 6 13 RUBBER SPACER 00166618 (2) 14 PACKING ELEMENT* 50D NBR 01129107 15 SHEAR SCREW* 00157541 (8) j BRASS 158 -PSI 1 EA. 5/16 -18 X 5/16" 16 O -RING* #252 90D NBR 00767341 s 1 I Illi ® 17 SETTING MANDREL 00166609 1 I 18 SETTING CYLINDER 00158704 19 LOCKING NUT* 00158841 . 0 6 ` 0 20 O -RING* #160 90D NBR 00767339 ,\ © I 21 LOWER CONE 00166602 .I ; , ►E 11 . 22 LOWER SLIP 00157035 (4) 23 LOWER SLIP BODY 00166595 24 PICK -UP RING 00158708 25 LOWER SLIP BODY CAP 00168856 1 RELEASE SCREW * (6) 00158543 6 26 BRASS 5.500 LB./EA. 5/8 -11 X 17/32" 27 SHEAR SLEEVE 00166692 28 LONG STRING MANDREL 01129104 29 CROSSOVER 01735183 1 @ ® 5 � ® 30 SHORT STRING MANDREL 01133992 31 CHANGE -OVER SUB _ 00164894 ® *Common repair parts. I — _g 1 l Weatherford products and services are subject to Weatherford's standard terms and conditions. Packer Systems 8 of 10 For more infomrabon concemin the full line of Weatherford products and services pha contact your authorized Weatherford representative. Unless noted otherwise, trademarks and servicemarks noted herein are the property of Weatherford. © 2010. Weatherford. All rights reserved. • • INDEX NO. 200 l UNIT NO. 907 -72 PN. 01129139 Weatherford® DATE Revision 31-Aug-2010 1.0 0-RING PRESSURE TEST KIT TEST PROCEDURE 1. Remove setting shear screws (15) from setting cylinder (18). 2. Slide one sleeve cap (32) onto lower end of packer with threads toward bottom of tool. 3. Slide sleeve (34) onto lower end of packer. 4. Install one (2 halves) split ring (33) into groove in setting mandrel (17) of packer. Slide sleeve (34) over split ring (33) and thread sleeve cap (32) into sleeve. 5. Slide sleeve toward top of the packer enough to install remaining split ring (33) into groove in lower cone (21) of packer. 6. Slide remaining sleeve cap (32) onto lower end of packer and thread into sleeve (34). Tighten sleeve caps (32) evenly. 7. Plug the top and bottom of the long string of packer. 8. Fill the mandrel with hydraulic oil or inhibited water. 9. Apply 500 -psi, hold and observe for leaks for five minutes. Increase pressure to 1,500 -psi and hold for five minutes. Increase pressure to 4,000 -psi, hold and observe for leaks for five minutes. No leaks acceptable. 10. Release pressure, remove test fixtures, and re- install setting shear screws (15) in setting cylinder (18). PARTS LIST ITEM 7.000" NO DESCRIPTION 17.0 - 32.0 00168468 32 SLEEVE CAP 00157285 (2) 33 SPLIT RING (2 HALVES) 00157247 (2) 34 TEST SLEEVE 00157182 32) (33) (15 a 18, (34) 33; (3 I ( I y =� l I � ( I Weatherford products and services are sutged to W eatherford's s terms and conditions. Packer Systems 9 of 10 For more information concerning the full line of Weath erford products and services, please contact your authorized Weatherford representative. Unless noted otherwise, trademarks and servicemarks noted herein are the property of Weatherford. © 2010. Weatherford. All fights reserved. • INDEX NO. 200 UNIT NO. 907 -72 PN. 01129139 Weatheriord® DATE 31 -Aug -2010 Revision 1.0 REVISIONS 1. 31- Aug -2010, Add crossover 01735183 (Item 29) to Parts List and drawing as per ECN(112726). Weatherford products and services are subject to Weatherford's standard terms and conditions. Packer Systems 10 of 10 For more information concerning the full line of Weatherford products and services, please contact your authorized Weatherford representative. Unless noted otherwise, trademarks and servicemarks noted herein are the property of Weat erford. © 2010. Weatherford. All rights reserved. FICdACI V CV STATE OF ALASKA NOV 1 6 2.0 AlltA OIL AND GAS CONSERVATION COMI,SION REPORT OF SUNDRY WELL OPERATIONS AOGCC 1. Operations Abandon U Repair Well U Plug Perforations U Perforate U Other U Replace Tubing & ESP Performed: Alter Casing ❑ Pull Tubing el Stimulate - Frac ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown E Stimulate - Other ❑ Re -enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Pioneer Natural Resources Alaska, Inc. Development © Exploratory ❑ - 209 -079 3. Address: 700 G Street, Suite #600 Stratigraphic❑ Service ❑ 6. API Number: Anchorage, AK 99501 50 7. Property Designation (Lease Number): r 8. Well Name and Number: ._ ADL 355036 ODST - 45A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): N/A Oooguruk - Torok Oil Pool 11. Present Well Condition Summary: Total Depth measured 15,429 feet Plugs measured N/A feet true vertical 5018 feet Junk measured N/A feet Effective Depth measured 15,422 feet Packer measured See Below feet true vertical 5018 feet true vertical feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 153' 153' N/A N/A Surface 4931' 10 - 3/4" 4973' 3438' 5210 psi 2470 psi Intermediate 9994' 7 -5/8" 10,050' 5001' 6890 psi 4790 psi Production Liner 5533' 4 -1/2" 9891' - 15,424' 4951' - 5018' 8430 psi 7500 psi Perforation depth Measured depth See Attachment, pg 2 feet True Vertical depth feet Tubing (size, grade, measured and true vertical depth) 2 -7/8 ", 6.4# L -80, IBT -M ' '''''1 b'15'' 1D 4847' TVD SSSV @ 2025' Hydro II Pkr © 2611' TSP Liner Top Pkr Water Swell Pkr © Packers and SSSV (type, measured and true vertical depth) MD/1994' TVD MD/2495' TVD @ 9907 MD/4956' 11,400'MD/5173' TVD TVD 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): SCANNED LIAR 11 2013 Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 230.2 723,397.1 194.5 991..6 265.9 Subsequent to operation: N/A N/A N/A N/A N/A 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development 0 e Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil -• U Gas U WDSPL U GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP SPLUG 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 312 -357 Prepared By: Kathy Campoamor, 343 - 2183 Contact Judy Golding Email Iudy.pOldinq(ipxd.COm Printed Name Judy Golding Title Well Work Supervisor Signature � , Phone 343 -2179 Date 11/14/2012 MS 0 21 2012 4,91_ Form 10 -404 Revised 10/2012 / 2. - 15' 0- Submit Original Only f l 4V ;li . • • Pioneer Rural Resources Alaska Inc. ODST -45A Page 2 AOGCC Form 10 -404, Report of Sundry Well Operations Present Well Condition Summary, Box 11 Perforation Depth (MD/TVD) Attachment Perforation Depth (MD/TVD) 4 -' /z ", 12.60 #, L -80 Liner - Pup joints ported with 6 -1/2" holes @ depths listed: MD TVD 11,581' - 11,586' 5170' - 5170' 11,786' - 11,791' 5169' - 5169' 11,991' - 11,996' 5171' - 5171' 12,196' - 12,200' 5171' - 5171' 12,402' - 12,406' 5159' - 5159' 12,688' - 12,692' 5132' - 5132' 13,009' - 13,014' 5101' -5101' 13,213' - 13,217' 5083' - 5083' 13,417' - 13,422' 5066' - 5065' 13,584' - 13,588' 5052' - 5051' 13,787' - 13,792' 5032' - 5032' 13,989' - 13,994' 5018' - 5018' 14,195' - 14,200' 5015' - 5015' 14,396' - 14,401' 5012' - 5011' 14,600' - 14,604' 5004' - 5004' 14,806' - 14,810' 5001' - 5001' 15,008' - 15,013' 5001' - 5001' 15,210' - 15,215' 5008' - 5008' 15,417' - 15,422' 5018' - 5018' P I 0 N E E R • Operations Summary Report - See Well Name: ODST -45A NATURAL RESOURCES Well Name: Contractor. Rig Number. Job Category: Start Date: End Date: Job Category WORKOVER Steitoep i Fo Mefers_ Dens Wt Strict ora1� Sesry : 10/6/2012 10/7/2012 1,311.0 8.55 Finish rigging up slick line unit and PU tool string. RIH with 2.25" gauge ring to "XX" plug set at 9,376' wlm. Attempt to POOH — slick line spool would not operate.Troubleshoot problem — Changed out hydraulic relief valve on hydraulic pump. POOH f/9,376' wlm with 2.25" gauge ring. RIH and pull equalizer prong from "XX" plug at 9,376' wlm. RIH and pull "XX" plug from "XX" nipple at 9,376' wlm. RU circulating lines on tubing and IA. Test lines to 3000 psi — Good test. Bullhead 1.5x tubing volume 83 bbls seawater w/ 3% KCL. RIH and set "WRP" plug on slick line at 2,820' wlm. RD slick line unit. RU E -line sheaves and lubricator to run tubing punch. Test tools — unable to send firing voltage to perf gun — Troubleshoot same. 10/7/2012 10/8/2012 1,311.0 8.55 Change out firing panel on E-line unit and test tools.— Good test, Test lubricator to 3500 pat — Good test. RIH with tubing punch 1/2,639" and shoot 8 shots 2,638`- 2,63, RD E-line lubricator and sheave& Test lines to 3500 psi and bullhead down annulus t perfs at 2,639". Pumped 340 bbls (1.5x annular volume) down tubing and out of perfs — tubing on slight vacuum when stopped pump. RU sliddlne unit sheaves and lubricator. RIH and latch on to' WRP" at 2,820 P and sheeted off at SSSV at writ U pull WRP thru SSSV and sheared �ed � tool and RH latch onto W at 2, free WRP by bufheadug tubing— 15 bbls down tub— No success. RIH and attempt again. to d WRP to free same— No success. POOH and RD sNckltne unit and lubricator — verily tubing, pressure is at 0 psi. Instal BPV in tubing hanger and ND production tree. NU BOPE. 10/8/2012 10/9/2012 1,311.0 8.60 Finish NU BOPE. Install test dart in BPV, and test upper and lower VBR w/ 2 7/8" and 4" test joint to 250 psi low /3500 psi high. Test upper and lower IBOP valve to 250 psi low /3500 psi high. Test annular w/ 2 7/8" test joint to 250 psi low /2500 psi high. Test all floor valves to 250 psi low /3500 psi high. Test 14 choke manifold valves to 250 psi low /3500 psi high. All tests charted and all tests held for 5 min. AOGCC Rep Check Sheave waived witness at 15:20 hrs on 10/04/1/ — updated at 15:00 hrs on 10/06/12. Initial system psi: 3000; 1950 after closure; 200 psi= 29 sec, full pressure 2 min. 07 sec. Fluid pack 7 5/8" x 2 7/8" annulus with seawater. Pull BPV from tubing, install landing joint, back out LDS and unseat hanger. Pump seawater down tubing attempting to circulate thru perfs — no returns. Pump 14 bbls down IA — Monitor well for 10 min, then pump additional 7 bbls down IA. Well confirmed to be taking fluid. RU ESP sheave, trunk and 2 7/8" tubing equipment to pull completion — Pump 4 bbUhr down tubing and 6 bbl/hr down IA to ensure well is static. Pull hanger to the rig floor and LD same. Connect ESP wire and control lines to spools. POOH laying down 2 7/8" completion f19,530' t/6,845'. Pump 100% excess displacement plus 10 bbls every hour — well continues to take fluid. 10/9/2012. 10/10/2012 1,311.0 8.60 POOH laying down 2 7/8" completion 1/8, 845' t/6,665'. Change out spools in ESP spoolkg unit. POOH laying down 2 7/8" completion 06,665' 1/80'. LD ESP pump assembly — al jewelry and clamps accounted for. Clean and der all used completion jewelry from rig floor. RU control line spools and instal new spool in ESP spooling unit MU Baker ESP pump & motor assembly, tech wire, and motor Work 10/10/2012 10/11/2012 1,311.0 8.60 RIH with 2 -7/8" L -80 6.5# IBT -M ESP completion t/6,876' MD' 10/11/2012 10/12/2012 1,311.0 8.60 RIH with 2-7/8'1-80 6.5# IBT -M ESP completion 1/8,876' MD' t/9,560'. Land Hanger, RILDS, and test hanger seals to 5000 psi for 10 min. Pressure test 2-7/8" x 7 -5/8" annulus to 2500 psi for 30 min charted, Good. Pressure test 2-7/8" tubug to 3500 psi for 30 min charted, Pressure decrease by 300 psi.. Page 1/2 - P I 0 N E E R • Operations Summary Report -e Well Name: ODST -45A I NATURAL RESOURCES Jobs Job Category WORKOVE sit o roasl.es€ Dens t.a „�, I Swine. En4OaYt (- - ..;, (tg . -: -_ Mudd. r ': Siannery- s 10/12/2012 10/13/2012 1,311.0 8.60 Attempt to test tubing to 3500 psi — 300 psi bleed down over 30 min. Shut in surface equipment and test same — Good test. RD control line sheaves and ESP sheave and hose. Move out ESP spooling unit and spot slick line unit. Attempt to test tubing to 3500 psi — No success, lost 600 psi in 1 hour. Change out 0-ring on landing joint and retest tubing — same result. RU slick line unit and lubricator and Run 1- 2.2" centralizer and SB pulling tool — sat down at 2,682' wlm. Run 2- Reconfigure tools string and RIH — same result. Run 3 - Reconfigure tools string and RIH — same result. Run 4 - Weight bar and 2.24 LIB and take impression at 2,682' wlm. Inspect LIB and discuss same — mark matches GLM pocket design. * Run 5- 2- 2.1" cent, 2- 5' weight bar and SB pulling tool — same result. Run 6 - Reconfigure tools string and RIH — same result. Run 7- 8' weight bar, 2.1" cent, 5' weight bar and SB pulling tool to 9,460' wlm. Pull ball and rod off of seat, flush ball seat with 10 bbls 8.6 ppg brine and reseat ball and rod. Attempt to test tubing — unable to reseat ball and rod. Attempt to seat ball and rod while pumping — No success. Pumped 35 bbls total at max rate of 4 bpm with 900 psi. POOH — retrieved dummy GLV, assumed from GLM #2 at 2,669' rkb, 2,682' wlm. 10/13/2012 10/14/2012 r 1,311.0 ` 8.60 Continue sock Ins work: Run S- same toot string as run sat down 81 2,682' wlm Run 9- bow spring cent and SB pulRng toot — sat down at 2,687 wkn. Run 10- Add 2 knuckle jokes, RIH and retrieve ball and rod at 9,483'. Run 11- RIH and set rebuff dummy GLV at 2,682' whir. Run 12 - RIH and attempt to ptd RHC-M body at 9, 484' wint — No success. Rut 13 - RIH and retriev RHC-M **al 9484_ Run 14 RIH ar4set c wat At tafest . c aucceee Average onesatue kss� 100 10 min. RD` slick line ir18 and = lubricator Clear rig floor of al ESP tools, used damps and ESPcabie: LD landing joint and instal BPV in tubing hanger, NO BOPE. Run control lines thru wellread penetrations and test' same. SSSV control fine tested to 5000 pal for 10 mitt— Good teat PVV control the tested ter 3500 psi for 10 min Good test " RIG RELEASED AT 24:00 HRS 10113/12" Page 2/2 - ODSi5A RWO - ESP Swap Smpietion Casing Well Head: 10 -3/4 ", 5K, VetcoGray item* - Item MD (1t) TVD (ft) y A 18" Conductor 153 153 Tree: 3 -1/2 ", 5K, Horizontal B 10 -3/4" 45.5# L -80 BTC, 9.95" ID 4,973 3,438 C 7 -5/8" 29.7# L -80 BTC-M, 8.875" ID (Window) 10,038 4,996 0 D 4 -1/2" 12.8# Hydril 521 3.958" ID 15,429 5,018 E 2 -7 6 .5# LSO IBT-M Tubing 9,560 4,847 O 1 VetcoCray Tubing Hanger 34 34 2 2 -7/8 HES Wellatar TRSV w/ 2.313" Packing Bore 2,025 1,994 GLM #1 - Vanoil 2 -7/8" x 1 -1/2" w/ DV installed O 3 (1 joint above top X nipple) 2,528 2,432 4 2 -7/8" XNipple 2.313" I.D. (1 joint from r' 2,575 2,488 ��� WFT 7 -5/8" x 2 -7/8" Gas Vent Valve Packer 5 (max. T/D 2500') 2,628 2,506 GLM #2 - Vanoil 2 -7/8" x 1 -1/2" DV installed e 7 6 (1 joint below packer) 2,668 2,537 G G #3 - Vend! 2 -7/8" x 1 -1/2" DV installed • O 7 (2 joints above X nipple) 9,360 4,785 0 2 -7/8" X Nipple, 2.313" I.D. w/ "RHC -M" Plug with - 8 extended neck installed inc. 68 deg) 9,442 4,810 9 Automatic Divert Valve (ADV) 9,490 4,825 /� 10 ESP (Pump, Motor, and Jewelry) 9,500 4,828 l"J 11 Chemical Injection Mandrel w/ 3/8" control line to surface 9,553 4,845 �_� End of Assembly 9,560 4,847 O 12 WFT PER Tie Back Sleeve 1511 9,891 4,951 WFT"TSP" Liner Top Pkr w/ Hold Down Slips 5 -1/2 20#x 13 7 -5/8 29.70 w/ Vam Top HT Box Down 9,907 4,956 WFT "PHR" Rotating Hyd Set Liner Hanger 5 -1/2 20# x 7- 5/8 29.70 #w/ 5 -1/2 Vam Top HT Pin x Pin XO w/ 5 -1/2 14 Vam Top HT Box x 4 -1/2 Hydril 521 Pin 9,910 4,957 WFT 4 -1/2 12.60# x 5.75od x 15 Ft "Genesis" Water - � 15 Based Swellable Packer w/ 4-1/2 Hydril 521 Box x Pin 11,401 5,173 L'J -.1 4 -1/2 12.60 L -80 Hydri Pupjt 4ft (Ported w/ 8 1/2 holes) 11,581 5,170 4 -1/2 12.80 L -80 Hydra Pupjt 411 (Ported w/ 6 1/2 holes) 11,788 5,169 • O • 4 -1/2 12.60 L-80 Hydra Pupjt 4ft (Ported w/ 6 1/2 holes) 11,991 5,171 © 4 -1/2 12.60 L -80 Hydra Pupjt 4ft (Ported w/ 6 1/2 holes) 12,196 5,171 4 -1/2 12.60 L-80 Hydra Pupjt Oft (Ported w/ 6 1/2 holes) 12,402 5,159 4 -1/2 12.80 L -80 Hydra Pupjt 4ft (Ported w/ 6 1/2 holes) 12,688 5,132 4 -1/2 12.80 L-80 Hydrl Pupjt 411 (Ported w/ 8 1/2 holes) 13,009 5,101 4 -1/2 12.60 L -80 Hydra Pupjt 4ft (Ported w/ 6 1/2 holes) 13,213 5,083 O 4 -1/2 12.80 L-80 Hydra Pupjt 411 (Ported w/ 8 1/2 holes) 13,417 5,065 4 -1/2 12.60 L-80 Hydri Pupjt 4ft (Ported w/ 8 1/2 holes) 13,584 5,052 O O O 4 -1/2 12.80 L -80 Hydra Pupjt 411 (Ported w/ 6 1/2 holes) 13,787 5,032 4 -1/2 12.60 L-80 Hydra Pupjt 411 (Ported w/ 8 1/2 holes) 13,989 5,018 4 -1/2 12.80 L-80 Hydra Pupjt 411 (Ported w/ 8 1/2 holes) 14,195 5,015 4 -1/2 12.60 L -80 Hydra Pupjt 411 (Ported w/ 6 1/2 holes) 14,398 5,012 4 -1/2 12.80 L -80 Hydra Pupjt 411 (Ported w/ 6 1/2 holes) 14,600 5,004 12 0 4 -1/2 12.60 L-80 Hydn Pupjt 411 (Ported w/ 8 1/2 holes) 14,808 5,001 � 4 -1/2 12.60 L-80 Hydn Pupjt 411 (Ported w/ 8 1/2 holes) 15,008 5,001 ® 4 -1/2 12.60 L-80 Hydra Pupjt 411 (Ported w/ 6 1/2 holes) 15,210 5,008 4 -1/2 12.60 L-80 Hydra Pupjt 411 (Ported w/ 6 1/2 holes) 15,417 5,018 Ray Oil Tool Silver Bul et Eccentric Float Shoe CO 1 . . 16 (PLUGGED) w/ 4 -1/2 Hydril 521 Box 15,422 5,018 _+ TO 15,429 5,018 O - 15 (Liiiii, � 00 00 00 00 00 00 00 00 Cement Squeeze 00 00 00 00 00 00 00 0 16 P O ° when well was 00 00 00 00 00 00 00 00 sidetracked o _ J Estimated Top of Cement @ EZSV 10100' MDrkb / 5017'TVDrkb 10100' MD / Cement above packer: 2.5bbI / 50' 5017' TVDrkb Cement below packer: 79.5bbI / 1277' to 7 -5/8" shoe + 100' w/ 30% excess bullhead below shoe 7 -5/8 ", 29.7# L -80 BTC -M, 6.875" ID 1 1 11377' MDrkb / 5412' TVDrkb Date: Revision By: Comments PIONEER 1/31/2011 RBT Proposed ESP Completion 2/23/2011 JAD Proposed ESP Completion ODST -45A ESP Swap NAI ��� I �� W 9/6/2012 RJJ Proposed ESP Swap + Add Chemical Inj Completion L 9/27/12 TC Added GLM below packer 10/13/12 KLC ESP Change Out RWO �wA'; ��� � THE STATE Alaska Oil and Gas °fA LASKIN,. Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue Anchorage, Alaska 99501 -3572 ��ALAS�� Main: 907.279.1433 Fax: 907.276.7542 Tim Crumrine Staff Completions Engineer Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, AK 99501 c. Q 7 7 Re: Oooguruk Field, Torok Oil Pool, ODST -45A Sundry Number: 312 -357 Dear Mr. Crumrine: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 67 v L7, ,t)_. Cathy I'? Foerster Chair L- DATED this L , day of September, 2012. Encl. A • RECEIVED PIONEER SEP142012 NATURAL RESOURCES ALASKA AOGCC Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, Alaska 99501 Tel: (907) 277 -2700 Fax: (907) 343 -2190 September 5, 2012 Commissioner Foerster Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Ste. 100 Anchorage, Alaska 99501 Re: Oooguruk Development Project Oooguruk Drill Site Well T -45A • Request for Sundry Approval to Recomplete Dear Commissioner Foerster: Pioneer Natural Resources Alaska, Inc. hereby applies for an Application for Sundry Approval to recomplete well ODST -45A (PTD 209 -079). The estimated date of commencement is September 30, 2012 following the ODST -47 completion. The well was drilled in the Oooguruk -Torok Pool as an oil producing development well. The original well was drilled in the Oooguruk-Nuiqsut pool (ODSN -45) and later recompleted to the Torok (ODST -45A) on October 30, 2009. A subsequent rig workover was conducted to swap the 4 -1/2 inch tubing completion to a 2 -7/8 inch ESP completion. During the well's producing time the ESP has failed with a prognosis of a shorted power cable. The proposed recompletion operation attached includes swapping the ESP for a smaller, fit for purpose pump based on well decline, and adding a scale inhibitor chemical injection mandrel below the pump. Please contact me at (907) 343 -2184, or by email at tim.crumrine(pxd.com if you have any questions. Sincerely, • e e 4, Tim Crumrine, P.E. Senior Staff Completions Engineer Pioneer Natural Resources, Inc. Enclosures: AOGCC Form 10 -403 Sundry Attachments • • RE,9 E4 l l Z, STATE OF ALASKA S hd 14 012 �� ALASKA OIL AND GAS CONSERVATION COMMISSION 9YIV APPLICATION FOR SUNDRY APPROVALS AOGCC 1 ' s 1 s 20 AAC 25280 1. Type of Request: Abandon ❑ Plug for Redrili ❑ Perforate New Pod 0 Repair Well El , Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing Q Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate 0 Alter Casing 0 Other. Replace Tubing & ESP El - 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Pioneer Natural Resources Alaska, Inc. Development El Exploratory ❑ 209 -079 3. Address: 700 G Street, Suite 600 Stratigraphic ❑ Service 0 6. API Number: Anchorage, AK 99501 50 -703- 20577 -01 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No !9 ODST -45A 9. Property Designation (Lease Number): 10. Field /Pool(s): ADL 355036 , Oooguruk -Torok Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MO (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 15,429' 5,018' . 15,422' 5018' N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 153' 153' N/A N/A Surface 4931' 10 -3/4" 4973' 3438' 5210 psi 2470 psi Intermediate 9994' 7 -5/8" 10,050' 5001' 6890 psi 4790 psi Production Liner 5533' 4 -1/2" 9891' - 15,434' 4951' - 5018' 8430 psi 7500 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attachment, pg. 2 See Attachment, pg. 2 4 12.6# L - 80, HYD 521 9906' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): TRSV; Hydro II Pkr; TSP Liner Top Pkr; Water Swell Pkr 2010' MD /1980' TVD; 2611' MD/2495' TVD; 9907' MD/4956' TVD; 11,400' MD/5173' TVD 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program Q BOP Sketch ❑ Exploratory ❑ Development [] Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 9/30/2012 Oil Q Gas ❑ WDSPL ❑ Suspended pe ❑ 1 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Tim Crumrine, 343 -2184 Printed Name Tim Crumrine - i °17' , V p `'''" vyy Title Staff Completions Engineer Signature Phone 343 -2184 Date 9/7/2012 Prepared By: Kathy Campoamor, 343 -2183 d j //, ir_ /i .4-. e_ COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ,3102 , ✓t37 Plug Integrity ❑ BOP Test b Mechanical Integrity Test ❑ Location Clearance ❑ Other: - ] — C S i .0' UP ./72 3 S S L Subsequent Form Required: /r (1174/' ) 9_(....1/7 L 1 APPROVED BY Approved by: /� _COMMISSIONER THE COMMISSION Date: C ) — "( 2— ,, io o �t • 1l?oW 2t i2 J ///'.V ORIGINA g ,� .�� Submit in Duplicate / � • Pioneer Natural Resources Alaska Inc. ODST -45A Page 2 AOGCC Form 10 -403, Application For Sundry Approvals Present Well Condition Summary, Box 11 Perforation Depth (MD/TVD) Attachment Perforation Depth (MD /TVD) 4 -1/2", 12.60 #, L -80 Liner - Pup joints ported with 6 -1/2" holes @ depths listed: MD TVD 11,581' - 11,586' 5170' - 5170' 11,786' - 11,791' 5169' - 5169' 11,991' - 11,996' 5171' - 5171' 12,196' - 12,200' 5171' - 5171' 12,402' - 12,406' 5159' - 5159' 12,688' - 12,692' 5132' - 5132' 13,009' - 13,014' 5101' - 5101' 13,213' - 13,217' 5083' - 5083' 13,417' - 13,422' 5066' - 5065' 13,584' - 13,588' 5052' - 5051' 13,787' - 13,792' 5032' - 5032' 13,989' - 13,994' 5018' - 5018' 14,195' - 14,200' 5015' - 5015' 14,396' - 14,401' 5012' - 5011' 14,600' - 14,604' 5004' - 5004' 14,806' - 14,810' 5001' - 5001' 15,008' - 15,013' 5001' - 5001' 15,210' - 15,215' 5008' - 5008' 15,417' - 15,422' 5018' - 5018' • SUMMARY PAGE • ODS -T45A Capital Rig Workover PTD #: 209 -079 Current Status: ODS -T45A is currently shut in due to failed Centrilift ESP. Scope of Work: • Prep well for rig workover, i.e. pull X plug with pressure gauge, tubing punch 2 -7/8" tubing below WFT Hydrow II packer and vent gas trapped. Dummy off all GLM. • MIRU Nabors 19AC, pull and lay down 2 -7/8" tubing and failed ESP equipment. • Pick up and run in the hole with Chemical Injection mandrel and new Baker Hughes Centrilift ESP equipment with new 2 -7/8" 6.5 #/ft L -80 IBT -M tubing along with TRSSSV and Weatherford's Hydrow II (Gas Vent Valve) Packer. • Land completion and function test all components. GENERAL WELL INFO: MASP: The maximum expected surface ressure, assuming gas from surface to the first perforated joint at 11,582' MD/5170' TVD is estimated at 1,700 psi (2,000 psi BHP @ 5,170' TVD with a 0.06 psi /ft gas gradient). Reservoir Pressure / TVD: The current reservoir pressure is estimated between 1700 and 2000 psi at the first perforated joint at 11,582'MD/5,170' TVD. A tubing plug with a memory gauge below is currently in the tubing X nipple at 9,377' MD/4,781' TVD. The annular packer vent valve is closed. Prior the workover the plug and gauge will be pulled to determine the current reservoir pressure. Wellhead Type & Pressure Rating: Vetco Gray MB -233 WH Production System rated at 5 000 psi YP 9 Y Y p BOP Configuration: 11" 5,000 psi Annular / Pipe / Blinds / Mud Cross / Pipe Kill Weight Fluid 8.4#/gal Seawater will be used from CPAI STP CPF3 TIFL / MIT -IA / MIT -OA: N/A Well Type: ESP Producer Estimated Start Date: October 15, 2012 Sr. Completion Engineer: Tim Crumrine Work: 907.343.2184 Cell: 907.240.4295 Email: tim.crumrine @pxd.com ODS Wellsite Leader Joe Polya / Rod Klepzig Work: 907.670.6606 Email: OoogurukDriltingSupervisor @ pxd.com • • ODS T -45 Workover Programme PIONEER NATURAL RESOURCES ODST -45A Oooquruk- Torok Production Well ESP Change Out AFE# 017062 — $X.XXX MM — 9.0 days Sundry #xxx.xx Version #1 Prepared: Date: Dave Hildreth Wellsite Leader Reviewed: Date: Tim Crumrine Senior Staff Completions Engineer Reviewed: Date: Rob Tirpack Drilling Superintendent Approved: Date: Vern Johnson Drilling Manager 1 ODS T -45 1 Pioneer Natural Resources ODS T -45 Workover Programme WORKOVER OBJECTIVE: Change out production tubing, ESP and install chemical injection mandrel. Operational Modes: 1. Wireline and Well Kill Operations 2. Workover /recomplete with Rig Nabors 19Ac 3. Wireline Operations CURRENT CONDITIONS: ODS T -45 was shut in 2 -3 -2012 due to failed motor. On 5 -2 -12 and a plug and pressure gauge was set on 6 -20 -2012. Prior to shut, the well was on production at Qo = 230 stb, Qw = 295 bpd, and Qg = 723 mscf /day with a WC of 60 %. NOTES: 1. Currently the formation pressure is 1,600 psi which is below a seawater gradient of 0.46psi /ft. 2. Filtered seawater ( <20 NTU's) from CPAI Seawater Treatment Plant (STP) will be the completion and kill fluid. 3. Store as must STP water from CPF3 as possible because of the possible interruption of STP operations. 4. In a well control situation, discontinue filtering completion fluids. Name Title Phone Tom Abbott, Marvin Zimmer Well Work Supervisor 907 - 670 -6602 Tim Crumrine Staff Completions Engineer 907 - 240 -4295 Vern Johnson Drilling Manager 907 - 575 -9430 Joe Polya / Rig Wellsite Leader 907 - 670 -6606 Rodney Klepzig Jeff Hight / NS Travel / Security 907 - 670 -6600 Greg Smith ODS Control Room Operations 907 - 670 -6642 Jimmy Clark /TBD Production Supervisor OTP 907 - 670 -6530 LIST OF ATTACHMENT: 1. ODS T -45 Pre -Rig Workover Checklist 2. ODS T -45 Current Schematic 3. ODS T -45 Recomplete Schematic Proposed 4. Current Vendors Upper Completion Diagram 5. Production Liner and upper completion Tally 6. Directional Survey 7. Approved Sundry xxx -xx 2 ODS T -45 ESP Change Out I Pioneer Natural Resources • • ODS T -45 Workover Programme BASIC WELL DATA: Well Number ODSK -45 Wed Type Torok Producer TD Depth 15,429' MD/5,018' TVD Permit to Drill 209-079 API Number 50- 703 - 20577 -01-00 Completion Date 10 -15 -2012 (Workover) Rig Name/No Nabors 19AC Pad Elevation 13.50' RKB to GL 42.7' RKB + MSL 56.2' Surface Co- ordinates 2965' FSL, 1102' FEL, Sec 11, T13N, R7E, U 1D Coordinates 1684' FSL, 1629' FEL, Sec 14, T13N, R7E, U Max Hole Angle & depth 95.8• (0 12,800 ft & 13,700 ft Hole Section Depot (ft KB) Hose Casing & Tubing MD/TVD Top Bottom Size Size Wt/ft Grads Conn ID Drift Burst Collasps MD Sulf 3173 ft Surface TVD Surf 3052 ft 9.625in 40 L-80 BT &C 8.835in 8.679in 5750 psi 3090 psi Intermediate MD 3401 ft 7853 ft 7.000in 26 L-80 BT &C -M 6.276in 6.276in 7240 psi 5410 psi TVD 2852 ft 5284 ft Lower Completion MD 9891 ft 4951 ft TVD 15429ft 5018 ft 4.500in 12.6 L-80 Hydril 521 3.958in 3.833in 8430 psi 7500 psi Upper Complston MD Surf 9536 ft Surf 4950ft 2.875in 6.5 L-80 IBT M 2.441 in 2.347in 10572 psi 11170 psi TVD Tubular and Annular Capacity Data Drift Capacity Annular or Casing Annular Volume OD ID Production Tubing bbUft ftn3/ft Size Mt ID bbUft 1thTllt 2.875in 2.4411n 2.347in 0.0058 0.0313 7.625in 29.7 6.875in 0.0459 0.2482 Mandrel Size Depth MD/TVD Valve Size Port Size Latch Type 1 2.875 MD 2553 ft 1 50in RK TVD 2451 ft MD 9376 ft Gas Litt Valve Data 2 2.875 TVD 4789 ft 1.50in RK 3 2.875 MD TVD 4 2.875 MD TVD PRE RIG WIRELINE & WELL KILL: 1. MIRU HES Wireline, Conduct PJSM and mitigate Hazards identified. Discuss operations with crew and discuss objectives. Lock SSSV open. 2. RU, RIH with 2.5" gauge ring with added wt. bars and centralizers tools string to top of plug set in "XX" Nipple at 9,440 ft MD (71°). Contingency is to pull the DGLV at 9,294 ft MD and using diesel from LRS or the P -6 pump to assist in mobilizing the tool string down hole. Can pump through the ports above the Auto Divert Value (ADV) 3. RIH and pull XX Plug and gauge to surface. Down Toad data and send to town. 4. If possible, put well on production over night through Expro Test Unit. ODS T -45 ESP Change Out I Pioneer Natural Resources • • ODS T -45 Workover Programme 5. Following the flow period, RU HES Wireline to tubing punch 2 -7/8" tubing. RIH using pipe tally and CCL and perforate 2 -7/8" tubing below the WFT Hydrow II packer using 2" gun 4spf, 0° phasing using decentralizer and magnet sub. 6. Put well back on production through Expro to dissipate the gas build up below WFT Hydrow II packer. 7. Packer Gas Vent Valve control line should be fluid packed. Lube & bleed hydraulic fluid into line. 8. RIH and pull DGLV from mandrel #2 2501 ft MD. 9. Line up P -6 or LRS and reverse circulate in 110 bbl FSW (1.5 %) down IA and up through tubing. 10. Set DGLV in GLM at 2,501 ft. Bleed trap pressure off the IA as needed until the tree is rigged down. FLUIDS & PITS AND RSC CLEANING 1. All rig pits and lines must be cleaned thoroughly before conducting workover operations. Downhole fluid losses are anticipated with the current bottomhole pressure. Clean fluid must be maintained at all times to minimize the potential for formation and or skin damage. 2. Use Baraclean FL mixed with filtered seawater and ensures it circulated through all pumps, lines and pits. All contaminated fluids can be sent to RSC for disposal. RIG WORKOVER SECTION (DECOMPLETION) 1. Install the BPV in the GE tubing hanger as per SOP's a. Note: A minimum of 2 barriers are required, i. Tubing: BPV, closed SSV and kill weight fluid on formation. ii. Annular; Kill weight fluid above packer, Packers gas vent valve is closed, Wellhead 2. Install VG test dart, ND tree and NU the BOP's Notify AOGCC 24 hr.'s prior to pressure testing BOP's. 3. Pressure test BOP's as per AOGCC requirement to 250 psi /3500 psi for 5 minutes on each item. 4. Ensure Eline unit is on location to utilize a string shot or Jet Cutter to assist in releasing packer if required. 5. Using a 2.25" drifted full open stabbing valve (FOSV), make up to a 3 -1/2" landing joint. 4 ODS T -45 ESP Change Out 1 Pioneer Natural Resources • ODS T -45 Workover Programme 6. Pull the BPV and test dart. Bull head 10 bbl of viscositied FSW and then followed with a tubing volume of FSW. Can bull head fluid through the ports above Auto divert valve. 7. Install 3 -1/2" landing joint with FOSV and screw into tubing hanger. Remember the Veco Gray tubing hanger is off set with ESP completions. Heat wellhead will make it easier to unseat tubing hanger. 8. Conduct PJSM on plan forward and discuss the operational step. Review the Baker Hughes Centrilift's "Pulling ESP Completion SOP dated 2 -2008. 9. PU and unset hanger. After the hanger is unseated, try and unset the Hydrow II packer set at 2,665 ft. Packer shear releases at 33,000Ibs Note: Be aware that pulling the packer may require pulling 90% of the tensile loading of the 2 -7/8" 6.5 #/ft L -80 IBT tubing which is 130,000Ibs. 10. If 90% tensile loading is exceeded refer to fishing operations in attachment. Notify Nabors Superintendent before exceeding 80% of the tensile loading (116,000Ibs not including top drive) on the 2 -7/8" tubing. 11. Once the packer is released, pick up and with the hanger below annular, close the annular and check for flow. Gas may be trapped below the packer. Monitor wellbore for 30 minutes. If an influx is seen, pump kill fluid down the tubing and down the IA as needed. 12. After monitor the well, open the annular, pull tubing hanger to surface. Rig up the following: a. HES control line spooler b. Centrilift cable sheave with drip pan and hose. c. Centrilift Spooler on the ground 13. Confirm that Centrilift checklist is completed for rigging up and POOH. 14. POOH laying down 2 -7/8" production tubing. New 2 -7/8" tubing will be run on the recompletion. While POOH, ensure the control lines and ESP cable are pulling 1:1 ratio. 15. Collect and count all clamps. Note and report in Well View any clamps lost in the hole. 16. POOH laying down 2 -7/8" tubing, jewelry and ESP a. Keep pressure on the SSSV control line to keep it open while POOH b. Have ESP cable and control line cutters on the rig floor at all times should an influx be seen. ODS T -45 ESP Change Out 1 Pioneer Natural Resources • i ODS T -45 Workover Programme c. Inspect all tubulars and jewelry for scale build up and report on WellView. p J rY p p All tubulars, jewelry and ESP will be replaced on the recompletion of the well. d. Landing joint with FOSV will be in the mouse hole as a contingency if a well control issue is seen. If influx is seen, pick up the 3 -1/2" contingency joint with FOSV. Make up landing joint to the tubing stub (XO may be required), cut ESP cable or control line if required. RIH, close annular and bleed control line. Fluid pack IA with 1.5 times the IA theoretical volume at Qp= 6 bpm. Once IA is fluid packed, shut down pump and monitor the IA for 30 minutes. If well is dead, open annular check flow again once annular is open. e. OOH, and if junk is left in the hole, converse with town, discuss and agreed upon plan forward to attempt fishing operations. Make sure junk baskets and magnets for 4" drill pipe is on ODS during workover. RE- COMPLETION OF WELL: Pick up the following using 2 -7/8 ", 6.5 # /ft, L -80, IBT tubing as per list below: 1. Pickup Baker Hughes Centrilift ESP -DH P/T Gauge -ADV- Chemical Injection Mandrel - Cable- Cannon Clamps @ ±9,560 ft MD. a. Centrilift will make electrical connect to ESP, install OTC clamps for ESP (every other joint. Need to check communication to confirm w/ ESP DHPTG's and conductivity of electrical cable every 1000 ft. GW and TRSSSV Control lines needs check periodically to confirm integrity. 5.13ID Cannon Clamps are okay to use b. I - jt 2 -7/8" 6.5 #/ft L -80 TCII Tubing c. 2 -7/8" "X" Nipple w/2.313" ID d. 2 - jts 2 -7/8" 6.5 #/ft L -80 TCII Tubing e. 2 -7/8" Vanoil GLM #2 w/ 1.5" DGLM installed f. 2 -7/8" 6.5 #/ft L -80 TCII Tubing g. Weatherford's 7 -5/8" X 2 -7/8" Hydrow II Gas Vent Valve Packer i. Weatherford to supervise the PU & MU of the Gas Vent Valve Packer With Chemical injection and ESP cable. They will install control lines to packer function test and maintain 500 psi control line pressure Ensure valve stays closed while RIH Purge control line to ensure clean hydraulic fluid for GW Packer h. I - jt 2 -7/8" 6.5 #/ft L -80 TCII Tubing. i. 2 -7/8" "X" Nipple w/2.313" ID. j. 2 -7/8" Vanoil GLM #2 w/ 1.5" DGLM installed. k. 2 -7/8" 6.5 #/ft L -80 TCII Tubing I. HES TRSSV at 2,500 ft. i. RIH pick up HES 2 -7/8" TRSSSV. Purge lines to ensure clean hydraulic fluid, install and function test valve. Hold 4,000 psi on control line while RIH. m. PU landing joint with FOSV and Veco Gray tubing hanger. 6 ODS T -45 ESP Change Out 1 Pioneer Natural Resources • • ODS T -45 Workover Programme OD ID Length Assembly Item Description Depth (MD) Length (ft) (inches) (inches) (ft) Nabors 19AC KB 34. :0 ft 34.00 ft Vetco Gray Tub ng Hanger 10.79 in 1 54 ft 35.54 ft Cross -Over TO > P -P 2.88 n 2.44 in 2 CC ft 37.54 ft 2 -7/8" 6.5#/ft 1-80 TCII Pup jts 2.88 in 2.44 in 2.00 ft 39.54 ft 75 2 -7/8" 6.5# /ft 1 -80 TCII Tubing 2.88 in 2.55 in 2417.25 ft 2456.79 ft 2 -7/8 ", 6.4# /ft. L -80 Pup Jts 2.88 in 2,44 in 6.00 ft HES 2.313" X Nipple 1.50 ft 13.50 ft 2470.29 ft 2 -7/8 ". 6.4# /ft, L -80 Pup its 2.88 .n 244 in 6.00 ft 2 -7/8" 6.5#/ft L -80 TO; Tubing 2.88 n 2.44 in 32.23 ft 2502.52 ft 2 -7/8" 6.5#/ft L -8C TC; Pup its 2 88 in 2.44 in 6.00 ft Vanoil 2 -7/8" X 1.5 " GLM #1 2.88 in 2.44 in 8.75 ft 18.75 ft 2521.27 ft 2 -7/8" 6.5#/ft 1 -80 TO: Pup its 2.88 in 2.44 in 4.00 ft 2 -7/8" 6 5 #/ft L -80 7 C: "ub :ng 2 88 in 2.44 in 32.23 ft 2553.50 ft 2-7/8 6.4# /ft, L -80 Pup its 2.88 n 2.44 n 6.00 ft HES 2.313" X Nipple 1.50 ft 13.50 ft 2567.00 ft 2 -7/8 ", 6.4#/ft, L -80 Pup Jts 2.88 in 2.44 in 6.00 ft 2 -7/8" 6.5#/ft L -80 TCII Tubing 2.88 in 2.44 in 32.23 ft 2599.23 ft Cross - Over 2.88 in 2.44 in 15.00 ft WFT &' X 2 -7/8" Hydrow II ESP / Chem 6.88 in 2.88 in 6.00 ft Injection line Packer 15.00 ft 2517.52 ft Cross- Over 2 n 2.:4 in 2.00 ft Cross -Over 4.00 ft 2:0 2 -7/8" 6.5# /ft L -80 TCII Tubing 2.8.8 in 2.55 in 6768 ft 9285.82 ft 2 -7/8" 6.5#/ft 1 -80 TCII Pup its 2.88 in 2.44 in 6.00 ft Vanoil 2 -7/8" X 1.5 " GUM #2 2.88 in 2.44 in 8.75 ft 18.75 ft 9304.57 ft 2 -7/8" 6.5 #/ft 1 -80 'C : Pup its 2.88 in 2.44 in 4.X ft 2 2 -718" 6.5 #/ft L -80 7C: Tubing 2.88 in 2.55 in 6446 ft 9369.03 ft 2 -7/8 ", 6.4#/ft, L -8C Pup Jts 2.88 in 2.44 in 6.00 ft HES 2.313" X Nipple 1.50 ft 13.50 ft 9382.53 ft 2-7/8", 6.4# /ft, L -80 Pup Jts 2.8.8 n 2.44 in 6.00 ft 2 -7/8" 6.5# /ft L -80 7C' -- ub rig 2 8S n 2.55 n 32.23 ft 9414.76 ft Cross -Over 10.00 ft Auto Divert Va :ve 4.0C ft 2 -7/8" 6.5#/ft L -80 TC Pup its 2.88 :n 2.44 :n 2.00 ft We Sgt Discharge Gauge 2.50 ft Centriflift ESP Assembly 98. ft 121.50 ft 9536.26 ft 2 -3/8" 4.7 #/ft L -80 EUE 8rd Pi Chemical Injection Valve 2.00 ft 2 -3/8" 4.7 #/ft 1-80 EUE 8rd Pi • Stab:.zer 3.00 ft 2. Land Tubing Hanger while maintaining 4500psi on control lines. Once landed, RILDS for Tubing Hanger. Test both the upper and lower Tubing Hanger body seals to 5000psi. Set BPV. 7 ODS T -45 ESP Change Out Pioneer Natural Resources • • ODS T -45 Workover Programme 3. ND BOPE and ensure Vetco Gray personnel are present prior to lifting stack and recovering control lines so as to prevent kinking. Note: Centrilift tech to continue to monitor cable conductivity throughout process. 4. Feed control lines thru WH body, install Vetco Gray Wellhead hydraulic fittings, install needle valve, test control lines 5000psi. Vetco Gray BIW penetrator prepped for THA installation. Monitor ESP communications during process. 5. NU Vetco Gray Production ESP X -mas Tree (Tubing Head Adaptor w/ ESP port, 3- 1/8 ",5k Vertical valve, & 5 -3/4" Otis Lubricator Adaptor) 6. Vetco Gray to replace BPV w/ TWC. Test Production X -mas Tree void to 5000psi and bleed off pressure. Test X -mas Tree internals through the 3" Prod Wing Assy. Test the 2" Gas Lift Wing Assembly against shop tested closed inner valve to 5000psi. Once tests are successfully completed, bleed pressure & recover TWC via lubricator or dry rod. 7. BHI install ESP pigtail to top of BIW penetrator protruding through the Tubing Head Adaptor. Monitor ESP communications during process. Centrilift techs to remain on location until released by drilling supervisor and production operations. 8. Set Weatherford GW packer per Weatherford rep instructions. Slowly increase tubing pressure to 3,500 psi (4,000 max) and hold for at least 15 minutes. Packer slips engage at 1,500 psi. Test annulus to 2,500psi. 9. Have Centrilift personnel on location to monitor ESP Comms. and electrical continuity. WIRELINE 1. MIRU HSE Wireline, conduct PJSM 2. Ensure the TRSSSV closural pressure to adequate hold open pressure 3. RU lubricator, tool string and pulling tool 4. RIH and pull rod and ball from X nipple located below WFT GW Packer 5. Pull DK Valve from upper GLM and dummy off same 6. RIH and retrieve RHC plug body, RD wireline and function test TRSSSV ESP START UP: 1. Ensure Baker Centrilift Personnel on location for ESP start up 2. Centrilift will be released with PNR operational approval. RDMO NABORS 19AC 1. Move drilling rig off and turn well over to Well Work Supervisor 2. Ensure ESP is operational before moving off well 8 ODS T -45 ESP Change Out I Pioneer Natural Resources • • • ODS T -45 Workover Programme CONTINGENCY FISHING OPERATIONS 1. If unable to pull packer with 90% of 2 -7/8" tubing tensile strength, prepare to cut tubing with Radial Cutting Torch. 2. Ensure casing collar locator is available to assist in correlating cutting position. 3. The optimum place to cut is 5' below the top of the 31.99' joint of pipe separating the X nipple assembly from the Weatherford Hydrow -II ESP Feed Thru packer. 4. A string shot should be run prior to cutting pipe to knock off any scale or debris from cutting area to ensure a clean cut. 5. A tubing punch may be needed below the cutting area for pressure equalization before cutting pipe. Verify with Halliburton and Baker Fishing prior to cutting pipe. 6. ESP Cable (1.395" OD) and Vent Valve Control Line (0.25 ") should cut along with the tubing, but may part on trip out of hole with upper cut section. 7. Baker Fishing Tools to provide overshot. 8. Baker Fishing Tools to provide dressing mill if needed. Upper section of cut should determine if flare is extensive and needs to be dressed prior to running overshot. 9 ODS T -45 ESP Change Out I Pioneer Natural Resources • • Client: Pioneer Natural Resources Nabors 19AC ODS T45 Proposd Installation: Exploration BOP Configuration Well: ODS T-45 API #: 50- 703 - 20577 -01 -00 PTD #: 209 -079 f' I O N E E R Date: TBD Nabors 19AC Rig Floor 4 • A A • 7 co To Shaker a xi rn a3 W 2 o m —I ao -o 0 0 ........... 0' 3 sv a co dnl Rh do Rh do dA rrn 1 in O 11" Sk Shaffer 11"5k Shaffer it o 0 0 W Spherical Spherical N o Annular C 11" 5k Double Gate m v BOP w/ 2 -7/8" X 5 " 1112 .a1 1•a .111 3 VBR's Top & Blind 3 -118" 5 K Choke Pi r Shears on Btm SEA:, Manifold w/ O ®lvJ ® Manual Chokes V • O Q. 1-2- 1/16" 5 k Manual Valve 1- o 2 Q 2 -1/16" HCR and 2-1/16" 5k ( P r 0 IMP i - e check valvecheck Valve �l ®� 4 -1 /6" X 3 -1 /8" I D SA ' L Blind Shears ii 4.. l CHOKE L ® ®� g / ., � -- t. 11" 51t _s 4,-.^-7:\,. c) KILL 'A' I :WI WI ° Mud ..... ... . f _ % _ ir. Cross i8 I , _i ® {^'� I 4-1/6" X ,rr„m in" ® 7 2-1/16" Var able Pipe Rams \ 0 DSA !■ rFi Ci 3 -1/8" 5k Manual im M • a � Valve w/ HCR �E ._ —__ ' 1 11" 5k X NT -2 11"5 =. N 5k Cameron Type U Single Studded Adaptor I t I Gate BOP w/ 2- 7 /8 "X5" VBR's 7 . 8 ft 94" Vetco Gray Spacer 0 ______fg - V -Lock with Gray Lock Clamp V --- MB-33 _ \' _ U l a Tree ILL uL as u.e ! cc oA L . • • GE Oil & Gas Drilling & Production PIONEER NATURAL RESOURCES - Oooguruk MB -233 WH PRODUCER SYSTEM 16" X 11 -3/4" X 7" X 3-1/2" HP 100228 -10; REF: S07112 -1A I (14.68) 1,.98 1 e _ (8.13) 100• - . -t (10.00) . t ' . CO 1 CASING MGR 11&2316 1.1 750 % 11.,50111 5% , IA MACE F.SOOEG SM. " a, 110.125) 141 15 9, 1 (1642) HI51006 -1 W GMN . `i 6 f (5 �) LIME 1111111E1017., Fms i r ^ f 6.915) Isao7}1 GRAYlOt ❑AWASST, lmu, 103173 5 CW/161.61,116230, 0„ A.12017 W/IIWC,5,4.50 OEGF, W w% ,i16,wP 1Y9{ 3.BYF NM �xmo5li A3zo1> ( 31) (,4.00).1 B9Ex. �ssEU,s %wx ALLOY 3 MACE 000: SERVICE, 11755 SEAL I II (.97) x.(1) .,3) (1.79) ` 6) (8. (4.56) „ (�',- 1' how L N " _ : a .' (8.13.) (16.00) + . (2.43) 11 1133695.45010479611, 11.711 M. COW RIM. 101)8 71 MS�CLAWxM MI6 w SID 109 7 7SA. 6M FOR 1010410M090X S E A L , 1140,04IA NICE Fy3P 1.1 1011. I ml (10.92) i i 1)5101 1 4040 52P10rt1, M &313, F41.12-571 7157 FIG :T! EnOS VUV6 �; (11. 7) (24 89) , ��= (34.57) L 1 I 4. I 111•6371 x11916... 0031; OF9.97. 9DO�R»10 ib➢MU6LpR55 IIIIIII MINI r (10.13)1 ( ) I .00 : r.. =fr4r� E 4.56 1 iIw ( 1737 1 t� _ 1161957 MOM AS9,m433.144/$97 41..• "IFF11' BE,[ EUdlOW 115F05, iMIC MEt MGM .... • i 1 (37.13) DOME � . .63 01 II ' _: )110, Y .. r .r _� (3 1.00) (13. 5) -- 1:11111111 - II 1111.103 1 l __ . : 1 ��...,� (24 i) x f mM luRw , %,FS113. 1 7COM O9111OS40 1 ft I. LEFT MO MA6QE AN 301 ■ (2.43) 0 (11.81) tan - 1 h r £ (2.39) = (4.38) (2.43) I A (11.04) (26 37) (26.37) (26.00) ,. r--1- (2.25 •.. ,1 06) (2.27) I ' I lil 1 ) — (12.75) 1151142 1 TUBING 4.411 EARL 16231, 321714 119 0011 &1 CMIII11 HER 579E MOM, 11.,50X 11 9BIO9AIC0 AWL 1 /&.110 OFF W] 7601116 11C. Ml, Rut® 1 1 MD MHO 0010.1 PIN 111117131) 616111.0.11. 4 10771116.1001 15 0lL 91401110,12.1 W21R W SAM. FR, 0/651 MODE dv a� w at 0a 0235 OK MD 51101001 RING 8 I 7 I 8 I 3 V L I 3 I 7 I / (24.88) , 9 118.2391 D (11.8691 0 0 0 © 0 I 3 /r�S�-rrVI • 0 (02.434) - -- -- -- ® (3.625) �����"__��--- 1/-14 AIN t i C -1- (2.6251 �, 0)09)6) ___ -_ -_ -_ ;03.903) - -- 103.94311 j - ` - - - - - -- 05.625 0 OFFSET i !4.909 -6TP1 NC l 4 © . (4 - 1/2 OD 12.6 PPF MOD BUTTRESS BO% 1 (4 H -RPV) A� s SECTION A - A e • r , 1 . SCALE 1/4 A �Jvetco Vetco Gray \ ASSEMBLY / SWE / \ MARKING LOCATION. TUBING 468, MB -233, OFFSET, MATT ROEBCNER 10 -3/4 % 4-1/2, 4-I/2 OD (2.6 PPF A I. DIMENSIONS ARE IN INCHES, a,. MOD BUTTRESS BOX BTM, 4.909 -6TPI MCA 306 TOP, 4H -BPV, W /HORIZONTAL OUTLET, + A/F 81W FEEDTHRU MANDREL AND LOWER MOPES' ; ar CONNECTOR, W /3-CONTROL LINES 02 JUN 10 ��� ` ®®-E} D ',Tar HP 100115- 10 I _It SOT uur tam. ...N.,., (an Of I 8 I 7 Pro /I MODEL PARAMS REV.VER: - .+ REL LEVEL: - BRANCH: 3 I 7 Pro /I DRAWING PARAMS REV.VER: - .0 GEL LEVEL: - BRANCH: - 1 .. I HMO • Current Schematic -State • PIONEER Well Name: ODSN -45A NATI )RAL RESOURCES HORIZONTAL - Sidetrack 1, 5/13/2011 9:45:41 AM Well Attributes API /UWI Field Name Well Status Total Depth (ftKB) Vertical schematic (actual) 50 -703- 20577 -01 -00 Oooguruk Unit DRILLED 15,429.0 1 -2 Casing Strings Conductor, 153.0ftKB Description OD (in) ID (in) Top (ftKB) Set Depth (ft... Set Dept... Grade Top Connection Wt/Len ( Ib/ft) 1 2-2 — 1 ='"="' Conductor 16 14.670 -67.6 153.0 153.0 H40 Welded 109.00 'll i 1 fl'' Casing Components a 1 Top (TVD) Item # Item Des Top (ftKB (ftKB OD (in) ID (in) Com 1 -2 Casing Joints -67.6 16 14.670 11 1 -1 Conductor Shoe 42.7 16 14.670 Surface, 4,973.0ftKB Description OD (in) ID (in) Top (ftKB) Set Depth (ft.._ Set Dept... Grade Top Connection Wt/Len (Ib/ft) Surface 10 3/4 9.950 -7.3 4,973.0 3,434.5 L -80 Buttress 45.50 12 -9 Thread M 1 Casing Components 12-131 Item # Item Des Top (ftKB) To (ftKB) D) OD (in) ID (in) Com IN 2 -7 10 3/4" Surface Shoe 4,971.4 3,434.0 10 3/4 9.950 12-17 Intermediate, 11,377.0ftKB Description OD (in) ID (in) Top (ftKB) Set Depth (ft... Set Dept... Grade Top Connection Wt/Len ( Ib/ft) 1I Intermediate 7 5/8 6.875 34.1 11,377.0 5,403.3 L -80 BTC -M 29.70 Casing Components _ Top (TVD) 2 - 23 - Item # Item Des Top (ftKB) (ftKB) OD (in) ID (in) Com 3 -10 7 5/8" Intermediate Shoe 11,374.0 5,402.3 7 5/8 6.875 WWT Reamer Float Shoe Production, 15,424.OftKB Description I OD (in) ID (in) Top (ftKB) Set Depth (ft. Set Dept... Grade Top Connection Wt/Len (5/5) I2 -7� Production 4 1/2 3.920 9,890.9 15,424.0 5,018.2 L -80 Wedge 521 12.60 Casing Components 2-29 Top (TVD) # Item Des Top (ftKB) (ftKB) OD (in) ID (in) Com 4 -1 WFT 16' PBR tie ba 9,890.9 6.38 5.750 2 -33 sleeve E C, � 4 -2 WFT TSP Liner top packer 9,907.2 6.65 4.750 2 -37 ✓ p 4 -3 WFT PHR Hyd Rotating 9,910.2 6.7 4.750 2 -39 V , i 4 -7 WFT Genesis 5.75" Water 11,400.5 5,173.4 4 1/2 3.920 2-41 �► ®( swell packer (= ■ 4 -2 \ 4 -10 4.5" Perf Pup with 6- 1/2" 11,581.5 5,169.9 4 1/2 3.920 r 4 -3 holes ti\ 4 -12 4.5" Perf Pup with 6- 1/2" 11,786.3 5,169.2 4 1/2 3.920 v holes I4 -7I ti < 4 -14 4.5" Perf Pup with 6- 1/2" 11,991.3 5,170.7 4 1/2 3.920 holes iI I 4 -10 4 -16 4.5" Perf Pup with 6- 1/2" 12,195.6 5,170.9 4 1/2 3.920 1 12 holes • 1 4 -18 4.5" Perf Pup with 6- 1/2" 12,401.6 5,159.1 4 1/2 3.920 '' 4 -14 holes 4 -16 4 -20 4.5" Perf Pup with 6- 1/2" 12,687.7 5,132.0 4 1/2 3.920 4 -18 holes 4-20 4 -22 4.5" Perf Pup with 6- 1/2" 13,008.8 5,101.6 4 1/2 3.920 • 1 holes 4 -22 4 -24 4.5" Perf Pup with 6- 1/2" 13,212.5 5,083.2 4 1/2 3.920 • 4 -24 holes i 4 -26 4 -26 4.5" Perf Pup with 6- 1/2" 13,417.0 5,065.5 4 1/2 3.920 1 4-28 holes 1 4 -30 4 -28 4.5" Perf Pup with 6- 1/2" 13,583.5 5,051.9 4 1/2 3.920 holes 4 -32 4 -30 4.5" Perf Pup with 6- 1/2" 13,787.0 5,031.8 4 1/2 3.920 • 4 -34 holes 7 4 -36 1 4 -38 4-40 4 -42 1 - 4 -44 4 -46 1 k - 4 - 47 Page 1/2 Report Printed: 5/13/2011 • • Well Name: ODSN -45A PIONEER Current Schematic - State NATI)RAI RESOURCES HORIZONTAL - Sidetrack 1, 5/13/2011 9:45:49 AM Casing Components Vertical schematic (actual) Top (TVD) I tem # Item Des Top (ftKB) (ftKB) OD (in) ID (in) Com 4 -32 4.5" Perf Pup with 6- 1/2" 13,989.2 5,017.6 4 1/2 3.920 1 -2 holes 4 -34 4.5" Perf Pup with 6- 1/2" 14,195.2 5,015.4 4 1/2 3.920 12 -2 — ara holes fl 4 -36 4.5" Perf Pup with 6- 1/2" 14,396.5 5,011.8 4 1/2 3.920 1 holes 4 -38 4.5" Perf Pup with 6- 1/2" 14,599.7 5,004.2 4 1/2 3.920 !■ holes ■ H1 -1 1 4-40 4.5" Perf Pup with 6- 1/2" 14,805.6 5,001.4 4 1/2 3.920 holes 4 -42 4.5" Perf Pup with 6- 1/2" 15,008.1 5,000.7 4 1/2 3.920 2 - holes 4 -44 4.5" Perf Pup with 6- 1/2" holes 15,210.3 5,007.7 4 1/2 3.920 2 -13 • 4 -46 4.5" Perf Pup with 6- 1/2" 15,417.4 5,017.9 4 1/2 3.920 holes 12 -171 4 4 -47 4.5" Production Liner Shoe 15,422.1 5,018.1 4 3/4 3.920 Ray Oil Tool Float shoe T Plugged Tubing Strings 4. Tubing Description String M. ID (in) Top (ftKB) Set Depth (f... Set Dept... Wt (Ib/ft) Grade Top Thread 1 2 -231 - ___ ESP completion 2 7/8 2.441 0.4 9,497.0 4,818.7 6.40 L -80 IBT -M Tubing Components Top (TVD) Item # Item Des Top (ftKB) (ftKB) OD (in) ID (in) Com J ® 13/16 2 -2 Vetco Grey Tubing Hanger 34.4 10 2.950 2 -9 HES TRSV Assembly 2,010.5 1,981.0 4.645 2.313 12-291 4 2 -13 HES GLM #2 w/ Dummy 2,501.6 2,412.1 5 1/2 2.365 Installed 12 -331 = 2 -17 HES X Nipple #2 w/ 2.313" 2,552.0 2,451.6 3.53 2.313 I ID 2 -23 WFT Hydrow 11 Packer 2,611.0 2,496.6 6.67 2.441 I2 -371 2 -29 GLM #1 w/ 1.5" DV 9,293.9 4,755.6 5 1/2 2.365 5/16" OV Installed Post 12 -391 j Installed Comp!. 12-41 2 -33 HES X Nipple w/ RHC -M 9,376.7 4,781.2 3.53 2.313 4 -1 2 -37 Baker Auto Diverter Valve 9,425.1 4,796.3 4 1/2 4-2 2 -39 Baker Discharge Gage 9,431.1 4,798.2 4 1/2 4 -3 2 -41 Baker ESP pump assembly 9,436.4 4,799.8 6.23 • 14 - 71 • 4 -10 • 4 -12 4 -14 4 -16 I 4 -18 i 4 -20 i 4 -22 • 4 -24 • 4 -26 • 4 -28 ▪ 4 -30 O 4 -32 O 4 -34 I 4 -36 • 4 -38 i 4 -40 • 4 -42 7 _4-44 4 -46 1 k - 4 -47 Page 2/2 Report Printed: 5/13/2011 D T- 45A0IVO - Proposed ESP At a Completion • O S p p p Casing - Item # item MD (ft) TVD (ft) A 16" Conductor 153 153 Well Head: 10 -3/4 ", 5K, VetcoGray 8 10.314" 45.5# t -80 BTC, 995' ID 4,973 3,438 Tree: 3-1/2", 5K, Horizontal C 7-5/8" 29 7# L-80 BTC-M, 6.875" ID (Window) 10,038 4,996 _ D 4 -112" 12.6#Hy4ri1521 3.958" ID 15,429 5,018 O E 2 -7/8" 6.5# L -80 IBT-M Tubing 9,560 4,847 0 ' 116- 1 Veto. ray Tubing Hanger 34 34 2 2 -7/8 HES W # Wester TRSV w/ 2.313" Packing Bore 2,031 2,000 G 1 - Vanoil 2.7/8" x 1 - 1/2" 4 DV installed • O 3 (1 joint a•.: 'op Xnipple) 2,553 2,451 4 2 -7/8" X Nipple 2.313" I.D. (1 joint from packer) 2,585 2,476 WFT 7-5/8" x 2 -7/8" Gas Vent Valve Packer (max. ND 5 2500) 2,617 2,500 GLM 02 - Vanoil 2 - 7/8" x 1 -1/2" DV installed ©M 8 (2 joints above X nipple) 9,376 4,789 2 -7/8" XNipple, 2.313" I.O. w/ "RHC-M" Plug with . O • 7 extended neck installed (Max inc. 68 de r 9,440 4,809 4 8 Automatic Divert Valve (ADV) 9,490 4,825 9 ESP (Pump, Motor, and Jewelry) 9,500 4,828 P . � � 10 Chemi Injection Mandrel w/ 3/8' control line to surface 9,530 4,828 ., End ofAssembly 9,560 4,847 " i O 11 WFT PBR Tie Back Sleeve 1511 9,891 4,951 WFT"TSP" Liner Top Pkr w/ Hold Down Slips 5-1/2 20#x 12 7 -5/8 29.70 w/ Vam Top HT Box Dawn 9,907 4,956 WFT "PHR" Rotating Hyd Set Liner Hanger 5-1/2 20# x 7- 5/8 29.70 #wd 5 -1/2 Vam Top HT Pin x Pin XD w/ 5-1/2 13 Vam Top HT Box x 4-1/2 Hydrll 521 Pin 9,910 4,957 WFT4 -1/2 12.60#x 5.75od x 15 Ft "Genesis" Water - � 14 Based Swellable Packer w/ 4-1/2 Hydril 521 Box x Pin 11,401 5,173 l J --J 4-1/2 12.60 L80 Hyddl Pupjt 4ft (Ported w/ 6 1/2 holes) 11,581 5,170 • 41/2 12.60 1-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,786 5,169 • O 4-1/2 12.60 L-80 Hydril Putt 4ft (Ported w/ 6 1/2 holes) 11,991 5,171 41----40 4- 1/212.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,196 5,171 4-1/2 12.60 L-80 Hyddl Pupjt 4ft (Ported w/ 6 1/2 holes) 12,402 5,159 '4-1/2 12.60 L80 Hydril Putt 4ft (Ported w/ 6 1/2 holes) 12,688 5,132 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,009 5,101 4-1/2 12.60 L-80 Hydril Putt 4ft (Ported wl 6 112 holes) 13,213 5,083 O 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,417 5,065 O 0 0 41/212.60180 - /744/ Putt 45 (Ported wl 61/2 holes) 13,584 5,052 4-1/2 12 60 L-80 Hydra Pupjt 411 (Ported w/ 6 1/2 holes) 13,787 5,032_ 4-1/2 12.601-80 Hyde{ Pupjt 45 (Ported wl 6 1/2 holes) 13,989 5,018 41/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,195 5,015 11 4-1/2 12.60180 Hydril Pupjt 45 (Ported w/ 6 1/2 holes) 14,396 5,012 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,600 5,004 ® O 41/2 12.60180 Hyddl Pupjt 4ft (Ported w/ 6 112 holes) 14,806 5,001 4-1/2 12.60 L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,008 5,001 4-1/2 12.60 L-80 Hydril Pupjt 4R (Ported w/ 6 1/2 hoes) 15,210 5,008 0 \ 41/2 12 60 L-80 Hydril Pu4t 4ft (Ported w/ 6 1/2 holes) 15,417 5,018 ��� Ray Oil Tool Silver Bullet Eccentric Float Shoe �� 15 (PLUGGED) w/ 4-1/2 Hydril 521 Box 15,422 5,018 O TO 15.429 5,018 C °A " 0 ‘ • ■.......,,......,......■ 1 00 00 00 00 00 00 00 00 - - ' 00 00 00 00 00 00 00 0 15 (�° Cement Squeeze 0 0 00 00 00 00 00 00 00 when well was sidetracked Estimated Top EZSV 10100' MDrkb / 5017'TVDrkb Cement @ 1 _ _ ____ _ Cement above packer: 2.5bb1150' 10100' MD ! Cement below packer: 79.5bbI / 1277' to 7 -5/8" shoe + 5017' TVDrkb 100' w/ 30% excess bullhead below shoe 7 -5/8 ", 29.7# L -80 BTC -M, 6.875" ID 1 1 11377' MDrkb / 5412' TVDrkb Date: Revision By: Comments P10 E 1/31/2011 RBT Proposed ESP Completion ODST -45A 2/23/2011 JAD Proposed ESP Completion Proposed ESP ����������� 9/6/2012 RJJ Proposed ESP Swap +Add Chemical In) Swap Completion 1 • ODS T45 Proposed ESP Completion Casing MI item ID MD (ft) 1VD (ft) A 16" Conductor 153 ft 153 ft 8 10- 3/4:45.5 # /ft L -80 BT &C 9.950 in 4973 ft 3438 ft C 7 -5/8" 29.7 # /ft L -8- BT &C M (Window) 6.875 in 10038 ft 4996 ft D 16" Conductor4 -1/2" 12.8 # /ft L -80 Hydril 521 3.958 in 15429 ft 5018 ft E 2 -7/8" 6.5 #/ft L -80 IBT -M 2.441 in 9560 ft 4847 ft - kipper Completion 1111 Description --- _ - - - - -- OD ID Length Assembly Depth NOD) Length (ft) inches inches 111111101111111 _ I Nabors 19AC KB 34.00 ft 34.00 ft Vetch Gray Tubing Hanger 10.79 in 1.54 ft 35.54 ft Cross -Over TC 11 P -P 2.88 in 2.44 in 2.00 ft 37.54 ft 2 -7/8" 6.5 # /ft L -80 Tell Pup jts 2.86 in 2.44 in 2.00 ft 39.54 ft 2 -7/8" 6.5#02 1 -80 TCII Tubing 2.88 in 2.55 in 2417.25 ft 2456.79 2 2 -7/8 ", 6.48/11, L -80 Pup Jis 2.88 in 2.44 in 6.00 ft HE5 2.313" X Nipple 1.50 ft 13 50 ft 2470.29 h 2-7/8", 6.49/ft, L -80 Pup Its 2.88 in 2.44 in 6.00 ft 2 -7/8" 6.58/ft 1 -80 TC3 Tubing 2.88 in 2.44 in 32.23 ft 2502.52 h 2 -7/8" 6.5 # /(t 1 -80 TO Pup jts 2.68 in 2.44 in 6.00 ft Vanoll 2 -7/8" % 1.5" GLM 81 2.88 fn 244 in 8.75 ft 18.75 ft 2521.27 ft 2 -7/8" 6.5 # /ft L -80 TCII Pup jts 2.88 in 2. 44 In 400 ft 2 -7/8" 6.59/ft 1-80 TCiI Tubing 2.88 in 2.44 in 32.23 ft 2553.50 ft 2 7/8 ", 6.4 # /ft, L -80 Pup its 2.88 in 2.44 in 6.00 ft HES 2.313" X Nipple 1.50 ft 13.50 ft 2567.00 ft 2 -7/8 ", 6.4 # /ft, L -80 Pup Its 2.88 in 2.44 in 6.00 ft 2 -7/8" 6.5 #/ft 1 -80 TCII Tubing 2.88 in 2.44 i 32.23 ft 2599.23 ft Cross- Over 2.88 in 2.44 in 15.00 ft WET &' X 2 -7/8" Hydrow it ESP / Chem 6.88 in 2.88 in 6.00 (t Injection line Packer 15.00 ft 2517.52 it Cross- Over 2.88 in 2.44 in 2.00 ft Cross -Over 4.00 ft 210 2 -7 /8" 6.58/ft 1 -80 TC0 Tubing 2.88 In 2.55 in 6768 ft 9285.82 ft 2 -7/8" 6.5 # /ft L -80 TCII Pup jts 2.88 in 2.44 in 6.00 ft Vanoll 2 -7/8" X 1.5 " GLM 82 2,88 in 2.44 in 8.75 ft 18 75 ft 9304.57 ft 2 -7/8" 6.5 #/ft 1 -80 TCII Pup jts 2.88 in 2.44 in 4.00 ft 2 2 -7/8" 6.5 #/ft L -80 TCII Tubing 2.88 in 2.55 in 64.46 ft 9369.03 ft 2 -7/8 ", 6.4 # /ft, L -80 Pup Its 2.88 in 2.44 in 6.00 ft HES 2.313" X Nipple 1.50 ft 1350 ft 9382.53 ft 2 -7/8 ", 6.4 # /ft, L -80 Pup its 2.88 in 2.44 in 6.00 ft 1 2 -7/8" 6.5 #/ft L -80 TCII Tubing 2.88 i0 2.55 in 32.23 ft 9414.76 ft Cross -Over 10.00 It Auto Divert Valve 4.00 ft 2 -7/8" 6.5 # /ft 1 -80 TCII Pup Its 2.88 in 2.44 in 2.00 ft Welligt Discharge Gauge 2.50 ft Centriflift ESP Assembly 98.00 ft 121 50 it 9536 26 ft 2 3/8" 4.79/511-80 EUE 8rd P1 - Chemical Injection Valve MEM - 2 -3/8" 4.78/ft 1 -80 WE 8rd Pi - Stabilzer 3 00 ft Description Lower Completion 00 ID Length 1ND(Et) 71/D (ft) (Inches) (Inc m WFT P08 Tie Back Sleeve 15ft ® i n WFT TSP Liner Top packer w/ hold down 5 -1/2" 20 #/ft X 7 -5/8" 29.70 #/ft w/ Vam 9907 ft 4956 ft Top HT Box down ® WFT "PHR" Rotating Hyd Set Liner hanger 5 -1/2" 20# /ft X 7 -5/8" 29.7 # /ft Mg= 4957 ft WFT 4 -1/2" 12.6# /ft X 5.75" OD X 15 ft "Genesis " Water Based Swellable Packer 13 14 4 -1/2 "12.6# /ft 1 -80 Pup Jt (Ported / 6 -1/2 holes) 4.00 ft 11401 ft 5173 ft 4-1/2"12.69/St 1-80 Pup 1t (Ported / 6 -1/2 holes) 4.00 ft 11581 ft 5170 ft 4- 1/2 "12.6#/ft 1 -80 Pup It (Ported / 6 -1/2 holes) 4.00 ft 11786 ft 5169 ft 4 -1/2 "12.66/11 1 -80 Pup Jt (Ported / 6 -1/2 holes) 4.00 ft 11991 ft 5171 ft 4-1/2"12.61t/ft L -80 Pup 11 (Ported / 6 -1/2 holes) 4.00 ft 12176 ft 5171 ft 4- 1/2 "12.6#/ft L -80 Pup 1t (Ported / 6 -1/2 holes) 4.00 ft 12402 ft 5159 ft 4 -1/2 "12.6#/11 L -80 Pup J1 (Ported / 6 -1/2 holes) 4.00 ft 12688 ft 5132 ft 4 -1/2 "12.6# /ft L -80 Pup It (Ported / 6 -1/2 holes) 4.00 ft 13009 ft 5101 ft 4- 1/2 "12.6#/ft 1.80 Pup It (Ported / 6 -1/2 holes) 4.00 ft 13213 ft 5083 ft 4 -1/2 "12.66/11 1 -80 Pup It (Ported / 6 -1/2 holes) 4.00 ft 13417 ft 5065 ft 4- 1/2 "12.6#/ft L -80 Pup It (Ported / 6 -1/2 holes) 4.00 ft 13584 ft 5052 ft 4 -1/2 "12.66/11 L -80 Pup Jt (Ported / 6 -1/2 holes) 4.00 ft 13787 ft 5032 ft 4- 1/2 "12.6#/ft L -80 Pup Jt (Ported / 6 -1/2 holes) 4.00 It 13989 ft 5018 ft 4- 1/2 "12.6#/ft L -80 Pup Jt (Ported / 6 -1/2 holes) 4.00 ft 14195 ft 5015 ft 4 -1/2 "12.6#/68 LSO Pup It (Ported / 6 -1/2 holes) 4.00 ft 14396 ft 5012 ft 4- 1/2 "12.6#/ft 1-80 Pup 11 (Ported / 6 -1/2 holes) 4.00 ft 14600 ft 5004 ft 4- 1/2 "12.6#/ft 1 -80 Pup 1t (Ported / 6 -1/2 holes) 4.00 h 14806 ft 5001 ft 4- 1/2 1 -80 Pup it (Ported / 6 -1/2 holes) 4.00 ft 15008 ft 5001 ft 4 -1/2 "12.6#/11 L -80 Pup It (Ported / 6 -1/2 holes) 4.00 ft 15210 ft 5008 ft 4- 1/2 "12.6#/ft L -80 Pup 11 (Ported / 6 -1/2 holes) 4.00 ft 15417 ft 5018 ft 15 Ray Oil Tool Silver Bullet Eccentric Float Shoe (Plugged w/ 4 -1/2" 15422 ft 5018 ft Hydril521 Bon TD 15429 ft 5018 ft • • ODSN -45A As Run Completion Well Head: 10 -3/4 ", 5K, VetcoGray Tree: 3 -1/2 ", 5K, Horizontal ;;�� Please see next page for completion detail �'J ' O ( 2 O O . 0 • O D o /„ �/ 0 / -c / 0 C 1�1 e • 0 14 o 00 00 00 00 00 00 00 00 Cement Squeeze 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 prior to the 00 00 00 00 00 00 00 00 1 sidetrack operations l� Estimated Top of Cement @ EZSV 10100' MDrkb / 5017'TVDrkb 10100' MD / - - -- Cement above packer: 2.5bbI / 50' 5017' TVDrkb Cement below packer 79.5bb1 / 1277' to 7 -5/8" shoe + i iii 100' w/ 30% excess bullhead below shoe L Top of 6" liner, 10,806' MDrkb / 5239' TVDrkb 7 -5/8 ", 29.7# L -80 __ BTC -M, 6.875" ID `` Top of Inner String fish, 10,825MDrkb 11377' MDrkb / 5412' 1 Live Severing Charge w/ 2.0" OD TVDrkb , Debris Catcher, 2.0" ID I 12413' MDrkb, Top of Expanded Section, 6 ", 18.6# L -80 Expanded to 44 6.767" OD, 6 ID, 6.131" Drift 1 tr);: t F FQ Connection unable to hol d pressure, 13,433 MDrkb 1 Expansion Cone 1 Expandable csg shoe 13,513' MDrkb / 6071' TVDrkb 13866' MDrkb / 6166' TVDrkb Hole Fill and Un- consolidated Cement Date: Revision By: Comments P10 N E E R 6/1/2009 JDF Proposed Completion Updat 6/16/2009 VHH Updated to current directional plan ODSN -45A 111001+ nCr � 'tCUA 9/28/2009 TWC Proposed Completion Revision Final Well tflfURRE d t9 SIO 11/21/2009 TWC As Run Update Schematic • • • ODSN -45A As Run Completion Casing Item # Item MD (ft) TVD (ft) A 16" Conductor 153 153 B 10 -3/4" 45.5# L -80 BTC, 9.95" ID 4,973 3,438 C 7 -5/8" 29.7# L -80 BTC -M, 6.875" ID (Window) 10,038 4,996 D 4 -1/2" 12.6# Hydril 521 3.958" ID 15,429 5,018 Upper Completion 1 VetcoGray Tubing Hanger 34 34 4 -1/2" XXO Safety Vale Landing Nipple w/ Wireline 2 Retreivable ScSSSV 759 758 3 GLM #1 Brou -1A GLM 4 -1/2" x 1" 2,032 2,000 4 4 1/2" X Nipple, 3.813" ID 2,089 2,053 5 GLM #2 Brou -1A GLM 4 -1/2" x 1" 9,689 4,889 6 4 1/2" XN Nipple, 3.725" ID Nogo 9,788 4,920 7 4 -1/2" HES ROC Gauge 9,840 4,936 8 WFT Seal Assy w/ Locator and 1/2 Muleshoe WLEG 9,890 4,951 End of Assembly 9,906 _ 4,956 Lower Completion Item # Item MD (ft) TVD (ft) 9 WFT PBR Tie Back Sleeve 15ft 9,891 4,951 WFT"TSP" Liner Top Pkr w/ Hold Down Slips 5 -1/2 20#x 7- 10 5/8 29.70 w/ Vam Top HT Box Down 9,907 4,956 WFT "PHR" Rotating Hyd Set Liner Hanger 5 -1/2 20# x 7- 5/8 29.70 #w/ 5 -1/2 Vam Top HT Pin x Pin XO w/ 5 -1/2 11 Vam Top HT Box x 4 -1/2 Hydril 521 Pin 9,910 4,957 WFT4 -1/2 12.60# x 5.75od x 15 Ft "Genesis" Water - 12 Based Swellable Packer w/ 4 -1/2 Hydril 521 Box x Pin 11,401 5,173 13 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,581 5,170 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,786 5,169 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,991 5,171 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,196 5,171 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,402 5,159 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,688 5,132 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,009 5,101 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,213 5,083 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,417 5,065 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,584 5,052 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,787 5,032 4 -1/2 12.60 L -80 Hydril Pupjt 411 (Ported w/ 6 1/2 holes) 13,989 5,018 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,195 5,015 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,396 5,012 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,600 5,004 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,806 5,001 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,008 5,001 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,210 5,008 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,417 5,018 Ray Oil Tool Silver Bullet Eccentric Float Shoe 14 (PLUGGED) w/ 4 -1/2 Hydril 521 Box 15,422 5,018 7D 15,429 5,018 DATA SUBMITTAL COMPLIANCE REPORT 6/12/2012 Permit to Drill 2090790 Well Name /No. 000GURUK TOR ODST -45A Operator PIONEER NATURAL RESOURCES AL API No. 50- 703 - 20577 -01 -00 MD 15429 TVD 5018 Completion Date 10/30/2009 Completion Status 1 -OIL Current Status 1 -OIL UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Su ey Yes DATA INFORMATION Types Electric or Other Logs Run: AFR, DGR, EWR, PWD (data taken from Logs Portion of Master Well Data Maint Well Log Information: III Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med /Frmt Number Name Scale Media No Start Stop CH Received Comments Rpt ✓ Report: Final Well R Open 11/25/2009 End of Well, Gen Info, 1 Morn Rep, Bit and Mud Rec, Show Rep, Form Top, Survey Rep, Days vs. Depth w /CD with EMF, PFD graphics for Mud Togs Log Mud Log 2 Col 153 15429 Open 11/25/2009 MD Combo Log Log , - Mud Log 5 Col 153 15429 Open 11/25/2009 MD Combo Log Log Mud Log 2 Col 153 15429 Open 11/25/2009 MD Engineering Log Log Mud Log 2 Col 153 15429 Open 11/25/2009 MD Gas Ratio Log ED ✓E Las 18977 Induction /Resistivity 150 15429 Open 11/25/2009 OH EWR logs DLIS, LAS and EMF, TIFF, CGM, & PDF graphics Log t. Induction /Resistivity 5 Col 153 15429 Open 11/25/2009 MD DGR, EWR, AFR III Log '' Induction /Resistivity 2 Col 153 15429 Open 11/25/2009 MD DGR, EWR, AFR Log Induction /Resistivity 5 Col 153 5018 Open 11/25/2009 TVD DGR, EWR, AFR Log ,- Induction /Resistivity 2 Col 153 5018 Open 11/25/2009 TVD DGR, EWR, AFR ED EVC Pdf 20699 Analysis - Misc 0 0 2/4/2011 Res Fluid Test, Water / analysis in PDF ED �C Pdf 14675 Gas Analysis 0 0 7/28/2011 Intertek Westport Technology Gas Analysis ( XLS and PDF) ED C 18976 Report: Final Well R Open 11/25/2009 End of Well, Gen Info, Morn Rep, Bit and Mud Rec, Show Rep, Form Top, Survey Rep, Days vs. Depth w /CD with EMF, PFD graphics for Mud logs DATA SUBMITTAL COMPLIANCE REPORT 6/12/2012 Permit to Drill 2090790 Well Name /No. 000GURUK TOR ODST -45A Operator PIONEER NATURAL RESOURCES AL API No. 50- 703 - 20577 -01 -00 MD 15429 TVD 5018 Completion Date 10/30/2009 Completion Status 1 -OIL Current Status 1 -OIL UIC N Well Cores /Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments ADDITIONAL INFORMATION Well Cored? Y /0 Daily History Received? 4811 • Chips Received? X1`7 V ---- Formation Tops N Analysis Received? Comments: Compliance Reviewed By: Date: `J `^� l •Z 410 • PIONEER NATURAL RESOURCES ALASKA J. Patrick Foley Manager of Land & External Affairs Pioneer Natural Re sources Alaska, Inc. 700 G Street, Suite 600 Anchorage, Alaska 99501 Voice (907) 343-2110 - Fax (907) 343-2190 September 27, 2011 Mr. Daniel T. Seamount, Jr. Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Suite 100 Anchorage, AK 99501-3539 ODST-45A Well Reclassification, Oooquruk Unit Dear Commissioner Seamount: Pioneer Natural Resources Alaska, Inc. (Pioneer) is in receipt of your letter dated September 20, 2011 in which you proposed reclassifying the ODST-45A well from exploratory to development. Pioneer has no objection to the proposed change and does not request a reconsideration of the proposed action. Please let us know if we can be of further assistance in this matter. Sincerely, 1(5`21tl J. Patrick Foley Attachment 1 1 o[F ALAzIKKA SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 September 20, 2011 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7009 2250 0004 3911 4320 Mr. Pat Foley Pioneer Natural Resources Company 700 G Street, Suite 600 Anchorage, AK 99501 Subject: Reclassification of Oooguruk ODST -45A Well (PTD 209 -079) Dear Mr. Foley: In accordance with 20 AAC 25.005(b), the Alaska Oil and Gas Conservation Commission (AOGCC) classified the Oooguruk ODST -45A well (ODST -45A) as an exploratory well when the permit to drill was issued. The AOGCC now believes that the well should be reclassified as a development oil well. Reclassification of ODST -45A from exploratory to development oil will remove the 24 month confidentiality period provided for exploratory wells by AS 31.05.035(c) and thus make the information filed on this well immediately available to the public. Pioneer Natural Resources Alaska, Inc. (PNR) has 20 days from your receipt of this letter to file an objection to the AOGCC's proposed reclassification of this well. The AOGCC believes the Oooguruk ODST -45A well should be reclassified as a development oil well because it has been in continuous production since March 2010 and has established the Oooguruk -Torok Oil Pool (defined in Conservation Order No. 645) as a known productive pool. Since ODST -45A is no longer functioning as an exploratory well,' but is instead a regular producer of oil, it should be reclassified as a development oil well. Additionally, subsequent wells permitted in the Torok Oil Pool have not been classified as exploratory. By statute, the AOGCC handles information from exploratory and development wells differently. AS 31.05.035(c) provides that information collected on exploratory wells be held confidential until 24 months after the well is completed, but information collected from 1 20 AAC 25.990(25): "exploratory well" means a well drilled to discover or to delineate a pool. 2 Through July 31, 2011, cumulative oil production from ODST -45A totals 203,128 barrels. 3 ODST -45A was completed on October 30, 2009; accordingly, the 24 -month confidentiality period expires on November 30, 2011. Mr. Pat Foley • • September 20, 2011 Page 2 of 2 development wells are not provided any period of confidentiality. Thus, upon reclassification, the AOGCC will make the information from ODST -45A available to the public immediately, unless it is provided confidentiality under another provision of state statute or regulation. Since reclassification will result in the release of information to the public, a couple of months sooner than would happen if the well is not reclassified, the AOGCC is allowing PNR the opportunity to provide justification as to why the AOGCC should reconsider this decision. Please contact Dave Roby at 793 -1232 with any questions regarding this matter. incerely, I af Daniel T. Seamount, Jr. Chair, Commissioner cc: William Barron, DNR -DOG RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. r U.S. Postal Service,,, CERTIFIED MAIL- RECEIPT r t- (Domestic Mail Only. No Insurance Coverage Provided) � For visit our website at www.usps.come ,a' y rl a a — Postage $ m Certified Fee = Postmark O Return Receipt Fee p (Endorsement Required) Here f' cm Restricted Delivery Fee 0 (Endorsement Required) I rU Total Postage & Fees fU Sen pi Natural Res. a o s 700 oneer G. Street, Suite 600 Alas r` °r te Anchora e, AK 99501 - - rse or - Instructions SENDER: COMPLETE THIS SECTION COMPLETE THIS SECTION ON DELIVERY • Complete Items 1, 2, and 3. Also complete A. ". re item 4 if Restricted Delivery is desired. .! 0 Agent ■ Print your name and address on the reverse i� — 0 Addressee so that we can retum the card to you. ~,_Iv b (Printed Name) C. Date of Delivery • Attach this card to the back of the mailpiece, or on the front if space permits. D. Is delivery address - i fy¢ ! • 1? 0 Yes 1. Article Addressed to: If YES,enter t • 0 No =' � -.., - •.^=+� • -•,, . „ r r�'9 Pioneer Natural Res. Alaska l \ a 700 G. Street, Suite 600 ' ` `S. Service Type . ' .c G s!" Anchorage, AK 99501 0ce►tmed Q Mail 0 Registered 0 Retum Receipt for Merchandise J � n . Q01-1 ale ! 0 Insured Mail 0 C.O.D. 4,,p c.10 55 4. Restricted Delivery? (Extra Fee) 0 Yes 2. Article Number 7009 2250 0004 3911 4320 (Transfer from service lam PS Form 3811, February 2004 Domestic Retum Receipt 102595 UNITED STATES POSTAL SERVICE I II II I First -Class Mail PS Po�ge & Fees Paid Permit No. G-10 a t • Sender. Please print your name, address, and ZIP +4 in this box' • C, cf TA %., (2,,, ra,,, i thska State of Alaska fa Oil and Gas Conservation Commission e 333 West 7th Ave., Suite 100 .. Anchorage, Alaska 99501 i liblbintJthll1uimi4t:ff ild.hisliflri,4e1ii,6ti:3'.FI • 1 PIONEER Y NATURAL RESOURCES ALASKA. Letter of Transmittal : ` "� } 3 =f , c. > T� ,, mss►� Date: July 27, 2011 FROM TO Shannon Koh AOGCC Pioneer Natural Resources Attn: Howard Okland 700 G Street, Suite 600 333 W. 7 Avenue, Suite 100 Anchorage, AK 99501 Anchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑ Maps ❑ Reports X Other —1 CD ❑ Agreement DETAIL QTY DESCRIPTION 1 CD ODST -45A and ODST -46 Gas Analysis Report (6 -2 -2011) We request that all data be treated as confidential information. Thank you. 51Afa- y- of q 3! pft_L(G Alo - #iE-t(, ?G OiL) Received by: Date: IA1_411_ Please sign and retum one copy to Pioneer Natural Resources, Inc., ATTN: Shannon Koh 700 G Street, Suite 600, Anchorage, AK 99501 907 - 343 -2193 fax 907- 343 -2128 phone STATE OF ALASKA ALASKA OAND GAS CONSERVATION COMMISSI• REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon ❑ Repair Well 0 Plug Perforations ❑ Stimulate D Other 0 Change Tubinq/Run ESP Performed: Alter Casing ❑ Pull TubinsEl Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown0 Perforate ❑ Re -enter Suspended Well 0 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Pioneer Natural Resources Alaska Inc Development 112 Exploratory ❑ b 209 -079 3. Address: 700 G Street, Suite 600 Stratigraphic Service ❑ 6. API Number: Anchorage, AK 99501 50- 703 - 20577 -01 -00 " 7. Property Designation (Lease Number): _ 8. Well Name and Number: ADL 355036 ODST -45A -. 9. Field /Pool(s): _ Oooguruk - Undefined `FRO k i 0 i L 5i + , 10. Present Well Condition Summary: Total Depth measured 15,429 feet Plugs measured N/A feet true vertical 5018 feet Junk measured N/A feet Effective Depth measured 15,422 feet Packer measured See Below feet true vertical 5018 feet true vertical feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 153' 153' N/A N/A Surface 4931' 10 -3/4" 4973' 3438' 5210 psi 2470 psi Intermediate 9994' 7 -5/8" 10,050' 5001' 6890 psi 4790 psi Production Liner 5533' 4-1/2" 9891' - 15,424' 4951' - 5018' N/A Perforation depth Measured depth See Attachment, pg 2 feet MAY 13al' True Vertical depth See Attachment, pg 2 feet & 3saha thi & GRR, Cnn6" Commission Tubing (size, grade, measured and true vertical depth) 2 -7/8 ", 6.5# L -80, IBT -M 7_flD 4827' TVD TS mer o p Pkr Water Swell Pkr Packers and SSSV (type, measured and true vertical depth) TRSV 42 2010' Hydro II Pkr 0 2611' @ 9907' MD/4956' 11,400' MD/5173' MD/1980' TVD MD/2495' TVD TVD TVD 11. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil-Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 530 52 167 865 267 Subsequent to operation: 258 362 578 278 309 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run Exploratory 0 Development 0 .. Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 15. Well Status after work: Oil Gas ❑ ?, a it ' WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP '] I SPLUG ❑ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 311 -052 . Contact Tim Crumrine, 343 -2184 Prepared By: Kathy Campoamor, 343 -2183 Printed Name Tim Crumrin_L Title Completions Engineer Signature Phone 343 -2184 Date 5/13/2011 ,,,,, ,0-_„?,,K, RBD �. / �'L— Submit Original Only Form 10-404 Revised 10/2010 M S MAY j 6 ZQn / g • Pioneer Natur Resources Alaska Inc. ODST -45A Page 2 AOGCC Form 10 -404, Report of Sundry Well Operations Box #10, Attachment Present Well Condition Summary - Perforation Depth 10. Open to production or injection 4 - ", 12.60 #, L -80 Liner - Pup joints ported with 6 -1/2" holes @ depths listed: MD TVD 11,581' - 11,586' 5170' - 5170' 11,786' - 11,791' 5169' - 5169' 11,991' - 11,996' 5171' - 5171' 12,196' - 12,200' 5171' - 5171' 12,402' - 12,406' 5159' - 5159' 12,688' - 12,692' 5132' - 5132' 13,009' - 13,014' 5101' - 5101' 13,213' - 13,217' 5083' - 5083' 13,417' - 13,422' 5066' - 5065' 13,584' - 13,588' 5052' - 5051' 13,787' - 13,792' 5032' - 5032' 13,989' - 13,994' 5018' - 5018' 14,195' - 14,200' 5015' - 5015' 14,396' - 14,401' 5012' - 5011' 14,600' - 14,604' 5004' - 5004' 14,806' - 14,810' 5001' - 5001' 15,008' - 15,013' 5001' - 5001' 15,210' - 15,215' 5008' - 5008' 15,417' - 15,422' 5018' - 5018' PIONEER OIllations Summary Report - State • Well Name: ODSN -45A NATURAL RESOURCES Well Name: Contractor: Rig Number: Job Category: Start Date: End Date: Start Depth Foot/Meters Dens Lest Start Date End Date (tt (B) (R) bud ( 0) Summary 4/8/2011 4/9/2011 15,429.0 8.80 Move rig f/ ODSK -41 to ODST -45A. RU on ODST -45A. RU slickline & lubricator. Test lubricator to 1300 psi. RIH and pull WRSSSV. MU 3.60" gage ring and brush assembly. RIH 1/9,690'. Tool stopped at 9,690'. RU circulating manifold and test to 3500 psi f/ 10 min. Fill tubing w/ 71 bbls 8.8 ✓ ppg 6% KCL water. Bullhead 6 bbls to push slickline tools 1/9,820'. POOH w/ gage ring / brush assembly. PU XN plug body on slickline and RIH. 4/9/2011 4/10/2011 15,429.0 8.75 Continue RIH w/ XN plug body on slickline to 9,765'. Attempt to set plug in RHC-M w/ no success. POOH and inspect plug body. Found frac sand preventing plug from shifting. Bulkhead 85 bbls 8.8 ppg 6% KCL water down tubing. RIH wI redressed / reconfigured XN plug body. Bullhead 80 bbls 8.8 ppg 6% KCL to assist in plug getting down and clean debits ahead. Attempt to set plug body in RHC-M w/ no success. POOH. Plug body hung up in lower GLM. Continue POOH. Lost plug in hole. RIH w/ "GS" pulling tool and tag up at lower GLM at 9,669'. POOH. No recovery. RIH w/ "GR" pulling tool and tag up at 9,669'. POOH w/ no recovery. PU double knuckle Joint w/ 3.25" centralizer and RIH. Tag up at 9,669'. Attempt to knock plug down and pump plug down w/ no success. POOH. RD slickline. RU Edine. RIH w/ Weatherford WL retrievable bridgeplug. 4/10/2011 4/11/2011 15,429.0 8.75 Continue RIH w/ Weatherford retrievable bridge plug on E -line f /6,000' and set at 9,620'. POOH w/ E -line. LD running tool. Pressure test tubing / bridge plug to 2500 psi f/ 10 min on chart. Good test. RIH w/ tubing punch to ±3,600'. Could not get down. POOH and LD guns. RU slickline and RIH. Pull dummy from GLM at 2,031'. POOH w/ slickline and RD same. Observe well. On vacuum. Reverse circulate 85 bbls 8.8 ppg 6% KCL taking returns to flowback tank. Pump down tubing taking retums out annulus and to flowback tank. Monitor well. On vacuum. Install BPV. ND tree. Install Test dart. NU BOPE. Test BOPE per AOGCC Sundry Approval: -Test BOPE w/ 4 -1/2" test joint to 250 psi low and 3500 psi high. Ba -Test annular w/ 4 1/2" test joint to 250 psi low and 2500 psi high. 1 -Test all floor valves to 250 psi low and 3500 psi high. -Test upper and lower IBOP valves to 250 psi low, 3500 psi high. -Test 14 choke manifold valves to 250 psi low, 3500 high. - Initial system pressure 3000, 2200 after closure, 200 psi= 19 sec. Full pressure 1 min.13 sec. -All tests charted and all tests held for 5 min. -Right to witness test waived by AOGCC Rep. Chuck Scheve at 15:00 hrs on 4/08/2011 and confirmed waiver at 09:30 hrs on 4/10/2011. 4/11/2011 4/12/2011 15,429.0 8.75 Continue to test BOPE. -Test Annular w/ 2 -7/8" test Jt to 250 psi low, 2500 psi high. -Test upper and lower variable rams to 250 psi low, 3500 psi high. -All tests held for 5 min - All tests on chart. -Right to witness test waived by AOGCC Rep. Chuck Scheve at 15 :00 hrs on 4/08/2011 and confirmed waiver at 09:30 hrs on 4/10/2011. -RD test equipment. Pull test dart. RU 4 -1/2" tubing equip. MU 4" XT39 x 4 1/2" HYD 521 XO to landing joint. Pup BPV, MU landing jt. to hanger and screw in Top Drive. Fluid pack tubing and IA w/ 8.8 ppg 6% KCL. Bleed gas from annulus to flowback tank. Circulate 20 bbls out annulus and into flowback tank. Shut in and monitor for pressure. 0 psi. Close annular. BOLDS. Pull hanger off seat w/ 135k up wt. Verify no pressure. Open annular and pup hanger to rig floor. LD landing jt and hanger. POOH LD 4-1/2" tubing f/9,905' 1303'. 4/12/2011 4/13/2011 925.0 386.00 8.80 Continue to POOH LD completion. Unload 4 -1/2" tubing from pipeshed. PU 4 -1/2" landing joint & break down. PU 4" DP w/ XO to hanger and break down. RU ESP equipment. Install wear ring. PU Baker reverse circ basket BHA and RIH 1/925'. Wash & ream f/925' 1/1,311'. POOH. LD BHA. Pull wear ring. Level rig for upcoming ESP completion run. RU to run completion. MU Baker ESP motor / pump. 4/13/2011 4/14/2011 1,311.0 0.00 8.80 RIH w/ 2 -7/8" ESP completion f/82'1/8,719'. Page 1/2 Report Printed: 5/13/2011 PIONEER O,ations Summary Report - State Well Name: ODSN -45A • NATE1RAL RESOURCES Start rah Foot/Metent Dens Last - Start Dale End Date (titCB) (R) Mud (ib/ya) Summary 4/14/2011 4/15/2011 1,311.0 0.00 8.80 Continue RIH w/ 2 -7/8" 6.5# L -80 IBT -M ESP completion f/8,719 PU IBT -M pup - PU jt. # 295 (last jt.) t/9,452'. PU & MU Vetco Grey hanger. Make ESP, PW and SSSV control line penetrations through hanger. Test SSSV contro line to 5000 psi f/ 10 min. Test PW control line to 3500 psi for 10 min. Land hanger f/9,452' 1/9,497' w/ BPV installed. RILDS. Test upper and lower hanger seals to 5000 psi. ND BOPE. NU Vetco Grey ESP Tree. Test tree to 250 psi low, 5000 psi high for 10 charted min. RU HES slickline & RIH w/ ball & rod assembly. Set ball & rod in RHC -M at 9,376'. POOH w/ Slickline. Fill tubing. Pressure up on tubing to set WFT packer to 3500 psi. Hold for 30 min on chart. Bleed tubing to 500 ps. Fill void in IA. Test IA to 2500 psi f/ 30 min on chart. Good test. RIH w/ Slickline to retrieve ball & rod. POOH. No recovery. PU bailer and RIH on Slickline to ±5,000'. 4/15/2011 4/16/2011 1,311.0 0.00 8.80 RIH w/ bailer fl *5,000' - Tag up at 9,166'. Worts bailer at 9,166'. Observed 1500 lbs overpum to get free. POOH w/ bailer. No significant recovery. RIH wl 2.30" swadge/centrallzer & bat/ and rod latch tool. Tag up at 9,166' WLM. Work through tight spot. RIH 1/9,368'. Latch up and POOH. Pulled tight at 9,166'. Work through and continue POOH. Lost B & R. RU and pressure to 300 psi to confirm bail on seat. RIH w/ latch tool & 2.27" centralizer. Tag up at 9,166' WLM. Could not get past 9,166'. POOH. LD 2.27" centralizer. RIH w/ latchn tool and no centralizer. Tag up at 9,296'. POOH. Recovered dummy valve from lower GLM. LD knuckle It and 5' weight bar. RIH w/ latch tool. RIH and latch B & R at 9,371' WLM. POOH. to 8 & R. RIH w/ 2.22" drift 1/9,200'. POOH. RIH w/ 5/16" Orifice valve and set in lower GLM at 9,293'. POOH. Verfy valve gone. Release rig at 24:00 hrs on 4/15/2011. Page 2/2 Report Printed: 5/13/2011 P i 0 N E E R •urrent Schematic - State Well Name: ODSN -45A NATURAL RESOURCES HORIZONTAL - Sidetrack 1, 5/13/2011 9:45:41 AM Well Attributes Vertical schematic (actual) API /UWI Field Name Well Status Total Depth (ftKB) 50- 703 - 20577 -01 -00 Oooguruk Unit DRILLED 15,429.0 1 -2 Casing Strings Conductor, 153.0ftKB Description OD (in) ID (in) Top (ftKB) Set Depth (ft... Set Dept... Grade Top Connection Wt/Len (lb/ft) 12 -2 r te. Conductor 16 14.670 -67.6 153.0 153.0 H40 Welded 109.00 - 1 Casing Components Top (TVD) Item # Item Des Top (ftKB) (ftKB) OD (in) ID (in) Com 1 -2 Casing Joints -67.6 16 14.670 �• --I1 -1 f 1 -1 Conductor Shoe 42.7 16 14.670 Surface, 4,973.0ftKB Description OD (in) ID (in) Top (ftKB) Set Depth (ft... Set Dept... Grade Top Connection Wt/Len (lb/ft) Surface 10 3/4 9.950 -7.3 4,973.0 3,434.5 L -80 Buttress 45.50 12 -91 !I'• Thread 1 Casing Components Top (TVD) 2 -13 IN Item # Item Des Top (ftKB) (ftKB) OD (in) ID (in) Com 1 1 2 -7 10 3/4" Surface Shoe 4,971.4 3,434.0 10 3/4 9.950 12-17 Intermediate, 11,377.0ftKB Description OD (in) ID (in) Top (ftKB) Set Depth (ft... Set Dept... Grade Top Connection Wt/Len (lb/ft) 1 Intermediate 7 5/8 6.875 34.1 11,377.0 5,403.3 L -80 BTC -M 29.70 -V Casing Components . 12-231 Top (TVD) _ _ _ - Item # Item Des Top (ftKB) (ftKB) OD (in) ID (in) Com ' 3 -10 7 5/8" Intermediate Shoe 11,374.0 5,402.3 7 5/8 6.875 WWT Reamer Float Shoe Production, 15,424.0ftKB 2 -7 Description OD (in) ID (in) Top (ftKB) Set Depth (ft... Set Dept... Grade Top Connection Wt/Len (lb/ft) Production 4 1/2 3.920 9,890.9 15,424.0 5,018.2 L -80 Wedge 521 12.60 12 29� Casing Components Top (TVD) Item # Item Des Top (ftKB) (ftKB) OD (in) ID (in) Com 4 -1 WFT 16' PBR tie back 9,890.9 6.38 5.750 12-33 — sleeve II 4 -2 WFT TSP Liner top packer 9,907.2 6.65 4.750 12 -37 4 -3 WFT PHR Hyd Rotating 9,910.2 6.7 4.750 hgr. 12-391 4 -7 WFT Genesis 5.75" Water 11,400.5 5,173.4 4 1/2 3.920 12-411 aEttl 4 -1 swell packer ....M , -2 4 -10 4.5" Perf Pup with 6- 1/2" 11,581.5 5,169.9 4 1/2 3.920 ' ,F � -3 holes 4 -12 4.5" Perf Pup with 6- 1/2" 11,786.3 5,169.2 4 1/2 3.920 holes . 14 -7 4 -14 4.5" Perf Pup with 6- 1/2" 11,991.3 5,170.7 4 1/2 3.920 holes • 4 -10 4 -16 4.5" Perf Pup with 6- 1/2" 12,195.6 5,170.9 4 1/2 3.920 4 -12 holes • I 4 -14 4 -18 4.5" Perf Pup with 6- 1/2" 12,401.6 5,159.1 4 1/2 3.920 holes i 4 -16 4 -20 4.5" Perf Pup with 6- 1/2" 12,687.7 5,132.0 4 1/2 3.920 7 4 -18 holes 4 -20 4 -22 4.5" Perf Pup with 6- 1/2" 13,008.8 5,101.6 4 1/2 3.920 1 holes i 4 -22 4 -24 4.5" Perf Pup with 6- 1/2" 13,212.5 5,083.2 4 1/2 3.920 • 4 -24 holes • 4 -26 4 -26 4.5" Perf Pup with 6- 1/2" 13,417.0 5,065.5 4 1/2 3.920 I 4 28 holes • 4 -30 4 -28 4.5" Perf Pup with 6- 1/2" 13,583.5 5,051.9 4 1/2 3.920 • 1 holes i 4 -32 4 -30 4.5" Perf Pup with 6- 1/2" 13,787.0 5,031.8 4 1/2 3.920 I 4 -34 holes i 4 -36 I 4 -38 i 4 -40 • 4 -42 -4-44 I f 4 -46 • k -4-47 Page 1/2 Report Printed: 5/13/2011 P 1 0NEER •urrent Schematic - State Well Name: ODSM -45A NATURAL RESOURCES HORIZONTAL - Sidetrack 1, 5/13/2011 9:45:49 AM Casing Components Vertical schematic (actual) Top(TVD) I tem # Item Des Top (ftKB) (ftKB) OD (in) ID (in) Corn 1 2 4 -32 4.5" Perf Pup with 6- 1/2" 13,989.2 5,017.6 4 1/2 3.920 holes 4-34 4.5" Perf Pup with 6- 1/2" 14,195.2 5,015.4 4 1/2 3.920 12 -2� 1 ' - holes 4 -36 4.5" Perf Pup with 6- 1/2" 14,396.5 5,011.8 4 1/2 3.920 I holes i 1 I I 4 -38 4.5" Perf Pup with 6- 1/2" 14,599.7 5,004.2 4 1/2 3.920 holes I 1 -1 4 -40 4.5" Perf Pup with 6- 1/2" 14,805.6 5,001.4 4 1/2 3.920 holes 4 -42 4.5" Perf Pup with 6- 1/2" 15,008.1 5,000.7 4 1/2 3.920 1 IlL holes P 4 -44 4.5" Perf Pup with 6- 1/2" 15,210.3 5,007.7 4 1/2 3.920 holes 12 -131 E 4 -46 4.5" Perf Pup with 6- 1/2" 15,417.4 5,017.9 4 1/2 3.920 i holes 12-17 i 4 -47 4.5" Production Liner Shoe 15,422.1 5,018.1 4 3/4 3.920 Ray Oil Tool Float shoe t Plugged Tubing Strings 1 e_ Tubing Description String M... ID (in) Top (ftKB) Set Depth (f... Set Dept. Wt (Ib /ft) Grade Top Thread 12 -23 : ESP completion 2 7/8 2.441 0.4 9,497.0 4,818.7 6.40 L -80 IBT -M x 1 Tubing Components Top (TVD) Item # Item Des Top (ftKB) (ftK6) OD (in) ID (in) Com ` 2 -2 Vetco Grey Tubing Hanger 34.4 10 2.950 1 12 -71 13/16 2 -9 HES TRSV Assembly 2,010.5 1,981.0 4.645 2.313 12 -29 2 -13 HES GLM #2 w/ Dummy 2,501.6 2,412.1 5 1/2 2.365 Installed 12-33 15-- 2 -17 HES X Nipple #2 w/ 2.313" 2,552.0 2,451.6 3.53 2.313 ID 1 2 -23 WFT Hydrow 11 Packer 2,611.0 2,496.6 6.67 2.441 2 -37 2.39 � 2 -29 GLM #1 w/ 1.5" DV 9,293.9 4,755.6 5 1/2 2.365 5/16" OV Installed Post Installed Compl. 12 -41 .rct 2 -33 HES X Nipple w/ RHC -M 9,376.7 4,781.2 3.53 2.313 4 -1 2 -37 Baker Auto Diverter Valve 9,425.1 4,796.3 4 1/2 2 -39 Baker Discharge Gage 9,431.1 4,798.2 4 1/2 1", ,. ∎ 4 -2 4-3 2 -41 Baker ESP pump assembly 9,436.4 4,799.8 6.23 I i 14-71 • • 4 - • 4 -121 I 4 -14 I i 4 -161 4 -18 I 4-20 I 4 -221 4 -241 • • 4 -26 4-281 • 4 -30 4 -321 I 4-341 4 -36 I 4-381 I i 4 -401 • 4-421 - -4-44 i / 4 -46 • 1 t - 4 - 47 Page 2/2 Report Printed: 5/13/2011 T STATE OF ALASKA ALAS OIL AND GAS CONSERVATION COMMIS N WELL COMPLETION OR RECOMPLETION REPORT AND LOG la. Well Status: Oil El Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development El Exploratory ❑ GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ No. of Completions: _ One Service p Stratigraphic Test ❑ 2. Operator Name: 5. Date Comp., Susp., or 12. Permit to Drill Number: Pioneer Natural Resources Alaska, Inc. Aband.: 3/10 /2010 209 - 079 3. Address: 700 G Street, Suite 600 6. Date Spudded: 13. API Number: Anchorage, AK 99501 10/10/2009 50 703 - 20577 - 01 - 00 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 2889' FSL, 1176' FEL, Sec. 11, T13N, R7E, UM 10/21/2009 ODST -45A Top of Productive Horizon: 8. KB (ft above MSL): 56.2' 15. Field/Pool(s): 1902' FSL, 5158' FEL, Sec. 14, T13N, R7E, UM GL (ft above MSL): 13.5' Total Depth: 9. Plug Back Depth(MD +TVD): Undefined 5165' FSL, 3650' FEL, Sec. 15, T13N, R7E, UM N/A 4b. Location of Well (State Base Plane Coordinates, NAD 27): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x - 469821.86 y 6031005.53 Zone - AsPA 15,429' MD / 5018' TVD ADL 355036 TPI: x 465820.3 y - 6024755.6 Zone - Asp a 11. SSSV Depth (MD + TVD): 17. Land Use Permit: Total Depth: x - 462059.3 y 6028036.9 Zone - Asp A 759' MD / 758' TVD 417497 18. Directional Survey: Yes 0 No • 19. Water Depth, if Offshore: 20. Thickness of Permafrost MD /TVD: (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) 835' MD / 821' TVD 21. Logs Obtained (List all logs here and submit electronic and printed information per 20AAC25.071): 22.Re- drill /Lateral Top Window MD/TVD: AFR, DGR, DGR /DDSr, DM, ABI, DIR, DDS, EWR, PWD, GR 10,050' MD / 5001' TVDD 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED Fr. 16" 109# H -40 Surface 153' Surface 153' 24" Driven 10 -3/4" 45.5# aTC Surface 4973' Surface 3438' 13 -1/2" 433 sx PF 'L'; 768 sx Class 'G' 7 -5/8" 29.7# L Surface 10,050' Surface 5001' 9 -7/8" 166 sx Class 'G' BTC - M 4 12.6# L 80 9891' 15,424' 4951' 5018' 6 Uncemented w/ pre - perfed pups HYD 521 24. Open to production or injection? YesU Noll If Yes, list each 25. TUBING RECORD interval open (MD +TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4-1/2", 12'6#' 9906' 9907' MD / 4956' TVD See Attachment, pg. 3 e L-80, HYD 521 f t•: i `Zth 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 1 ` DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED l Mi i • T ar 2032' Freeze protect w/ 85 bbls diesel w Perfed Pup Intervals,see pg :. Frac w/ 607,000 Ibs 20/40 Proppant 27. PRODUCT! 0 N TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Test Period - Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 24 -Hour Rate -pp. 28. CORE DATA Conventional Core(s) Acquired? Yes ❑ No El Sidewall Cores Acquired? Yes ❑ No In If Yes to either question, list formations and intervals cored (MD +TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. None RECEIVED MAY 0 6 20v, ReDMS MAY 0 S 2011.4 Aligkalfil & tiiN CMS g9i...e Form 10 -407 Revised 12/2009 CONTINUED ON REVERSE i irlf ?Pkinal only Antrieffsfie • • 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? ] Yes No If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if needed, Permafrost - Top 843' 842' and submit detailed test information per 20 AAC 25.071. Permafrost - Base 1678' 1663' Top West Sak 2343' 2280' Top Torok 10,036' 4996' None Mid Torok 10,648' 5090' Lower Torok 10,894' 5133' Formation at total depth: 15,429' 5018' 31. List of Attachments: Summary of Daily Drilling Operations, Well Schematic Diagram, Survey 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Alex Vaughan, 343 - 2186 Printed Name: Robert Tirpack Title: Drilling Superintendent Signature: 7 / ' Phone: 343 -2121 Date: 5/4/2011 Well Name: ODST -45A Perthit 209-079 Prepared By: Kathy Campoamor, 343-2183 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10 -407 well completion report and 10 -404 well sundry report when the downhole well design is changed. Item 1 b: Classification of Service wells: Gas Injection, Water Injection, Water - Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50- 029 - 20123- 00 -00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: 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 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut -in, or Other (explain). Item 28: 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 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10 -407 Revised 12/2009 • i Pioneer Natural Resources Alaska Inc. ODST -45A Page 3 AOGCC Form 10 -407, Well Completion or Recompletion Report and Log Box #24, Attachment 23. Open to production or injection 4-1/2", 12.60 #, L -80 Liner - Pup joints ported with 6 -1/2" holes @ depths listed: MD TVD 11,581' - 11,586' 5170' - 5170' 11,786' - 11,791' 5169' -5169' 11,991' - 11,996' 5171' - 5171' 12,196' - 12,200' 5171' - 5171' 12,402' - 12,406' 5159' - 5159' 12,688' - 12,692' 5132' - 5132' 13,009' - 13,014' 5101' - 5101' 13,213' - 13,217' 5083' - 5083' 13,417' - 13,422' 5066' - 5065' 13,584' - 13,588' 5052' - 5051' 13,787' - 13,792' 5032' - 5032' 13,989' - 13,994' 5018' - 5018' 14,195' - 14,200' 5015' - 5015' 14,396' - 14,401' 5012' - 5011' 14,600' - 14,604' 5004' - 5004' 14,806' - 14,810' 5001' - 5001' 15,008' - 15,013' 5001' - 5001' 15,210' - 15,215' 5008' - 5008' 15,417' - 15,422' 5018' - 5018' 1 • ODST -45A As Run Completion Well Head: 10 -3/4 ", 5K, VetcoGray Tree: 3 -1/2 ", 5K, Horizontal Please see next page for completion detail • 1 • O �� l ® O O O p 0 ./ O O ..Z D • 0 •,l O 4111 1 3 14 00 00 00 00 00 00 00 00 Cement Squeeze 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 prior to 00 00 00 00 00 00 00 00, sidetrack operations j ---- Estimated Top of Cement @ EZSV 10100' MDrkb / 5017'TVDrkb 10100' MD / Cement above packer: 2.5bbl / 50' 5017' TVDrkb Cement below packer: 79.5bbI / 1277' to 7 -5/8" shoe + 6 100' w/ 30% excess bullhead below shoe 7 -5/8 ", 29.7# L -80 Top of 6" liner, 10,806' MDrkb / 5239' TVDrkb BTC-M, 6.875" ID i Top of Inner String fish, 10,825MDrkb 11377' MDrkb / 5412' L Live Severing Charge w/ 2.0" OD TVDrkb • Debris Catcher, 2.0" ID 12413' MDrkb, Top of Expanded Section, i 6", 18.6# L -80 Expanded to 6.767" OD, 6.19" ID, 6.131" Drift Connection unable to hold pressure, 13,433 MDrkb 4 Expansion Cone Expandable csg shoe 13,513' MDrkb / 6071' TVDrkb 13866' MDrkb / 6166' TVDrkb Hole Fill and Un- consolidated Cement Date: Revision By: Comments P10 ■ i [ R 6/1/2009 JDF Proposed Completion Updat /16/2009 VHH Updated to current directional plan ODST -45A Current tl n^�lo ^I RESOURCES ALAN ALAN 9/28/2009 TWC Proposed Completion Revision Well Schematic IYIRE ft C 11/21/2009 TWC As Run Update ODSf -45A As Run Completion Casing Item # Item MD (ft) TVD (ft) A 16" Conductor 153 153 B 10 -3/4" 45.5# L -80 BTC, 9.95" ID 4,973 3,438 C 7 -5/8" 29.7# L -80 BTC -M, 6.875" ID (Window) 10,038 4,996 D 4 -1/2" 12.6# Hydril 521 3.958" ID 15,429 5,018 Upper Completion Item # Item MDrkb (ft) TVDrkb (ft) VetcoGray Tubing rlanger 34 34 4 -1/2" XXO Safety Vale Landing Nipple w/ Wireline 2 Retreivable ScSSSV 759 758 3 GLM #1 Brou -1A GLM 4 -1/2" x 1" 2,032 2,000 4 4 1/2" XNipple, 3.813" ID 2,089 2,053 5 GLM #2 Brou -1A GLM 4 -1/2" x 1" 9,689 4,889 6 4 1/2" XN Nipple, 3.725" ID Nogo 9,788 4,920 7 4 -1/2" HES ROC Gauge 9,840 4,936 8 WFT Seal Assy w/ Locator and 1/2 Muleshoe WLEG 9,890 4,951 End of Assembly 9,906 4,956 Lower Completion Item # Item MD (ft) TVD (ft) 9 WFT PBR Tie Back Sleeve 15ft 9,891 4,951 WFT "TSP" Liner Top Pkr w/ Hold Down Slips 5 -1/2 20#x 7- 10 5/8 29.70 w/ Vam Top HT Box Down 9,907 4,956 WFT "PHR" Rotating Hyd Set Liner Hanger 5 -1/2 20# x 7- 5/8 29.70 #w/ 5 -1/2 Vam Top HT Pin x Pin XO w/ 5 -1/2 11 Vam Top HT Box x 4 -1/2 Hydril 521 Pin 9,910 4,957 WFT 4 -1/2 12.60# x 5.75od x 15 Ft "Genesis" Water - 12 Based Swellable Packer w/ 4 -1/2 Hydril 521 Box x Pin 11,401 5,173 13 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,581 5,170 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,786 5,169 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,991 5,171 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,196 5,171 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,402 5,159 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,688 5,132 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,009 5,101 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,213 5,083 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,417 5,065 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,584 5,052 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,787 5,032 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,989 _ 5,018 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,195 5,015 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,396 5,012 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,600 _ 5,004 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,806 5,001 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) _ 15,008 5,001 _ 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,210 5,008 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,417 5,018 Ray Oil Tool Silver Bullet Eccentric Float Shoe 14 (PLUGGED) w/ 4 -1/2 Hydril 521 Box 15,422 5,018 TD 15,429 5,018 . 1 rcsunrnw- Rscofor I ,,_....- __, ...i Ft ESOUCP.:E36, ' 7pYsIO Name: Oppk+ '1 ' ' - Don4ractor: NABORS DRILLING Rig Number: 19 AC I IJob Ca4egzrr DEVELOPMENT DRILL abud Date: Rig Reiease Dee: ,..- :74Fxr.r.ex'7. :: IF:507,'"gr•*:=19stwatie•.'f;.;.4.1.,:'.:0744v;:,2',14•-.,:.;,,,,,,,Z ,- i ;•:, :.; . i;M : ; 24 :' , ' - ' 7 7 :- .7 4- i:I'':; ; .' s, 1- 3 7::: 0 4 . r.;: : :: , A:*, ,,, W414. - 1 7. 4.;;TaTil• C ' 7 4: , 1 - .. ;‘ , „logitioi - 47,:i. .. : :, := -7 ..4-1 , , , .V ' : '"%, , 7 N . -- , ' ,4 VA. , ,J 7 A ' 7 - ,4, ; 14. '" .-- 'Vt.'. ,.' , ':" 10/4/2009 10/5/2009 0.0 ' ' 8.55 Move Nabors 19AC from ODSN-34i to ODSN-45A (Note: ODSN-45i until mill window & kickoff) I and RU. Rig accepted on ODSN-45A ID 00:00 hrs, 10/04/09. Reverse circulate out diesel freeze protect. Check well for flovv - static. Install TWC valve and ND tree. NU BOPE. Change out bottom pipe rams from 3.5° to 4°. Test BOPE's. Annular to 250 psi low / 2500 psi high. Blind Rams, Upper VBR's (2-7/8° X 5') Lower 4° Rams, Kill & Choke HCR valves, Kill & Choke manual valves, Floor Safety & Dart valves, Upper & Lower IBOP valves to 250 psi low / 3500 psi high. 14 Choke Manifold valves to 250 psi low / 3500 psi high. All tests held 5 min each on chart. Accumulator test, System Pressure 3000 psi, After Closure 2100 psi, Initial 200 psi I recovery 17 seconds, Full pressure recovery 1 min 32 seconds. No Failures. AOGCC rep Jeff Jones waived witness of BOP test at 20:15 hrs on 10/3/09. Change out top drive saver sub. RU 2-7/8° handling tools. Install landing joint and unseat tubing hanger. LD tubing hanger and landing joint. 0,5129011C -._ ; 4 . 4 4 ,45 - : :ril&ii.:t;.. , - .*. IlL515, POOH & LD 2,71r WeidiStiffig,TPU dean 44.6=3/4 T1H tt3,104 -,, fai ..,-- , , , ,:, ,:. x ,,,,. ,--,,,,,,;,;,, 40, - ,..i.p to*e, - ::;: - :•''Ll l'C'-t ,:?-.,'. `,.', ', , -:4,: , 4 '.;' '-',.k ,. ; t.i- :'-'.-%..'. :. '-'-.W...-,.4,5",',4rAvt':'.7 ,'-'=. 'A ; ;t:''. , - ,2 '-=:;;;;:,' 7, - , --'-` , "-c4.)' , :: I. "'"-- ." ' ':',,-,7;12..:;., -e4 ...u,:-,41144 ,'‘,:-:;; . - %,,;;.y. , : .: ,,,-,:', -,*, ' 4.4 : i d :: : 1 :1Wt.: '' '4 : ; , .,,,;' , :it -, A; , 4 4 ;1:;"c:A6 -7 44 4 410,'" . 4.14.4V.I . ',54W4,2 . :', -, 4, al ',,-. ,i'.:1', : ?. ':*:" ' '''': N50 'Mt' ' :I.^^ ' 4 ,' , "0 . ..' , -... ,- !-- ' ,,,,' '''---.:- -,',"- ',-- 1 ."' '-g:%;;;'::-;,71.., ', 0 .T. ,-;',C-- ',; ',-. 10/6i2009 10/7/2009 0.0 8.60 TIH 113,104 1/9,350. LWD log 1/9,350' i/9,473. Pump 20 bbl hi-vis sweep and circulate out same through gas buster.1LWD log 1/9,473' 1/10,104'. Tagged up on cement retainer at 10,104'. I Pump 30 bbl hi-vis sweep and circulate out same. RU and test casing to 3500 psi held 30 min I on chart - Good test. POOH 1/10,104' to the BHA. Download LWD, remove nuclear sources, LD BHA. PU Fast Drill cement retainer with 4°, 2' shot interval, 6 spf, 60* phased Drill Guns and TIH 1/2,616'. arnatect ,, t i: , 4' 0 ! ',?:: ,44,2. -'-' , ..,51,1;Y: . ::; ,, z 4 RI14 with DrieGinAiiiibly f/2,618' 't/10,040`."Set Fast Drilt Packer neat doiiii It* to '.,, q' 146.,,,,Z-1 1, ',,,,';, ",,: .,. . Tn. Pressure up annulus to 1000 psi and fire pert guns with 3400 psi DP presstire,' c, ', 70 3,; ,, .',"-,,, ,4 0 ,. *, ,1 ,4 ,,54 t.,,,, •!; 7 eleased frore.packer with 220k PUW. RU cement lines and test to 3200 psi. perfOirri, iniethivity ;s1 '''' ".4 . '!'e04: - ; - , ',‘' ,. ",-1 . ..,t4, , k . — , at .5-3 bprn with IMP of psi. 20 bbls 8.6 ppg seawater ahead. Pump 33 bbls :,--,"..-',",,, --,. " 1.17 oulsk)'15.8 ppg Class . G. -- Cement, .2% CFR-3, .75%, Haled-344, .3°4 SCR-100 and. *pieced with 13-bb1s 8.6 ppg seawater. Sting into packer and squeeze cement away with tO , 1*:, ' . :‘,4 Liss 8.6 ppg seams* at 2.$ bpin with 2950 psL Final injection rate at 2, OM witil3ptxypC 1 i '''-' .. t ,,,,I t H 4-1 ::: us away.Total). Linitiriglrom-Fis Drill and POOH, t/9, Circulate surfacetcrtUrface.,,, ; ^'::•-•-.. ;,;''-4.51,,,44., v :::, 4 00014119;853`. pimio.a ppg. Dry POOH U9,85..TA,5,319'.:SecOnda4r Given SaVerfilied. ,-&. ,„ ,, ,.,-4, ,,„', .9 , . -......0- - e gt '. .',,.,,,•'-'il' : = .• ,, . ' korn derrick.: primary Crown Saier still operatiorcaL P0011,14,319,1/4257`4',..i 44 ;LT,,446, ' :, , ',;;•=_,"5 ..", OGCC given 24 to notice 10 witness 7=5/8" perforated casing cement squeeze.,.f9GCCS 0.7 V, , •nwevri„,k;ii:i.; :',--; :;E:„..:• i • - entities Jeff Jones waived of cement squeeze on 10 M74 7/09,::. ; ,,.., ; „ ‘ „ 4 .,.. : , i, ,,,, ,,,,,,,,. ,,,, -,,,,, 3., .y.:,,,„,-..,,,,,f--,-,-.., ; ,,,..,-..- ,-,. .' ,, i's r; *:>: 7 6 , ;si- ,7 1k4eaht:',*,:j ' ' '' :-`;'• '' .:,-,-, ffiiiir-,... ;-.„,:-,,..V 4: V.., ,, ' - 'ili - 4,V: -, '-;:t1..i:1 , :ixte': , :•,;.. - .:,_ ,, ,k, ,t14.7? ,%,- ; . ; ,,1 ;3 , : ,, I,1= 4 .7;:i.: 7' '' ' Ai 7 4" 1 11 7 431! , •;. , '.,,,--", 4;;:,'''';',* ;OAT,' ;;;4/- '7. , ,,,,,,I,1 ' Aq," '',.:1:-.;,„Acrt,r,,,6!"ei!.: ' '''' , "': . ."%f,l,r5tr:,4 , ■ '''' t.'''',''' Vr-Vr : '''''' ' „ '; '''', .:'.: .:;.'6`;'f .-rl-t.• ,'■:',',":&';:'::::'',"■:' 1:n'''',77!.:.=''lleCq'it it ' :" ; ' .; :r T 4 ' t" ';';''' ' ''..' ''' ' : , ' ' '''''' ' !: ' ,1, , -.., .., .: : ,, , ,,,:;,; . .,' ' 4,;,„ , ; , ,tA, ';='-;', ' ';.:7 - . 4;: - , , -..-:,,,:,;,;. 1 . ,,,::4:':%'? :. r,:: 4 ;' , ..„: ::;-;', t! . ;,.';.,:i'r.,;•:` : , ....... 7 AA; , .. • ;:=.: - . - ` - ' ,1 :;;I: :4 10/8/2009 10/9/2009 10,040.0 0.00 9.10 POOH with Fas Drill Running Tool and LD same. PU BHA #12, 6-3/4° Smith XR+312 Bit- Watermelon Mill - Bit Sub - NM Float Sub - 2x NM Flex DC's - Stab - NM Flex DC - Bumper Sub - al HI/VDP Drilling Jar - 21x HWDP 1/871'. RIH f/871' 1/9,648'. Clean out cement stringers 1/9,648' 4/10,020'. Drill Cement 1/10,020' 1/10,040'. Drill Packer and Perf Gun tail assembly 1/10,040' 1/10,095'. Circulate 2ea 50 bbl high-vis sweeps surface to surface. POOH with BHA 1#12 1/10,095' 1/871', installing Super Sliders on first 111 jts out of hole. POOH laying down BHA 1f/871' 1/42'. I 'Notified AOGCC of early BOPE test to be performed on 10/9/09. Witness of test waived by I 1 AOGCC representative Chuck Scheve. 147020094"kr1.1.,(020,0tir '7: 10440.0 7: 0.00, '.::, ';,-.., 8.99 POOH VW BHA *12: Tested Anibilir t6250 Wirt 2500081 hiertUPPer1/BFKI,(2-7,16 eff,,,?..,,..,„,,,,,,,,,,,,,,,,' - .... ,, A•:t..:x!'„?' 7,-- _,,,I?: er,' 5'); Lower 4'Ranis (fbced bore), Blind Rams,-Choicertnd, Kill One HCR valves; MantietC,hoke 7 - ' - 4 . 1 - 1":% 0 „ . '*•,:stif';'..1•,., .,* and Kill One valves; Floor safety.. Dert:„UpPer BOP and Loiter IBOP'veiNee tO'?.59 1 . . , ,,;.:„ . ;,, , N•.: -- F . ,--,,, , • - f - '7.4..„..', , ,440',;.! , !•444,,,;;; •-,i. All low and higiv tests helef.5 min each and charted. kilt line HCR failed. , ,Accereulator :::: " :; ' ,.''':,41,,,Ii 7•F,41,7,.:;- System Pressure 3000 psi; Pressure After Closer 2000 pSr,ftnitialL200Pet aitiliferf2Q:SOCA: -:, , .,.•,:.,.. ,,i,; ;;; ff,i Pressure attained1mkt 36 secs. Replace WI HCRiabie and retested. PU EIHA"*13:,,,`:::4 :...:,,,..,,,,.,,,',4`if,!;3-,I;(4.3-Track Whipstock Assembly: RIK k?' 1%070 and Set whipstock at 4.9, deg ,R1:ID witti:3500 * , : 4-...,,',:' , ..,t...A jr i t .;' 4., ,.,...!::.7..,105444. Pet Sheared hanger vat 235k oveiPrikand pulled 1010,040'. (ker Rotated et *Ilia Cfriiiiia**:* A • ,ir „: eg- , :...i. 4 .!!"1 , P,P1 ,- ,',and broke off bit jet nozzle Maw, Established circuit: , ,. '.„iiitit 250 cipm,*(1606, -. : 4 ; A?; ,_‘ ,:,,::.,1-:,: ;',':%4*1,.,i.i'4i.e.,I;44,::-;,ei*itili'ij;W:$;14;:4M‘.' YM::,,94'V1r;''''-4'.A;-f4'-'-;--.''''r'*-,-P-z-r,—,',--,;;'e-,",,„,3P'--, ;'slks- 7*-kwii:A;Z-104l.4.,:::,;-1,1*.z:Ml,:. 1 1 1 Page 1/4 Report Printed: 12/8/2009 _____ 'PIONEER 111P Operations Summary Report ( NATURAL RESOURCES Depth Stan Foot/Meters Last Mid Stan Date End Date (11K9) 0t) Dens (Ib/gal) S 10/10/2009 10/11/2009 10,061.0 63.00 9.30 Displace 8.9 ppg brine with 9.3 ppg Milling/Drilling fluid. Mill 6 -3/4' window in 7 -5/8" casing 1/10,050' 1/10,061'. Drill 1/10,061' 1110,091'. Perform FIT with 9.3 ppg mud at 5,004 TVD to 12.5 ppg EMW (ISIP 837 psi, FSIP 761 psi after 10 min). Drill 1/10,091' V10,124'. Pump Dry Job while rigging down E -line. POOH 1/10,124' V8,494'. Adjust stack and level rig. POOH (/8,494' 1/8,258'. 10/11/2009 10/12/2009 10,124.0 0.00 9.30 POOH (/8,258' 1/213'. LD BHA #131/98'. Download MWD data. POOH w/ BHA. Flush stack of metal cuttings and junk. PU BHA #141196'. Upload MWD program. RIH W/ Bf\ #14 t/6,600'. Pulse test MWD, good test. Move pits away from substructure. Reposition substructure over wellhead. 10/12/2009 10/13/2009 10,124.0 282.00 9.30 Reposition pits to mate up to substructure. Finish leveling rig and connect service lines in PUTZ. RU E -line. RIH w/ BHA #141/6,739' V10,124'. Drill (/10,124' 1/10,309'. Gryo on E -line V10,188' (WLM). Drill (/10,309' 1/10,406'. Took survey and established that the MWD survey was clear of any magnetic interferance. ' 10/13/2009 10/14/2009 10,406.0 800.00 9.30 Drill 6-3/4' Hole section 1/10,550' 1/11,206'rnd per WP14 & Well Site Geologists requests. • 10/14/2009 10/15/2009 11,206.0 119.00 9.30 Drill f/11,206' V11,325'. Circulate hole clean. P00141/11,325' 1/9,923'. Cut Drilling Line. POOH (/9,923' 1/400'. LD BHA # 14. Test Annular to 250 psi low / 2500 psi high. Test Blind Rams, Upper 2 -7/8' x 5" VBR pipe rams, Lower 4" pipe rams, Kill and Choke line HCR's valves, Kill and Choke line manual valves, Floor Safety, Dart, Upper IBOP and Lower IBOP valves to 250 psi low / 3500 psi high. 14 Choke manifold valves tested while tripping out of hole. All low and high tests held 5 min each and charted. Accumulator test, System Pressure 3000 psi, After Closure 2200 psi, Initial 200 psi recovery 22 sec's, Full recovery 1 min 37 sec's. 5 nitrogen btls at 1,650 psi avg. No failures. AOGCC representative Lou Grimaldi waived witness of BOPE test. 10/15/2009 10/16/2009. 11,325.0 0.00 9.30 RIH w/ BHA 1115. Shallow pulse test at 381', good pulse. RIH 1/381' t/11;100 removed Super Sliders from DP. Washed and reamed down 1/11-,100 t/11,325'. CPU. Backrearlr g logging up (/11,325 1/10,897' at 150 fph. z • • 10/16/2009 10/17/2009 11,325.0 190.00 9.30 Perform Mad Pass (/10,897' 1/10,200'. RIH 1/11,325'. Drill 1/11,325' 1/11,515'. Monitor well - static. POOH w/ BHA #151/11,515' 1/7,617'. 10/17/2009 10/18/2009 11,515.0 53.00 9.30 POOH w/ BHA 415. PU BHA #16 w/ 6-1/8' Security FMFX641Z bit and RIH t/381 St &ll W ` pulse test. RIH 1/381' V11,325'. Ream 1/11,325' V11,515'. Drill 1111,515' 1/11,56 ` ; >:w ::Cr 10/18/2009 10/19/2009 11,568.0 1,042.00 9.30 Drill 1/11,568' V12,610'. 1W19/2009 10/20/2009 12,610.0 1,206.00 ' 9.30 Drill (/12,610' 1/13,816'. '.: '.• ". °tea "=: ; , <. x., vb 10/20/2009 10/21/2009 13,816.0 1,049.00 9.30 Drill 1/13,816' (/14,865'. 10/21/2009 10/22/2009 14,865.0 564.00. 9.30: Drill (/14,865' (/15,429'- Circulate Hole Clean. POOH 1/15,5294111; �� x 1 A : - ;; °f,` ; ; ,` - . # .x, - 10/22/2009 10/23/2009 15,429.0 9.30 POOH 1/11,859' V11,750'. Attempt to circulate at 11,750' with 55% losses, POOH 1/11,750' (/11,570'. Establish circulation at 11,570' with 42 gpm and staged up to 200 gpm with 40-50% initial losses, losses decreased to 20% as we circulated. Backreamed 1/11,570' t/10,200' for open hole mad pass logs - losses reduced to 8 to 10 bph and then zero. POOH 1/10,200' (/9,930'. Circulate and condition mud 1.5 X BUS Monitor well - static. Pump slug and POOH f/ 9,930' up to the BHA. Lay down BHA tools up to the MWD tools. Plug in and download MWD/LWD data. Page 2/4 Report Printed: 12/7/2009 PIONEER Operations Summary Report NATURAL RESOURCES Depth Sleet ' Foot/Meters Last Mud Start Date End Date (ttKS) (ft) Dens (th/gal) Summary 10/23/2009 10/24/2009 15,429.0 9.30 Finish laying down BHA. Intall Test Plug and Test BOPE.Test Annular @ 250/2500 psi for 4" DP.Test Upper Pipe Ram VBR and Lower Pipe Ram © 250/3500 psi for 4" DP. Test Annular 0 250/2500 psi for 4-1/2" liner. Test Upper Pipe Ram VBR 250/3500 psi for 4 -1/2" Liner. AOGCC North Slope Field Inspector John Crisp waived witness 0 0855 on 10/22/09. Make up clean out BHA and shallow pulse test same. Slip and cut drill line. TIH f/325' t/11,610. 10/24/2009 10/25/2009 15,429.0 9.55 Wash and ream in the hole (/11,610' 1/15,429'. Pump 30 bbl hi -vis sweep and circulate oat same. Back ream out the hole 1/14,529' 1/14,214'. 10/25/2009 10/26/2009 15,429.0 9.40 Backreamed 1/14,200' 1/10,200'. TIH on elevators 1/10,200' V14,311'. Rotate and pump in the hole 1/14,311' V15,429' due to negative slack off wt - no issues. Establish circulation, stage pumps up to 250 gpm and circulate hole clean with 2x O.H. volume while racking back 1 stand every 30 min (/15,429' 1/15,083'. Rotate and pump in the hole f/15,083' V15,429' due to negative slack off wt - no issues. Stage pumps up to 250 gpm and spot 250 bbl liner running pill with polymer breaker across open hole section (/15,429' V12,264'. POOH 1/15,429' V9,969' on elevators - No issues. 10/26/2009 10/27/2009 15,429.0 9.30. Circulate hole clean with 1.5x bottoms up at 9,969'. POOH 1/9,969' V325'. Download MWD data and laydown BHA #17. RU 4.5" casing tools and have PJSM for running liner. MU 4.5' HYD 521, shoe and thread lock same. TIH picking up 4.5 ", L -80, 12.6 #, HYD 521 finer as per WFT rep. including 19 pre -pert pup joints and 1 water swell packer from surface V5,508'. PU and MU WFT `PHR` hydraulic setting liner hanger with WFT "TSP" liner top packer and WFT "PBR` tie back sleeve as per WFT rep.f /5,508' V5,533'. TIH 1/5,679' V9,343' with 4.5' liner on 4' DP. - 10/27/2009 10/28/2009 15,429.0 0.00 9.30 TIH (SLM) 1/9,343' 1110,018'. Circulate DP and liner capacity down to the first perfs in the liner to flow paths are clear. TIH (SLM) 1/10,018' 1/14,408'. Rotate in the hole 1/14,408' 1/15,529'. Drop 1.75" ball and pump down same with 42 gpm at 650 psi, seat ball with 1700 psi. Set hanger with 35k down, pressure up to 3700 psi to shear ball seat, PU to expose packer setting dogs and set packer with 50k down. Attempt to test packer and casing to 3500 psi - unsuccessful - bled off. Check all surface equipment and retest with same results. Stroke DP to make sure tie back seals are sealing and retest - Good test. Tested casing and liner top packer to 3500 psi on chart for 30 min. Circulate casing clean with 2x bottoms up. Pump 20 bbl dirt magnet pill followed by 20 bbis hi -vis brine pill and displace the well to 9.3 ppg filtered brine. POOH 1/9,849' 1/9,656'. Change out spools of drill line. Slip and cut 1,500' of drill line. Found twisted drill line on the draw works drum. Slip and cut 22' of drill line to remove twisted drill line. 10/28/2009 10/29/2009 15,429.0 0.00 9.30 Finish cutting drill line and reset C.O.M. POOH laying down 276 jts 4` DP f/9,656" to surface. LD • casing scraper, brush and junk basket assembly. Lay down WFT liner running tool. Retrieve wear bushing and install junk screen. PU 4" clean out tool, function all rams on BOP stack, and flush stack with sea water. Pull junk screen. Change bottom pipe rams to 4.5" and test same to 250/3,500 for 5 min on chart. AOGCC rep John Crisp waived witness of test on 10/26/09 at 14:00 hrs. PU 4.5' tubing hanger, landing joint and RIH with same. Test seals on tubing hanger to 5000 psi for 10 min - Good test. LD hanger and landing joint. RU 4.5' casing equipment. Pick up WFT Tie back seal assembly with locator sub, 1 joint of 4.5' L -80 Hyd 521 tubing and HES ROC gauge carrier: Tie in ROC gauge wire to ROC gauge, run all electrical diagnostics on wire OK. Test ROC gauge to 10,000 psi for 15 min - Good test. TIH picking up 4.5', ;'� L -80, 12.61 .'`, • HYD 521 liner t/71' 1/582'. Y 10/29/2009 10/30/2009 15,429.0 0.00 9.30 TIH picking up 4.5 ", L -80, 12.64, HYD 521 Tbg. f/582' 1/9,153'. Make up HES SSSV and control line and test same to 5,000 psi for 10 min - Good test. TIH w/ 4.5" Tbg f/9,153'1/9,905'. Sting into tie back Sleeve with seal assembly (/9,901' 1/9,916' with 15k down on seal assembly - test I.A. to 3,500 psi for 10 min - Good test. Space out, PU and make up 4.5" tubing hanger and landing joint, make penetrations through hanger. Pressure up to 5,000 psi on control line and land hanger with 16k down with seal assembly. Test tubing hanger upper and lower seals to 5,000 psi for 10 min each on chart - Good test. Pressure up on I.A. to 3500 psi to test casing, held 30 min on chart - Good test. Pull landing joint and install BPV. Rig down SSSV control line and ROC gauge wire sheeves and spools. Page 3/4 Report Printed: 12/7/2009 PIONEER (TS Operations Summary Report l NATURAL RESOURCES Depth Start FootrMeters Last BMW Start Date End bate 4fKS) ftt) Dens (Iblgal) Summary - 10/30/2009 10/31/2009 15,429.0 0.00 9.30 Change out bottom pipe rams from 4.5" to 5'. ND all BOP equipment. Terminate ROC gauge TEC wire and SSSV control line as per Vetco Gray and HES rep. in M -233 Well Head Penatrators. Test Well seal & void to 5000psi each & chart same for 15 mins (good test). Witness SSSCV tested to 5000psi & needle valve installed (ok). Rig up HES slickline unit and lubricator /BOPs. RIH with 3.83" GR to the top of SVLN Iso Sleeve at 768' wlm. RIH with 4.5" GS pulling and 4.5" RCH -M plug body and set same at 2,098'. RIH with p g tool and retrieve dummy GLV from GLM #1 at 2,032'. Freeze protect 7 -5/8" x 4 -1/2' annulus. Reverse circulate 60 bbls of corrosion inhibited 9.3 ppg brine followed by 85 bbls of diesel. RIH and set dummy GLV in GLM • f)1 at 2,032'. RIH with RCH -M plug catcher and pull RHC -M plug from 2,098'. RIH with 4.5' FXE WRSSSV and set same in XXO SVLNat 768', function test valve - ok. RD slick•line unit. Install BPV in hanger. Rig Released at 24:00 hrs 10/30/09. Prep rig for rig move from ODSN -45A to ODSK -42i. • • • • • • Page 4/4 Report Printed: 12/7/2009 PIONEER •erations Summary Report - Stat. Well Name: ODST -45A NATI IRAI _R SOL JRCES Well Name: Contractor: Rig Number: Job Category: Start Date: End Date: Start Depth Foot/Metens Dena Lest Start Date End Date (*CB) (ft3 Mud phtgat Summary 3/8/2010 3/9/2010 1,311.0 Finalize rig up, hold pre -frac safety meeting with all personnel, prime pumps and pressure test lines to 8000 psi - Good test, apply 3000 psi to IA and frac ODST -45A as per SLB frac schedule. 319/2010 3/10/2010 1,311.0 Complete Frac, pumped 607,000 lbs of 20/40 proppant at 35 Co bpm at treating pressures of 3000 to 3800 psi. RD frac equipment, MIRU Stickline Unit. Retrieve Isolation sleeve from ported laming nipple. Set valve rather sub in XN at 9,788'. Attempt to pull DMY GLM at 9,689'. Could not locate, POOH tools packed with proppant. Retrieve catcher sub. RIH with wire brush and perform brush and flush with diesel. 3/10/2010 3/11/2010 1,311.0 Pull DMY GLM from station # 4 © 7,327'. Set 1" Orifice valve with 1/4" port in station #4. Pull Catcher sub. Run in Wireline Retrievable ScSSSV in XXO at 759' MD, test control lines to 5000 psi. Function test the the ScSSSV, RDMO slickline unit. Page 1/1 Report Printed: 5/4/2011 ii Halliburton Company rill Definitive Survey Report , Company: Well Planning - Pioneer - Oooguruk Local Co-ordinate Reference: Well ODSN -45A - Slot ODS-45 Project Oooguruk Development TVD Reference: 42.7' + 13.5 42 56.20ft (Nabors 19 AC) Sitm Oooguruk Drill Site MD Reference: 42.7' + 13.5 CD 56.20ft (Nabors 19 AC) We ODSN -45A North Reference: True Welborn: ODSN -45A Survey Cakuiation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Project Oooguruk Development Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor 1 Well ODSN -45A - Slot ODS-45 Well Position +N/-S 0.00 ft Northing: 6,031,005.53 ft Latitude: 70° 29' 44.804 N +E/ -W 0.00 ft Easting: 469,821.86 ft Longitude: 150° 14' 48.349 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 13.50ft Welibore ODSN -45A Magnetics Model Name Sample Date Declnation Dip Angle Field Strength (') (') (nT) IGRF200510 10/2/2009 22.10 80.81 57,749 Design ODSN -45A Audk Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 10,035.40 Vertical Section: Depth From (1VD) +NU-S +E/-W Direction (tt) PR) (11) (') 42.70 0.00 0.00 290.00 Survey Program Data 11/3/2009 From To (ft) ` • (n) Survey (Welbore) Tool Name Description Survey Date 50.00 533.00 ODSN -45i 1N13 PB1 Gyro (ODSN -451 IN SR- Gyro -SS Fixed:v2:surtace readout gyro single shot 1/13/2009 1: 533.00. 10,035.40 ODSN -45i IN13 PB1 MWD (ODSN -45i IP MWD +IFR2 +MS +sag Fixed:v2:IIFR dec & 3-axis correction + sag 1/13/2009 1: 10,049.98 10,191.98 ODSN -45A Gyro (ODSN -45A) NS- Gyro-MS Fixed:v2:North- seeking gyro muitishot 10/3/2009 1: 10,259.91 15,393.08 ODSN -45A MWD (ODSN -45A) MWD +IFR2 +MS +sag Fixed:v2:I1FR dec & 3-axis correction + sag 10/4/2009 1: Surw�t SS NhS +E/ -W ' North Ea DUB . -, : < - _ s;:-. MD . hoc AM ND ND + ( fl (1 (ft) (R) . (8) (ft) (8) rep (8) (1 . „ A 42.70 0.00 0.00 42.70 -13.50 0.00 0.00 ' 6,031,005.53 469,821.86 0.00 0.00 UN 50.00 0.30 141.13 50.00 -6.20 -0.01 0.01 6,031,005.52 469,821.87 4.11 -0.02 SR- Gyro-SS (1) 100.00 0.30 191.03 100.00 43.80 -0.25 0.07 6,031,005.28 469,821.93 0.51 -0.15 SR- Gyro-SS (1) 168.00 0.50 165.94 168.00 111.80 -0.71 0.11 6,031,004.82 469,821.96 0.38 -0.34 SR- Gyro -SS (1) 197.00 0.48 148.51 197.00 140.80 -0.93 0.20 6,031,004.60 469,822.06 0.52 -0.51 SR -Gyro -SS (1) 228.00 0.59 198.76 228.00 171.80 -120 0.22 6,031,004.33 469,822.07 1.50 -0.61 SR- Gyro-SS (1) 258.00 0.58 166.67 257.99 201.79 -1.49 020 6,031,004.04 469,822.06 1.08 -0.70 SR- Gyro -SS (1) 288.00 0.68 167.36 287.99 231.79 -1.81 0.28 6,031,003.72 469,822.13 0.33 -0.88 SR- Gyro-SS (1) 321.00 0.98 173.11 320.99 264.79 -2.28 0.35 6,031,003.25 469,822.20 0.94 -1.11 SR- Gyro -SS (1) 351.00 1.08 175.74 350.98 294.78 -2.82 0.41 6,031,002.71 469,822.25 0.37 -1.35 SRGGyroSS (1) • 382.00 1.32 178.28 381.98 325.78 -3.47 0.44 6,031.002.06 469,82228 0.79 -1.60 SR-Gyro-SS (1) 11/3/2009 2 :48:59PM Page 2 COMPASS 2003.16 Build 71 )411) HaNiburton Company n Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -45A - Slot ODS-45 Project Oooguruk Development TVD Reference: 42.7' + 13.5 ? 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: . 42.7' + 13.5 Q 56.20ft (Nabors 19 AC) W & 1 ODSN -45A North Reference: True Weibull: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical MD Inc Ara TVD TVDSS +NI-S +E/-W Northing Easting DLS Section (ft) _ (l (`) (ft) (ft) (ft) (ft) (ft) (ft) ('/100') (ft) Survey Tool Name 413.00 1.75 179.15 412.96 356.77 -4.30 0.46 6,031,001.23 469,822.30 1.39 -1.90 SR- Gyro-SS (1) 443.00 2.13 178.74 442.95 386.75 -5.31 0.47 6,031,000.22 469,822.31 1.27 -2.26 SR- Gyro-SS (1) 533.00 2.88 180.19 532.86 476.66 -9.25 0.50 6,030,996.28 469,822.33 0.84 -3.64 SR- Gyro-SS (1) 575.40 2.94 174.16 575.21 519.01 -11.39 0.61 6,030,994.14 469,822.42 0.74 -4.47 MWD +IFR2 +MS +sag (2) 670.40 3.91 162.96 670.04 613.84 -16.91 1.81 6,030,988.61 469,823.60 1.24 -7.48 MWD +IFR2 +MS +sag (2) 764.70 5.03 162.67 764.05 707.85 -23.93 3.98 6,030,981.58 469,825.74 1.19 -11.93 MWD +IFR2 +MS +sag •(2) 859.30 5.77 161.44 858.23 802.03 -32.40 6.73 6,030,973.10 469,828.46 0.79 -17.41 MWD +IFR2 +MS +sag (2) 954.90 5.70 160.56 953.35 897.15 -41.43 9.84 6,030,964.06 469,831.53 0.12 -23.42 MWD +IFR2 +MS +sag (2) 1,049.20 7.62 163.09 1,047.01 990.81 -51.83 13.22 6,030,953.65 469,834.87 2.06 -30.15 MWD +IFR2 +MS +sag (2) 1,143.50 8.56 164.80 1,140.37 1,084.17 -64.59 16.88 6,030,940.88 469,838.47 1.03 -37.95 MWD-4FR2 +MS +sag (2) 1,238.70 9.80 165.71 1,234.35 1,178.15 - 7928 20.73 6,030,926.18 469,842.27 1.31 .46.60 MWD+IFR2 +MS +sag (2) ■ 1,334.70 11.30 167.74 1,328.72 1,272.52 -96.39 24.75 6,030,909.05 469,846.21 1.61 -56.22 MWD +1FR2 +MS +sag (2) 1,428.60 1321 170.21 1,420.48 1,364.28 - 115.95 28.53 6,030,889.48 469,849.91 2.11 -66.46 MWD +IFR2 +MS +sag (2) 1,523.55 12.76 171.01 1,513.00 1,456.80 - 137.00 32.01 6,030,868.42 469.853.31 0.51 -76.94 MWD+IFR2 +MS +sag (2) 1,618.50 13.98 172.54 1,605.37 1,549.17 - 158.73 35.14 6,030,846.68 469,856.35 1.34 -87.31 MWD +IFR2 +MS +sag (2) 1,712.90 14.83 172.59 1,696.81 1,640.61 - 182.01 38.18 6,030,823.38 469,85929 0.90 -98.13 MWD +4FR2 +MS +sag (2) 1,808.20 16.36 172.06 1,788.59 1,732.39 - 207.40 41.60 6,030,797.98 469,862.62 1.61 - 110.03 MWD+IFR2 +MS +sag (2) 1,902.60 18.07 178.03 1,878.77 1,822.57 - 235.21 43.94 6,030,770.17 469,864.84 2.60 - 121.74 MWD+IFR2 +MS +sa9 (2) 1,999.40 21.10 181.35 1,969.96 1,913.76 - 267.64 44.05 6,030,737.74 469,864.82 3.33 - 132.93 MWD+IFR2 +MS +sag (2) 2,093.80 24.37 188.46 2,057.03 2,000.83 - 303.91 40.78 6,030,701.49 469,861.40 4.52 - 142.26 MWD +IFR2 +MS +sag (2) 2,187.50 25.30 191.15 2,142.07 2,085.87 - 342.67 34.07 6,030,662.76 469,854.53 1.56 - 14921 MWD+IFR2 +MS +sag (2) 2,282.30 28.06 195.13 2,226.77 2,170.57 - 384.08 24.33 6,030,621.39 469,844.62 3.47 - 15422 MWD+1FR2 +MS +sag (2) 2,326.00 29.70 195.74 2,265.04 2,208.84 - 404.43 18.71 6,030,601.07 469,838.92 3.81 - 155.90 MWD+IFR2 +MS +sag (2) 2,377.20 32.48 198.82 2,308.88 2,252.68 - 429.65 10.83 6,030,575.88 469,830.94 625 - 157.13 MWD+IFR2 +MS +sap (2) 2,424.00 34.60 199.84 2,347.89 2,291.69 - 454.05 2.26 6,030,551.52 469,82228 4.69 - 157.42 MWD+IFR2 +MS +sag {2) 2,472.50 36.16 200.43 2,387.43 2,331.23 - 480.41 -7.40 6,030,525.20 469,812.51 3.29 - 157.35 MWD+IFR2 +MS +sag (2) 2,566.59 39.82 202.47 2,461.58 2,405.38 - 534.29 -28.62 6,030,471.41 469,791.08 4.11 - 155.85 MWD+IFR2 +MS +sag (2) 2,659.39 43.52 202.62 2,530.89 2,474.69 -59126 -5227 6,030,414.55 469,767.19 3.99 - 153.10 MWD+IFR2 +MS •sag (2) 2,698.99 44.79 203.91 2,559.30 2,503.10 - 616.60 -63.17 6,030,389.25 469,756.19 3.93 - 151.53 MWD+IFR2 +MS +sag {2) 2,752.29 48.34 205.85 2,595.94 2,539.74 -651.69 -79.47 6,030,354.23 469,739.76 7.17 - 14822 MWO+IFR2 +MS +sap (2) 2,805.09 49.84 207.14 2,630.52 2,574.32 -687.40 -9727 6,030,318.60 469,721.81 3.39 - 143.70 MWD+1FR2 +MS +sag (2) 2,848.99 51.64 207.46 2,658.30 2,602.10 - 717.61 - 112.86 6,030,288.46 469,706.10 4.14 - 139.38 MWD+IFR2 +MS +sag (2) 2,943.19 53.16 207.96 2,715.77 2,659.57 - 783.68 - 147.57 6,030,222.54 469,671.13 1.67 - 129.36 MWD+IFR2 +MS +sag (2) 3,040.19 55.15 209.57 2,772.57 2,716.37 - 852.59 - 185.41 6,030,153.79 469,633.00 2.45 - 117.37 MWD+IFR2 +MS +sa9 (2) 3,133.79 57.80 210.63 2,824.27 2,768.07 - 920.08 - 224.55 6,030,086.46 469,593.60 2.98 - 103.68 MWD•IFR2 +MS +sag (2) 3,229.59 59.33 210.06 2,874.23 2,818.03 - 990.62 - 265.84 6,030,016.09 469,552.02 1.68 -89.00 MW17.)+1FR2 +MS +sag{2) 3,323.39 61.07 209.65 2,920.84 2,864.64 - 1,06121 - 306.36 6,029,945.67 469,511.23 1.89 -75.07 MWD +IFR2 +MS +sag (2) 3,417.39 64.24 210.67 2,964.02 2,907.82 - 1,133.39 - 348.31 6,029,873.68 469,468.99 3.51 -60.34 MWD+IFR2 +MS +sag (2) 3,465.29 65.89 210.86 2,984.21 2,928.01 - 1,170.71 - 370.53 6,029,836.45 469,446.62 3.46 -52.22 MWD+IFR2 +MS +sap (2) 3,512.29 69.49 210.64 3,002.05 2,945.85 - 1,208.07 - 392.76 6,029,799.18. 469,42424 7.67 -44.12 MWD+IFR2 +MS +sag (2) 11/3/2009 2:48 :59PM Page 3 . COMPASS 2003.16 Build 71 Halliburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Coordinate Reference: Well ODSN -45A - Slot ODS -45 Project: Oooguruk Development TVD Reference: 42,7' + 13.5 a 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 0 56.20ft (Nabors 19 AC) Welk ODSN -45A North Reference: True Wellore: ODSN -45A Survey Cakulation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User DI) Survey Map Map Vertical MD Inc All TVD TVDSS +NI-S *El -W Northing fasting DLS Section . (R) 1 (') (ft) (ft) (n) (ft) (R) (ft) 0100 (ft) Survey Tol Name 3,559.99 71.29 209.81 3,018.06 2,961.86 - 1,246.90 - 415.37 6,029,760.45 469,401.47 4.11 -36.14 MWD+IFR2 +MS +sag (2) 3,607.69 73.43 210.51 3,032.51 2,976.31 - 1,286.20 - 438.21 6,029,721.25 469,378.48 4.70 -28.12 MWD +IFR2 4,15 +sag (2) 3,700.79 73.49 209.15 3,059.02 3,002.82 - 1,363.62 - 482.60 6,029,644.02 469,333.77 1.40 -12.89 MWD +IFR2 +MS +sag (2) 3,797.59 75.67 213.26 3,084.76 3,028.56 - 1,443.40 - 530.95 6,029,564.44 469,285.11 4.67 5.26 MWD+IFR2 +MS +sag (2) 3,892.09 75.67 212.88 3,108.15 3,051.95 - 1,520.13 - 580.91 6,029,487.92 469,234.84 0.39 25.96 MWD+IFR2 +MS +sag(2) 3,986.89 74.92 215.00 3,132.22 3,076.02 - 1,596.19 - 632.10 6,029,412.07 469,183.35 2.30 48.05 MWD+IFR2 +MS +sag(2) 4,081.09 74.82 216.86 3,156.81 3,100.61 - 1,669.82 - 685.46 6,029,338.67 469,129.70 1.91 73.01 MWD+IFR2 +MS +sag (2) 4,175.99 73.20 216.32 3,182.95 3,126.75 - 1,743.07 - 739.84 6,029,265.65 469,075.03 1.79 99.05 MWD+IFR2 +MS +sag (2) 4,268.49 72.50 218.38 3,210.23 3,154.03 - 1,813.33 - 793.45 6,029,195.62 469,021.13 2.26 125.41 MWD+IFR2 +MS +sag (2) 4,365.09 71.06 219.72 3,240.43 3,184.23 - 1,884.59 - 851.25 6,029,124.60 468,963.05 1.99 155.35 MWD +IFR2 +MS +sag (2) 4,458.59 70.94 218.34 3,270.87 3,214.67 - 1,953.26 - 906.92 6,029,056.16 468,907.10 1.40 184.18 MWD+IFR2 +MS +sag (2) 4,554.79 70.77 219.77 3,302.43 3,246.23 - 2,023.83 - 964.18 6,028,985.83 468,849.57 1.42 213.84 MWD+IFR2 +MS +sag (2) 4,648.49 71.10 218.30 3,333.03 3.276.83 - 2,092.62 - 1,019.95 6,028,917.28 468,793.52 1.52 242.73 MWD+IFR2 +MS +sag (2) 4,744.59 71.00 217.70 3,364.24 3,308.04 - 2,16424 - 1,075.91 6,028.845.89 468,737.28 0.60 270.81 MWD+IFR2 +MS +sag (2) 4,839.59 70.69 218.10 3,395.41 3,339.21 - 2,235.05 - 1,131.04 6,028,775.31 468,681.87 0.51 298.39 MWD+IFR2 +MS +sag (2) 4,931.39 71.44 218.07 3,425.20 3,369.00 - 2,303.40 - 1,184.60 6,028,707.19 468,628.04 0.82 325.35 M1N0+IFR2 +MS +sag (2) 5,012.77 71.57 218.31 3,451.02 3,394.82 - 2,364.05 - 1,232.31 6,028,646.73 468,580.08 0.32 349.44 MWD +IFR2 +MS +sag (2) 5,10527 70.97 217.33 3,480.72 3,424.52 - 2,43325 - 1,286.03 6,028,577.76 468,526.09 1.19 376.25 MWD+IFR2 +MS +sag (2) 5,202.47 70.78 216.37 3,512.57 3,456.37 - 2,506.74 - 1,341.10 6,028,504.50 468,470.72 0.95 402.87 MWD+IFR2 +MS +sag (2) 5,29226 71.43 216.16 3,541.64 3,485.44 - 2,57523 - 1,391.35 6,028,43622 468,420.20 0.76 426.66 MWD+IFR2 +MS +sag (2) 5,393.87 72.60 214.62 3,573.02 3,516.82 - 2,654.02 - 1,447.32 6,028,357.67 468,363.92 1.84 452.31 MWD+IFR2 +MS +sag (2) I 5,489.91 72.80 213.99 3,601.58 3,545.38 - 2,729.76 - 1,499.00 6,028,282.14 468,311.94 0.66 474.96 MWD+IFR2 +MS +sag (2) 5,577.52 72.79 214.00 3,627.49 3,571.29 - 2.799.15 - 1,545.79 6,028,212.96 468,264.87 0.02 495.20 MWD +IFR2 +MS +sag (2) 5,673.74 72.92 213.93 3,655.86 3,599.66 - 2,875.41 - 1,597.16 6,028,136.92 468,21320 0.15 517.39 MWD+IFR2 +MS +sag (2) 5,773.16 72.72 211.84 3,685.23 3,629.03 - 2,955.16 - 1,648.73 6,028,057.38 468,161.31 2.02 538.57 MWD+IFR2 +MS +sag (2) 5,868.29 72.53 210.72 3,713.63 3,657.43 - 3,032.75 - 1,695.87 6,027,979.99 468,113.87 1.14 556.33 MWD+IFR2 +MS +sag (2) 5,962.54 7220 211.00 3,742.19 3,685.99 - 3,109.86 - 1,741.94 6,027,903.08 468,067.48 0.45 573.25 MWD+IFR2 +MS +sag (2) 6,057.34 72.53 212.72 3,770.91 3,714.71 - 3,186.59 - 1,789.62 6,027,826.55 468,019.49 1.76 591.82 MWD+IFR2 +MS +sag (2) 6,151.53 72.92 21127 3,798.88 3,742.68 - 3,262.86 - 1,837.28 6,027,750.47 467,971.53 1.53 610.51 MWD+1F122 +MS +sap (2) 6,247.50 72.48 21127 3,827.42 3,771.22 - 3,341.18 - 1,884.84 6,027,672.36 467,923.66 0.46 628.42 MWD+IFR2 +MS +sag (2) 6,340.48 72.26 212.99 3,855.58 3,799.38 - 3,416.22 - 1,931.96 6,027,597.52 467,87624 1.78 647.04 MWD+IFR2 +MS+sag (2) 6,434.78 72.46 211.57 3,884.16 3,827.96 - 3,492.19 - 1,979.96 6,027,521.75 467,827.94 1.45 666.15 MWD+IFR2 +MS +sag (2) 6,529.17 72.54 211.31 3,912.54 3,856.34 - 3,569.00 - 2,026.91 6,027,445.14 467,780.68 028 684.00 MWD+IFR2 +MS +sag (2) 6,623.98 72.35 212.08 3,941.14 3,884.94 - 3,645.91 - 2,074.40 6,027,368.43 467,732.88 0.80 702.33 MWD+IF112 +MS +sa912) 6,720.34 71.83 213.74 3,970.78 3,914.58 - 3,722.88 - 2,124.22 6,027,291.67 467,682.76 1.73 722.81 MWD+IFR2 +MS +sag (2) 6,814.39 71.76 214.87 4,000.16 3,943.96 - 3,796.68 - 2,174.57 6,027,218.08 467,632.11 1.14 744.88 MWD+IFR2 +MS +sag (2) 6,908.91 71.70 215.49 4,029.79 3,973.59 - 3,870.05 - 2,226.28 6,027,144.94 467,580.11 0.63 768.39 MWD+IFR2+MS +sag (2) 7,004.56 71.68 215.84 4,059.84 4,003.64 - 3,943.82 - 2,279.22 6,027,071.38 467,526.87 0.35 792.90 MWD+IFR2 +MS +sa9 (2) 7,100.29 72.01 215.80 4,089.67 4,033.47 -4,017.58 - 2,332.46 6,026,997.85 467,473.34 0.35 817.70 MWD+IFR2 +MS +sag (2) 7,193.34 72.53 215.54 4,118.01 4,061.81 - 4,089.58 - 2,384.14 6,026,926.07 467,421.37 0.62 841.64 MWD+IFR2 +MS +sag (2) 11/3/2009 2 :48 :59PM Page 4 COMPASS 2003.16 Budd 71 {"0 Halliburton Company l Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -45A - Slot ODS-45 Project Oooguruk Development TVD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference: True Welborn: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical MD ' Inc Azi TVD TVDSS +N!-S +F-/ -W Northing • Easting DLS Section (f(). (7 ( (R) (ft) 1S) (ft) (ft) (ft) ( °HOo') (ft) Survey Tool Name 7,288.68 72.40 215.89 4,146.73 4,090.53 - 4,163.39 - 2,437.21 6,026,852.48 467,368.01 0.38 866.26 MWD +IFR2 +MS +sag 12) 7,382.88 72.80 215.45 4,174.90 4,118.70 - 4,236.42 - 2,489.63 6,026,779.67 467,315.30 0.62 890.54 MWD +IFR2 +MS +sag(2) 7,477.84 72.16 214.78 4,203.49 4,147.29 - 4,310.49 - 2,541.71 6,026,705.82 467,262.92 0.95 914.16 MWD+IFR2 +MS *sag (2) 7,572.90 71.77 214.65 4,232.92 4,176.72 -4,384.80 - 2,593.20 6,026,631.73 467,211.14 0.43 937.12 MWD +IFR2 +MS +sag (2) 7,667.48 71.96 215.11 4,262.36 4,206.16 -4,458.53 - 2,644.60 6,026,558.21 467,159.45 0.50 960.20 MWD*IFR2 +MS +sag (2) 7,758.38 72.02 214.91 4,290.46 4,234.26 - 4,529.34 - 2,694.19 6,026,487.62 467,109.57 0.22 982.59 MWD+IFR2 +MS +sag (2) 7,857.09 72.14 214.91 4,320.84 4,264.64 -4.606.36 - 2,747.94 6,026,410.82 467,055.51 0.12 1,006.75 MWD +IFR2 •MS +sag (2) 7,951.52 72.13 214.87 4,349.80 4,293:60 - 4,680.08 - 2,799.35 6,026,337.32 467,003.81 0.04 1,029.85 MWD +IFR2 +MS +sag (2) 1 8,047.26 72.73 214.89 4,378.70 4,322.50 - 4,754.95 - 2,851.55 6,026,262.66 466,951.32 0.63 1,053.29 MWD +IFR2 *MS +sag (2) 8,142.02 72.86 213.92 4,406.73 4,350.53 - 4,829.64 - 2,902.69 6,026,188.19 466,899.87 0.99 1,075.81 MWD+IFR2 +MS+sag(2) 8,235.56 72.73 214.08 4,434.40 4,378.20 - 4,903.71 - 2,952.66 6,026,114.33 466,849.61 0.21 1,097.42 MWD +IFR2 +MS +sag (2) 8,330.90 72.86 213.75 4,462.60 4,406.40 -4,979.29 - 3,003.47 6,026,038.96 466,798.50 0.36 1,119.32 MWD +IFR2 +MS +sag (2) 8,425.38 72.21 213.89 4,490.96 4,434.76 - 5,054.17 - 3,053.64 6,025,964.30 466,748.04 0.70 1,140.85 MWD +IFR2 +MS +sag (2) 8,520.57 71.03 214.65 4,520.97 4,464.77 - 5,128.82 - 3,104.50 6,025,889.86 466,696.87 1.45 1,163.12 MWD +1FR2 +MS +sag (2) 8,614.82 70.45 215.43 4,552.06 4,495.86 - 5,201.67 - 3,155.58 6,025,817.23 466,645.50 0.99 1,186.20 MW0+IFR2 +MS +sag (2) 8,707.23 70.97 215.11 4,582.59 4,526.39 - 5,272.88 - 3,205.95 6,025,746.23 466,594.85 0.65 1,209.17 MWD •IFR2 +MS +sag (2) 8,802.23 71.56 214.91 4,613.10 4,556.90 - 5,346.56 - 3.257.56 6,025,672.76 466,542.94 0.65 1,232.47 MWD+IFR2 +MS +sap (2) 8,897.27 71.76 215.01 4,643.01 4,586.81 - 5,420.50 - 3,309.25 6,025,599.05 466,490.96 0.23 1,255.76 MWD+IFR2 +MS +sag (2) 8,992.31 71.70 215.37 4,672.80 4,616.60 - 5,494.25 - 3,361.26 6,025,525.51 466,438.65 0.37 1,279.41 MWD+IFR2 +MS +sag (2) 9,087.70 72.40 214.07 4,702.20 4,646.00 - 5,568.84 - 3,412.95 6,025,451.14 466,386.67 1.49 1,302.46 MWD+IFR2 +MS +sag (2) 9,182.27 72.66 214.32 4,730.59 4,674.39 - 5,643.45 - 3,463.64 6,025,376.74 466,335.68 0.37 1,324.58 MWD +IFR2 +MS+sag (2) 9,276.95 72.27 212.54 4,759.12 4,702.92 - 5,718.79 - 3,513.38 6,025,301.61 466,285.64 1.84 1,345.55 MWD*IF112 +MS +sag (2) 9,371.44 71.83 212.53 4,788.24 4,732.04 - 5,794.58 - 3,561.72 6,025,226.03 466,237.00 0.47 1,365.06 MWD+IFR2 +1AS +sag (2) 9,466.39 71.88 213.38 4,817.81 4,761.61 - 5,870.29 - 3,610.81 6,025,150.53 466,187.61 0.85 1,385.29 MWD4IFR2+MS+sag (2) 9,561.41 71.43 216.75 4,847.72 4,791.52 - 5,944.10 - 3,662.61 6,025,076.94 466,135.52 3.40 1,408.73 MWD*IFR2 *MS +sag (2) 9,656.14 70.96 220.58 4,878.27 4,822.07 - 6,014.10 - 3,718.62 6,025,007.17 466,079.23 3.86 1,437.41 MWD+IFR2 +MS +sag (2) 9,750.60 72.00 222.51 4,908.28 4,852.08 - 6,081.13 - 3,778.02 6,024,940.39 466,019.56 2.23 1,470.31 MWD+IFR2 +MS +sag (2) 9,845.48 72.39 225.50 4,937.29 4,881.10 - 6,146.09 - 3,840.77 6,024,875.69 465,956.55 3.03 1,507.05 MWD+IFR2 *MS+sag(2) 9,940.31 72.08 228.44 4,966.23 4,910.03 - 6,207.71 - 3,906.77 6,024,814.34 465,890.31 2.97 1,548.00 MWD+IFR2 +MS +sag(2) 10,035.40 70.98 231.76 4,996.37 4,940.17 -6,265.56 - 3,975.95 6,024,756.78 465,820.90 3.51 1,593.22 MWD+IFR2 +MS +sag (2) 10,049.98 70.97 232.37 5,001.12 4,944.92 - 6,274.04 - 3,986.82 6,024,748.35 465,810.00 3.96 1,600.54 NS- Gyro -MS (3) 10,104.98 84.74 237.65 5,012.67 4,956.47 - 6,304.73 - 4,030.78 6,024,717.84 465,765.92 26.73 1,631.35 NS- Gyro -MS (3) 10,191.98 84.62 241.67 5,020.74 4,964.54 - 6,348.48 - 4,105.53 6,024,674.40 465,691.00 4.60 1,686.63 NS-Gyro -MS (3) 10,259.91 84.25 246.20 5,027.33 4,971.13 - 6,378.18 - 4,166.25 6,024,644.95 465,630.17 6.66 1,733.53 MWD+lFR2 +MS +sag(4) 10,306.57 83.51 248.83 5,032.31 4,976.11 - 6,395.92 - 4,209.11 6,024,627.38 465,587.24 5.82 1,767.73 MWD+IFR2 •MS +sag (4) 10,356.69 82.24 252.28 5,038.53 4,982.33 - 6,412.47 - 4,256.00 6,024,611.02 465,540.29 7.29 1,806.13 MWD+IFR2 +MS +sag (4) 10,402.89 80.50 256.64 5,045.46 4,989.26 - 6,424.71 -4,299.99 6,024,598.96 465,496.25 10.06 1,843.29 MWD +IFR2 +MS +sag (4) 10,452.16 79.12 261.21 5,054.18 4,997.98 - 6,434.03 -4,347.56 • 6,024,589.84 465,448.64 9.55 1,884.81 MWD*IFR2 +MS •sag (4) 10,499.52 78.81 264.76 5,063.25 5,007.05 - 6,439.71 - 4,393.69 6,024,584.35 465,402.50 7.39 1,926.21 MWD+IFR2 +MS +sap (4) 10,549.42 79.15 268.20 5,072.79 5,016.59 - 6,442.71 -4,442.57 6,024,581.54 465,353.61 6.80 1,971.11 MWD +IFR2 +MS +sag (4) 11/3/2009 2:48:59PM Page 5 COMPASS 2003.16 Build 71 Halliburton Company • Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Coordinate Reference: Well ODSN -45A - Slot ODS-45 Project Oooguruk Development TVD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 56.20(1 (Nabors 19 AC) W.H. ODSN -45A North Reference: True Welbore: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db 1 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N /S +E!-W Northing Easting DLS Section , (ft) ( (') (ft) (ft) (R) {R) (ft) (ft) ('1100') (R) Survey ToatName 10,596.90 79.90 271.70 5,081.43 5,025.23 - 6,442.75 - 4,489.25 6,024,581.69 465,306.94 7.42 2,014.97 MWD+IFR2 +MS +sag (4) 10,646.00 80.10 275.72 5,089.95 5,033.75 - 6,439.62 - 4,537.49 6,024,585.02 465,258.71 8.07 2,061.37 MWD+IFR2 4AS +sag (4) 10,692.11 79.72 278.83 5,098.03 5,041.83 - 6,433.87 -4,582.52 6,024,590.95 465,213.71 6.69 2.105.64 MWD+IFR2 +MS +sag (4) 10,741.83 79.16 282.40 5,107.15 5,050.95 - 6,424.87 - 4,630.55 6,024,600.14 465,165.72 7.15 2,153.86 MWD+IF122 +MS *sag (4) 10,838.48 79.83 288.06 5,124.78 5,068.58 - 6,399.92 - 4,722.20 6,024,625.47 465,074.18 5.80 2,248.52 MWD +IFR2 +MS +sag (4) 10,935.46 82.65 293.08 5,139.56 5,083.36 - 6,366.24 - 4,811.90 6,024,659.51 464,984.64 5.88 2,344.32 MWD +IFR2 +MS +sag (4) 11,032.19 84.12 298.09 5,150.71 5,094.51 - 6,324.75 - 4,898.53 6,024,701.34 464,898.18 5.36 2,439.92 MWD+IFR2 +MS +sag (4) 11,127.72 85.25 304.59 5,159.57 5,103.37 - 6,275.30 -4,979.72 6,024,751.11 464,817.20 6.88 2,533.12 MWD+IFR2 +MS +sag (4) 11,224.34 85.01 312.68 5,167.79 5,111.59 - 6,21525 - 5,054.86 6,024,811.47 464,742.31 8.35 2,624.27 MWD+IFR2 +MS +sag {4) 11,275.22 86.50 316.47 5,171.55 5,115.35 - 6,179.64 - 5,090.99 6,024,847.22 464,706.33 7.98 2,670.41 MWD+IFR2 +MS +sag (4) 11,344.46 90.00 318.36 5,173.67 5,117.47 - 6,128.70 - 5,137.81 6,024,898.35 464,659.72 5.74 2,731.83 MWD+IFR2+41S +sap (4) 11,440.96 91.24 320.71 5,172.62 5,116.42 -6,055.28 - 5.200.44 6,024,972.01 464,597.39 2.75 2,815.79 MWD+IFR2 +MS +sag (4) 11,478.97 9123 320.47 5,171.80 5,115.60 - 6,025.93 - 5,224.56 6,025,001.45 464,573.40 0.63 2,848.49 MWD+IFR2 +MS +sag (4) 11,532.05 91.17 317.88 5,170.69 5,114.49 - 5,985.78 - 5,259.25 6,025,041.74 464,538.88 4.88 2,894.82 MWD+IFR2 +MS +sap (4) 11,630.25 90.49 320.13 5,169.27 5,113.07 - 5,911.67 - 5,323.66 6,025,116.10 464,474.78 2.39 2,980.69 MWD +IFR2 +MS +sag (4) 11,726.86 89.75 320.30 5,169.07 5,112.87 - 5,837.43 - 5,385.48 6,025,190.58 464,413.27 0.79 3,064.17 MWD+IFR2 +MS +sag (4) 11,823.02 90.56 320.56 5,168.81 5,112.61 - 5,763.31 - 5,446.73 6,025,264.95 464,352.32 0.88 3,147.09 MWD+IFR2 +MS +sag (4) 11,920.83 88.76 320.36 5,169.39 5,113.19 - 5,687.88 - 5,508.99 6,025,340.62 464,290.37 1.85 3,231.39 MWD+IFR2 +MS +sag(4) 12,016.50 89.38 321.88 5,170.94 5,114.74 - 5,613.42 - 5,569.04 6,025,415.32 464,230.63 1.72 3,313.28 MWD+IFR2 +MS *sag (4) 12,113.06 90.19 323.01 5,171.30 5,115.10 - 5,536.87 - 5,827.89 6,025,492.09 464,172.10 1.44 3,394.76 MWD*IFR2 +MS +sag (4) ' 12,209.55 90.62 32225 5,170.62 5,114.42 - 5,460.19 - 5,686.45 6,025,569.01 464,113.85 0.90 3,476.02 MWD+IFR2 +MS +sag (4) 12,304.26 93.77 320.94 5,166.99 5,110.79 - 5,386.04 - 5,745.24 6,025,643.39 464,055.38 3.60 3,556.62 MWD+IFR2 +MS +sag (4) 12,401.69 95.69 320.55 5,158.96 5,102.76 - 5,310.86 - 5,806.67 6,025,718.81 463,994.25 2.01 3,640.07 MWD+IFR2 +MS +sap (4) 12,498.15 95.43 319.48 5,149.61 5,093.41 - 5,237.30 - 5,868.36 6,025,792.62 463,932.86 1.14 3,723.20 MWD*IFR2 +MS +sag (4) 12,594.55 95.44 320.11 5,140.48 5,084.28 - 5,164.00 - 5,930.32 6,025,866.16 463,871.21 0.65 3,806.49 MWD+IFR2 +MS +sag (4) 12,69127 95.12 319.87 5,131.58 5,075.38 - 5,090.23 - 5,992.24 6,025,940.17 463,809.60 0.41 3.889.90 MWD+IFR2 +MS +sag (4) 12,788.04 95.87 320.32 5,122.32 5,066.12 - 5,016.34 - 6,054.03 6,026,014.30 463,748.11 0.90 3,973.24 MWD+IFR2 +MS +sag (4) 12,884.40 95.55 320.07 5,112.73 5,056.53 - 4,942.68 - 6,115.41 6,026,088.20 463,687.04 0.42 4,056.11 MWD+IFR2 +MS +sag (4) 12,980.93 94.94 320.09 5,103.90 5,047.70 - 4,868.96 - 6,177.10 6,026,162.17 463,625.66 0.63 4,139.29 MWD+1FR2 +MS +sap (4) 13,080.50 95.69 321.17 5,094.68 5,038.48 - 4,792.32 - 6,239.99 6,026,239.06 463,563.09 1.32 4,224.60 MWD+IFR2 +MS +sag (4) 13,173.65 94.63 320.42 5,086.30 5,030.10 - 4,720.43 - 6,298.63 6,026,311.17 463,504.75 1.39 4,304.29 MWD*IFR2 +MS +sag (4) 13,271.18 95.19 321.05 5,077.96 5,021.76 - 4,645.20 - 6,360.13 6,026,386.65 463,443.56 0.86 4,387.81 MWD+IFR2 +MS +sag (4) 13,367.56 94.93 320.41 5,069.45 5,013.25 - 4,570.87 - 6,420.89 6,026,461.21 463,383.10 0.71 4,470.34 MWD*1FR2 +MS +sag (4) 13,463.74 94.14 318.43 5,061.85 5,005.65 - 4,498.06 - 6,483.26 6,026,534.27 463,321.03 2.21 4,553.85 MWD+IFR2+MS+sag (4) 13,560.24 95.25 317.88 5,053.95 4,997.75 - 4,426.41 6,547.42 6,026,606.17 463,257.17 1.28 4,638.84 MWD+IFR2 +MS +sag (4) 13,657.42 95.43 318.94 5,044.91 4,988.71 - 4,354.05 - 6,611.65 6,026,678.79 463,193.25 1.10 4,723.74 MWD*IFR2 +MS +sap (4) I. 13,753.72 96.24 318.56 5,035.12 4,978.92 - 4,282.02 - 6,674.81 6,026,751.06 463,130.38 0.93 4,807.73 MWD+IFR2 +MS +sag (4) 13,848.13 94.44 319.00 5,026.33 4,970.13 -4,211.32 - 6,736.75 6,026,822.01 463,068.74 1.96 4,890.12 MWD+IFR2 +MS +sap (4) 13,945.88 93.46 319.70 5,019.60 4,963.40 - 4,137.33 - 6,800.28 6,026,896.24 463,005.52 1.23 4,975.12 MWD+IFR2 +MS *sap (4) 14,042.44 9024 319.55 5,016.48 4,960.28 - 4,063.82 - 6,862.79 6,026,970.00 462,943.31 3.34 5,059.00 MWD*IFR2 +MS +sap (4) 11/3/2009 2:48 :59PM Page 6 COMPASS 2003.16 Build 71 • Halliburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co -ordinate Reference: Well ODSN -45A - Slot ODS-45 Project Oooguruk Development TVD Reference; 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference. 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference: True Welibone: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical • MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (R) (7 (9 (n) {R) (ft) (n) (ft) (R) (°1100') (f!) Survey Tool Name 14,138.64 90.56 319.39 5,015.81 4,959.61 - 3,990.70 - 6,925.30 6,027,043.37 462,881.10 0.37 5,142.75 MWD+IFR2*MS+sag (4) 14,235.40 90.25 319.05 5,015.12 4,958.92 - 3,917.44 - 6,988.50 6,027,116.88 462,818.21 0.48 5,227.20 MWD+IFR2 +MS +sag (4) 14,331.88 91.49 319.22 5,013.66 4,957.46 - 3,844.48 - 7,051.61 6,027,190.08 462,755.40 1.30 5,311.46 MWD+IFR2 +MS +sag (4) 14,428.93 92.23 319.66 5,010.51 4,954.31 - 3,770.79 - 7,114.68 6,027,264.02 462,692.63 0.89 5,395.93 MWD+IFR2 +MS +sag (4) 14,525.20 92.10 319.53 5,006.87 4,950.67 - 3,697.54 - 7,177.04 6,027,337.52 462,630.58 0.19 5,479.58 MWD+IFR2 +MS +sag (4) 14,621.70 92.10 319.40 5,003.34 4,947.14 - 3,624.25 - 7,239.72 6,027,411.06 462,568.21 0.13 5,563.54 MWD +IFR2 +MS +sag (4) 14,715.37 90.61 320.11 5,001.12 4,944.92 - 3,552.77 - 7,300.21 6,027,482.77 462,508.01 1.76 5,644.84 MWD+IFR2 +MS +sag (4) 14,813.48 89.01 321.39 5,001.45 4,945.25 - 3,476.80 - 7,362.28 6,027,558.99 462,446.25 2.09 5,729.15 MWD+IFR2 +MS +sag (4) 14,909.63 90.93 322.51 5,001.50 4,945.30 - 3,401.09 - 7,421.54 6.027,634.93 462,387.31 2.31 5,810.73 MWD +IFR2 +MS +sag (4) 15,007.07 90.12 320.67 5,000.60 4,944.40 - 3,324.74 - 7,482.07 6,027,711.51 462,327.09 2.06 5,893.72 MWD+IFR2 +MS +sag (4) 15,103.49 87.52 320.30 5,002.59 4,946.39 - 3,250.38 - 7,543.41 6,027,786.12 462,266.07 2.72 5,976.79 MWD+IFR2*MS+sag (4) 15.200.31 87.16 320.06 5,007.08 4,950.88 - 3,176.10 - 7,605.34 6,027,860.64 462,204.44 0.45 6,060.39 MWD+IFR2 +MS +sag (4) 15,296.62 87.10 320.66 5,011.91 4,955.71 - 3,102.03 - 7,666.70 6,027,934.96 462,143.39 0.63 6,143.39 MWD+IFR2 +MS +sag (4) 15,393.08 87.28 319.99 5,016.63 4,960.43 - 3,027.88 - 7,728.21 6,028,009.35 462,082.18 0.72 6,226.55 MWD+IFR2 +MS +sag (4) 15,428.97 87.28 319.99 5,018.34 4,962.14 - 3,000.42 - 7,751.26 6,028,036.90 462,059.25 0.00 6,257.60 PROJECTED to TD 11/3/2009 2 :48 :59PM Page 7 COMPASS 2003.16 Build 71 • Page 1 of 2 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Thursday, April 07, 2011 8:55 AM To: 'Tirpack, Robert' Subject: RE: T -45A Change in Operations (PTD 209 -079) Rob, Thanks for the reply and information. Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Tirpack, Robert [mailto:Robert.Tirpack @pxd.com] Sent: Wednesday, April 06, 2011 5:35 PM To: Schwartz, Guy L (DOA) Subject: RE: T -45A Change in Operations We leave the BPV installed to give us a path to circ kill fluids down in case pressure builds up below the BPV. If a TWC is installed, we would have to remove the TWC under pressure and install the BPV with pressure, then kill the well. With the BPV installed we can close the blinds. Rob From: Schwartz, Guy L (DOA) [mailto:guy.schwartz @alaska.gov] Sent: Wednesday, April 06, 2011 10:47 AM To: Tirpack, Robert Subject: RE: T -45A Change in Operations OK... Thanks. Was thinking of some way you could test the mechanical barriers. No tubing tail plug so that makes it difficult.... Is TWC (vs BPV) an option for surface? Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Tirpack, Robert [mailto:Robert.Tirpack @ pxd.com] Sent: Wednesday, April 06, 2011 10:22 AM To: Schwartz, Guy L (DOA) Subject: RE: T -45A Change in Operations Tubing — closed SSSV and BPV IA — upper seal and lower seal on tubing hanger From: Schwartz, Guy L (DOA) [mailto:guy.schwartz @alaska.gov] Sent: Wednesday, April 06, 2011 9:49 AM 4/7/2011 3 Page 2 of 2 To: Tirpack, Robert Subject: RE: T -45A Change in Operations Can you restate again what barriers will be in place to nipple up the BOPs. Not clear on that ... Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Tirpack, Robert [mailto:Robert.Tirpack @pxd.com] Sent: Tuesday, April 05, 2011 5:02 PM To: Schwartz, Guy L (DOA) Cc: Delmonico, Joe; Johnson, Vern; Vaughan, Alex Subject: T -45A Change in Operations Guy, As discussed on the phone, we will be changing the operations from the approved Sundry on T -45A. The original plan called for placement of an inflatable bridge plug in the liner top. We are now going to eliminate the inflatable bridge plug. During coil tubing operations to set the IRBP, the coil started to pull tight while coming out of the hole during a gauge ring - nipple locator run. The decision was made to eliminate the IRBP due to possible fish in the tubing. During slickline work on 6/13/10, a GLM valve was pulled that was missing the bottom 6" of the valve. Please call if you have any questions. Thanks, Rob Robert Tirpack Drilling Superintendent Pioneer Natural Resources 907 -343 -2121 office 907 - 903 -9454 cell 907 -243 -3773 home robert.tirpack @pxd.com Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e -mail and delete the message and any attachments. 4/7/2011 • PIONEER NATURAL RESOURCES ALASKA Letter of Transmittal Date: March 9, 2011 FROM TO Shannon Koh AOGCC Pioneer Natural Resources Attn: Christine Shartzer 700 G Street, Suite 600 333 W. 7 Avenue, Suite 100 Anchorage, AK 99501 Anchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑ Maps ❑ Report X Other-1 CD ❑ Agreement DETAIL QTY DESCRIPTION ODSN -45A (API: 50703205770100) 1 CD ODSN -45A Complete PVT Reservoir Fluid Study We request that all data be treated as confidential information. Thank you. RECEIVED MAR 1 4 2011 Received by: a- Date: Make ON & Gas Cons. Commission Anchors Please sign and return one copy to Pioneer Natural Resources, Inc., ATTN: Shannon Koh 700 G Street, Suite 600, Anchorage, AK 99501 907 -343 -2190 fax 907 - 343 -2128 phone 1�` i I • • ll SEAN PARNELL, GOVERNOR LA M �_ .a =J ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION / SSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 ! FAX (907) 276 -7542 Joe Delmonica Drilling Engineer Pioneer Natural Resources Alaska, Inc. , ©9 , 011 700 G Street, Suite 600 p Anchorage, AK 99501 Re: Oooguruk Field, Undefined WiD P Pool, ODST -45A Sundry Number: 311 -052 Dear Mr. Delmonica: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 0, Daniel T. Seamount, Jr. Chair DATED this 1 day of March, 2011. Encl. Page 1 of 1 • • Schwartz, Guy L (DOA) From: Delmonico, Joe [Joe.Delmonico @pxd.com] Sent: Monday, February 28, 2011 10:42 AM To: Schwartz, Guy L (DOA) Cc: Tirpack, Robert; Johnson, Vern Subject: RE: ODST -45A RWO (PTD 209 -079) Guy, Per our conversation. ,, - ----- ODST -45A: MASP = 555 psi An additional step will be added after setting the Dummy GLV's to test the 7 -5/8" casing to 2500 psi for 30 min charted. ODSK- 41: \..._...-- .-- _ ----, _...._._ .._.-. - ,......__.. _ ...- MASP = 375 psi An additional step will be added to attempt to bullhead kill weight fluid down the IA through the PVV prior to pulling the tubing hanger and releasing the packer. Regards, Joe Delmonico Jr. Drilling Engineer Pioneer Natural Resources Alaska Office: 907 - 343 -2182 Mobile: 907 - 980 -7690 From: Schwartz, Guy L (DOA) [ mailto:guy.schwartz @alaska.gov] Sent: Friday, February 25, 2011 3:06 PM To: Delmonico, Joe Subject: ODST -45A RWO (PTD 209 -079) Joe, I reviewed the RWO to pull frac completion on ODST -45A . I saw in step 7 ( pre -rig SL operations) that you are pulling GLV and circulating to KWF. This would be an opportune time to get a CMIT in order to pressure test the 7 5/8" casing. I didn't see any other place until you run the new completion to do this. Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e -mail and delete the message and any attachments. 2/28/2011 IONEER • NATURAL RESOURCES ALASKA Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, Alaska 99501 Tel: (907) 277 -2700 Fax: (907) 343 -2190 February 25, 2011 __ State of Alaska FEB 2 5 2011 Alaska Oil and Gas Conservation Commission RECEIVED 333 West 7 Ave, Suite #100 Anchorage, AK 99501 FEB 2 201 RE: Application for Sundry to Modify Completion, ODST -45A Alaska Oil & Gas Cons. Commission Anchorage Pioneer Natural Resources Alaska is requesting Sundry approval for the workover of the ODST -45A production well. Please see the attached Form 10 -403 and proposed rig workover plan. The well's upper completion is currently a 4 -1/2" fracture stimulation . string, producing with gas lift. The proposed workover would replace the 4 -1/2" string with a 2 -7/8" Electric Submersible Pump (ESP) completion. Please see the attached proposed completion diagram and operations summary for further detail. Sincere , sr Joe Delmonico Jr. Drilling Engineer Attachments: Form 10 -403 Supporting Sundry information cc: ODST -45A Well File s 0 ,t STATE OF ALASKA 1111 '� ALASKA OIL AND GAS CONSERVATION COMMISSION SA APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well 0 Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate p Pull Tubing 0 Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Change Tubing/Run ESP 0 • 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Pioneer Natural Resourcs Alaska, Inc. Development 0 Exploratory ❑ 209 -079 . 3. Address: 700 G Street, Suite 600 Stratigraphic ❑ Service ❑ 6. API Number: Anchorage, AK 99501 50- 703 - 20577 -01 -00 , 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No 0 . ODST -45A , 9. Property Designation (Lease Number): 10. Field/Pool(s): e)a,,ru 4=. /� rz j L e y 6 R ADL 355036 ' L w Oooguruk - Undefined 2.2c 11. PRESENT WELL CONDITION SUMMARY ��� 2011 Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (me�s g�d): un (ea msured): 18surKaOII &GasC J s.to 7AIon 15,429' + 5018' . 15,422' 5018' N/A A�p� Casing Length Size MD TVD Biir'>#f'r B Collapse Structural Conductor 110' '16" 153' 153' N/A N/A Surface 4931' 10 - 3/4" 4973' 3438' 5210 psi 2470 psi Intermediate 9994' 7 -5/8" 10,050' 5001' 6890 psi 4790 psi Production 5533' 4 -1/2" 9891' - 15,424' 4951' - 5018' N/A N/A Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attachment, pg. 2 See Attachment, pg. 2 4 - 1/2 ", 12.6# L - 80, HYD 521 9906' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): SSSV; TSP Liner Top Packer; Water Swell Packer 768' MD / 768' TVD; 9907' MD / 4956' TVD; 11,400' MD / 5173' TVD 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory p Development 0 . Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 3/10/2011 Oil 0 . Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ p GINJ p WAG ❑ Abandoned p Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Joe Delmonico, 343 -2182 Printed Name � �e�,1 ' •, 2182 /907- 980-7690 Title Drilling Engineer Signature Phone Date 2/25/2011 Prepared By: Kathy Campoamor, 343 -2183 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: j ) f . (76 < 2.... Plug Integrity ❑ BOP Test 12 Mechanical Integrity Test p Location Clearance ❑ ✓ / Other: i e SS p sty POP S �� 0-2 2S p \ si- Akin. s /) Subsequent Form Required: / a _ Gib t-/' APPROVED BY 3 ii J r Approved by: COMMISSIONER THE COMMISSION Date: J ` S MAR 0 2 7011 RIGINA1_% :2:=. L' z.(; /( Form 10 -403 Revised 1/2010 e'2 `S �� Submft in plicate 774,--/./,, • Pioneer Naturiesources Alaska Inc. ODST -45A Page 2 AOGCC Form 10 -403, Application For Sundry Approvals Box #11, Attachment Present Well Condition - Perforation Depth 23. Open to production or injection P P injection 12.60 #, L -80 Liner - Pup joints ported with 6 - 1/2" holes @ depths listed: MD TVD 11,581' - 11,586' 5170' -5170' 11,786' - 11,791' 5169' - 5169' 11,991' - 11,996' 5171' - 5171' 12,196' - 12,200' 5171' - 5171' 12,402' - 12,406' 5159' - 5159' 12,688' - 12,692' 5132' - 5132' 13,009' - 13,014' 5101' - 5101' 13,213' - 13,217' 5083' - 5083' 13,417' - 13,422' 5066' - 5065' 13,584' - 13,588' 5052' - 5051' 13,787' - 13,792' 5032' - 5032' 13,989' - 13,994' 5018' - 5018' 14,195' - 14,200' 5015' - 5015' 14,396' - 14,401' 5012' - 5011' 14,600' - 14,604' 5004' - 5004' 14,806' - 14,810' 5001' - 5001' 15,008' - 15,013' 5001' - 5001' 15,210' - 15,215' 5008' - 5008' 15,417' - 15,422' 5018' - 5018' • • ODST -45A Proposed Rich Workover Operations Summary Pre Rig: Slickline Operations 1. SI ODST -45A 1 - 3 days prior to MIRU. 2. MIRU slickline. 3. RIH and remove the WRScSSSV. 4. RDMO. Pre Rig: Coil Tubing Operations 1. MIRU coil tubing and RIH with 4.5" mechanical bridge plug and set below the 4 -1/2 "x 7 -5/8" / liner /hanger /packer assembly in the 4.5" liner at 9,970' MD. 2. Circulate kill weight fluid through coil, to fluid pack the tubing./ 3. Pressure test bridge plug to 2500 psi for 5 min. ,i 4. RDMO. Pre Rig: Slickline Operations 2 1. MIRU slickline. 2. RIH and set plug catcher. 3. RIH and retrieve LGLV from GLM #2( 4. RIH and retrieve LGLV from GLM #1. ✓ 5. RIH and set dummy GLV in GLM #1. 6. Circulate kill weight fluid through GLM #2. o IA and tubing should be packed. �M�T 7. RIH and set a dummy GLV in GLM #2. -� We'd N a 8. Retrieve plug catcher. 9. RDMO. 10. Monitor WHP and IAP via operator's daily reading schedule until rig moves on location, prep surface equipment for rig move. MIRU Nabors 19AC: 1. Install a BPV into the tubing hanger profile. a. Barriers are (a minimum of 2): i. Tubing side 1. Kill weight fluid to formation 2. Bridge plug in liner. 3. BPV in the tubing hanger. ii. Annulus 1. Kill weight fluid to the tested liner hanger packer. " 2. Tested Seals stabbed into polished bore. Page 1 of 2 PIONEER NATURAL RESOURCES ALASW. • • 3. Bridge plug in liner. 4. Packoff. 2. Test BOP's as per standard AOGCC requirements. With low (250 psi) and high (3500 psi) 5 minutes each. State will need to be notified to witnes1 test. 3. Pull to release seals from seal bore. — a 44- 4. Pull 4 -1/2" frac completion string out of the hole filling hole matching pipe displacement. 5. PU4 "DP. 6. PU casing scraper and junk basket and RIH to the top of the liner. Circulate hole clean. POOH. 7. RIH and retrieve BP from liner. 8. Have FOSV on rig floor crossed over to 2 -7/8" IBT -M. 9. PU & RIH 2 -7/8 ", 6.5 ppf, L -80, IBT -M tbg consisting of: a. ESP w/ ADV b. X nipple w/ RHCM plug body c. Dummied 2 7/8" GLM d. 7 -5/8" x 2 -7/8" Packer with GW. e. X nipple above packer f. Dummied 2 7/8" GLM g. TRScSSSV 10. PU LJ w/ production tubing hanger. 11. Land tubing hanger. RILDS for tubing hanger. Test both the upper and lower tubing hanger body seals to 5000psi. Set BPV. 12. ND BOPE 13. NU Vetco Gray Production ESP X -mas tree and body test to 5000 psi. 14. Monitor ScSSSV control line pressure to ensure adequate hold open pressure during roller stem ball running. Set packer. Test annulus and tubing to 2500psi, 30 min tests. Post Rig: 1. MIRU HES Slickline 2. Retrieve ball /rod assembly from RHC -M plug body. 3. RIH with kick over tools and pull dummy from lowest GLM. Run LGLV with 0.25 orifice back in mandrel. 4. RIH w/ 2 -7/8" GS to X nipple, retrieve RHC -M plug body. 5. Rig down slickiine 6. Function Test TRScSSSV. Page 2 of 2 PIC)NEER NATURAL RESOUR(.F.S ALASKA • • ODST -45A As Run Completion Well Head: 10 -3/4 ", 5K, VetcoGray Tree: 3 -1/2 ", 5K, Horizontal • O Please see next page for completion detail 1 OA1 'fib – —1 0 • r O O i 0 0 '' 111 0 0 1 0 0 ® c D1 1 4 • 00 00 00 00 00 00 00 00 Cement Squeeze 00 00 00 00 00 00 00 00 prior to the 00 00 00 00 00 00 00 00 t sidetrack - - operations �� J Estimated Top of Cement @ EZSV 10100' MDrkb / 501 TTVDrkb 10100' MD / 1 Cement above packer: 2.5bbI / 50' 5017' TVDrkb Cement below packer: 79.5bbI / 1277' to 7 -5/8" shoe + 6 100' w/ 30% excess bullhead below shoe Top of 6" liner, 10,806' MDrkb / 5239' TVDrkb 7 -5/8 ", 29.7# L -80 BTC -M, 6.875" ID i Top of Inner String fish, 10,825MDrkb i 11377' MDrkb / 5412' �� Live Severing Charge w/ 2.0" OD ./` TVDrkb , Debris Catcher, 2.0" ID 12413' MDrkb, Top of Expanded Section, / 6 ", 18.6# L -80 Expanded to 6.767" OD, 6.19" ID, 6.131" Drift Connection unable to hold pressure, 13,433 MDrkb Expansion Cone ' Expandable csg shoe 13,513' MDrkb / 6071' TVDrkb 13866' MDrkb / 6166' TVDrkb Hole Fill and Un- consolidated Cement Date: Revision By: Comments Pio E E R 6/1/2009 JDF Proposed Completion Updat 6/16/2009 VHH Updated to current directional plan ODST -45A Current 'I�TTo^' f1131 ppCp�IIII0p CCpp�^�ppI^ 9/28/2009 TWC Proposed Completion Revision Well Schematic Y.1lESOEJnCES4 S(A 11/21/2009 TWC As Run Update • • ODST -45A As Run Completion Casing Item # Item MD (ft) TVD (ft) A 16" Conductor 153 153 B 10 -3/4" 45.5# L -80 BTC, 9.95" ID _ 4,973 _ 3,438 C 7 -5/8" 29.7# L -80 BTC -M, 6.875" ID (Window) 10,038 4,996 D 4 -1/2" 12.6# Hydril 521 3.958" ID 15,429 5,018 Upper Completion MDrkb (ft) TVDrkb (ft) 1 VetcoGray Tubing Hanger _ 34 34 4 -1/2" XXO Safety Vale Landing Nipple w/ Wireline _ 2 Retreivable ScSSSV 759 758 _ 3 GLM #1 Brou -1A GLM 4 -1/2" x 1" 2,032 2,000 4 4 1/2" X Nipple, 3.813" ID 2,089 2,053 _ 5 GLM #2 Brou -1A GLM 4 -1/2" x 1" 9,689 4,889 6 4 1/2" XN Nipple, 3.725" ID Nogo _ 9,788 _ 4,920 7 4 -1/2" HES ROC Gauge 9,840 4,936 8 WFT Seal Assy w/ Locator and 1/2 Muleshoe WLEG 9,890 4,951 End of Assembly 9,906 4,956 Lower Completion r m MD (ft) TVD (ft) 9 WFT PBR Tie Back Sleeve 15ft 9,891 4,951 WFT "TSP" Liner Top Pkr w/ Hold Down Slips 5 -1/2 20 #x 7- 10 5/8 29.70 w/ Van Top HT Box Down _ 9,907 _ 4,956 WFT "PHR" Rotating Hyd Set Liner Hanger 5 -1/2 20# x 7- 5/8 29.70 #w/ 5 -1/2 Vam Top HT Pin x Pin XO w/ 5 -1/2 11 Vam Top HT Box x 4 -1/2 Hydril 521 Pin 9,910 4,957 WFT 4 -1/2 12.60# x 5.75od x 15 Ft "Genesis" Water - 12 Based Swellable Packer w/ 4 -1/2 Hydril 521 Box x Pin _ 11,401 _ 5,173 13 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,581 5,170 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,786 5,169 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) _ 11,991 _ 5,171 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) _ 12,196 5,171 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,402 5,159 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,688 _ 5,132 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) _ 13,009 5,101 _ 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,213 5,083 _ 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,417 5,065 _ 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) _ 13,584 _ 5,052 _ 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,787 5,032 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) _ 13,989 5,018 _ 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,195 5,015 _ 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,396 _ 5,012 _ 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) _ 14,600 5,004 _ 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,806 5,001 _ 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,008 5,001 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) _ 15,210 5,008 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,417 5,018 Ray Oil Tool Silver Bullet Eccentric Float Shoe _ 14 (PLUGGED) w/ 4 -1/2 Hydril 521 Box _ 15,422 _ 5,018 TD 15,429 5,018 • II ODST -45A Proposed ESP Completion Casing Item # Item MD (ft) TVD (ft) A 16" Conductor 153 153 B 10 -3/4" 45.5# L -80 BTC, 9.95" ID 4,973 3,438 Well Head: 10 3/4 ", 5K, VetcoGray I C 7 -5/8" 29.7# L -80 BTC -M, 6.875" ID (Window) 10,038 4,996 y D 4 -1/2" 12.6# Hydril 521 3.958" ID 15,429 5,018 Tree: 3 -1/2 ", 5K, Horizontal E 2 -7/8" 6.58 L -80 IBT -M Tubing 9,560 4,847 O Upper Completion "� MDrkb (ft) TVDrkb t� 1 VetcoGray Tubing Hanger 34 34 O ' 2 2 -7/8 HES Wellstar TRSV w/ 2.313" Packing Bore 2,031 2,000 • GLM #1 - Vanoil 2 -7/8" x 1 -1/2" w/ DV installed 3 (1 joint above top X nipple) 2,553 2,451 O 4 2 -7/8" XNipple 2.313" I.D. (1 joint from packer) 2,585 2,476 111:311- WFT 7 -5/8" x 2 -7/8" Gas Vent Valve Packer (max. TVD 5 2500') 2,617 2,500 GLM #2 - Vanoil 2 -7/8" x 1 -1/2" DV installed 6 (2 joints above X nipple) 9,376 4,789 • ©M 2 -7/8" XNipple, 2.313" I.D. w/ "RHC -M" Plug with • O • 7 extended neck installed (Max inc. 70 deg) 9,440 4,809 © 8 Automatic Divert Valve (ADV) 9,490 4,825 S A 9 ESP (Pump, Motor, and Jewelry) 9,500 4,828 EndofAssembly 9,560 4,847 O 10 WFT PBR Tie Back Sleeve 158 9,891 4,951 WFT "TSP" Liner Top Pkr w/ Hold Down Slips 5-1/2 20#x 11 7 -5/8 29.70 w/ Vam Top HT Box Down 9,907 4,956 WFT "PHR" Rotating Hyd Set Liner Hanger 5-1/2 20# x 7- 5/8 29.70 #w/ 5-1/2 Vam Top HT Pin x Pin XO w/ 5-1/2 12 Vam Top HT Box x 4-1/2 Hydril 521 Pin 9,910 4,957 WFT 4-1/2 12.60# x 5,75od x 15 Ft "Genesis" Water - � . 13 Based Swellable Packer w/ 4-1/2 Hydril 521 Box x Pin 11,401 5,173 l%J 14 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,581 5,170 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,786 5,169 ■ O • 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,991 5,171 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,196 5,171 0 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,402 5,159 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,688 5,132 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,009 5,101 O 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,213 5,083 4-1/2 12.60 L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 13,417 5,065 0 0 0 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,584 5,052 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,787 5,032 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,989 5,018 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,195 5,015 0 4-1/2 12.60 L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 14,396 5,012 al O 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,600 5,004 4-1/2 12.60 L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 14,806 5,001 4-1/2 12.60 L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 15,008 5,001 ® 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,210 5,008 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,417 5,018 Ray Oil Tool Silver Bullet Eccentric Float Shoe O 15 • • (PLUGGED) w/ 4-1/2 Hydril 521 Box 15,422 5,018 13 TD 15,429 5,018 1 •• •• •• •• •• •• •• •• •• •• 14 •• •• •• •• • 15 O Cement Squeeze when well was •• •• •• •• •• is •• sidetracked Estimated Top EZSV 10100' MDrkb / 501TNDrkb of Cement @ 10100' MD / Cement above packer: 2.5bbI / 50' 5017' TVDrkb Cement below packer: 79.5bb1 / 1277' to 7 -5/8" shoe + 100' w/13001%00 30% excess bullhead below shoe 7 -5/8 ", 29.7# L -80 BTC -M, 6.875" ID 1 11377' MDrkb / 5412' TVDrkb Date: Revision By: Comments P n R 1/31/2011 RBT Proposed ESP Completion 2/23/2011 JAD Proposed ESP Completion ODST -45A Proposed ESP NERAl.RESNRCESM Completion MI PIONEER REc �� NATURAL RESOURCES ALASKA FEB 0 4 2D A Letter of Transmittal ° /ge CM& G81 C¢ ®t:bi Q. rivn 600 Date: February 3, 2010 FROM TO Shannon Koh AOGCC Pioneer Natural Resources Attn: Christine Shartzer 700 G Street, Suite 600 333 W. 7 Avenue, Suite 100 Anchorage, AK 99501 Anchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑ Maps ❑ Reports X Other - CD ❑ Agreement DETAIL QTY DESCRIPTION ODSN -45A (a.k.a ODST -45A) 1 CD Reservoir Fluid PVT Study Inventory List Water Analysis Final Report Recomb #1 Validation Study We request that all data be treated as confidential information. Thank you. Received by: �, . Date: return one copy to Pioneer Natural Resources, Inc., Please sign and retu py ATTN: Shannon Koh 700 G Street, Suite 600, Anchorage, AK 99501 907 -343 -2193 fax 907 - 343 -2128 phone ' 2d PIONEER NATURAL RESOURCES ALASKA Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, Alaska 99501 Tel: (907) 277 -2700 F1RQ _ December 14 2010 DEC 1 8 2010 Alaska Oil & Gas Cans. Commission State of Alaska Anchorage Alaska Oil and Gas Conservation Commission Fri) ,q3CJ_ 7 333 West 7 Avenue, Suite #100 Anchorage, AK 99501 RE: Name Change for ODSN -45A Permit To Drill #209 -079, API #50- 703 - 20577 -01 Surface Location: 2889' FSL, 1176' FEL, Sec 11, T13N, R7E, UM X = 469821.86, Y = 6031005.53, ASP4 Pioneer Natural Resources Alaska, Inc. (PNRA) wishes to change the well name on ODSN -45A, which was permitted and approved by the AOGCC on 08/10/09. The well, located within the Oooguruk Unit, was originally planned as a Nuiqsut well, but was re- designed, drilled, and completed in the Torok formation. Original Well Name /Number: ODSN -45A New Well Name /Number: ODST -45A Please update the AOGCC files to reflect the name change from ODSN -45A to ODST -45A accordingly. Aside from the name change, all other data remains the same. If you have any questions or require further information, please contact Alex Vaughan at 907.343.2186. Sincere! 1 - Alex Vaughan Operations Drilling Engineer cc: ODSN -45A / ODST -45A Well File I RECEIVED I/ STATE OF ALASKA • k1 2009 ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORWaANINLOGns.Commssion 1a. Well Status: Oil El Gas ❑ SPLUG ❑ Plugged ❑ Abandoned ❑ Suspended 1b. Well Class: Anchorage 20AAC 25.105 20AAC 25.110 Development ❑ Exploratory 0 GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ Other ❑ No. of Completions: One Service ❑ Stratigraphic Test ❑ 2. Operator Name: 5. Date Comp., Susp., or 12. Permit to Drill Number: Pioneer Natural Resources Alaska, Inc. Aband.: 10/30/2009 209 -079 3. Address: 700 G Street, Suite 600 6. Date Spudded: 13. API Number: Anchorage, AK 99501 10/10/2009 50- 703 - 20577 -01 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 2889' FSL, 1176' FEL, Sec. 11, T13N, R7E, UM 10/21/2009 ODSN - 45A Top of Productive Horizon: 8. KB (ft above MSL): 56.2' 15. Field /Pool(s): -�- 1902' FSL, 5158' FEL, Sec. 14, T13N, R7E, UM GL (ft above MSL): 13.5' a� IkQk1L , 1 o R I) k_ Total Depth: 9. Plug Back Depth(MD +TVD): Undefined O ' L• 5165' FSL, 3650' FEL, Sec. 15, T13N, R7E, UM N/A SPOI gaigf d9 4b. Location of Well (State Base Plane Coordinates, NAD 27): 10. Total Depth (MD + TVD): 16. Property Designa ion. Surface: x- 469821.86 y- 6031005.53 Zone - ASP 4 15,429' MD / 5018' TVD ADL 355036 TPI: x- 465820.3 y- 6024755.6 Zone - ASP 4 11. SSSV Depth (MD + TVD): 17. Land Use Permit: Total Depth: x- 462059.3 y 6028036.9 Zone - ASP 4 768' MD / 767' TVD 417497 18. Directional Survey: Yes 0 No ❑ 19. Water Depth, if Offshore: 20. Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) 835' MD / 821' TVD 21. Logs Obtained (List all logs here and submit electronic and printed information per 20AAC25.071): 22.Re- drill /Lateral Top Window MD/TVD: AFR, DGR, EWR, PWD 10,050' MD / 5001' TVD 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 16" 109# H -40 Surface 153' Surface 153' 24" Driven 10 -3/4" 45.5# L-80 BTC Surface 4973' Surface 3438' 13 -1/2" 433 sx PF'L'; 768 Class 'G' 7 -5/8" 29.7# L- 80 Surface 10,050' Surface 5001' 9 -7/8" 166 sx Class 'G' 4 -1/2" 12.6# HYD 521 9891' 15,424' 4951' 5018' 6 -1/8" Uncemented w/ pre - perfed pups • 24. Open to production or injection? Yes No If Yes, list each 25. TUBING RECORD P p � ❑ interval open (MD +TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4 -1/2 ", 12.6 #, HYD 521 9906' 9907' MD / 4956' TVD See Attachment, Page 3 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 2032' Freeze protect w/ 85 bbls diesel 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Test Period .■► Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 24 -Hour Rate - 28. CORE DATA Conventional Core(s) Acquired? Yes ❑ No ❑ Sidewall Cores Acquired? Yes ❑ No ❑ If Yes to either question, list formations and intervals cored (MD +TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. None ' • Pi F1EO Re n/I P4 C t [ Y t Form 10 -407 Revised 7/2009 CONTINUER EV ERSE 74 /2 .M. 07 Subm' rlgtnal only G • • 28. GEOLOGIC MARKERS (List all formations and markers encountered): 29. FORMATION TESTS NAME MD TVD Well tested? U Yes No If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if needed, Permafrost - Top 843' 842' and submit detailed test information per 20 AAC 25.071. Permafrost - Base 1678' 1663' Top Wes Sak 2343' 2280' Top Torok 10,036' 4996' Mid Torok 10,648' 5090' Lower Torok 10,894' 5133' None Formation at total depth: 15,429' 5018' 30. List of Attachments: Summary of Daily Drilling Operations, Well Schematic Diagram, Surveys 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Alex Vaughan, 343 - 2186 Printed Name: Vern �y�"son — Title: Sr. Staff Drilling Engineer Signature: /Z ' Phone: 343 -2111 Date: 12/7/2009 ODSN -45A Permit To Drill #209 -079 Prepared By: Kathy Campoamor, 343 -2183 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10 -407 well completion report and 10 -404 well sundry report when the downhole well design is changed. Item la: Classification of Service wells: Gas Injection, Water Injection, Water - Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50- 029 - 20123- 00 -00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut -in, or Other (explain). Item 27: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 29: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10 -407 Revised 7/2009 • +� Pioneer Natural Resources Alaska Inc. ODSN -45A Page 3 AOGCC Form 10 -407, Well Completion or Recompletion Report and Log Box #23, Attachment 23. Open to production or injection 4 -1/2", 12.60 #, L -80 Liner - Pup joints ported with 6 -1/2" holes @ depths listed: MD TVD 11,581' - 11,586' 5170' - 5170' 11,786' - 11,791' 5169' - 5169' 11,991' - 11,996' 5171' - 5171' 12,196' - 12,200' 5171' - 5171' 12,402' - 12,406' 5159' - 5159' 12,688' - 12,692' 5132' - 5132' 13,009' - 13,014' 5101' - 5101' 13,213' - 13,217' 5083' - 5083' 13,417' - 13,422' 5066' - 5065' 13,584' - 13,588' 5052' - 5051' 13,787' - 13,792' 5032' - 5032' 13,989' - 13,994' 5018' - 5018' 14,195' - 14,200' 5015' - 5015' 14,396' - 14,401' 5012' - 5011' 14,600' - 14,604' 5004' - 5004' 14,806' - 14,810' 5001' - 5001' 15,008' - 15,013' 5001' - 5001' 15,210' - 15,215' 5008' - 5008' 15,417' - 15,422' 5018' - 5018' 0 -4111 ODSN -45A As Run Completion 1 � Well Head: 10 -3/4 ", 5K, VetcoGray Tree: 3-1/2", 5K, Horizontal _ Please see next page for completion detail 0 A ■ �� O� O O 0 • O O 0 0 II 0 0 OZ. 0 !•,! • ' 0 1 14 ( ..-- 00 00 00 00 00 00 00 00 Cement Squeeze 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 prior to the 00 00 00 00 00 00 00 00 , sidetrack - - operations f—__ Estimated Top of Cement @ EZSV 10100' MDrkb / 5017'TVDrkb 10100' MD / Cement above packer: 2.5bbI / 50' 5017' TVDrkb Cement below packer: 79.5bbI / 1277' to 7 -5/8" shoe + 100' w/ 30% excess bullhead below shoe Top of 6" liner, 10,806' MDrkb / 5239' TVDrkb 7 -5/8 ", 29.7# L -80 BTC -M, 6.875" ID i Top of Inner String fish, 10,825MDrkb 11377' MDrkb / 5412' Live Severing Charge w/ 2.0" OD TVDrkb j Debris Catcher, 2.0" ID 12413' MDrkb, Top of Expanded Section, / 6 ", 18.6# L -80 Expanded to 6.767" OD, 6.19" ID, 6.131" Drift I Connection unable to hold pressure, 13,433 MDrkb 4 ( Expansion Cone 1 Expandable csg shoe 13,513' MDrkb / 6071' TVDrkb 13866' MDrkb / 6166' TVDrkb Hole Fill and Un- consolidated Cement Date: Revision By: Comments PIO\ [ER 6/1/2009 JDF Proposed Completion Updat 6 /16/2009 VHH Updated to current directional plan ODSN -45A ^ nI pCC IIp Cp ^ 9/28/2009 TWC Proposed Completion Revision NA Final Well ALO 11/21/2009 TWC As Run Update Schematic ODSN -45A As Run Completion Casing Item # Item MD (ft) TVD (ft) A 16" Conductor 153 153 B 10 -3/4" 45.5# L -80 BTC, 9.95" ID 4,973 3,438 C 7 -5/8" 29.7# L -80 BTC -M, 6.875" ID (Window) 10,038 4,996 D 4 -1/2" 12.6# Hydril 521 3.958" ID 15,429 5,018 Upper Completion �+ +� ►* MDrkb (ft) TVDrkb (ft) 1 VetcoGray Tubing Hanger 34 34 4 -1/2" XXO Safety Valve Landing Nipple w/ Wireline 2 Retreivable ScSSSV 759 758 3 GLM #1 Brou -1A GLM 4 -1/2" x 1" 2,032 2,000 4 4 1/2" XNipple, 3.813" ID 2,089 2,053 5 GLM #2 Brou -1A GLM 4 -1/2" x 1" 9,689 4,889 6 4 1/2" XN Nipple, 3.725" ID Nogo 9,788 4,920 7 4 -1/2" HES ROC Gauge 9,840 4,936 8 WFT Seal Assy w/ Locator and 1/2 Muleshoe WLEG 9,890 4,951 End of Assembly 9,906 4,956 Lower Completion Item # Item MD (ft) TVD (ft) 9 WFT PBR Tie Back Sleeve 15ft 9,891 4,951 WFT "TSP" Liner Top Pkr w/ Hold Down Slips 5 -1/2 20 #x 7- 10 5/8 29.70 w/ Vam Top HT Box Down 9,907 4,956 WFT "PHR" Rotating Hyd Set Liner Hanger 5 -1/2 20# x 7- 5/8 29.70 #w/ 5 -1/2 Vam Top HT Pin x Pin XO w/ 5 -1/2 11 Vam Top HT Box x 4 -1/2 Hydril 521 Pin 9,910 4,957 WFT 4-1/2 12.60# x 5.75od x 15 Ft "Genesis" Water - 12 Based Swellable Packer w/ 4 -1/2 Hydril 521 Box x Pin 11,401 5,173 13 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,581 5,170 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,786 5,169 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,991 5,171 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,196 5,171 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,402 5,159 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,688 5,132 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,009 5,101 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,213 5,083 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,417 5,065 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,584 5,052 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,787 5,032 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,989 5,018 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,195 5,015 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,396 5,012 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,600 5,004 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,806 5,001 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,008 5,001 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,210 5,008 4 -1/2 12.60 L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 15,417 5,018 Ray Oil Tool Silver Bullet Eccentric Float Shoe 14 (PLUGGED) w/ 4 -1/2 Hydril 521 Box 15,422 5,018 TD 15,429 5,018 dij E E R p ©n AURAL RESOURCES , _ ; 6; w elI Same: OD A ' ` Contractor: NABOBS DRILLING Rig Number: 19 AC Job Cate rlr DEVELOPMENT DRILL Date. Rig Release Date: s b "t1fQ @. _ .bs . . ,. shy ;"4 . , -(}: �"�k`' °'s',,., a _'�...v... i . ,..„ _ t .r . ,.;.'^.'- ct« . z��..:: �'..� ?. `"'s ... 10/4/2009 10/5/2009 0,0 8.55 Move Nabors 19AC from ODSN -34i to ODSN -45A (Note: ODSN -45i until mill window & kickoff) and RU. Rig accepted on ODSN -45A 0 00:00 hrs, 10/04/09. Reverse circulate out diesel freeze protect. Check well for flow - static. Install TWC valve and ND tree. NU BOPE. Change out bottom pipe rams from 3.5 to 4. Test BOPE's. Annular to 250 psi low / 2500 psi high. Blind Rams, Upper VBR's (2 -7/8' X 5') Lower 4' Rams, Kill & Choke HCR valves, Kill & Choke manual valves, Floor Safety & Dart valves, Upper & Lower IBOP valves to 250 psi low 13500 psi high. 14 Choke Manifold valves to 250 psi low / 3500 psi high. All tests held 5 min each on chart. Accumulator test, System Pressure 3000 psi, After Closure 2100 psi, Initial 200 psi recovery 17 seconds, Full pressure recovery 1 min 32 seconds. No Failures. AOGCC rep Jeff Jones waived witness of BOP test at 20:15 hrs on 10/3/09. Change out top drive saver sub. RU 2 -7/8' handling tools. Install landing joint and unseat tubing hanger. LD tubing hanger and landing joint. 1G'6/2009 10/7/2009 0.0 8.60 TIH f/3,104' t/9,350. LWD log f/9,350' t/9,473'. Pump 20 bbl hi -vis sweep and circulate out same through gas buster. LWD log f/9,473' t/10,104. Tagged up on cement retainer at 10,104. Pump 30 bbl hi -vis sweep and circulate out same. RU and test casing to 3500 psi held 30 min on chart - Good test. POOH f/10,104' to the BHA. Download LWD, remove nuclear sources, LD BHA. PU Fast Drill cement retainer with 4, 2' shot interval, 6 spf, 60* phased Drill Guns and TIH t12,616. 95 RIH with Drill Gun Assembly (/2,616' t/10,040. Set Fast Dnit P acker arxi stdown.2f to rm pressure up annulus to W00 psI and fire perf guns with 3400 psi DP #sre�s ? � . sed from packer with 220k PUW. RU cement lines and test to 3200 psi. Pero at .5.3 bpm with FCP of 2990 psi. Pump 20 bbls 8.6 ppg seawater ahead. Pump 33 t7 eufsk) 15.8 ppg Class 'G' Cement, :2% CFR 3; 75% Halad 344 3°lo SCR 100 an splaced with 13.bbls 8.6 ppg seawater. Sting into packer and squeeze ment aw aw*, Ott 25 bpm with 2950 psi Final mection rate*2bpn mth itJM1 i `�9 from Fas Drill and POQIioatasl� Job. POOH V9 �� s a dew > ma f�iulown Saver Still operatlonal '? PO3 �� x« 24 hr notic to witness 7 5/8 perforated casing ce 3s x�4 .an *�`` Jgff Jone�+wtatved YintrteSS Cement',SEtiQeZQ a `�' " 10/8/2009 10/9/2009 10,040.0 0.00 9.10 POOH with Fas Drill Running Tool and LD same. PU BHA #12, 6 -314' Smith XR +312 Bit - Watermelon Mill - Bit Sub - NM Float Sub - 2x NM Flex DC's - Stab - NM Flex DC - Bumper Sub - 3x HWQP- Dulling Jar - 21x HWDP t/871'. RIH f/871' t/9,648. Clean out cement stringers f/9,648' t/10,020'. Drill Cement f/10,020' t/10,040'. Drill Packer and Perf Gun tail assembly f/10,040' t/10,095. Circulate 2ea 50 bbl high -vis sweeps surface to surface. POOH with BHA #12 f/10,095' t1871', installing Super Sliders on first 111 jts out of hole. POOH laying down BHA f/871' t/42'. Notified AOGCC of early BOPE test to be performed on 10/9/09. Witness of test waived by AOGCC representative Chuck Scheve. 10.040 $ POOH +d BHA ff 2 Tested 'Arun ar to - 250 psl I tY 2500 p si high. Tested Upper VBR's (2 ). tower 4` Rams (ffted bore) Blind Rams, - line Choke .:. Kill line va3veFloor safety, Dart Upper TP `` - ' high A� Iow 5 min and Kill line y I i fail k/+t 4 3 2s f .A` �v ey' £ +, 9 $ A r 4 Initi 2j ! € F' kT ` rete . PU y s , i r._ n a td and tested ,.s. a r •.e - .-ff Y I S s i'� a . a � .: w kCr at 1 9 ° w - 'rt • a$..e€ s e a tle , e e Page 1/4 Report Printed: 12/8/2009 PIONEER Operations Summary Report NATURAL RESOURCES Depth Start Foot/Meters Last Mud Start Date End Dale MKS) (ft) Dens (tbigal) Summary 10/10/2009 10/11/2009 10,061.0 63.00 9.30 Displace 8.9 ppg brine with 9.3 ppg Milling /Drilling fluid. Mill 6 -3/4" window in 7 -5/8" casing (/10,050' 1110,061'. Drill (/10,061' t/10,091'. Perform FIT with 9.3 ppg mud at 5,004 TVD to 12.5 ppg EMW (ISIP 837 psi, FSIP 761 psi after 10 min). Drill (/10,091' 1110,124'. Pump Dry Job while rigging down E -line. POOH f/10,124' 118,494'. Adjust stack and level rig. POOH 1/8,494' t/8,258'. 10/11/2009 10/12/2009 10,124.0 0.00 9.30 POOH (/8,258' t/213'. LD BHA #131198'. Download MWD data. POOH w/ BHA. Flush stack of metal cuttings and junk. PU BHA #14 V96'. Upload MWD program. RIH W/ BH/X #14 t/6,600`. Pulse test MWD, good test. Move pits away from substructure. Reposition substructure over wellhead. 10/12/2009 10/13/2009 10,124.0 282.00 9.30 Reposition pits to mate up to substructure. Finish leveling rig and connect service lines in PUTZ. RU E -line. RIH w/ BHA #141/6,739' 1110,124'. Drill f/10,124' 1110,309'. Gryo on E -line V10,188' (WLM). Drill (/10,309' 1110,406'. Took survey and established that the MWD survey was clear of any magnetic interference. 10/13/2009 10/14/2009 10,406.0 800.00 9.30 Drill 6-3/4" Hole section 1/10,550' 1/11,206'md per WP14 & Well Site Geologists requests. 10/14/2009 10/15/2009 11,206.0 119.00 9.30 Drill f/11,206' V11,325'. Circulate hole clean. POOH 1/11,325' 119,923'. Cut Drilling Line. POOH 1/9,923' 11400'. LD BHA # 14. Test Annular to 250 psi low / 2500 psi high. Test Blind Rams, Upper 2 -7/8" x 5" VBR pipe rams, Lower 4" pipe rams, Kill and Choke line HCR's valves, Kill and Choke line manual valves, Floor Safety, Dart, Upper IBOP and Lower IBOP valves to 250 psi low / 3500 psi high. 14 Choke manifold valves tested while tripping out of hole. All low and high tests held 5 min each and charted. Accumulator test, System Pressure 3000 psi, After Closure 2200 psi, Initial 200 psi recovery 22 sec's, Full recovery 1 min 37 sec's. 5 nitrogen btls at 1,650 psi avg. No failures. AOGCC representative Lou Grimaldi waived witness of BOPE test. 10/15/2009 10/16/2009 11,325.0 0.00 9.30 R1H w/ BHA 415. Shallow pulse test al 381', good pulse. RIH 1 /381' 1/11,100', removed Super Sliders from DP. Washed and reamed down f/11,100' 1/11,325'. CBU. Backreaming and logging up 1/11,325' 1/10,897' at 150 fph. 10/16/2009 10/17/2009 11,325.0 190.00 9.30 Perform Mad Pass 1/10,897' 1/10,200'. RIH 1111,325'. Drill f/11,325' 211,515'. Monitor well - static. POOH w/ BHA #15 f/11,515' 1/7,617'. 10/17/2009 10/18/2009 11,515.0 53.00 9.30 POOH w/ BHA #15. PU BHA 4/16 w/ 6 -1/8" Security FMFX641Z bit and RIH 2381'. Shallow pulse test. RIH f/381' 1/11,325', Ream 1/11,325' 211,515'. Drill 1/11,515' 211,568'- 10/18/2009 10/19/2009 11,568.0 1,042.00 9.30 Drill f /11,568' 1112,610'. 10/19/2009 10/20/2009 12,610.0 1,206.00 9.30 Drill f/12,610' 1/13,818'. 10/20/2009 10/21/2009 13,816.0 1,049.00 9.30 Drill f /13,816' 214,865'. 10/21/2009 10/22/2009 14,865.0 564.00 9.30 Drill f/14,865' 215,429:. Circulate Hole Clean. POOH 1/15,529' t/11,565'.., 10/22/2009 10/23/2009 15,429.0 9.30 POOH f/11,859' 1/11,750'. Attempt to circulate at 11,750' with 55% losses, POOH f/11,750' 211,570'. Establish circulation at 11,570' with 42 gpm and staged up to 200 gpm with 40 -50% initial losses, losses decreased to 20% as we circulated. Backreamed f/11,570' 210,200' for open hole mad pass logs - losses reduced to 8 to 10 bph and then zero. POOH f/10,200' 1/9,930'. Circulate and condition mud 1.5 X BUS Monitor well - static. Pump slug and POOH f/ 9,930' up to the BHA. Lay down BHA tools up to the MWD tools. Plug in and download MWD /LWD data. Page 2/4 Report Printed: 12/7/2009 ' P 10 N E E R •perations Summary Report • NATURAL RESOURCES Depth Start Foot/Meters Last Mud Start Date End Date (h58 (ft) Dens Ib/ ) Summa a ate e ? ) # 9� Summary 10/23/2009 10/24/2009 15,429.0 9.30 Finish laying down BHA. Intel! Test Plua and Test BOPE.Test Annular @ 250/2500 psi for 4" DP.Test Upper Pipe Ram VBR and Lower Pipe Ram @ 250/3500 psi for 4" DP. Test Annular @ 250/2500 psi for 4 -1/2" liner. Test Upper Pipe Ram VBR 250/3500 psi for 4 -1/2" Liner. AOGCC North Slope Field Inspector John Crisp waived witness @ 0855 on 10/22/09. Make up clean out BHA and shallow pulse test same. Slip and cut drill line. TIH 1/325' 1/11,610'. 10/24/2009 10/25/2009 15,429.0 9.55 Wash and ream in the hole 1/11,610' 1/15,429'. Pump 30 bbl N-vis sweep and circulate out same. Back ream out the hole 1/14,529' 1/14,214'. 10/25/2009 10/26/2009 15,429.0 9.40 Backreamed 1/14,200' 1/10,200'. TIH on elevators f/10,200' 1114,311'. Rotate and pump in the hole f/14,311'1/15,429' due to negative slack off wt - no issues. Establish circulation, stage pumps up to 250 gpm and circulate hole clean with 2x O.H. volume while racking back 1 stand every 30 min 1/15,429' 1/15,083'. Rotate and pump in the hole 1/15,083'1/15,429' due to negative slack off wt - no issues. Stage pumps up to 250 gpm and spot 250 bbl liner running pill with polymer breaker across open hole section f/15,429'1/12,264'. POOH 1/15,429' 1/9,969' on elevators - No issues. 10/26/2009 10/27/2009 15,429.0 9.30 Circulate hole clean with 1.5x bottoms up at 9,969'. POOH f/9,969' t/325'. Download MWD data and laydown BHA #17. RU 4,5" casing tools and have PJSM for running liner. MU 4.5" HYD 521 shoe and thread lock same. TM picking up 4,5 ", L -80, 12,6 #, HYD 521 liner as per WFT rep. including 19 pre -perf pup joints and 1 water swell packer from surface 115,508'. PU and MU WFT "PHR" hydraulic setting liner hanger with WFT "TSP" liner top packer and WFT "PBR" tie back sleeve as per WFT rep.f15,508' 1/5,533'. TIH 1/5,679'1/9,343' with 4,5" liner on 4" DP. 10/27/2009 10/28/2009 15,429.0 0.00 9.30 TIH (SLM) 1/9,343' 1/10,018'. Circulate DP and liner capacity down to the first perfs in the liner to flow paths are clear. TIH (SLM) f/10,018'1/14,408'. Rotate in the hole (/14,408' 1/15,529'. Drop 1.75" ball and pump down same with 42 gpm at 650 psi, seat ball with 1700 psi. Set hanger with 35k down, pressure up to 3700 psi to shear ball seat, PU to expose packer setting dogs and set packer with 50k down. Attempt to test packer and casing to 3500 psi - unsuccessful - bled off. Check all surface equipment and retest with same results. Stroke DP to make sure tie back seals are sealing and retest - Good test. Tested casing and liner too Packer to 3500 psi on chart for 30 min. Circulate casing clean with 2x bottoms up. Pump 20 bbl dirt magnet pill followed by 20 bbls hi -vis brine pill and displace the well to 9.3 ppg filtered brine. POOH 1/9,849' 1/9,656'. Change out spools of drill line. Slip and cut 1,500' of drill line. Found twisted drill line on the draw works drum. Slip and cut 22' of drill line to remove twisted drill line. 10/28/2009 10/29/2009 15,429.0 0.00 9.30 Finish cutting drill line and reset C.O.M. POOH laying down 276 Its 4* DP f/9,656' to surface. LD casing scraper, brush and junk basket assembly. Lay down WFT liner running tool. Retrieve wear bushing and Install junk screen, PU 4" clean out tool, function all rams on BOP stack, and flush stack with sea water. Pull junk screen. Change bottom Pipe rams to 4,5" and test same to,,, 250/3,500 for 5 min on chart. AOGCC rep John Crisp waived witness of test on 10/26/09 at 1'4:00 hrs. PU 4.5" tubing hanger, landing joint and RIH with same. Test seals on tubing hanger to 5000 psi for 10 min - Good test, LD hanger and landing joint. RU 4,5" casing equipment, Pick up WFT Tie back seal assembly with locator sub, 1 joint of 4.5" L -80 Hyd 521 tubing and HES ROC gauge carrier. Tie in ROC gauge wire to ROC gauge, run all electrical diagnostics on wire - OK. Test ROC gauge to 10,000 psi for 15 min - Good test. TIH picking up 4.5 ", L -80, 12,6#, HYD 521 liner f/71' t/582'. 10/29/2009 10/30/2009 15,429.0 0.00 9.30 TIH picking UP 4.5 ", L -80. 12.6 #, HYD 521 Tba. 1/582' 1/9.153'. Make up HES SSSV and control line and test same to 5,000 psi for 10 min - Good test. TIH w/ 4.5" Tbg 1/9,153' 1/9,905'. Sting into tie back Sleeve with seal assembly f/9,901'1/9,916' with 15k down on seal assembly - test I.A. to 3,500 psi for 10 min - Good test. Space out, PU and make up 4.5" tubing hanger and landing joint, make penetrations through hanger. Pressure up to 5,000 psi on control line and land hanger with 16k down with seal assembly. Test tubing hanger upper and lower seals to 5,000 psi for 10 min each on chart - Good test. Pressure up on I.A. to 3500 psi to test casing, held 30 min on chart - Good test. Pull landing joint and install BPV. Rig down SSSV control line and ROC gauge wire sheeves and spools. Page 3/4 Report Printed: 12/7/2009 PIONEER operations Summary Report • NATURAL RESOURCES Depth Start Foot/Meters _ Last Mud Start Date End Date (ttKB) (It) Dens (Ib/gai) Summary 10/30/2009 10/31/2009 15,429.0 0.00 9.30 Change out bottom pipe rams from 4.5" to 5 ". ND all BOP equipment. Terminate ROC gauge TEC wire and SSSV control line as per Vetco Gray and HES rep. in M -233 Well Head Penatrators. Test Well seal & void to 5000psi each & chart same for 15 mins (good test). Witness SSSCV tested to 5000psi & needle valve installed (ok). Rig up HES slickline unit and lubricator /BOPS. RIH with 3.83" GR to the top of SVLN 'so Sleeve at 768' wlm. RIH with 4.5" GS and 4.5" RCH -M plug body and set same at 2,098'. RIH with pulling tool and retrieve dummy GLV from GLM #1 at 2,032'. Freeze protect 7 -5/8" x 4 -1/2" annulus. Reverse circulate 60 bbls of corrosion inhibited 9.3 ppg brine followed by 85 bbls of diesel. RIH and set dummy GLV in GLM #1 at 2,032'. RIH with RCH -M plug catcher and pull RHC -M plug from 2,098'. RIH with 4.5" FXE WRSSSV and set same in XXO SVLNat 768', function test valve - ok. RD slickline unit. Install BPV in hanger. Riq Released at 24:00 hrs 10/30/09. Prep rig for rig move from ODSN -45A to ODSK -42i. Page 4/4 Report Printed: 12/7/2009 . Halliburton Company • Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Coordinate Reference: Well ODSN -45A - Slot ODS-45 Pro Ct; Oooguruk Development TVD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Site Oooguruk Drill Site MD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Weft: ODSN -45A North Reference: True Welborn: ODSN -45A SurveyCalculadon Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Project Oooguruk Development 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 I Well ODSN -45A - Slot ODS-45 Well Position +N/-S 0.00 ft Northing: 6,031,005.53 ft Latitude: 70° 29' 44.804 N +E/ -W 0.00 ft Easting: 469,821.86 ft Longitude: 150° 14' 48.349 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 13.50ft Wellborn ODSN -45A Magnetics Model Name Sample Date Declination Dip Angie Field Strength CI C) (nT) IGRF200510 10/2/2009 22.10 80.81 57,749 Design ODSN -45A Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 10,035.40 Vertical Section: Depth From OVD) +N/•S +E! W Direction (ft) (f) (ft) t 42.70 0.00 0.00 290.00 Survey Program Date 11/312009 From To (ft) • (ft) Survey (Wellborn) Tool Name Description Stinfey Date 50.00 533.00 ODSN -45i IN13 PB1 Gyro (ODSN -45i IN SR- Gyro-SS Fixed:v2:surface readout gyro single shot 1/13/2009 1: 533.00 10,035.40 ODSN -45i 1N13 PB1 MWD (ODSN -45i 11' MWD +IFR2 +MS +sag Fixed:v2:IIFR dec & 3-axis correction + sag 1/13/2009 t 10,049.98 10,191.98 ODSN -45A Gyro (ODSN -45A) NS- Gyro -MS Fixed:v2:North- seeking gyro multishot 10/3/2009 1: 10,259.91 15,393.08 ODSN -45A MWD (ODSN -45A) MWD +IFR2 +MS +sag Fixed:v2:IIFR dec & 3-axis correction + sag 10/4/2009 1: Survey , Map Map Vocal MD : Inc Aa:i TVD TVDSS +NPS +EI-W NortMag Easting DM Section (ft) (°) (') (ft) • (ft) (ft) (R) (ft) (ft) moo ) (fly Solvay Toot Name 42.70 0.00 0.00 42.70 -13.50 0.00 0.00 6,031,005.53 469,821.86 0.00 0.00 UNDEFINED 50.00 0.30 141.13 50.00 -6.20 -0.01 0.01 6,031,005.52 469,821.87 4.11 -0.02 SR- Gyro -SS (1) 100.00 0.30 191.03 100.00 43.80 -0.25 0.07 6,031,005.28 469,821.93 0.51 -0.15 SR-Gyro-SS (1) 168.00 0.50 165.94 168.00 111.80 -0.71 0.11 6,031,004.82 469,821.96 0.38 -0.34 SR-Gyro-SS (1) 197.00 0.48 148.51 197.00 140.80 -0.93 0.20 6,031,004.60 469,822.06 0.52 -0.51 SR-Gyro-SS (1) 228.00 0.59 198.76 228.00 171.80 -1.20 0.22 6,031,004.33 469,822.07 1.50 -0.61 SR-Gyro-SS (1) 258.00 0.58 166.67 257.99 201.79 -1.49 0.20 6,031,004.04 469,822.06 1.08 -0.70 SR- Gyro-SS(1) 288.00 0.68 167.36 287.99 231.79 -1.81 0.28 6,031,003.72 469,822.13 0.33 -0.88 SR- Gyro -SS (1) 321.00 0.98 173.11 320.99 264.79 -2.28 0.35 6,031,003.25 469,822.20 0.94 -1.11 SR-Gyro-SS (1) 351.00 1.08 175.74 350.98 294.78 -2.82 0.41 6,031,002.71 469,822.25 0.37 -1.35 SR (1) 382.00 1.32 178.28 381.98 325.78 -3.47 0.44 6,031,002.06 469,822.28 0.79 -1.60 SR-Gyro-SS (1) 11/3/2009 2 :48:59PM Page 2 COMPASS 2003.16 Build 71 0 Halliburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Coordinate Reference: Well ODSN -45A - Slot ODS-45 Pte: Oooguruk Development TVD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Ste: Oooguruk Drill Site MD Reference: - 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Wet: ODSN -45A North Reference: True Wetbore: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical MD inc Ara TVD TVDSS +Nil - +E! W Northing ' Ming OLS Section ' () (°) (°) (ft) (ft) (ft) (ft) (ft) (ft) ( °0100' (ft) Survey Tool Name 413.00 1.75 179.15 412.96 356.77 -4.30 0.46 6,031,001.23 469,822.30 1.39 -1.90 SR- Gyro-SS (1) 443.00 2.13 178.74 442.95 386.75 -5.31 0.47 6,031,000.22 469,822.31 1.27 -2.26 SR- Gyro-SS (1) 533.00 2.88 180.19 532.86 476.66 -9.25 0.50 6,030,996.28 469,822.33 0.84 -3.64 SR- Gyro -SS (1) 575.40 2.94 174.16 575.21 519.01 -11.39 0.61 6,030,994.14 469,822.42 0.74 -4.47 MWD +IFR2 +MS +sag (2) 670.40 3.91 162.96 670.04 613.84 -16.91 1.81 6,030,988.61 469,823.60 1.24 -7.48 MWD +IFR2 +MS +sag (2) 764.70 5.03 162.67 764.05 707.85 -23.93 3.98 6,030,981.58 469,825.74 1.19 -11.93 MWD+IFR2+MS+sag {2) 859.30 5.77 161.44 858.23 802.03 -32.40 6.73 6,030,973.10 469,828.46 0.79 -17.41 MWD +IFR2 +MS +sag (2) 954.90 5.70 160.56 953.35 897.15 -41.43 9.84 6,030,964.06 469,831.53 0.12 -23.42 MWD +IFR2 +MS +sag (2) 1,049.20 7.62 163.09 1,047.01 990.81 -51.83 13.22 6,030,953.65 469,834.87 2.06 -30.15 MWD +IFR2 +MS +sag (2) 1,143.50 8.56 164.80 1,140.37 1,084.17 -64.59 16.88 6,030,940.88 469,838.47 1.03 -37.95 MWD+IFR2 +MS +sag (2) 1,238.70 9.80 165.71 1,234.35 1,178.15 - 79.28 20.73 6,030,926.18 469,842.27 1.31 -46.60 MWD +IFR2 +MS +sag (2) 1,334.70 11.30 167.74 1,328.72 1,272.52 -96.39 24.75 6,030,909.05 469,846.21 1.61 -56.22 MWD +IFR2 +MS +sag (2) 1,428.60 13.21 170.21 1,420.48 1,364.28 - 115.95 28.53 6,030,889.48 469,849.91 2.11 -66.46 MWD +1FR2 +MS +sag (2) 1,523.55 12.76 171.01 1,513.00 1,456.80 - 137.00 32.01 6,030,868.42 469,853.31 0.51 -76.94 MWD +1FR2 +MS+sag (2) 1,618.50 13.98 172.54 1,605.37 1,549.17 - 158.73 35.14 6,030,846.68 469,856.35 1.34 -87.31 MWD +IFR2 +MS +sag (2) 1,712.90 14.83 172.59 1,696.81 1,640.61 - 182.01 38.18 6,030,823.38 469,859.29 0.90 -98.13 MWD +IFR2 +MS +sag (2) 1,808.20 16.36 172.06 1,788.59 1,732.39 - 207.40 41.60 6,030,797.98 469,862.62 1.61 - 110.03 MWD +1FR2 +MS +sag (2) 1,902.60 18.07 178.03 1,878.77 1,822.57 - 235.21 43.94 6,030,770.17 469,864.84 2.60 - 121.74 MWD +IFR2 +MS +sag (2) 1,999.40 21.10 181.35 1,969.96 1,913.76 - 267.64 44.05 6,030,737.74 469,864.82 3.33 - 132.93 MWD +IFR2 +MS +sag (2) 2,093.80 24.37 188.46 2,057.03 2,000.83 - 303.91 40.78 6,030,701.49 469,861.40 4.52 - 142.26 MWD +IFR2 +MS +sag (2) 2,187.50 25.30 191.15 2,142.07 2,085.87 - 342.67 34.07 6,030,662.76 469,854.53 1.56 - 149.21 MWD +IFR2 +MS +sag(2) 2,282.30 28.06 195.13 2,226.77 2,170.57 - 384.08 24.33 6,030,621.39 469,844.62 3.47 - 154.22 MWD +IFR2 +MS +sag (2) 2,326.00 29.70 195.74 2,265.04 2,208.84 - 404.43 18.71 6,030,601.07 469,838.92 3.81 - 155.90 MWD+IFR2 +MS +sag (2) 2,377.20 32.48 198.82 2,308.88 2,252.68 - 429.65 10.83 6,030,575.88 469,830.94 6.25 - 157.13 MWD +IFR2 +MS +sag (2) 2,424.00 34.60 199.84 2,347.89 2,291.69 - 454.05 2.26 6,030,551.52 469,822.28 4.69 - 157.42 MWD +IFR2 +MS +sag {2) 2,472.50 36.16 200.43 2,387.43 2,331.23 - 480.41 -7.40 6,030,525.20 469,812.51 3.29 - 157.35 MWD +IFR2 +MS +sag (2) 2,566.59 39.82 202.47 2,461.58 2,405.38 - 534.29 -28.62 6,030,471.41 469,791.08 4.11 - 155.85 MWD +1FR2 +MS +sag (2) 2,659.39 43.52 202.62 2,530.89 2,474.69 - 591.26 -52.27 6,030,414.55 469,767.19 3.99 - 153.10 MWD +IFR2 +MS +sag {2) 2,698.99 44.79 203.91 2,559.30 2,503.10 -616.60 -63.17 6,030,389.25 469,756.19 3.93 -15153 MWD +IFR2 +MS+sag42) 2,752.29 48.34 205.85 2,595.94 2,539.74 - 651.69 -79.47 6,030,354.23 469,739.76 7.17 - 148.22 MWD+IFR2 +MS +sag (2) 2,805.09 49.84 207.14 2,630.52 2,574.32 -687.40 -97.27 6,030,318.60 469,721.81 3.39 - 143.70 MWD +IFR2 +MS +sag (2) 2,848.99 51.64 207.46 2,658.30 2,602.10 - 717.61 - 112.86 6,030,288.46 469,706.10 4.14 - 139.38 MWD +IFR2 +MS +sag (2) 2,943.19 53.16 207.96 2,715.77 2,659.57 - 783.68 - 147.57 6,030,222.54 469,671.13 1.67 - 129.36 MWD +IFR2 +MS+sag (2) 3,040.19 55.15 209.57 2,772.57 2,716.37 - 852.59 - 185.41 6,030,153.79 469,633.00 2.45 - 117.37 MWD +IFR2 +MS +sag (2) 3,133.79 57.80 210.63 2,824.27 2,768.07 - 920.08 - 224.55 6,030,086.46 469,593.60 2.98 - 103.68 MWD +IFR2 +MS +sag (2) 3,229.59 59.33 210.06 2,874.23 2,818.03 - 990.62 - 265.84 6,030,016.09 469,552.02 1.68 -89.00 MWD +IFR2 +MS +sag (2) 3,323.39 61.07 209.65 2,920.84 2,864.64 - 1,061.21 - 306.36 6,029,945.67 469,511.23 1.89 -75.07 MWD+IFR2 +MS +sag (2) 3,417.39 64.24 210.67 2,964.02 2,907.82 - 1,133.39 - 348.31 6,029,873.68 469,468.99 3.51 -60.34 MWD+IFR2 +MS +sag (2) 3,465.29 65.89 210.86 2,984.21 2,928.01 - 1,170.71 - 370.53 6,029,836.45 469,446.62 3.46 -52.22 MWD+IFR2 +MS +sag (2) 3,512.29 69.49 210.64 3,002.05 2,945.85 - 1,208.07 - 392.76 6,029,799.18 469,424.24 7.67 -44.12 MWD +IFR2 +MS +sag (2) 11/3/2009 2 :48 :59PM Page 3 COMPASS 2003.16 Build 71 • Hailiburton Company • Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Coordinate Reference: Well ODSN -45A - Slot ODS-45 Project Oooguruk Development TVD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: + 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference: True Wel)hare: ODSN -45A Survey Cakuladon Method: Minimum Curvature ODSN -45A EDM 2003.16 Single Database: le User Db 9 Survey Map Map Vertical MO Inc Azi TVD TVDSS +N!-S +E1 W Northing Easting DLS Section (ft). ( ( (ft) (ft) ( (ft) (ft] (ft) riioo (ft) Survey Tool Name 3,559.99 71.29 209.81 3,018.06 2,961.86 - 1,246.90 - 415.37 6,029,760.45 469,401.47 4.11 -36.14 MWD+IFR2 +MS +sag (2) 3,607.69 73.43 210.51 3,032.51 2,976.31 - 1,286.20 - 438.21 6,029,721.25 469,378.48 4.70 -28.12 MWD +IFR2 +M$ +sag (2) 3,700.79 73.49 209.15 3,059.02 3,002.82 - 1,363.62 - 482.60 6,029,644.02 469,333.77 1.40 -12.89 MWD +IFR2 +MS +sag (2) 3,797.59 75.67 213.26 3,084.76 3,028.56 - 1,443.40 - 530.95 6,029,564.44 469,285.11 4.67 5.26 MWD +IFR2 +MS +sag (2) 3,892.09 75.67 212.88 3,108.15 3,051.95 - 1,520.13 - 580.91 6,029,487.92 469,234.84 0.39 25.96 MWD +IFR2 +MS +sag(2) 3,986.89 74.92 215.00 3,132.22 3,076.02 - 1,596.19 - 632.10 6,029,412.07 469,183.35 2.30 48.05 MWD +IFR2 +MS +sag(2) 4,081.09 74.82 216.86 3,156.81 3,100.61 - 1,669.82 - 685.46 6,029,338.67 469,129.70 1.91 73.01 MWD+IFR2 +MS +sag (2) 4,175.99 73.20 216.32 3,182.95 3,126.75 - 1,743.07 - 739.84 6,029,265.65 469,075.03 1.79 99.05 MWD +IFR2 +MS +sag(2) 4,268.49 72.50 218.38 3,210.23 3,154.03 - 1,813.33 - 793.45 6,029,195.62 469,021.13 2.26 125.41 MWD+IFR2 +MS +sag (2) 4,365.09 71.06 219.72 3,240.43 3,184.23 - 1,884.59 - 851.25 6,029,124.60 468,963.05 1.99 155.35 MWD +IFR2 +MS +sag (2) 4,458.59 70.94 218.34 3,270.87 3,214.67 - 1,953.26 - 906.92 6,029,056.16 468,907.10 1.40 184.18 MWD +IFR2 +MS +sag (2) 4,554.79 70.77 219.77 3,302.43 3,246.23 - 2,023.83 - 964.18 6,028,985.83 468,849.57 1.42 213.84 MWD +IFR2 +MS +sag (2) 4,648.49 71.10 218.30 3,333.03 3,276.83 - 2,092.62 - 1,019.95 6,028,917.28 468,793.52 1.52 242.73 MWD +IFR2 +MS +sag (2) 4,744.59 71.00 217.70 3,364.24 3,308.04 - 2,164.24 - 1,075.91 6,028,845.89 468,737.28 0.60 270.81 MWD +IFR2 +MS +sag (2) 4,839.59 70.69 218.10 3,395.41 3,339.21 - 2,235.05 - 1,131.04 6,028,775.31 468,681.87 0.51 298.39 MWD +IFR2 +MS +sag (2) 4,931.39 71.44 218.07 3,425.20 3,369.00 - 2,303.40 - 1,184.60 6,028,707.19 468,628.04 0.82 325.35 MWD +IFR2 +MS +sag (2) 5,012.77 71.57 218.31 3,451.02 3,394.82 - 2,364.05 - 1,232.31 6,028,646.73 468,580.08 0.32 349.44 MWD +IFR2 +MS +sag (2) 5,105.27 70.97 217.33 3,480.72 3,424.52 - 2,433.25 - 1,286.03 6,028,577.76 468,526.09 1.19 376.25 MWD +IFR2 +MS +sag (2) 5,202.47 70.78 216.37 3,512.57 3,456.37 - 2,506.74 - 1,341.10 6,028,504.50 468,470.72 0.95 402.87 MWD+IFR2 +MS +sag (2) 5,292.26 71.43 216.16 3,541.64 3,485.44 - 2,575.23 - 1,391.35 6,028,436.22 468,42020 0.76 426.66 MWD +IFR2 +MS +sag (2) 5,393.87 72.60 214.62 3,573.02 3,516.82 - 2,654.02 - 1,447.32 6,028,357.67 468,363.92 1.84 452.31 MWD +IFR2 +MS +sag (2) 5,489.91 72.80 213.99 3,601.58 3,545.38 - 2,729.76 - 1,499.00 6,028,282.14 468,311.94 0.66 474.96 MWD +IFR2 +MS +sag (2) 5,577.52 72.79 214.00 3,627.49 3,571.29 - 2,799.15 - 1,545.79 6,028,212.96 468,264.87 0.02 495.20 MWD +IFR2 +MS +sag (2) 5,673.74 72.92 213.93 3,655.86 3,599.66 - 2,875.41 - 1,597.16 6,028,136.92 468,213.20 0.15 517.39 MWD+IFR2 +MS +sag (2) 5,773.16 72.72 211.84 3,685.23 3,629.03 - 2,955.16 - 1,648.73 6,028,057.38 468,161.31 2.02 538.57 MWD +IFR2 +MS +sag (2) 5,868.29 72.53 210.72 3,713.63 3,657.43 - 3,032.75 - 1,695.87 6,027,979.99 468,113.87 1.14 556.33 MWD +IFR2 +MS +sag (2) 5,962.54 72.20 211.00 3,742.19 3,685.99 - 3,109.86 - 1,741.94 6,027,903.08 468,067.48 0.45 573.25 MWD +IFR2 +MS +sag (2) 6,057.34 72.53 212.72 3,770.91 3,714.71 - 3,186.59 - 1,789.62 6,027,826.55 468,019.49 1.76 591.82 MWD +IFR2 +MS +sag (2) 6,151.53 72.92 211.27 3,798.88 3,742.68 - 3,262.86 - 1,837.28 6,027,750.47 467,971.53 1.53 610.51 MWD+IFR2 +MS +sag (2) 6,247.50 72.48 21127 3,827.42 3,771.22 - 3,341.18 - 1,884.84 6,027,672.36 467,923.66 0.46 628.42 MWD+IFR2 +MS +sag (2) 6,340.48 7226 212.99 3,855.58 3,799.38 - 3,416.22 - 1,931.96 6,027,597.52 467,876.24 1.78 647.04 MWD +IF122 +MS +sag (2) 6,434.78 72.46 211.57 3,884.16 3,827.96 - 3,492.19 - 1,979.96 6,027,521.75 467,827.94 1.45 666.15 MW0+1FR2 +MS +sag (2) 6,529.17 72.54 211.31 3,912.54 3,856.34 - 3,569.00 - 2,026.91 6,027,445.14 467,780.68 0.28 684.00 MWD+IFR2 +MS +sag (2) 6,623.98 72.35 212.08 3,941.14 3,884.94 - 3,645.91 - 2,074.40 6,027,368.43 467,732.88 0.80 702.33 MWD +IFR2 +MS +sag4(2) 6,720.34 71.83 213.74 3,970.78 3,914.58 - 3,722.88 - 2,12422 6,027,291.67 467,682.76 1.73 722.81 MWD +IFR2 +MS +sag (2) 6,814.39 71.76 214.87 4,000.16 3,943.96 - 3,796.68 - 2,174.57 6,027,218.08 467,632.11 1.14 744.88 MWD +1FR2 +MS +sag (2) 6,908.91 71.70 215.49 4,029.79 3,973.59 - 3,870.05 - 2,226.28 6,027,144.94 467,580.11 0.63 768.39 MWD +IFR2 +MS +sag (2) 7,004.56 71.68 215.84 4,059.84 4,003.64 - 3,943.82 - 2,279.22 6,027,071.38 467,526.87 0.35 792.90 MWD +IFR2 +MS +sag (2) 7,100.29 72.01 215.80 4,089.67 4,033.47 - 4,017.58 - 2,332.46 6,026,997.85 467,473.34 0.35 817.70 MWD +IFR2 +MS +sag (2) 7,193.34 72.53 215.54 4,118.01 4,061.81 - 4,089.58 - 2,384.14 6,026,926.07 467,421.37 0.62 841.64 MWD +IFR2 +MS +sag (2) 11/3/2009 2 :48 :59PM Page 4 COMPASS 2003.16 Build 71 • Halliburton Company • Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Coordinate Reference: Well ODSN -45A - Slot ODS-45 Project Oooguruk Development TVD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference: True Wellore: ODSN -45A SurveyCafculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical MD inc Azi TVD TVDSS +N!-S +Ei W Northing Fasting DLS Section (ft) t l ift) (ft) (ft) (ft) (ft) (ft) {°1100') (ft) Survey Tool Name 7,288.68 72.40 215.89 4,146.73 4,090.53 - 4,163.39 - 2,437.21 6,026,852.48 467,368.01 0.38 866.26 MWD +IFR2 +MS +sag(2) 7,382.88 72.80 215.45 4,174.90 4,118.70 - 4,236.42 - 2,489.63 6,026,779.67 467,315.30 0.62 890.54 MWD +IFR2 +MS +sag(2) 7,477.84 72.16 214.78 4,203.49 4,147.29 - 4,310.49 - 2,541.71 6,026,705.82 467,262.92 0.95 914.16 MWD +IFR2 +MS +sag (2) 7,572.90 71.77 214.65 4,232.92 4,176.72 - 4,384.80 - 2,593.20 6,026,631.73 467,211.14 0.43 937.12 MWD +IFR2 +MS +sag(2) 7,667.48 71.96 215.11 4,262.36 4,206.16 - 4,458.53 - 2,644.60 6,026,558.21 467,159.45 0.50 960.20 MWD +IFR2 +MS +sag (2) 7,758.38 72.02 214.91 4,290.46 4,234.26 - 4,529.34 - 2,694.19 6,026,487.62 467,109.57 0.22 982.59 MWD+IFR2 +MS +sag (2) 7,857.09 72.14 214.91 4,320.84 4,264.64 - 4,606.36 - 2,747.94 6,026,410.82 467,055.51 0.12 1,006.75 MWD +IFR2 +MS +sag (2) 7,951.52 72.13 214.87 4,349.80 4,293.60 -4,680.08 - 2,799.35 6,026,337.32 467,003.81 0.04 1,029.85 MWD +IFR2 +MS +sag (2) 8,047.26 72.73 214.89 4,378.70 4,322.50 - 4,754.95 - 2,851.55 6,026,262.66 466,951.32 0.63 1,053.29 MWD +IFR2 +MS +sag (2) 8,142.02 72.86 213.92 4,406.73 4,350.53 - 4,829.64 - 2,902.69 6,026,188.19 466,899.87 0.99 1,075.81 MWD +IFR2 +MS +sag(2) 8,235.56 72.73 214.08 4,434.40 4,378.20 - 4,903.71 - 2,952.66 6,026,114.33 466,849.61 0.21 1,097.42 MWD +IFR2 +MS +sag (2) 8,330.90 72.86 213.75 4,462.60 4,406.40 - 4,979.29 - 3,003.47 6,026,038.96 466,798.50 0.36 1,119.32 MWD +IFR2 +MS +sag (2) 8,425.38 72.21 213.89 4,490.96 4,434.76 - 5,054.17 - 3,053.64 6,025,964.30 466,748.04 0.70 1,140.85 MWD +IFR2 +MS +sag (2) 8,520.57 71.03 214.65 4,520.97 4,464.77 - 5,128.82 - 3,104.50 6,025,889.86 466,696.87 1.45 1,163.12 MWD +IFR2 +MS +sag (2) 8,614.82 70.45 215.43 4,552.06 4,495.86 - 5,201.67 - 3,155.58 6,025,817.23 466,645.50 0.99 1,186.20 MWD +1FR2 +MS +sag(2) 8,707.23 70.97 215.11 4,582.59 4,526.39 - 5,272.88 - 3,205.95 6,025,746.23 466,594.85 0.65 1,209.17 MWD +IFR2 +MS+sag (2) 8,802.23 71.56 214.91 4,613.10 4,556.90 - 5,346.56 - 3,257.56 6,025,672.76 466,542.94 0.65 1,232.47 MWD +IFR2 +MS+sag (2) 8,897.27 71.76 215.01 4,643.01 4,586.81 - 5,420.50 - 3,309.25 6,025,599.05 466,490.96 0.23 1,255.76 MWD +IFR2 +MS +sag (2) 8,992.31 71.70 215.37 4,672.80 4,616.60 - 5,494.25 - 3,361.26 6,025,525.51 466,438.65 0.37 1,279.41 MWD +IFR2 +MS +sag (2) 9,087.70 72.40 214.07 4,702.20 4,646.00 - 5,568.84 - 3,412.95 6,025,451.14 466,386.67 1.49 1,302.46 MWD +IFR2 +MS +sag (2) 9,182.27 72.66 214.32 4,730.59 4,674.39 - 5,643.45 - 3,463.64 6,025,376.74 466,335.68 0.37 1,324.58 MWD +IFR2 +MS+sag (2) 9,276.95 72.27 212.54 4,759.12 4,702.92 - 5,718.79 - 3,513.38 6,025,301.61 466,285.64 1.84 1,345.55 MWD +1FR2 +MS +sag (2) 9,371.44 71.83 212.53 4,788.24 4,732.04 - 5,794.58 - 3,561.72 6,025,226.03 466,237.00 0.47 1,365.06 MWD+IFR2 +MS +sag (2) 9,466.39 71.88 213.38 4,817.81 4,761.61 - 5,870.29 - 3,610.81 6,025,150.53 466,187.61 0.85 1,385.29 MWD+IFR2 +MS +sag (2) 9,561.41 71.43 216.75 4,847.72 4,791.52 - 5,944.10 - 3,662.61 6,025,076.94 466,135.52 3.40 1,408.73 MWD +IFR2 +MS +sag (2) 9,656.14 70.96 220.58 4,878.27 4,822.07 - 6,014.10 - 3,718.62 6,025,007.17 466,079.23 3.86 1,437.41 MWD +IFR2 +MS +sag (2) 9,750.60 72.00 222.51 4,908.28 4,852.08 - 6,081.13 - 3,778.02 6,024,940.39 466,019.56 2.23 1,470.31 MWD+IFR2 +MS +sag (2) 9,845.48 72.39 225.50 4,937.29 4,881.10 - 6,146.09 - 3,840.77 6,024,875.69 465,956.55 3.03 1,507.05 MWD +IFR2 +MS +sag(2) 9,940.31 72.08 228.44 4,966.23 4,910.03 - 6,207.71 - 3,906.77 6,024,814.34 465,890.31 2.97 1,548.00 MWD+IFR2 +MS +sag (2) 10,035.40 70.98 231.76 4,996.37 4,940.17 - 6,265.56 - 3,975.95 6,024,756.78 465,820.90 3.51 1,593.22 MWD +IFR2 +MS+sag(2) 10,049.98 70.97 232.37 5,001.12 4,944.92 -6,274.04 - 3,986.82 6,024,748.35 465,810.00 3.96 1,600.54 NS- Gyro -MS (3) 10,104.98 84.74 237.65 5,012.67 4,956.47 - 6,304.73 - 4,030.78 6,024,717.84 465,765.92 26.73 1,631.35 NS-Gyro -MS (3) 10,191.98 84.62 241.67 5,020.74 4,964.54 - 6,348.48 - 4,105.53 6,024,674.40 465,691.00 4.60 1,686.63 NS- Gyro -MS (3) 10,259.91 84.25 246.20 5,027.33 4,971.13 - 6,378.18 - 4,166.25 6,024,644.95 465,630.17 6.66 1,733.53 MWD +IFR2 +MS +sag(4) 10,306.57 83.51 248.83 5,032.31 4,976.11 - 6,395.92 - 4,209.11 6,024,627.38 465,587.24 5.82 1,767.73 MWD +IFR2 +MS+sag (4) 10,356.69 82.24 252.28 5,038.53 4,982.33 - 6,412.47 - 4,256.00 6,024,611.02 465,540.29 7.29 1,806.13 MWD +IFR2 +MS +sag (4) 10,402.89 80.50 256.64 5,045.46 4,989.26 - 6,424.71 - 4,299.99 6,024,598.96 465,496.25 10.06 1,84329 MWD +IFR2 +MS +sag(4) 10,452.16 79.12 261.21 5,054.18 4,997.98 - 6,434.03 - 4,347.56 6,024,589.84 465,448.64 9.55 1,884.81 MWD +IFR2 +MS +sag (4) 10,499.52 78.81 264.76 5,063.25 5,007.05 - 6,439.71 - 4,393.69 6,024,584.35 465,402.50 7.39 1,926.21 MWD +IFR2 +MS +sag (4) 10,549.42 79.15 268.20 5,072.79 5,016.59 - 6,442.71 - 4,442.57 6,024,581.54 465,353.61 6.80 1,971.11 MWD +IFR2 +MS +sag (4) 11/3/2009 2 :48 :59PM Page 5 COMPASS 2003.16 Build 71 • Halliburton Company Definitive Survey Report • • • • „ *00 ••• „ Company: Well Planning - Pioneer - Oooguruk Local Coordinate Reference: Well ODSN -45A - Slot ODS-45 Project Oooguruk Development TVD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Wet ODSN -45A North Reference: True Welibore: ODSN -45A SurreyCakulation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical MD Inc Azt TVD ' VDSS +NI-S +Ei W Northing Easting DLS Section {ft) 4") {7 (ft) 41t) (ft) - (ft) (ft) (ft) moo') (tt) Surrey tool ;Name 10,596.90 79.90 271.70 5,081.43 5,025.23 - 6,442.75 - 4,489.25 6,024,581.69 465,306.94 7.42 2,014.97 MWD +IFR2 +MS +sag (4) 10,646.00 80.10 275.72 5,089.95 5,033.75 - 6,439.62 - 4,537.49 6,024,585.02 465,258.71 8.07 2,061.37 MWD+IFR2 +Iv4S +sag (4) 10,692.11 79.72 278.83 5.098.03 5,041.83 - 6,433.87 - 4,582.52 6,024,590.95 465,213.71 6.69 2,105.64 MWD +IFR2 +MS +sag (4) 10,741.83 79.16 282.40 5,107.15 5,050.95 - 6,424.87 - 4,630.55 6,024,600.14 465,165.72 7.15 2,153.86 MWD +IFR2 +MS +sag (4) 10,838.48 79.83 288.06 5,124.78 5,068.58 - 6,399.92 - 4,722.20 6,024,625.47 465,074.18 5.80 2,248.52 MWD +IFR2 +MS +sag (4) 10,935.46 82.65 293.08 5,139.56 5,083.36 - 6,366.24 - 4,811.90 6,024,659.51 464,984.64 5.88 2,344.32 MWD +IFR2 +MS +sag (4) 11,032.19 84.12 298.09 5,150.71 5,094.51 - 6,324.75 - 4,898.53 6,024,701.34 464,898.18 5.36 2,439.92 MWD +IFR2 +MS +sag (4) 11,127.72 85.25 304.59 5,159.57 5,103.37 - 6,275.30 - 4,979.72 6,024,751.11 464,817.20 6.88 2,533.12 MWD +IFR2 +MS +sag (4) 11,224.34 85.01 312.68 5,167.79 5,111.59 - 6,215.25 - 5,054.86 6,024,811.47 464,742.31 8.35 2,624.27 MWD +IFR2 +MS +sag {4) 11,275.22 86.50 316.47 5,171.55 5,115.35 - 6,179.64 - 5,090.99 6,024,847.22 464,706.33 7.98 2,670.41 MWD +IFR2 +MS +sag (4) 11,344.46 90.00 318.36 5,173.67 5,117.47 - 6,128.70 - 5,137.81 6,024,898.35 464,659.72 5.74 2,731.83 MWD +IFR2 +MS +sag (4) 11,440.98 91.24 320.71 5,172.62 5,116.42 - 6,055.28 - 5,200.44 6,024,972.01 464,597.39 2.75 2,815.79 MWD +IFR2 +MS +sag (4) 11,478.97 91.23 320.47 5,171.80 5,115.60 - 6,025.93 - 5,224.56 6,025,001.45 464,573.40 0.63 2,848.49 MWD+IFR2 +MS +sag (4) 11,532.05 91.17 317.88 5,170.69 5,114.49 - 5,985.78 - 5,259.25 6,025,041.74 464,538.88 4.88 2,894.82 MWD+IFR2 +MS +gag (4) 11,630.25 90.49 320.13 5,169.27 5,113.07 - 5,911.67 - 5,323.66 6,025,116.10 464,474.78 2.39 2,980.69 MWD+ IF R2+MS+sag (4) 11,726.86 89.75 320.30 5,169.07 5,112.87 - 5,837.43 - 5,385.48 6,025,190.58 464,413.27 0.79 3,064.17 MWD +IFR2 +MS +sag (4) 11,823.02 90.56 320.56 5,168.81 5,112.61 - 5,763.31 - 5,446.73 6,025,264.95 464,352.32 0.88 3,147.09 MWD +IFR2 +MS +sag (4) 11,920.83 88.76 320.36 5,169.39 5,113.19 - 5,687.88 - 5,508.99 6,025,340.62 464,290.37 1.85 3,231.39 MWD +IFR2 +MS +sag(4) 12,016.50 89.38 321.88 5,170.94 5,114.74 - 5,613.42 - 5,569.04 6,025,415.32 464,230.63 1.72 3,313.28 MWD +IFR2 +MS +sag (4) 12,113.06 90.19 323.01 5,171.30 5,115.10 - 5,536.87 - 5,627.89 6,025,492.09 464,172.10 1.44 3,394.76 MWD+ IF R2+MS+sag (4) 12,209.55 90.62 322.25 5,170.62 5,114.42 - 5,460.19 - 5,686.45 6,025,569.01 464,113.85 0.90 3,476.02 MWD +IFR2 +MS +sag (4) 12,304.26 93.77 320.94 5,166.99 5,110.79 - 5,386.04 - 5,745.24 6,025,643.39 464,055.38 3.60 3,556.62 MWD +IFR2 +MS +sag (4) 12,401.69 95.69 320.55 5,158.96 5,102.76 - 5,310.86 - 5,806.67 6,025,718.81 463,994.25 2.01 3,640.07 MWD+IFR2 +MS +sag (4) 12,498.15 95.43 319.48 5,149.61 5,093.41 - 5,237.30 - 5,868.36 6,025,792.62 463,932.86 1.14 3,723.20 MWD+1FR2 +MS +sag (4) 12,594.55 95.44 320.11 5,140.48 5,084.28 - 5,164.00 - 5,930.32 6,025,866.16 463,871.21 0.65 3,806.49 MWD +IFR2 +MS +sag (4) 12,691.27 95.12 319.87 5,131.58 5,075.38 - 5,090.23 - 5,992.24 6,025,940.17 463,809.60 0.41 3,889.90 MWD+IFR2 +MS +sag (4) 12,788.04 95.87 320.32 5,122.32 5,066.12 - 5,016.34 - 6,054.03 6,026,014.30 463,748.11 0.90 3,973.24 MWD +IFR2 +MS +sag (4) 12,884.40 95.55 320.07 5,112.73 5,056.53 -4,942.68 - 6,115.41 6,026,088.20 463,687.04 0.42 4,056.11 MWD+IFR2 +MS +sag (4) 12,980.93 94.94 320.09 5,103.90 5,047.70 - 4,868.96 - 6,177.10 6,026,162.17 463,625.66 0.63 4,139.29 MWD +IFR2 +MS +sag (4) 13,080.50 95.69 321.17 5,094.68 5,038.48 - 4,792.32 - 6,239.99 6,026,239.06 463,563.09 1.32 4,224.60 MWD +IFR2 +MS +sag (4) 13,173.65 94.63 320.42 5,086.30 5,030.10 - 4,720.43 - 6,298.63 6,026,311.17 463,504.75 1.39 4,304.29 MWD+IFR2 +MS +sag (4) 13,271.18 95.19 321.05 5,077.96 5,021.76 - 4,645.20 - 6,360.13 6,026,386.65 463,443.56 0.86 4,387.81 MWD+1FR2 +MS +sag (4) 13,367.56 94.93 320.41 5,069.45 5,013.25 -4,570.87 - 6,420.89 6,026,461.21 463,383.10 0.71 4,470.34 MWD+IFR2+MS+sag (4) 13,463.74 94.14 318.43 5,061.85 5,005.65 - 4,498.06 - 6,483.26 6,026,534.27 463,321.03 2.21 4,553.85 MWD +IFR2 +MS +sag (4) 13,560.24 95.25 317.88 5,053.95 4,997.75 - 4,426.41 - 6,547.42 6,026,606.17 463,257.17 1.28 4,638.64 MWD+IFR2 +MS +sag (4) 13,657.42 95.43 318.94 5,044.91 4,988.71 - 4,354.05 - 6,611.65 6,026,678.79 463,193.25 1.10 4,723.74 MWD+IFR2 +MS +sag (4) 13,753.72 96.24 318.56 5,035.12 4,978.92 - 4,282.02 - 6,674.81 6,026,751.06 463,130.38 0.93 4,807.73 MWD+IFR2 +MS +sag (4) 13,848.13 94.44 319.00 5,026.33 4,970.13 - 4,211.32 - 6,736.75 6,026,822.01 463,068.74 1.96 4,890.12 MWD +IFR2 +MS +sag (4) 13,945.88 93.46 319.70 5,019.60 4,963.40 - 4,137.33 - 6,800.28 6,026,896.24 463,005.52 1.23 4,975.12 MWD+IFR2 +MS +sag (4) 14,042.44 90.24 319.55 5,016.48 4,960.28 - 4,063.82 - 6,862.79 6,026,970.00 462,943.31 3.34 5,059.00 MWD+IFR2 +MS+sag (4) 11/3/2009 2 :48 :59PM Page 6 COMPASS 2003.16 Build 71 Halliburton Company • Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference Well ODSN -45A - Slot ODS-45 Project: Oooguruk Development TVD Reference: 42.7 + 13.5 @ 56.20ft (Nabors 19 AC) Sit*: Oooguruk Drill Site MD Reference: • 42.7 + 13.5 @ 56.20ft (Nabors 19 AC) 'WeN: ODSN -45A North Reference: True We re: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical MD Inc Azi TVD TVOSS +N!-S +EI-W Northing Easting DLS Section (ft) t ° ) (1 Cb) ( (ft) ( t (1» ( °31000 (ft) Survey Tool Name 14,138.64 90.56 319.39 5,015.81 4,959.61 - 3,990.70 - 6,925.30 6,027,043. 462,881.10 0.37 5,142.75 MWD +IFR2 +MS +sag (4) 14,235.40 90.25 319.05 5,015.12 4,958.92 - 3,917.44 - 6,988.50 6,027,116.88 462,818.21 0.48 5,227.20 MWD +IFR2 +MS +sag {4) 14,331.88 91.49 319.22 5,013.66 4,957.46 - 3,844.48 - 7,051.61 6,027,190.08 462,755.40 1.30 5,311.46 MWD +IFR2 +MS +sag (4) 14,428.93 92.23 319.66 5,010.51 4,954.31 - 3,770.79 - 7,114.68 6,027,264.02 462,692.63 0.89 5,395.93 MWD +IFR2 +MS +sag (4) 14,525.20 92.10 319.53 5,006.87 4,950.67 - 3,697.54 - 7,177.04 6,027,337.52 462,630.58 0.19 5,479.58 MWD +IFR2 +MS +sag (4) 14,621.70 92.10 319.40 5,003.34 4,947.14 - 3,624.25 - 7,239.72 6,027,411.06 462,568.21 0.13 5,563.54 MWD +IFR2 +MS +sag {4) 14,715.37 90.61 320.11 5,001.12 4,944.92 - 3,552.77 - 7,300.21 6,027,482.77 462,508.01 1.76 5,644.84 MWD +IFR2 +MS +sag (4) 14,813.48 89.01 321.39 5,001.45 4,945.25 - 3,476.80 - 7,362.28 6,027,558.99 462,446.25 2.09 5,729.15 MWD +IFR2 +MS +sag (4) 14,909.63 90.93 322.51 5,001.50 4,945.30 - 3,401.09 - 7,421.54 6,027,634.93 462,387.31 2.31 5,810.73 MWD +11122 +MS +sag (4) 15,007.07 90.12 320.67 5,000.60 4,944.40 - 3,324.74 - 7,482.07 6,027,711.51 462,327.09 2.06 5,893.72 MWD +IFR2 +MS +sag (4) 15,103.49 87.52 320.30 5,002.59 4,946.39 - 3,250.38 - 7,543.41 6,027,786.12 462,266 :07 2.72 5,976.79 MWD +IFR2 +MS +sag (4) 15,200.31 87.16 320.06 5,007.08 4,950.88 - 3,176.10 - 7,605.34 6,027,860.64 462,204.44 0.45 6,060.39 MWD +IFR2 +MS +sag (4) 15,296.62 87.10 320.66 5,011.91 4,955.71 - 3,102.03 - 7,666.70 6,027,934.96 462,143.39 0.63 6,143.39 MWD +IFR2 +MS +sag (4) 15,393.08 87.28 319.99 5,016.63 4,960.43 - 3,027.88 - 7,728.21 6,028,009.35 462,082.18 0.72 6,226.55 MWD+IFR2 +MS +sag (4) 15,428.97 87.28 319.99 5,018.34 4,962.14 - 3,000.42 - 7,751.26 6,028,036.90 462,059.25 0.00 6,257.60 PROJECTED to TD 11/3/2009 2 :48 :59PM Page 7 COMPASS 2003.16 Build 71 • • PIONEER NATURAL RESOURCES ALASKA Letter of Transmittal Date: November 24, 2009 FROM TO Shannon Koh AOGCC Pioneer Natural Resources Attn: Christine Mahnken 700 G Street, Suite 600 333 W. 7 Avenue, Suite 100 Anchorage, AK 99501 Anchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑ Maps X Report X Other —1 CD, 4 Well Logs ❑ Agreement DETAIL QTY DESCRIPTION • ODSN -45A (API: 50- 703 - 20577 -01) 1 CD 1 CD Digital graphic logs (EMF, CGM, PDF, TIFF) 4 Well Logs 4 Well lops DGR, EWR - Phase 4, AFR (1:600, 1:240) MD logs, TVD Iogs 1 Report End of Well Report We request that all a a be treated as confidential information. Thank you. Received by: Date: Please sign and return one copy to Pioneer Natural Resources, Inc., ATTN: Shannon Koh 700 G Street, Suite 600, Anchorage, AK 99501 907 -343 -2190 fax 907 - 343 -2128 phone • Page 1 of 2 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, October 21, 2009 7:52 AM To: 'Franks, James' Subject: RE: PTD 209 -079 - BOPE test extension An additional day is certainly OK. This rig is running on a 7 day BOP schedule due to the exploration "tag" for the target. As long as operations are progressing toward TD'ing this wellbore 1 would stay the course. Touch bases with me tomorrow. Guy Schwartz Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Franks, James [mailto:James.Franks @pxd.com] Sent: Wednesday, October 21, 2009 7:23 AM To: Schwartz, Guy L (DOA) Subject: RE: PTD 209 -079 - BOPE test extension Guy, Good morning. All indications look as though we will be able to drill to TD, perform our wiper trip to the window (we have a short section to MAD pass log), and get out of the hole prior to the end of the day on 10/22. Should operations move a bit slower than anticipated, we might not get out of the hole until the 23 Could we get an additional days extension for the testing of the BOPE to 10/23 at this time or should I touch base with you in the morning tomorrow once I see where we are? Once out of the hole, our next step is to run the liner. Thanks! James James Franks Pioneer Natural Resources Alaska 907.343.2179 From: Franks, James Sent: Tuesday, October 20, 2009 8:46 AM To: 'Schwartz, Guy L (DOA)' Subject: RE: PTD 209 -079 - BOPE test extension Thanks Guy. We'll be sure to keep you in the loop. james 10/21/2009 • • Page 2 of 2 James Franks Pioneer Natural Resources Alaska 907.343.2179 From: Schwartz, Guy L (DOA) [ mailto:guy.schwartz @alaska.gov] Sent: Tuesday, October 20, 2009 7:51 AM To: Franks, James Subject: RE: PTD 209 -079 - BOPE test extension Frank, That is a reasonable request.... If the well continues much past 10/22 (or two days out) lets re -look at the BOP test cycle. Guy Schwartz Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Franks, James [mailto:James.Franks @pxd.com] Sent: Monday, October 19, 2009 3:23 PM To: Schwartz, Guy L (DOA) Subject: RE: PTD 209 -079 - BOPE test extension Guy, We are currently drilling ahead with our lateral on the ODSN -45A well and have - 3 days until we are out of the hole (10/22). We are on a 7 day test cycle with the BOPE last tested on 10/14 (due on 10/21). We were last out of the hole on 10/17 and we thought there was a very good chance to drill to TD and get out of the hole to test our BOPE as scheduled. As of now, it would appear that we are not going to be able to test the BOPE on 10/21 unless we were to make a special trip out of the hole to do so. As such, we would like to request and extension of the BOPE testing requirements past the 7 day interval. Please let me know if you agree with this extension. It should only be 1 day, but we might need 2 days. I look forward to hearing from you. james James Franks Pioneer Natural Resources Alaska 907.343.2179 10/21/2009 Page 1 of 2 Schwartz, Guy L (DOA) From: Franks, James [James.Franks ©pxd.com] Sent: Thursday, October 08, 2009 10:27 AM To: Schwartz, Guy L (DOA) Cc: Vaughan, Alex; Hazzard, Vance; Delmonico, Joe; Johnson, Vern; OoogurukDrillingSupervisor Subject: RE: RE: Sundry Approval 309 -274, PTD 209 -079 - Pressure Test of the perfs Guy, In response to a message you left on the phone, here is a note. You and Vance Hazzard had a conversation about the pressure testing of the perfs to a 12.5 ppg equivalent and following this conversation it was agreed that we would eliminate this step from the amended Sundry. At this time, we will not be pressure testing the perforatons. I apologize for the bother, the last information I had documented was the amended Sundry you and I worked on. As an additional piece of information, when we did the injectivity test of the formation through the perfs, we had an "'15 ppg LOT. Take care, james James Franks Pioneer Natural Resources Alaska 907.343.2179 From: Franks, James Sent: Thursday, October 08, 2009 9:32 AM To: 'Schwartz, Guy L (DOA)'; AOGCC North Slope Office Cc: Vaughan, Alex; Hazzard, Vance; Delmonico, Joe; Johnson, Vern; OoogurukDrillingSupervisor Subject: RE: Sundry Approval 309 -274, PTD 209 -079 - Testing BOPE Guy, We have performed the squeeze portion of the approved sundry above and are now in the process of running in the hole to clean out the cement. In looking at the time it will take to perform the next set of operations, with regards to the BOPE testing requirements (we are due on Sunday, 10/11), we have 2 choices 1. Proactively test the BOPE when we come out of the hole on this trip — possibly Tess than a 24 hour notice prior to test 2. Go ahead and run in the hole with the whipstock and mill the window and commence drilling and get an extension on the BOPE test. Based on our phone conversation, it is your recommendation that we test the BOPE at the conclusion of this 10/8/2009 • Page 2 of 2 cleanout trip and prior to the next steps in the operations. I have cc'd our drilling staff to this note so that everyone is in the loop. Thanks for your time. james James Franks Pioneer Natural Resources Alaska 907.343.2179 10/8/2009 • . Page 1 of 1 Schwartz Guy L (DOA) From: Schwartz, Guy L (DOA) ( ) Sent: Tuesday, October 06, 2009 3:50 PM To: 'Franks, James' Cc: Hazzard, Vance; Vaughan, Alex; Johnson, Vern; Delmonico, Joe; OoogurukDrillingSupervisor Subject: RE: Sundry Approval 309 -274, PTD 209 -079 James, Thanks for the update. Since the PT is OK you are good to go. Good luck on the cement sqz work. Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Franks, James [mailto:James.Franks @pxd.com] Sent: Tuesday, October 06, 2009 3:09 PM To: Schwartz, Guy L (DOA) Cc: Hazzard, Vance; Vaughan, Alex; Johnson, Vern; Delmonico, Joe; OoogurukDrillingSupervisor Subject: RE: Sundry Approval 309 -274, PTD 209 -079 Guy, I just wanted to give you an update on the operations for the Sundry 309 -274. We have run in the hole with a bit and a scraper thinking we were going to tag up on cement at 10050' MD and then have to mill cement to ^'10095' (EZSV set at 10100' MD) to ensure we placed the perf guns at the proper depth for squeeze operations. While running in the hole, we were able to drift down to 10105' prior to tagging anything firm — we have no reason to go further and do not plan to mill anything at this depth to verify cement, however it is suspected that this is the original EZSV. At this depth, we have performed a pressure test of the casing to 3500 psi for 30 minutes that looks good. With this information in hand, we have been able to verify internal isolation of the ODSN -45i welibore for Sundry 308 -366. Operations are to continue as approved in Sundry 309 -274 and 209 -079 1. Perf and squeeze cement 2. Cleanout cement to allow rathole for whipstock (not going past 10105' MD) 3. Set whipstock, mill and drill. Thanks for your time. james James Franks Pioneer Natural Resources Alaska 907.343.2179 10/6/2009 • Page 1 of 1 Schwartz, Guy L (DOA) From: Vaughan, Alex [AIex.Vaughan @pxd.com] Sent: Thursday, August 06, 2009 4:15 PM To: Schwartz, Guy L (DOA) Cc: Johnson, Vern Subject: RE: ODSN -45A Sundry 10-401 Attachments: AC ODSN -45A wp13 10038 to TD.PDF; Moraine NW wp13 Planning Report DRAFT.pdf; Visio - ODSN -45A draft Completion.pdf Guy, Attached you will find; • ODSN -45a Proposed Completion Schematic • ODSN -45a Anti - Collision • ODSN -45a DRAFT Directional Plan Alex Vaughan Operations Drilling Engineer PIONEER NATURAL RESOURCES 907.343.2186 (office) 907.748.5478 (mobile) 907.343.2190 (fax) From: Schwartz, Guy L (DOA) [mailto:guy.schwartz @alaska.gov] Sent: Thursday, August 06, 2009 11:20 AM To: Johnson, Vern; james.frank @pdx.com Cc: Vaughan, Alex Subject: ODSN -45A Sundry 10 -401 Alex/James, I am reviewing the sundry to drill ODSN -45A (PTD 209 -079). I did not see an attached proposed well sketch ( the current status wellsketch is included however). Could you forward a copy to me ?? In addition, do you have any more collision avoidance data available? A traveling cylinder plot and map view of the well in question (Kalubik 2) would be helpful. Thanks, Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e -mail and delete the message and any attachments. 8/7/2009 Well Planning - Pioneer - Oooguruk Oooguruk Developement Oooguruk Drill Site ODSN -45 ODSN -45A Moraine • ODSN -45A Moraine NW w p 13 Sperry Drilling Services Clearance Summary Anticollision Report 07 August, 2009 • Tray. Cylinder North Proximity Scan on Current Survey Data (North Reference) Reference Design: Oooguruk Drill Site - ODSN -45 - ODSN -45A Moraine - ODSN -45A Moraine NW wp13 Well Coordinates: 6,031,005.53 N, 469,821.86 E (70° 29' 44.80" N, 150° 14' 48.35" W) Datum Height: 42.7' + 13.5 @ 56.2ft (Nabors 19 AC) Scan Range: 10,058.0 to 15,038.0 ft. Measured Depth. Scan Radius is 1,699.5 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 HALLIBURTON Sperry Drilling Services Well Planning - Pioneer - Oooguruk HALLIBURTON Oooguruk Developement Anticollision Report for ODSN -45 - ODSN -45A Moraine NW wp13 Tray. Cylinder North Proximity Scan on Current Survey Data (North Reference) Reference Design: Oooguruk Drill Site - ODSN -45 - ODSN -45A Moraine - ODSN -45A Moraine NW wp13 Scan Range: 10,058.0 to 15,038.0 ft. Measured Depth. Scan Radius is 1,699.5 ft . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (ft) (ft) (ft) (ft) ft • Ooguruk Offset Wells Kalubik #2 - Kalubik #2 - Kalubik #2 14,293.0 234.5 14,293.0 106.0 5,000.0 1.824 Clearance Factor Pass - Major Risk Oooguruk Drill Site ODSN -16i - ODSN -16 PS14 - ODSN -16 PS14 wp09 10,150.0 1,292.8 10,150.0 1,166.1 12,600.0 10.201 Centre Distance Pass - Major Risk ODSN -16i - ODSN -16 PS14 - ODSN -16 PS14 wp09 10,150.0 1,293.9 10,150.0 1,165.5 12,650.0 10.080 Clearance Factor Pass - Major Risk ODSN -17i - ODSN -17i IS15 - ODSN -17i 1S15 wp08 12,375.4 922.3 12,375.4 800.7 10,600.0 7.586 Clearance Factor Pass - Major Risk ODSN -40 - ODSN -40 PN12 - ODSN -40 PN12 Surveys 14,557.1 1,445.3 14,557.1 1,291.0 13,300.0 9.367 Clearance Factor Pass - Major Risk ODSN -40 - ODSN -40 PN12 PB2 - ODSN -40 PN12 PB 14,613.8 1,406.9 14,613.8 1,246.8 13,359.0 8.789 Clearance Factor Pass - Major Risk ODSN -43 - ODSN -43 PN14 - ODSN -43 PN14 wp12 10,070.3 527.9 10,070.3 293.7 10,200.0 2.254 Clearance Factor Pass - Major Risk ODSN -45 - ODSN -45i IN13 PB1 - ODSN -45i IN13 PB1 10,075.0 1.0 10,075.0 0.3 10,075.0 1.392 Clearance Factor Pass - NOERROR • Survey tool program From To Survey /Plan Survey Tool (ft) (ft) 50.0 533.0 CB- GYRO -SS 575.4 10,037.9 MWD +SAG +CA +I IFR +MS 10,037.9 15,037.8 ODSN -45A Moraine NW wp13 MWD +SAG +CA +IIFR +MS Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 07 August, 2009 - 11:26 Page 2 of 4 COMPASS Well Planning - Pioneer - Oooguruk HALLIBURTON Oooguruk Developement Anticollision Report for ODSN -45 - ODSN -45A Moraine NW wp13 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to 42.7' + 13.5 © 56.2ft (Nabors 19 AC). Northing and Easting are relative to ODSN -45 - Slot ODS -45. Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 04. Central Meridian is - 150.00 °, Grid Convergence at Surface is: -0.23 ?. 1 L adder P Iot I • 1 80 D • • • 1 1 • 1 I it .==. 1 350 • 1 7 i 1 1 • 1 r1 1 1 1 1 . _- C V 1 1 C37 9 0 0 • i ' -- t 1 1 / c : I it : -1r co 1 / 1 G> J _ J - _ J __ - - J J p 1 1 i co 1 1 1 1 1 1 ...J. c 1 1 1 t � 450 • • ti 1 1 t.: 1 1 1 1 1 • J J 1 / 4.. 1 / 1 • ° • K a lu b i 1< iM 2 \f 0 0 2 5 0 D 0 DS N-15210).0 : O S N -1 6 P S 147. N- 1 6 P 6 1 4 q. 0121S/D0.1:1 - N - 30 4. 0 0 911.5.1aff10IN 11 0 0 -44 0 i po s a l , 005 OW 1 -44 0 i p o s al \}B - 005 N -171, 00rtil J t7E115 $ti4 1ft F{ orp 8 NAD -- 0 0 S N -391, 0 0 S N-3 9i IN 11 , 0 0 : -20 Disposal, 00S D -20 Disposal u..-p4314- %ZOO SN -2 . 00S 14-2 P S1 , 00 SN -2 PS 1 0.1p08 \/0 - 00614- 34. 00 SN -3i 162.006N- Ip -Ii 1, 006 K -13 Ku p Hi 1 w p02 \/0 -„F- 0 OSN -25 . 005 N -25, 00S14-2 N84 wp 02 \10 —7INF 00 S N- 4. 005 N -4 PS3.00S14- Ip- ii2,00S K -13 Ku Hi 2 wpO1 WO ,.^r 00511 -26, OOS N -26 P 14 ,005 N -26 P111 w pO6 \iO -..- OOS N -40, OOSN-4-0 PN12. 00 p E 1, 0 0 S K-14 K u p B 1 w p O 1 \/O t o 0 0 5 N -2 71. O O S N -2 71 1142. 0 O S N-2711142 w p 06 \FO --lei-- O O S N- 40 , O D S N- 40 PN12 P 811 pE 2, 00SK -14 Kup8 2 w pO1 \l0 OOSN- 28.00614-28 PN3, 00SN -28 PN3 wpO7.a \f0 --- "• -5 - -- OOSN -40. 0 O N -40 PN12 PB2 pR. 005 K -33 KupA \/0 —fir— 0 OSN -201, 00 SN -29i IN 4, 00 SN -291 IN 4 wpO6 WO 0 0 S14-43, OOS N -43 PN14, OD pA PB1, 0DSK -33 KupB P81 Survc ys - OOSN -30. OD N -30 PN6, OOSN -30 PN5 w p05 \/D --If 00514-45, 0 0 S N- 45 A..lulorain., p E , 0 0 6 K-35 Ku p B Surveys ' 1 0 $- 00 S N -3 1 . O D S N-31 P81 PNO, O D S N-31 P 8 1 P N6 Surveys '10-0- O D S N-45, 0 0514- 45 i 1 N 13 P 131 p E . 0 D S K-35 Kup 1 Test \/O - O O S N -3 1 . O D S N- 3 1 P N 6 . O O S N -3 1 P N 6 Surveys \ID -$- O O S N- 46 . O O S N- 46 I N 1 1 . 0 0 E ups . 0 OS K -38i KupO Surveys \✓0 --jar- 0 OSN -32i, 00SN -32i 1N7, 00514- 3211N7 Surve vs '!0 006 N- 47 , 006 N -47 SW 11 w3C p F , 0 0 S K -4 1 K u p F Surveys \f O - 0 O S N -3 2 i . 0 O S N -3 2 i 1147 P B 1 . 0 D S N-3211147 P B 1 WO -le)- 0 0 5 14- 48 , O O S n- 48 S W 9, 0 D S p F P 8 1 . 00514-41 KupF P81 \/O 1 . . - - 1 - 0 0 S N -3 4i. 0 O S N -3 4i 1N9 . 0 0 5 N-34 i I N 9 S u rve y s WO -11 - 0 O S N-51. O D S N- 5 i 154, 0 O S N- ••. 0 r1 (IC If_A2. Ie.",.2 •... -.n3 ••l - -- - - -- 1212 CN -26: .2 r1CN -'2 a: INO .212 14_2 d :1140 •..., 1+51fn fl 12 N -R r1 fl C 1...1_ Pt PC., 0 PlCN 07 August, 2009 - 11:26 Page 3 of 4 COMPASS Well Planning - Pioneer - Oooguruk HALLIBURTON Oooguruk Developement Anticollision Report for ODSN-45 - ODSN-45A Moraine NW wp13 Clearance Factor Plot: Measured Depth versus Separation(Clearance) Factor - r Magnetic Model: IGIRF2005I 0 IVI • Date: 05-Jun-09 Declination: 22.24? Inclination/Dip: 80.81? F ield Strength: 57736 • rid North i 0.237 XIV &-t cit T rule N Drth rid C convergence) ignetic NI orth i 22.247 E elet of T rue North (M egrtetic D eclinetion) r1e!tic N orth i 22.487 E of 1G rid N orth (M gine Corrvergeni=e) To core T ri..i aft ID ireiction tD e rid ID iructiDn, add l 0 .23? c onvert M grietic ID irection to a T we Direction, "cid 22.247 E est o convert Megrietic D retior to e rid 'Direction, eft.cici 22.487 07 August, 2009 - 11:26 Page 4 of 4 COMPASS SURVEY PROGRAM ANTI- COLLISION SETTINGS Date: 2009 - 06-11700:00:00 Validated: Yes Version: Interpolation Method: MD, interval: 25.0 Depth Range From: 10038.0 To 15038.0 Depth From Depth To Survey/Plan Tool Results Limited By: Centre Distance: 1699.5 50.0 533.0 ODSN -45i IN13 PB1 Gyro CB- GYRO -SS Reference: Plan: ODSN -45A Moraine NW wp13 (ODSN- 45 /ODSN -45A Moraine) 575.4 10037.9 ODSN -45i IN13 FBI MWD MWD+SAG+CA +IIFR+MS Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference 10037.9 15037.8 ODSN -45A Moraine NW wp1D1WD+SAG +CA +IIFR +ASS FOR USE FROM 10038' TO TD 0 From Color To MD rt 0 250 330 30 250 500 - 30 500 750 330 30 750 ... 1000 1000 1250 1250 1500 1500 ___.__.._.. 1750 2U • 1750 2000 2000 2250 300 - 60 2250 "` - -- 2500 300 60 o p K1 lik 2500 2750 2750 3000 w 10 • oo 3250 7 ( ‘ / 3250 3500 3500 3750 3750 -- 4000 • 4000 -- 5000 /� �'� �t It i t,., 270 • f..• :�� - � - 'rte ` _. 90 8000 8000 soon 7000 ,� 7000 270 - - '' .� 90 SON 10000 1 10 , 1 MI" 10000 11000 11000 12000 12000 13000 13000 14000 240 12 11111 ' 14000 15000 �15000 18000 > r 16000 ....... .......... 17000 ' 17000 18000 18000 19000 3000 20000 210 150 240 D 120 20000 21000 30 - i 21000 -- - - - - -- 22000 180 ODSN -461 IN13 PB1 \ ODSN -461 IN13 PB1 Surveys 7 5 - Travelling Cylinder Azimuth (TFO +AZI) [bearing] vs Centre to Centre Separation 120 ft /in] ODSN-46i 1N13 PB1 210 150 ODSN -45i IN13 PB1 Surveys I 100 180 Travelling Cylinder Azimuth (TFO+AZI) ]bearing] vs Centre to Centre Separation ]50 ft/in] REFERENCE INFORMATION Well Planning - Pioneer - Oooguruk 9E07138 DETALS On MO Inc A0 WD +816 +EI-W 0160 TF.q 25.4 T.1.t Co - ordinate (NfE) Reference: Well ODSN - - Slot ODS - 45, True North 1 10037.9 7058 23188 49972 62673 3977.8 030 030 1594.5 r� Calculation Method: Minimum Curvature 2 10057.9 72.58 23354 5003.4 62783 38925 1230 4530 16042 t Vertical (TVD) Reference: 42.7' + 13.5 56.2ft (Nabors 19 AC) 3 10207.4 78.18 24284 5041.1 4354.4 .119.8 7.00 5931 16943 Error System: ISCWSA 4 102112 78.18 242.84 50419 4356.1 -4119.2 030 030 1696.8 Section (VS) Reference: Slot - ODS 0.0E) 5 113173 9030 320.00 51762 4148.7 41123 740 8733 2701.4 Moraine NW vu TiA Measured Depth Reference: 42.+13.5 56.2ft (Nabors 19 AC) Scan Method: Tray. Cylinder North 6 12267.0 9030 32030 51762 4403.7 4735.5 030 030 35413 YptM• 7' ( ) Error Surface: Elliptical Conic 7 124792 95.78 320.00 5166.5 4254.4 4659.1 340 631 37083 Calculation Method: Minimum Curvature P 8 13876.1 95.78 32030 5325.9 -4192.1 4752.2 030 030 49112 Warning Method: Rules Based 0 0 150384 0000 32000 60163 40442 7468.8 000 17929 000 58172 Moraine NWV/3 T2 NAD 27 ASP Zone 4 : WELL DETAILS: ODSN -45 Ground Level: 13.5 +N / -S +E/ -W Northing Easting Latittude Longitude Slot 0.0 0.0 6031005.53 469821.86 70° 29' 44.804 N 150° 14' 48.350 W ODS-45 • • ODSN -45A Proposed Completion - WP13 Well Head: 10 -3/4 ", 5K, VetcoGray Tree: 3 -1/2 ", 5K, Horizontal 16" Conductor �— ` 153' MDrkb / 153' TVDrkb J 10-3/4", 45.5# L -80 BTC, 9.95" ID 114 4973' MDrkb / 3438' TVDrkb • • 4-W 12.6 # L -80 Hyd 521 @ 15038' MDrkb / 5016' TVDrkb Cement Squeeze prior to the 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 00 ' sidetrack operations 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 1 f --- Estimated Top of Cement @ EZSV 10100' MDrkb / 5017'TVDrkb 10100' MD / 5017' TVDrkb Cement above packer: 2.5bb1 / 50' Cement below packer: 79.5bb1 / 1277' to 7 -5/8" shoe + 100' w/ 30% excess bullhead below shoe Top of 6" liner, 10,806' MDrkb / 5239' TVDrkb 7 - 5/8 ", 29.7# L - 80 BTC - M, 6.875" ID Top of Inner String fish, 10,825MDrkb 11377' MDrkb /5412' TVDrkb Live Severing Charge w/ 2.0" OD Debris Catcher, 2.0" ID 12413' MDrkb, Top of Expanded Section, /- 6 ", 18.6# L -80 Expanded to 6.767" OD, 6.19" ID, 6.131" Drift Connection unable to hold pressure, 13,433 MDrkb eArte: Expansion Cone Expandable csg shoe 13,513' MDrkb / 6071' TVDrkb 13866' MDrkb / 6166' TVDrkb Hole Fill and Un- consolidated Cement Date: Revision By: Comments PIONEER 6/1/2009 JDF Proposed Completion 6/16/2009 VHH Updated to current directional plan ODSN -45A tAIORAI RESOURCES ALASKA Proposed Well Schematic • • Page 1 of 2 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Thursday, September 10, 2009 9:48 AM To: 'Franks, James' Cc: Hazzard, Vance; Vaughan, Alex; Johnson, Vem; Delmonico, Joe Subject: RE: Sundry Approval 309 -274, PTD 209 -079 James, I would agree with you that a 3500 psi casing test is not needed. I am inclined to still recommend a test of the squeeze perfs to what ever the cementing squeeze pressure reached or possibly go to a 12.5 ppg equivalent pressure test to ensure you have that in hand before you drill out at do your FIT. Does that make sense ?? I am heading to the gym at noon and can stop by to meet for a few minutes after that. Would be good to meet a few of you guys in person (Vern not included!!) Does 1:OOpm work for you to meet at your office ?? Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 From: Franks, James [mailto:James.Franks @pxd.com] Sent: Thursday, September 10, 2009 8:58 AM To: Schwartz, Guy L (DOA) Cc: Hazzard, Vance; Vaughan, Alex; Johnson, Vern; Delmonico, Joe Subject: Sundry Approval 309 -274, PTD 209 -079 Guy, When the request for Sundry Approval and Permit to drill were sent in for the ODSN -45i and ODSN -45A wells, there was an entry to do a pressure test of the casing following the setting of the whipstock. Upon further review in- house, we would like to request that we remove this step of the operation. From 309 -274 18. ecc Inc ,.ell 0, er to -9 3 epe r' - rte ,;.nG fluid 07 ro wa+c S� i h Pk Ilse continue t the Permit to Drill request for ODSN -45A for the sidetrac � summary of operations From 209 -079 urk. 16. Set the Whipstock RHS so that the lop of Ire hrndow s below t"e top of the Torok at - 10042' MC) 4 according to the Simtn Rep on acat,on. 17. D sptace the well over to -9 3 cog nwiltg dr:thng flu+d. 18 Perform ? tonsure test of Me cos:n. to 3500 .sr — chart and hoist for 30 rturwtes 19. M.t the window ;r. 7.58" cas'ng and erg' -20' to 50' Caul? me bit back into the casing and perform: an FIT to 12 5 bog 20. Drill 6 -a 4" attend to the end of the bu.ld.°turn at - 11317' MD Tenth me GecTrac* t4trthnglDritting 1y ,c+( ) asserrhty 11 wi *,eke ;.farmed 7 deg:100' DLS to get to the landing point t Note: ThtS systern i s never been : see .o (tr;t1 a bole of th s 4ength, -1275 from the top of the w so if tv.ere are any cJe$t:On$ about performance or ab;tdy in this attempt, the n 0 tco s will be trapped for dedicatee motor run to land tits wet. I� 9/10/2009 • • Page 2 of 2 Justification: A pressure test is going to be performed at the beginning of the well prior to the start of the workover. This pressure test will provide a casing test down to the top of the cement plug in the 7 -5/8" casing — estimated top of 10050'. Following the squeeze plan of the workover, we are going to drill out the cemented perforations (planned depth of the perforations are - 10042' to 10046') to provide enough rat hole for the whipstock. The window will be milled in the casing through and across these cemented perforations, so casing integrity across this interval is not needed. Following the drilling, a liner will be run with a hanger and packer set above the interval perforated and the window milled and the liner top will be tested. Based on the above, we feel that there is no real value to the additional pressure test on the cemented perforations. Please let me know if there is any additional information you require. I look forward to your reply. Thanks for your time. james James Franks Senior Drilling Engineer Pioneer Natural Resources Alaska 907.343.2179 9/10/2009 • Page 1 of 2 • Maunder, Thomas E (DOA) From: Franks, James [James.Franks ©pxd.com] Sent: Friday, June 26, 2009 8:11 AM To: Maunder, Thomas E (DOA) Cc: Hazzard, Vance; Johnson, Vern Subject: Possible sidetrack option for ODSN -45 (PTD 208 -100) Attachments: ODSN -45i 1N13 Propsed P &A Schematic.pdf Tom, I am looking into a sidetrack of the ODSN-45 well (PTD 208 -100) and I have a question or two... Background: ODSN -45 was drilled in the fall of 2008. We got the 7 -5/8" casing stuck off bottom and attempted to run an expandable liner without success to tie into the Oooguruk - Nuiqsut formation. Following this attempt, we abandoned the well - schematic attached. The 7 -5/8" was cemented off bottom without returns during the cement job. Since the well was drilled to TD and we were going to tie an expandable liner back to the intermediate casing string, an FIT was not performed. However, in the attempt to regain the hole to set the expandable, we had dynamic ECD's of - 14.5 ppg EMW around the intermediate casing shoe, as measured by PWD. Based on this ECD measured, the fact that we did not regain circulation during the cement job and we were unable to get the intermediate casing moving again once it stopped, we feel that the area between the 7 -5/8" shoe and the base of the Torok are isolated. Also, as indicated in the approved sundry 308 -366, we pumped 82 bbls of 15.8 ppg cement through an EZSV set at 10100' MD to plug the inside of the 7 -5/8" casing and the 6" x 7 -5/8" expandable casing left in the hole. Add to this the wellbore instability in the shale intervals between the Torok and the Nuiqsut - consisting of the HRZ, Kalubik and the Miluveach - we feel that the Nuiqsut reservoir is effectively isolated from the Torok. Further evaluation of the Torok in this area shows a potential for it to be oil bearing, something we did not completely understand at the time of drilling the ODSN -45i well. As such, we would like to drill an exploration /appraisal sidetrack into this interval from the ODSN -45 wellbore. This wellbore provides us with an opportunity to sidetrack off into the Torok (5001' to 5216' TVD rkb) as an exploration target to test the Torok zone for a possible development in the future. The ODSN -45 wellbore is the only wellbore to cross the Torok on the southwest side of a fault believed to be isolating. This sidetrack is planned as a frac'd exploration /appraisal well for Pioneer Natural Resources Alaska and if it produces as hoped, we would plan on keeping the well and drill wells around it in the same wellbore orientation. Some of those wells will be injectors and would be within % mile of this well. Sidetrack and well design issues: From looking at the cement job attempted on the intermediate casing stuck off bottom, the cement isolated the intermediate shoe from the formations above, but there is a good chance it did not cover the top of the Torok interval. As such, I am planning to perform a cement squeeze of the Torok interval to, 1. Provide cement isolation above the top of the Torok 2. Aid in securing the wellbore to the formation at the sidetrack point 3. Secure the centralizer which should be located behind the pipe at the sidetrack interval 1 plan to perforate - 5' at the top of the Torok interval, just above the top of the sidetrack point at the top of the Torok interval, -10042' MD / 5001' TVDrkb. In sidetracking the well at this point, we can avoid any problems from the shales directly above the Torok that would require additional mud weight to re -drill through the interval. 7/27/2009 Page 2 of 2 • Question: Do we need to squeeze an additional section in the shales above the top of the Torok? My Answer: No. Justification: The well was originally drilled with a barite weighted water-based drilling fluid. It is my belief that in the time the well has been static, the barite has fallen out of the fluid, decreasing the mud weight across the shales above the Torok sands and allowing them to swell and collapse in on the intermediate casing, isolating the wellbore from the surface. We should be able to verify this during an injectivity test prior to the cement squeeze across the planned sidetrack point. During the injectivity test prior to the squeeze, we would open the well up on the 7-5/8" annulus and see if we got circulation to the surface. If no circulation is seen, we would assume that the wetibore would be isolated to the surface. Questions for you: Does this plan sound reasonable? What are your concerns? What additionally would the State require? I'd be happy to come buy and discuss when it is convenient for you as I know this is difficult to do over e-mail. Thanks! James Franks Pioneer Natural Resources Alaska 907.343.2179 Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. 7/27/2009 • 0 CCO it i k '17 i - ` p1 ti - A\ (Q [ i /' l / E 3 ) Li r L.:, IT -A „ rb i L \ LPL\ / SEAN PARNELL, GOVERNOR ALASKA OIL AND GA,S CONSERVATION COMMISSION AN N R G A A SUITE 9 01- ANCHORAGE, ALASKA 99501 -3539 / PHONE (907) 279 -1433 FAX (907) 276 -7542 Mr. Vern Johnson Sr. Staff Drilling Engineer Pioneer Natural Resources Alaska Inc. 700 G Street, Suite 600 Anchorage, AK 99501 Re: Field Undefined, Pool Undefined, ODSN -45A Pioneer Natural Resources Alaska Inc. Permit No: 209 -079 Surface Location: 2889' FSL, 1176' FEL, Sec. 11, T13N, R7E, UM Bottomhole Location: 4863' FSL, 3398' FEL, Sec. 15, T13N, R7E, UM Dear Mr. Johnson: Enclosed is the approved application for permit to re -drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the ermit in the event it was erroneously t as er oneously 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, 1 ‘'/ /9„,/,,___ Cathy P. Foerster // Commissioner DATED this ( day of August, 2009 cc: Department of Fish 85 Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. RECEIVED • STATE OF ALASKA jUL 1 7 2009 ALASKA OIL AND GAS CONSERVATION COMMISSION C.f PERMIT TO DRILL Alaska Oil Gas Cons. (amrrfissian �Tt!o 20 AAC 25.005 1a. Type of Work: 1 b. Current Well Class: Exploratory is Development Oil ❑ 1 c. Specify if well is proposed for: Al Rif& avid Drill ❑ Redrill Di Stratigraphic Test ❑ Service ❑ Development Gas ❑ Coalbed Methane ❑ Gas Hydrates ❑ Re -entry / ,t� Multiple Zone ❑ Single Zone ❑ Shale Gas ❑ 2. Operator Nam 5. Bond: Blanket gi Single Well ❑ 11. Well Name and Number: Pioneer Natural Resources Alaska Inc Bond No. 103655283 • ODSN - 45A 3. Address: 6. Proposed Depth: 12. Field /Pool(s): 700 G Street, Suite 600 Anchorage, AK 99501 MD: 15038' - TVD: 5016' r 4a. Location of Well (Governmental Section): 7. Property Designation: Undefined Surface: 2889' FSL, 1176' FEL, Sec. 11, T13N, R7E, UM ' ADL 355036 . Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1902' FSL, 5159' FEL, Sec. 14, T13N, R7E, UM 417497 8/3/2009 Total Depth: 9. Acres in Property: i . , 4 14. Distance to Nearest 4863' FSL, 3398' FEL, Sec. 15, T13N, R7E, UM 5760 e ,Zvvu° Property: l ) Zru. /e_ A (.4., 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 5t feet 15. Distance to Nearest Well Open Surface: x- 469821.86 • y- 6031005.53 ' Zone -ASP 4 KB Elevation above GL: . 7 gm feet to Sa ,e pool: 250' ift' rd'R �'? L 7 k<atiZi '+2 - /1� G s n rhj . 16. Deviated wells: N/A Kickoff depth: 10,038 feet • 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) /� z 7. cc Maximum Hole Angle: 96 degrees Downhole: 2261 . Surface: 1711 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 6 - 3/4 "x 6 - 1/8" 4 -1/2" 12.6 L -80 Hyd 521 5150' 9888' 4950' 15038' 5016' N/A - liner w/ pre -perf'd pups 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 13866' 6166' 10100' 10050' 5000' N/A Casing Length Size Cement Volume MD TVD Conductor /Structural 109' 16" Driven 153' 153' Surface 4820' 10 -3/4" 168 sxs PF'L'; 105 ssxs Class 'G' 4973' 3438' Intermediate 6404' 7 -5/8" Cement pumped w/o lift press. 11377' 5412' Production 2707' 6" - 7 -5/8" 13513' 6071' Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee ❑ BOP Sketch El Drilling Program Q Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Property Plat el Diverter Sketch EI Seabed Report ❑ Drilling Fluid Program El 20 AAC 25.050 requirements p 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact James Franks, 343 -2179 Prepared Bu: Kathy Campoamor, 343 - 2183 Printed Name 7" erohn,bn Title Sr. Staff Drilling Engineer Signature ' (� � ( J '' / Phone 343 -2111 Date 7/16/2009 Commission Use Only Permit to Drill 77 ,/1--z- q API Number Permit Approval I" G, See cover letter for other Number: /- J / 50 7C...-' - 26677 - El r/ Date: K' / o / 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: [r Other: /1� ,� T Samples req'd: Yes ❑ No[; Mud log req'd: Yes ❑ o [ 3500 Sc: lX/r �i I S H measures: Yes ❑ No Directional svy req'd: Yes [ " N o ❑ LSD psi AMK Jd& - w_ 5 7 i j3OP - (e..)+' cjt /. acs 7 Mc 2 5.0 35 (e)(10 8 f APPROVED BY THE COMMISSION DATE: Q -f o - D COMMISSIONER ORIGINAL Form 10 (Revised 1/2009) This permit is valid for 24 months from the date of approval (20 AAC 25.005(9)) Submit in Duplicate • Oooguruk Well Plan Summary: Permit to Drill ODSN -45A — Torok Exploratory Sidetrack Surface Location: 2889' FSL, 1176' FEL, Sec 11, T13N, R7E, UM ASP 4 (NAD27) projection X = 469821.86 Y = 6031005.53 Target: 1902' FSL, 5159' FEL, Sec 14, T13N, R7E, Umiat X = 465819.02 1 Y = 6024755.32 1 4,998' TVDrkb Bottom Hole Location: 4863.2' FSL, 3397.8' FEL, Sec. 15, T13N, R7E X = 462310.42 Y = 6027734.09 5,016' TVDrkb AFE Number: 17062 Est. Start Date: August 3, 2009 Rig: Nabors 19AC Operating days: 22.4 days Drill and Complete TD: 15,038' MD / 5,016' TVDrkb Objective: Torok 1 Well Type (exp, dev, etc): Exploratory Well Design (conventional, slimhole, etc): Slimhole Current Mechanical Condition: Well Bay Footing / ODS Ground Level: Elevation above MSL: 13.5' RKB to Ground Level: 42.7' Rig Elevation: RKB + MSL = 56.2' Conductor: 153' MDrkb Well Control: Based on calculations below, BOP equipment will be tested to 3,500 psi. Production Hole Section: • Maximum anticipated BHP: 2261 psi @ 4997' TVDrkb . • Maximum surface pressure: 1711 psi @ surface (Based on BHP and a full column of gas from TD @ 0.11 psi /ft) Planned BOP test pressure: 3500 psi (annular to 2500 psi) Planned completion fluid: 9.3 ppg Brine /6.8 ppg Diesel 5000 psi BOP stack (see attached schematic): o Hydril GK 11" 5M annular BOP o Hydril 11" 5M double gate ram BOP w/ studded connections o Drilling cross 11" 5M x 11" 5M with 2 ea. 3 -1/8" 5M side outlets w /flanged connections o 2 ea. 3 -1/8" 5M full opening inner manual gate valves mounted on drilling cross o 2 ea. 3 -1/8" 5M full opening outer remote hydraulic controlled gate valves mounted on inner gate valves. o Hydril 11" 5M single ram BOP w/ studded connections Pioneer Natural Resources Last Revised: July 16, 2009 ODSN -45A Permit To Drill Page 1 of 9 .‘ • • Formation Integrity Testing Requirements: Test Point Depth Test Type Minimum EMW 7 -5/8" window Rathole + 20' to 50' from 7" shoe FIT 12.5 ppg Drilling Fluids Program: Production Hole Mud Properties: 6 -3/4" x 6 -1/8" hole Baradril -N Interval Density (ppg) Viscosity (secs) YP PV MBT API FL Initial 9.3 40 - 60 15- 25 15-20 0 <4 Disposal: Annular Injection: Currently not requested, but may be requested in the future. Cuttings Handling: All Class 2 solids will be processed on the Oooguruk Drill Site by the Grind and Inject facility in the Rig Support Complex and injected down the approved Class 1 / Class 2 disposal well, ODSDW1 -44. Fluid Handling: All Class 1 and Class 2 fluids will be processed on the Oooguruk Drill Site by the Grind and Inject facility in the Rig Support Complex and injected down the approved Class 1 / Class 2 disposal well, ODSDW1 -44. Hydraulics: Production Hole: 6 -3/4" x 6 -1/8" Interval Pump Drill Pipe AV Pump ECD ppg- Motor Jet Nozzles TFA (in GPM (fpm) PSI emw ( "/32) Window to TD 250 4" 15.7# 210 4200 11.3 N/A 5x11 0.464 Formation Markers: TVD Pore Press. EMW Formation Tops MD Comments (rkb) (psi) (ppg) Top Torok Sand 10038 4997 2261 8.7 Estimated KOP Base Torok Sand 5208 Not penetrated Logging Program: 6 -3/4" Section: Drilling: Mud logging Dir / GR / Insite AFR / PWD Open Hole: N/A Cased Hole: N/A Pioneer Natural Resources Last Revised: July 16, 2009 ODSN -45A Permit To Drill Page 2 of 9 • . Casing Program: Hole Casing / Weight Grade Conn. Casing Csg/Tbg Top Hole Btm Size Tubing Length MDrkb/TVDrkb MDrkb/TVDrkb 6 -3/4" x 4 -1/2" 12.6# L -80 Hyd 521 5150' 9888' / 4950' 15038' / 5016' 6 -1/8" Tubing 4-1/2" 12.6# L -80 Hyd 521 9844' Surface 9888' / 4950' Casing Properties Size Weight Grade ID Drift ID Conn. Internal Collapse Tensile Strength Yield (psi) * (psi) * Joint Body 4-1/2" 12.6# L -80 3.959" 3.833" Hyd 521 8430 7500 288 M 288 M * 4 -1/2" Liner will have perforated pups in the string for a dynamic diversion fracture stimulation treatment. Pioneer Natural Resources Last Revised: July 16, 2009 ODSN -45A Permit To Drill Page 3 of 9 • Cement Calculations: Assumptions at this time are that the cement from the original primary cement job on the 7 -5/8" casing did not bring cement over the top of the Torok interval — no appreciable lift pressure was seen at the surface during the cement job. The original hole drilled is 9 -7/8" and the casing is 7 -5/8" 29.7 ppf L -80. Basis: 1 Squeeze Volume: Squeeze 15 bbls / 72 sx of 15.8 ppg Premium "G" + adds. 1.18 cf /sk, 5.18 Slurry gps water req. Displ 100 bbls mud Temp BHST — 130° F at 5000' TVDrkb, —105° F BHCT This well is outside the 1/2 mile radius around the disposal well. Proximity to Kalubik 2: API # 50- 103 - 20252 -00 The toe of this well comes within —250' of the Kalubik 2 well. Kalubik 2 current conditions: The Kalubik 2 well as originally spudded by Arco on Feb 7,1998 and abandoned on March 9, 1998. Pioneer Natural Resources Last Revised: July 16, 2009 ODSN -45A Permit To Drill Page 4 of 9 • • Pioneer Natural Resources Well Plan Summary Drilling Operations Present Well Condition: Diagram attached 1. ODSN -45i has 7 -5/8" 29.7 ppf L -80 casing set across the Torok interval. 2. The primary cement job showed little lift during the job and it is assumed that cement is not covering the Torok Interval. It is assumed that the 7 -5/8" casing shoe is isolated with cement. 3. It is assumed that due to the high stress in the shale above the Kuparuk, that in the time the well has been static, the shale has collapsed, isolating the Kuparuk formation. 4. It is assumed that due to the high stress in the shale above and below the Torok, that in the time the well has been static, the shale has collapsed, isolating the Torok sands from above and below. 5. An EZSV bridge plug was run in the 7 -5/8" casing and set at —10100' MD. —80 bbls of 15.8 ppg cement was placed via injection through the plug and then —50' of cement was left on top of the plug to abandon the inside of the 7 -5/8" casing. 6. -2000' of 2 -7/8" tubing was run in the well as a kill string. Pre -Rig Work 1. The Oooguruk Drill Site Class 1 / Class 2 Disposal Well, ODSDW1 -44, is operational 2. Expro equipment has been staged to allow Nabors 19AC access to ODSN -45i. Rig Activity: Prep Wellbore, Mill Window, Drill, Case and Complete 1. MIRU Nabors 19AC over ODSN -45i. 2. RU circulation lines and circulate out the freeze protection diesel from the well with seawater. 3. Flow check the well. Set two way check. ND Tree. NU BOPE and test to 250 psi low / 3500 psi (2500 psi Annular) high. Pull two way check. 4. Pull the 2 -7/8" kill string. 5. Test the casing to 3500 psi — chart and hold for 30 minutes 6. MU 6 -3/4" bit and scraper picking up 4" DP as necessary and RIH to the top of the cement (-10050' MD) above the EZSV. Cleanout cement as needed to provide enough room for the squeeze perforation guns. Note: Do not drill up the Abandonment EZSV at —10100'. Contact the ODE should this be of concern. 7. POH standing back the 4" DP. 8. MU HES DrillGun (3 -3/8" guns — 6 spf — 60 deg phase) and RIH on 4" DP from the derrick. Set the DrillGun packer (Drillable EZSV) at the top of the Torok (- 10042' MD). Fire the DrillGun drillable, aluminum perf guns hanging below the packer. 9. Unsting from the EZSV. Extend the DrillGun stinger and sting into the EZSV. 10. Perform injectivity test with seawater and then pump the cement squeeze through the EZSV. 11. Unsting from the EZSV and leave —50' of cement on top of the EZSV. Pull up above the cement plug and circulate the drill pipe and casing clean with seawater. 12. POH standing back the 4" DP. 13. MU 6 -3/4" bit and scraper picking up 4" DP as necessary to TD the well and RIH to the top of the cement (-9990' MD) above the DrillGun EZSV. Drill up the cement, EZSV and aluminum perf guns to a depth to allow for the setting of the Whipstock. Utilize seawater and viscous sweeps until finished drilling the EZSV and perf guns. Note: Do not drill up the Abandonment EZSV at — 10100'. Contact the ODE should this be of concern. Pioneer Natural Resources Last Revised: July 16, 2009 ODSN -45A Permit To Drill Page 5 of 9 • • 14. Circulate the well clean with seawater and viscous sweeps. 15. MU 6 -3/4" Smith GeoTrack Whipstock window milling /drilling system with a 1.5 deg motor and Dir /GR. 16. Set the Whipstock RHS so that the top of the window is below the top of the Torok at —10042' MD S" according to the Smith Rep on location. 1 4 � , Z� 17. Displace the well over to —9.3 ppg milling /drilling fluid. 3 f 18. Perform a pressure test of the casing to 3500 psi — chart and hold for 30 minutes 19. Mill the window in the 7 -5/8" casing and drill —20' to 50'. Pull the bit back into the casing and Q perform an FIT to 12.5 ppg. pin 0 161 20. Drill 6 -3/4" ahead to the end of the build /turn at — 11317' MD with the GeoTrack Milling /Drilling ;0 assembly. It will take planned 7 deg /100' DLS to get to the landing point. Note: This system has never been used to drill a hole of this length, —1275' from the top of the window, so if there are any questions about performance or ability in this attempt, the tools will be tripped for a dedicated motor run to land the well. 21. Once at the landing point, circulate the hole clean and MAD pass any intervals as needed for geology. Note: Do not rotate across the whipstock with the BHA. 22. POH standing back 4" DP and LD the GeoTrack BHA. 23. MU 6 -1/8" Geopilot RSS with Dir /GR/Insite AFR and RIH to the landing point. Drill 6 -1/8" hole to planned TD at -15038' MD. Note: PU WWT Super Sliders to position them to not go out into the open hole. 24. Circulate the hole clean and perform a wiper trip back to the landing point (previous bit trip) 25. Once back on bottom circulate the hole clean and POH standing back the 4" DP and LD the BHA. Note: We will use the drillpipe with the WWT Supersliders when we run the liner. 26. PU 4 -1/2" 12.6 ppf L -80 Hydril 521 liner while and spacing out the pre - perforated pups as required for the dynamic diversion fracture stimulation treatment. The liner top will be made up of a Weatherford hanger, liner top packer and tieback sleeve. RIH on 4" DP. Note: A 6 -3/4" Swellable Packer will be run at the transition from the 6 -3/4" hole to 6 -1/8" hole to aid in isolating the frac'd portion of the wellbore from the window 27. Set the liner hanger and liner top packer as directed by Weatherford Rep on location. 28. Displace the well over to 10.2 ppg Brine. POH. 29. Run 4'/2" completion string 30. ND BOPE. NU tree and test. 31. Move the rig off to the next well Post Rig Activity: 1. Fracture stimulate well 620,000 Ibs of 20/40 Carboceramics Carbolite proppant pumped in 300,000 gallons of Schlumberger's YF125ST. The fluid volume includes a pad stage yet to be determined. The stimulation will target zones 1 and 5 of the Nuiqsut reservoir in a 10 stage treatment using dynamic diversion (Bioballs). The expected surface treating pressure at a planned pump rate of 40 barrels per minute is 6800 psi. Maximum proppant concentration is 5 ppa per gallon. The Schlumberger YF125ST is a water based guar gel system with borate crosslinker. The chemical make -up of the YF125ST includes: Seawater base — 983.75 gpt Clay Stabilizer — 2 gpt Pioneer Natural Resources Last Revised: July 16, 2009 ODSN -45A Permit To Drill Page 6 of 9 • • Polymer — 6.25 gpt Surfactant — 2 gpt Crosslinker — 6 gpt Oxidative Breaker — 0.05 ppt 2. Remove SSSV sleeve and install wireline retrievable SSSV 3. Install live gas lift valves 4. Flowback well with gas lift. Pioneer Natural Resources Last Revised: July 16, 2009 ODSN -45A Permit To Drill Page 7 of 9 • Casing Window Leak Off Test Procedure: � BL S 1. After testing BOPE, pick up the milling /drilling assembly and RIH to the flg-e6(1ar. 2. Displace the well over to milling /drilling fluid. Circulate the hole clean and bring the mud to a consistent mud weight and rheology. 3. Shut in with the pipe rams and test the casing to the required test pressure. Record the volume of mud required and the corresponding pressures in 1 /4 bbl increments. When the design pressure is reached shut in the well and record the shut in pressure for 30 minutes. 4. Bleed off pressure while taking returns to a calibrated tank and record volume recovered. 5. Mill the window and 20' to 50' of new formation per plan. 6. Circulate the hole clean and bring the mud to a consistent mud weight and rheology. 7. Pull the bit back in the casing and above the top of the Whipstock 8. Perform a Leak Off Test (or Formation Integrity Test): • Calculate the required test pressure to reach leak off (or formation integrity test limit) with the actual mud weight and the estimated fracture EMW. • Plot the casing test data and the calculated leak off on appropriate scale coordinate paper. As a guide, use the data from the casing test to determine the approximate volume of mud required to reach the calculated LOT /FIT. • Shut the well in. R/U the test pump. • Bring the pump on line at 0.25 — 0.50 bpm. Maintain a constant rate. • Record the pressure for every ' of a bbl pumped. • Continue pumping until the pressure vs. volume curve breaks over indicating leak off. Note: For FIT, do not take to leak off • Discontinue pumping and shut in the well. Record the shut in pressure in 1 minute increments for 10 minutes or until pressure shows stabilization. • Bleed off the pressure and record the volume of mud recovered. • Plot the data to determine the LOT /FIT pressure at the shoe as EMW. • Submit the test results to the Pioneer drilling engineer for distribution as required. Pioneer Natural Resources Last Revised: July 16, 2009 ODSN -45A Permit To Drill Page 8 of 9 • • ODSN -45A Drilling Hazards and Contingencies POST THIS NOTICE IN THE DOGHOUSE Well Control • No abnormally pressured zones are expected to be encountered while drilling this well as YP p g none were seen in drilling the original ODSN -45i or the Kalubik 2 well which bracket this lateral sidetrack. Lost Circulation /Breathing /Formation Stability /Stuck Pipe Events • Be on the look out for lost circulation events and follow the Decision Tree as required. • Should we end up kicking off of the whipstock and enter the shale section above the Torok Sands, we might have to increase the mud weight to compensate for the instability of this shale. Estimate that we may need -10.5 ppg EMW to hold these shales open for the duration of the well. Additionally, should we drill out the bottom of the sands, this same mud weight or higher may be required. Kick Tolerance /Integrity Testing Kick Tolerance / Integrity Testing Summary Table Casing set / Interval Maximum Influx Mud Exp Pore Min LOT / FIT Volume Weight Press 7 -5/8" Interm / 6 -3/4" hole Infinite 9.3 2261 12.5 ppg (FIT) NOTE: All LOT / FIT will be taken with a minimum of 20 -ft and a maximum of 50 -ft of new hole drilled outside of the previous casing string Hydrogen Sulfide • The Oooguruk Drill Site is not designated as an H site, however Standard Operating Procedures for H precautions should be followed at all times. Faults • No seismically visible faults are expected to be crossed and sub seismic faults with throws <25' may be encountered. Losses may be associated with these faults. CONSULT THE ODS DATA SHEET FOR ADDITIONAL INFORMATION (still in development) Pioneer Natural Resources Last Revised: July 16, 2009 ODSN -45A Permit To Drill Page 9 of 9 • • ODSN -45A Proposed Completion - WP13 Well Head: 10 -3/4 ", 5K, VetcoGray Tree: 3 -1/2 ", 5K, Horizontal 16" Conductor 10:230- 153' MDrkb / 153' TVDrkb j 10 -3/4 ", 45.5# L-80 BTC, 9.95" ID j 4973' MDrkb / 3438' TVDrkb • • ill � 4-1/2" 12.6 # L - 80 Hyd 521 @ 15038' MDrkb / 5016' TVDrkb 1 Cement Squeeze prior to the 00 00 00 00 00 00 00 00 00 sidetrack operations 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 J Estimated Top of Cement @ EZSV 10100' MDrkb / 5017'rVDrkb 10100' MD / 5017' TVDrkb Cement above packer: 2.5bbl / 50' Cement below packer: 79.5bbI / 1277' to 7 -5/8" shoe + 6 100' w/ 30% excess bullhead below shoe Top of 6" liner, 10,806' MDrkb / 5239' TVDrkb 7 -5/8 ", 29.7# L -80 BTC -M, 6.875" ID Top of Inner String fish, 10,825MDrkb l it 11377' MDrkb / 5412' TVDrkb Live Severing Charge w/ 2.0" OD ■ 1 Debris Catcher, 2.0" ID 12413' MDrkb, Top of Expanded Section, / 6 ", 18.6# L -80 Expanded to 6.767" OD, 6.19" ID, 6.131" Drift Connection unable to hold pressure, 13,433 MDrkb ttourr I Expansion Cone Expandable csg shoe 13,513' MDrkb / 6071' TVDrkb 1 k 13866' MDrkb / 6166' TVDrkb Hole Fill and Un- consolidated Cement Date: Revision By: Comments PIONEER 6/1/2009 JDF Proposed Completion 6 /16/2009 VHH Updated to current directional plan ODSN -45A .Ai. r16UJnlh; ,S% Proposed Well Schematic • • ODSN -45i Nuiqsut Injector, P &A /Operation Shutdown Schematic Well Head: 10 -3/4 ", 5K, VetcoGray Tree: 3 -1/2", 5K, Horizontal 16" Conductor I ■ 153' MDrkb / 153' TVDrkb 2 -7/8" 6.5# L -80 IBT -M, 2100' TVDrkb • Diesel to —2100' TVDrkb Seawater from —2100' TVDrkb 10 -3/4 ", 45.5# L -80 BTC, 9.95" ID 4973' MDrkb / 3438' TVDrkb EZSV 10100' MDrkb / 5017TVDrkb Estimated Cement Cement above packer: 2.5bbl / 50' E ed Top of ement @ stimat d T / 5of C TVDrkb Cement below packer: 79.5bbI / 1277' to 7 -5/8" shoe + 100' w/ 30% excess bullhead below shoe Top of 6" liner, 10,806' MDrkb / 5239' TVDrkb Top of Inner String fish, 10,825MDrkb 0 7-5/ 8", III Live Severing Charge w/ 2.0" OD 29.7# L -80 BTC -M, 6.875" ID Debris Catcher, 2.0" ID 11377' MDrkb / 5412' TVDrkb 12413' MDrkb, Top of Expanded Section, / 6 ", 18.6# L -80 Expanded to 6.767" OD, 6.19" ID, 6.131" Drift The highly stressed and unstable HRZ, Kalubik and Miluveach shales in the openhole section \ below the liner from 13513' and I 1 Connection unable to hold pressure, 13,433 MDrkb to the top of the Nuiqsut Expansion Cone formation at 13812' and will 1 collapse and effectively seal 1 ■ Expandable csg shoe 13,513' MDrkb / 6071' TVDrkb above the Nuiqsut — qualifying as - % 20AAC25.112(a)(3) 111 7 13866' MDrkb / 6166' TVDrkb Hole Fill and Un- consolidated Cement Date: Revision By: Comments P 0 N C E R 9/22/2008 JDF Proposed Completion v2 L 10/13/2008 Alex Vaughan P &A/ Operation Shutdown Condition ODSN -45i Injector NATURAL RESOURCES ALASKA well Schematic • SURVEY PROGRAM ANTI- COLLISION SETTINGS Date: 2009 -06- 11700:00:00 Validated: Yes Version: Interpolation Method: MD, interval: 25.0 Depth Range From: 10038.0 To 15038.0 Depth From Depth To Survey/Plan Tool Results Limited By: Centre Distance: 1699.5 50.0 533.0 ODSN -45i 1N13 Pill Gyro CB- GYRO -SS Reference: Plan: ODSN -45A Moraine NW wp13 (ODSN- 45 /ODSN -45A Moraine) 575.4 10037.9 ODSN -45i IN13 P111 MWD MWD+SAG+CA +II1R+1vLS Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference 10037.9 15037.8 ODSN -45A Moraine NW wpIDIWD+SAG+CA +IIFR+MS FOR USE FROM 10038' TO TD 0 From Color To MD 111 0 200 30 330 . 250 500 500 750 330 30 750 _. 1000 1000 1250 1250 1500 1500 ____......... 1750 20 v-----•---.. 1750 2000 2000 2250 300 � 60 300 60 2250 - - -° 2500 2500 2750 2750 3000 / ./- 10 3000 3250 3250 3500 l ' 3500 3750 1 3750 4000 4000 5000 270 ag �:�� �1 4.. 5000 8000 mily 6000 7000 • 900 7000 5000 lb. 5000 0 270 -- - ±7 90 0000 11000 I 10000 11000 1 11000 12000 1 12000 13000 13000 14000 240 12 14000 15000 1 1 15000 16000 \ 0 16000 " "" " "" 17000 1 17000 18000 / 15000 19000 Illir 19000 20000 210 ��150 1 240 120 20000 21000 30 - 1 37000 ' 3000 180 ODSN -45i IN13 PB1 ODSN -451 IN13 P' "it.:lrveys 75 - Travelling Cylinder Azimuth (TFO+AZI) [bearing] vs Centre to Centre Separation 120 ft /in] ODSN -45i IN13 PB1 • 210 150 ^� ODSN -45i IN13 PBI Surveys 100 180 Travelling Cylinder Azimuth (TFO +AZI) 'bearing] vs Centre to Centre Separation )50 ft/inl I REFERENCE INFORMATION Well Planning - Pioneer - Oooguruk SECTION DETAILS Sec MD Inc At WD +WS +5/48) DLag TFS+. V544 T Co- ordinate N/ Reference: Well ODSN-45 Calculation Me - Slot ODS-45, True North 1 10037.9 70 231.88 4997.2 62675 6977.8 ODD 5.00 15845 1 Q Method: Minimum Curvature 2 10057.9 7228 23324 5003.4 62785 89925 1250 4520 1804.7 Vertical (TVD) Reference: 42.7' +13.5 @56.2ft (Nabors 19AC) 3 10207A 78.18 242.84 5041.1 6354.4 -4115.5 750 55.54 16943 Error System: ISCWSA 4 102112 78.18 242.84 5041.9 6356.1 45182 0.00 050 18965 Section (VS) Reference: Slot - ODS- 45(0.0N, 0.0E) 5 113172 90.00 32020 51762 6146.7 -5112.0 750 87.33 2701.4 Moraine NW v12 T1A Measured Depth Reference: 42.T + 13.5 56.2ft Nabors 19 AC) Scan Method: Tray. Cylinder North 6 12267.0 90.00 320.00 51762 -5403.7 .5735.5 050 050 35415 ( ) E Surface: Elliptical Conic 7 12478.6 95.76 32020 51865 82582 -5556.1 350 651 3708.0 Calculation Method: Minimum Curvature P 5 13876.1 95.78 32050 5025.9 4192.1 6752.2 0.00 000 49112 Warning Method: Rules Based 1 15039.0 9000 320200 5 -33 .74488.9 300 1 000 59172 Moraine NWV13 72 NAD 27 ASP Zone 4 : WELL DETAILS: ODSN45 Ground Level: 13.5 +N / -S +E/ -W Northing Easting Latittude Longitude Slot 0.0 0.0 6031005.53 469821.86 70° 29' 44.804 N 150° 14' 48.350 W ODS-45 • Well Planning - Pioneer - Oooguruk Oooguruk Developement Oooguruk Drill Site ODSN -45 - Slot ODS-45 ODSN -45A Moraine Plan: ODSN -45A Moraine NW wp13 Standard Proposal Report 11 June, 2009 HALLIBURTDN Sperry Drilling Services ■ COMPANY DETAILS: Well Planning • Pioneer HALLIBURTON Design: ODSN - 45A Moraine NW wp13 Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Tray. Cylinder North Sperry Drilling Error Surface: Elliptical Conic PIONEER Waming Method: Rules Based - CASING DETAILS TVD MD Name Size 3478.5 5098.4 10 314" 10.751 4997.2 10037.9 7 5/8" 7.625 -750 W 0 II 750 - 10° 1500 Start Dir 12.00/100' TFO 90L 10037.90' MD, 4997.20 TVD 2250 30° o 1 Start Dir 3.0/100' 12287.00' MD, 5176.20 TVD in 50° Start Dir 7.0/100' 10057.90' MD, 5003.70 TVD 3000 113 / End Dir 12479.60' MD, 5166.50 TVD m 10 3/4" End Dir 10207.40' MD, 5041.10 TVD 0 ' Start Dir 3.0/100' 13876.10' MD, 5025.90 TVD cu I > 3750 z , I Start Dir 7.0 /100' 10211.20' MD, 5041.90 TVD , a 2 , /' / End Dir 14068.70' MD, 5016.20 TVD i i / End Dir 11317.00' MD, 5176.20 TVL7 , ' Total Depth at 15038.00' MD, 5016.20' TVD • 4500 5250 7 5/8" Moraine NW v12 T1 \ ODSN -45A Moraine NW wp13 7 5/8" Moraine NW v13 T2 6000 ODSN -45i IN13 PB1 Surveys 6750 7500 iiiiiiiiiIiiIiiiiiIpiiii -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 Vertical Section at 290.00bearing (1500 ft /in) _ _.,,,, 1 HALLiBUATON COMPANY DETAILS: Well Planning - Pioneer Design: ODSN 45A Moraine NW wp13 Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Tray. Cylinder North Sperry Drilling CASING DETAILS Error Surface: Elliptical Conic PIONEER Warning Method: Rules Based . TVD MD Name Size 3478.5 5098.4 10 3/4" 10.751 4997.2 10037.9 7 5/8" 7.625 750- 0- - 2000 -750- - 3000 -1500 — -2250— ,/,/ Total Depth at 15038.00' MD, 5016.20' TVD 10 3/4 0 o u0 ODSN -45A Moraine NW wp13 -3000— End Dir 14068.70' MD, 5016.20 TVD + - st - Start Dir 3.0/100' 13876.10' MD, 5025.90 TVD 0 Z -3750— - - • , - "End Dir 12479.60' MD, 5166.50 TVD 1.000 o - !Moraine NW v13 T2 -4500— Start Dir 3:0/100' 12287.00' MD, 5176.20 TVD 5250— ODSN -45i IN13 PB1 Surveys Moraine NW v12 T1A Start Dir 12.00/100' TFO 90L 10037.90' MD, 4997.20 TVD -6000— • 7 5/8" - ' / - Start Dir 7.0/100' 10057.90' MD, 5003.70 TVD - i mod- - O -6750— - End Dir 11317.00' MD, 5176.20 TVD _ End Dir 10207.40' MD, 5041.10 TVD -7500— Start Dir 7.0/100' 10211.20' MD, 5041.90 TVD iii 1 1 1 1 1 I f 1 1 1 I 1 1 1 1 I 1 1 1 1 I miiiii 1 1 1 1 1 1 1 1 1 1 1 I 1 1 1 1 1 1 1 1 1 1 1 1 1 1 I 1 1 1 1 I 1 1 1 1 I 1 1 1 1 I 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 11 i r -10500 -9750 -9000 -8250 -7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 0 750 1500 2250 3000 West( -) /East( +) (1500 ft/in) • • Sperry Drilling HALL1BURT0N Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -45 - Slot ODS -45 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 42.7' + 13.5 @ 56.2ft (Nabors 19 AC) Project: Oooguruk Developement MD Reference: 42.7' + 13.5 @ 56.2ft (Nabors 19 AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -45 Survey Calculation Method: Minimum Curvature Wellbore: ODSN -45A Moraine Design: ODSN -45A Moraine NW wp13 S.,- Project Oooguruk Developement 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 Oooguruk Drill Site Site Position: Northing: 6,031,151.32ft " Latitude: 70° 29' 46.242 N From: Map Easting: 469,920.45ft Longitude: 150° 14' 45.465 W Position Uncertainty: 0.0 ft Slot Radius: in Grid Convergence: -0.23 ? Well ODSN -45 - Slot ODS -45 Well Position +NI-S 0.0 ft Northing: 6,031,005.53 ft , Latitude: 70° 29' 44.804 N +E / -W 0.0 ft Easting: 469,821.86 ft . Longitude: 150° 14' 48.350 W Position Uncertainty 0.0 ft Wellhead Elevation: ft Ground Level: 13.5ft ,. Wellbore ODSN -45A Moraine Magnetics Model Name Sample Date i i ... Dip Field Strength '" 3 ( ?) . , , ;; r�; ,s A ,( ?) (nT) IGRF200510 6/5/2009 22.24 80.81 57,736 Design ODSN -45A Moraine NW wp13 Audit Notes: Version: Phase: PLAN Tie On Depth: 10,037.9 Vertical Section: Depth From a h ° +N/-S '`" " +EIW Direction (ft) . i .' : a" " ,7: (ft) (bearing) 42.7 0.0 0.0 290.00 Plan Sections Measured t , ," V I Dogleg Build Turn Depth = R on -' %� Depth a' £ 41/-S +E/ W Rate Rate Rate Tool Face (ft) . ', ( ?) (bea . Y ft) " (ft) (ft) ( ?I100ft) ( ? /100ft) ( ?MOOft) ( ?) 10,037.9 70.98 231.86 4,997.2 4,941.0 - 6,267.0 - 3,977.8 0.00 0.00 0.00 0.00 10,057.9 72.68 233.64 5,003.4 4,947.2 - 6,278.5 - 3,992.9 12.00 8.53 8.89 45.00 10,207.4 78.18 242.84 5,041.1 4,984.9 - 6,354.4 - 4,115.8 7.00 3.68 6.16 59.54 10,211.2 78.18 242.84 5,041.9 4,985.7 - 6,356.1 - 4,119.2 0.00 0.00 0.00 0.00 11,317.0 90.00 320.00 5,176.2 5,120.0 - 6,146.7 - 5,112.0 7.00 1.07 6.98 87.33 12,287.0 90.00 320.00 5,176.2 5,120.0 - 5,403.7 - 5,735.5 0.00 0.00 0.00 0.00 12,479.6 95.78 320.00 5,166.5 5,110.3 - 5,256.4 - 5,859.1 3.00 3.00 0.00 -0.01 13,876.1 95.78 320.00 5,025.9 4,969.7 - 4,192.1 - 6,752.2 0.00 0.00 0.00 0.00 14,068.7 90.00 320.00 5,016.2 4,960.0 - 4,044.8 - 6,875.8 3.00 -3.00 0.00 179.99 15,038.0 90.00 320.00 5,016.2 4,960.0 - 3,302.2 - 7,498.9 0.00 0.00 0.00 0.00 6/11/2009 4:30:46PM Page 2 COMPASS 2003.16 Build 428 • III • Sperry Drilling HALLIBURTON Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -45 - Slot ODS -45 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 42.7' + 13.5 @ 56.2ft (Nabors 19 AC) Project: Oooguruk Developement MD Reference: 42.7' + 13.5 @ 56.2ft (Nabors 19 AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -45 Survey Calculation Method: Minimum Curvature Wellbore: ODSN -45A Moraine Design: ODSN -45A Moraine NW wp13 Planned Survey Measured Vertical Map Depth Inclination Azimuth Depth TVDss 41/-S +EJ-W Northing ': , OLS Vert Section (ft) ( ?) (bearing) (ft) ft (ft) (ft) (ft) , A ' �) ` < "' ? ":_. 43.80 100.0 0.30 191.03 100.0 43.8 -0.2 0.1 6,031,005.29 469,821.93 0.00 -0.15 200.0 0.47 153.85 200.0 143.8 -1.0 0.2 6,031,004.57 469,822.07 0.30 -0.53 300.0 0.79 169.96 300.0 243.8 -2.0 0.3 6,031,003.57 469,822.16 0.36 -0.96 400.0 1.57 178.84 400.0 343.8 -3.9 0.4 6,031,001.61 469,822.29 0.80 -1.76 500.0 2.60 179.76 499.9 443.7 -7.7 0.5 6,030,997.86 469,822.33 1.04 -3.10 600.0 3.18 170.61 599.8 543.6 -12.7 0.8 6,030,992.84 469,822.59 0.73 -5.08 700.0 4.26 162.85 699.6 643.4 -18.9 2.4 6,030,986.59 469,824.21 1.19 -8.76 800.0 5.31 162.17 799.2 743.0 -27.0 4.9 6,030,978.55 469,826.69 1.05 -13.87 900.0 5.74 161.07 898.7 842.5 -36.3 8.0 6,030,969.24 469,829.75 0.45 -19.96 1,000.0 6.62 161.95 998.2 942.0 -46.0 11.4 6,030,959.47 469,833.06 0.88 -26.44 1,100.0 8.13 164.06 1,097.3 1,041.1 -58.5 15.2 6,030,946.97 469,836.80 1.53 -34.28 1,200.0 9.30 165.37 1,196.2 1,140.0 -73.1 19.1 6,030,932.40 469,840.69 1.19 -42.97 1,300.0 10.76 167.07 1,294.7 1,238.5 -89.9 23.3 6,030,915.54 469,844.79 1.49 -52.65 1,400.0 12.63 169.54 1,392.6 1,336.4 -109.7 27.4 6,030,895.78 469,848.81 1.93 -63.26 1,500.0 12.87 170.81 1,490.0 1,433.8 -131.8 31.2 6,030,873.58 469,852.50 0.37 -74.40 1,600.0 13.74 172.26 1,587.4 1,531.2 - 154.3 34.5 6,030,851.07 469,855.78 0.93 -85.25 1,700.0 14.71 172.58 1,684.3 1,628.1 -178.8 37.8 6,030,826.64 469,858.88 0.98 -96.61 1,800.0 16.23 172.10 1,780.7 1,724.5 -205.1 41.3 6,030,800.26 469,862.31 1.52 - 108.95 1,900.0 18.02 177.88 1,876.3 1,820.1 -234.4 43.9 6,030,770.98 469,864.82 2.47 - 121.44 2,000.0 21.12 181.40 1,970.5 1,914.3 -267.9 44.0 6,030,737.53 469,864.81 3.31 - 133.00 2,100.0 24.43 188.64 2,062.7 2,006.5 -306.4 40.4 6,030,698.96 469,861.01 4.33 - 142.77 2,200.0 25.66 191.72 2,153.4 2,097.2 -347.9 33.0 6,030,657.49 469,853.44 1.79 - 150.01 2,300.0 28.72 195.38 2,242.4 2,186.2 -392.2 22.1 6,030,613.28 469,842.37 3.49 - 154.92 2,400.0 33.51 199.33 2,328.0 2,271.8 -441.4 6.8 6,030,564.16 469,826.83 5.20 - 157.33 2,500.0 37.23 201.06 2,409.5 2,353.3 -495.8 -13.2 6,030,509.86 469,806.62 3.85 - 157.14 2,600.0 41.15 202.53 2,487.0 2,430.8 -554.3 -36.9 6,030,451.41 469,782.69 4.03 - 154.90 2,700.0 44.86 203.95 2,560.0 2,503.8 -617.2 -63.5 6,030,388.61 469,755.90 3.83 - 151.48 2,800.0 49.69 207.02 2,627.2 2,571.0 -683.9 -95.5 6,030,322.05 469,723.59 5.34 - 144.18 2,900.0 52.46 207.73 2,689.7 2,633.5 -753.2 -131.5 6,030,252.90 469,687.32 2.82 - 134.06 3,000.0 54.32 208.91 2,749.4 2,693.2 -824.0 -169.4 6,030,182.36 469,649.15 2.09 - 122.64 3,100.0 56.84 210.25 2,806.0 2,749.8 -895.6 -210.1 6,030,110.92 469,608.11 2.75 - 108.83 3,200.0 58.86 210.23 2,859.0 2,802.8 -968.7 -253.1 6,030,038.00 469,564.86 2.01 -93.48 3,300.0 60.64 209.75 2,909:5 2,853.3 - 1,043.5 -296.2 6,029,963.38 469,521.42 1.83 -78.52 3,400.0 63.65 210.49 2,956.4 2,900.2 - 1,119.9 -340.4 6,029,887.10 469,476.99 3.09 -63.21 3,500.0 68.55 210.70 2,997.7 2,941.5 - 1,198.2 -386.9 6,029,809.03 469,430.13 4.90 -46.24 3,600.0 73.08 210.40 3,030.3 2,974.1 - 1,279.8 -434.5 6,029,727.58 469,382.23 4.55 -29.46 3,700.0 73.49 209.16 3,058.8 3,002.6 - 1,363.0 -482.2 6,029,644.68 469,334.14 1.25 -13.01 3,800.0 75.67 213.25 3,085.4 3,029.2 - 1,445.4 -532.2 6,029,562.50 469,283.82 4.50 5.79 3,900.0 75.61 213.06 3,110.1 3,053.9 - 1,526.6 -585.1 6,029,481.52 469,230.64 0.20 27.68 4,000.0 74.91 215.26 3,135.6 3,079.4 - 1,606.5 -639.4 6,029,401.75 469,176.02 2.24 51.35 4,100.0 74.50 216.75 3,161.8 3,105.6 - 1,684.4 -696.4 6,029,324.12 469,118.71 1.50 78.28 4,200.0 73.02 216.85 3,189.9 3,133.7 - 1,761.5 -753.5 6,029,247.26 469,061.26 1.48 105.61 4,300.0 72.03 218.81 3,219.8 3,163.6 - 1,836.8 -812.2 6,029,172.24 469,002.31 2.12 134.98 4,400.0 71.01 219.21 3,251.8 3,195.6 - 1,910.1 -872.2 6,029,099.20 468,941.96 1.08 166.35 4,500.0 70.87 218.96 3,284.4 3,228.2 - 1,983.8 -931.4 6,029,025.71 468,882.54 0.28 196.69 6/11/2009 4:30:46PM Page 3 COMPASS 2003.16 Build 428 . Sperry Drilling HALLIBURTON Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -45 - Slot ODS -45 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 42.7' + 13.5 @ 56.2ft (Nabors 19 AC) Project: Oooguruk Developement MD Reference: 42.7 + 13.5 @ 56.2ft (Nabors 19 AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -45 Survey Calculation Method: Minimum Curvature Wel!bore: ODSN -45A Moraine Design: ODSN -45A Moraine NW wp13 Planned Survey Measured Vertical Map e. Depth Inclination Azimuth Depth TVDss +N/-S +E/ -W Northing -.1 DLS Vert Section (ft) ( ?) (bearing) (ft) ft (ft) (ft) (ft) : ':' t, ft) ` _ ,261.06 . "fin'` -h _. 4,600.0 70.93 219.06 3,317.3 3,261.1 - 2,056.8 -991.3 6,028,952.95 468,822.32 0.12 228.04 4,700.0 71.05 217.98 3,349.7 3,293.5 - 2,130.9 - 1,050.0 6,028,879.08 468,763.28 1.03 257.90 4,800.0 70.82 217.93 3,382.4 3,326.2 - 2,205.6 - 1,108.0 6,028,804.66 468,705.01 0.23 286.83 4,900.0 71.18 218.08 3,415.1 3,358.9 - 2,280.0 - 1,166.3 6,028,730.52 468,646.47 0.39 316.12 5,000.0 71.55 218.27 3,447.0 3,390.8 - 2,354.5 - 1,224.8 6,028,656.21 468,587.62 0.41 345.64 5,098.4 71.01 217.40 3,478.5 3,422.3 - 2,428.1 - 1,282.1 6,028,582.88 468,530.03 1.00 374.32 10 314° 5,100.0 71.00 217.39 3,479.0 3,422.8 - 2,429.3 - 1,283.0 6,028,581.71 468,529.13 1.19 374.76 5,200.0 70.78 216.39 3,511.8 3,455.6 - 2,504.9 - 1,339.7 6,028,506.38 468,472.11 0.96 402.21 5,300.0 71.52 216.04 3,544.1 3,487.9 - 2,581.2 - 1,395.7 6,028,430.31 468,415.85 0.81 428.70 5,400.0 72.61 214.58 3,574.9 3,518.7 - 2,658.8 - 1,450.6 6,028,352.87 468,360.58 1.77 453.78 5,500.0 72.80 213.99 3,604.6 3,548.4 - 2,737.8 - 1,504.4 6,028,274.18 468,306.52 0.59 477.29 5,600.0 72.82 213.98 3,634.1 3,577.9 - 2,817.0 - 1,557.8 6,028,195.20 468,252.79 0.02 500.39 5,700.0 72.87 213.38 3,663.6 3,607.4 - 2,896.3 - 1,611.1 6,028,116.08 468,199.21 0.58 523.32 5,800.0 72.67 211.52 3,693.2 3,637.0 - 2,977.0 - 1,662.2 6,028,035.63 468,147.77 1.78 543.76 5,900.0 72.42 210.81 3,723.2 3,667.0 - 3,058.7 - 1,711.3 6,027,954.07 468,098.29 0.72 561.98 6,000.0 72.33 211.68 3,753.6 3,697.4 - 3,140.3 - 1,760.5 6,027,872.68 468,048.80 0.83 580.27 6,100.0 72.71 212.06 3,783.7 3,727.5 - 3,221.0 - 1,811.4 6,027,792.26 467,997.54 0.52 600.56 6,200.0 72.70 211.27 3,813.2 3,757.0 - 3,302.4 - 1,861.3 6,027,711.00 467,947.34 0.76 619.56 6,300.0 72.35 212.24 3,843.3 3,787.1 - 3,383.7 - 1,911.2 6,027,629.91 467,897.15 0.99 638.62 6,400.0 72.39 212.09 3,873.7 3,817.5 - 3,464.0 - 1,962.5 6,027,549.84 467,845.54 0.14 659.35 6,500.0 72.52 211.39 3,903.8 3,847.6 - 3,545.2 - 2,012.4 6,027,468.84 467,795.25 0.68 678.53 6,600.0 72.40 211.89 3,933.9 3,877.7 - 3,626.5 - 2,062.3 6,027,387.76 467,745.06 0.49 697.58 6,700.0 71.94 213.39 3,964.5 3,908.3 - 3,706.8 - 2,113.5 6,027,307.73 467,693.51 1.50 718.28 6,800.0 71.77 214.70 3,995.7 3,939.5 - 3,785.5 - 2,166.8 6,027,229.27 467,639.95 1.25 741.40 6,900.0 71.71 215.43 4,027.0 3,970.8 - 3,863.2 - 2,221.4 6,027,151.81 467,585.04 0.70 766.13 7,000.0 71.68 215.82 4,058.4 4,002.2 - 3,940.3 - 2,276.7 6,027,074.88 467,529.41 0.37 791.73 7,100.0 72.01 215.80 4,089.6 4,033.4 - 4,017.4 - 2,332.3 6,026,998.07 467,473.50 0.33 817.63 7,200.0 72.52 215.56 4,120.0 4,063.8 - 4,094.8 - 2,387.8 6,026,920.91 467,417.65 0.56 843.35 7,300.0 72.45 215.84 4,150.2 4,094.0 - 4,172.1 - 2,443.5 6,026,843.75 467,361.65 0.27. 869.22 7,400.0 72.68 215.33 4,180.0 4,123.8 - 4,249.8 - 2,499.1 6,026,766.38 467,305.78 0.54 894.88 7,500.0 72.07 214.75 4,210.3 4,154.1 - 4,327.8 - 2,553.7 6,026,688.54 467,250.82 0.83 919.53 7,600.0 71.82 214.78 4,241.4 4,185.2 - 4,406.0 - 2,607.9 6,026,610.63 467,196.40 0.25 943.66 7,700.0 71.98 215.04 4,272.4 4,216.2 - 4,483.8 - 2,662.4 6,026,532.98 467,141.58 0.29 968.24 7,800.0 72.07 214.91 4,303.3 4,247.1 - 4,561.8 - 2,716.9 6,026,455.25 467,086.78 0.15 992.78 7,900.0 72.14 214.89 4,334.0 4,277.8 - 4,639.9 - 2,771.3 6,026,377.43 467,032.01 0.07 1,017.26 8,000.0 72.43 214.88 4,364.6 4,308.4 - 4,718.0 - 2,825.8 6,026,299.55 466,977.25 0.30 1,041.70 8,100.0 72.80 214.35 4,394.3 4,338.1 - 4,796.4 - 2,880.2 6,026,221.33 466,922.53 0.63 1,066.00 8,200.0 72.78 214.02 4,423.9 4,367.7 - 4,875.6 - 2,933.6 6,026,142.39 466,868.74 0.32 1,089.18 8,300.0 72.82 213.86 4,453.5 4,397.3 - 4,954.8 - 2,987.1 6,026,063.43 466,815.02 0.16 1,112.28 8,400.0 72.38 213.85 4,483.2 4,427.0 - 5,034.1 - 3,040.2 6,025,984.32 466,761.59 0.43 1,135.06 8,500.0 71.28 214.48 4,514.3 4,458.1 - 5,112.8 - 3,093.5 6,025,905.85 466,707.98 1.25 1,158.22 8,600.0 70.54 215.31 4,547.1 4,490.9 - 5,190.3 - 3,147.5 6,025,828.59 466,653.63 1.08 1,182.50 8,700.0 70.93 215.13 4,580.2 4,524.0 - 5,267.3 - 3,202.0 6,025,751.81 466,598.81 0.42 1,207.39 8,800.0 71.55 214.91 4,612.4 4,556.2 - 5,344.8 - 3,256.4 6,025,674.50 466,544.16 0.65 1,231.93 6/11/2009 4:30:46PM Page 4 COMPASS 2003.16 Build 42B • Sperry Drilling HALLIBURTOM Standard Proposal Report Database: ..EDM _Alaska Local Co- ordinate Reference: Well ODSN -45 - Slot ODS -45 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 42.7' + 13.5 @ 56.2ft (Nabors 19 AC) Project: Oooguruk Developement MD Reference: 42.7' + 13.5 @ 56.2ft (Nabors 19 AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -45 Survey Calculation Method: Minimum Curvature Wellbore: ODSN -45A Moraine Design: ODSN -45A Moraine NW wp13 Planned Survey Measured Vertical Map Depth Inclination Azimuth Depth TVDss +N/-$ +E/ -W Northing ng ; , DLS . Vert Section (ft) ( ?) (bearing) (ft) ft (ft) (ft) (ft) ! 4, {ft) . • :;. - 4,587.67 8,900.0 71.76 215.02 4,643.9 4,587.7 - 5,422.6 - 3,310.7 6,025,596.93 466,489.46 0.23 1,256.43 9,000.0 71.76 215.26 4,675.2 4,619.0 - 5,500.2 - 3,365.5 6,025,519.57 466,434.41 0.23 1,281.34 9,100.0 72.43 214.10 4,705.9 4,649.7 - 5,578.6 - 3,419.5 6,025,441.46 466,380.06 1.30 1,305.32 9,200.0 72.59 213.99 4,735.9 4,679.7 - 5,657.5 - 3,473.2 6,025,362.78 466,326.12 0.19 1,328.72 9,300.0 72.16 212.54 4,766.2 4,710.0 - 5,737.3 - 3,525.2 6,025,283.16 466,273.76 1.44 1,350.32 9,400.0 71.84 212.79 4,797.2 4,741.0 - 5,817.4 - 3,576.4 6,025,203.25 466,222.26 0.40 1,371.01 9,500.0 71.71 214.57 4,828.3 4,772.1 - 5,896.8 - 3,628.7 6,025,124.13 466,169.66 1.70 1,393.00 9,600.0 71.23 218.31 4,860.1 4,803.9 - 5,973.1 - 3,684.9 6,025,048.04 466,113.13 3.58 1,419.74 9,700.0 71.44 221.48 4,892.4 4,836.2 - 6,045.4 - 3,745.9 6,024,975.96 466,051.85 3.01 1,452.32 9,800.0 72.20 224.07 4,923.5 4,867.3 - 6,115.4 - 3,810.3 6,024,906.31 465,987.19 2.57 1,488.90 9,900.0 72.21 227.19 4,953.9 4,897.7 - 6,182.0 - 3,878.4 6,024,839.99 465,918.83 2.97 1,530.10 10,000.0 71.38 230.52 4,985.0 4,928.8 - 6,244.5 - 3,949.9 6,024,777.70 465,847.08 3.27 1,575.90 10,037.9 70.98 231.86 4,997.2 4,941.0 - 6,267.0 - 3,977.8 6,024,755.32 465,819.02 3.52 1,594.48 Start Dir 12.00/100' TFO 90L 10037.90' MD, 4997.20 TVD - 75/8" 10,057.9 72.68 233.64 5,003.4 4,947.2 - 6,278.5 - 3,992.9 6,024,743.90 465,803.88 12.02 1,604.74 Start Dir 7.0/100' 10057.90' MD, 5003.70 TVD 10,100.0 74.20 236.28 5,015.4 4,959.2 . - 6,301.7 - 4,026.0 6,024,720.87 465,770.74 7.00 1,627.88 10,200.0 77.90 242.40 5,039.6 4,983.4 - 6,351.1 - 4,109.4 6,024,671.79 465,687.10 7.00 1,689.39 10,207.4 78.18 242.84 5,041.1 4,984.9 - 6,354.4 - 4,115.8 6,024,668.50 465,680.67 6.98 1,694.28 End Dir 10207.40' MD, 5041.10TVD 10,211.2 78.18 242.84 5,041.9 4,985.7 - 6,356.1 - 4,119.2 6,024,666.82 465,677.36 0.00 1,696.81 Start Dir 7.0/100' 10211.21)" MD, 5041.90 TVD 10,300.0 78.54 249.18 5,059.8 5,003.6 - 6,391.5 - 4,198.6 6,024,631.80 465,597.79 7.00 1,759.37 10,400.0 79.11 256.29 5,079.2 5,023.0 - 6,420.6 - 4,292.2 6,024,603.09 465,504.06 7.00 1,837.39 10,500.0 79.84 263.38 5,097.5 5,041.3 - 6,437.9 - 4,388.9 6,024,586.16 465,407.29 7.00 1,922.35 10,600.0 80.72 270.43 5,114.4 5,058.2 - 6,443.2 - 4,487.3 6,024,581.25 465,308.92 7.00 2,012.95 10,700.0 81.74 277.44 5,129.7 5,073.5 - 6,436.4 - 4,585.8 6,024,588.43 465,210.43 7.00 2,107.86 10,800.0 82.88 284.41 5,143.1 5,086.9 - 6,417.6 - 4,683.0 6,024,607.59 465,113.27 7.00 2,205.66 10,900.0 84.12 291.34 5,154.4 5,098.2 - 6,387.2 - 4,777.5 6,024,638.46 465,018.91 7.00 2,304.88 11,000.0 85.45 298.25 5,163.5 5,107.3 - 6,345.4 - 4,867.9 6,024,680.57 464,928.75 7.00 2,404.06 11,100.0 86.85 305.13 5,170.2 5,114.0 - 6,293.0 - 4,952.7 6,024,733.29 464,844.12 7.00 2,501.70 11,200.0 88.29 311.99 5,174.4 5,118.2 - 6,230.8 - 5,030.8 6,024,795.84 464,766.31 7.00 2,596.36 11,300.0 89.75 318.83 5,176.2 5,120.0 - 6,159.6 - 5,101.0 6,024,867.28 464,696.46 7.00 2,686.61 11,317.0 90.00 320.00 5,176.2 5,120.0 - 6,146.7 - 5,112.0 6,024,880.23 464,685.46 7.00 2,701.41 End Dir 11317.00' MD, 517620 TVD - Moraine NW v12 T1A 11,400.0 90.00 320.00 5,176.2 5,120.0 - 6,083.1 - 5,165.4 6,024,944.03 464,632.37 0.00 2,773.30 11,500.0 90.00 320.00 5,176.2 5,120.0 - 6,006.5 - 5,229.6 6,025,020.89 464,568.40 0.00 2,859.90 11,600.0 90.00 320.00 5,176.2 5,120.0 - 5,929.9 - 5,293.9 6,025,097.74 464,504.44 0.00 2,946.50 11,700.0 90.00 320.00 5,176.2 5,120.0 - 5,853.3 - 5,358.2 6,025,174.60 464,440.48 0.00 3,033.11 11,800.0 90.00 320.00 5,176.2 5,120.0 - 5,776.7 - 5,422.5 6,025,251.46 464,376.52 0.00 3,119.71 11,900.0 90.00 320.00 5,176.2 5,120.0 - 5,700.1 - 5,486.8 6,025,328.31 464,312.56 0.00 3,206.31 12,000.0 90.00 320.00 5,176.2 5,120.0 - 5,623.5 - 5,551.0 6,025,405.17 464,248.60 0.00 3,292.91 12,100.0 90.00 320.00 5,176.2 5,120.0 - 5,546.9 - 5,615.3 6,025,482.03 464,184.64 0.00 3,379.52 12,200.0 90.00 320.00 5,176.2 5,120.0 - 5,470.3 - 5,679.6 6,025,558.89 464,120.68 0.00 3,466.12 6/11/2009 4 :30:46PM Page 5 COMPASS 2003.16 Build 428 • Sperry Drilling HALLIBURTOR Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -45 - Slot ODS -45 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 42.7' + 13.5 @ 56.2ft (Nabors 19 AC) Project: Oooguruk Developement MD Reference: 42.7' + 13.5 @ 56.2ft (Nabors 19 AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -45 Survey Calculation Method: Minimum Curvature Welibore: ODSN -45A Moraine Design: ODSN -45A Moraine NW wp13 Planned Survey . ti- Measured Vertical Map Depth Inclination Azimuth Depth TVDss +N/-S +E/ -W Northing ,; DLS Vert Section (ft) ( ?) (bearing) (ft) ft (ft) (ft) (ft) a ft) : ' , .'. >. 5,120.00 12,287.0 90.00 320.00 5,176.2 5,120.0 - 5,403.7 - 5,735.5 6,025,625.73 464,065.05 0.00 3,541.44 Start Dir 3.0/100' 12287.00' MD, 5176.20 TVD 12,300.0 90.39 320.00 5,176.2 5,120.0 - 5,393.7 - 5,743.9 6,025,635.74 464,056.72 2.99 3,552.72 12,400.0 93.39 320.00 5,172.9 5,116.7 - 5,317.1 - 5,808.1 6,025,712.55 463,992.80 3.00 3,639.27 12,479.6 95.78 320.00 5,166.5 5,110.3 - 5,256.4 - 5,859.1 6,025,773.51 463,942.07 3.00 3,707.96 End Dir 12479.60' MD, 5166.50 TVD 12,500.0 95.78 320.00 5,164.4 5,108.2 - 5,240.8 - 5,872.2 6,025,789.12 463,929.07 0.00 3,725.56 12,600.0 95.78 320.00 5,154.4 5,098.2 - 5,164.6 - 5,936.1 6,025,865.59 463,865.43 0.00 3,811.72 12,700.0 95.78 320.00 5,144.3 5,088.1 - 5,088.4 - 6,000.1 6,025,942.06 463,801.79 0.00 3,897.88 12,800.0 95.78 320.00 5,134.2 5,078.0 - 5,012.2 - 6,064.0 6,026,018.52 463,738.16 0.00 3,984.05 12,900.0 95.78 320.00 5,124.2 5,068.0 - 4,936.0 - 6,128.0 6,026,094.99 463,674.52 0.00 4,070.21 13,000.0 95.78 320.00 5,114.1 5,057.9 - 4,859.7 - 6,191.9 6,026,171.45 463,610.88 0.00 4,156.38 13,100.0 95.78 320.00 5,104.0 5,047.8 - 4,783.5 - 6,255.9 6,026,247.92 463,547.24 0.00 4,242.54 13,200.0 95.78 320.00 5,094.0 5,037.8 - 4,707.3 - 6,319.8 6,026,324.38 463,483.61 0.00 4,328.70 13,300.0 95.78 320.00 5,083.9 5,027.7 - 4,631.1 - 6,383.8 6,026,400.85 463,419.97 0.00 4,414.87 13,400.0 95.78 320.00 5,073.8 5,017.6 - 4,554.9 - 6,447.7 6,026,477.31 463,356.33 0.00 4,501.03 13,500.0 95.78 320.00 5,063.8 5,007.6 - 4,478.7 - 6,511.7 6,026,553.78 463,292.69 0.00 4,587.19 13,600.0 95.78 320.00 5,053.7 4,997.5 - 4,402.5 - 6,575.7 6,026,630.24 463,229.06 0.00 4,673.36 13,700.0 95.78 320.00 5,043.6 4,987.4 - 4,326.2 - 6,639.6 6,026,706.71 463,165.42 0.00 4,759.52 13,800.0 95.78 320.00 5,033.6 4,977.4 - 4,250.0 - 6,703.6 6,026,783.17 463,101.78 0.00 4,845.69 13,876.1 95.78 320.00 5,025.9 4,969.7 - 4,192.1 - 6,752.2 6,026,841.34 463,053.37 0.00 4,911.23 Start Dir 3.0/100' 13876.10' MD, 5025.90 TVD 13,900.0 95.06 320.00 5,023.6 4,967.4 - 4,173.8 - 6,767.5 6,026,859.65 463,038.13 3.00 4,931.86 14,000.0 92.06 320.00 5,017.4 4,961.2 - 4,097.4 - 6,831.7 6,026,936.35 462,974.30 3.00 5,018.29 14,068.7 90.00 320.00 5,016.2 4,960.0 - 4,044.8 - 6,875.8 6,026,989.10 462,930.40 3.00 5,077.73 End Dir 1406830" MD, 5016.20 TVD Moraine NW v13 T2 14,100.0 90.00 320.00 5,016.2 4,960.0 - 4,020.8 - 6,895.9 6,027,013.20 462,910.35 0.00 5,104.88 14,200.0 90.00 320.00 5,016.2 4,960.0 - 3,944.2 - 6,960.2 6,027,090.05 462,846.39 0.00 5,191.48 14,300.0 90.00 320.00 5,016.2 4,960.0 - 3,867.6 - 7,024.5 6,027,166.91 462,782.43 0.00 5,278.08 14,400.0 90.00 320.00 5,016.2 4,960.0 - 3,791.0 - 7,088.8 6,027,243.77 462,718.47 0.00 5,364.69 14,500.0 90.00 320.00 5,016.2 4,960.0 - 3,714.3 - 7,153.1 6,027,320.62 462,654.51 0.00 5,451.29 14,600.0 90.00 320.00 5,016.2 4,960.0 - 3,637.7 - 7,217.3 6,027,397.48 462,590.55 0.00 5,537.89 14,700.0 90.00 320.00 5,016.2 4,960.0 - 3,561.1 - 7,281.6 6,027,474.34 462,526.59 0.00 5,624.49 14,800.0 90.00 320.00 5,016.2 4,960.0 - 3,484.5 - 7,345.9 6,027,551.20 462,462.63 0.00 5,711.10 14,900.0 90.00 320.00 5,016.2 4,960.0 - 3,407.9 - 7,410.2 6,027,628.05 462,398.66 0.00 5,797.70 15,000.0 90.00 320.00 5,016.2 4,960.0 - 3,331.3 - 7,474.4 6,027,704.91 462,334.70 0.00 5,884.30 15,038.0 90.00 320.00 5,016.2. 4,960.0 - 3,302.2 - 7,498.9 6,027,734.09 462,310.42 0.00 5,917.19 Total Depth at 15038.00' MD, 5016.20' TVD 6/11/2009 4:30:46PM Page 6 COMPASS 2003.16 Build 42B 1 • Sperry Drilling HALLIBURTOle Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -45 - Slot ODS -45 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 42.7' + 13.5 @ 56.2ft (Nabors 19 AC) Protect: Oooguruk Developement MD Reference: 42.7' + 13.5 @ 56.2ft (Nabors 19 AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -45 Survey Calculation Method: Minimum Curvature Welibore: ODSN -45A Moraine Design: ODSN -45A Moraine NW wp13 Targets �'' Target Name • t' - hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/ W : ! ?` w' ` • ing Easting - Shape ( ?) (bearing (ft) (ft) (�). : ' `� (ft) Moraine NW v12 T1A 0.00 359.98 5,176.2 - 6,146.7 - 5,112.0 6,024,880.23 464,685.46 - plan hits target - Point Moraine NW v13 T2 0.00 359.98 5,016.2 - 4,044.8 - 6,875.8 6,026,989.10 462,930.40 - plan hits target - Point Casing Points Measured Verticals ,T '' ' < Casing Hole Depth Dept Diameter Diameter (ft) (ft) pm -, (in) (in) 5,098.4 3,478.5 10 3/4" 10.751 12.250 10,037.9 4,997.2 7 5/8" 7.625 9.875 µ Plan Annotations ~ Measured Vertical Local ' CooMlnates k y , k �'' : Depth Depth +N/-S +EI-W s °t (ft) (ft) ; `t 10,037.9 4,997.2 - 6,267.0 - 3,977.8 Start Dir 12.00/100' TFO 90L 10037.90' MD, 4997.20 TVD 10,057.9 5,003.4 - 6,278.5 - 3,992.9 Start Dir 7.0/100' 10057.90' MD, 5003.70 TVD 10,207.4 5,041.1 - 6,354.4 - 4,115.8 End Dir 10207.40' MD, 5041.10 TVD 10,211.2 5,041.9 - 6,356.1 - 4,119.2 Start Dir 7.0 /100' 10211.20' MD, 5041.90 TVD 11,317.0 5,176.2 - 6,146.7 - 5,112.0 End Dir 11317.00' MD, 5176.20 TVD 12,287.0 5,176.2 - 5,403.7 - 5,735.5 Start Dir 3.0/100' 12287.00' MD, 5176.20 TVD 12,479.6 5,166.5 - 5,256.4 - 5,859.1 End Dir 12479.60' MD, 5166.50 TVD 13,876.1 5,025.9 - 4,192.1 - 6,752.2 Start Dir 3.0/100' 13876.10' MD, 5025.90 TVD 14,068.7 5,016.2 - 4,044.8 - 6,875.8 End Dir 14068.70' MD, 5016.20 TVD 15,038.0 5,016.2 - 3,302.2 - 7,498.9 Total Depth at 15038.00' MD, 5016.20' TVD 6/11/2009 4:30:46PM Page 7 COMPASS 2003.16 Build 428 1. McEVOY TYPE C 3 1/8' -5000 PSI GATE VALVE 2. McEVOY TYPE C 2 9/16' -5000 PSI GATE VALVE 3. SWACO 2 1/16 -10000 P51 REMOTE CHOKE CHOKE MANIFOLD SCHEMATIC 4. THORNHILL- CRAVER 3 1/8" -5000 PSI MANUAL CHOKE NABORS ALASKA RIG 1 9AC 5. FLANGED TEE 2 1/16' X 2 1/16' X 2 1/16" -5000 P51 6. 5 WAY FLOW BLOCK 3 1/8" X 3 1 /8" X 2 1/16' X 2 1/16" X 2 1/16" -5000 P51 7. 5 WAY FLOW BLOCK 3 1/8" X 3 1/8" X 3 1/8" X 3 1/8" X 2 1/16" -5000 PSI 3h 9. 8. 4 2 1A 2 1/16' X BLOCK 2 1/16' X 2 1/16" X 2 1/16' -5000 PSI T4 10. 2 1/16 "- 10,000PSI X 2 1 /16" -5000 PSI SPOOL L S`pA Rgoo G 12. 2 1 /16 XX /16 "- 5000 R 13. 3 1/8" -5000 PSI X 2 1/16" -5000 PSI SPOOL 15 14. 2 1/16' - 10,000 PS1 X 2 1/16' -5000 PSI DOUBLE STUD ADAPTOR 4. 5 15. 2 1/16' -5000 PSI TARGET FLANGE 20 © 16. 3 1/8" -5000 PSI TARGET FLANGE 4 a p 18. 3 1/8'X PS X 2 / 1 "-50L PSI DOUBLE STUD ADAPTOR 3 qN'C 11 19. 3 WAY FLOW BLOCK 3 1 /8" X 3 1/8" X 3 1/8" -5000 PSI Ne 2 1 1 op , 20. 5 WAY FLOW BLOCK 2 9/16' X 2 9/16" X 2 9/16" X 2 9/16' X 2 9/16" -5000 PSI ' 9 3" lb 1 / 1 1 . 7< t j i ) ii A kFR Q � a © 0 0 * oo�E 2 ,3 • f Olu6 iU OIYt P1 4TC 5, °MM19t& 0 ya6as rjr My Ye 9Y6D]. 2. MNYO�MI/,Air4A MOOD °°6f NABORS ALASKA RIG 19AC %m[ CHOKE MANIFOLD SCHEMATIC 8/14/07 TCR REVISED MID UPDATED D. SHERMAN T C. REED ,00m's[D b T.C. REED *v. - 0.10 sat HIS X 24 MAR 99 o m. Ma 19AC�0008 ' at 1 1 1 \ HYDRIL 11" 5k PSI GK ANNULAR BOP 3'-1 1 I FLANGED C BOITQM CONNECTION 1 i ( 47 3/4 LENGTH ` I L. L - -- - _____ _I_- ________ - -_E 11" 5000# • 4 ' -7 " = I -- FLA NGED HYDRIL 1.3'-11" ^� DOUBLE GATE PREVENTOR 3 1/8" 5000# HCR VALVE ° - - "- - - -� • DOUB 55" LENGTH - 3 1/8" 5000# HCR VALVE 1 1 ._ 3 CHOKE LINE -_ -. MII ∎o � ' V - �- nP` 'IIP' All,,...,,, - - - KILL LINE_ 1 ' 1 3x2' i 3 1/8" 50001 GATE VALVE I 1 3" 5000# GATE VALVE 1 ------1 HYDRIL 11" 5k PSI 3' -si E_-- -- .- -- -- --'----- -- . -- --- HYDRAULIC RAM SINGLE GATE - 1 FL 41 3/4 LENGTH N I i � 1 1 NABORS ALASKA RIG 19AC BOP STACK CONFIGURATION • MA s ® glIn°14=tra.MTAZIV Ndmrs Afadm c g. ,. m .r An elwAIa4s vaoa -xz 007- " NABORS ALASKA RIG 19AC "" BLOW-OUT PREVENTS' STACK CONFICURATON mow owner 6/14/07 A RREM O APA/ W I1ED TRIMS AYES JOE AS O4 TON ,awg�m n E IEEERT ray. A 6tl, . C r ., 1L [COMM 1616 N/A 616 OA 2004 g.a M° IWC 0016 4 1 W 1 i • . s i 1. !tilt I %- i 1 41! I= !di a g ; la IfI �G C, 11 g 1 N t r MO= ...:L=E--. P it i 1 t . ,a ¥ t m L t 1 1 1 1 ! .1 a 9 ' ! PI S En 9 PT S __ �I�IIl�l1l�I�� = 1 0 — ,EgIii..i i � _ ; _ • { .-. . — IIIII.IIIr _„ 1 ILM . mom 1 1 1: `t' III 011 er—' w _____ jEIlaI ,.., Ir . -4)- 1 t I i Legend fl, ° ° ._ �....r , As —built Conductor w ° . R ryE + M* 0 0 Projeet cotton i T p to o '' o +te+ yea O fjt I�YI • 1.. A O 0 '.`k , 1 p It rr � ,� ° o ° ° ° `La' Location Map GRAPHIC SCALE NA • 45:' S 30 1 5 • 0 30 • o ®N'` I ° ry of t mlti_mw N. 0 / 00 o yk 4 e '•9' 1 I 0 ° • ' � ilip G. Davis : 1 No. .4110 -5 . • J `° # ry p ° o 4 ` F Op je.ww+Ne * r ry y o 0 tp ,�RorEssON '` ryry o o k� �1`g� tt (1 a kti z w o f t 777 ,, O O k0 i 1 Y 7l h t ! R 77 1 • o ON i t j 7 ,,c 0 4) ). , ; / Ft 0 0 0 e7/ Pioneer Natural Resouoes JOB NAME: Oooguruk Drill Site DRAWN BY: BL 'CHECKED BY: MJD . LOCATION: Protracted Section 11 SCALE: 1 ..30' Township 13 North Range 7 East DATE: 7 - - Umiat Meridian Notes: NANUQ JOB NO. SHEET Coordinates are listed on sheets 3 and 4 DESCRIPTION: Alaska Nod 27, Zone 4 Conductor As —built Plan 05204 1 of 4 0 1 __A, _ CC Ct J I % 1 z t t I s a z I I i I istri�ct Saundry _ I ` 1 SE Corner of `` OOOGURUK SITE Protracted Section 11 It E $ Pi Coordinates I rt N 6028111.04 n 1 - E 470989.01 L �! i \ . • A m p'— � Ref. AK BLM .s I. s • re i '" ♦% `1 4 t Harrison . Bay Tract! "A" N _ >� -24 1_ F 4.CSi ' rawin ---_ a u 1 x � \ i � . • ts = 1 Z I' l # � � � fY O t 4. L 7s 9' J 12 c7 • ° Ph -..> • I .x • E r R" Offs re leeraod- --3.89 Mos ' 14 1 � ear shore ieeroodiv3 -812 , 13 a PI 20 to Dooga�ruk Site • � • • PI 7 to PI 20 za a • z; a I PI -16 -- r M- Tundra leer= i n 4 V: x i i R da to A i► 1 1 ! PI .1 St ■ ►A ,. ■ X11 ...idig ill i / Fi g:i',„ ii , :i: „ i Fl— -, ,.. PI-19 )k.j._ .v ,. B as i s of Location J11 BUC i f;'` • E N '' DS -3H West Monument lr x s tires _ Mit 1 Coordinates Aid — •• +, ;; s ,, N 6001016.61 IN -STAKED PI INFORMA110N ONLY E 498081.23 µr, ill !/ m L _� * Ref. Lownsbury & Assoc. � a� d ; c < Drawing No. ce . n , ------ NSK 6.01 –d672 .. c OF AC 19 1 o r��•••••.. 000 is �. oh•• r�. • \ill ', *; • e ' nip G. Duds : o , ♦ 'sn S No. 41104 0,4 0 •, - l iile:o • 44.1,. »,,e , 0 OFES8 ION N.‘ de► � N%.1A ° ° � Pioneer Natural Resouces JOB NAME: Oooguruk Drill Site Conductors DRAWN BY: BL CHECKED BY: MJD LOCATION: Protracted Section 11 SCALE: N/A Township 13 North Range 7 East DATE: 7 -12 -07 Umiat Meridian NANUQ JOB N0. SHEET DESCRIPTION: Basis of Location 05204 2 of 4 Ala State Pla ere Line gffisef - - ` - -- - le` -- Well No. -- - -.- . _i X Latitude (N) (W) FSL — Pad Ev, - -- - - - - -- -- - - - - - -- - - - -- -- Longitude -- - -- _ - EEL — Pad _. . 1 6,031,151,32 469, 920,45 70 29 46,24160 150 14 45.46468 3035 1077 13,50 5,03t 146,35 469, 915, 52 70 29 46,19252 150 14 45.60922 3030 1082 13,50 3 6,031,141.39 469,910,59 70 29 46,14354 15014 45,75375 3025 1087 13.50 6,031,136.46 46%905,67 • 70 29 46.09485 150 14 45,89799 3020 1092 13.50 - 5 6,031,131,45 469, 900,74 ' 70 29 46,04538 150 14 46,04252 3015 1097 13,50 6 6,031,126,51 469, 895,80 70 29 45,99660 150 14 46,18735 3010 1102 13.50 7 6,031,113,73 469, 883.13 70 29 45, 87039 150 14 46.55879 2997 1115 13.50 8 6, 031,108.73 469, 878.21 70 45.82102 150 14 46.70303 2992 1120 - 13,50 9 6,031,103.75 469, 873,26 70 29 45.77184 150 14 46.84814 2987 1125 13.50 10 6, 031, 098.79 469, 868.36 70 29 45, 72286 150 14 46, 99179 2982 1130 13,50 - • 11 6, 031, 093.84 469, 863,39 70 29 45,67398 150 14 47,13750 2977 1135 13,50 • 12' 6, 031, 088,87 469, 858,47 70 29 45.62490 150 47.28174 2972 1140 — 13.50 13 6,031,076.06 469,845.81 70 29 45 49840 - 150 14 47.65288 2960 1152 1 3, 50 • 14 469840.87 — 6, 031, 071.09 , 70 29 45.44932 150 14 47.79770 2955 1157 13.50 15 6, 031, 066.15 469, 835,96 70 29 45.40053 150 14 47,94165 2950 1162 13,50 16 -777 6, 031, 061.18 469, 831.04 70 29 45.35145 150 14 48.08588 2945 1167 13.50 17 6, 031, 056.25 469, 826,11 70 29 45, 30277 150 14 48.23042 2940 1172 13.50 7-- 18 5,031,051,27 469, 821.18 70 29 45, 25359 150 14 48, 37495 — 2935 1177 13.50 19 6,031,038,52 469,808,50 70 29 45,12768 150 14 48, 74668 2922 1189 _ 13.50 • • 20 6,031,033,50 469,803.59 70 29 45,07811 15014 48.69061 2917 1194 13.50 21 • — 0,031,028,53 469, 79$.62 70 29 45,02903 150 14 49.03632 2912 1199 13,50 22 6, 031, 023,58 469, 793,67 70 29 44,98014 150 14 4918144 2907 1204 — 13,50 23 •6, 031, 018,57 469, 788.76 70 29 44, 93067 150 14 49.32537 2902 1209 — 13, 50 • 24 6, 031, 013.60 469, 783,84 70 29 44,88159 150 14 49.46960 2897 1214 13.50 • .v or s ic 0 .a.••• • ., , 4 s i s . .►co .0 ii il ' n+ Philip G. Davis : o / 4 • S No. 41104 ..**4.141 1 "'''''''''''Atf*:'' ~ c � • •• Notes; • a, 1. Elevations ore based on BP Mean Soo Level, 2. Coordinates ore based on Alaska State Plane Nod 27, Zone 4, 3, All conductors are within Protracted Section 11, Pioneer NQtur-QI R @ s4uces JOB NAME: 9oogur-uk Drill $ite Conductors DRAWN BY: BL CHECKED BY: MJD LOCATION: Protracted Section it SCALE: N/A Township 13 North _ Range 7 EQst DATE: 7 =12 =07 Umiat Meridian __.. NANUQ JOB NO, SHEET DESCRIPTION: As » b l C oord i nates 05204 3 of 4 r Well No. Well State Pia Latitude (N) Longitude (\ Section Line Offset Pad Elev. Y X FSL FEL 25 6,031,128.32 469, 943.64. 70 29 46.01630 150 14 44.77930 3013 1055 13.50 26 6,031,123.35 469, 938.69 70 29 45.96722 150 14 44.92442 3008 1060 13.50 27 6,031,118.33 469, 933.76 70 29 45.91765 150 14 45.06895 300 1065 13.50 28 6,031,113.39 469, 928.86 70 29 45.86887 150 14 45.21260 2997 1070 13.50 29 . ' 6,031,108.44 469, 923.95 , 70 29 45.81999 150 14 45.35655 2992 1075 13.50 30 ' 6,031,103.45 469, 919.01 70 29 45.77071 15014 45.50137 2988 1079 13.50 31 6, 031, 090.65 469, 906.38 70 29 45.64431 15014 45.87163 2975 1092 13.50 32 6, 031, 085.68 469, 901.39 70 29 45.59523 15014 46.01793 2970 1097 13.50 33 6, 031, 080.67 469, 896.50 ' 70 29 45.54576 150 14 46.16128 2965 1102 13.50 34 6, 031, 075.73 469, 891.57 70 29 45.49698 150 14 46.30581 2960 1106 13.50 35 6,031,070.76 469,886.60 70 29 45.44789 150 14 46.45152 2955 1111 13.50 36 6,031,065.83 469,881.69 70 29 45.39921 150 14 46.59547 2950 .1116 13.50 37 6, 031, 053.00 469, 869.00 70 29 45.27251 150 14 46.96749 2937 1129 13.50 38 6,031,047.99 469, 864.14 70 29 45.22304 150 14 47.10995 2932 1134 13.50 39 6,031,043.03 469, 859.20 70 29 45.17406 150 14 47.25478 2927 1139 13.50 40 6,031,038.10 469,854.21 70 29 45.12537 150 14 47.40108 2922 1144 13.50 41 6,031,033.05 469,849.29 70 29 45.07551 150 14 47.54530 2917 1149 13.50 42 6, 031, 028.13 469,844.38 70 29 45.02692 150 14 47.68925 2912 1154. 13.50 43 6, 031, 015.46 469, 831.70 70 29 44.90180 150 14 48.06099 2899 1166 13.50 44 6, 031, 010.49 469, 826.79 70 29 44.85272 150 14 48.20493 2894 1171 13.50 ---> 45 6, 031, 005.53 469, 821.86 70 29 44.80373 150 14 48.34946 2889 1176 13.50 46 6, 031, 000.54 469, 816.94 70 29 44.75446 150 14 48.49369 2884 1181 13.50 47 6, 030, 995.50 469, 811.98 70 29 44.70469 150 14 48.63910 2879 1186 13.50 48 6, 030, 990.58 469, 807.07 70 29 44.65610 150 14 48.78304 2874 1191 13.50 • OF AL 1`1 rr'�Q'••• SURVEYOR'S CERTIFICATE °••�•���° • ° I HEREBY CERTIFY THAT I AM / ' ° % la 1 PROPERLY REGISTERED AND f yt j � ' ' " ' �, � � LICENSED TO PRACTICE LAND . r j " � -0 "" SURVEYING IN THE STATE OF h ALASKA AND THAT THIS PLAT ' • • : REPRESENTS A SURVEY DONE BY All ][ . 1 • iiip G. Davis o c 4 . � . E M E OR UNDER MY SUPERVISION as, x ; s� ti Ne. 4110.5 a I 1e,, �� • 4 , - c'+ AND THAT I BELIEVE THAT ALL ,1 ,'`-,;; f c , jDA DIMENSIONS AND OTHER DETAILS -' ,� "~w",101' ARE CORRECT AS SUBMITTED TO ,- ME BY NANUQ, INC. AS OF JULY 4 " 12TH, 2007. Pioneer Natural Resouces JOB NAME: Oooguruk Drill Site Conductors DRAWN BY: BL CHECKED BY: MJD, LOCATION: Protracted Section 11 SCALE: N/A Township 13 North Range 7 East DATE: 7 - - Umiat Meridian NANUQ JOB NO. SHEET DESCRIPTION: As -built Coordinates 05204 4 of 4 • • • PIONEER NATURAL RESOURCES Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, Alaska 99501 Tel: (907) 277 -2700 Fax: (907) 343 -2190 RECEIVED .,11,A, (, 1 7 211119 July 16, 2009 4iask4 Oil & Gas C& ms, +•Ui't'sfnissior, Anchoro State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite #100 Anchorage, AK 99501 RE: Application for Permit to Drill ODSN -45A Surface Location: 2889' FSL, 1176' FEL, Sec 11, T13N, R7E, UM X = 469821.86, Y = 6031005.53, ASP4 Pioneer Natural Resources Alaska, Inc. (PNRA) hereby applies for a Permit to Drill an exploration well from the Oooguruk Drill Site (ODS) located within the Oooguruk Unit. The well is designed to be an exploration well in the Torok formation, sidetracked from existing casing on ODSN -45. As indicated in the attachments, the drilling program will entail pulling a circulation string of tubing from the existing well, ODSN -45. It is planned to perforate and squeeze cement to anchor the casing at the window depth, and provide additional isolation. A whipstock will be run and a window milled in the casing. A lateral section will be drilled in the Torok sands and an uncemented liner will be run. The well will then be completed, fractured and tested. Please find attached information as required by 20 AAC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1) Form 10 -401 Application for Permit to Drill per 20 AAC 25.005 (a). 2) A plat showing the surface location proposed for the well per 20 AAC 25.005 (c) (2). 3) A copy of the proposed drilling program per 20 AAC 25.005 (c) (13) including: a. The drilling fluid program as required by 20 AAC 25.033 b. Complete logging and mud logging operations are planned and descriptions are attached. y . c. A complete proposed casing and cementing program is attached as per 20 AAC 25.030. d. A description of the procedure for conducting formation integrity tests per 20 AAC 25.035 (c) (5). e. A summary of the drilling operations. f. A summary of drilling hazards per 20 AAC 25.005 (c) (4). g. A wellbore schematic is also attached visually depicting the proposed well. 4) A copy of the Planned Directional Well Path. 5) Diagrams and descriptions of the BOP and diverter equipment to be used on Nabors Alaska Rig 19 -AC as required by 20 AAC 25.035 (b) and (c). 6) PNRA does not anticipate the presence of H2S in the formations to be encountered in this well. However, H2S monitoring equipment as specified in 20 AAC 25.065(1) will be functioning on the rig as standard operating procedure for all wells drilled by that rig. Products for treating H2s contamination in the drilling mud system will be maintained on the ODS. In the future, PNRA will provide information and permitting requesting annular disposal of drilling wastes on this well. The following are PNRA's designated contacts for reporting responsibilities to the Commission: 1) Completion Report Vern Johnson, Senior Drilling Engineer (20 AAC 25.070) 907/343 -2111 Vern.johnosn @pxd.com 2) Geologic Data and Logs Tim Reed, Senior Operations Geologist (20 AAC 25.071) 907/343 -2144 Tim.reed @pxd.com The anticipated spud date for this well is August 3, 2008. If you have any questions or require further information, please contact Vern Johnson at 907/343 -2111. Sincere , Vern Johnson Sr. Staff Drilling Engineer Attachments: Form 10 -401 Supporting permit information cc: ODSN -45A Well File • TRANSMITTAL LETTER CHECKLIST WELL NAME �� (1c PTD# Development Service / Exploratory Stratigraphic Test Non - Conventional Well (J)e (i a -ta-.) FIELD: l- J(JP Lt rji POOL: tit i L C rc: k L / n Or ( i Circle Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK ADD -ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in Permit No. , API No. 50- - - API number are between 60 -69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(0, all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or /vim ► L2Ii from where samples are first caught and 10' sample intervals ,4 1 7. 17 C through target zones. Non - Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. r4 �'' l � / Rev: 1/11/2008 WELL P E IT CHECK fzrField & Pool - Well Name: 000GURUK NUQ OD SN -45A Program EXP Well bore seg ❑ PTD #:2090790 Company PIONETURAL RESOURCES ALASKA INC Initial Class /Type EXP / PEND GeoArea 973 Unit 11550 On /Off Shore Off Annular Disposal ❑ Administration 1 1 Permit fee attached NA 2 Lease number appropriate Yes Entire well in ADL 355036 3 Unique well name and number Yes 1 4 Well located in a defined pool No Undefined Torok Pool 5 Well located proper distance from drilling unit boundary Yes Only well open to Torok in Sections 10 and 15; >2 miles to OoogurukUnit boundary 6 Well located proper distance from other wells Yes Only well open to Torok in Sections 10 and 15 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes >2 miles to OoogurukUnit boundary; all offset leases have same ownership /landownership 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval Yes SFD 7/27/2009 13 Can permit be approved before 15 -day wait Yes 14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For No 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre - produced injector: duration of pre production less than 3 months (For service well only) NA 17 Nonconven. gas conforms to AS31.05.0300,1.A),(j.2.A -D) NA 18 Conductor string provided NA Conductor set in ODSN -45i (PTD 208 -100) Engineering 19 Surface casing protects all known USDWs NA Surface casing set in ODSN -45i 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing set and cement to surface 21 CMT vol adequate to tie-in long string to surf csg No Will perf and Sqz 7 5/8" csg before drilling window. 22 CMT will cover all knownproductive horizons No Slotted liner to be run (4.5" od) 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig equipped with Steel pits. All waste to approved disposal wells. 25 If a re- drill, has a 10 -403 for abandonment been approved Yes 309 -274 26 Adequate wellbore separation proposed Yes Proximity analysis performed. 27 If diverter required, does it meet regulations NA BOP stack already in place. (surf casing set) Appr Date 1 28 Drilling fluid program schematic & equip list adequate Yes Torok BHP = 2261 psi (8.7 ppg) ...drilling with 9.3 ppg GLS 8/7/2009 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP = 1711 psi .. BOP test to 3500 psi 31 Choke manifold complies w /API RP -53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of H25 gas probable No Not expected but SOP for H2S will be followed. Rig has alarms and gas detectors . 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures Yes H2S sensors will be operational; scavenger materials will be stockpiled onsite. Geology 36 Data presented on potential overpressure zones Yes Expect pressure gradient of 8.7 ppg EMW; will be drilled with 9.3 ppg mud. Appr Date 37 Seismic analysis of shallow gas zones NA SFD 7/27/2009 38 Seabed condition survey (if off - shore) NA 39 Contact name /phone for weekly progress reports [exploratory only Yes Vern Johnson 907 - 343 -2111 Geologic Engineering This re drill will delineate the hydrocarbon accumulation in the Torok Formation of the central Oooguruk Unit. Per 20 AAC Commissioner: Date: issioner: Date .., '.sinner Date J 25.990(25), wells that delineate a pool are considered exploratory wells. Mud log and samples NOT required because this lv_ ,c7Gj t �../D,..Q� wellbore will pass within 300' of Kalubik 2 (PTD 1980200) which has a mud log and samples from 120' to 5640' MD /TVD. SFD / � 7/27/2009 • • Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the 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. 1 1 HALLI BURTON i Sperry Drilling 1 1 END OF WELL REPORT 1 ODSN -45A Oooguruk Development 1 1 1 i ..._... 1 .w • 1 t r • 1 y WigIsirapr 1 P 111 1 Surface Data Logging Services 1 I 1 1 )1 nJ fern P1133NOld 1 1 1 1 1 1 1 1 s6o, 6uueeu s6oi uogen!en3 uo! }ewaod gidea . SA si(ea •g 1 podgy /(ananS L sdol uo!lewaod '9 111 spode nos .9 pJooe J pnL'8 i!8 spoday 6ulwoW •£ Aaewwns A!!ea 'Z 1 uo!4ewao }u! !eaeUeo 1 SIN31NOO JO 318V1 1 6U O AJJeds 1 ND.1b118I„dH 1 1 1 HALLIBURTON I S perry Drilling GENERAL WELL INFORMATION 1 Company: Pioneer Natural Resources AK 1 Rig: Nabors 19AC Well: ODSN -45A Field: Oooguruk I Borough: North Slope Borough State: Alaska I Country: API Number: United States 50- 703 - 20577 -01 Sperry Job Number: AK -AM- 5710484 1 Job Start Date: 5 Oct 2009 — 30 Oct 2009 Spud Date: 4 Aug 2008 Total Depth: Surface Section drilled to 4971' MD, 3437.8' I TVD Intermediate Section to 13866' MD, 6166' TVD 1 Production Section window cut at 10050' MD, 5001' TVD Rig Release Date: 30 Oct 2009 I North Reference: True Declination: 21.814° I Dip Angle: 80.898° Total Field Strength: 57640 nT Date of Magnetic Data: 02 Oct 2009 1 Wellhead Coordinates N: North 70° 29' 44.80" Wellhead Coordinates W: West 150° 14' 48.35" Drill Floor Elevation 42.70' I Ground Elevation: 13.6' Permanent Datum: Mean Sea Level I SDL Engineers: Tom Mansfield, Dan Kane, Dan Sherwood, Colby Marks Company Geologist: Jacque Ledbetter, Paul Cozma, Jim Stewart 1 Company Representatives: Joe Polya Rod Klepzig, Joey Cortez, Jim Brown SSDS Unit Number: 123 1 1 1 PIONEER h. F11 UHAL HESOUHCES, 1 1 1 HALLIBURTON I Sperry Drilling DAILY SUMMARY I 10/5/2009 Complete rig move over ODSN 45i for re -entry and preparation to cut window and drill ODSN 45A. I Reverse circulate out diesel with sea water and nipple down tree, nipple up BOP's and test. Rig up to pull 2 7/8" completion liner. Begin POOH with 2 7/8" production liner L/D. 1 10/6- 7/2009 Non essential personnel off island. 10/8/2009 IRan in hole and set packer. Pressured up on annulus and shut in. Pressured up on drill pipe to activate guns. Extended stinger assembly and rigged up cement lines. Pressure tested cement lines and stung into packer. Conducted injectivity test with brine and monitored, no return recorded. Un -stung from packer and displaced hole with 8.9 ppg brine. Pumped 33 bbls of cement. Returns observed. Shut I upper rams and continued to pump. Un -stung from packer and circulated drill pipe volume. POOH to 9853' and well became unbalanced due to failed packer and ballooning formation. Pumped 50 bbls of 9.6 kill mud and observed static well. Continued to POOH to 5319' and repaired crownsaver. Continued to POOH to surface. Laid down stinger assembly and picked up scraper assembly. Began running in hole. I Sperry recorded an 18.7 bbl loss prior to pulling out of the hole. 10/9/2009 I Continued to run in the hole with a scraper assembly and began washing and reaming @ 9649'. Tagged hard cement @ 10,020' and drilled out packer and guns to 10,046'. Drilled out "fast drill" plug and cement to 10,095' MD. Pumped 50 bbl HiVis sweep and circulated 2x bottoms up. Pulled out of the hole while attaching super sliders, 1 per joint. Laid down BHA and began testing BOP's. Repaired HRC on BOP 1 stack. 10/10/2009 I Completed testing of BOP's and picked up BHA. Ran in the hole with the whipstock and milling assembly. Shallow pulse tested MWD tools and continued to run in the hole. Oriented the whipstock and set the shear pin. Rotated and circulated to shear the nozzle plugs from the bit. Began milling the window at 10050' MD. 1 10/11/2009 Continued to mill window into new formation. Drilled and slid to 10,091' MD. Circulated bottoms up and conduct FIT to 12.5 ppg. Continued to drill and slide to 10,124'. Pumped slug and observed static well. I Pulled out of the hole due to poor ROP to 8494' and adjusted rig and BOP stack due to trouble with Super Sliders colliding with stack. Continued to pull out of the hole. Formation gas remained under 40 units while drilling with no significant peaks and was reflective of ROP. Sample quality was very poor due to I LCM, bit action and abundant mud losses over the shakers. Observed formation cutting were primarily very argillaceous siltstones and shales with minor sandstone cutting. All recorded fluid losses were attributed to solid control equipment. I 10/12/2009 Pulled out of hole from 8,258' to 213' MD. Laid down BHA #13 to 98'. Downloaded MWD data. Finished pulling out of hole with BHA. Flushed stack of metal cuttings and junk. Picked up BHA #14 to 96'. Uploaded MWD program. Ran in hole with BHA #14 to 6,600'. Successfully pulse tested MWD. Moved 1 pits away from substructure. Repositioned substructure over wellhead. 10/13/2009 Repositioned pits to mate up to substructure. Finished leveling rig and connect service lines in PUTZ. 1 Rigged up E -line. Ran in hole with BHA #14 from 6,739' to 10,124'. Drilled from 10,124' to 10,309'. 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D &c wads 1 N0101181'17VH 1 HALLIBURTON I Sperry Drilling 14500' MD, the existing WBM at 9.45ppg was displaced with new 9.30ppg WBM. Immediately after ' getting the new mud around, drilling torque, which had slowly built to 8kfps jumped to 10kfps & further increased to — 11kfps. In addition, little EMW relief has been seen with the new mud as PWD ECDs have built up to an 11.2- 11.3ppg EMW. Drilling parameters have improved in the past 400' MD with more consistent ROPs, no pressure events, and what torsional vibration that had developed with the new mud ' dilution has since dissipated to previous (low) background levels, presumably from mud warming and gel shearing. Drilled formation gas has averaged 300 -600 units for the bulk of the drilled interval with three small shows of less than 1000 units observed. Very minor connection gasses have occurred on 65% of ' connections and there have been no losses or gains to the hole in the past 24 hours. Open -hole annulus correction has increased to 132bbIs at a fairly consistent rate of 2bbls /hr over the previous 24 hours. This equates to an average 7.73" diameter for the open -hole section & an estimated 7.47" average diameter for the 6.125" hole section. Sampling at surface is primarily siltstones to very-fine grained sandstones 1 and all expected shales are assumed to be passing through the solids control equip. 10/22/09 Continued drilling 6 1/8" hole from 15082' to a TD of 15429' MD (5018' TVD) with average on- bottom ' ROPs of 65 -75fph and 10.5-11K fps torque with no torsional vibration observed. Drilled formation gas averaged 400 units with a few ROP- induced gas peaks. No connection gasses were observed & no losses to the hole while drilling. Over the last 24 hours of drilling, signs of wellbore breathing were observed when the drilling ECDs surpassed 11.0ppg. Excessive flow and slow pit gains were observed during connections. Upon TD of the well, circulated the hole —2.7x B/U with ECDs staying above 11 ppg & started tripping with a few tight spots encountered requiring reaming and /or washing to pull through. Flow back was observed from the well as the result of the higher ECDs charging the formation. Continued tripping on elevators when possible until a tight spot was encountered at 11850' MD. Upon turning on the pumps, the hole packed off and immediately saw 80% losses. Worked the pipe & started pumping at 40- 60gpm until 90% returns were regained. Washed one more stand before tripping on elevators to 11564' MD to start an AFR MAD Pass. Circulation was established with initial losses of 45% and ECDs at 12ppg ' while pumping at 260gpm. Continued pumping and MAD Passing at 150fph, with the average loss rate reduced to —30 %. With bottoms up from the 11850' MD approximately 10- 15bbls cuttings (40bbls mud & cuttings) were unloaded with a sustained 5000 -5500 unit gas peak. Trip gas has since dropped to 500- ' 700 units with cuttings still coming to surface and with an ECD of 10.9ppg. Annulus correction was 112bbIs upon TD, but has since increased to 145bbls with the cuttings unloading at surface. Avg diam = 8.01" & 6 1/8" section avg. diam = 7.85 ". 10/23/09 Continued MAD Passing from 11262' MD to 10216' MD while washing at 200gpm & rotating at 80- 115rpm (rotary changed to mitigate downhole vibration). Wellbore breathing experienced in the past 24 hours continued to occur for the rest of the MAD Pass, although diminishing with lower ECDs. Average losses ' at 11262' MD were initially 15 -20% & slowly fell to 5% for the rest of the MAD Pass (5- 10bbls hr max observed thereafter) as the ECDs dropped from 11.05 to 10.25ppg. Pumps off average EMWs dropped to 9.43ppg by 10200' MD & flow back with pumps off ceased by 10900' MD while MAD Passing. Ceased ' pumping & rotating to pull through the window & circulated 1x bottom's up. Gas from the MAD Pass fell from 1000 to 100 units & background gas levels fell to less than 50 units once pulling inside the casing window. After completing the 1x bottom's up circulation, pumped dry job for trip out & observed a Pumps Off average EMW of 9.48ppg. Based upon inspection of the solids control equipment, the annulus correction has been conservatively ramped up to 158bbIs for the entire open -hole section after seeing the hole unload significant cuttings initially from the 11850' MD bottom's up followed up by a slow steady cuttings stream until pulling within the window. Since reaching TD, the open -hole correction has increased by 46bbls; the correction increased by 20bbls after the first 3x B/U circulation, increased another 18bbls after receiving the 11850' MD bottom's up & hole unloading , & has since increased another 8bbls with the steady stream of cuttings seen at surface to the window. The average hole diameter is 8.23" with the estimated 6.125" section diameter at 8.01". Losses over the last 24 hours: 96bbls. Losses over entire event: 248bb1s. 10/24/09 PIONEERh aooguruk 1 HALLIBLJRTON I Sperry Drilling Completed BOPE Test & picked up Clean -Out BHA #16. Tripped in on elevators circulating every 25 ' stands seeing a total loss during the trip of 14bbls over calculated displacement. After circulating above the window, worked BHA through window seeing tight conditions which resulted in the jars firing twice. Once through the window, tripped in on elevators and worked pipe through tight spots at 10185' to 10219' MD, 11120' to 11150' MD, & 11554' to 11575' MD. Started washing & reaming at 11575' MD with tight ' hole conditions & began experiencing similar hole conditions during the wiper trip out. Frequent pack -offs were observed with loss rates up to 75% accompanied w/ high torque, high downhole vibration, and ECDs in excess of 11.0ppg. The welibore was observed charging (increase in pumps off EMWs after ' high pumps on ECDs) & discharging (gains with pumps off increasing with greater pumps off EMWs - -as great as calc 40bbls /hr during 04:05 connection at 12184' MD) with very clear wellbore breathing. Trip gas peaked at 5520 units observed from the 11575' MD bottom's up (gas rose steadily as deeper open - hole lag came to surf) with the gas peak showing the open -hole correction to 11575' MD to be 90bbls. ' This shows severe washouts in the 6.75" hole section with a rough calculated washout diameter of 9.5- 9.75". There is insufficient data to calculate the washout for the 6.125" hole section but it appears the overall open -hole washout correction will grow considerably when the bottom is reached. Spot samples from the shakers show predominantly siltstone grading to a very fine sandstone. Calcium carbonate from ' slug intially made up 25% of the cuttings load & is currently at 10 -15 %. Losses since circulation started, 56bbls and total losses past 24 hours 71 bbls. ' 10/25/09 Completed wiper trip from 12164' MD to bottom seeing a significant improvement in the tripping parameters (lower torque /drag and fewer pack -offs) after leaving the Torok base horizontal tangent and starting to move up the ramp. Tripped on elevators from 12377' to 13281' MD having to wash and ream from 12750'- 12845' MD because of tight hole conditions. Washed and reamed to TD thereon seeing significant downhole vibration, packing off, & increased torque /drag from cuttings beds. Once to TD, circulated 8310strokes (2.2x open -hole volume) with little to no torque, dropping ECDs from 11.50 to 11.08ppg, and less erratic SPP. Trip gas was dependent on the running rate & ranged from 500 -1650 units over a background of 150 units with mud losses partially dependent on the ECDs and number of pack -offs across the interval. With the hole circulated, started check trip to the window. Washing and reaming stands out at 217gpm /128rpm while observing overall good hole conditions with the exception of ' one pack -off requiring extra circulation at 14204' MD. Gas units while tripping have been recently climbing from 200 to 500 units and losses have been averaging 5 -15% with 5- 10bbls /hr flow seen with pumps off due to a combination of the annulus /drillstring mud weight differential and the formation discharging charged fluid (welibore breathing) from elevated circulating ECDs. The open -hole washout has increased to 195bbIs (using bottom's up gas data and observed in /out strokes of sweep pumped once on bottom -- returned at 9150stks, gauge hole 6819stks). Using a 9.75" average hole size through 11325' MD, the average diameter for the 6.125" hole section is 8.43" with the washout primarily composed of fine solids as evidenced by the climbing mud weight despite high dilution rates (40bbls /hr). ' 10/26/09 Continued check trip from 12376' MD to 10200' MD seeing good hole conditions throughout the sump and ' back up the ramp towards the casing window while washing (200gpm) and reaming (118rpm). During the trip towards the shoe, welibore breathing was observed throughout, although the magnitude of the breathing diminished with decreasing circulating ECDs and lower pumps off EMWs by 10200' MD, the pumps off EMW matched the mud weight out and previously seen gains with the pumps off ceased and were replaced with a slight loss (1- 2bbl /hr seepage). Started tripping in on elevators from 10200' MD and continued on the elevators until a tight spot at 13928' MD required slow pipe rotation at 20rpm to work through. Attempted to continue on elevators but decided to rotate at 20rpm to TD while pumping 20- 40gpm to keep the bit jets from plugging. Worked to bottom with rotation without any problems. Once on bottom, circulated hole clean with max trip gas of 1703 units from 15390' MD while taking 5 -30% losses with occasional partial pack -offs. With the hole clean, spotted the HT Breaker (250bbIs, 13bbls lost while pumping) across the open hole section and started tripping out on elevators with no substantial open -hole problem intervals - -a slightly higher hookload was observed from 12150' to 11600' MD. Passed through the window with ease, circulated 2x B/U (minor losses), and continued tripping at 5798" MD showing a 1- 2bbl/hr sustained loss to the hole. Gas data analysis from the on- bottom circulation before spotting the PIONEER NATURAL RESOURCES 000guruk I 1 1 HALLIBURTON Sperry Drilli breaker shows the open -hole washout has increased a further 1 Obbis to 205bbis. The average open -hole ' size is 9.21" & gas data suggests a —10" hole section through 11325' MD and a tapered hole in the 6.125" section with an average diameter of 8.48 ". 10/27/09 1 Continued tripping to surface with clean out BHA seeing a total loss of 7.5bbls across the entire trip. Downloaded MWD & broke down & laid down BHA. Rigged up liner running equipment and started running in with 4.5" 12.6ppf L -80 liner. Ran in with 135 joints of liner & attached liner hanger. Continued running in with 4" XT -39 drill pipe to 10000' MD and circulated above the window. After circulation ceased, started running liner in to the open hole & tripping in with 4" XT -39 DP (8 stands of HWDP were picked up as well) to depth of 13557' MD. Total trip in losses, 13bbls with a slow 0.5bb1 /hr seeping loss observed (consistent across the entire trip). 24 hr mud loss of 17 bbls. 1 10/28/09 Finished running liner to bottom at 15429' MD before pulling up 5' MD to hang the liner. Dropped & seated ball & then proceeded to pressure test the liner -- tests failed until slacked off 4' MD. With the liner ' hung & pressure tested, circulated 2x B/U & chased with dirt magnet chasing wash to displace the well over to 9.30ppg NaCI brine. Max trip gas while circulating was 300 units at bottoms up that quickly diminished to 5 -10 units background shortly thereafter. With the dirt magnet around, slipped & cut 1500' I MD drill line before starting to pull & lay down 4" drill pipe per pipe management. Total losses past 24 hours 25bbls. ' 10/29/09 Completed pipe management, lay down 276 joints drill pipe and 24 joints HW drill pipe. Laid down BHA and liner running assy. Flushed stack and changed lower pipe rams to 4.5 ". Picked up tubing hanger and made up to landing jnt. Performed mock run with tubing hanger and tested seals to 5,000 psi. Laid ' down hanger. Rigged up to run tubing. Picked up rock gauge and control line spools and hung sheaves. Rigged up and ran ROC gauge and tie in. Began running tubing with a current depth of 2354'. Total losses for 24 hrs were 23 bbls. A 7 bbl loss has been recorded while running tubing. ' 10/30/09 SDL released. 1 1 1 1 1 1 1 PIONEER , OUH( ES cccguruk 1 1 Customer: Pioneer Natural Res. Report #: 1 HALLIBURTON Well: ODSN -45i Date: 08/03/2008 -5:00 1 Area: Oooguruk L oc 05:00 Depth 0' ation: North Slope Progress 24 hrs: 0' S perry Drilling Services Rig: Nabors 19AC Rig Activity: Maintenance 1 Job No.: AK -MW- 5710484 Report For: Jim /Jeff Al Daily Charges $3,540.00 Total Charges $3,540.00 11 +. I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr 0.0 0.0 0.0 0 Flow in • •m 0 SPP •si 0 1 r IMEMBM 0 0 0 0 Flow Rate s•m 0 Gallons /stroke 3.6 1 Mud � Dataft Density (ppg) Viscosity ml /30 min cP (Ib 100ft Elec Rme I ;i CorS� lids • 8.8 8.8 55/80 - 19 46 - as 2.4 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current - _---- - - - - -- Gas Breakdown Gas (units) Chromatograph (ppm) 1 Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to to I to to to 1 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG Pumps Off Gas; TG peas hr �.�,� a , y _r - ,; - ' � 24 hr Recap: Rig move and maintenance. 1 Total losses from 0500 -2359 08/2/08 0 bbl. Total losses 0000 -0500 08/02/08 0 bbls. 1 Logging Engineer: Dan Sherwood / Wayne Hermanson * 10000 units = 100% Gas In Air I 4 , I 1 1 1 I . C ustomer: P ioneer Natural Res. R eport #: 2 HALLIBURTDN Well: ODSN -45i Date: 08/04/2008 -5:00 I Area: Oooguruk 05:00 Depth 0' L ocation: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: P/U & Maintenance Job No.: AK -MW- 5710484 Report For: Jim /Jeff 1 i Daily Charges $3,540.00 Total Charges $7,080.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING '. R.O.P. ft/hr 0.0 0.0 0.0 0 Flow in •.m 0 SPP es' 0 , 0 0 0 0 Flow Rate s.m 0 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP Elec Stab Lime Cor Solids De.th ft in out sec/•t m1/30 min cP lb /100ft volt • • • •b 8.8 8.8 100/60 - 15 42 - - - 2.4 I :'* BHA R u n # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 100 IIM1 13.5 0.699 -_ - - -- . 1 '' ' Lit hology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current ------ -_ - - -- Gas Breakdown Gas (units) Chromatograph (ppm) De pth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 1 to to to to ' to to to 1 to to to to if I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; i - 11 ,,, .. BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas .... 4 .. . ;. ' ~fit ,. '` .;,* ° 24 hr Recap: Rig maintenance, P/U 5" DP, TD maintenance. i Total losses from 0500 -2359 08/3/08 0 bbl. Total losses 0000 -0500 08/4/08 0 bbls. Logging Engineer: Dan Sherwood / Wayne Hermanson 10000 units = 100% Gas In Air 1 1 .w . Customer: Pioneer Natural Res. Report #: 3 HALLIBURTON Well: ODSN -45i Date: 08/05/2008 -5:00 I S Area: Oooguruk 05:00 Depth Progress 610 Location: North Slope ress 24 hrs: 457 perry Drilling Ser L oc ces Rig: Nabors 19AC ... Rig Activity: Drilling Ahead on Job No.: AK -MW- 5710484 Report For: Jim /Jeff 1 1 Daily Charges $3,540.00 Total Charges $10,620.00 ' I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr 188.0 150.0 280.0 430 Flow in • •m 440 SPP es] 806 • Gas (units) 7 10 37 407 Flow Rate (spm 124 Gallons /stroke 3.6 1 Mud Data: Density (ppg) Viscosity HTHP PV YP Elec Stab WPS Lime Cor Solids x Depth ft in out (sec/gt) (m1/30 min) cP (Ib /100ft volt ppm (ppb) 8.9 8.9 93 - 16 42 - - - 2.9 ' : BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM 1 Condition 100 Hughes MX -1 13.5 0.699 4.38 153 I 445 39 ' � 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) I I I I I I I G as Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 153 to 578 37 7 10 0 0 0 0 0 to to to I to to to I. to to to to I A Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: Rig maintenace on TD, made up BHA,drilled rat hole, drilled to 610' md. Aii Total losses from 0500 -2359 08/4/08 32 bbl. Total losses 0000 -0500 08/5/08 14 bbls. ' Logging Engineer: Dan Sherwood / Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 1 m 1 Customer: Pioneer Natural Res. Report #: 4 HALLIBURTON Well: ODSN -45i Date: 08/06/2008 -5:00 Area: Oooguruk 05:00 Depth 2360' L North Slope Progress 24 hrs: 1734' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Ahead ' Job No.: AK -MW- 5710484 Report For: Jim /Jeff Daily Charges $3,540.00 Total Charges $14,160.00 I . ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) 160.0 151.0 338.0 1652 Flow in (gpm) 559 SPP (psi) 1250 Gas units 35 10 145 1001 Flow Rate s•m 150 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP Elec Stab WPS Lime Cor Solids Depth ft in out (sec/gt) (m1/30 min) cP (Ib /100ft volt ppm (ppb) 9.3 9.3 105 - 22 54 - - 6.0 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 100 Hughes MX -1 13.5 0.699 19.05 153 2147 40 I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) I Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 04 Tot C5 Tot Type I ! 626 to 2300 145 10 15633 0 0 0 0 to to I to to to to to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; v. BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas ' 24 hr Recap. Drill and slide from 626' and to 2313' md. I :E Total losses from 05:00 -23:59 08/5/08 204 bbl. Total losses 00:00 -05:00 08/6/08 51 bbls. Note: these losses are over shaker and solids control equipment. II Logging Engineer: Dan Sherwood / Wayne Hermanson * 10000 units = 100% Gas In Air II 1 me 1 1 Customer: Pioneer Natural Res. Report #: 5 HALLIBURTON Well: ODSN -45i Date: 08/07/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 3630' Location: North Slope ress 24 hrs: 1294' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Ahead Job No.: AK -MW- 5710484 Report For: Jim /Nick 1 Daily Charges $3,540.00 Total Charges $17,700.00 ROP&Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data R = ROTATING I R.O.P. (ft/hr) 44.0 109.0 309.0 2388 Flow in (gpm) 600 SPP (psi) 1650 Gas (units) 40 253 128 1372 Flow Rate (spm; 170 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP Elec Stab WPS Lime Cor Solids Depth ft in out (sec/qt) (m1/30 min) cP (Ib /100ft volt ppm (ppb) % 9.4 9.4 85 - 22 50 - - - 8.0 -r f 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 100 Hughes MX -1 13.5 0.699 19.05 153 3477 12 42 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current) 5 10 10 65 10 Vi a ; • Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 2336 to 3472 128 40 to to to to to to 1 t0 t0 t0 t0 Nt Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: Drill a nd slide from 2366' and to 3630' and at time of report. 1 1 Total losses from 05:00 -23:59 08/5/08 153 bbl. Total losses 00:00 -05:00 08/6/08 93 bbls. Note: these losses are over shaker and solids control equipment. I Logging Engineer: Dan Sherwood / Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 1 1 1 Customer: Pioneer Natural Res. Report #: 6 HALLIBURTON Well: ODSN -45i Date: 08/08/2008 -5:00 I Area: Oooguruk Location: 5:00 Depth 4985' ation: North Slope Progress 24 hrs: 1355' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: POOH , Job No.: AK -MW- 5710484 Report For: Jim /Nick ' Daily Charges $3,540.00 Total Charges $21,240.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) 0.0 134.0 282.0 4157 Flow in (gpm) 707 SPP (psi) 1950 Gas units 0 60 127 4372 Flow Rate (spm 190 I Gallons /stroke I 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP Elec Stab WPS Lime Cor Solids Depth ft in out (sec/gt) (m1/30 min) cP (Ib /100ft volt ppm (ppb) 9.5 9.5 82 - 19 52 - - - 7.0 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 100 Hughes MX -1 13.5 0.699 19.05 153 4832 3477 22 80 I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 25 5 10 45 10 5 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 3630 to 4985 127 60 to to I to to to to I to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: Drill and slide from 3630" and to 4985' md, circulate btms up and sweep and start POOH. I Total losses from 05:00 -23:59 08/7/08 65 bbl. Total losses 00:00 -05:00 08/8/08 130 bbls. Note: these losses are over shaker and solids control equipment. 1 Logging Engineer: Dan Sherwood / Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 , III 1 1 1 1 ,h, Customer: Pioneer Natural Res. Report #: 7 HALLIBURTON Well: ODSN -45i Date: 08/09/2008 -5:00 1 Area: Oooguruk Location: 5:00 Depth 4985' ation: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: POOH ., Job No.: AK -MW- 5710484 Report For: Jim/Nick Daily Charges $3,540.00 Total Charges $24,780.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) 0.0 Flow in (gpm) SPP (psi) Gas (units) 0 50 272 Flow Rate (spm, Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/gt) (m1/30 min) cP (Ib /100ft m1/30 min mg/1 % 9.7 9.7 62 12 40 7.6 9 19k 9.0 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 100 Hughes MX -1 13.5 0.699 19.05 153 4832 3477 22 80 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 25 5 _ 10 45 10 5 1 Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to 1 to to I to to to to I to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: Circulate 3x BU. POOH wiper trip to 1367'. TIH to btm, circulate and condition mud for csg. run. Circulate 3x BU and POOH. 1 Total mud losses: negligible. 17 bbls lost over centrifuge, 320 bbls sent to RSC. I i. =' Logging Engineer: Tom Mansfield / Wayne Hermanson * 10000 units = 100% Gas In Air I 1 1 1 1 Customer: Pioneer Natural Res. Report #: 8 ' HALLIBURTON Well: ODSN -45i Date: 08/10/2008 -5:00 I Area: Oooguruk 05:00 Depth 4985' Location: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Cementing 1 Job No.: AK -MW- 5710484 Report For: Jim/Nick Daily Charges $3,540.00 Total Charges $28,320.00 I ROP&Gas: Current Avg 24 hr Max Max © ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr 0.0 - -- Flow in • •m - SPP •si - 0 0 45 Flow Rate s.m,- Gallons /stroke 3.6 I Mud Data Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/•t m1/30 min cP Ib /100ft m1/30 min m• /I 9.9 9.9 65 16 40 8.2 10 19k 10.0 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 - -_- -_ -- 1 - II Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current 25 -- 5 10 45 10 5 - -- Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to I to to to qi to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: Run Casing to 4933' TD. Circulate and condition mud. Pump cement. 1 o'ii'i ,r.4,.,.,.:,:.,.,,, ,:. ,,, . i,• 1 , Logging Engineer: Tom Mansfield /Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 1 1 1 Customer: Pioneer Natural Res. Report #: 9 HALLIBURTON Well: ODSN -45i Date: 08/11/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 4985' Location: North Slope ress 24 hrs: 0 Sperry D rilling Services Rig: Nabors 19AC Rig Activity: UD BHA Job No.: AK- MW- 5710484 Report For: Jim /Nick I Daily Charges $3,540.00 Total Charges $31,860.00 a . I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr 0.0 Flow in • •m - SPP •si '; 'IllEMBMIll 0 0 0 Flow Rate s•m,- Gallons /stroke 3.6 a= I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out (seG•t ml /30 min cP Ib/100ft m1/30 min m•/I 9.7 9.7 47 - 13 20 8.6 9 19k 9.0 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Lithology ( %): I Sd Sst I Silt I Siltst I Cht Clyst Sh 1 Lst Coal I Gvl I Tuff I 1 ll (current Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to I to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 0., I . 24 hr Recap: Pump 324 bbls of primary cmt, 183 bbls tail cmt. Circ and disp Nipple down, nipple up BOPE. UD p � P p� N p pp pp p MWD. 1 Logging Engineer: Tom Mansfield /Wayne Hermanson * 10000 units = 100% Gas In Air r.. AMINIIMI h.. 1 1 1 1 1 Customer: Pioneer Natural Res. Report #: 10 HAI.UBURTON Well: ODSN -45i Date: 08/12/2008 -5:00 Area: Oooguruk 05:00 Depth 4985' Location: North Slope Progress 24 hrs: 0 S perry Drilling Services Rig: Nabors 19AC Rig Activity: Prep to POOH Job No.: AK -MW- 5710484 Report For: Jim /Nick 1 Daily Charges $3,540.00 Total Charges $35,400.00 ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING I R.O.P. ft/hr 0.0 - -- Flow in • •m - SPP •si CEETER1 0 0 0 Flow Rate so - Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/•t m1/30 min cP Ib /100ft m1/30 min ma/1 % 9.7 9.7 49 - 13 22 8.8 9 19k 9.0 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) ------ - - - - -- I Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to II to to to to 111 to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas I 24 hr Recap: : L/D and download MWD. RIH to 4700'. Power down for back -feed test. POOH. RIH picking up singles. 1 Logging Engineer: Tom Mansfield /Wayne Hermanson 10000 units = 100% Gas In Air 1 1 1 1 1 Customer: Pioneer Natural Res. Report #: 11 MALUBURTON Well: ODSN -45i Date: 08/13/2008 - 5:00 I Area: Oooguruk 05:00 Depth 4985' Location: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Testing BOPE Job No.: AK -MW- 5710484 Report For: Jim /Nick I Daily Charges $3,540.00 Total Charges $38,940.00 ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING .0 I R . O . P . ft/h 0 . 0 - -- Fl ow in • • - SPP .si IMEIDEINI 0 0 0 Flow Rate s•m,- Gallons /stroke 3.6 . .m ,err.= 1 . Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out (sec/•t) m1/30 min cP Ib /100ft m1/30 min m. /I % k 9.7 9.7 47 13 20 9 9 19k 9.0 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) ------ - - -_ -- 1 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I to to to I to to to to I to to to to la Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 2 hr Recap: : RIH picking up singles. Stand back same in derrick. Test BOPE. Test plug hanging up. 1 0.„ 0.- 1 i Logging Engineer: Tom Mansfield / Wayne Hermanson * 10000 units = 100% Gas In Air - .1: 1 1 1 1 Customer: Pioneer Natural Res. Report #: 12 HALLIBURTON Well: ODSN -45i Date: 08/14/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 5000 Location: North Slope ress 24 hrs: 15 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drill ahead to FIT Job No.: AK -MW- 5710484 Report For: Jim /Nick 1 Daily Charges $3,540.00 Total Charges $42,480.00 ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) 0.0 Flow in (qpm) 547 SPP (psi) 1425 Gas units 5 5 41 Flow Rate (spm, 155 Gallons /stroke 3.6 N ,,r I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/gt) (mI /30 min) cP (Ib/100ft m1/30 min mg /I 9.7 9.7 49 - 13 23 9 9 19k 9.0 '' y 111 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to I to i to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas p p P 1 v ... a N , AN 'rte 24 hr Recap: Test surface casing to 3500 psi. TIH w/ BHA #2. Wash and ream from 4665' to 4903'. Displace to LSND mud. Drill out 15' of formation from 4985 to 5000'. 1 1 Logging Engineer: Tom Mansfield / Wayne Hermanson " 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural R es. R eport #: 13 HALLIBURTON Well: ODSN -45i Date: 08/15/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 6561 Location: North Slope ress 24 hrs: 1576 Sperry Drilling S ervices Rig: Nabors 19AC Rig Activity: Short Trip Job No.: AK -MW- 5710484 Report For: Jim /Nick 1 Daily Charges $3,540.00 Total Charges $46,020.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) 128.0 124.0 253.0 6479 Flow in (gpm) 642 SPP (psi) 2567 Gas units 95 65 134 6347 Flow Rate s•m, 182 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/gt) (ml /30 min) cP (Ib /100ft m1/30 min mg /I % 9.7 9.7 49 - 13 23 9 9 19k 9.0 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 12.7 4985 1576 39797 120 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) n 20 20 60 tr 1 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I 5000 to 5800 69 4440 138 16 8 BG 5800 to 5922 118 75 9795 332 81 48 BG 5922 to 6340 75 41 3876 168 59 29 BG I 6340 to 6350 134 95 12978 409 133 68 2 GP 6350 to 6560 101 85 9202 436 154 74 2 BG to to I to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas I 24 hr Recap: Drilled 20' of new formation. Performed FIT to 14.8 ppg EMW. Drill ahead to 6561'. Short trip to shoe at report time. 1 1 Logging Engineer: Tom Mansfield / Wayne Hermanson * 10000 units = 100% Gas In Air 'r 1 1 1 1 Customer: Pioneer Natural Res. Report #: 14 in HALLIBUATON Well: ODSN -45i Date: 08/16/2008 -5:00 I Area: Oooguruk 05:00 Depth 7984 Location: North Slope Progress 24 hrs: 1423 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Short Trip Job No.: AK -MW- 5710484 Report For: Jim /Nick I Daily Charges $3,540.00 Total Charges $49,560.00 . . I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr 178.0 144.0 280.0 7325 Flow in • •m 646 SPP •si 2936 199 160 515 7601 Flow Rate s.m, 183 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/•t m1/30 min cP (Ib /100ft m1/30 min me/1 9.1 9.1 47 - 16 19 6.2 9 10K 4.9 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 22.65 4985 6408 15 -20 120 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) _ -- 15 -- 60 - -- 25 I Gas Breakdown Gas (units) Chromatograph (ppm) I fil Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 6350 to 6560 101 85 9202 436 154 74 2 BG 6561 to 6561 664 664 70650 2450 812 330 48 STG 6561 to 6845 185 150 13024 513 210 117 2 BG I 6845 to 6848 437 437 42047 1548 595 224 4 CG 6848 to 7580 398 173 17113 1122 498 169 21 BG 7580 to 7650 515 395 45714 3626 1850 695 169 GP 7650 to 7750 340 281 30475 2354 1306 569 151 GP I 7750 to 7984 286 170 23482 1654 937 498 166 BG to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas . : T $ ' . . , ' t . , : : '.... 4 ,,,: - . ; ` . 1 . 24 hr Recap: Short tripped 6561' to shoe with tight spots at 5445', 5640'. 5730', and 6160'. RIH. Short trip gas of 664 units. Drilled ahead with connection gases of 200 to 400 units and minimal to no mud losses. Circulated 3X bottoms up to clean 1 hole at 7985'. Perform FIT to 13.0 ppg EMW. Make wiper trip. Pulled tight at approx. 6930'. juiiii miwilillo 1 Logging Engineer: Tom Mansfield / Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 1 - ' ' : . ' elf . ,; , ,,tz. ; .. i , Customer: Pioneer Natural Res. Report #: 15 HALLIBURTON Well: ODSN -45i Date: 08/17/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 8941 L North Slope ress 24 hrs: 957 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK - 5710484 Report For: Jim /Nick Daily Charges $3,540.00 Total Charges $53,100.00 I ROP &Gas: Current Avg 24 hr Max Max c ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr 28.0 101.0 222.0 8461 Flow in • •m 640 SPP .si 2920 105 90 171 8459 Flow Rate s.m, 182 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/.t m1/30 min cP Ib /100ft m1/30 min m. /I % 8740 9.1 9.1 48 - 16 17 8 9 12.5K 5.3 ' BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition i ; . 200 Sec FSF3563Z 9.88 1.108 39.1 4985 3956 15 -30 120 c a' 1111 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current - -- 20 -- 70 - -- 10 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 7750 to 7984 286 170 23482 1654 937 498 166 BG 7984 to 7984 1231 1231 92738 7178 4226 2004 802 STG 7984 to 8268 206 75 6963 462 258 146 71 BG I i 8268 to 8268 202 85 13144 842 440 251 108 CG 8268 to 8922 130 75 7462 440 218 139 55 BG to to to to to to , 1 :.;,* Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: POOH from 7890' to 6468'. Serviced rig. RIH and drill ahead from 7985' to 8941' at report time. si 1 1 Logging Engineer: Tom Mansfield /Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 1 Customer: Pioneer Natural Res. Report #: 16 HALLIBUATON Well: ODSN -45i Date: 08/18/2008 -5:00 I Ar Oooguruk 05:00 Depth 9750 L ocation: North Slope Progress 24 hrs: 809 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK -MW- 5710484 Report For: Jim /Nick I Daily Charges $3,540.00 Total Charges $56,640.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) 30.0 84.3 203.0 9010 Flow in (gpm) 601 SPP (psi) 2550 Gas units 50 61 182 8930 Flow Rate s m 171 Gallons /stroke 3.6 I . Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/gt) (m1/30 min) cP (Ib /100ft m1/30 min mg /I % 8740 9.2 9.2 48 - 16 16 7.2 9 14.5K 6.2 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.8 . 8 1.108 56.5 4985 4765 15 -30 120 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 20 70 10 f Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 8268 to 8922 130 75 7462 440 218 139 55 BG 8 922 to 9080 120 86 9959 533 241 120 13 BG 9080 to 9695 108 54 5256 239 105 62 8 BG --..- : to to to to to II to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas I P p p 24 Recap: Drilled ahead from 8941' to 9750' pumping occassional nut plug sweeps to clean bit. No mud losses to report. X I Logging Engineer: Tom Mansfield /Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 1 Customer: Pioneer Natural Res. Report #: 1 HALLIBURTON Well: ODSN -45i Date: 08/19/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 10543 Location: North Slope ress 24 hrs: 793 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK -MW- 5710484 Report For: Jim /Nick II Daily Charges $3,540.00 Total Charges $60,180.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) 104.0 90.8 206.0 9874 Flow in (gpm) 640 SPP (psi) 2700 Gas units 95 182 1425 10330 Flow Rate s•m` 182 Gallons /stroke 3.6 * I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (m1/30 min) cP (Ib /100ft m1/30 min mg /I % 10140 9.2 9.2 56 - 19 21 6.2 10 10K 5.9 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 68.35 4985 5558 6-12 147 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 35 40 25 II Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I 9080 to 9695 108 54 5256 239 105 62 8 BG 9695 to 10042 131 100 7504 325 133 69 2 BG � 10042 to 10316 325 270 30815 1877 791 358 122 BG I 10316 to 10339 1425 1250 119453 8627 3875 1567 551 GP 10339 to 10395 457 150 33518 2601 1277 607 238 BG 10395 to 10412 465 385 37392 2473 1044 463 185 GP 10412 to 10450 261 205 20293 1565 848 418 172 BG l to to u to - to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms U p Pumps POG - Pum s Off Gas; TG - Trip Gas ' 4 n . 4, ` ;, ,1, n ., ,.i, 24 hr Recap: Drilled ahead from 9750' to 9973'. Circulated and conditioned mud. Make wiper trip to 7995'. RIH. Washed and reamed from 9878' to bottom. Short trip gas of 278 units. Drilled ahead. Top of Torok at 10042' MD, 4999' TVD. Max gas of 1425 units from 25' sandstone at 10316' MD, 5088' TVD. 1 t Logging Engineer: Tom Mansfield /Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 1 1 1 Customer: Pioneer Natural Res. Report #: 18 i: HALUBURTON Well: ODSN -45i Date: 08/20/2008 -5:00 I : ` ;1 Aea: Oooguruk 05:00 Depth 12058 Location: North Slope Progress 24 hrs: 1515 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling li Job No.: AK -MW- 5710484 Report For: Jim /Nick Daily Charges $3,540.00 Total Charges $63,720.00 4 . I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) 124.0 109.4 225.5 11408 Flow in (gpm) 620 SPP (psi) 3000 Gas units) 160 135 610 10960 Flow Rate (spml 176 Gallons /stroke I 3.6 I Mud Data: Density (ppg) Viscosity HTHP 1 PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/gt) (m1/30 min) cP (Ib /100ft m1/30 min mg /I % 11584 9.2 9.2 48 - 14 16 6.2 9 700 6.8 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 85.05 4985 7073 6 -12 147 1 Lithology ( %): Sd Sst I Silt I Siltst I Cht I Clyst Sh I Lst Coal I Gvl I Tuff I (current 35 65 I Gas Breakdown 1 Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 10412 to 10450 261 205 20293 1565 848 418 172 BG 10450 to 10706 138 73 9528 547 239 142 60 BG 10706 to 10952 151 126 10906 561 309 266 165 BG I 10952 to 10963 610 256 54637 3619 1544 767 335 GP 10963 to 11396 185 113 14726 958 426 261 140 BG 11396 to 11405 358 172 37138 1195 400 202 115 GP 11405 to 11999 192 82 17166 862 312 172 54 BG 1 to to to :, to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 1 hr 4 Rec ap: Drilled ed losing ahead from • m 1 0 54 to Base 11950 Torok at 10042' 4 observe 98e.' Max un TVD. M gas of 225 units at Suspect g g p Loss from Mud cleaner adjustment. 1 `' • 1 Logging Engineer: Tom Mansfield / Wayne Hermanson * 10000 units = 100% Gas In Air ni 1 1 1 1 Customer: Pioneer Natural Res. Report #: 19 HALL (BURTON Well: ODSN -45i Date: 08/21/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 12323 Location: North Slope ress 24 hrs: 265 ' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Work Pipe Ati Job No.: AK -MW- 5710484 Report For: Jim /Nick II '''; Daily Charges $3,540.00 Total Charges $67,260.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) na 87.5 228.0 12071 Flow in (gpm) SPP (psi) Gas (units) na 262 432 12248 Flow Rate (spm; Gallons /stroke 3.6 I F. Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (m1/30 min) cP (Ib /100ft m1/30 min mg/1 % a 12323 9.3 9.3 59 - 15 20 4.4 9 7000 7.0 max= BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10 -20 120 Lith ( %): Sd S Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 15 85 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 11405 to 11999 192 82 17166 862 312 172 54 BG 11999 to 12281 432 296 32120 1614 565 262 104 BG 12248 to 12248 432 432 44062 2088 687 302 125 CG I to to to to I to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; il 4. BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 1 , W 24 hr Recap: Drilled from 12058' to 12323'. Worked stand. Hole packed off with a 39 bbl mud loss. Unable to circulate. Pulled pipe to approx. 11320'. Hole very tight. Worked pipe cycling jars. Pipe began pulling tight at 04:15. 1 1 Logging Engineer: Tom Mansfield / Wayne Hermanson * 10000 units = 100% Gas In Air lira ::,;.. ., ,J. ,k" ., , 1 1 1 1 Customer: Pioneer Natural Res. Report #: 20 HAL.UBURTON Well: ODSN -45i Date: 08/22/2008 -5:00 • Area: Oooguruk 05:00 Depth Progress 12323 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Work Pipe Job No.: AK - 5710484 Report For: Rodney /Jeff Daily Charges $3,540.00 Total Charges $70,800.00 .. ROP &Gas: Current Avg 24 hr Max Max © ft Pump & Flow Data: R = ROTATING I R.O.P. ft/hr na - -- Flow in • •m - SPP •si MEIRM..1 na - -- Flow Rate s•m,_ Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De•th ft in out sec/.t m1/30 min cP Ib /100ft m1/30 min m. /I % 12323 9.1 9.1 58 - 15 17 6.2 10 7000 5.5 s;- ..,i ',! BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10 -20 120 1 . u `, . Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) - -- 15 _- 85 _ - - -- I Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; 0 BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas ,.... : , a. e x °E t _ $ r ",,, n ' ' �. - „ °,: n 24 hr Recap: Attempt to jar pipe free. 1 1 1 Logging Engineer: Tom Mansfield /Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 21 NALLIBURTON Well: ODSN -45i Date: 08/23/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 12323 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: POOH Job No.: AK -MW- 5710484 Report For: Rodney /Jeff 1 Daily Charges $3,540.00 Total Charges $74,340.00 ROP &Gas: Current Avg 24 hr Max Max c ft Pump & Flow Data: R = ROTATING R ft/h n - -- Flow in • •m - SPP •si Y na 1464 a•.rox 12000 Flow Rate s.m,- Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/.t m1/30 min cP Ib /100ft m1/30 min m. /I 12323 9.2 9.2 58 - 12 18 6.2 10 7000 6.5 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 0 200 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10 -20 120 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current) - -- 15 -- 85 - - -- ` Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type approx to 12000 1464 12969 5969 2766 1364 420 POG to to to to to to I to to 4. to to III Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas I 24 hr Recap: . Attempt to jar pipe free. Blind back off pipe to pull out of hole to allow for new fishing assembly to be utilized, Circulate and condition hole, Service top drive, POOH 1 1 Logging Engineer: Boyd Piercey / Wayne Hermanson * 10000 units = 100% Gas In Air 4 . , ,,F i 1 1 1 I Customer: Pioneer Natural Res. Report #: 22 HALUBUATON Well: ODSN -45i Date: 08/24/2008 -5:00 Area: Oooguruk 05:00 Depth 12323 Location: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: TIH Job No.: AK -MW- 5710484 Report For: Rodney /Jeff 1 Daily Charges $3,540.00 Total Charges $77,880.00 ROP&Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING I R.O.P. ft/hr na - -- Flow in • on SPP •si IHMEEDM 12 15 30 4830 Flow Rate s.m,— Gallons /stroke 3.6 t I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De.th ft in out (sec/.t m1/30 min cP Ib /100ft m1/30 min m•/I % 12323 9.2 9.2 50 - 11 15 5.6 10 8000 6.5 BHA R un # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 2 00 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10 -20 120 I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff — (current) - -- 15 -- 85 I - - - -- Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to 4830 30 15 1392 142 89 49 0 POG to to to to to to 1 111 to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: : Pull out of hole to shoe. Service rig. Cut and slip drill line. Continue POOH to surface, retorqueing every connection. MU & RIH with Fishing assembly. RIH to shoe 4830' start pumping BU to condition mud Gas values minimal 1 at 15 to 27 units. 1 Logging Engineer: Boyd Piercey / Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 1 1 II Customer: Pioneer Natural Res. Report #: 23 HALLIBURTON Well: ODSN -45i Date: 08/25/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 12323 Location: North Slope ress 24 hrs: 0 Sperry Drilling Serv Rig: Nabors 19AC Rig Activity: TIH Job No.: AK -MW- 5710484 Report For: Rodney /Jeff Daily Charges $3,540.00 Total Charges $81,420.00 ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING I R.O.P. ft/hr na - -- Flow in • •m - SPP •si na 260 9400 Flow Rate s•m,- Gallons /stroke 3.6 1 Mu Da ta: Density (ppg) Viscosity HTHP PV YP API Alt pH Chlorides Cor Solids Death ft in out sec/st m1/30 min cP Ib /100ft m1/30 min m• /I 12323 9.2 9.2 56 12 16 5.4 10 8000 6.5 • t E3 FIA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10-20 120 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current - -- 15 -- 85 - - -_ - 1 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I i to 9400 260 30 25646 1077 5 12 302 107 TG to to to to to to 111 1 ill :1 to to s to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas I 24 hr Recap: RIH and tagged fish. Circulated hole clean. Ran wire line and unable to get into fish at 9350'. Backed off drill pipe and POOH. Serviced rig. TIH to tag fish. 1 1 Logging Engineer: Boyd Piercey /Wayne Hermanson " 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 24 HALLIBURTON Well: ODSN -45i Date: 08/26/2008 -5:00 U Area: Oooguruk 05:00 Depth Progress 12323 Location: North Slope ress 24 hrs: 0 k. Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Wireline Job No.: AK -MW- 5710484 Report For: Rodney /Jeff Daily Charges $3,540.00 Total Charges $84,960.00 ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING ` '4 R.O.P. ft/hr na Flow in ••m - SPP •si ria 160 9400 Flow Rate s•m _ Gallons /stroke 3.6 i F I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids i' De•th ft in out (sec/•t m1/30 min cP Ib /100ft m1/30 min m. /I % 12323 9.2 9.2 50 - 12 14 5.2 11 8000 6.5 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10 -20 120 i Lithology ( %): Sd I Sst Silt I Siltst I Cht Clyst Sh I Lst Coal J I Gvl I Tuff (current) 15 85 U Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to 9400 160 30 25851 1105 505 289 67 TG to to I to to to to I to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas ','%.1 ..' . . 4 ' :0 'VW ' -',. .:, .; i • . ;.,i!Zfaiaknaill'6'..:::- 24 hr Recap: RIH to fish with dummy run. POOH with wireline and P/U string shot. RIH with string shot down to fish to attempt back off. Charge failed. POOH to replace charge and RIH. While RIH with wireline, returns were observed. te Pumps were shut down and well was monitored for flow. Continued to RIH to break off. II 1 Logging Engineer: Boyd Piercey / Wayne Hermanson * 10000 units = 100% Gas In Air w 1 1 1 . Customer: Pioneer Natural Res. Report #: 25 HALIUBURTON Well: ODSN -45i Date: 08/27/2008 -5:00 l Area: Oooguruk 05:00 Depth 12323 Location: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Test BOPs Job No.: AK -MW- 5710484 Report For: Rodney /Jeff Daily Charges $3,540.00 Total Charges $88,500.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in •.m - SPP •si .4 - na 193 9400 Flow Rate s.m - Gallons /stroke 3.6 1 Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/•t m1/30 min cP Ib /100ft m1/30 min m • /I 12323 9.2 9.2 52 - 16 19 5.2 11 7000 6.0 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10 -20 120 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff - current) - -- 15 -- 85 - -_ -- • �� Gas Breakdown Gas (units) Chromatograph (ppm) 1 Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 34 16249 to 10407 193 585 189 91 5 POG to to 1 to to to to 1 to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; ri ItA BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 1 24 hr Recap: Make another attempt at backing off with 2nd, 3rd and 4th charges pumped d own on wireline, unsucessful. While pumping wireline down for third attempt, circulation was restored and returns were seen at surface. Worked the drillstring and able to pull back one stand. Packed off again but movement of the drillstring was still possible. Pumped I 4th shot attempt down with no returns, approximately 240bbIs pumped into the formation. 4th shot failed. Back off and POOH to test BOPs. 1 Logging Engineer: Boyd Piercey / Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 26 I . HALLIBURTON Well: ODSN -45i Date: 08/28/2008 -5:00 I Area: Oooguruk 05:00 Depth 12323 L North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Fishing Job No.: AK- MW- 5710484 Report For: Rodney /Herb I Daily Charges $3,540.00 Total Charges $92,040.00 ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in • •m - SPP •si na - -- Flow Rate s•m - Gallons /stroke 3.6 Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids • De•th ft in out (seG•t ml /30 min cP Ib /100ft ml /30 min m• /I 12323 9.2 9.2 58 - 14 20 4.6 11 7000 6.0 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10 -20 120 II Litholo y (/o Sd ';' st Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) - -- 15 -- 85 _ - - -- Gas Breakdown 4 Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I to � to to to to to to to to iii to I q Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas I li 24 hr Recap: Backed off drill pipe and POOH from approximately 600'. Pick up and RIH with RTTS and set at 600'. Nipple down stack and change out multi bowl. Test BOPs. Pull packer back to surface and lay down drill collars. RIH with 5" drill pipe and screw back into string. Perform another blind backoff to POOH and retest BOPs. 1 I I i Logging Engineer: Boyd Piercey / Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 1 1 . . by 1;',e.'4, ,...Vi 7 Customer: Pioneer Natural Res. Report #: 27 ALL1WURTON Well: ODSN -45i Date: 08/29/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 12323 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: POOH Job No.: AK -MW- 5710484 Report For: Rodney /Herb Daily Charges $3,540.00 Total Charges $95,580.00 j , I ROP&Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) na Flow in (gpm) SPP (psi) Gas (units) na 11 161 9966 Flow Rate (spm; Gallons /stroke 3.6 I Mud Data Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/gt) (m1/30 min) cP (Ib /100ft m1/30 min mg /I % 12323 9.2 9.2 50 - 14 16 4.4 10 8000 6.0 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10 -20 120 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) _ 15 85 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 0 POG I to 9966 16 11 15911 572 152 58 to to 1 i 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas A 1 . 24 hr Recap: RIH and screw into drill string. Rig up and run wireline CCL and string shot. Pump down to fish with the hole breathing. 85 bbls of losses noted while pumping wireline down, with no returns. Fire shot and back off drill pipe at approx 9966'. Circulate 3 bottums up, staging pumps up to 600gpm with 140 rpm. Start POOH and pump dry job with approx 24 1 stands POOH. Continue to POOH, perform rig maintenance on top drive. I .'"' Logging Engineer: Boyd Piercey / Wayne Hermanson " 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 28 HALLIBURTON Well: ODSN -45i , Date: 08/30/2008-5:00 I Area: Oooguruk 05:00 Depth 12323 Location: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Fishing /Circulating Job No.: AK -MW- 5710484 Report For: Rodney /Herb 1 Daily Charges $3,540.00 Total Charges $99,120.00 I ROP &Gas: Current Avg 24 hr Max Max ae ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) na Flow in (gpm) 600 SPP (psi) 2630 Gas (units) 54 63 194 10337 Flow Rate s•m, 171 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV cP (I YP b /100ft API ml /30 Filt min pH Chlorides Cor Solids Depth ft in out (sec/qt) (m1/30 min) mg /I % 12323 9.2 9.2 47 - 14 16 4.3 11 8000 6.0 I Y BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10 -20 120 II I Litholo ( %): Sd S st Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) r 1 15 85 1 Gas Breakdown 4 Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to 10337 194 63 6349 421 274 243 254 POG to to 1 to to to to to to rr to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 1 2 •r hr Recap: RIH and screw into drill string with fishing assembly. Pump up stand pipe pressure and begin jarring string. With circulation established the pumps were continuously staged up. After continuing circulation and jarring rotation was possible and that to was staged up to 138rpm. Working pipe at report time. 1 Logging Engineer: Boyd Piercey / Wayne Hermanson * 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. R eport #: 29 HALLIBURTON Well: ODSN -45i Date: 08/31/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 12323 Location: North Slope ress 24 hrs: 0 Sperry Drilling Serv Rig: Nabors 19AC Rig Activity: POOH 4 u Job No.: AK -MW- 5710484 Report For: Rodney /Herb I Daily Charges $3,540.00 Total Charges $105,060.00 `3.,. ` �. -® ROP &Gas: Current Avg 24 hr Max Max © ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in • •m 560 SPP •si 2150 IRMIEMEll 240 169 3838 7581 Flow Rate s•m 158 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/.t m1/30 min cP Ib /100ft m1/30 min m• /I % 112323 9.5 9.7 57 - 25 21 5.2 10 8500 10.0 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10 - 120 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) - -- 15 -- 85 - - - -- ' Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type ,. 1 to 9990 221 84 7380 701 432 348 189 TG 7682 to 7570 3838 590 43222 2246 1043 511 166 TG a" 7567 to 7208 1433 281 26930 1476 833 483 186 TG I 7206 to 6827 361 150 13154 962 631 338 110 TG 6819 to 6614 681 140 12739 710 443 237 56 TG to to to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; 1 3 BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas ii I 4124 hr Recap: POOH with fish. Pumping up to 650gpm with 145rpm, pulling tight in some sections. Circulate down stand pipe pressure and ecds to acceptable levels while pulling out of the hole. Lower pump rates with increases to same. Continue pulling out of hole to approimately 6600' at report time. Gas values as high as 3838units were observed. I 1 .,,'-i..,..,,,, Logging Engineer: Boyd Piercey / Eugene Payne * 10000 units = 100% Gas In Air 1 l 1 1 1 Customer: Pioneer Natural Res. Report #: 30 HALLIBUATON Well: ODSN -45i Date: 09/01/2008-5:00 1 Ar Oooguruk 05:00 Depth Progress 12323 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: POOH , Job No.: AK-MW-5710484 Report For: Rodney /Herb Daily Charges $3,540.00 Total Charges $108,600.00 I ROP &Gas: Current Avg 24 hr Max Max © ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - Flow in • •m 542 SPP •si 1500 IMMallYM 2 63 1141 5540 Flow Rate s.m, 154 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De.th ft in out (sec/.t) m1/30 min cP Ib /100ft m1/30 min m•/I % 12323 { 9.4 9.4 47 - 10 15 4.8 10 12000 7.8 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10 -20 120 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff M (current - -- 15 -- 85 - - - -- 1 '. Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I 6596 to 5698 1061 147 13781 703 407 276 78 TG 5 570 to 5512 1141 223 25271 589 194 131 54 TG 5506 to 4935 331 55 5271 195 95 111 36 TG I 3979 to 3894 195 29 3576 135 47 40 18 TG to to to I to to to to 1 Gas Type abreviations: BG Background Gas; GP - Gas Peak; CG Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: POOH with fish. Pumping up to 550gpm with low rpm, pulling tight in some sections. Circulate in casing shoe. Perform FIT pressured up to 700 +psi. Perform rig maitenance, inspect derrick and slip and cut drill line. Pump dry job. Continue pulling out of hole inside casing with noticable swabbing. Start pumping to stop swabbing. Continue pulling out of hole to approimately 2400' at report time. . 1 Logging Engineer: Boyd Piercey / Eugene Payne 10000 units = 100% Gas In Air 1 1 1 1 1 Customer: Pioneer Natural Res. Report #: 31 HALLIBURTON Well: ODSN -45i Date: 09/02/2008 -5:00 1 Area Oooguruk 05:00 Depth Progress 12323 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Cleanout Run I Job No.: AK -MW- 5710484 Report For: Rodney /Herb Daily Charges $3,540.00 Total Charges $112,140.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in • •m 0 SPP •si 0 IEMEIMMIM na 10 58 4869 Flow Rate s•m 0 Gallons /stroke 3.6 s I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids i, Death ft in out sec/et m1/30 min cP Ib /100ft m1/30 min me/1 12323 9.4 9.4 48 14 17 4.5 10 12000 7.8 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 200 Sec FSF3563Z 9.88 1.108 88.08 4985 7338 10 -20 120 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current - -- 15 -- 85 - - - -- 1 1 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 4826 to 4916 58 10 to to to to to to to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas '4 PO OH with fish. Pumping to 550 m rpm, � 24 hr Recap: low r m pulling tight in some sections. Circulate p p g p gp p p g g ate in casing shoe due to swabbing. Continue out of hole to surface. Lay down fishing BHA and Fish. Perform rig maintenance Pick up and make up clean out run BHA and run in hole with same. Perform shallow hole test on MWD tools and continue I running in hole to casing shoe. Circulate and condition mud at shoe. Hole giving back proper pipe displacement and taking proper fill in pipe. Rih to shoe and circulate 4 bottums up while servicing top drive. t 1 I 4 Logging Engineer: Boyd Piercey / Eugene Payne * 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 32 HAL LIIBURTON Well: ODSN -45i Date: 09/03/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 12323 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Cleanout Run Job No.: AK -MW- 5710484 Report For: Rodney /Herb Daily Charges $3,540.00 Total Charges $115,680.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in • .m 0 SPP •si 0 IIETHEMIM 69 41 1195 7565 Flow Rate s•m, 0 Gallons /stroke 3.6 '' I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/.t m1/30 min cP Ib /100ft m1/30 min m•/I % 12323 9.4 9.4 75 - 16 24 4.2 10 12000 7.3 - :1 . -. 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 300 MZ7514 8.75 3.142 0 - - -- 200 Sec FSF3563Z 9.88 1.108 88.08 4985 12323 7339 10 -20 120 1- 1- CT- C- X- I -NO -HP 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current - -- 15 -- 85 - - - -- U Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I 7560 to 7570 1195 360 40599 1212 404 154 34 TG 9944 to 9970 698 192 19269 990 454 235 73 TG 9975 to 1026 89 55 5126 346 155 83 101 TG I to to to to t0 1 t° to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: After RIH with cleanout run to shoe. Service top drive for electrical failure. Continue to RIH to approx 7500' and circulate 2.5 bottums up. Continue to RIH to 9990 and circulate to swap mud over to 10.5ppg. Approx 1400bbIs. 1 1 Logging Engineer: Boyd Piercer / Eugene Payne ` 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 33 HALLIBURTON Well: ODSN -45i Date: 09/04/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 12323 Location: North Slope ress 24 hrs: 0 S perry Drilling Services Rig: Nabors 19AC Rig Activity: Cleanout Run Job No.: AK -MW- 5710484 Report For: Rodney /Jeff I Daily Charges $3,540.00 Total Charges $119,220.00 x' I b' ROP&Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING 1 N r R.O.P. ft/hr na - -- Flow in ..m 615 SPP .si 2458 V 189 205 994 11539 Flow Rate s.m 175 Gallons /stroke 3.6 E Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De.th ft in out (sec/.t m1/30 min cP (Ib /100ft m1/30 min ma/1 12323 10.5 10.5 52 - 20 28 4 9 13000 10.3 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 300 MZ7514 8.75 3.142 0 _ - -- 200 Sec FSF3563Z 9.88 1.108 88.08 4985 12323 7339 10 -20 120 1 - 1 - CT C - X - I - NO - HP 1 ; < , Lith ( %): Sd S st Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) - -- 15 -- 85 - - - -- 1 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type lills* 9972 to 10036 134 72 7421 420 222 148 73 TG 11061 to 12015 994 296 29447 1561 609 287 78 TG WI 12032 to 12207 89 55 22979 1433 703 390 115 TG 0117' to to to to to to , � to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas ii h "^ -. t ` nd ' ` f'�3 yr ° °:' 24 hr Recap: RIH to 10,038' and 6 circulate 2 bottums up at 00gpm to clean hole and continue with mud swap to 10.5ppg. RIH to 10,725' and continue in, reaming to 12217'. Pump high vis sweep and continue to circulate to clean hole in preperation for dynamic FIT. ke Al Logging Engineer: Boyd Piercey / Eugene Payne 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 34 HALLIBURTON Well: ODSN -45i Date: 09/05/2008 -5:00 I Area: Oooguruk 05:00 Depth 12323 Location: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Cleanout Run Job No.: AK -MW- 5710484 Report For: Rodney /Jeff 1 Daily Charges $3,540.00 Total Charges $122,760.00 ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING . R.O.P. ft/hr na - -- Flow in • •m 615 SPP •si 2458 IDEMED' 201 110 380 12199 Flow Rate s•m 175 Gallons /stroke 3.6 I Mud Data Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De.th ft in out sec/• m1/30 min cP Ib /100ft m1/30 min me/1 % 12323 11.5 11.5 51 - 20 27 5.2 8.90 12500 12.3 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 300 MZ7514 8.75 3.142 0 - - -- 200 Sec FSF3563Z 9.88 1.108 88.08 4985 12323 7339 10 -20 120 1 - 1 - CT C - X - I - NO - HP Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff a (current) - -- 15 _- 85 - - - -- I Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to 12199 380 99 8562 497 330 261 115 TG 12199 to 11835 150 32 7214 431 228 125 59 TG 11800 to 10786 89 55 10962 872 425 239 36 TG to to to 4 to 1 '!..,,,, to to — — ,.,.., to to ,., :,- 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: Performed dynamic FIT to 12.77 ECD. Continue circulating with losses of 51 bbls after flow back. Circulate and build mud weight to 11.5ppg. Start POOH on elevators and noticed increasing hookloads. Continue POOH while pumping 544gpm. ECDs 1 I Logging Engineer: Boyd Piercey / Eugene Payne * 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 35 HALLIBURTON Well: ODSN -45i Date: 09/06/2008 -5:00 II Area: Oooguruk 05:00 Depth Prog 12323 Ai Location: North Slope ress 24 hrs: 0 Sperry Drilling S ervices Rig: Nabors 19AC Rig Activity: T est BOPs Job No.: AK -MW- 5710484 Report For: Jim /Jeff I Daily Charges $3,540.00 Total Charges $126,300.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in • •m 0 SPP •si 0 IHMEMBIN na 26 230 5271 Flow Rate s•m 0 Gallons /stroke 3.6 . -*" ._ Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De.th ft in out sec/.t) m1/30 min cP Ib /100ft m1/30 min me/1 % 12323 11.5 11.5 51 - 19 29 5.8 9.20 13000 14.3 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 300 MZ7514 8.75 3.142 0 - - -- 200 Sec FSF3563Z 9.88 1.108 88.08 4985 12323 7339 10 -20 120 1 - CT C X I - NO - HP Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) -_- 15 -- 85 _ - - -- 1 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I - .,.4. .. 10741 to 10697 151 130 9507 851 471 280 48 TG 8514 to 8418 123 86 7214 431 228 125 59 TG ri 6987 to 6767 145 83 TG 5427 to 4817 230 62 5102 417 221 141 48 TG to to to ¢ - I to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG -Pumps Off Gas; TG Trip Gas I 24 hr Recap: POOH from cleanout run, encountering some tight spots which required pumping on. Lay down BHA. Perform rig maintenance and prepare to test BOPs. Test BOPs to 4500psi. 0 . 1 1.... ....._ Logging Engineer: Boyd Piercey / Eugene Payne * 10000 units = 100% Gas In Air 1 1 1 ': Customer: Pioneer Natura Res. R eport #: 36 HAL.LIBURTON Well: ODSN -45i Date: 09/07/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 12323 Location: North Slope ress 24 hrs: 0 Sperry Dr Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK -MW- 5710484 Report For: Jim /Jeff 1 Daily Charges $3,540.00 Total Charges $129,840.00 I IIIIIIMIIIII.lri ROP &Gas: Cu rrent Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING 1 R.O.P. ft/hr na - -- Flow in • .m 0 SPP es' 0 4 I na 26 429 7567 Flow Rate s.m, 0 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/.t m1/30 min cP Ib /100ft m1/30 min me/1 12323 11.5 11.5 49 15 27 6.2 9.40 13000 13.3 I : ar BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 400 FSF -3563Z 9.88 1.108 12000 - - -- 300 MZ7514 8.75 3.142 0 12000 - -- Clean out run I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff _ current) - -- 15 -- 85 - - -_- 1 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I 11 4931 to 4981 38 21 1654 158 129 84 4 TG 7385 to 7692 429 178 15175 961 434 199 36 TG 9951 to 10141 414 47 3538 300 162 84 20 TG to I to t to to I to to to 1 ti Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas F µr 24 hr Recap: Finish testing BOPs. Rig up and make up new BHA. Start tripping in hole run #400 to drill remaining intermediate section. Encountered tight hole @ 6346' , 7421', 7584 and pumped it down. Run in hole to +/- 10,000' and circulate to condition mud. Continue RIH working tight sections and pumping on same. Approximately 10,600' at report 1 time. 1 Logging Engineer: Boyd Piercey / Eugene Payne * 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 37 HALLIBURTON Well: ODSN -45i Date: 09/08/2008 -5:00 1 Area: Oooguruk 05:00 Depth 12796 Location: North Slope Progress 24 hrs: 473 ' , Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling z Job No. AK -MW- 571048 Report For Jim /Jeff Daily Charges $3,540.00 Total Charges $133,380.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING - R.O.P. (ft/hr) 11.7 79.5 126.4 12437 Flow in (gpm) 600 SPP (psi) 3600 Gas units 433 461 743 7567 Flow Rate s•m' 170 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (m1/30 min) cP (Ib /100ft m1/30 min mg /I % 12512 11.5 11.5 55 - 21 29 4.2 9.40 13000 14.3 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 400 FSF -3563Z 9.88 1.108 12000 300 MZ7514 8.75 3.142 0 12000 Clean out run Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 15 85 ' Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I 10600 to 11179 168 72 3947 297 151 83 13 TG 11932 to 12319 419 202 18200 1976 723 352 93 TG to 12322 770 41974 4104 1731 659 206 CG I to 12417 920 50036 5455 2299 832 243 CG to 12463 731 35890 4593 1966 834 269 PG 12546 to 12699 587 415 23513 2501 1319 635 192 BG to 12702 742 33590 3753 1931 943 310 CG I 12731 to 12779 536 431 23701 2495 1438 761 251 BG to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 1 I 24 hr Recap: RIH to bottom and circulate to swap out with new mud and commence drilling. Drill ahead to approximately 12,800' at report time. 1 1 '$ Logging Engineer: Boyd Piercey /Eugene Payne * 10000 units = 100% Gas In Air 1 __ 1 1 1 Customer: Pioneer Natural Res. Report #: 38 HALLIBURTON Well: ODSN -45i Date: 09/09/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 12868 Location: North Slope ress 24 hrs: 72 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK -MW- 5710484 Report For: Jim /Jeff 1 Daily Charges $3,540.00 Total Charges $136,920.00 I ROP&Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING 0 . R.O.P. ft/hr na 48.0 161.8 12793 Flow in • na SPP •si na 'A EONIEMIIIII 0 162 789 7567 Flow Rate s•m na Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/gt) (m1/30 min) cP (Ib /100ft m1/30 min mg /I % 12512 11.5 11.5 58 - 21 34 5.4 9.40 13500 13.3 I 11 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 400 FSF -3563Z 9.88 1.108 12000 300 MZ7514 8.75 3.142 0 12000 Clean out run Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 10 85 5 I Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 1 12793 to 12868 760 325 19077 2073 1256 690 232 BG 12868 to 11620 789 291 16010 1831 1111 624 209 TG 9063 to 8975 441 333 18561 2361 1486 863 297 TG 5400 to 4908 337 146 9589 1281 950 574 189 TG 1 to to to to r * to to #, € 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 1 24 hr Recap: Drill ahead to 12868' and experienced MWD failure. POOH with tight sections encountered and higher hook loads. Pumped to help pull through these sections. POOH to shoe and circulate bottoms up, then pump dry job and continue to POOH to begginning of BHA at report time. 1 1 Logging Engineer Boyd Piercey / Eugene Payne * 10000 units = 100% Gas In Air w 1 1 1 1 Customer: Pioneer Natural Res. Report #: 39 HALLIBURT ©N Well: ODSN -45i Date: 09/10/2008 -5:00 `,•; 1 I Ara: Oooguruk 05:00 Depth 12868 Location: North Slope Progress 24 hrs: 0 ,, Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Run in hole Job No.: AK - 5710484 Report For: Jim /Jeff 1 Daily Charges $3,540.00 Total Charges $140,460.00 I ROP&Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na 0.0 0.0 0 Flow in • •m 600 SPP •si 3500 162 119 1770 12550 Flow Rate s • m 169 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/it m1/30 min cP Ib /100ft m1/30 min ma/1 % 12868 11.5 11.5 55 - 19 30 5.8 10.00 13500 13.3 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 500 FSF -3563Z 9.88 0.982 12868 - - -- 400 FSF -3563Z 9.88 1.108 8.8 12323 12868 545 1 -29 122 0 - 1 - CT T - X - I - NO - DTF x _ Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current) - -- 10 -- 85 -_- 5 1 i Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I 4833 to 4928 112 64 3395 608 553 384 131 TG to 7555 775 29184 3348 2202 1147 352 BUG to 10000 1120 39115 5023 2918 1543 419 TG 10013 to 10145 295 177 12572 1519 1125 684 221 TG I to 12550 1770 400 BUG to to to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: Finish POOH to s urface and swap out MWD tools to make up RIH # 7. H with sa me to casing shoe and stage circulat Perform rig maintenance and slip / cut drill line. Continue RIH approximately 7,500' and stage circulation. Continue further in the hole to approximately 10,000' and repeat stage circulation. Continue to TD reaming last few stands. 1 X At approximately 12,000' complete 1,000 bbl mud swap as per HES mud engineer. 12,641' @ report time. 1 1 Logging Engineer: Boyd Piercey / Eugene Payne * 10000 units = 100% Gas In Air #., 4 ,7.:. - •-• - ;, - --,.. -_ --,,,,-,:.:*: -,,, , ,- ,....,..,-,-._...: , ,.-„,„..............,,,,,.. . -, 1 1 1 1 1 Customer: Pioneer Natural Res. Report #: 40 HALLIBURTON Well: ODSN -45i Date: 09/11/2008 -5:00 I Area: Oooguruk 05:00 Depth 13286 Location: North Slope Progress 24 hrs: 418 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK -MW- 5710484 Report For: Jim /Nick 1 nz Daily Charges $3,540.00 Total Charges $144,000.00 1 rt- -' ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr 71.0 48.6 126.0 13205 Flow in • •m 646 SPP •si 3900 ''IMEIBMIll 232 308 2208 12550 Flow Rate s•m, 184 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/•t m1/30 min cP Ib /100ft m1/30 min me/1 % 12868 11.5 11.5 52 21 27 5.2 9.30 15000 13.2 4 " 1 ; 1:3 :; 11 :' HA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 500 FSF -3563Z 9.88 0.982 12868 - - -- 400 FSF -3563Z 9.88 1.108 8.8 12323 12868 545 1,. 1 -29 122 0- 1- CT- T- X- I- NO -DTF 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff � (current) - -- 20 -- 80 - - - -- : ' Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type i 12614 to 12814 531 281 19269 1896 1023 493 131 TG 12903 to 12941 284 260 18275 1613 875 437 122 BG to 12951 2208 65061 6133 2729 1125 313 CG , 12984 to 13226 290 283 19406 1865 1030 549 188 BG to ' to to • to to to to k Gas Type abreviations: BG - Background Gas; - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG Trip Gas r, 24 hr Rec RIH to 12,868' circulating down the last few stands, fighting tight hole and torque situations. Commence drilling ahead. Perform rig mud pump repares on pump 2. Continue drilling ahead to 13,234' and repair pump 2 again. Pull back one stand and work pipe while waiting on repairs each time. 1 3 33 ap: 1 Logging Engineer: Boyd Piercey / Eugene Payne * 10000 units = 100% Gas In Air I 1 1 1 Customer: Pioneer Natural Res. Report #: 41 HALUBURTON Well: ODSN -45i Date: 09/12/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 13583 Location: North Slope ress 24 hrs: 286 • S perry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK -MW- 5710484 Report For: Jim /Nick 1 Daily Charges $3,540.00 Total Charges $147,540.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr no 47.4 140.8 13560 Flow in • •m 498 SPP •si 2790 I I 221 207 429 13536 Flow Rate s.m, 141 Gallons /stroke 3.6 1 Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/•t m1/30 min cP Ib /100ft m1/30 min m./I % 13583 11.9 11.9 52 - 22 37 5.8 9.50 15000 15.3 I ',.,:, BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 500 FSF -3563Z 9.88 0.982 12868 -_ -- 400 FSF -3563Z 9.88 1.108 8.8 12323 12868 545 1 -29 122 o- 1- CT- T- X- I- NO -DTF I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) - -- 20 -- 80 - - - -- 1 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I 13292 to 13465 315 244 17011 1471 847 485 172 BG 13466 to 13554 394 296 20591 1694 942 530 190 BG 13560 to 13584 284 257 18304 1480 806 459 166 BG I 13554 to 13162 299 291 13358 1174 697 411 154 WTG 13488 to 13000 429 206 15993 1424 825 480 178 TG 13000 to 12900 488 226 18147 1500 776 438 164 TG to 1 13466 to 409 300 25488 2353 1236 662 249 CG to to to 0 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas ' Vit.ft).,--. :-' -'.' - Ag..., "Ati0604, k.., , .,: : 7 . ,.-,‘,,,'•'- -- ,:-., - -- - i.:,..; - ',...:- ,-.4 . 0 :: - . ' 24 hr Recap: Drill ahead to 13583' experiencing tight hole conditions with high torque. Lost communication with MWD tools and decision was made to POOH. Circulate and condition hole back reaming out to help clean it. RIH to TD and weight up mud to 12ppg to hold formation. POOH to approx 12,900'. 1 oi 1 Logging Engineer: Boyd Piercey / Eugene Payne * 10000 units = 100% Gas In Air `�..` 1 1 1 1 Customer: Pioneer Natural Res. Report #: 42 HAIJ.IBURTON Well: ODSN -45i Date: 09/13/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 13583 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Tripping Job No.: AK - 5710484 Report For: Jim/Nick Daily Charges $3,540.00 Total Charges $151,080.00 ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING I R.O.P. ft/hr na - -- Flow in • •m 492 SPP •si 2200 na 250 1250 13583 Flow Rate s•m 140 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De•th ft in out seGst m1/30 min cP Ib /100ft m1/30 min m•/I % 13583 12.0 12.0 49 - 18 31 6.4 9.50 15000 15.3 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 500 FSF -3563Z 9.88 0.982 13.5 12868 13583 715 13 -20 125 n/a 400 FSF -3563Z 9.88 1.108 8.8 12323 12868 545 1 -29 122 0- 1- CT- T- X- I- NO -DTF Llthology ( % ): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal GvI Tuff current - -_ 20 -- 80 -_ - -- III Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I 13583 to 13583 1250 250 74557 9403 4448 2107 675 GP to to 1 to to to to I to to to to Gas Type abrev iations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG Pumps Off Gas; TG -Trip Gas 1 24 hr Recap: Weighted up to 12 ppg. POOH, tight at 13060', 13012', 13000', 12941', 12928', 12925', 12916', 12856', 12789', 12750', and 12340'. Work tight spots and ream and wash from 8818' to 10712' with a max gas of 1250 units. Pull on elevators from 10712' to inside casing at 4971'. Circulate inside casing with a max gas of 285 units. Continue POOH at report time. 1 0 Logging Engineer: Tom Mansfield / Eugene Payne * 10000 units = 100% Gas In Air n . , 1 1 1 1 I Customer: Pioneer Natural Res. Report #: 43 HALLIBUR'TON Well: ODSN -45i Date: 09/14/2008-5:00 1 Area: Oooguruk 05:00 Depth Progress 13583 Location: North Slope ress 24 hrs: 0 S perry Drilling Services Rig: Nabors 19AC Rig Activity: Tripping Job No.: AK-MW-5710484 Report For: Jim /Nick Daily Charges $3,540.00 Total Charges $154,620.00 ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING 1 R.O.P. ft/hr na - -- Flow in . •m 401 SPP •si 1825 'M�1 _ 73 30 556 circ at 7740' Flow Rate s.m 115 Gallons /stroke 3.6 t ` , I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De.th ft in out sec/•t m1/30 min cP Ib /100ft m1/30 min m• /1 % 13583 12.0 12.0 55 - 21 36 7 9.50 15000 15.3 1.'1 '` 1 , BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition f. 600 FSF -3563Z 9.88 0.982 - 13583 _ - -- 500 FSF -3563Z 9.88 0.982 13.5 12868 13583 715 13 -20 125 2- 1- CT- CT- X- I- NO -DTF 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) - -- 20 -- 80 - - - - -;. Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type .. 4892 to 4892 79 79 4916 785 650 433 168 TG 7740 to 7740 556 385 32378 3147 1654 860 314 TG to :,. I to to to to to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas I ; 24 hr Recap: POOH. Function test BOP's. Change out MWD. RIH to 4892' and circulate bottoms up with max gas of 79 units. Send 255 bbls mud to RSC. Return 210 bbls from RSC to pits. RIH to 7740' and circulate bottoms up with max gas of 556 units. Continue RIH changing out some worn pipe. Circulate at 10000' at report time. 1 Logging Engineer: Tom Mansfield / Eugene Payne * 10000 units = 100% Gas In Air 1 1 1 1 1 .. * =*:.ii Customer: Pioneer Natural Res. Report #: 44 HALLIBURTON Well: ODSN -45i Date: 09/15/2008 -5:00 I Area: Oooguruk 05:00 Depth 13866 Location: North Slope Progress 24 hrs: 283 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Circ. Prior to POOH Job No.: AK -MW- 5710484 Report For: Jim /Nick 1 Daily Charges $3,540.00 Total Charges $158,160.00 { II ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr 50.8 38.1 122.0 13770 Flow in • •m 494 SPP •si 2630 IEZMID 313 365 629 13852 Flow Rate s•m, 140 Gallons /stroke 3.6 i' I:- : I M ud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out (sec/•t m1/30 min cP Ib /100ft m1/30 min m. /I % 13803 12.0 12.0 48 - 20 30 6 9.30 15000 15.3 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 500 FSF -3563Z 9.88 0.982 13.5 12868 13583 715 13 -20 125 2 - 1 - CT- CT X - I - NO - DTF 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 20 20 -- 60 _ - - -- x Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I 13583 to 13583 3830 83855 8614, 3543 1418 376 TG 13583 to 13655 321 270 23871 1723 585 179 15 BG 13655 to 13670 451 425 36292 3407 1451 483 137 BG I 13670 to 13760 260 225 16951 1470 798 394 135 BG 13760 to 13815 324 310 23548 2058 1068 509 199 BG 13815 to 13866 621 450 32711 3110 1532 627 205 BG to 111 ;1i to to to to 1 , ;'1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; t BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas g �$ f$t;. < ;..Fe �.,: ��.. l.zw :'Y., •: ?`, .,a x i f "iL:rv. ! C,Jt , 24 hr Recap: Circulate B/U at 10000'. RIH. Wash and Ream f/ 12600' to 13583' w/ max trip gas of 3830 units. Drill to 13866' and TD intermediate hole interval. Circulate 3.5 bottoms up. String torqued to 30K and ECD spiked to 14.8 as hole tried to pack off losing 28 bbls mud. Moved pipe down and staged pumps up slowly, continuing to clean hole. Circulating 1 out at report time. i Logging Engineer: Tom Mansfield / Eugene Payne * 10000 units = 100% Gas In Air 1 1 1 1 1 Customer: Pioneer Natural Res. Report #: 45 HALLIBURTON Well: ODSN -45i Date: 09/17/2008 5:00 I Area: Oooguruk 05:00 Depth Prog 13866 ation: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC R ig Activity: Tr ipping „: Job No.: AK-MW-5710484 Report For: Jim /Nick Daily Charges $3,540.00 Total Charges $165,240.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in • •m - SPP •si IMIEUMIIMI 4455 174 4455 13866 STG Flow Rate s • m - Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/•t m1/30 min cP Ib /100ft m1/30 min m•/I % 13803 12.5 12.5 53 - 23 30 6.2 9.50 16000 15.2 111111111111IMMIS *:•;.: 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 500 FSF -3563Z 9.88 0.982 13.5 12868 13583 715 13 -20 125 2 - 1 - CT CT X - I - NO - DTF 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current) 20 20 -- 60 _ - - -- 1 Gas Breakdown Gas (units) Chromatograph (ppm) ' Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 13866 to 13866 4435 393871 14570 4904 2227 392 STG to to 1 .4 to tO tO t0 t0 _ . to ' to ti Gas Type abreviations BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas ill 24 hr Recap: Circulate out with max gas of 1655 units. POOH to 10000'. Tight and packed off at 13630', 13476'. Circulate and condition at 10000' with a max gas of 1815 units. RIH, wash and ream tight spots as needed while weighting up mud to 12.5 ppg. Circulate bottoms up with 4435 units STG. • 1 Logging • Engineer: Tom Mansfield / Eugene Payne 10000 units = 100% Gas In Air 1 1 1 1 " ' - ..' Customer: Pioneer Natural Res. Report #: 46 HALLIBURTON Well: ODSN -45i Date: 09/18/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Run CSG Job No.: AK -MW- 5710484 Report For: Jim /Nick I Daily Charges $3,540.00 Total Charges $168,780.00 ..,.. fir. ROP &Gas: Current Avg 24 hr Max Max @ ft P um p & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in ..m SPP .si -, +.:1=EDS. na 75 118 Flow Rate s•m Gallons/stroke 3.6 ri 71 I Mud Data: Density ( ; p 9 ) Visco HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/.t m1/30 min cP Ib /100ft m1/30 min m. /1 13803 12.5 12.5 52 - 15 22 6 9.50 15000 16.3 II BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 500 FSF -3563Z 9.88 0.982 13.5 12868 13583 715 13 -20 125 2 - 1 - CT CT X - I - NO - DTF Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current 20 20 -- 60 f I Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 13866 to 13866 4435 393871 14570 4904 2227 392 STG ' to to to to t0 to 1 to to t0 . t0 1 } Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG Trip Gas 24 hr Recap: Continued circulating bottoms up from short trip with a maximum short trip gas of 4455 units. Weighted up mud system to 12.5 ppg. POOH to 4948' washing and reaming tight spots as needed. Slip and cut drill line. Continue POOH. 1 1 1 Logging Engineer: Tom Mansfield / Eugene Payne * 10000 units = 100% Gas In Air r 1 1 1 r y ' ;et a '''':*1 Customer: Pioneer Natural Res. Report #: 47 HALLIBURTON Well: ODSN - 45i Date: 09/18/2008 - 5:00 1 Area: Oooguruk 05:00 Depth Prog 13866 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Run CSG Job No.: AK -MW- 5710484 Report For: Jim /Nick 1 Daily Charges $3,540.00 Total Charges $168,780.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in •.m - SPP •si i p na 75 118 Flow Rate s•m,- Gallons /stroke 3.6 ter« I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out secht m1/30 min cP Ib /100ft m1/30 min m• /I 13803 12.5 12.5 52 - 15 22 9.00 15000 17.3 y r . . 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD 500 FSF -3563Z 9.88 0.982 13.5 12868 13583 715 13 -20 125 2 - 1 - CT CT x - I - NO - DTF Litholog Sd Sst Silt Siltst Cht Clyst Sh y ( %): Lst Coal Gvl Tuff (current) 20 20 -- 60 _ - - -- 1 Gas Breakdown Gas (units) Chromatograph (ppm) 1 Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to to 1 to to to 111 to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; el BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: POOH. Rig up for running 7 5/8 "casing. Run casing. 1 1 Logging Engineer: Tom Mansfield / Eugene Payne * 10000 units = 100% Gas In Air 1 1 1 1 ' Customer: P ioneer Natural Res. R eport #: 48 HALLIBURTON Well: ODSN -45i Date: 09/19/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Run CSG Job No.: AK -MW- 5710484 Report For: Jim /Nick 1 Daily Charges $3,540.00 Total Charges $172,320.00 I ROP &Gas: Current Avg 2 4 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. thr) na Flow in - PP (psi) units s na Flow Rate te s. s.m Gallons/stroke 3.6 . „..„ I Mud Data: Depth ft Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids in out (sec/gt) (m1/30 min) cP (Ib /100ft m1/30 min mg /I % 13803 12.5 12.5 57 - 19 30 6 9.00 15000 17.3 n 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 600 FSF -3563Z 9.88 0.982 7.43 13583 1 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD 500 FSF -3563Z 9.88 0.982 13.5 12868 1 13583 715 13 -20 125 2 - 1 - CT CT X - I - N0 4 Lithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 20 20 60 Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to to 1 to to to 1 ,,, Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: Run 7 5/8" CSG. 1 Logging Engineer: Tom Mansfield / Eugene Payne " 10000 units = 100% Gas In Air 1 ,..:4: 1 1 1 Customer: Pioneer Natural Res. Report #: 49 HALUBUATON Well: ODSN -45i Date: 09/20/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 Sperry Drilling Serv Rig: Nabors 19AC Rig Activity: Run CSG Job No.: AK -MW- 5710484 Report For: Jim /Nick Daily Charges $3,540.00 Total Charges $175,860.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING . R.O.P. ft/hr na - -- Flow in • •m - SPP •si na - -- Flow Rate s•m,- Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out (sec/.t mI /30 min cP Ib /100ft m1/30 min m• /I % 13803 12.5 12.5 57 - 19 30 6.3 9.50 15000 17.3 I A i! BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10-18 124 3- 2- CT- CT- X- I -ER -TD 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current ------ - - - - -- Ill Gas Breakdown • 14: Gas (units) Chromato ra h (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I to to to to to to to 1 to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; i BUG Bottoms Up Gas: POG - Pumps Off Gas TG Trip Gas } 1 t '' .."• , } 24 hr Recap: Run 7 5/8" CSG. Rig up wireline and run packer. Set packer at 204. Retrieve and rig down wireline. Continue runn casing. 1 1 ti Logging Engineer: Tom Mansfield / Eugene Payne * 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 50 HALI.IBURTON Well: ODSN -45i Date: 09/21/2008 -5:00 I Area: Oooguruk 05:00 Depth 13866 ation: North Slope Progress 24 hrs: 0 Sperry Driling ervces Rig: Nabors 19AC Rig Activity: Run CSG Job No.: AK -MW- 5710484 Report For: Jim /Nick 1 Daily Charges $3,540.00 Total Charges $179,400.00 I ,. ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) na Flow in (gpm) SPP (psi) •- Gas units na Flow Rate s•m' Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (m1/30 min) cP (Ib /100ft m1/30 min mg /I % 13866 12.5 12.5 58 - 19 29 6 8.70 15000 17.3 . - . ._, 7 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD 1 Lithology ( %): Sd Sst 1 Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) • Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to I to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas I c 24 hr Recap: Running 7 5/8" CSG. Packer set at 204'. Rotate down and fill CSG. Continue running CSG to 11395'. CSG stuck after connection at 11395'. Prepare to run in and pull packer at report time. 1 1 Logging Engineer: Tom Mansfield / Eugene Payne * 10000 units = 100% Gas In Air 1 1 1 1 1 Customer: Pioneer Natural Res. Report #: 51 HALLIBURTON Well: ODSN -45i Date: 09/22/2008 -5:00 1 Area: Oooguruk 05:00 Depth 13866 ( Location: North Slope Progress 24 hrs: 0 S perry Drilling Services Rig: Nabors 19AC Rig Activity: Run CSG Job No.: AK - 5710484 Report For: Jim /Nick 1 Daily Charges $3,540.00 Total Charges $182,940.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in • •m - SPP •si IIMMEMIll na 122 11395 Flow Rate s•m Gallons /stroke 3.6 u ,, I Mud Data Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/•t MI/30 min cP Ib /100ft m1/30 min m• /I 13866 11.5 12.2 51 - 24 23 5.6 9.80 15000 13.2 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD Lithology ( %): k Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current) ------ - - - - -- Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I to to to to I to € to to it to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; 4 BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas .wx fr L ��* t. z k ' ry y , 24 hr Recap. P/U 4" DP and RIH to engage packer at 1600'. Allow mud to drain below packer. Pull packer and POOH. Fill CSG w/ 11.5 ppg mud. R/U to pump 11.5 ppg mud down casing. Pump down casing at 88 qpm, 25 spm with good i. returns, 120 units of gas, for 20 minutes before losing 157 bbls down hole. Work pipe. Attempt to circulate again with it,. ...*:11,1 ' additional 16 bbls lo Work pipe at report time. 1 Logging Engineer: Tom Mansfield / Eugene Payne * 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 52 HALLIBURTON Well: ODSN -45i Date: 09/23/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 13866 L North Slope ress 24 hrs: 0 Sperry Grilling services Rig: Nabors 19AC Rig Activity: L/D Drill Pipe I Job No.: AK -MW- 5710484 Report For: Jim /Nick Daily Charges $3,540.00 Total Charges $186,480.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in • .m - SPP .si na - -- Flow Rate s•m - Gallons /stroke 3.6 1 Mud Data Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/.t m1/30 min cP Ib /100ft m1/30 min me /I % 13866 11.5 11.5 45 - 16 18 5.5 8..80 15000 17.3 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) ------ - - - - -- 1 Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to I to tO to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas " .e.: 24 hr Recap: r. Lost returns, unable to move CSG. R/U to cement CSG. Cement CSG with no returns. Nipple up BOPs. 1 Logging Engineer: Tom Mansfield / Eugene Payne * 10000 units = 100% Gas In Air 1 1 1 Customer: Pioneer Natural Res. Report #: 53 HALIIUBURTON Well: ODSN -45i Date: 09/24/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 S perry Drilling Services Rig: Nabors 19AC Rig Activity: T.I.H. Job No.: AK -MW- 5710484 Report For: Jim /Nick 1 Daily Charges $3,540.00 Total Charges $190,020.00 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in • •m - SPP •si p na - -- Flow Rate s•m,_ Gallons /stroke 3.6 ' I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De.th ft in out (sec/.t m1/30 min cP Ib /100ft m1/30 min m• /1 % 13866 12.5 12.5 44 - 16 23 6.5 8.00 15000 17.3 i BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3- 2- CT- CT- X- I -ER -TD I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) ------ - - - - -- I III Gas B reakdown cii Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I to to to to ' !,: to o to 4 to to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 3 f. te 24 hr Rec Nipple up B.O.P.'s Lay dow 5 "drill pipe. 1 1 Logging Engineer: Tom Mansfield / Mike Daigle * 10000 units = 100% Gas In Air 1 1 1 Customer: Pioneer Natural Res. Report #: 54 HALUBUATON Well: ODSN -45i Date: 09/25/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: T.I.H. l' Job No.: AK -MW- 5710484 Report For: Jim /Nick s D aily Charges $4,340.00 Total Charges $194,360.00 ,,. I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr na - -- Flow in • •m - SPP •si na - -- Flow Rate s•m,- Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out seG8t m1/30 min cP Ib /100ft m1/30 min m• /I % 13866 12.5 12.5 44 - 16 23 6.5 8.50 15000 17.3 I ., tAi't # , : : . q~ Y• •. n: �$ V r, k, 4 , -. BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) M , Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to 1 to to to to 1 to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG Pumps Off Gas; TG Trip Gas 24 hr Recap: Lay down 5" drill pipe, T.I.H. with 4" drill pipe. 1 1 • ' Logg Eng Tom Mansfield / Mike Daigle * 10000 units = 100% Gas In Air 1 1 �1 1 Customer: Pioneer Natural Res. Report #: 55 HALURTON Well: ODSN -45i Date: 09/26/2008 -5:00 I IB Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 S perry Drilling Services Rig: Nabors 19AC Rig Activity: P.O.O.H. 1 Job No.: AK -MW- 5710484 Report For: Jim /Nick , Daily Charges $3,540.00 Total Charges $197,900.00 L ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING ill R.O.P. ft/h N/A N/A N/A N/A Flow in ..m N/A SPP •si p N/A 7 14 N/A Flow Rate s•m N/A Gallons /stroke 3.6 > >.,,.. I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De.th ft in out sec/.t m1/30 m i n cP Ib /100ft ml /30 min . /I 13866 12.5 12.5 52 19 21 4.4 9.00 150 17.3 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff - (current) ------ - - -_ -- 1 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I 1:'`.: to to to to I to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas ,n 24 hr Recap: Pi up B.H.A., Trip in hole, Wash and ream from 11171' to 11289', tagged cement at 11266", Drilling cement 1 i 1 A ,,,,, I Logging Engineer: Tom Mansfield / Mike Daigle * 10 000 units = 100% Gas In Air s = 1 1 I Customer: Pioneer Natural Res. 1 ALL BURTON Well: ODSN-45i Report #: 56 05:00 D D e a p t t e h : 09/27/2008-5:00 13866 I Area: Oooguruk Location: North Slope Progress 24 hrs: 0 ! t - ) Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Wash and Ream Job No.: AK-MW-5710484 Report For: Rod/Jeff I Daily Charges $4,340.00 Total Charges $202,240.00 ','••., I ROP&Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) N/A N/A N/A N/A Flow in (qpm) 405 SPP (psi) 1389 Gas units 350 394 3907 N/A Flow Rate s.m N/A Gallons/stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (m1/30 min) cP (lb/100ft m1/30 min mg/I % 1 13866 12.5 12.5 55 25 30 4.8 9.20 15000 18.3 1 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 1 1 Lithology (%): 1 Sd Sst I Silt Siltst Cht Clyst Sh 1 Lst Coal Gvl I Tuff I (current) I Gas Breakdown Gas (units) Chromatograph (ppm) R Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to ss to ., to I ':::: to to to ,. 1 to to -4 to - s 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas ;.' :f.:14 . ''.•• . '2.-:';`-..; • .: ' -.. . • .../ , , .. - !:.•1 1 ,10.43.. , . , :. .,. -' -k...',..'. ' ' ',. .:-": 24 hr Recap: Wash from 11320 to 11377, drilled through shoe to 11438, Logged cased hole from 11420' to 10330', Run in hole from 10328' to 13379. Circulate, lost returns, reduced pumps, Washed tight at 13589' packed off, pulled to free A . . .., I ' Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air ii itilk: 11111.1111M ;: 1 ; '` '-\ ' ;,;' ."' "- '• . *,.'', ,‘,t1-:. " ' : i 1 I 1 Customer: Pioneer Natural Res. Report #: 57 i s HALLIBURTON Well: ODSN - 45i Date: 09/28/2008 - 5:00 1 Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 Sperry Drilling Serv Rig: Nabors 19AC Rig Activity: P.O.O.H. Job No.: AK -MW- 5710484 Report For: Rod /Jeff 1 Daily Charges $3,540.00 Total Charges $205,780.00 ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING 1 R.O.P. (ft/hr) N/A N/A N/A N/A Flow in (gpm) 283 SPP (psi) 3960 Gas (units) 364 734 5711 N/A Flow Rate (spm; 81 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (m1/30 min) cP (Ib /100ft m1/30 min mg /I % 13866 12.5 12.5 55 - 25 30 4.8 9.20 15000 18.3 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition mow. . ,.. c..: ,:..: 1 . . Lit hology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 1 .r w � fi Gas B reakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I p to to e to to I to to to 1 to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas I 24 hr Recap: Back reaming from 13693' to 13596' packed off, Reaming from 13693' to 13789', Back reaming to 13565' , Tripped and worked tight spot at 13580', reamed to 13473' tight and packed off, Worked through and regained circ, Circ and cond, back ream from 13307' to tight spots at 13243' ,13180', 13178', back reaming from 13178' to 13095' at report 1 1 . Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 58 HALLIBURTON Well: ODSN -45i Date: 09/29/2008 -5:00 I Area: Oooguruk 05:00 Depth 13866 Location: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Reaming Job No.: AK -MW- 5710484 Report For: Rod /Jeff --1 Daily Charges $3,540.00 Total Charges $209,320.00 I s " ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) N/A N/A N/A N/A Flow in (gpm) I 283 I SPP (psi) I 396 le Gas units 124 530 5711 N/A Flow Rate (spmj 81 Gallons /stroke 3.6 0 ; :,1 f I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids a i Depth ft in out (sec/gt) (m1/30 min) cP (Ib /100ft m1/30 min m. /I % 13866 12.5 12.5 55 - 25 30 4.8 9.20 15000 18.3 At` 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current I I I Gas Breakdown i. Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I ''''ii to to to to to to 11 1 to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; II BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 1 24 hr Recap: Back reaming from 13693' to 13596' packed off, Reaming from 13693' to 13789', Back reaming to 13565' , Tripped and worked tight spot at 13580', reamed to 13473' tight and packed off, Worked through and regained circ, Circ and cond, back ream from 13307' to tight spots at 13243' ,13180', 13178', back reaming from 13178' to 13066' at report 1 time. 1 Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air a ? 1 1 1 1 1 ...",..,...,,,...— Customer: Pioneer Natural Res. Report #: 60 HALLIBURTON Well: ODSN-45i Date: 10/01/2008-5:00 I Area: Oooguruk 05:00 Depth 13866 *:'4' Location: North Slope Progress 24 hrs: 0 i Sperry Drilling Services Rig: Nabors 19AC Rig Activity: P.O.O.H. Job No.: AK-MW-5710484 Report For: Rod/Jeff I Daily Charges $3,976.60 Total Charges $213,296.60 I ROP&Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) N/A N/A N/A N/A Flow in (gpm) N/A SPP (psi) N/A Gas units N/A 214 2042 N/A Flow Rate (spms,, N/A Gallons/stroke 3.6 !II -' "lf.c:■„.g,,,, I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (mI/30 min) cP (lb/100ft m1/30 min mg/I 13866 12.5 12.5 55 19 26 5.2 8.80 16000 18.3 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) I ;14 Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to — to I to to _ to to I to _ ...4, ' to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; VVTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas .„. I ' 24 hr Reca Back reamed from 13866' to 13070', Reamed and circ out of hole to 12729' lost 750psi, continued to circ out of hole to 12439', Back reamed from 12397' to 11438' with reamer up above shoe, slip and cut drill line, P.O.O.H. to 10590' 1 1 Logging Engineer: Boyd Piercey / Mike Daigle " 10000 units = 100% Gas In Air ; , '''',.—,.., : ,.ric , '''.W.4.:.„, ,7,-,:A= 1 1 1 1 Customer: Pioneer Natural Res. Report #: 60 HALLIBURTON Well: ODSN -45i Date: 10/01/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: P.O.O.H. Job No.: AK -MW- 5710484 Report For: Rod /Jeff I ' Daily Charges $3,720.12 Total Charges $217,016.72 m ri ' ROP&Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING r R.O.P. (ft/hr) N/A N/A N/A N/A Flow in (gpm) N/A SPP (psi) N/A Gas units) N/A 214 2042 N/A Flow Rate (spmf N/A Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids t Depth ft in out (sec/gt) (m1/30 min) cP (Ib /100ft m1/30 min mg/1 % 13866 12.5 12.5 55 - 19 26 5.2 8.80 16000 18.3 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3- 2- CT- CT- X- l -ER -TD 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 1 Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to to to to to I to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: Back reamed from 13866 to 13070', Reamed and circ out of hole to 12729' lost 750psi, continued to circ out of hole to 12439', Back reamed from 12397' to 11438' with reamer up above shoe, slip and cut drill line, P.O.O.H. to 10590' at report time. 1 1 Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natura Res. Report #: 61 HALLIBURTON Well: ODSN -45i Date: 10/02/2008 -5:00 ' Area: Oooguruk 05:00 Depth 13866 Location: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: L/D B.H.A. Job No.: AK -MW- 5710484 Report For: Rod /Jeff I Daily Charges $3,720.12 Total Charges $220,736.84 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. (ft/hr) N/A N/A N/A N/A Flow in (gpm) N/A SPP (psi) N/A Gas (units) N/A 214 N/A N/A Flow Rate (spm, N/A Gallons /stroke 3.6 I = Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (m1/30 min) cP (Ib /100ft m1/30 min mg /I % 13866 12.5 12.5 55 - 19 24 4.8 8.80 16000 18.3 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff . (current) Gas Breakdown Gas (units) Chromatograph (ppm) Depth to Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I to I to to to to to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: P.O.O.H. to 6175', Repair top drive, continue to P.O.O.H. from 6175' to B.H.A., L/D B.H.A. 1 1 Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 62 HALUBURTON Well: ODSN -45i Date: 10/03/2008 -5:00 I rea: Oooguruk 05:00 Depth 13866 Location: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Service Top Drive Job No.: AK -MW- 5710484 Report For: Rod /Nick I Daily Charges $3,720.12 Total Charges $224,456.96 ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING I -, R.O.P. ft/hr N/A N/A N/A N/A Flow in • •m N/A SPP •si N/A N/A N/A N/A N/A Flow Rate s • m N/A Gallons /stroke 3.6 ' Mud D De nsity (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out sec/•t m1/30 min cP Ib /100ft m1/30 min m• /I 13866 12.5 12.5 55 - 21 24 4.6 9.00 16000 18.3 1 ';.. BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD It I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) ------ - - - - -- I Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to to = to to I to to to 4 to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas v''. - .. . - - - 1 c-, , . t - '. s 4n � '�i�' ° , 24 hr Recap: R/U B.H.A., trip in hole filling pipe every 10 stands to 11510, top drive failure, service top drive. Il i 1 Logging Engineer: Boyd Piercey /Mike Daigle 10000 units = 100% Gas In Air � • ■ 1 ■ 1 1 ■ 1 Customer: Pioneer Natural Res. Report #: 63 NALLIBURTON Well: ODSN -45i Date: 10/04/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 Sperry Drilling S ervices Rig: Nabors 19AC Rig Activity: Service Top Drive Job No.: AK -MW- 5710484 Report For: Rod /Nick I Daily Charges $3,720.12 Total Charges $228,177.08 I d en ROP &Gas: Current Avg 24 hr Max Max ac ft Pump & Flow Data: R = ROTATING ' ' R.O.P. (ft/hr) N/A N/A N/A N/A Flow in (gpm) N/A SPP (psi) N/A J Gas units N/A N/A N/A N/A Flow Rate s•m, N/A Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out sec/•t m1/30 min cP Ib /100ft m1/30 min mg /I % 13866 12.5 12.5 55 - 22 23 5 9.00 16000 18.3 I BHA Run # Bit Type Size l TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD F 1 ,' Lithology ( %): S d Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 1 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I to to to to to to to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 111 24 hr Recap: Circulating while working on top drive. 1 1 Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air 3, . Qp I 1 1 1 w 1 Customer: Pioneer Natural Res. Report #: 6 4 HALUBURTON Well: ODSN -45i Date: 10/05/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 S perry Drilling Services Rig: Nabors 19AC Rig Activity: Service Top Drive Job No.: AK -MW- 5710484 Report For: Rod /Nick 1 Daily Charges $3,720.12 Total Charges $231,897.20 o ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING I R.O.P. ft/hr N/A N/A N/A N/A Flow in • •m 347 SPP •si N/A IIMINEIMI 13 N/A 23 N/A Flow Rate s•m, 56 Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out seG•t m1/30 min cP Ib /100ft m1/30 min m• /I % 13866 12.5 12.5 55 - 24 29 4.7 9.50 16000 18.3 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 - 18 124 3 - 2 - CT CT X - I - ER - TD I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current ------ -� - � -- I Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to =�s to ?; to I to to t0 { t0 1 #' Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; 0 BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas k 24 hr Recap: .1 Circulating while working on top drive. � �� �� -� ; # �� ,1 � l �� I '3 I Logging Engineer: Boyd Piercey / Mike Daigle ` 10000 units = 100% Gas In Air I 1 1 1 Customer: Pioneer Natural Res. Report #: 65 HALLIBURTON Well: ODSN -45i Date: 10/06/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Ciculating Job No.: AK -MW- 5710484 Report For: Rod /Nick 1 ' „ Daily Charges $3,720.12 Total Charges $235,617.32 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr N/A N/A N/A N/A Flow in • •m 326 SPP •si 3183 AIMIRMEMEI 1206 498 6849 N/A Flow Rate s•m 84 Gallons /stroke 3.6 I ' Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De•th ft in out sec/•t m1/30 min cP Ib /100ft m1/30 min me/1 % 13866 12.5 12.5 54 20 26 5.5 9.00 16000 18.3 - - , .. -: ,. � � 1 BHA Run n AR # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD i Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) ------ - - - - -- 1 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 13419 to 13460 4745 380541 11485 3375 1184 339 TG to 6849 455740 26134 8659 2103 397 TG to to to to to ' to "' to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas w �+. §..�.i l '. .. .. 4 � . . � "_... * . L ':� . � J n4 'reamer �}tl^ �� . }� " 5+. �x " 1 24 hr Recap: C irculating while working on top drive, T.I.H. to 13866', open reamer back r eam to 13830', P.0.0.1 to 12660', circulate gas out, max gas 6849u mud cut 11.9ppg 1 4 1 Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air e rr -. ' 1 : " 111 1 1 1 I Customer: Pioneer Natural Res. Report #: 66 HALLIBURTON Well: ODSN -45i Date: 10/07/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 S perry D r i lling S erv i ces Rig: Nabors 19AC Rig Activity: Back Reaming ii 4 Job No.: AK -MW- 5710484 Report For: Rod /Nick Daily Charges $3,720.12 Total Charges $239,337.44 I ROP &Gas: R . O . P . ft/hr Current N/A Avg 24 hr N/ Max A NIA Max! ft Pump & • •m Flow Data: 295 SPP R = ROTATING . 3240 1206 1028 7727 N/A Flow Rate s•m 84 Gallons /stroke 3.6 Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out seG•t) m1/30 min cP Ib /100ft m1/30 min me/1 13866 12.5 12.5 52 21 26 5.4 9.50 16000 19.8 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3- 2- CT- CT- X- I -ER -TD I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal GvI Tuff (current) ------ - - -_ -- A _ I Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 12625 to 12660 7040 453504 31588 10988 2767 538 III 12580 to 12620 6879 450461 29512 9960 2472 477 12480 to 12520 6871 451179 29135 9573 2339 452 12130 to 12160 7727 464568 35910 12996 3592 778 to to 1 to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: Back reaming from 12649' to 11582' ,4] 1 Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air irl I 1 1 1 1 Customer: Pioneer Natural Res. Report #: 68 HALLIBURTON Well: ODSN -45i Date: 10/09/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 S perry Drilling Services Rig: Nabors 19AC Rig Activity: R.I.H. Liner Job No.: AK-MW-5710484 Report For: Rod /Nick • I aily Charges $3,720.12 Total Charges $246,817.68 I 1 ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr N/A N/A N/A N/A Flow in ..m N/A SPP •si N/A DEN N/A N /A N/A N/A Flow Rate s.m N/A Gallons /stroke 3.6 " , , I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/•t m1/30 min cP Ib /100ft m1/30 min m•/I % 13866 12.5 12.5 58 24 27 5.8 8.70 16000 17.2 I BHA Run # Bit TypeS TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A -- 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3- 2- CT- CT- X- I -ER -TD Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) ----- - -_ - -- . II Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas ? " fi 111 24 hr Recap: P.O.O.H. from 11222' to 1127', pump dry job, P.O.O.H. to 427', UD B.H.A., R/U Weatherford casing tools, ;::: 1 :,1, ' 1 1..',. Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air t g 1 1 1 1 Customer: Pioneer Natural Res. Report #: 68 HALLIBURTON Well: ODSN -45i Date: 10/09/2008 -5:00 1 Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: R.I.H. Liner Job No.: AK -MW- 5710484 Report For: Rod /Nick 1 1 Daily Charges $3,720.12 Total Charges $246,817.68 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R . O . P . ft/hr N/A N/A N/A N/A Flow in • •m N/A SPP •si N/A N/A N/A N/A N/A Flow Rate s•m N/A Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Desth ft in out (sec/.t m1/30 min cP Ib /100ft m1/30 min m• /I % 13866 12.5 12.5 58 24 27 5.8 8.70 16000 17.2 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD 1 rr t� Lit hology ( %): Sd Sst Silt Siltst Cht Cly Sh Lst Coal Gvl Tuff current ------ - - -_ -- Gas Breakdown Gas (units) Chromatograph (ppm) I 4, Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to to to to to 1 to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; ,S, BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas ,.r,..., s. F ., ys i /.4 a „ � y-. i . ... � '� � s Ye � ..A �i�%� �#a t� i ' .. tc .. _ 24 hr Recap: P.O.O.H. from 11222' to 1127 , pump dry job, P.O.O.H. to 427 , UD B.H.A., R/U Weatherford ca tools, T.I.H. with expandable liner 1 1 Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air 1 1 1 1 1 Customer: Pioneer Natural Res. Report #: 70 HALLIBURTON Well: ODSN -45i Date: 10/11/2008 -5:00 I Area: Oooguruk L oc 05:00 Depth 13866 Location: North Slope Progress 24 hrs: 0 S perry D r il ling S erv i ces Rig: Nabors 19AC Rig Activity: R.I.H. Liner Job No.: AK -MW- 5710484 Report For: Rod /Nick 1 Daily Charges $3,720.12 Total Charges $254,293.92 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr N/A N/A N/A N/A Flow in • •m N/A SPP .si N/A Erria N/A N/A N/A N/A Flow Rate son, N/A Gallons /stroke 3.6 $: I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out seG•t m1/30 min cP Ib /100ft m1/30 min m. /I 13866 12.5 12.5 58 24 28 5.6 9.00 16000 17.2 I BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD III 4i4,- A11.11111111 '. ‘Mir EIMINIMIMEMININIMMINEMIL6, Il Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current ------ - - - - -- : ; 1 Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to t II to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas 24 hr Recap: T.I.H. with expandable liner, Cement, expand liner, no returns, P.O.O.H. to 11987', T.I.H. to 13041' and worked liner to 13425', Circ and condtion, P.O.O.H. to 13259', T.I.H. to 13111', Fishing backed off 14 wrps 8k torque at 675' from surface, P.O.O.H. to 675', picking up B.H.A., R/U to test B.O.P.'s, Test B.O.P. 1 Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 70 HALLIBURTU�v Well: ODSN -45i Date: 10/11/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 S perry Drilling Services Rig: Nabors 19AC Rig Activity: Test B.O.P.'s Job No.: AK -MW- 5710484 Report For: Rod /Nick 1 Daily Charges $3,720.12 Total Charges $254,293.92 I , ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr N/A N/A N/A N/A Flow in • •m N/A SPP •si N/A I N/A N/A N/A N/A Flow Rate s•m, N/A Gallons /stroke 3.6 Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De•th ft in out sec/.t m1/30 min cP Ib /100ft m1/30 min m. /I % 13866 12.5 12.5 58 24 28 5.6 9.00 16000 17.2 I B Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3- 2- CT- CT- X- I -ER -TD Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current ------- _ - - - M 1 Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to I to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas , I '' .- i. £ -- .b ,{ - . 1,7 + 44%,.. k fie » e 24 hr Recap: T.I.H. with expandable liner, Cement, expand liner, no returns, P.O.O.H. to 11987', T.I.H. to 13041' and worked liner to 13425', Circ and condtion, P.O.O.H. to 13259', T.I.H. to 13111', Fishing backed off 14 wrps 8k torque at 675' from surface, P.O.O.H. to 675', picking up B.H.A., R/U to test B.O.P.'s, Test B.O.P. M. 1 Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air , 1 1 I 1 Customer: P ioneer Natural Res. R eport #: 7 HALLIBURTON Well: ODSN -45i Date: 10/13/2008 -5:00 Area: Oooguruk 05:00 Depth 13866 L North Slope Progress 24 hrs: 0 S perry Drilling Serv Rig: Nabors 19AC Rig Activity: Trip in hole Job No.: AK -MW- 5710484 Report For: Rod /Nick 1 Daily Charges $3,720.12 Total Charges $258,688.04 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr N/A N/A N/A N/A Flow in • •m N/A SPP •si N/A IIMEMEM N/A 230 365 N/A Flow Rate s•m, N/A Gallons /stroke 3.6 I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out (seG.t ml /30 min cP Ib /100ft m1/30 min m. /1 % 13866 12.5 12.5 51 19 21 5.6 8.50 16000 17.2 I ...-.: BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3- 2- CT- CT- X- I -ER -TD ''` al Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current) ----- - - -� -- 1 Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I ry' to to t to to I to _ to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas L n 4 Y . 24 hr Recap: T.I.H. to 13513', Service top drive, R/U wireline, Running wireline with severe charge. .i ./. 1 1 : ry Logging Engineer: Boyd Piercey /Mike Daigle y$ • 10000 units = 100% Gas In Air 1 1 1 1 Customer: Pioneer Natural Res. Report #: 72 HALLIBURTON Well: ODSN -45i Date: 10/13/2008 -5:00 1 Area: Oooguruk Location: 5:00 Depth 13866 ation: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Trip in hole Job No.: AK -MW- 5710484 Report For: Rod /Nick "" Daily Charges $3,720.12 Total Charges $262,408.16 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr N/A N/A N/A N/A Flow in •.m N/A SPP •si N/A 1 N/A 230 365 N/A Flow Rate s•m N/A Gallons /stroke 3.6 i -, Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids De•th ft in out sec/.t m1/30 min cP Ib /100ft m1/30 min m•/I % 13866 12.5 12.5 57 24 27 5.6 9.50 16000 17.2 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A -- 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) ------ -_ - - -_ I Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to I to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas I 24 hr Recap: P.O.O.H. Wire line, wireline parted, Backed off drill pipe, R/U cement tools, T.I.H. to cement. i o 1 Logging Engineer: Boyd Piercey / Mike Daigle 10000 units = 100% Gas In Air lig& N 1 1 1 1 I Customer: Pioneer Natural Res. Report #: 73 HAU.IBURTON Well: ODSN -45i Date: 10/14/2008 -5:00 I Area: Oooguruk 05:00 Depth Progress 13866 Location: North Slope ress 24 hrs: 0 Sperry Grilling Services Rig: Nabors 19AC Rig Activity: Slip and Cut Job No.: AK -MW- 5710484 Report For: Jim /Nick Daily Charges $3,720.12 Total Charges $266,128.28 ;4.F : " t I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr N/A N/A N/A N/A Flow in •.m N/A SPP •si N/A N/A 73 4780 N/A Flow Rate s•m N/A Gallons /stroke 3.6 eth I Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Depth ft in out sec/.t m1/30 min cP Ib /100ft m1/30 min m. /I % 13866 12.5 12.5 59 25 27 5.6 9.10 16000 17.2 ,. 1 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD r 1. , LlthOlOgy ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current) ------ _ - - - -- 1 Gas Breakdown Gas (units) Chromatograph (ppm) I Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to II to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas ` , r 24 hr Recap: to Cement, pressure tested to 4310psi, Displaced mud system to seawater, Monitor well, P.O.O.H., slip and cut drill line. 1 1 •n Logging Engineer: Boyd Piercey / Mike Daigle * 10000 units = 100% Gas In Air I 1 1 1 Customer: Pioneer Natural Res. Report #: 74 ri HALL.IBURTON Well: ODSN -45i Date: 10/15/2008 -5:00 I Area: Oooguruk 05:00 Depth 13866 Location: North Slope Progress 24 hrs: 0 Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Nipple Down Job No.: AK -MW- 5710484 Report For: Jim /Nick I Daily Charges $3,720.12 Total Charges $269,848.40 I ROP &Gas: Current Avg 24 hr Max Max @ ft Pump & Flow Data: R = ROTATING R.O.P. ft/hr N/A N/A N/A N/A Flow in • •m N/A SPP •si N/A N/A 73 4780 N/A Flow Rate s•m, N/A Gallons /stroke 3.6 I ' Mud Data: Density (ppg) Viscosity HTHP PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/•t m1/30 min cP Ib /100ft m1/30 min m• /I % 13866 8.5 8.5 28 0 0 0 9.00 16000 0.0 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 660 Tricone 6.75 0.331 11393 13866 N/A 600 FSF -3563Z 9.88 0.982 7.43 13583 13866 283 10 -18 124 3 - 2 - CT CT X - I - ER - TD Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff current) ------ - - - - -- Gas Breakdown Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to to to to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; 1 BUG Bottoms Up Gas: POG - Pumps Off Gas; TG - Trip Gas g $ 3n 24 hr Recap: P.O.O.H. UD Drill pipe, run kill string, nipple down y3 B.O.P. I Logging Engineer: Boyd Piercey / Mike Daigle " 10000 units = 100% Gas In Air I I 1 II Customer: Pioneer Natural Res. Report #: 10 HALLIBURTON Well: ODSN -45A Date: 10/16/2009 -04:00 Area: Oooguruk 04:00 Depth 11325' Location: North Slope Progress 24 hrs: N/A Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Mad Pass Job No.: AK -AM- 0005710484 Report For: J. Poyla /R. Klepzig I Daily Charges $6,565.83 Total Charges: $315,553.34 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I : R.O.P. ft/hr Flow In • •m 195 SPP •si 1197 Gas (units) 127 169 While Circ 2127 While Circ Flow In (spm) 56 Gallons /stroke 3.5175 Death On Bot Hrs Av. Diam Drillin• .�,' Min Av. -... Max Hole Condition 11325' 39.46 j PWD All Circ 9.83 Min 10.29 Avg 11.09 Max M Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Death ft in out sec/•t • •b E• cP Ib /100ft m1/30min m• /I % I 11325' 9.35 hut 42 5.0 10 16 5.0 9.00 44K 4.6 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 900 Security 6.75 0.389 27.46 10124' 11325' 1201' 0 -30 180 -220 TT 1- 1- NO- A- E -I -NO -BHA 1000 Reed Hycalo• 6.125 0.461 11325' - - -- r Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) MIN Mli Gas Breakdown I H2S Data l Sample Line 'Max: 1 IAvg: 0 ' Ambient Air Pit Room 'Max: 1 'Avg: 0 ( I Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 20:13 to 20:33 2127 1049 197143 9729 3604 1395 541 POG/TG I 20:34 to 20:55 1795 924 159137 9176 3434 1304 495 PoG/TG 21:45 to 22:15 348 170 32181 2360 963 452 213 POG/TG 22:30 to 23:10 819 465 79247 4528 1693 727 327 POGTTG 23:18 to 23:45 360 273 32701 2343 959 453 224 TG /RG I 3:23 to 3:55 415 226 38601 2170 944 498 259 TG /RG to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip... ; F -- - Formation... ; E -- - Early... 24 hr Recap: Continue to make up remainder of BHA and RIH shallow pulse test MWD and cont RIH tight @ 5,000 down due to junk Rotary on @ 10,214' @ 20 rpms conttinue to roatate down w max torque fo 19K. (Stick slip) Wash and rotate from 10,310' to 10,366' Cont to rotate down to 11,136' and begin washing and roatating to 11,195' and stage pumps to 146 gpm and increase rotatry to I 63 rpms. Working pipe@ 11,285' attempt to P/O @ 13.6K torque, 1737 spp, @ 141 gpm. Attempt to P/0 @ 11,313' @ 13.3K torque 1554 spp, @ 144 gpm. Cont to Rih to btm and begin MAD pass, attempt to P/O @ 11,280' w max spp @ 2345 @ 227 gpm and EMW @ 9.9 ppg. Shut down pumps and bring back up w max spp @ 2375 and EMW 10.92 ppg. Cont to mad pass to 11,193' and attempt to P/0 max spp @ 2128, @ 231 gpm EMW 9.9 gpm. Begin loosing fluid to formation. Shut down pumps and stage to 93 gpm w/ 1595 I spp recorded. Pumps off and POOH pumps on and cont to POOH loosing fluid to 11,122' w total recorded loss of 24 bbls . Gas detection was poor during interval while loosing fluid due to low flow. Continue to Mad pass @ max 150' to 10,632' and attempt to I P/O max spp @ 1603 @ 198 gpm, torque 10.3K , EMW dripped to 9.83 with an initial fluid loss of 6 bbls. Logs revealed a sand or sandstone and previous surface cuttings marked the zone as an unconsolidated SST. Continue to MAD pass to a current depth of 10,407' md. Total downhole losses calculated at 27 bbls. Background gas levels from unfractured unswabbed formation stayed below 150U. Logging Engineer: Daniel Sherwood /Tom Mansfield /Danny Kane * 10000 units = 100% Gas In Air 1 1 I Customer Pioneer Natural Res. Report #: 10 1AL.LIBURT ©N Well: ODSN -45A Date: 10/17/2009 -04:00 I Area: Oooguruk 04:00 Depth 11515' Location: North Slope Progress 24 hrs: 190' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Trip out Job No.: AK -AM- 0005710484 Report For: J. Poyla /R. Klepzig Daily Charges $5,685.51 Total Charges: $321,238.85 ROP & Gas: Current Avg 24 hr Max Max © ft Current Pump & Flow Data: I R.O.P. (ft/hr) 15.9 123.1 11338' Flow In (gpm) 0 SPP (psi) 30 Gas (units) 0 141 809 11326' Flow In (spm) 0 Gallons /stroke 3.5175 Hole Condition Depth Hrs Ann Corr Avg Diam PWD 9. 11515 On ' 51 . 12 bbls 7.34" All Circ Drilling 9 .94 M in M in 10 101 1 .1 0 Avg Avq 10 28 Max Max I Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib /100ft m1/30min mg /I % I 11515' 9.20 9.30 43 3.6 7 17 3.8 9.20 28k 4.8 4 , BHA Run # I Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 900 Security 6.75 0.389 27.46 10124' 11325' 1201' 0 -30 180 -220 1- 1- NO- A- E -I -NO -BHA s 1000 Reed Hycalog 6.125 0.461 11.98 11325' 11515' 190' 19 -30 67 -129 1 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 20 75 5 G as Breakdown i I H2S Data 1 Sample Line !Max: 1 Avg: 0 1 Ambient Air Pit Room Max: 0 Avg: 0 I I Depth Gas (units) Chromatograph (ppm) Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 10050' to 11300' 809 82667 3627 1135 429 182 TG 11350' to 11434' 212 138 16552 1119 472 228 125 FBG 11435' to 11435' 196 (BG) 145 16353 1103 478 227 114 RG 11436' to 11499' 178 124 15097 927 372 172 91 FBG to I to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG Ream Gas; T -- - Trip ; F -- - Formation... ; E -- - Early... . . _ I 24 hr Recap: Continue MAD Pass down to bottom. Bring rotary & flow up to full drilling -rates & start drilling new 6.75" hole at 06:33. Initial drilling (first 15 minutes) resulted in a highly erratic ROP before settling to a 10 -20fph average with WOB stacking to 20- 25klbs & drilling torque holding fairly steady from 7- 10kftlbs (dependent on amount of time WOB allowed to stack). Attempted various I combinations of drilling parameters with no success seeing ROPs struggle to break 25fph. A full -mud dilution with new 4% mud lubricants failed to reduce the stacking WOB & little reduction in drilling torque was observed. With no response in higher ROPs, pulled off bottom at 20:02 at 11515' MD (5171' TVD) & started trip out to surface. Currently tripping out & laying down worn drill pipe at 3847' MD. Drilled formation gas continued to remain below 200 units with the low ROPs observed & was ROP- dependent for the I drilled interval. Before reaching bottom, the previous open -hole section back to the window (10050' MD) produced trip gas that rose to 809 units over a steady background of 50 units observed before the open -hole section lag. No connection gasses were seen but there was one ream gas observed at 11435' MD of 196 units over a 146 unit formation background. No losses were seen during the drilling interval with 8bbls currently lost to the hole to the trip out (to 4000' MD). The samples collected are more I competent (better sample quality) with increasing depth with the most recently drilled lithology composed primarily of a siltstones interbedded with sandstones & occasional shale stringers, scattered dull yellow florescence, & a weak streaming milky white cut florescence; further, a greater than normal amount of non -mag metal shavings have been observed throughout the drilled interval. Logging Engineer: Tom Mansfield /Danny Kane * 10000 units = 100% Gas In Air 1 1 Customer: Pioneer Natural Res. Report #: 12 w 1ALLIBURT ©N Well: ODSN -45A Date: 10/18/2009 -04:00 I Area: Oooguruk 04:00 Depth 11703' Location: North Slope Progress 24 hrs: 188' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling 6.125" Hole Job No.: AK -AM- 0005710484 Report For: J. Poyla /R. Klepzig I Daily Charges $5,685.51 Total Charges: $326,924.36 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I » R.O.P. ft/hr 78.5 42.8 100.3 11628' Flow In • •m 74 SPP •si 2018 , Gas (units) 129 185 299 11570' Flow In (spm) 21 Gallons /stroke 3.5175 Hole Conditi De On Bot Hrs Ann Corr Avg Diam PWD ' Drilling 10.07 Min 10.24 Avg 10.47 Max 11703 55.83 33 bbls 7.68 All Circ 9.21 Min 10.22 Avg 10.52 Max r Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib /100ft m1/30min mg /I % I 11515' 9.30 9.30 41 4.3 8 12 4.4 10.70 48k 4.3 BHA Run # 1 Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 1000 Hycalog RSR413D -A1 6.125 0.461 11.98 11325' 11515' 190' 19 -30 67 -129 1100 SDBS FMFX641Z 6.125 0.389 4.39 11515' _ 11703' 188' 1 -21 64 -137 I I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 30 60 10 Gas Breakdown 1 H2S Data 1 Sample Line Max: 2 Avg: 0 1 Ambient Air Pit Room IMax: 0 IAvg: 0 I I Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 9000' to 1000' 74 70 6390 343 138 72 37 TBG 10500' to 11300' 1356 635 130857 6514 2216 803 301 TBG I 11518' to 11568' 288 235 28255 1702 650 263 108 FBG 11570' to 11608' 299 242 27781 1630 615 263 118 FBG 11620' to 11621' 173 (BG) 147 15712 954 380 179 90 RG I to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation... ; E -- - Early... I 24 hr Recap: Finish tripping to surface with a total loss of 6bbls to the wellbore. Once on surface, broke down BHA #15 & found the bit to be in good shape but found aluminum SS clamps wedged into the GeoPilot housing. Prepared & built BHA #16 with SDBS bit, uploaded MWD tools, & started trip to bottom. Tripped in while pulse - testing MWD tools every 25 stands seeing no losses to I the hole during the entire trip in. Once on bottom, established circulation & started reaming at 11320' MD to bottom. Trip gas rose with the open -hole lag to surface and peaked at 1356 units from — 11000' MD. Once the previously uncirculated open -hole lag was circulated out at surface, background levels stabilized around 120 units. Resumed drilling at 22:16 while feathering bit down to I establish the cutting pattern. Since then, ROP has been highly variable with stacking WOB limiting ROP where it climbs too high. I On- bottom torque has remained steady at 7- 8.5klbft & SPP has been following the cuttings load with no pack -off events observed. Drilled formation gas has varied with the flow rate & the ROP but has remained below 300 units with max sustained ROPs around 75fph observed in the drilled interval. No connection gasses have been observed, but there was one ream gas observed from the 11620' MD backreaming to alleviate stacking WOB. No losses have been observed to the hole, and the annular adjustment has I been increased to 33bbls for an overall hole size average of 7.68" and an average for the 6.125" drilled section of 7.1". Drilled lithology currently consists of primarily siltstones with interbedded sandstones and occasionally shale with calcareous cement and a dull to yellow florescence and streaming milky white cut florescence. Logging Engineer: Tom Mansfield /Danny Kane * 10000 units = 100% Gas In Air • if,¢ 1 1 1 Customer: Pioneer Natural Res. Report #: 13 HALLIBURTON Well: ODSN -45A Date: 10/19/2009 -04:00 I Area: Oooguruk 04:00 Depth Progress 12845' Location: North Slope ress 24 hrs: 1142' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling 6.125" Hole Job No.: AK -AM- 0005710484 Report For: J. Poyla /R. Klepzig 1 Daily Charges $5,685.51 Total Charges: $332,609.87 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. ft/hr 92.0 60.7 143.4 12160' Flow In • •m 76 SPP •si 2371 Gas (units) 314 305 501 12754' Flow In (spm) 22 Gallons /stroke 3.5175 Hole Condition Death On Bot Hrs Ann Corr Av. Diam PWD ' Drillin• 10.12 Min 10.55 Ave 10.78 Max 11780' 74.65 51 bbls 7.53" All Circ 10.12 Min 10.54 Avg 10.78 Max Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Death ft in out (sect • •b Es cP (Ib /100ft m1/30min me/1 % I 12495' 9.30 9.40 39 6.0 8 13 4.6 10.00 36k 5.2 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 1000 H calo• RSR413D -A1 6.125 0.461 11.98 11325' 11515' 190' 19 -30 67 -129 I 1100 SDBS FMFX641Z 6.125 0.389 23.21 11515 12845' 1330' 1 -21 42 -141 I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 60 35 5 I Gas Breakdown I H2S Data 1 Sample Line 'Max: 1 'Avg: 0 1 Ambient Air Pit Room (Max: 0 'Avg: 0 I l I Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 11775' to 11808' 331 298 29632 1888 782 354 167 FBG 12052' to 12052' 286 (BG) 220 25864 1611 651 292 144 CRG 1 12153' to 12200' 254 214 22108 1420 597 285 151 FBG 12245' to 12245' 328 (BG) 234 28942 1801 718 385 169 CRG 12352' to 12370' 267 211 23608 1354 526 245 126 FBG I 12472' to 12535' 373 289 32552 1987 798 365 183 FBG 12635' to 12657' 433 333 41004 2527 1020 429 196 FBG 12745' to 12754' 501 423 46134 2907 1202 526 245 FBG to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... ". 24 hr Recap: Continue drilling 6 1/8" hole from 11703' to 12845' MD with an average effective ROP of 60.7fph. Drilling continued on the tangent section at the Torok bottom through interbedded sandstones, siltstones, & occasionally shales with sustained ROPs ranging from 40- 100fph with occasional ROPs greater than 120fph. Optimal drilling parameters have been holding 5- 10klbs WOB I while pumping 260 +gpm; these parameters have kept the drilling torque between 7- 9klbsft for the entire interval with good ROPs. From 12200' to 12243' MD, the bit balled up & ROPs dropped to 20- 30fph, drilling torque rose slightly, & the SPP & PWD EMW started to climb. The bit was unballed after pumping a nut plug sweep with the previous ROPs & drilling parameters returning. Currently drilling 90fph w/ 8klbs WOB, 8klbsft torq, & flow 269gpm. Drilled formation gas has varied with the flow rate & lagged I ROPs and has averaged 300 -400 units for most of the interval. Two connection ream gasses were seen from higher swabbing of the wellbore resulting from faster stand -end backreams; both were less than 50% of background. No losses observed to the hole and the PWD EMW has been slowly rising (partially to higher ROP cuttings load) from 10.45 to 10.70ppg in the past 24hrs. The annular adjustment has increased over the past 24 hours but has also shown some dynamic fluctuations that roughly correlate w/ I the PWD EMW to suggest that there may be some slow & minor hole loading (adjustment decr w /time) followed by slow unloading (adjustment incr again). The current average hole size for the entire hole section is 7.53" and 7.17" for the 6.125" hole section. Drilled lithology coarsened with good oil shows before ramping up & thereafter has graded finer with decreased oil shows. • ri Logging Engineer: Tom Mansfield /Danny Kane * 10000 units = 100% Gas In Air 1 1 w` Customer: Pioneer Natural Res. Report #: 14 HALLJBURTON Well: ODSN -45A Date: 10/20/2009 -04:00 Area: Oooguruk 04:00 Depth 13915' Location: North Slope Progress 24 hrs: 1070' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling 6.125" Hole Job No.: AK -AM- 0005710484 Report For: J. Poyla /R. Klepzig I Daily Charges $5,685.51 Total Charges: $338,295.38 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I r R.O.P. (ft/hr) 34.4 58.8 171.9 13596' Flow In (gpm) 76 SPP (psi) 2420 Gas (units) 274 467 1666 13780' Flow In (spm) 22 Gallons /stroke 3.5175 Hole Condition Depth On Bot Hrs Ann Corr Avg Diam PWD Drilling 10.55 Min 10.77 Avg 10.90 Max I 13871' 92.84 81 bbls 7.70" All Circ 10.44 Min 10.76 Avg 10.96 Max Mud Data: _ Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib /100ft m1/30min mg /I % I 13740 9.30 9.40 39 6.0 10 14 4.4 9.20 42k 4.8 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 1000 Hycalog RSR413D -A1 6.125 0.461 11.98 11325' 11515' 190' 19 -30 67 -129 I 1100 SDBS FMFX641Z 6.125 0.389 41.4 11515' 13915 2400' 1 -21 42 -142 Lithology ( %): Sd Sst 1 Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 50 40 10 , -,,,,,„ 1 -, Gas Breakdown H2S Data 1 Sample Line Max: 1 Avg: 0 1 Ambient Air Pit Room Max: 0 IAvg: 0 1 I Depth Gas (units) Chromatograph (ppm) Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 12867' to 12883' 1244 (FBG) 234 108458 7033 2880 1121 468 FGP U 13045' to 13075' 1002 (FBG) 517 86964 4698 2253 921 398 FGP 13150' to 13165' 1289 (FBG) 335 108816 7160 3176 1328 576 FGP 13186' to 13206' 1153 (FBG) 333 108077 5475 2143 929 423 FGP 13226' to 13238' 1063 (FBG) 562 94022 5653 2420 1062 482 FGP 13585' to 13615' 1538 (FBG) 339 126864 8046 3473 1591 726 FGP 13695' to 13704' 459 (FBG) 350 41478 2469 1073 529 300 FGP 13763' to 13813' 1666 (FBG)185 147270 8747 3658 1478 297 FGP to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip... ; F -- - Formation... ; E -- - Early... 2. ,'<, ,; x,.55r5,, I ry; 24 hr Recap: Continue drilling 6 1/8" hole from 12845' to 13915' MD (5021' TVD) with an average effective ROP of 58.8fph. Continued drilling -95deg ramp up- formation to Target T3 encountering interbedded fine - grained sandstones, siltsones, & shales. The finer siltstones & shales are not fully represented in the samples but their content has been high at times as seen by mud weight I increase & constant dilution needed to mitigate the fine solids (MBT <6.0ppb). While drilling high gamma formations, ROP was highly erratic and is generally 20- 50fph, WOB has been stacking, & the bit/BHA have balled up occasionally. ROPs in the cleaner formation are 80- 140fph. Overall, drilling torque has risen by less than 0.5kfps within the last 1500' MD & the PWD EMWs have fallen from their earlier peaks to 10.65- 10.80ppg currently with better management of the fine solids & frequent dilutions. Drilled I formation gas in the high gamma formation never exceeds 400 units & there have been seven good shows in excess of 1000 units observed in the last 1000' MD. The show from 13580'- 13620' MD was a fine- grained sandstone w/ 77api gamma & 18ohmm resistivity. The largest show from 13764'- 13812' MD resulted in a 1666 unit gas peak (185unit background) from a fine - grained sandstone with 65 -70api gamma & 24- 28ohmm resistivity. These shows both showed good visible & cut fluorescence as well as I visible oil cuts. Connection gas has been seen on half of the connections (with most resulting from the full -stand reaming) and no losses /gains observed. The open -hole adjustment has been rising gradually with time and is currently at 81 bbls through 13871' MD for an average hole diameter of 7.70" and an approximate average of 7.45" for the 6.125" hole section. Logging Engineer: Tom Mansfield /Danny Kane " 10000 units = 100% Gas In Air I 1 Customer: Pioneer Natural Res. Report #: 15 1ALLIBURTON Well: ODSN -45A Date: 10/21 /2009 -04:00 Area: Oo0guruk 04:00 Depth 15082' 1 Location: North Slope Progress 24 hrs: 1167' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling 6.125" Hole Job No.: AK -AM- 0005710484 Report For: J. Poyla /R. Klepzig I Daily Charges $5,685.51 Total Charges: $343,980.89 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. (ft/hr) 5.0 59.6 139.9 14166' Flow In (gpm) 76 SPP (psi) 2373 Gas (units) 524 349 960 14509' Flow In (spm) 22 Gallons /stroke 3.5175 Hole Condition Depth On Bot Hrs Ann Corr Avg Diam PWD Drilling 10.61 Min 10.98 Avg 11.30 Max 15002' 112.42 107 bbls 7.73" All Circ 10.52 Min 10.98 Avg 11.42 Max I Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft m1/30min mg /I 1 14776' 9.30 9.35 45 2.5 9 22 1.0 10.80 35k 5.3 BHA Run # I Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 1000 Hycalog RSR413D -A1 6.125 0.461 11.98 11325' 11515' 190' 19 -30 67 -129 I 1100 SDBS FMFX641Z 6.125 0.389 60.98 11515' _ 15082' 3567' 1 -21 42 -142 I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) 30 45 20 5 Gas Breakdown I H2S Data 1 Sample Line 'Max: 6 Avg: 0 1 Ambient Air Pit Room Max: 2 'Avg: 0 I I Depth Gas (units) Chromatograph (ppm) Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 14064' to 14077' 677 541 65809 3731 1499 661 309 FBG r 14112' to 14124' 1122 (BG) 295 96313 6153 2753 1264 557 FGP I 14231' to 14247' 632 (BG) 385 54054 3480 1616 799 378 FGP 14431' to 14445' 700 555 65585 3737 1505 578 307 FBG 14489' to 14516' 960 (BG) 500 86212 5073 2379 1169 448 FGP 14584' to 14606' 735 503 68422 4059 1915 886 308 FBG I 14779' to 14858' 394 296 33567 2225 1156 665 312 FBG 14879' to 14895' 580 469 52604 3181 1482 780 350 FBG to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... 1 ,4 24 hr Recap: Continue drilling 6 1/8" hole from 13915' to 15082' MD (5001' TVD) with an average effective ROP of 59.6fph. After reaching T3 target, turned wellbore over horizontally & drilled ahead on roughly 90 -91deg tangent on route to extended TD of — 15400' MD. Initially drilled through high 135api gamma formation resulting in poor drilling parameters, occasional bit balling, and I a couple 150- 200psi pack -offs (below PWD tool). Since 14000' MD, gamma has slowly fallen to 100api currently with resistivity averaging 5- 7ohmm. At 14500' MD, the existing WBM at 9.45ppg was displaced with new 9.30ppg WBM. Immediately after getting the new mud around, drilling torque which had slowly built to 8kfps jumped to 10kfps & has increased to —11 kfps since. In addition, little EMW relief has been seen with the new mud as PWD ECDs have built up to a 11.2- 11.3ppg EMW. Drilling parameters have I improved in the past 400' MD with more consistent ROPs, no pressure events, & what torsional vibration that had developed with the new mud dilution has since dissipated to previous (low) background levels. Drilled formation gas has averaged 300 -600 units for the bulk of the drilled interval with three small shows less than 1000 units observed. Connection gasses have occurred on 65% of connections and there have been no losses or gains to the hole in the past 24 hours. Currently our open -hole correction is I 132bbIs and has increased at a pretty consistent rate of 2bbls /hr over the last 24 hours; this equates to an average 7.73" diameter for the open -hole section & an estimated 7.47" average diameter for the 6.125" hole section. Sampling at surface is primarily siltstones to very-fine grained sandstones and all expected shales are assumed to be passing through the solids control equip. Logging Engineer: Tom Mansfield /Danny Kane * 10000 units = 100% Gas In Air 1 1 1 * R' Customer: Pioneer Natural Res. Report #: 16 dALLIBURTON Well: ODSN -45A Date: 10/22/2009 -04:00 Area: Oooguruk 04:00 Depth 15429' I Location: North Slope Progress 24 hrs: 347' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: MAD Pass Job No.: AK -AM- 0005710484 Report For: J. Poyla /R. Klepzig I Daily Charges $5,685.51 Total Charges: $349,660.40 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: 1 R.O.P. ft/hr IIIMIIM 55.1 139.9 14166' Flow In • •m 201 SPP •si 1688 860 392 5639 — 11000' Flow In (spm) 57 Gallons /stroke 3.5175 i S De On Bot Hrs Ann Corr Av. Diam Drillin• 11.10 Min 11 Ave 11.28 Max Hole Condition 15429' 118.42 145 bbls 8.01" PWD 12.06 Max All Circ 10.16 Min 11.21 Avg , 1 Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out sec/.t • .b E. cP Ib /100ft m1/30min m. /I % 1 15429' 9.30 9.30 43 y 5.0 9 a k 20 5.4 10.20 34k 5.4 ` BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition I 1000 H calo. RSR413D -A1 6.125 0.461 11 98 11325' 11515 190 19 -30 67 -129 1100 SDBS FMFX641Z 6 125 0.389 66. , ` 11515' 15429 391140 ® 42 -146 -, Lithology (%): Sd Sst Silt Siltst Cht " Clyst Sh Lst Coal Gvl Tuff I (current) 25 70 —_ 5 - - - -- Gas Breakdown HI 2 S Data I Sample Line 'Max: 1 Avg: 0 1 Ambient Air Pit Room 'Max: 0 IAvg: 0 I Depth Gas (units) Chromatograph (ppm) Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to I to to to to to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... I 24 hr Recap: Continue drilling 6 1/8" hole from 15082' to TD of 15429' MD (5018' TVD) with average on- bottom ROPs of 65 -75fph with 10.5 -11 kfps torque & little to no torsional vibration logged. Drilled formation gas averaged 400 units with a few ROP- induced gas peaks. No connection gasses were observed & no losses to the hole while drilling. Over the last 24 hours of drilling, signs of I wellbore breathing were observed when the drilling ECDs surpassed 11.0ppg. Excessive flow & slow pit gains were observed during connections. Upon TD of the well, circulated the hole —2.7x B/U with ECDs staying above 11ppg & started tripping with a few tight spots encountered requiring reaming and /or washing to pull through. Flow back was observed from the well as the result of the higher ECDs charging the formation. Continued tripping on elevators when possible until a tight spot was encountered at 1 11850' MD. Upon turning on the pumps, the hole packed off & immediately saw 80% losses. Worked the pipe & started pumping at 40 -60gpm unesh stand before p' MAD Pass. Estab lished 90% ret circula were tion with obtai initially d. Wa 45% losses ed one & ECDs more at 12ppg whi ping pumping on at 260gpm. elevators to 11564 Continued MD to pumping startthe & AFR running 150fph, seeing the average loss rate reduced to —30% as of 03:30. With bottom's up from the 11850' MD approximately I 10- 15bbls cuttings (40bbls mud & cuttings) were unloaded with a sustained 5000 -5500 unit gas peak. Trip gas has since dropped to 500 -700 units with cuttings still coming to surface and with an ECD of 10.9ppg. Annulus correction was 112bbIs upon TD, but has since increased to 145bbIs with the cuttings unloading at surface. Avg diam = 8.01" & 6 1/8" section avg. diam = 7.85 ". Logging Engineer: Tom Mansfield /Danny Kane * 10000 units = 100% Gas In Air Al 1 1 1 w wt Customer: Pioneer Natural Res. Report #: 1 HALLIBURTON Well: ODSN -45A Date: 10/23/2009 -04:00 I Area: Oooguruk 04:00 Depth 15429' Location: North Sloe p Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: BOPE Test Job No.: AK -AM- 0005710484 Report For: J. Poyla /R. Klepzig Daily Charges $5,685.51 Total Charges: $355,345.91 ROP & Gas: Current Avg 24 hr Max Max cd ft Current Pump & Flow Data: 1 R.O.P. ft/hr gall111111111111111111111111 IIIIIIIIIIIIIII Flow In • •m 0 SPP •si 23 860 392 5639 — 10950' Flow In (spm) 0 Gallons /stroke 3.5175 Hole Condition De.th On Bot Hrs Ann Corr Av. Diam PWD ' Drillin• _ Min MI Ave ® Max 15429 118.42 158 bbls 8.23" All Circ 9.95 Min 10.41 Avg 11.56 Max Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids r' Depth ft in out sec/.t • .b E. cP Ib /100ft m1/30min m• /1 % I 15429' 9.30 9.30 39 5.5 9 15 5.0 9.70 40k 4.9 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 1000 H calo• RSR413D -A1 6.125 0.461 11.98 11325' 11515' 190' 19 -30 67 -129 0- 0- CT- S- X- I -NO -PR I 1100 SDBS FMFX641Z 6.125 0.389 66.37 11515' 15429' 3914 1 -21 42 -146 0-0-ER-N-X-I-NO-TD Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (curre 25 70 -- 5 - -_ -- Gas Breakdown I H2S Data 1 Sample Line Max: 1 Avg: 0 i Ambient Air Pit Room 'Max: 0 'Avg: 0 l I Depth Gas (units) Chromatograph (ppm) Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 1 1 000' to 10800' 1372 (BG) 486 121413 7235 3014 1334 578 WTG to I to to to I to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... c k41/%7,1%1:i,...;' .. < .% t k ; : . I 24 hr Recap: Continued performing MAD Pass from 11262' MD to 10216' MD while washing at 200gpm & rotating at 80- 115rpm (changed rotary to mitigate downhole vibration). Wellbore breathing experienced in the past 24 hours continued to occur for the rest of the MAD Pass, although diminishing with lower ECDs. Average losses at 11262' MD were initially 15 -20% & slowly fell to I 5% for the rest of the MAD Pass (5- 10bbls hr max observed thereafter) as the ECDs dropped from 11.05 to 10.25ppg. Pumps off average EMWs dropped to 9.43ppg by 10200' MD & flow back with pumps off ceased by 10900' MD during the MAD Pass. Ceased pumping & rotating to pull through the window & circulated lx bottom's up. Trip gas from the MAD Pass fell from 1000 to 100 units ii.. & background gas levels bottomed out at 50 units by the end of the trip. After completing the lx bottom's up circulation, pumped I dry job for trip out & observed a Pumps Off average EMW of 9.48ppg. Based upon inspection of the solids control equipment, the annulus correction has been conservatively ramped up to 158bbIs for the entire open -hole section after seeing the hole unload significant cuttings initially from the 11850' MD bottom's up followed up by a slow steady cuttings stream until pulling within the window. Since reaching TD, the open -hole correction has increased by 46bbls; the correction increased by 20bbls after the first I 3x B/U circulation, increased another 18bbls after receiving the 11850' MD bottom's up & hole unloading , & has since increased another 8bbls with the steady stream of cuttings seen at surface to the window. The average hole diameter is 8.23" with the estimated 6.125" section diameter at 8.01". Losses over the last 24 hours: 96bbls. Losses over entire event: 248bb1s. I Logging Engineer: Tom Mansfield /Danny Kane * 10000 units = 100% Gas In Air "' 1 1 C Pi Natural Res. Report #: 18 4ALUBURTON Well: ODSN -45A Date: 10/24/2009 -04:00 I Area: Oooguruk 04:00 Depth 15429' Location: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Clean Out Run Trip In Job No.: AK -AM- 0005710484 Report For: J. Poyla /J. Cortez I Daily Charges $4,970.25 Total Charges: $359,964.53 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I _ R.O.P. (ft/hr) Flow In (gpm) 209 SPP (psi) 1704 Gas (units) 335 252 5520 — 11575' Flow In (spm) 59 Gallons /stroke 3.5175 Hole Condition Depth On Bot Hrs Ann Corr Avg Diam PWD Drilling Min Avg Max 15429' 118.42 165 bbls 8.78" All Circ 2.87 Min 9.72 Avg 11.88 Max ii Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft m1/30min mg /I % 15429' 9.30 9.30 42 4.0 11 17 4.2 10.30 43k 4.5 BHA Run # I Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 1100 9 -SDBS FMFX641Z 6.125 0.389 66.37 11515' 15429' 3914' 1 -21 42 -148 0- 0- ER- N- X- I -NO -TD I 1200 9rrl SDBS FMFX641Z 6.125 0 389 15429' 15429' 0' I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 25 70 5 Gas Breakdown I H2S Data 1 Sample Line !Max: 1 lAvg: 0 1 Ambient Air Pit Room Max: 0 Avg: 0 I Depth Gas (units) Chromatograph (ppm) Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 11500' to 11575' 5520 (BG) 15 409289 19002 6106 2003 640 TG I to to to to I t to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... I 24 hr Recap: Completed BOPE Test & picked up Clean -Out BHA #16. Tripped in on elevators circulating every 25 stands seeing a total loss during the trip of 14bbls over calculated displacement. After circulating above the window, worked BHA through window seeing tight conditions which resulted in the jars firing twice. Once through the window, tripped in on elevators and worked pipe I through tight spots at 10185' to 10219' MD, 11120' to 11150' MD, & 11554' to 11575' MD. Started washing & reaming at 11575' MD with tight hole conditions & began experiencing similar hole conditions during the wiper trip out. Frequent pack -offs were observed with loss rates up to 75% accompanied w/ high torque, high downhole vibration, & ECDs in excess of 11.0ppg & the wellbore was observed charging (increase in pumps off EMWs after high pumps on ECDs) & discharging (gains with pumps off increasing with 1 greater pumps off EMWs - -as great as calc 40bbls /hr during 04:05 connection at 12184' MD) with very clear wellbore breathing. Trip gas peaked at 5520 units observed from the 11575' MD bottom's up (gas rose steadily as deeper open -hole lag came to surf) with the gas peak showing the open -hole correction to 11575' MD to be 90bbls. This shows severe washouts in the 6.75" hole section with a rough calculated washout diameter of 9.5- 9.75 ". There is insufficient data to calculate the washout for the 6.125" I hole section but it appears the overall open -hole washout correction will grow considerably when the bottom is reached. Spot samples from the shakers show predominantly siltstone grading to a very fine sandstone. Sagged calcium carbonate intially made up 25% of the cuttings load & is currently at 10 -15 %. Losses since circulation started 56bbls & total losses past 24 hours 71 bbls. 1. . Logging Engineer: Tom Mansfield /Danny Kane * 10000 units = 100% Gas In Air 1 Customer: Pioneer Natural Res. Report #: 19 rIALLUBURTON Well: ODSN -45A Date: 10/25/2009 -04:00 Area: Oooguruk 04:00 Depth 15429' Location: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Clean Out Run Trip Out Job No.: AK -AM- 0005710484 Report For: J. Poyla /J. Cortez Daily Charges $4,970.25 Total Charges: $364,934.78 r: „sue, ri . ` v `;v ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: 1 R.O.P. (ft/hr) Flow In (gpm) 0 SPP (psi) 29 Gas (units) 0 273 1692 —14800' Flow In (spm) 0 Gallons /stroke 3.5175 Hole Condition Depth On Bot Hrs Ann Corr Avg Diam PWD Drilling Min Avg Max 15429' 118.42 195 bbls 9.10" All Circ 10.39 Min 11.05 Avg 12.77 Max M Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib /100ft m1/30min mg /I % I 15429' 9.55 9.85 40 5.0 9 16 5.2 9.50 34k 7.0 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition I 1100 9 -SDBS FMFX641Z 6.125 0.389 66.37 11515' 15429' 3914' 1 -21 42 -148 0- 0- ER- N- X- I -NO -TD 1200 9rr1 - SDBS FMFX641Z 6.125 0.389 15429' 15429' 0' I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) 25 70 5 Gas Breakdown I H2S Data 1 Sample Line 'Max: 2 Avg: 0 1 Ambient Air Pit Room Max: 2 Avg: 0 1 I Gas (units) Chromatograph (ppm) Depth Maximum Average 01 C2 C3 C4 Tot C5 Tot Type 12750' to 12850' 1630 134982 8326 3490 1407 523 TG 13250' to 13350' 1461 117043 8372 3726 1472 528 TG I 13550' to 13650' 1280 115778 6805 2783 1137 461 TG 14050' to 14150' 1039 123259 7748 3508 1559 644 TG 14250' to 14350' 996 88875 5484 2386 1106 457 TG 14400' to 14450' 1403 124486 7217 3026 1308 542 TG I 14775' to 14825' 1692 147450 8346 3371 1423 562 TG l l to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... 24 hr Recap Completed wiper trip from 12164' MD to bottom seeing a significant improvement in the tripping parameters (lower torque /drag & fewer pack -offs) after leaving the Torok base horizontal tangent & started moving up the ramp. Tripped on elevators from 12377' to 13281' MD having to wash /ream from 12750'- 12845' MD because of tight hole conditions. Washed /reamed to TD I thereon seeing significant downhole vibration, packing off, & increased torque /drag from cuttings beds. Once to TD, circulated 8310strokes (2.2x open -hole volume) with little to no torque, dropping ECDs from 11.50 to 11.08ppg, & cleaner SPP. Trip gas was dependent on the running rate & ranged from 500 -1650 units over a background of 150 units & losses were partially dependent on the ECDs & number of pack -offs across the interval. With the hole circulated, started check trip to the window & currently at 12376' I MD. Washing & reaming stands out at 217gpm /128rpm observing overall good hole conditions to current depth with the exception of one pack -off requiring extra circulation at 14204' MD. Trip gas has been recently climbing from 200 to 500 units & losses have averaged 5 -15% w/ 5- 10bbls /hr flow seen with pumps off from a combination of the annulus /drillstring mud weight differential & the formation discharging charged fluid (wellbore breathing) from elevated circulating ECDs. The open -hole washout has increased to I 195bbls (using bottom's up gas data & observed in /out strokes of sweep pumped once on bottom -- returned at 9150stks, gauge hole 6819stks). Using a 9.75" average hole size through 11325' MD, the average diameter for the 6.125" hole section is 8.43" with the washout primarily composed of fine solids as evidenced by the climbing mud weight despite high dilution rates (40bbls /hr). Logging Engineer: Tom Mansfield /Danny Kane * 10000 units = 100% Gas In Air 1 1 1 �� Cus tomer: Pioneer Natural Res. Report #: 76 HALLIBURTON Well: ODSN -45A Date: 10/08/2009 -04:00 Area: Oooguruk 04:00 Depth 10105' 1 Location: North Slope Progress 24 hrs: N/A Sperry Drilling Services Rig: Nabors 19AC Rig Activity: RIH w/ ScraperAssy Job No.: AK -AM- 0005710484 Report For: J. Brown /R. Klepzig I Daily Charges $3,539.73 Total Charges: $270,678.34 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. (ft/hr) Flow In (gpm) 0 SPP (psi) 30 Gas (units) 2 2 4 Flow In (spm) 0 Gallons /stroke 3.5175 Depth On Bot Hrs Open - Hole Adj Avg Diam Drilling Min Avg Max Hole Condition PWD All Circ Min Avg Max 1 Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib /100ft ml /30min mg /I 1 10105' 8.95 28 10.40 66K 4.8 BHA Run # I Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 760 Smith XR -312 6.75 0.518 0' Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) I Gas Breakdown I H2S Data 1 Sample Line Max: jAvg: ( Ambient Air Pit Room Max: 'Avg: l I Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to I to to to to I to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... I 24 hr Recap: RIH and set packer, press up on annulus and shut in pressure up on drill pipe to activate guns. Extend stinger assy and R/U cmnt lines. Pressure test cmnt lines and and sting into packer. Conduct injectivity test with brine and monitor, no return recorded. Unsting I from packer and displace hole with 8.9 ppg brine. Pump 33 bbls of cement returns observed shut U rams and cont to pump. Unsting from packer and circulate drill pipe volume. POOH to 9853' and well becomes unbalanced due to failed packer and ballooning formation. Pump 50 bbls of 9.6 kill mud and observe static well. Continue to POOH to 5319' and repair crownsaver. Continue to POOH to surface, L/D stinger assy and P/U scraper assy and begin RIH. Sperry recorded a 18.7 bbl loss POOH. 1 1 Logging Engineer: Colby Marks /Daniel Sherwood * 10000 units = 100% Gas In Air I n 1 1 1 Customer: Pioneer Natural Res. Report #: 20 HALLIBURTON Well: ODSN -45A Date: 10/26/2009 -04:00 Area: Oooguruk 04:00 Depth 15429' R Location: North Slope Progress 24 hrs: 0' •� Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Trip out Job No.: AK -AM- 0005710484 Report For: J. Poyla /J. Cortez 1 Daily Charges $4,970.25 Total Charges: $369,905.03 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. ft/hr -- Flow In • •m 0 SPP *Si 29 0 216 1703 15390' Flow In (s.m 0 Gallons /stroke 3.5175 Hole Condition Depth On Bot Hrs Ann Corr Av. Diam PWD Drilling _ Min Av• _ Max 15429' 118.42 205 bbls 9.21" All Circ 10.15 Min 10.87 Avg 11.46 Max .,x °v M Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out sec/•t • •b E. cP Ib /100ft m1/30min m. /I % I 15429' 9.40 9.40 40 5.0 10 16 5.5 10.70 38k 5.5 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition ' 1100 9 -SDBS FMFX641Z 6.125 0.389 66.37 11515' 15429' 3914' 1 -21 42 -148 0- 0- ER- N- X- I -NO -TD 1200 9rr1 - SDBS FMFX641Z 6.125 0.389 — 15429' 15429' 0' -- Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) 25 70 -- 5 - - - -_ Gas Breakdown I H2S Data 1 Sample Line Max: 2 ]Avg: 0 1 Ambient Air Pit Room !Max: 1 IAvg: 0 I I Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 14200' to 14200' 926 91291 5811 2633 1277 578 TG 15390' to 15390' 1703 142250 8372 3395 1471 598 TG Bckgrnd to Aft B/U 97 6041 629 449 318 172 TG to to 1 to to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip... ; F -- - Formation...; E -- - Early... r i 1 24 hr Recap: Continue check trip from 12376' MD to 10200' MD seeing good hole conditions throughout the sump & back up the ramp towards the casing window while washing (200gpm) & reaming (118rpm). During the trip towards the shoe, wellbore breathing was observed throughout although the magnitude of the breathing diminished with decreasing circulating ECDs & lower I pumps off EMWs - -by 10200' MD, the pumps off EMW matched the mud weight out & previously seen gains with the pumps off ceased & were replaced with a slight loss (1- 2bbl /hr seep). Started tripping in on elevators from 10200' MD & continued on the elevators until a tight spot at 13928' MD required slow pipe rotation at 20rpm to get through. Attempted to continue on elevators but decided to rotate at 20rpm to TD while pumping 20 -40gpm to keep the bit jets from plugging. Worked to bottom with rotation I without any problems. Once on bottom, circulated hole clean with max trip gas of 1703 units from 15390' MD while taking 5 -30% losses w/ occasional pack -offs. With the hole clean, spotted the HT Breaker (250bbIs, 13bbls lost while pumping) across the open hole section & started tripping out on elevators with no substantial open -hole problem intervals - -a slightly higher hookload was observed from 12150' to 11600' MD. Passed through the window with ease, circulated 2x B/U (minor losses), & currently tripping I at 5798" MD showing a 1- 2bbl /hr sustained loss to the hole. Gas data analysis from the on- bottom circulation before spotting the breaker shows the open -hole washout has increased a further 10bbls to 205bbIs. The average open -hole size is 9.21" & gas data suggests a —10" hole section through 11325' MD & a tapered hole in the 6.125" section with an average diameter of 8.48 ". ,M 1 Logging Engineer: Tom Mansfield /Danny Kane * 10000 units = 100% Gas In Air I 1 1 1 Customer: Pioneer Natural Res. Report #: 2 1 HALLIBURTON Well: ODSN -45A Date: 10/26/2009 -04:00 Area: Oooguruk 04:00 Depth 15429' I Location: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Run Liner to Bottom Job No.: AK -AM- 0005710484 Report For: J. Poyla /J. Cortez I Daily Charges $4,420.05 Total Charges: $123,174.11 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. (ft/hr) Flow In (gpm) 0 SPP (psi) 29 Gas (units) 0 3 14 Flow In (spm) 0 Gallons /stroke 3.5175 Depth On Bot Hrs Ann Corr Avg Diam Drilling Min Avg Max Hole Condition 15429' 118.42 I 205 bbls 9.21" PWD All Circ Min _Avg Max II ,. V} Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib /100ft m1/30min mg /I % I 15429' 9.30 9.30 41 5.0 11 14 4.2 10.10 36k 5.2 BHA Run # l Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 1100 9 - SDBS FMFX641Z 6.125 0.389 66.37 11515' 15429' 3914' 1 -21 42 -148 0- 0- ER- N- X- I -NO -TD I 1200 9rr1 - SDBS FMFX641Z 6.125 0.389 15429' 15429' 0' I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) G as Breakdown H2S Data I Sample Line Max: 3 Avg: 0 1 Ambient Air Pit Room Max: 1 'Avg: 0 I Depth Gas (units) Chromatograph (ppm) Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to I to to to to to 1 to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... II 24 hr Recap: Continued trip to surface with clean out BHA seeing a total loss of 7.5bbls across the entire trip. Downloaded MWD & broke down & laid down BHA. Rigged up liner running equipment & started running in with 4.5" 12.6ppf L -80 liner. Run in with 135 joints of liner & attach liner hanger. Continue running in with 4" XT -39 drill pipe to 10000' MD & circulated above the window. After I circulation ceased, started running liner in to the open hole & tripping in with 4" XT -39 DP (8 stands of HWDP were picked up as well) to current depth of 13557' MD. Total trip in losses 13bbls with a slow 0.5bbI /hr seeping loss observed (consistent across the entire trip). 1 1 Logging Engineer: Tom Mansfield /Danny Kane * 10000 units = 100% Gas In Air 1 1 1 I Customer: Pioneer Natural Res. Report #: , ., - . 22 HALLUBURTON Well: ODSN -45A Date: 10/27/2009 -04:00 Area: Oooguruk 04:00 Depth 15429' I Location: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Trip & UD 4" DP Job No.: AK -AM- 0005710484 Report For: J. Poyla /J. Cortez I Daily Charges $4,420.05 Total Charges: $123,174.11 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. (ft/hr) Flow In (gpm) 0 SPP (psi) 23 Gas (units) 0 12 300 Flow In (spm) 0 Gallons /stroke 3.5175 Hole Condition Depth On Bot Hrs Ann Corr Avg Diam PWD Drilling Min Avg Max 15429' 118.42 205 bbls 9.21" All Circ Min Avg Max Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib /100ft m1/30min mg /I % 4:, 1 15429' 9.30 9.30 27 47k 4.1 BHA Run # I Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 1100 9 - SDBS FMFX641Z 6.125 0.389 66.37 11515' 15429' 3914' 1 -21 42 -148 0- 0- ER- N- X- I -NO -TD 1200 9rr1 - SDBS FMFX641Z 6.125 0.389 15429' 15429' 0' I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) Gas Breakdown I H2S Data 1 Sample Line 'Max: 6 Avg: 0 1 Ambient Air Pit Room 'Max: 2 Avg: 0 I Depth Gas (units) Chromatograph (ppm) Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to I to to to to to to to to i I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; i POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... I 24 hr Recap: Finished running liner to bottom at 15429' MD before pulling up 5' MD to hang the liner. Dropped & seated ball & then proceeded to pressure test the liner -- tests failed until slacked off 4' MD. With the liner hung & pressure tested, circulated 2x B/U & chased with dirt magnet chasing wash to displace the well over to 9.30ppg NaCI brine. Max trip gas while circulating was 300 unit at bottoms up that quickly diminished to 5 -10 units background shortly thereafter. With the dirt magnet around, slipped & cut 1 1500' MD drill line before starting to pull & lay down 4" drill pipe per pipe management. Total losses past 24 hours 25bbls. 1 1 Logging Engineer: Tom Mansfield /Danny Kane * 10000 units = 100% Gas In Air 1 1 Customer: P ioneer Natural Res. R eport #: 23 A' t' 4ALLIBURTON Well: ODSN -45A Date: 10/28/2009 -04:00 Area: Oooguruk 04:00 Depth 15429' I k Location: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Running 4.5" Tubing Job No.: AK -AM- 0005710484 Report For: J. Brown /J. Cortez I Daily Charges $4,420.05 Total Charges: $127,594.16 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. (ft/hr) Flow In (gpm) 0 SPP (psi) 23 Gas (units) 0 0 0 Flow In (spm) 0 Gallons /stroke 3.5175 Depth On Bot Hrs Ann Corr Avg Diam Drilling Min Avg Max Hole Cond 15429' 118.42 i 205 bbls 9.21" PWD All Circ Min Avg Max Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft m1/30min mg /I 1 " _ 15429' 9.30 n/a 27 47k 4.1 BHA Run # l e,_ Bit Type Size TFA Hours Depth in /out Footage WOB RPM Condition 1100 9 - SDBS FMFX641Z 6.125 0.389 66.37 11515' 15429' 3914' 1 -21 42 -148 0- 0- ER- N- X- I -NO -TD I 1200 9rr1 SDBS FMFX641Z 6.125 0.389 15429' 15429' 0' I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) Gas Breakdown H2S Data 1 Sample Line IMax: Avg: 1 Ambient Air Pit Room Max: jAvg: I r Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to to to I to to I E ^ . to to to t0 I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... - , 24 hr Recap: Complete pipe mangment UD 276 jts dp and 24 jts H/W dp . L/D BHA liner running assy. Flush stack and and change lower rams to 4.5" . P/U tubing hanger and M/U to landing jnt. Perform mock run with tubing hanger and test seals to 5,000 psi and UD hanger. R/U to run tubing, P/U rock gauge and control line spools and hang sheaves. R/U and run ROC gauge and and tie in. Begin running tubing with a current depth of 2354'. Total losses for 24 hrs were 29 bbls. A 5 bbl loss has been recorded while I running tubing. 1 Logging Engineer: r +A1 10000 units = 100% Gas In Air I , , .- 1 1 Customer: Pioneer Natural Res. Report #: 24 HALLIBURTON Well: ODSN -45A Date: 10/30/2009 -04:00 Area: Oooguruk 04:00 Depth 15429' Location: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: wD Bop's Job No.: AK -AM- 0005710484 Report For: J. Brown /J. Cortez Oii Daily Charges $5,300.37 Total Charges: $131,133.89 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. (ft/hr) Flow In (gpm) 0 SPP (psi) Gas (units) Flow In (spm) 0 Gallons /stroke 3.5175 Depth On Bot Hrs Ann Corr Avg Diam Drilling Min Avg Max Hole Condition PWD Au Circ Min Avg Max Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib /100ft m1/30min mg /I % I 15429' 9.30 n/a _ 28 48k 4.0 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 1100 9 - SDBS FMFX641Z 6.125 0.389 66.37 11515' 15429' 3914' 1 -21 42 -148 0- 0- ER- N- X- I -NO -TD 1 1200 9rr1 - SDBS FMFX641Z 6.125 0.389 15429' 15429' 0' .P Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) Gas Breakdown H2S Data 1 Sample Line 'Max: 'Avg: 1 Ambient Air Pit Room 'Max: 'Avg: I Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to I to to to to 11 to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... , ' na _. 24 hr Recap: Continue running 4.5" liner to 9905.61' md. Stung in and set down to 15K pressure test to 3500 psi for 10 min. M/U hanger landing jnt and land at 16 k on on tie back seal assy. Test upper and lower hanger seals to 5000 psi for 10 min. Test ann 52 stks, 3500 psi for 10 min. Pull landing jnt and and install BPV. Clear liner running equipment from rig floor, begin rig maint. And I N/D BOP's preparing for rig move. Sperry obsverved a 7 bbls loss while running liner. r e 1 Logging Engineer: Tom Mansfield /Dan Sherwood /Colby Marks * 10000 units = 100% Gas In Air 1 1 Customer: Pioneer Natural Res. Report #: 3 #ALLIBURTON Well: ODSN -45A Date: 10/09/2009 -04:00 I Area: Oooguruk 04:00 Depth 10095' Location: North Slope Progress 24 hrs: N/A S perry Drilling Services Rig: Nabors 19AC Rig Activity: Testing BOP's Job No.: AK -AM- 0005710484 Report For: J. Brown /R. Klepzig I Daily Charges $5,256.21 Total Charges: $275,934.55 are ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. (ft/hr) Flow In (gpm) 0 SPP (psi) 30 Gas (units) 1 11 Flow In (spm) 0 Gallons /stroke 3.5175 Death OnBotHrs 0.en Ad' Av. Diam Drilling Min Avg Max Hole Condition PWD All Circ Min Avg Max I Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/gt) (ppb Eq) cP (Ib/100ft m1/30min mg /I I 10105' 8.95 28 10.60 57K 0.8 BHA Run # I Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 760 Smith XR -312 6.75 0.518 3.6 10020' 10095' 20 -40 50 -60 2- 2- CT -A -BT -BHA 800 Smith 6.75 0.589 10095' I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) _ , I Gas Breakdown I H2S Data 1 Sample Line Max: 'Avg: I Ambient Air Pit Room jMax: IAvg: I Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to I to to to to I 1 to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip... ; F -- - Formation... ; E -- - Early... I 4i,, 24 hr Recap: Continue to RIH with scraper run assy and begin washing and reaming @ 9649' tag hard cement @ 10,020' and drill to out packer and guns to 10,046'. Drill out fast drill plug and cement to 10,095' and Pump 50 bbl hi vis sweep and circulate 2x btms up. POOH attaching super sliders 1 per joint. L/D BHA and begin testing BOP's currently repairing HRC on BOP stack at the time of I report. 1 1 Logging Engineer: Colby Marks /Daniel Sherwood /Tom Mansfield " 10000 units = 100% Gas In Air �, J X?' a .. `1 x� to 4 1 1,,'-';',' - ,-;.: 4 M-,4 7 , , V - ', - 1 1 �t I Customer: Pioneer Natural Res. Report #: 4 I HALLIBURTON Well: ODSN -45A Date: 10/10/2009 -04:00 Area: Oooguruk 04:00 Depth 10054' Location: North Slope Progress 24 hrs: c Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Milling Window/Drilling Job No.: AK -AM- 0005710484 Report For: J. Brown /R. Klepzig I F Daily Charges $4,375.89 Total Charges: $276,770.71 ii ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. ft/hr 0.0 1.5 ® 10052' Flow In • •m 190 SPP •si 1447 Gas (units) 7 6 8 10052' Flow In (spm) 54 Gallons /stroke 3.5175 Death OnBotHrs O•en -Hole Ad' Av• Diam Drillin• 9.76 Min 9.79 Av. 9.91 Max Hole Condition - - -- P WD All Circ _ Min _Avg MN Max Mud Data: Density (ppg) Viscosity MB PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/.t) • •b E• cP (Ib /100ft m1/30min m•/I % I 10105' 9.00 28 - -_ -- 10.50 61k 1.6 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 760 Smith XR -312 6.75 0.518 3.6 10020' 10095' 20 2-2-CT-A-BT-BHA I 800 Smith 6.75 0.589 1.8 10050' 10054' 4' 90_15200-64 Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff _ „, I (current) ® ® ®--- _ -__ =II Gas Breakdown I H2S Data I Sample Line 'Max: IAvg: 1 Ambient Air Pit Room !Max: IAvg: I I Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to I to to to to 1 to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... I 24 hr Recap: Complete testing of BOP's and P/U BHA, RIH with whipstock and milling assy, shallow pulse test MWD tools and cont to RIH. Orient whipstock and set shear pin. Rotate and circulate to shear nozzle plugs from bit. Begin milling window, currently milling window at the time of report. All losses are attributed to flow over shakers. No significant gas peaks have been recorded. 1 1 1 Logging Engineer: Daniel Sherwood /Tom Mansfield * 10000 units = 100% Gas In Air 1 n 1 1 Customer: Pioneer Natural Res. Report #: 5 HALLIBURTQN Well: ODSN -45A Date: 10/11/2009 - 04:00 I Area: Oooguruk 04:00 Depth 10124' li Location: North Slope Progress 24 hrs: 70' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: POOH Job No.: AK -AM- 0005710484 Report For: J. Brown /R. Klepzig I x Daily Charges $5,685.51 Total Charges: $285,875.05 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. (ft/hr) 0.0 5.8 37.0 10060' Flow In (gpm) 0 SPP (psi) 0 Gas (units) 2 9 32 10068' Flow In (spm) 0 Gallons /stroke 3.5175 Depth On Bot Hrs Open - Hole Adj Avg Diam Drilling 9.85 Min L 9 : 98 Avg 10.12 Max Hole Condition PWD 10124 12 All Circ 9.66 Min 97 Avg 10.17 Max Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft m1/30min mg /I % 10124' 9.30 9.30 39 2.0 7 12 9.80 43k 4.5 BHA Run # I Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 760 Smith XR -312 6.75 0.518 3.6 10020' 10095' 20 -40 50 -60 2- 2- CT -A -BT -BHA 800 Smith 6.75 0.589 12 10050' 10124 74' 5. -30 90 -120 TT Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) 10 25 65 Gas Breakdown ' H2S Data 1 Sample Line Max: 0 Avg: 0 1 Ambient Air Pit Room Max: 1 !Avg: 0 I Depth Gas (units) Chromatograph (ppm) Maximum Average C1 C2 C3 C4 Tot C5 Tot Type I 10054' to 10124' 32 9 1559 57 19 8 0 FBG to I to to to I to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation... ; E -- - Early... P.. , Vin x:;:; >; ., ' I 24 hr Recap: Continue to mill window into new formation, drill and slide to 10,091' md. Circ btms up and conduct FIT to 12.5 ppg Contine to drill and slide to 10,124' . Pump slug observe static well and POOH due to poor ROP. POOH to 8494' and adjust rig and BOP stack due to trouble w super sliders colliding with stack. Continuing to POOH at the time of report. Formation gas remained under 40 units while drilling with no significant peaks and was reflective upon ROP. Sample quality was very poor due to Icm and .,. bit action and exposure w pred, v agrill shale, slst, and sme sst, w mod p. por. All recorded losses have been attributed to solid control equipment. 1 ;, Logging Engineer: Daniel Sherwood /Tom Mansfield " 10000 units = 100% Gas In Air 1 1 Customer: Pioneer Natural R es. Repo #: 6 ALLIBURTON Well: ODSN -45A Date: 10/12/2009 -04:00 Area: Oooguruk 04:00 Depth 10124' Location: North Slope Progress 24 hrs: N/A Sperry Drilling Services Rig: Nabors 19AC Rig Activity: RIH Job No.: AK -AM- 0005710484 Report For: J. Brown /R. Klepzig 1 Daily Charges $5,685.51 Total Charges: $290,130.04 4i ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: 1 1 R.O.P. (ft/hr) ,, >, ,, :_ Flow In (gpm) 0 SPP (psi) 0 Gas (units) 1 2 11 Flow In (spm) 0 Gallons /stroke 3.5175 Depth On Bot Hrs Open -Hole Adj Avg Diam Drilling x :,? Min Avg ' Max Hole Condition 10124' 12 PWD All Circ' Min (Avg ' Max Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/gt) (ppb Eq) cP (Ib/100ft m1/30min mg /I % ' 10124 9.30 9.30 44 2.0 8 17 4.0 11.90 48k 4.2 BHA Run # I Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 800 Smith 6.75 0.589 12 10050' 10124' 74' 5. -30 90 - 120 TT 78- R- O- A- X- 2 -BT -TR 1 900 Security 6.75 0.389 10124' I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff 1 (current) Gas Breakdown H2S Data 1 Sample Line 'Max: 0 IAvg: 0 1 Ambient Air Pit Room Max: 0 'Avg: 0 I Depth Gas (units) Chromatograph (ppm) Maximum Average 01 C2 C3 C4 Tot C5 Tot Type to to I to to to I to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; f POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... I 24 hr Recap: Continue to POOH to surface and L/D BHA. P/U new bit, Sperry mud motor, MWD and remainder of BHA and RIH to 6735' and and reposition rig. Complete rig move and continue to RIH. 1 1 1 Logging Engineer: Daniel Sherwood /Tom Mansfield * 10000 units = 100% Gas In Air °« 1 1 w, Customer: Pioneer Natural Res. Report #: 7 ` HALLIBURTON Well: ODSN -45A Date: 10/13/2009 -04:00 I Area: 1 . Oooguruk 04:00 Depth 10524' ation: North Sloe p Progress 24 hrs: 400' py g Rig: Nabors 19AC Rig Activity: Driving Ahead Job No.: AK -AM- 0005710484 Report For: J. Brown /R. Klepzig Daily Charges $5,685.51 Total Charges: $294,385.04 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. (ft/hr) 3 33. 7 10422' Flow In (gpm) 269 SPP (psi) 2107 , Gas (units) 57 102 409 10478' Flow In (spm) 76 Gallons /stroke 3.5175 Hole Condition Depth On Bot Hrs Open - Hole Adj Avg Diam PWD Drillin• 9.94 Min 10.10 Av. 10.37 Max 10525' 22.95 g All Circ 2.35 Min 10 10 Avg 10.45 Max I .r' 1 v Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib /100ft m1/30min mg /I % I 10414' 9.30 44 3.0 9 20 3.8 10.90 43k 4.6 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition I 800 Smith 6.75 0.589 12 10050' 10124' 74' 5. -30 90 -120 TT 78- R- O- A- X- 2 -BT -TR 900 Security 6.75 0.389 11 10124' 10524' 400' 0 -30 180 -220 TT I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 40 40 20 Gas Breakdown I H2S Data I Sample Line Max: 1 Avg: 0 1 Ambient Air Pit Room Max: 1 Avg: 0 I Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 10124' to 10194' 76 33 6989 294 117 55 17 FBG 10194' to 10278' 115 69 9747 485 203 108 47 FBG 10279' to 10309' 239 156 22439 1340 607 270 134 FBG 10400' to 10405' 221 213 20334 1207 581 329 148 CG 10420' to 10453' 315 213 28857 1820 1820 514 231 FBG I 10479' to 10494' 249 173 22728 1394 658 376 180 FBG to to to 1 Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip... ; F -- - Formation...; E -- - Early... I 24 hr Recap: Continue to RIH to10,019' and service top drive and crown saver, cont to RIH to btm and drill and slide to 10,309' Circ btms up and R \U wireline and multishot gyro service equipment. RIH with gyro to 10,174 and pump down gyro tool. POOH with gyro\ equipment and R/D gyro and wireline equipment. RIH to btm and drill ahead to 10,524' at the time of report. Primary lithology I consisted of siltstones, silt, shale and claystones with some tuff. Gas levels remained under 450 U with one small connection gas recorded @ 10, 403 w max gas 15 U above background gas levels. Gas levels flucuated accordingly with sliding and rotaong drilling and according to recorded ECD levels. Cuttings samples revealed poor visible porosity and sample fluorecence was tainted due to mud additives. No downhole losses were recorded circulating or static. 1 Logging Engineer: Daniel Sherwood /Tom Mansfield * 10000 units = 100% Gas In Air I ' , **. .._ .„. :, , 1 1 Customer: Pioneer Natural Res. Report #: 8 -'IALLIBURTON Well: ODSN -45A Date: 10/14/2009 -04:00 Area: Oooguruk 04:00 Depth 11325' I Location: North Slope Progress 24 hrs: 801' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Circulating and Condition Job No.: AK -AM- 0005710484 Report For: J. Brown /R. Klepzig Daily Charges $6,565.83 Total Charges: $302,381.38 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I ,, R.O.P. (ft/hr) 48.8 162.0 10676' Flow In (gpm) 327 SPP (psi) 2929 x Gas (units) 98 238 1084 10662' Flow In (spm) 94 Gallons /stroke 3.5175 Hole Condition Depth On Sot Hrs Avg Diam PWD Drilling 9.91 Min 10.18 Avg 10.63 Max 11325' 39.46 All Circ 9.91 Min 10.19 Avg 10.76 Max I n + Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib /100ft m1/30min mg /I % 1 11215' 9.30 9.45 41 4.5 8 16 4.0 10.60 40 4.7 BHA Run # I Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 800 Smith 6.75 0.589 12 10050' 10124' 74' 5. -30 90 -120 TT 78- R- O- A- X- 2 -BT -TR I 900 Security 6.75 0.389 27.47 10124' 11325' 1201' 0 -30 180 -220 TT Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) 10 85 5 Gas Breakdown I H2S Data 1 Sample Line Max: 1 Avg: 0 1 Ambient Air Pit Room Max: 1 Avg: 0 I i I Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 10648' to 10682' 1084 471 95746 6391 2830 1280 565 GP /FBG 10760' to 10771' 502 349 44677 2987 1494 825 397 FBG I 10807' to 10840' 641 520 59161 3648 1631 839 390 FBG 10856' to 10882' 935 703 84291 5251 2203 1128 511 FBG /GP 10900' to 10935' 578 428 52896 3281 1492 783 382 FBG I 10965' to 10984' 417 364 37579 2305 1083 600 307 FBG 10984' to 11325' 341 170 27083 1753 867 510 271 FBG to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip... ; F -- - Formation...; E -- - Early... 24 hr Recap: Drill and slide from 10,524' and to 11,325' md. Major gas peaks occurred at 10,661' and that was centred on a vf gr gr ang -sub ang p consd, sst with some visible oil stn, dul yel fluor w/ fast bri ct. Gamma and resistivity confirmed the sst bed. Max gas was 1084U with the majority of the gas peak being drilled while sliding. An increase in ROP occurred as well w max ROP recorded I @ 162 ft/hr while rotating and 106 hr while sliding. The next peak occurred at 10,887' also centred on vf gr sst mod -w srtd, w/ MWD tools confirmin. sst section. The ma of the 'as .eak was drilled with rota , w max ROP of 153' hr. Backe round 'as levels after 11,000' and remained under 400 units with little changes in lithology consisting almost entirely of silstone with the occasional shale and sst -grdg to sltst stringer. Section TD was called at 11,325' and currently pumping one of three sweeps. No downhole I losses were recorded. 1 Logging Engineer: Daniel Sherwood /Tom Mansfield " 10000 units = 100% Gas In Air 1 Customer: Pioneer Natural Res. Report #: 9 'IALLIBURTON Well: ODSN -45A Date: 10/15/2009 -04:00 I Area Oooguruk 04:00 Depth 11325' Location: North Slope Progress 24 hrs: N/A Sperry Drilling Services Rig: Nabors 19AC Rig Activity: RIH Job No.: AK -AM- 0005710484 Report For: J. Brown /R. Klepzig I Daily Charges $6,606.13 Total Charges: $309,987.51 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. ft/hr Flow In • •m ft, SPP •si Gas (units) 0 7 102 Flow In (spm) m Gallons /stroke 3.5175 Death OnBotHrs- Avc Diam Drillin• Min Av. Max Hole Cond 11325' 39.46 PWD All Circ ani Min 4111 Avg Max 1 Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Death ft in out (sec/•t) •.b E. cP (Ib /100ft m1/30min m. /I % 1 11215' 9.30 IMO 42 5.0 10 18 4.4 10.50 43K 4.5 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition 900 Security 6.75 0.389 27.46 10124' 11325' 1201' 0 -30 180 -22o TT 1- 1- NO- A- E -I -NO -BHA U 1000 Reed Hycalog 6.125 0.461 11325' I Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) Gas Breakdown 1 H2S Data 1 Sample Line Max: 1 Avg: 0 l Ambient Air Pit Room Max: 1 Avg: 0 I I Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type 4:00 to 4:00 102 7 6865 482 240 163 114 RG I to to to to 1 to to to to I Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... I 24 hr Recap: Pump high vis 40bbI sweeps and circ btm up and POOH to 9923' md. Slip and cut drill line and service top drive. POOH to surface and test BOP's. P/U BHA #15 and confidence test MWD tools. Currently making up remainder of BHA and RIH. 1 1 1 Logging Engineer: ak +A1 * 10000 units = 100% Gas In Air 1 Customer: Pioneer Natural Res. Report #: 75 HALLIBURTON Well: ODSN -45A Date: 10/05/2009 -04:00 I Area: Oooguruk 04:00 Depth N/A Location: North Slope Progress 24 hrs: N/A Sperry grilling Services Rig: Nabors 19AC Rig Activity: Pulling Tubing Job No.: AK -AM- 0005556601 Report For: J. Brown /J. Cortez I Daily Charges $3,539.73 Total Charges: $263,598.88 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. ft/hr - - -- Flow In • •m 0 SPP •si 30 , Gas (units) 16 2 19 Flow In (spm) 0 Gallons /stroke 3.5175 Death On Bot Hrs O•en -Hole Ad' Av• Diam Drillin• _ Min _ Ave _ Max Hole Condition - - -- PWD All Circ _ Min Avg Max • 1 ' Mud Data: Density (ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Death ft in out (sec/.t) • •b E• cP (Ib/100ft m1/30min m. /I % I N/A 8.55 28 IIIIIIIIIIIII. 8.00 13100 200.0 BHA Run # Bit Type Size TFA Hours Depth in / out Footage WOB RPM Condition Lithology ( %): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) IIIIIIIIIIIIIII 111111111111111 MEM Mil Gas Breakdown H2S Data 1 Sample Line Max: 0 Avg: 0 1 Ambient Air Pit Room 'Max: 0 Avg: 0 I Gas (units) Chromatograph (ppm) Depth Maximum Average C1 C2 C3 C4 Tot C5 Tot Type to I to to to to II to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T -- - Trip...; F -- - Formation...; E -- - Early... I t_� 24 * h r Recap: Complete rig move, reverse circ out diesel with sea water. N/D tree, N/U BOP's and test. R/U to pull 2 7/8" comletion II liner. Begin POOH with 2 7/8" production liner L /D. Azt '''' I '4' ,,,:.: 1 Logging Engineer: Colby Marks /Daniel Sherwood * 10000 units = 100% Gas In Air <r� ..a� • MO I MI N NE MN E ME 1 NE MN 1 NM M 1 M NM NM NM HA`LI BLJ RTQIV WELL NAME: ODSN -45A LOCATION: Oooguruk OPERATOR: Pioneer Natural Resources AREA: North Slope MUD CO: Baroid STATE: Alaska Qa+ililirtst RIG: Nabors 19AC SPUD: 4- Aug -08 SPERRY JOB: AK -AM -0005710484 TD: 21- Oct -09 BIT RECORD BHA# SDL Bit # Bit Type Bit Depth Depth Footage Bit TFA AVG WOB RPM SPP FLOW GPM Bit Grade Remarks RUN # Size In Out Hours ROP (max) (max) (max) (max) 1 100 1 Hughes MXL -1 13.50 153 4985 4832 47.39 0.699 102.0 40 80 2500 650 2- 2- WT- A- E- 3 -ER -TD TD 13.5" Surface Section at 4985' MD /3442' TVD on 15:59 08-Aug -2008 2 200 2 Security DBS FSF3563Z 9.88 4985 12323 7338 88.10 1.108 83.3 40 132 2570 632 1- 1- CT- C- X- I -NO-HP TD 9.875" Intermediate Section at 12323' MD on 09:21 20- Aug -2008 13 800 6 Smith Pathfinder 6.75 10050 10124 74 11.98 0.589 6.2 35 64 2124 234 7- 8- RO- A- X- 2 -BT -PR Mill 6.75" Window, Trip for Formation Bit 14 900 7 Security DBS FSF -3563Z 6.75 10124 11325 1201 27.50 0.389 43.7 25 200 2340 270 1- 1- NO- A -E -NO -BHA Trip Out to Replace Motor with GeoPilot BHA 15 1000 8 Hycalog RSR413D -A1 6.13 11325 11515 190 11.98 0.461 15.9 30 129 1889 247 0- 0- CT -S -X -I -NO-PR Trip Out for Bit (Poor ROP) 16 1100 9 Security DBS FMFX641Z 6.13 11515 15429 3914 66.37 0.389 59.0 23 148 2658 283 0- 0- ER- N- X -I -NO TD TD 6.125" Production Section at 15429' MD / 5018' TVD on 10:16 16-Oct-2009 17 1200 9 Security DBS FMFX641Z 6.13 15429 15429 0.451 33.8 138 2580 255 _ Clean Out Trip ■ 1 N i• r N I N MO N OM NM all MO NM --11 MI r MN MI I HALLIBURT'aN WELL NAME: ODSN -45A LOCATION: Oooguruk OPERATOR: Pioneer Natural Resources AREA: North Slope Sperry CRrii lino MUD CO: Baroid STATE: Alaska RIG: Nabors 19AC SPUD: 4 -Aug -08 SPERRY JOB: AK- AM- 5710484 TD: 21- Oct -09 Water- and Oil-Based Mud Record R6001R300/R200/R100/ Date Depth Wt Vis PV YP Gels Filt R6/R3 Cake Solids Water /OiI Sd Pm pH MBT Pf /Mf Chlor Hard Remarks ft - MD ppg sec lb/100 Ib/100ft2 m130m Rheometer 32nds % % % mg /I Ca++ 4 -Aug 294 8.90 92 16 51 22/27/- 7.6 83/67/60/49/26/23 2 2.9 94.0 0.50 0.20 8.8 1.0 0.20/2.00 19.0 640 Drilling 5-Aug 1957 9.30 90 18 46 22/30/- 6.2 82/64/56/44/23/20 2 6.0 92.0 0.50 2.10 9.5 6.0 .15/1.9 19.0 440 Drilling 6 -Aug 3378 9.40 90 21 46 26/38/- 6.8 88/67/58/47/25/22 2 7.0 90.0 0.75 1.90 9.1 8.0 .1/1.9 19.0 480 Drilling 7 -Aug 4747 9.50 67 16 42 26/46/- 7.0 74/58/51/43/27/26 2 7.0 90.0 0.75 0.20 9.0 12.5 .1/2 19.0 480 Cond. Mud & Circ 8 -Aug 4985 9.70 62 12 40 22/ -/- 7.6 64/52/46/38/24/23 2 9.0 88.0 0.75 0.10 9.0 15.0 .1/2.2 19.0 480 Tripping 9 -Aug 4985 9.90 65 16 40 26/36/- 8.2 72/56/50/42/27/26 2 10.0 87 0.75 0.20 9.5 12.5 .2/2.4 19.0 480 Cementing 10-Aug 4985 9.70 47 13 20 15/25/- 8.6 46/33/27/23/14/12 2 9.0 88 0.50 8.8 15.0 0.05/2.00 19.0 480 WOC 11 -Aug 4985 9.70 49 13 22 16/27/- 8.8 48/35/29/33/14/12 2 9.0 88.0 0.50 8.9 15.0 0.10/2.20 19.0 480 Tripping 12 -Aug 4985 9.70 47 13 20 18/30/- 9.0 46/33/28/22/14/13 2 9.0 88.0 0.50 8.5 15.0 0.05/2.20 19.0 480 Test BOPE 13 -Aug 4985 9.70 49 13 23 20/34/- 9.0 49/36/30/24/15/13 2 9.0 88.0 0.50 8.6 15.0 0.05/2.30 19.0 480 Cond. Mud & Circ 14-Aug 6138 8.90 45 14 23 6/8/- 5.8 51/37/31/23/8/6 2 3.9 93.5 0.25 0.60 9.9 7.0 0.20/1.60 9.5 360 Drilling 15-Aug 7985 9.10 47 16 19 8/11/- 6.2 51/35/28/20/8/6.5 2 4.9 92.0 0.25 8.6 12.0 0.05/0.80 10.0 480 Drilling 16 -Aug 8740 9.10 48 16 17 7/12/- 8.0 49/33/25/17/7/6 2 5.3 90.5 0.25 0.20 8.9 12.5 0.10/0.80 12.5 480 Drilling 17 -Au9 9550 9.20 48 16 _ 16 11/16/- 7.2 48/322/26/18/9/8 2 6.2 87.0 0.10 _ 8.5 12.5 0.10/0.70 14.5 400 Drilling . " .. - Move Over Rig on October 5, 2009 6 -Oct 10050 7 5/8" CSG window at 10050' MD 7 -Oct 10105 8.95 28 4.8 - /95.0 10.4 66.0 Tripping 8 -Oct 9 -Oct 10095 9.00 28 1.6 -/95.0 10.5 61.0 Cond. Mud & Circ 10 -Oct 10124 9.30 39 7 12 6/8/11 2.4 26/19/16/12/4/3 1/- 4.5 4.0/88.2 0.31 9.8 2.0 0.05/2.10 43.0 200 Tripping 11 -Oct 10124 9.30 44 8 17 8/10/13 4.0 33/25/21/16/6/5 1/- 4.2 40/88.1 1.50 11.9 2.0 0.35/2.70 48.0 180 Drilling 12 -Oct 10330 9.30 44 9 20 8/12/15 3.8 38/29/25/19/7/6 1/- 4.6 4.0/88.1 0.10 0.67 10.9 3.0 0.17/2.33 43.0 160 Drilling 13 -Oct 11129 9.30 41 8 16 6/12/16 4.0 32/24/20/15/5/4 1/- 4.7 4.0/88.2 0.58 10.6 4.5 0.09/1.90 40.0 120 Drilling 14 -Oct 11325 9.30 42 10 18 8/14/- 4.4 382823/18/6/5 1/- 4.5 4 0/88.2 0.10 0.71 10.5 5.0 0.19/2.47 43.0 200 Test BOPE 15 -Oct 11325 9.30 42 10 16 7/12/16 5.0 362621/18/6/5 1/- 4.6 2.0/89.9 0.10 0.10 9.0 5.0 0.07/2.05 44.0 200 MAD Pass Log 16 -Oct 11515 9.20 43 7 17 7/9/12 3.8 31/24/20/16/5/4 1/- 4.8 2.0/91.0 0.10 0.20 9.2 3.6 0.10/2.32 28.0 320 Tripping 17 -Oct 11515 9.30 41 8 12 6/8/- 4.4 28/20/17/13/5/4 1/- 4.3 4.0/88.0 0.10 0.57 10.7 4.2 0.15/2.55 48.0 280 Tripping 18 -Oct 12495 9.30 39 8 13 6/8/- 4.6 29/21/17/13/5/4 1/- 5.2 4.0/88.0 0.10 0.40 10.0 6.0 0.16/2.60 36.0 360 Drilling 19 -Oct 13740 9.30 39 10 14 6/9/- 4.4 34/24/20/14/5/4 1/- 4.4 4.0/88.0 0.10 0.10 9.2 6.0 0.05/1.22 42.0 280 Drilling 20 -Oct 14776 9.30 45 9 22 10/13/- 1.0 40/31/26/20/8/7 1/- 5.3 4.0/880 0.10 1.07 10.8 2.5 0.11/0.83 35.0 320 Drilling 21 -Oct 15429 9.30 43 9 20 7/11/- 5.4 38/29/24/19/5/4 1/- 5.4 4.0/88.0 0.10 0.55 10.2 5.0 0.09/0.75 34.0 280 Wiper Trip 22 -Oct 15429 9.30 39 9 15 6/8/- 5.0 332420/15/5/4 1/- 4.9 4.0/88.0 0.10 0.57 9.7 5.5 0.09/0.81 40.0 280 Wiper Trip 23 -Oct 15429 9.30 42 11 17 7/11/- 4.2 39/28/23/18/7/6 1/- 4.5 4.0/88 2 0.10 0.15 10.3 4.0 0.10/1.10 43.0 220 Clean Out Trip In 24 -Oct 15429 9.55 40 9 16 7/11/- 5.2 342520/14/7/6 1/- 7.0 4.0/86.4 0.10 0.10 9.5 5.0 0.05/1.20 34.0 200 Clean Out Check Trip 25 -Oct 15429 9.40 40 10 16 7/11/- 4.1 36/26/22/16/7/6 1/- 5.5 4.0/87.6 0.10 0.15 10.7 5.0 0.10/1.90 38.0 200 Clean Out Trip Out 26 -Oct 15429 9.30 41 11 14 7/11/- 4.2 36/25/21/15/6/5 1/- 5.2 40/88.0 0.10 0.15 10.1 5.0 0.10/1.60 36.0 200 Running Completion Liner 27 -Oct 15429 9.30 27 4.1 _ -/93.0 47.0 Trip Out (Hung Liner) Casing Record 16" Conductor @ 153.00' MD 10a /:' Surface @ 4973.0' MD 7W Intermediate @ 10050.00' MD 1 1 -1A1J-11311JIMTCHNI Well Name: ODSN -45A Depth (MD) 10658 to 10685 ft 1 » a+llb+a Location: North Slope, Alaska (ND) 5091 to 5097 ft Show Reports Operator: Pioneer Natural Resources Show Report No. 1 Report Prepared By: Tom Mansfield Date/Time: 13- Oct -09 Report Delivered To: 1 Interpretation: Ratios slightly steeper and higher due to chromatograph "gas as air' analysis from gas trap at possum belly rather than "gas in mud" as designed and would fall within the oil range, sloping into the lower gas range. Samples went from Siltstone to a very fine I to fine grained, poorly consolidated Sandstone during show interval. Minor traces of oil staining were present. A slight sheen was evident while washing samples. Sample fluorescence masked by mud additives. Trace of oil staining and sheen indicate presence of oil. 11 % Hydrocarbon Ratios I Depth 10659 ft Gas Units 3182 Mud Chlorides (1000's) : 23 C1 C1 C1 C1 Flowline Background Show C2 C3 C4 C5 ppm ppm ppm Hydrocarbon Ratios 1000 I 01 25583 6699 = 18884 C1 /C2 = 15 C2 1641 - 403 = 1238 C1 /C3 = 34 C3 787 - 233 = 554 C1 /C4 = 72 C4 434 - 171 = 263 C1 /C5 = 156 NPH 1 C5 223 - 102 = 121 Production 100 - ;" Analysis nGas nOil nWater n Non- Producible Hydrocarbons - % I - Depth 10666 ft Gas HUnits 4623 Mud Chlorides (1000's) : 23 Gas Flowline Background Show ... ppm ppm ppm ............ Hydrocarbon Ratios 10 - C1 92800 6699 = 86101 C1 /C2 = 15 C2 6245 403 = 5842 C1 /C3 = 34 C3 2768 - 233 = 2535 C1 /C4 = 80 Oil C4 1251 - 171 = 1080 C1 /C5 = 188 - - - 1 C5 559 - 102 = 457 NPH Production 1 Analysis nGas nOil nWater nNon- Producible Hydrocarbons Hydrocarbon Ratios - Depth 10670 ft Gas � Units 4623 Mud Chlorides (1000's) = 23 C1 C1 C1 01 I Flowline Background Show C2 C3 C4 C5 ppm ppm ppm Hydrocarbon Ratios 1000.0 I 01 85065 6699 = 78366 C1 /C2 = 15 C2 5674 - 403 = 5271 C1 /C3 = 35 C3 2500 233 = 2267 C1 /C4 = 82 NPH C4 1130 - 171 = 959 C1 /C5 = 193 1 C5 507 102 = 405 _ - - - _ Production 100.0 Analysis nGas f n Oil Water nNon - Producible Hydrocarbons _ 1 - Depth 10680 ft Gas x Units 4158 Mud Chlorides (1000's) 23 Gas - _ _ _ _ - Flowline Background Show r - - ppm ppm ppm Hydrocarbon Ratios 10.0 I 01 35047 - 6699 = 28348 C1 /C2 = 15 C2 2241 403 = 1838 C1 /C3 = 35 Oil C3 1044 - 233 = 811 C1 /C4 = 75 C4 551 - 171 = 380 C1 /C5 = 164 ---- -- - - - 1 C5 275 - 102 = 173 NPH Production 1.0 Analysis nGas f011 nWater nNon- Producible Hydrocarbons 1 1 1 1 ... ... ._.. '°'`1-4-Y uH i LSI ' Well Name: ODSN -45A Depth (MD) 13130 to 13167 ft I cs+sna Location: North Slope, Alaska (TVD) 5090 to 5086 ft Show Reports Operator. Pioneer Natural Resources Show Report No. 2 Report Prepared By: Danny Kane Date/Time: 19- Oct -09 Report Delivered To: I a Interpretation: Ratios slightly steeper and higher due to chromatograph "gas as air analysis from gas trap at possum belly rather than "gas in mud" as designed and would fall within the oil range, sloping into the lower gas range. Samples went from Siltstone to a very fine I to fine grained, poorly consolidated Sandstone during show interval. The samples had a yellow -gold fluorescence with a good streaming dull- bright yellow cut fluorescence. The good fluorescence along with an increase in the resistivity to 12ohmm suggests presence of oil. tea, J _ °%° Hydrocarbon Ratios I Depth 13137 ft Gas x Units 861 Mud Chlorides (1000's) 36 01 C1 01 C1 Flowline Background Show C2 C3 C4 C5 ppm ppm ppm Hydrocarbon Ratios 1000 - 1 01 C2 78932 - 16524 = 62408 C1 /02 = 15 5320 1039 = 4281 C1 /C3 = 33 C3 2389 - 470 = 1919 C1 /C4 = 79 C4 1060 - 270 = 790 C1 /C5 = 199 NPH I C5 478 - 164 = 314 Production 100 �' Analysis nGas nOil nWater nNon- Producible Hydrocarbons _ J I Depth 13139 ft Gas Units 905 Mud Chlorides (1000's) 36 Gas Flowline Background Show ppm ppm ppm --------------- _ _ _ _ _ _ _ _ _ - Hydrocarbon Ratios 10 01 78250 - 16524 = 61726 01 /02 = 14 02 5337 1039 = 4298 01/03 = 32 C3 2373 - 470 = 1903 01/04 = 80 Oil C4 1044 - 270 = 774 C1/05 = 196 - — — - ' C5 Production 479 - 164 = 315 NPH 1 Analysis nGas nOil nWater n Non- Producible Hydrocarbons J _ % Hydrocarbon Ratios 1 Depth 13158 ft Gas x Units 1289 Mud Chlorides (1000's) = 36 C1 C1 C1 C1 Flowline Background Show C2 C3 C4 C5 ppm ppm ppm Hydrocarbon Ratios 1000.0 I 01 108816 - 16524 = 92292 C1 /C2 = 15 02 7160 1039 = 6121 01 /03 = 34 C3 3176 470 = 2706 C1/04 = 87 NPH C4 1328 - 270 = 1058 C1/05 = 224 1 C5 576 164 = 412 _ — .. — -- - — Production 100.0 _ �,--� Analysis nGas 171011 nWater nNon- Producible Hydrocarbons — — I Depth 13160 ft Gas x Units 1245 Mud Chlorides (1000's) 36 Gas Flowline Background Show — — — ppm ppm ppm .. Hydrocarbon Ratios 10.0 - _ 01 94014 - 16524 = 77490 01/02 = 14 02 6523 1039 = 5484 01/03 = 34 oil 03 2740 470 = 2270 01 /04 = 88 — C4 1150 - 270 = 880 01/05 = 230 — — — — — — — — — C5 501 - 164 = 337 NPH 1 Production Analysis nGas fOil nWater nNon- Producible Hydrocarbons 1.0 1 1 1 1 #AILLlf RTC711it Well Name: ODSN -45A Depth (MD) 13580 to 13620 ft I Location: North Slope, Alaska (TVD) 5052 to 5048 ft Show Reports Operator: Pioneer Natural Resources Show Report No. 3 Report Prepared By: Danny Kane Date/Time: 19- Oct -09 Report Delivered To: 1 Interpretation: Ratios slightly steeper and higher due to chromatograph "gas as air analysis from gas trap at possum belly rather than "gas in mud" as designed and would fall within the oil range, sloping into the lower gas range. Samples went from Siltstone to a very fine I to fine grained, poorly consolidated Sandstone during show interval. Samples had a yellow -gold fluorescence with a very good streaming dull- bright yellow cut and a visible cut. The good fluorescence along with an increase in the resistivity to 17ohmm suggests presence of oil. 11 % Hydrocarbon Ratios Depth 13595 ft Gas Units 995 Mud Chlorides (1000's) 40 C1 C1 C1 C1 Flowline Background Show C2 C3 C4 C5 ppm ppm ppm Hydrocarbon Ratios 1000 I C1 110386 - 16524 = C2 7070 1039 = 93862 C1 /C2 = 16 6031 C1 /C3 = 35 C3 3137 - 470 = 2667 Cl/C4 = 79 C4 1456 - 270 = 1186 C1 /C5 = 184 NPH C5 675 - 164 = 511 Production 100 _ -. Analysis nGas NOil nWater nNon- Producible Hydrocarbons . ---..---• J % �— I Depth 13597 ft Gas x Units 1530 Mud Chlorides (1000's) 40 Gas _ _ — Flowline Background Show PPm PPm PPm ........... Hydrocarbon Ratios 10 — I C1 126864 - 16524 = 110340 C1 /C2 = 16 C2 8046 - 1039 = 7007 C1 /C3 = 37 C3 3473 - 470 = 3003 C1 /C4 = 84 Oil C4 1591 - 270 = 1321 C1 /C5 = 196 — - 1111 . C5 726 - 164 = 562 NPH Production 1 Analysis nGas nOil nWater nNon- Producible Hydrocarbons - J % Hydrocarbon Ratios I Depth 13607 ft Gas Units 1289 Mud Chlorides (1000's) : 40 C1 C1 C1 C1 • Flowline Background Show C2 C3 C4 C5 ppm ppm ppm Hydrocarbon Ratios 1000.0 I C1 108816 - 16524 = 92292 C1 /C2 = 15 C2 7160 1039 = 6121 C1 /C3 = 34 C3 3176 470 = 2706 C1 /C4 = 87 NPH C4 1328 - 270 = 1058 C1 /C5 = 224 I C5 Production 576 164 = 412 100.0 Analysis nGas nOil nWater nNon- Producible Hydrocarbons _ J Il% I Depth 13610 ft Gas LxJUnits 1245 Mud Chlorides (1000's) 40 Gas ........ Flowline Background Show PPm PPm ppm - - - -___ Hydrocarbon Ratios 10.0 I C1 99449 - 16524 = 82925 C1 /C2 = 15 C2 6630 1039 = 5591 C1 /C3 = 33 oil C3 2975 - 470 = 2505 C1 /C4 = 72 C4 1416 - 270 = 1146 C1 /C5 = 164 I C5 670 - 164 = 506 NPH Production 1.0 Analysis nGas Moil nWater nNon - Producible Hydrocarbons 1 1 1 1 ALLIESUFITCMI Well Name: ODSN -45A Depth (MD) 13764 to 13812 ft I Location: North Slope, Alaska (TVD) 5034 to 5029 ft Show Reports Operator: Pioneer Natural Resources Show Report No. 4 Report Prepared By: Danny Kane Date/Time: 19- Oct -09 Report Delivered To: I Interpretation: Ratios slightly steeper and higher due to chromatograph "gas as air analysis from gas trap at possum belly rather than "gas in mud" as designed and would fall within the oil range, sloping into the lower gas range. Samples went from Siltstone to a very fine I to fine grained, poorly consolidated Sandstone during show interval. Samples had a yellow -gold and a very good streaming bright yellow - white cut fluorescence as well as a visible oil cut. High 28ohmm resistivity along w/ samples suggest presence of a light oil. Jj % Hydrocarbon Ratios Depth 13775 ft Gas �x Units 1473 Mud Chlorides (1000's) 42 C1 C1 C1 01 I Flowline Background Show C2 C3 C4 C5 ppm ppm ppm Hydrocarbon Ratios 1000 - I 01 134256 - 10712 = 123544 C1/02 = 17 C2 7839 - 536 = 7303 C1/03 = 35 C3 3729 - 214 = 3515 C1 /C4 = 100 C4 1351 - 121 = 1230 C1 /05 = 263 NPH 1 550 - 80 = 470 _ _ _ _ Production 100 � ( Analysis nGas f1 naer non- ouce yo _ --- J % - - I Depth 13780 ft Gas x Units 1666 Mud Chlorides (1000's) : 42 Gas _ _ ..... — Flowline Background Show • PPm PPm PPm Hydrocarbon Ratios 10 — ' 01 147270 10712 = 136558 01 /02 = C2 8747 536 = 17 8211 C1/03 = 40 C3 3658 - 214 = 3444 01/04 = 101 Oil C4 1478 - 121 = 1357 C1/05 = 264 I C5 Production 597 - 80 = 517 NPH • 1 Analysis nGas f1Oil nWater n Non- Producible Hydrocarbons °A Hydrocarbon Ratios Depth 13782 ft Gas �x Units 1643 Mud Chlorides (1000's) 42 C1 C1 C1 C1 I Flowline Background Show C2 C3 C4 C5 ppm ppm ppm Hydrocarbon Ratios 1000.0 I C1 143232 - 10712 = 132520 C1/02 = 16 C2 8674 - 536 = 8138 C1/03 = 39 C3 3614 214 = 3400 C1/04 = 98 NPH C4 1473 - 121 = 1352 01/05 = 258 I C5 594 - 80 = 514 -- — _ _ _ Production 100.0 Analysis nGas f1 Oil nWater nNon- Producible Hydrocarbons � _ I Depth 13802 ft Gas x Units 1616 Mud Chlorides (1000's) 42 Gas ........ _ ..-------. •-• — • Flowline Background Show PPm ppm ppm Hydrocarbon Ratios 10.0 I 01 128991 - 10712 = 118279 C1/02 = C2 7173 - 536 = 6637 01/03 = Oil C3 2824 - 214 = 2610 C1/04 = i C4 1099 - 121 = 978 01/05 = -- -- - - - - -- I C5 445 - 80 = 365 NPH Production 1.0 Analysis © Gas II Oil I Water I Non - Producible Hydrocarbons 1 I 1w BE i MI I NE M M- M I MN w- M- MI UN r ODSN -45A Morraine Interpolated Tops tlfarlaRr f • se im AZ Tif0 TVDSS SECT N (S) E filill X Y =Me BR/160 DC Rf CL AZ. Top West Sak 2343.0 30.6 196.8 2279.7 2223.5 -156.5 -412.6 16.3 469836.5 6030592.9 6.21 5.43 0.01844 1.00003 412.9 357.7 Tuffaceous Shale 3311.0 60.8 209.7 2914.8 2858.6 -76.9 - 1051.8 -301.0 469516.7 6029955.1 1.89 1.86 0.02690 1.00006 1094.0 180.0 SCP 4973.0 71.5 218.2 3438.4 3382.2 337.6 - 2334.4 - 1209.0 468603.7 6028676.2 0.32 0.16 0.00234 1.00000 2628.9 180.0 Brook 2B 7583.0 71.8 214.7 4236.1 4179.9 939.5 - 4392.7 - 2598.6 467205.9 6026623.8 0.50 0.20 0.00089 1.00000 5103.8 180.0 Black 1 Fault 8462.0 71.8 214.2 4502.3 4446.1 1149.3 - 5083.0 - 3073.1 466728.7 6025935.4 1.45 -1.24 0.00929 1.00001 5939.8 180.0 Torok Top 10036.0 71.0 231.8 4996.6 4940.4 1593.5 - 6265.9 - 3976.4 465820.8 6024756.3 3.96 -0.07 0.00040 1.00000 7421.1 180.0 TOW 10050.0 71.0 232.4 5001.1 4944.9 1600.5 - 6274.0 - 3986.8 465810.3 6024748.2 0.00 #DIV /0! 0.00000 1.00000 7433.6 180.0 BOW 10061.0 73.7 233.4 5004.5 4948.3 1606.2 - 6280.4 - 3995.2 465801.9 6024741.9 26.65 25.04 0.05117 1.00022 7443.4 180.0 Top Mid Torok - Down 1 10660.0 80.0 276.7 5092.4 5036.2 2074.7 - 6438.1 - 4551.2 465245.3 6024586.3 6.69 -0.82 0.01633 1.00002 7884.4 180.0 Top Lower Torok - Down 1 10894.0 81.4 290.9 5133.8 5077.6 2303.3 - 6381.7 - 4773.8 465022.9 6024643.7 5.88 2.91 0.05693 1.00027 7969.6 180.0 T1 11325.0 89.0 317.8 5173.5 5117.3 2714.6 - 6143.2 - 5124.8 464672.9 6024883.6 5.74 5.05 0.04988 1.00021 8000.2 180.0 Invert #1 11344.5 90.0 318.4 5173.7 5117.5 2731.8 - 6128.7 - 5137.8 464660.0 6024898.1 0.00 #DIV /0! 0.00000 1.00000 7997.4 180.0 Revert #1 11694.3 90.0 320.2 5169.0 5112.8 3036.0 - 5862.5 - 5364.6 464434.3 6025165.2 0.79 -0.77 0.00878 1.00001 7946.6 180.0 Invert #2 12090.5 90.0 322.7 5171.4 5115.2 3375.8 - 5554.9 - 5614.3 464185.9 6025473.8 1.44 0.84 0.01860 1.00003 7897.9 180.0 T2 12230.0 91.3 322.0 5170.3 5114.1 3493.3 - 5444.1 - 5699.0 464101.6 6025584.9 3.60 3.33 0.01284 1.00001 7881.4 180.0 Fault #1 20' DTSE 12550.0 95.4 319.8 5144.7 5088.5 3768.0 - 5198.0 - 5901.8 463899.9 6025831.8 0.65 0.01 0.00589 1.00000 7864.5 180.0 Fault #2 20' DTSE 12890.0 95.5 320.1 5112.2 5056.0 4060.9 -4938.4 - 6119.0 463683.7 6026092.2 0.63 -0.63 0.00061 1.00000 7863.2 180.0 Top Lower Torok - Up 1 13380.0 94.8 320.2 5068.4 5012.2 4481.0 - 4561.4 - 6428.8 463375.4 6026470.5 2.21 -0.82 0.00479 1.00000 7882.6 180.0 Top Mid Torok - Up 1 13810.0 95.2 318.8 5029.5 4973.3 4856.8 -4240.0 - 6711.8 463093.8 6026792.9 1.96 -1.91 0.01926 1.00003 7938.9 180.0 T3 14069.0 90.3 319.5 5016.4 4960.2 5082.1 -4043.6 - 6880.0 462926.4 6026989.9 0.37 0.33 0.00172 1.00000 7980.3 180.0 Fault or fracture zone 14700.0 90.9 320.0 5001.3 4945.1 5631.5 - 3564.6 - 7290.3 462518.0 6027470.6 1.76 -1.59 0.02407 1.00005 8115.1 180.0 Revert #2 15011.6 90.0 320.7 5000.6 4944.4 5897.6 - 3321.3 - 7484.9 462324.4 6027714.7 2.72 -2.70 0.00214 1.00000 8188.7 180.0 T4 - TD 15429.0 87.3 320.0 5018.3 4962.1 6257.6 - 3000.4 - 7751.3 462059.4 6028036.5 0.00 0.00 0.00000 1.00000 8311.7 180.0 1 1 1 1 Well Planning - Pioneer - Oooguruk Oooguruk Development 1 Oooguruk Drill Site ODSN -45A Permit to Drill: 2090790 API: 507032057701 1 Sperry Drilling Services P �/ 9 1 Definitive Survey Report 03 November, 2009 1 1 1 1 1 ' HALLIBURTON Sperry Drilling Services 1 1 Halliburton Company I Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -45A - Slot ODS -45 I ProJect: Oooguruk Development TVD Reference: 42.7' + 13.5 © 56.20ft (Nabors 19 AC) CO Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference: True Wellbore: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db I Project Oooguruk Development Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level I Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well ODSN -45A - Slot ODS-45 I Well Position +N / -S +E/-W 0.00 ft Northing: Easting: 6,031,005.53 ft Latitude: Longitude: 70° 29' 44.804 N 0.00 ft 469,821.86 ft 150° 14' 48.349 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 13.50ft I Wellbore ODSN -45A Magnetics Model Name Sample Date Declination Dip Angle Field Strength I ( °) (°) (nT) IGRF200510 10/2/2009 22.10 80.81 57,749 Design ODSN -45A I Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 10,035.40 I Vertical Section: Depth From (TVD) +N/-S +E�r///-W Direction (ft) (•t) ( 42.70 0.00 0.00 290.00 I Survey Program Date 11/3/2009 From To (ft) (ft) Survey (Wellbore) Tool Name Description Survey Date I 50.00 533.00 ODSN -45i 1N13 PB1 Gyro (ODSN -45i IN SR- Gyro -SS Fixed:v2:surface readout gyro single shot 1/13/2009 1: 533.00 10,035.40 ODSN -45i IN13 PB1 MWD (ODSN -45i I1' MWD +IFR2 +MS +sag Fixed:v2:IIFR dec & 3 -axis correction + sag 1/13/2009 1: 10,049.98 10,191.98 ODSN -45A Gyro (ODSN -45A) NS- Gyro -MS Fixed:v2:North- seeking gyro multishot 10/3/2009 1: 10,259.91 15,393.08 ODSN -45A MWD (ODSN -45A) MWD +IFR2 +MS +sag Fixed:v2:IIFR dec & 3 -axis correction + sag 10/4/2009 1: 1 Survey I Map Map Vertical MD Inc Azi TVD TVDSS +N /-S +E/ -W Northing Easting DLS Section (ft) ( °) (1 (ft) (ft) (ft) (ft) (ft) (ft) ( °1100') (ft) Survey Tool Name 42.70 0.00 0.00 42.70 -13.50 0.00 0.00 6,031,005.53 469,821.86 0.00 0.00 UNDEFINED 50.00 0.30 141.13 50.00 -6.20 -0.01 0.01 6,031,005.52 469,821.87 4.11 -0.02 SR- Gyro -SS (1) 100.00 0.30 191.03 100.00 43.80 0.25 0.07 6,031,005.28 469,821.93 0.51 -0.15 SR- Gyro -SS (1) 168.00 0.50 165.94 168.00 111.80 -0.71 0.11 6,031,004.82 469,821.96 0.38 -0.34 SR- Gyro-SS (1) I 197.00 0.48 148.51 197.00 140.80 -0.93 0.20 6,031,004.60 469,822.06 0.52 -0.51 SR- Gyro -SS (1) 228.00 0.59 198.76 228.00 171.80 -1.20 0.22 6,031,004.33 469,822.07 1.50 -0.61 SR- Gyro-SS (1) 258.00 0.58 166.67 257.99 201.79 -1.49 0.20 6,031,004.04 469,822.06 1.08 -0.70 SR- Gyro-SS (1) I 288.00 0.68 167.36 287.99 231.79 0.28 6,031,003.72 469,822.13 0.33 -0.88 SR- Gyro -SS (1) 321.00 0.98 173.11 320.99 264.79 -2.28 0.35 6,031,003.25 469,822.20 0.94 -1.11 SR- Gyro-SS (1) 351.00 1.08 175.74 350.98 294.78 -2.82 0.41 6,031,002.71 469,822.25 0.37 -1.35 SR- Gyro -SS (1) III 382.00 1.32 178.28 381.98 325.78 -3.47 0.44 6,031,002.06 469,822.28 0.79 -1.60 SR- Gyro-SS (1) 11/372009 2 :48 :59PM Page 2 COMPASS 2003.16 Build 71 MEM Halliburton Company P Y Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -45A - Slot ODS -45 I 42.7' + 13.5 56.20ft Nabors 19 AC Oooguruk Develop ment TVD Reference: ( ) Project: g Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 © 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference: True Welibore: ODSN -45A Survey Calculation Method: Minimum Curvature I Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical I MD Inc Azi TVD TVDSS +NI-S +E/ -W Northing Easting DLS Section (ft) ( °) ( °) () (ft) (ft) (R) (ft) (ft) ( °1100') (ft) Survey Tool Name 413.00 1.75 179.15 412.96 356.77 -4.30 0.46 6,031,001.23 469,822.30 1.39 -1.90 SR- Gyro-SS (1) 443.00 2.13 178.74 442.95 386.75 -5.31 0.47 6,031,000.22 469,822.31 1.27 -2.26 SR- Gyro -SS (1) I 533.00 2.88 180.19 532.86 476.66 -9.25 0.50 6,030,996.28 469,822.33 0.84 -3.64 SR- Gyro -SS (1) 575.40 2.94 174.16 575.21 519.01 -11.39 0.61 6,030,994.14 469,822.42 0.74 -4.47 MWD +IFR2 +MS +sag (2) 670.40 3.91 162.96 670.04 613.84 -16.91 1.81 6,030,988.61 469,823.60 1.24 -7.48 MWD +IFR2 +MS +sag (2) I 764.70 5.03 162.67 764.05 707.85 -23.93 3.98 6,030,981.58 469,825.74 1.19 -11.93 MWD +IFR2 +MS +sag (2) 859.30 5.77 161.44 858.23 802.03 -32.40 6.73 6,030,973.10 469,828.46 0.79 -17.41 MWD +IFR2 +MS +sag (2) 954.90 5.70 160.56 953.35 897.15 -41.43 9.84 6,030,964.06 469,831.53 0.12 -23.42 MWD +IFR2 +MS +sag (2) I 1,049.20 7.62 163.09 1,047.01 990.81 -51.83 13.22 6,030,953.65 469,834.87 2.06 -30.15 MWD +IFR2 +MS +sag (2) 1,143.50 8.56 164.80 1,140.37 1,084.17 -64.59 16.88 6,030,940.88 469,838.47 1.03 -37.95 MWD +IFR2 +MS +sag (2) 1,238.70 9.80 165.71 1,234.35 1,178.15 -79.28 20.73 6,030,926.18 469,842.27 1.31 -46.60 MWD +IFR2 +MS +sag (2) I 1,334.70 11.30 167.74 1,328.72 1,272.52 96.39 24.75 6,030,909.05 469,846.21 1.61 -56.22 MWD +IFR2 +MS +sag (2) 1,428.60 13.21 170.21 1,420.48 1,364.28 115.95 28.53 6,030,889.48 469,849.91 2.11 -66.46 MWD +IFR2 +MS +sag (2) 1,523.55 12.76 171.01 1,513.00 1,456.80 - 137.00 32.01 6,030,868.42 469,853.31 0.51 -76.94 MWD +IFR2 +MS +sag (2) I 1,618.50 13.98 172.54 1,605.37 1,549.17 1,712.90 14.83 172.59 1,696.81 1,640.61 -158.73 35.14 6,030,846.68 469,856.35 1.34 -87.31 MWD +IFR2 +MS +sag (2) -182.01 38.18 6,030,823.38 469,859.29 0.90 -98.13 MWD +IFR2 +MS +sag (2) 1,808.20 16.36 172.06 1,788.59 1,732.39 - 207.40 41.60 6,030,797.98 469,862.62 1.61 - 110.03 MWD +IFR2 +MS +sag (2) I 1,902.60 18.07 178.03 1,878.77 1,822.57 43.94 6,030,770.17 469,864.84 2.60 - 121.74 MWD +IFR2 +MS +sag (2) 1,999.40 21.10 181.35 1,969.96 1,913.76 267.64 44.05 6,030,737.74 469,864.82 3.33 - 132.93 MWD +IFR2 +MS +sag (2) 2,093.80 24.37 188.46 2,057.03 2,000.83 - 303.91 40.78 6,030,701.49 469,861.40 4.52 - 142.26 MWD +IFR2 +MS +sag (2) I 2,187.50 25.30 191.15 2,142.07 2,085.87 - 342.67 34.07 6,030,662.76 469,854.53 1.56 - 149.21 MWD +IFR2 +MS +sag (2) 2,282.30 28.06 195.13 2,226.77 2,170.57 384.08 24.33 6,030,621.39 469,844.62 3.47 - 154.22 MWD +IFR2 +MS +sag (2) 2,326.00 29.70 195.74 2,265.04 2,208.84 - 404.43 18.71 6,030,601.07 469,838.92 3.81 - 155.90 MWD +IFR2 +MS +sag (2) 2,377.20 32.48 198.82 2,308.88 2,252.68 - 429.65 10.83 6,030,575.88 469,830.94 6.25 - 157.13 MWD +IFR2 +MS +sag (2) I 2,424.00 34.60 199.84 2,347.89 2,291.69 - 454.05 2.26 6,030,551.52 469,822.28 4.69 - 157.42 MWD +IFR2 +MS +sag (2) 2,472.50 36.16 200.43 2,387.43 2,331.23 - 480.41 -7.40 6,030,525.20 469,812.51 3.29 - 157.35 MWD +IFR2 +MS +sag (2) 2,566.59 39.82 202.47 2,461.58 2,405.38 - 534.29 -28.62 6,030,471.41 469,791.08 4.11 - 155.85 MWD +IFR2 +MS +sag (2) I 2,659.39 43.52 202.62 2,530.89 2,474.69 - 591.26 -52.27 6,030,414.55 469,767.19 3.99 - 153.10 MWD +IFR2 +MS +sag (2) 2,698.99 44.79 203.91 2,559.30 2,503.10 616.60 -63.17 6,030,389.25 469,756.19 3.93 - 151.53 MWD +IFR2 +MS +sag (2) 2,752.29 48.34 205.85 2,595.94 2,539.74 - 651.69 -79.47 6,030,354.23 469,739.76 7.17 - 148.22 MWD +IFR2 +MS +sag (2) I 2,805.09 49.84 207.14 2,630.52 2,574.32 -97.27 6,030,318.60 469,721.81 3.39 - 143.70 MWD +IFR2 +MS +sag (2) 2,848.99 51.64 207.46 2,658.30 2,602.10 717.61 - 112.86 6,030,288.46 469,706.10 4.14 - 139.38 MWD +IFR2 +MS +sag (2) 2,943.19 53.16 207.96 2,715.77 2,659.57 - 783.68 - 147.57 6,030,222.54 469,671.13 1.67 - 129.36 MWD +IFR2 +MS +sag (2) I 3,040.19 55.15 209.57 2,772.57 2,716.37 - 852.59 - 185.41 6,030,153.79 469,633.00 2.45 - 117.37 MWD +IFR2 +MS +sag (2) 3,133.79 57.80 210.63 2,824.27 2,768.07 920.08 - 224.55 6,030,086.46 469,593.60 2.98 - 103.68 MWD +IFR2 +MS +sag (2) 3,229.59 59.33 210.06 2,874.23 2,818.03 - 990.62 - 265.84 6,030,016.09 469,552.02 1.68 -89.00 MWD +IFR2 +MS +sag (2) I 3,323.39 61.07 209.65 2,920.84 2,864.64 - 1,061.21 3,417.39 64.24 210.67 2,964.02 2,907.82 -1,133.39 -306.36 6,029,945.67 469,511.23 1.89 -75.07 MWD +IFR2 +MS +sag (2) - 348.31 6,029,873.68 469,468.99 3.51 -60.34 MWD +IFR2 +MS +sag (2) 3,465.29 65.89 210.86 2,984.21 2,928.01 - 1,170.71 - 370.53 6,029,836.45 469,446.62 3.46 -52.22 MWD +IFR2 +MS +sag (2) I 3,512.29 69.49 210.64 3,002.05 2,945.85 - 1,208.07 -392.76 6,029,799.18 469,424.24 7.67 -44.12 MWD +IFR2 +MS +sag (2) 11/312009 2:48:59PM Page 3 COMPASS 2003.16 Build 71 MN 1 Halliburton Company P Y Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -45A - Slot ODS-45 I Project: Oooguruk Development TVD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 © 56.20ft (Nabors 19 AC) Well: ODSN-45A North Reference: True Wellbore: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db I Survey Map Map Vertical I MD Inc Azi TVD TVDSS +NiS +e-W Northing Easting DLS Section (ft) ( °) ( °) (ft) (ft) (ft) (ft) (ft) (ft) ( °1100') (ft) Survey Tool Name 3,559.99 71.29 209.81 3,018.06 2,961.86 - 1,246.90 - 415.37 6,029,760.45 469,401.47 4.11 -36.14 MWD +IFR2 +MS +sag (2) I 3,607.69 73.43 210.51 3,032.51 2,976.31 - 1,286.20 - 438.21 6,029,721.25 469,378.48 4.70 -28.12 MWD +IFR2 +MS +sag (2) 3,700.79 73.49 209.15 3,059.02 3,002.82 - 1,363.62 - 482.60 6,029,644.02 469,333.77 1.40 -12.89 MWD +IFR2 +MS +sag (2) 3,797.59 75.67 213.26 3,084.76 3,028.56 - 1,443.40 - 530.95 6,029,564.44 469,285.11 4.67 5.26 MWD +IFR2 +MS +sag (2) 3,892.09 75.67 212.88 3,108.15 3,051.95 - 1,520.13 - 580.91 6,029,487.92 469,234.84 0.39 25.96 MWD +IFR2 +MS +sag (2) I 3,986.89 74.92 215.00 3,132.22 3,076.02 - 1,596.19 - 632.10 6,029,412.07 469,183.35 2.30 48.05 MWD +IFR2 +MS +sag (2) 4,081.09 74.82 216.86 3,156.81 3,100.61 - 1,669.82 -685.46 6,029,338.67 469,129.70 1.91 73.01 MWD +IFR2 +MS +sag (2) 4,175.99 73.20 216.32 3,182.95 3,126.75 - 1,743.07 - 739.84 6,029,265.65 469,075.03 1.79 99.05 MWD +IFR2 +MS +sag (2) I 4,268.49 72.50 218.38 3,210.23 3,154.03 - 1,813.33 - 793.45 6,029,195.62 469,021.13 2.26 125.41 MWD +IFR2 +MS +sag (2) 4,365.09 71.06 219.72 3,240.43 3,184.23 - 1,884.59 - 851.25 6,029,124.60 468,963.05 1.99 155.35 MWD +IFR2 +MS +sag (2) 4,458.59 70.94 218.34 3,270.87 3,214.67 - 1,953.26 - 906.92 6,029,056.16 468,907.10 1.40 184.18 MWD +IFR2 +MS +sag (2) I 4,554.79 70.77 219.77 3,302.43 3,246.23 - 2,023.83 - 964.18 6,028,985.83 468,849.57 1.42 213.84 MWD +IFR2 +MS +sag (2) 4,648.49 71.10 218.30 3,333.03 3,276.83 - 2,092.62 - 1,019.95 6,028,917.28 468,793.52 1.52 242.73 MWD +IFR2 +MS +sag (2) 4,744.59 71.00 217.70 3,364.24 3,308.04 - 2,164.24 - 1,075.91 6,028,845.89 468,737.28 0.60 270.81 MWD +IFR2 +MS +sag (2) I 4,839.59 70.69 218.10 3,395.41 3,339.21 - 2,235.05 - 1,131.04 6,028,775.31 468,681.87 0.51 298.39 MWD +IFR2 +MS +sag (2) 4,931.39 71.44 218.07 3,425.20 3,369.00 - 2,303.40 - 1,184.60 6,028,707.19 468,628.04 0.82 325.35 MWD +IFR2 +MS +sag (2) 5,012.77 71.57 218.31 3,451.02 3,394.82 - 2,364.05 - 1,232.31 6,028,646.73 468,580.08 0.32 349.44 MWD +IFR2 +MS +sag (2) I 5,105.27 70.97 217.33 3,480.72 3,424.52 - 2,433.25 - 1,286.03 6,028,577.76 468,526.09 1.19 376.25 MWD +IFR2 +MS +sag (2) 5,202.47 70.78 216.37 3,512.57 3,456.37 - 2,506.74 - 1,341.10 6,028,504.50 468,470.72 0.95 402.87 MWD +IFR2 +MS +sag (2) 5,292.26 71.43 216.16 3,541.64 3,485.44 - 2,575.23 - 1,391.35 6,028,436.22 468,420.20 0.76 426.66 MWD +IFR2 +MS +sag (2) I 5,393.87 72.60 214.62 3,573.02 3,516.82 - 2,654.02 - 1,447.32 6,028,357.67 468,363.92 1.84 452.31 MWD +IFR2 +MS +sag (2) 5,489.91 72.80 213.99 3,601.58 3,545.38 - 2,729.76 - 1,499.00 6,028,282.14 468,311.94 0.66 474.96 MWD +IFR2 +MS +sag (2) 5,577.52 72.79 214.00 3,627.49 3,571.29 - 2,799.15 - 1,545.79 6,028,212.96 468,264.87 0.02 495.20 MWD +IFR2 +MS +sag (2) 5,673.74 72.92 213.93 3,655.86 3,599.66 - 2,875.41 - 1,597.16 6,028,136.92 468,213.20 0.15 517.39 MWD +IFR2 +MS +sag (2) I 5,773.16 72.72 211.84 3,685.23 3,629.03 - 2,955.16 - 1,648.73 6,028,057.38 468,161.31 2.02 538.57 MWD +IFR2 +MS +sag (2) 5,868.29 72.53 210.72 3,713.63 3,657.43 - 3,032.75 - 1,695.87 6,027,979.99 468,113.87 1.14 556.33 MWD +IFR2 +MS +sag (2) 5,962.54 72.20 211.00 3,742.19 3,685.99 - 3,109.86 - 1,741.94 6,027,903.08 468,067.48 0.45 573.25 MWD +IFR2 +MS +sag (2) I 6,057.34 72.53 212.72 3,770.91 3,714.71 - 3,186.59 - 1,789.62 6,027,826.55 468,019.49 1.76 591.82 MWD +IFR2 +MS +sag (2) 6,151.53 72.92 211.27 3,798.88 3,742.68 - 3,262.86 - 1,837.28 6,027,750.47 467,971.53 1.53 610.51 MWD +IFR2 +MS +sag (2) 6,247.50 72.48 211.27 3,827.42 3,771.22 - 3,341.18 - 1,884.84 6,027,672.36 467,923.66 0.46 628.42 MWD +IFR2 +MS +sag (2) I 6,340.48 72.26 212.99 3,855.58 3,799.38 - 3,416.22 - 1,931.96 6,027,597.52 467,876.24 1.78 647.04 MWD +IFR2 +MS +sag (2) 6,434.78 72.46 211.57 3,884.16 3,827.96 - 3,492.19 - 1,979.96 6,027,521.75 467,827.94 1.45 666.15 MWD +IFR2 +MS +sag (2) 6,529.17 72.54 211.31 3,912.54 3,856.34 - 3,569.00 - 2,026.91 6,027,445.14 467,780.68 0.28 684.00 MWD +IFR2 +MS +sag (2) I 6,623.98 72.35 212.08 3,941.14 3,884.94 - 3,645.91 - 2,074.40 6,027,368.43 467,732.88 0.80 702.33 MWD +IFR2 +MS +sag (2) 6,720.34 71.83 213.74 3,970.78 3,914.58 - 3,722.88 - 2,124.22 6,027,291.67 467,682.76 1.73 722.81 MWD +IFR2 +MS +sag (2) 6,814.39 71.76 214.87 4,000.16 3,943.96 - 3,796.68 - 2,174.57 6,027,218.08 467,632.11 1.14 744.88 MWD +IFR2 +MS +sag (2) I 6,908.91 71.70 215.49 4,029.79 3,973.59 - 3,870.05 - 2,226.28 6,027,144.94 467,580.11 0.63 768.39 MWD +IFR2 +MS +sag (2) 7,004.56 71.68 215.84 4,059.84 4,003.64 - 3,943.82 - 2,279.22 6,027,071.38 467,526.87 0.35 792.90 MWD +IFR2 +MS +sag (2) 7,100.29 72.01 215.80 4,089.67 4,033.47 - 4,017.58 - 2,332.46 6,026,997.85 467,473.34 0.35 817.70 MWD +IFR2 +MS +sag (2) I 7,193.34 72.53 215.54 4,118.01 4,061.81 - 4,089.58 - 2,384.14 6,026,926.07 467,421.37 0.62 841.64 MWD +IFR2 +MS +sag (2) 11/3/2009 2:48:59PM Page 4 COMPASS 2003.16 Build 71 1 Halliburton Company P Y Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co-ordinate Reference: Well ODSN -45A - Slot ODS -45 Project: Oooguruk Development TVD Reference: 42.7' + 13.5 @ 56.20ft (Nabors 19 AC) I Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 © 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference: True Wel!bore: ODSN -45A Survey Calculation Method: Minimum Curvature I Design: ODSN -45A Database: EDM 2003.16 Single User Db Survey Map Map Vertical I MD Inc Azi TVD TVDSS +14I-S +E/ -W Northing Easting DLS Section (ft) ( °) ( °) (ft) (ft) (ft) (ft) (ft) (ft) ( °1100') (ft) Survey Tool Name 7,288.68 72.40 215.89 4,146.73 4,090.53 - 4,163.39 - 2,437.21 6,026,852.48 467,368.01 0.38 866.26 MWD +IFR2 +MS +sag (2) 7,382.88 72.80 215.45 4,174.90 4,118.70 - 4,236.42 - 2,489.63 6,026,779.67 467,315.30 0.62 890.54 MWD +IFR2 +MS +sag (2) I 7,477.84 72.16 214.78 4,203.49 4,147.29 - 4,310.49 - 2,541.71 6,026,705.82 467,262.92 0.95 914.16 MWD +IFR2 +MS +sag (2) 7,572.90 71.77 214.65 4,232.92 4,176.72 - 4,384.80 - 2,593.20 6,026,631.73 467,211.14 0.43 937.12 MWD +IFR2 +MS +sag (2) 7,667.48 71.96 215.11 4,262.36 4,206.16 - 4,458.53 - 2,644.60 6,026,558.21 467,159.45 0.50 960.20 MWD +IFR2 +MS +sag (2) I 7,758.38 72.02 214.91 4,290.46 4,234.26 - 4,529.34 - 2,694.19 6,026,487.62 467,109.57 0.22 982.59 MWD +IFR2 +MS +sag (2) 7,857.09 72.14 214.91 4,320.84 4,264.64 - 4,606.36 - 2,747.94 6,026,410.82 467,055.51 0.12 1,006.75 MWD +IFR2 +MS +sag (2) 7,951.52 72.13 214.87 4,349.80 4,293.60 - 4,680.08 - 2,799.35 6,026,337.32 467,003.81 0.04 1,029.85 MWD +IFR2 +MS +sag (2) I 8,047.26 72.73 214.89 4,378.70 4,322.50 - 4,754.95 - 2,851.55 6,026,262.66 466,951.32 0.63 1,053.29 MWD +IFR2 +MS +sag (2) 8,142.02 72.86 213.92 4,406.73 4,350.53 - 4,829.64 - 2,902.69 6,026,188.19 466,899.87 0.99 1,075.81 MWD +IFR2 +MS +sag (2) 8,235.56 72.73 214.08 4,434.40 4,378.20 - 4,903.71 - 2,952.66 6,026,114.33 466,849.61 0.21 1,097.42 MWD +IFR2 +MS +sag (2) I 8,330.90 72.86 213.75 4,462.60 4,406.40 - 4,979.29 - 3,003.47 6,026,038.96 466,798.50 0.36 1,119.32 MWD +IFR2 +MS +sag (2) 8,425.38 72.21 213.89 4,490.96 4,434.76 - 5,054.17 - 3,053.64 6,025,964.30 466,748.04 0.70 1,140.85 MWD +IFR2 +MS +sag (2) 8,520.57 71.03 214.65 4,520.97 4,464.77 - 5,128.82 - 3,104.50 6,025,889.86 466,696.87 1.45 1,163.12 MWD +IFR2 +MS +sag (2) I 8,614.82 70.45 215.43 4,552.06 4,495.86 - 5,201.67 - 3,155.58 6,025,817.23 466,645.50 0.99 1,186.20 MWD +IFR2 +MS +sag (2) 8,707.23 70.97 215.11 4,582.59 4,526.39 - 5,272.88 - 3,205.95 6,025,746.23 466,594.85 0.65 1,209.17 MWD +IFR2 +MS +sag (2) 8,802.23 71.56 214.91 4,613.10 4,556.90 - 5,346.56 - 3,257.56 6,025,672.76 466,542.94 0.65 1,232.47 MWD +IFR2 +MS +sag (2) I 8,897.27 71.76 215.01 4,643.01 4,586.81 - 5,420.50 - 3,309.25 6,025,599.05 466,490.96 0.23 1,255.76 MW0+1FR2 +MS +sag (2) 8,992.31 71.70 215.37 4,672.80 4,616.60 - 5,494.25 - 3,361.26 6,025,525.51 466,438.65 0.37 1,279.41 MWD +IFR2 +MS +sag (2) 9,087.70 72.40 214.07 4,702.20 4,646.00 - 5,568.84 - 3,412.95 6,025,451.14 466,386.67 1.49 1,302.46 MWD +IFR2 +MS +sag (2) I 9,182.27 72.66 214.32 4,730.59 4,674.39 - 5,643.45 - 3,463.64 6,025,376.74 466,335.68 0.37 1,324.58 MWD +IFR2 +MS +sag (2) 9,276.95 72.27 212.54 4,759.12 4,702.92 - 5,718.79 - 3,513.38 6,025,301.61 466,285.64 1.84 1,345.55 MWD +IFR2 +MS +sag (2) 9,371.44 71.83 212.53 4,788.24 4,732.04 - 5,794.58 - 3,561.72 6,025,226.03 466,237.00 0.47 1,365.06 MWD +IFR2 +MS +sag (2) 9,466.39 71.88 213.38 4,817.81 4,761.61 - 5,870.29 - 3,610.81 6,025,150.53 466,187.61 0.85 1,385.29 MWD +IFR2 +MS +sag (2) I 9,561.41 71.43 216.75 4,847.72 4,791.52 - 5,944.10 - 3,662.61 6,025,076.94 466,135.52 3.40 1,408.73 MWD +IFR2 +MS +sag (2) 9,656.14 70.96 220.58 4,878.27 4,822.07 - 6,014.10 - 3,718.62 6,025,007.17 466,079.23 3.86 1,437.41 MWD +IFR2 +MS +sag (2) 9,750.60 72.00 222.51 4,908.28 4,852.08 - 6,081.13 - 3,778.02 6,024,940.39 466,019.56 2.23 1,470.31 MWD +IFR2 +MS +sag (2) I 9,845.48 72.39 225.50 4,937.29 4,881.10 - 6,146.09 - 3,840.77 6,024,875.69 465,956.55 3.03 1,507.05 MWD +IFR2 +MS +sag (2) 9,940.31 72.08 228.44 4,966.23 4,910.03 - 6,207.71 - 3,906.77 6,024,814.34 465,890.31 2.97 1,548.00 MWD +IFR2 +MS +sag (2) 10,035.40 70.98 231.76 4,996.37 4,940.17 - 6,265.56 - 3,975.95 6,024,756.78 465,820.90 3.51 1,593.22 MWD +IFR2 +MS +sag (2) I 10,049.98 70.97 232.37 5,001.12 4,944.92 - 6,274.04 - 3,986.82 6,024,748.35 465,810.00 3.96 1,600.54 NS- Gyro-MS (3) 10,104.98 84.74 237.65 5,012.67 4,956.47 - 6,304.73 - 4,030.78 6,024,717.84 465,765.92 26.73 1,631.35 NS- Gyro-MS (3) 10,191.98 84.62 241.67 5,020.74 4,964.54 - 6,348.48 - 4,105.53 6,024,674.40 465,691.00 4.60 1,686.63 NS- Gyro -MS (3) I 10,259.91 84.25 246.20 5,027.33 4,971.13 - 6,378.18 - 4,166.25 6,024,644.95 465,630.17 6.66 1,733.53 MWD +IFR2 +MS +sag (4) 10,306.57 83.51 248.83 5,032.31 4,976.11 - 6,395.92 - 4,209.11 6,024,627.38 465,587.24 5.82 1,767.73 MWD +IFR2 +MS +sag (4) 10,356.69 82.24 252.28 5,038.53 4,982.33 - 6,412.47 - 4,256.00 6,024,611.02 465,540.29 7.29 1,806.13 MWD +IFR2 +MS +sag (4) I 10,402.89 80.50 256.64 5,045.46 4,989.26 - 6,424.71 - 4,299.99 6,024,598.96 465,496.25 10.06 1,843.29 MWD +IFR2 +MS +sag (4) 10,452.16 79.12 261.21 5,054.18 4,997.98 - 6,434.03 - 4,347.56 6,024,589.84 465,448.64 9.55 1,884.81 MWD +IFR2 +MS +sag (4) 10,499.52 78.81 264.76 5,063.25 5,007.05 - 6,439.71 - 4,393.69 6,024,584.35 465,402.50 7.39 1,926.21 MWD +IFR2 +MS +sag (4) I 10,549.42 79.15 268.20 5,072.79 5,016.59 - 6,442.71 - 4,442.57 6,024,581.54 465,353.61 6.80 1,971.11 MWD +IFR2 +MS +sag (4) 11/3/2009 2:48:59PM Page 5 COMPASS 2003.16 Build 71 1 Halliburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -45A - Slot ODS -45 I Project: Oooguruk Development TVD Reference: 42.7' + 13.5 © 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 © 56.20ft (Nabors 19 AC) Well: ODSN -45A North Reference: True Welibore: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db I Survey Map Map Vertical I MD Inc Azi TVD TVDSS +N /S +EI -W Northing Easting DLS Section (ft) ( °) ( °) (ft) (ft) (ft) (ft) (ft) (ft) ( °1100') (ft) Survey Tool Name 10,596.90 79.90 271.70 5,081.43 5,025.23 - 6,442.75 - 4,489.25 6,024,581.69 465,306.94 7.42 2,014.97 MWD +IFR2 +MS +sag (4) 10,646.00 80.10 275.72 5,089.95 5,033.75 - 6,439.62 - 4,537.49 6,024,585.02 465,258.71 8.07 2,061.37 MWD +IFR2 +MS +sag (4) I 10,692.11 79.72 278.83 5,098.03 5,041.83 - 6,433.87 - 4,582.52 6,024,590.95 465,213.71 6.69 2,105.64 MWD +IFR2 +MS +sag (4) 10,741.83 79.16 282.40 5,107.15 5,050.95 - 6,424.87 - 4,630.55 6,024,600.14 465,165.72 7.15 2,153.86 MWD +IFR2 +MS +sag (4) 10,838.48 79.83 288.06 5,124.78 5,068.58 - 6,399.92 - 4,722.20 6,024,625.47 465,074.18 5.80 2,248.52 MWD +IFR2 +MS +sag (4) I 10,935.46 82.65 293.08 5,139.56 5,083.36 - 6,366.24 - 4,811.90 6,024,659.51 464,984.64 5.88 2,344.32 MWD +IFR2 +MS +sag (4) 11,032.19 84.12 298.09 5,150.71 5,094.51 - 6,324.75 - 4,898.53 6,024,701.34 464,898.18 5.36 2,439.92 MWD +IFR2 +MS +sag (4) 11,127.72 85.25 304.59 5,159.57 5,103.37 - 6,275.30 - 4,979.72 6,024,751.11 464,817.20 6.88 2,533.12 MWD +IFR2 +MS +sag (4) I 11,224.34 85.01 312.68 5,167.79 5,111.59 - 6,215.25 - 5,054.86 6,024,811.47 464,742.31 8.35 2,624.27 MWD +IFR2 +MS +sag (4) 11,275.22 86.50 316.47 5,171.55 5,115.35 - 6,179.64 - 5,090.99 6,024,847.22 464,706.33 7.98 2,670.41 MWD +IFR2 +MS +sag (4) 11,344.46 90.00 318.36 5,173.67 5,117.47 - 6,128.70 - 5,137.81 6,024,898.35 464,659.72 5.74 2,731.83 MWD +IFR2 +MS +sag (4) I 11,440.98 91.24 320.71 5,172.62 5,116.42 - 6,055.28 - 5,200.44 6,024,972.01 464,597.39 2.75 2,815.79 MWD +IFR2 +MS +sag (4) 11,478.97 91.23 320.47 5,171.80 5,115.60 - 6,025.93 - 5,224.56 6,025,001.45 464,573.40 0.63 2,848.49 MWD +IFR2 +MS +sag (4) 11,532.05 91.17 317.88 5,170.69 5,114.49 - 5,985.78 - 5,259.25 6,025,041.74 464,538.88 4.88 2,894.82 MWD +IFR2 +MS +sag (4) I 11,630.25 90.49 320.13 5,169.27 5,113.07 - 5,911.67 - 5,323.66 6,025,116.10 464,474.78 2.39 2,980.69 MWD +IFR2 +MS +sag (4) 11,726.86 89.75 320.30 5,169.07 5,112.87 - 5,837.43 - 5,385.48 6,025,190.58 464,413.27 0.79 3,064.17 MWD +IFR2 +MS +sag (4) 11,823.02 90.56 320.56 5,168.81 5,112.61 - 5,763.31 - 5,446.73 6,025,264.95 464,352.32 0.88 3,147.09 MWD +IFR2 +MS +sag (4) I 11,920.83 88.76 320.36 5,169.39 5,113.19 - 5,687.88 - 5,508.99 6,025,340.62 464,290.37 1.85 3,231.39 MWD +IFR2 +MS +sag (4) 12,016.50 89.38 321.88 5,170.94 5,114.74 - 5,613.42 - 5,569.04 6,025,415.32 464,230.63 1.72 3,313.28 MWD +IFR2 +MS +sag (4) 12,113.06 90.19 323.01 5,171.30 5,115.10 - 5,536.87 - 5,627.89 6,025,492.09 464,172.10 1.44 3,394.76 MWD +IFR2 +MS +sag (4) I 12,209.55 90.62 322.25 5,170.62 5,114.42 - 5,460.19 - 5,686.45 6,025,569.01 464,113.85 0.90 3,476.02 MWD +IFR2 +MS +sag (4) 12,304.26 93.77 320.94 5,166.99 5,110.79 - 5,386.04 - 5,745.24 6,025,643.39 464,055.38 3.60 3,556.62 MWD +IFR2 +MS +sag (4) 12,401.69 95.69 320.55 5,158.96 5,102.76 - 5,310.86 - 5,806.67 6,025,718.81 463,994.25 2.01 3,640.07 MWD +IFR2 +MS +sag (4) 12,498.15 95.43 319.48 5,149.61 5,093.41 - 5,237.30 - 5,868.36 6,025,792.62 463,932.86 1.14 3,723.20 MWD +IFR2 +MS +sag (4) I 12,594.55 95.44 320.11 5,140.48 5,084.28 - 5,164.00 - 5,930.32 6,025,866.16 463,871.21 0.65 3,806.49 MWD +IFR2 +MS +sag (4) 12,691.27 95.12 319.87 5,131.58 5,075.38 - 5,090.23 - 5,992.24 6,025,940.17 463,809.60 0.41 3,889.90 MWD +IFR2 +MS +sag (4) 12,788.04 95.87 320.32 5,122.32 5,066.12 - 5,016.34 - 6,054.03 6,026,014.30 463,748.11 0.90 3,973.24 MWD +IFR2 +MS +sag (4) I 12,884.40 95.55 320.07 5,112.73 5,056.53 - 4,942.68 - 6,115.41 6,026,088.20 463,687.04 0.42 4,056.11 MWD +IFR2 +MS +sag (4) W 12,980.93 94.94 320.09 5,103.90 5,047.70 - 4,868.96 - 6,177.10 6,026,162.17 463,625.66 0.63 4,139.29 MD +IFR2 +MS +sag (4) W 13,080.50 95.69 321.17 5,094.68 5,038.48 - 4,792.32 - 6,239.99 6,026,239.06 463,563.09 1.32 4,224.60 MD +IFR2 +MS +sag (4) 1 13,173.65 94.63 320.42 5,086.30 5,030.10 - 4,720.43 - 6,298.63 6,026,311.17 463,504.75 1.39 4,304.29 MWD +IFR2 +MS +sag (4) 13,271.18 95.19 321.05 5,077.96 5,021.76 - 4,645.20 - 6,360.13 6,026,386.65 463,443.56 0.86 4,387.81 MWD +IFR2 +MS +sag (4) 13,367.56 94.93 320.41 5,069.45 5,013.25 - 4,570.87 - 6,420.89 6,026,461.21 463,383.10 0.71 4,470.34 MWD +IFR2 +MS +sag (4) I 13,463.74 94.14 318.43 5,061.85 5,005.65 - 4,498.06 - 6,483.26 6,026,534.27 463,321.03 2.21 4,553.85 MWD +IFR2 +MS +sag (4) 13,560.24 95.25 317.88 5,053.95 4,997.75 - 4,426.41 - 6,547.42 6,026,606.17 463,257.17 1.28 4,638.64 MWD +IFR2 +MS +sag (4) 13,657.42 95.43 318.94 5,044.91 4,988.71 - 4,354.05 - 6,611.65 6,026,678.79 463,193.25 1.10 4,723.74 MWD +IFR2 +MS +sag (4) I 13,753.72 96.24 318.56 5,035.12 4,978.92 - 4,282.02 - 6,674.81 6,026,751.06 463,130.38 0.93 4,807.73 MWD +IFR2 +MS +sag (4) 13,848.13 94.44 319.00 5,026.33 4,970.13 - 4,211.32 - 6,736.75 6,026,822.01 463,068.74 1.96 4,890.12 MWD +IFR2 +MS +sag (4) 13,945.88 93.46 319.70 5,019.60 4,963.40 - 4,137.33 - 6,800.28 6,026,896.24 463,005.52 1.23 4,975.12 MWD +IFR2 +MS +sag (4) L 14,042.44 90.24 319.55 5,016.48 4,960.28 - 4,063.82 - 6,862.79 6,026,970.00 462,943.31 3.34 5,059.00 MWD +IFR2 +MS +sag (4) 11/3/2009 2:48:59PM Page 6 COMPASS 2003.16 Build 71 1 1 Halliburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -45A - Slot ODS-45 1 Project: Oooguruk Development TVD Reference: 42.7 + 13.5 © 56.20ft (Nabors 19 AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5 © 56.2Oft (Nabors 19 AC) Well: ODSN -45A North Reference: True Welibore: ODSN -45A Survey Calculation Method: Minimum Curvature Design: ODSN -45A Database: EDM 2003.16 Single User Db I Survey Map Map Vertical I MD (ft) Inc Azi TVD TVDSS +N /-S +0-W Northing Easting DLS Section ( °) ( °) (ft) (ft) (ft) (ft) (ft) (ft) MOO') (ft) Survey Tool Name 14,138.64 90.56 319.39 5,015.81 4,959.61 - 3,990.70 - 6,925.30 6,027,043.37 462,881.10 0.37 5,142.75 MWD +IFR2 +MS +sag (4) 14,235.40 90.25 319.05 5,015.12 4,958.92 - 3,917.44 - 6,988.50 6,027,116.88 462,818.21 0.48 5,227.20 MWD +IFR2 +MS +sag (4) I 14,331.88 91.49 319.22 5,013.66 4,957.46 - 3,844.48 - 7,051.61 6,027,190.08 462,755.40 1.30 5,311.46 MWD +IFR2 +MS +sag (4) 14,428.93 92.23 319.66 5,010.51 4,954.31 - 3,770.79 - 7,114.68 6,027,264.02 462,692.63 0.89 5,395.93 MWD +IFR2 +MS +sag (4) 14,525.20 92.10 319.53 5,006.87 4,950.67 - 3,697.54 - 7,177.04 6,027,337.52 462,630.58 0.19 5,479.58 MWD +IFR2 +MS +sag (4) I 14,621.70 92.10 319.40 5,003.34 4,947.14 - 3,624.25 - 7,239.72 6,027,411.06 462,568.21 0.13 5,563.54 MWD +IFR2 +MS +sag (4) 14,715.37 90.61 320.11 5,001.12 4,944.92 - 3,552.77 - 7,300.21 6,027,482.77 462,508.01 1.76 5,644.84 MWD +IFR2 +MS +sag (4) 14,813.48 89.01 321.39 5,001.45 4,945.25 - 3,476.80 - 7,362.28 6,027,558.99 462,446.25 2.09 5,729.15 MWD +IFR2 +MS +sag (4) I 14,909.63 90.93 322.51 5,001.50 4,945.30 - 3,401.09 - 7,421.54 6,027,634.93 462,387.31 2.31 5,810.73 MWD +IFR2 +MS +sag (4) 15,007.07 90.12 320.67 5,000.60 4,944.40 - 3,324.74 - 7,482.07 6,027,711.51 462,327.09 2.06 5,893.72 MWD +IFR2 +MS +sag (4) 15,103.49 87.52 320.30 5,002.59 4,946.39 - 3,250.38 - 7,543.41 6,027,786.12 462,266.07 2.72 5,976.79 MWD +IFR2 +MS +sag (4) I 15,200.31 87.16 320.06 5,007.08 4,950.88 - 3,176.10 - 7,605.34 6,027,860.64 462,204.44 0.45 6,060.39 MWD +IFR2 +MS +sag (4) 15,296.62 87.10 320.66 5,011.91 4,955.71 - 3,102.03 - 7,666.70 6,027,934.96 462,143.39 0.63 6,143.39 MWD +IFR2 +MS +sag (4) 15,393.08 87.28 319.99 5,016.63 4,960.43 - 3,027.88 - 7,728.21 6,028,009.35 462,082.18 0.72 6,226.55 MWD +IFR2 +MS +sag (4) 1 15,428.97 87.28 319.99 5,018.34 4,962.14 - 3,000.42 - 7,751.26 6,028,036.90 462,059.25 0.00 6,257.60 PROJECTED to TD 1 1 1 1 1 1 1 1 11/3/2009 2:48:59PM Page 7 COMPASS 2003.16 Build 71 1 ■ Oooguruk ODSN -45A 1 Days -vs- Depth 1 10000 I , Prognosed 1 1 e j ■ • (Low ROP) 1 Y -- i BitTrip 10124' MD/5014' TVD i . i I I I Off Bot: 19:21 10- Oct -09 I Mill Window in 7 5/8 Intermediate Casing 11000 10050 MD /5001' I VIA 1 On Bot: 06:57 12-Oct-09 On Bot: 01:22 10-Oct-09 Bit Trip (Low ROP) ■ Move Rig 11515' MD/5171' TVD Over OQSN -45i . Off Bot: 20:02 16- Oct -09 Completion String On Bot: 22:16 17- Oct -09' Remove Com p 9' Reenter Well 05- Oct -09 I Reached T1 Target v . -111 12000 Trip for RSS BHA ............................1 - -- - - -- 11325' MD/5173' TVD ,, 1- 1■ 1 Off Bot: 02:56 14-Oct-09 06:33 16- Oct -09 in On Bot: 06 1 I ■■ ■ 1 a III ■ P I O N E E R ,ATURAL RESOURCES 13000 CD kh. ■ o . -■ ■■-_ . . ' CD ■■ 1111■■■ L 1 N ■■111111111■ ■■■■ as � 1 11111.►11 TD 6 1/8" HoleSection C 14000 ' C 11 15429 MD/501'8.3 TVD Off Bot: 10.15 21- Oct -09 ■1 __ 11 ■ ■ 111■ 41 , . 1 i III Mt , - 1 5000 — — . 1 1 ■ ■_ ■■► . //1 ME II i 1 , III 1 1 I 16000 11 ■■ 111 ._111111_ ■ ■■ ■1■ ■11■ ■ • ■■■ 1 17000 – ' 1 __ ■■■ 0 5 10 15 20 25 30 ■ Rig Days
