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208-157
• 208157 29390 CE CAELLS LETTER OF TRANSMITTAL Energy Alaska RECEIVED JUN 2 0 2018 AOGCC DATE: June 18, 2018 FROM: TO: Shannon Koh AOGCC Caelus Energy Alaska Attn: Makana Bender 3700 Centerpoint Dr., Suite 500 333 W. 7th Avenue, Suite 100 Anchorage, AK 99503 Anchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter I I Maps CD-R I I Other Agreement DETAIL QTY DESCRIPTION ODSN-37 (50-703-20586-0000) 1 CD Memory TEMP-GRCCL on CD-Rom (CD contains DLIS, LAS, PDF) SCANNED JUN 2 510a Received by: Date: 04/*CIE— Cpiease sign and return one copy to: Caelus Energy Alaska ATTN: Shannon Koh 3700 Centerpoint Dr., Suite 500, Anchorage, AK 99503 907-343-2193 fax 907-343-2128 phone shannon.koh(c�caelusenergy.com • • 208157 29390 e CAE-1_1J S LETTER OF TRANSMITTAL 1,rv. f Alaska RECEIVED JUN 2 0 2018 AOGCC DATE: June 18, 2018 FROM: TO: Shannon Koh AOGCC Caelus Energy Alaska Attn: Makana Bender 3700 Centerpoint Dr., Suite 500 333 W. 7th Avenue, Suite 100 Anchorage, AK 99503 Anchorage, AK 99501 INFORMATION TRANSMITTED Letter I I Maps CD-R I I Other ❑ Agreement DETAIL QTY DESCRIPTION ODSN-37 (50-703-20586-0000) 1 CD Memory TEMP-GRCCL on CD-Rom (CD contains DLIS, LAS, PDF) SCANNED JUN 252016 Date. 06/X/WReceived bY ''"-ase sign and return one copy to: Caelus Energy Alaska ATTN: Shannon Koh 3700 Centerpoint Dr., Suite 500, Anchorage, AK 99503 907-343-2193 fax 907-343-2128 phone shannon.koha,caelusenergy.com IP RECE1 ED STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS APR 1 0 2018 1.Operations Abandon U Plug Perforations U Fracture Stimulate U Pull Tubing U .'.w U Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other:Scale Squeeze w/CTU 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Caelus Natural Resources Alaska,LLC Development U Exploratory ❑ 208-157 3.Address: 3700 Centerpoint Drive,Suite 500 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-703-20586-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 355036 ODSN-37 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Oooguruk- Nuiqsut Oil Pool 11.Present Well Condition Summary: Total Depth measured 14,295 feet Plugs measured N/A feet true vertical 6,302 feet Junk measured N/A feet Effective Depth measured 14,283 feet Packer measured See attached,pg.3 feet true vertical 6,287 feet true vertical See attached,pg.3 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 115' 16" 158' 158' N/A N/A Surface 3,109' 9-5/8" 3,150' 3,012' 5,750 psi 3,090 psi Intermediate 7,725' 7" 7,764' 6,319' 7,240 psi 5,410 psi Production Liner 6,702' 4-1/2" 14,283' 6,287' 8,430 psi 7,500 psi Perforation depth Measured depth See attached, pg.2 feet True Vertical depth See attached,pg.2fee feet Tubing(size,grade,measured and true vertical depth) 2-7/8",6.4# L-80,IBT-M 7,601'MD 6,281'TVD Packers and SSSV(type,measured and true vertical depth) See attached,pg.3 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A L .. 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: 382 61 0 931 445 Subsequent to operation: 379 113 0 866 362 14.Attachments(required per 20 AAC 25.070,25.071,&25283) 15.Well Class after work: Daily Report of Well Operations U Exploratory ❑ Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil U Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ 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: 318-040 Authorized Name: Rami Jasser Contact Name: Rami Jasser Authorized Title: Senior S •.f ompletion Engineer Contact Email: rami.iasser@caelusenergv.com Authorized Signature: / "4 Date: ii'L-18 Contact Phone: 907-343-2182 Form 10-404 Revised 4/2017 RB `� �" APR 1 ZQ� Submit Original Only 41- 1—,S • • Attachment 2 AOGCC Form 10-404 Sundry Report Box 11 - Perforation Locations Well: ODSN-37 Top(MD) Top(TVD) 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 7,766 6,320 4-Y2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 7,892 6,345 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 8,060 6,368 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 8,186 6,378 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 8,311 6,382 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 8,516 6,384 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 8,718 6,381 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 8,920 6,373 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 9,130 6,373 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 9,340 6,374 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 9,550 6,370 4-Y2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 9,758 6,356 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 10,011 6,335 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 10,139 6,328 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 10,348 6,320 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 10,553 6,317 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 10,755 6,317 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 10,958 6,313 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 11,165 6,312 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 11,363 6,312 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 11,564 6,320 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 11,765 6,333 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 11,966 6,350 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 12,088 6,358 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 12,295 6,364 4-'A", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 12,498 6,362 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 12,700 6,358 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 12,906 6,353 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 13,112 6,342 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 13,315 6,323 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 13,443 6,310 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 13,647 6,298 4-%2", 12.6#, L-80 Liner- perforated pup jts with 6-1/2" holes 13,851 6,294 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 14,063 6,290 4-%2", 12.64, L-80 Liner- perforated pup jts with 6-1/2" holes 14,233 6,288 • Attachment 3 AOGCC Form 10-404 Sundry Report Box 11 - Packers & SSSV Well: ODSN-37 SSSV MD TVD 2-7/8" HES "NE" TRSV 2,096 2,056 PACKERS 2-7/8" x 7" 4762 'F' Packer 6,600 5,934 WFT"NTH" Liner Top Packer 7,597 6,281 • Operations Summary Report - State W Well Name: ODSN-37 CE CAELL k ant r:9y=Alaska 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 3/12/2018 3/13/2018 14,295.0 00:00 3/12/18-00:00 3/13/18(Scale Squeeze) *Completed well handover from Ops to wells.Shut in well. LRS freeze protected tubing w/18 bbls of diesel.(3000') *GE installed 3"secondary gate valve and SLB BOP stack. (WC barriers=TRSV&5k Gate valve) *SLB crew&LRS layed herculite in front of ODSN-28. *SLB staged 1.75"reel utilizing 275 ton crane.(88k). *SLB staged Ops cab,tool trailer, BOP stack,coil pump.Rig up high pressure kelly hose from test header to 212 bbl tank. *Rig up 3"water supply line from RSC to SLB coil pump. *Rig up all 2"1502 hardline from reel to pump to P-sub. *Hook up all electrical cables and transducers for job monitoring. *Stab coiled tubing into the injector head. *Spot cement guideline blocks on north side of well bays. 3/13/2018 3/14/2018 14,295.0 00:00 3/13/18-00:00 3/14/18 (Scale Squeeze) *Make up the Gamma Ray,CCL and Temp log BHA. *RIH with 1.75-Coiled Tubing w/Gamma ray,CCL and Temp log from 13,076'ctm to 6.500' ctm. *Run back in the hole to 13,110'ctm to begin the scale squeeze. *Reach 13,110'ctm. Pump stage from 13,110'ctm to 12,500'ctm while laying in 4 bbl pre-flush and 30 bbl main treatment. Pump 150 bbl over flush while sitting at 13,110'ctm. *Pump stage 2 from 12,500'to 11,000'while laying in,pump the 4 bbl pre-flush,30 bbl main treatment and 150 bbl over flush. *Pump stage 3 from 11,000 to 9,500'while laying in,pump the 4 bbl pre-flush,30 bbl main treatment and 150 bbl over flush. *Pump stage 4 from 9,500'to 7,000'while laying in,pump the 4 bbl pre-flush,30 bbl main treatment and 150 bbl over flush. *Freeze protect the Coiled Tubing with 50 bbls of diesel while POOH. *Pump 20 bbls of diesel down the TBG x Coil Annuli to free up ice plug in tubing @ 1,070'ctm. *23:55 pm.In lubricator w/BHA.Bullhead 10 bbls of diesel down tubing. Page 1/1 Report Printed: 4/6/2018 lie • ODSN-37 Nuiqsut Production Well Completion Final 2015-01-05 N3 Upper Completion Eauioment pllDlftl TVOIkI •ii 16"Conductor 1 Vetco Gray Tubing Hanger 34 34 ;iii' c::i 2 2-7/8"6.4#L-80 IBT-M Tubing EK E'3 2096 2056 iiii2-718"HES'NTRSV w/2.313"X"Profile 15'Pup BxP Top&Bottom-Control line I to surface 4 2-7/8"6.48 L-80 IBT-M Tubing 3 iiiii 5 2-7/8"x 1"GLM#2,KBMG w/BK-5 Latch-11'Pup BxP Top&Bottom 2158 2114 6 2-7/8"6.4#L-80 IBT-M Tubing 5 7 HES"X"Nipple 2.313"9 Chr w/15'Pup BxP Top&Bottom 2223 2174 GLM#2 i GI_ 8 2-7/8"6.4#L-80 IBT-M Tubing DV iiiiii 9 2-7/8"x 1"GLM#1,KBMG w/BK-5 Latch-11'Pup BxP Top&Bottom 6538 5899 10 2-7/8"6.4#L-80 IBT-M Tubing 11 2-7/8"x 7"47B2'FH'Packer w/11'Pup Top&Bottom-30k shear to release 6600 5934 °•0" O 1213 22-7/ .7/88"6.4#6.5#L-809CrIBT-M Tubing " 'CMU'Sliding Sleeve w/2.312""BX"Profile-13'Pup Top&Bottom 6663 5968 41111 ''i 14 2-7/8"6.4#L-80 IBT-M Tubing 9 5/8"40#L 80 15 HES XN 2.313'w/15'Pup BxP Top&Bottom 6721 5997 16 2-7/8"6.48 L-80187-M Tubing BTC Surface Casing 17 3-1/2"Mule Shoe TC-Il Box 7569 6274 @ 3,150'MD/3,012'TVD Bottom of Mule Shoe 7601 6281 fs Lower Completion Eauiament MD(ftl TVD(ft) 18 WFT PBR Tie Back Sleeve 15ft SN#23682673-01 7581 6277 19 WFT"NTH"Liner Top Pkr 7596 6281 20 WFT"PHR"Rotating Hyd Set Liner Hanger 7597 6281 21 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 7766 6320 22 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 7892 6345 23 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 8060 6368 24 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 8186 6378 25 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 8311 6382 26 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 8516 6384 27 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 8718 6381 28 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 8920 6373 29 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 9130 6373 30 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 9340 6374 31 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 9550 6370 GLM#1 GL JO 32 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 9758 6356 5/16"OV 33 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 10011 6335 34 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 10139 6328 35 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 10348 6320 36 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 10553 6317 37 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 10756 6317 38 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 10958 6313 E g 11 4-1/2" 12.60#L-80 39 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 11165 6312 Sliding QQQ 13 y g Hydril Tubing 40 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 11363 6312 41 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 11564 6320 Sleeve (Lower Completion) 42 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 11765 6333 Closed 43 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 11966 6350 0 44 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 12088 6358 45 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 12295 6364 46 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 12498 6362 47 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 12700 6358 48 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 12906 6353 49 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13112 6342 50 4-1/2"12.60#L-80 Hydril Pupjt Oft(Ported w/61/2 holes) 13315 6323 51 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 13443 6310 ` 52 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13647 6298 7"26#L-80 BTC-M 53 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 13851 6294 •.. 54 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 14063 6290 iiii / ii Intermediate Casing 55 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 14233 6288 @ 7,764' MD/6,319'TVD 56 Ray Oil Tool Silver Bullet Float Shoe(PLUGGED)w/4-1/21BT 14281 6287 1 \ End of Assembly 14283 6287 \ \ ®,®'®,g 0 o oo 00o00 D0 00 00 D0 00 00 00 00 00 D0 00 00 D0 o0 00 I 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 �I 0 _ I 6-1/8"Hole TD at at 14,295'MD/6302'TVD • yw,I%%,v THE STAT Alaska Oil and Gas ���'►' �, ®ALASKA Conservation Commission _- 333 West Seventh Avenue - GOVERNOR BILL WALKER , ., ,.. Anchorage, Alaska 99501-3572 OF ALAS�� Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Rami Jasser Senior Staff Completion Engineer ��-� 2016 Caelus Natural Resources.Alaska, LLC 3700 Centerpoint Drive, Suite 500 Anchorage, AK 99503 Re: Oooguruk Field,Nuiqsut Oil Pool, ODSN-37 Permit to Drill Number: 208-157 Sundry Number: 318-040 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, ICE62 Hollis S. French -t( Chair DATED this ICj day of February, 2018. RE DSNJ L —F_r' - 7 2018 • "� / RECEIVED 2'Q\ JAN 3 0 2018 STATE OF ALASKA n/� ALASKA OIL AND GAS CONSERVATION COMMISSION A OGCC APPLICATION FOR SUNDRY APPROVALS /"'► 20 MC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown El Suspend ❑ Perforate El Other Stimulate ❑ Pull Tubing ❑ Change Approved Program 0 Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other:Scale Squeeze 0 2.Operator Name: Caelus Natural Resources Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number. Li/ C r Exploratory ❑ Development 0, 208-157 ' 3.Address: 3700 Centerpoint Drive,Suite 500 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,AK 99503 50-703-20586-00-00 ' 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A - ODSN-37 r Will planned perforations require a spacing exception? Yes ❑ No 0/ 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 355036 ' Oooguruk-Nuiqsut 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): 14,295' 6,287' ' 14,283' - 6,287' N 1,400 psi N/A N/A Casing Length Size MD ND Burst Collapse Structural Conductor 115' 16" 158' 158' N/A N/A Surface 3,109' 9-5/8" 3,150' 3,012' 5,750 psi 3,090 psi Intermediate 7,725' 7" 7,764' 6,319' 7,240 psi 5,410 psi Production Liner 6,702' 4-1/2" 14,283' 6,223' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See attached,pg.2 I See attached,pg.2 2-7/8",6.4# L-80,IBT-M 7,601' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): NE TRSV;FH Pkr;NTH Liner Top Pkr 2,096'MD/2,056'TVD;6,600'MD/5,934'TVD;7,596'MD/6,281'TVD 12.Attachments: Proposal Summary ❑ Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory El Stratigraphic ❑ Development 0 ' Service ❑ 14.Estimated Date for � 15.Well Status after proposed work: tv Commencing Operations: 1r`r' .CN .245 20(8 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 herein will not be deviated from without prior written approval. Authorized Name: Rami Jasser s. Contact Name: Rami Jasser Authorized Title: Senior S • +impletion Engineer Contact Email: rami.iasserecaeluserteray.com ,/ A Contact Phone: 907-343-2182 Authorized Signature: L' Date: il/O f l(ii COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. /�(�j� 313 - V /V Plug Integrity ❑ BOP Test,?.., Mechanical Integrity Test ❑ Location Clearance ❑ Other: REDPAS t (-- FE1.3 - 7 2018 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: /0 —L/ oil APPROVED BY Approved by: L-Lf. — COMMISSIONER THE COMMISSION Date: 2-16116 ItAh i/3///s' A 4i10, 21: _ -5--1 e nForm 10-403 Revised 4/2017 Approved applicatioQRIGJ rodate of approval. Attachments in Duplicate • Ca cAE-Lus Energy Alaska Caelus Natural Resources Alaska,LLC 3700 Centerpoint Drive,Anchorage,AK 99503 Tel:(907)277-2700 Fax:(907)343-2190 January 29, 2018 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite #100 Anchorage, AK 99501 RE: ODSN-37 Sundry Application for Scale Squeeze Treatment REF: Approved Permit to Drill #208-157 Caelus Natural Resources Alaska, LLC. (CNRA) hereby submits an Application for Sundry to perform a Scale Squeeze Treatment across the production lateral. The treatment is requested as a preventative measure, with no current water cut while on production.• Please see the proposed plan attachment and supporting documentation. Sincerely, ii Rami Jass r Senior Staff Completion Engineer Attachments: Form 10-403 Supporting information cc: ODSN-37 Well File • Caelus Natual Resources Alaska, LLC ODSN-37 Page 2 AOGCC Form 10-403, Sundry Application Present Well Condition Summary, Box #11 Perforation Depth (MD/TVD) - Attachment 4-W, 12.6#, L-80 Liner - perforated pup jts with 6-1/2" holes @ depths listed: MD TVD 7766' — 7771' 6320' — 6321' 7892' — 7897' 6345' — 6345' 8060' — 8065' 6368' — 6368' 8186' — 8191' 6378' — 6378' 8311' — 8316' 6382' — 6382' 8516' — 8521' 6384' — 6384' 8718' — 8723' 6381' — 6381' 8920' — 8925' 6373' — 6373' 9130' — 9135' 6373' — 6373' 9340' — 9345' 6374' — 6374' 9550' — 9555' 6370' — 6370' 9758' — 9763' 6356' — 6355' 10011' — 10016' 6335' — 6335' 10139' — 10144' 6328' — 6328' 10348' — 10353' 6320' — 6320' 10553' — 10558' 6317' — 6318' 10755' - 10761' 6317' - 6316' 10958' — 10963' 6313' — 6313' 11165' — 11170' 6312' — 6312' 11363' — 11368' 6312' — 6313' 11564' — 11569' 6320' — 6320' 11765' — 11770' 6333' — 6334' 11966' — 11971' 6350' — 6351' 12088' — 12093' 6358' — 6358' 12295' — 12300' 6364' — 6364' 12498' — 12503' 6362' — 6361' 12700' — 12705' 6358' — 6357' 12906' — 12911' 6353' — 6352' 13112' — 13118' 6342' — 6341' 13315' — 13320' 6323' — 6323' 13443' — 13448' 6310' — 6309' 13647' — 13852' 6298' — 6294' 13851' — 13856' 6294' — 6294' 14063' — 14068' 6290' — 6290' 14233' — 14238' 6288' — 6288' • Oooguruk Wells Group • cAELLs -no! Alaska ODSN-37 Coil Tubing — Scale Squeeze Treatment 1-30-2018 Version 1 Prepared: Date: Rami Jasser Completions Engineer Reviewed: Date: Keith Lopez Production Engineer ODSN-37 Coil Tubing Scale Squeeze Treatment—version 1 (1/30/2018) • Oooguruk Wells Group • Objective: ODSN-37 sustained production at 460 BOPD with no water cut recorded while on production, decision has been made to utilize Coil Tubing during the ice road season to lay scale treatment evenly across the production lateral as a preventative measure. Scale Squeeze Design: Baker Petrolite recommends the following scale squeeze design and operational procedure to protect ODSN-37 from barium sulfate and calcium carbonate precipitation: • 16 barrel pre-flush containing 50% WAW5206 o 330 gallons WAW5206 & 8 barrels seawater • 121 barrel main treatment containing 13% SCW4004 o 660 gallons SCW4004 & 105 barrels seawater • 600 est. barrel seawater formation over-displacement (0.5 ft. OD). • 12 hour shut in • Use recommended maximum injection pressures and rates. • Please be aware that SCW4004 is not compatible with methanol. • Obtain QA/QC concentration samples during job. Slickline: 1 . Coordinate with Operations to shut in well. 2. Record WH, IA, and OA pressures. Shoot and record fluid levels on Tubing, IA, and OA. If the OA is bled, measure and record H2S level. Send results to Anchorage team. 3. Complete handover from Operations to Wells. 4. Conduct pre-job safety meeting with Wells Group Supervisor, Operations, and all service companies involved in the job scope. 5. MIRU HES Slick-line. Pick up lubricator, tool string, and 2.35" gauge. 6. Pressure test PCE as per HES policy and procedure. 7. RIH w/ 2.35" gauge ring to XXO TRSV @ 2,096' MD while holding 5,000 psi max on the TRSV control line to hold flapper open. 8. Drift w/ 2' of weight bar, and 2.35" gauge ring to XN nipple @ 6,721' MD. 9. RDMO HES Slickline. 10.Prepare to rig up coil tubing unit. ODSN-37 Coil Tubing Scale Squeeze Treatment—version 1 (1/30/2018) • Oooguruk Wells Group • p Coiled Tubing Gamma Ray / CCL / Temp Loq: ? V' • The objective of running the Gamma Ray/ CCL Log to identify the source of water. 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. 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 Site Supervisor and the Coiled Tubing Unit Supervisor should agree to contingencies to follow in the event of a tubing failure during operations. 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. Consider site control measures during the cleanout operations 6. Ensure that the IA is shut-in and both IA & OA pressures are monitored throughout the job. NOTE: Ensure that IA is always higher pressure than the OA (maintain a 500 psi differential). 7. Ensure that all tanks and lines are clean and all fluids filtered before entering the CT pump. 8. Rig up Schlumberger (SLB) 2" 1502 hardline from the manifold on the swivel joint side of the coiled tubing reel. NOTE: Ensure the Micro Motion (MM) is calibrated with water and will record in both direction of flow. 9. Conduct HSE walk through with Schlumberger's CTU supervisor and CEA Well Site Supervisor. 10.Conduct BOP pressure test using Diesel. Re: Schlumberger's Seven Day BOP Test Guidelines and Procedure for CTS Operations date 10/31/11. Also pressure test all associated equipment Release pressure and un-stab. 11.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. 12.Make-up (MU) BHA.Install roll-on Coiled Tubing Connector (CTC) (refer to SLB SOP's on CTC installation) and pull test to 10k. Both the CTU and Well Site Supervisor must pre-approve the BHA. 13.Make-up (MU) BHA, Install the 1-11/16" Gamma Ray Logging BHA. ODSN-37 Coil Tubing Scale Squeeze Treatment—version 1 (1/30/2018) Oooguruk Wells Group S 14.AlI BHA items run in the hole dimensions will be measured and posted by Well Site Supervisor and CTU Supervisor in the Op's Cab. 15.Pick up the required lubricator and stab on well. Line up and pressure test the BOP body to 250/4000 psi. :Line up to diesel out of SLB pumps truck. Pressure up on the lubricator to equal the Well Head Pressure (WHP) and open the lower FV, count and record turns. Open the upper FV slowly and count and record turns. NOTE: Open bottom valve first and with low pressure differential between wellbore and lubricator, open top FV slowly to reduce any possible erosion of bottom FV gate. 16.RIH not pumping (dry) to 3,500ft MD. 17.Pump friction reducer at 1 BPM running at coil speed of 50 fpm until reach coil lockup depth. 18.RIH at the SLB Coiled Tubing Memory Gamma Ray Tool and follow Schlumberger running procedure per tool specialist. NOTE: If unable to reach a desired deepest depth consult with the Anchorage team and discuss plan forward. 19.POOH while logging at recommended logging parameters as per SLB Memory. 20.Once on surface download and notify the Caelus Energy LLC team on logging results for a plan forward. Scale Squeeze Treatment: 1 . Make-up (MU) BHA, Install a Jet Swirl BHA. 2. All BHA items run in the hole dimensions will be measured and posted by Well Site Supervisor and CTU Supervisor in the Op's Cab. 3. Pick up the required lubricator and stab on well. Line up and pressure test the BOP body to 250/4000 psi. Line up to diesel out of SLB pumps truck. Pressure up on the lubricator to equal the Well Head Pressure (WHP) and open the lower FV, count and record turns. Open the upper FV slowly and count and record turns. NOTE: Open bottom valve first and with low pressure differential between wellbore and lubricator, open top FV slowly to reduce any possible erosion of bottom FV gate. 4. RIH not pumping (dry) as deep as possible. ODSN-37 Coil Tubing Scale Squeeze Treatment—version 1 (1/30/2018) • Oooguruk Wells Group • 5. Begin laying in the treatment as per the table below: Down Coil Back Side Coil Zone (MD) ft. Fluid Type Volume (bbl.) Pump Rate Pump Rate (BPM) Max Depth Pre-Flush 4 Scale Squeeze 30 Over Flush 150 11000 — 12500 Pre-Flush 4 0.25 BPM Scale Squeeze 30 Max Rate While pumping Over Flush 150 not to exceed 2,000 psi down coil 9500 — 11000 Pre-Flush 4 tubing 30 coil x tubing Scale Squeeze annulus WHP simultaneously Over Flush 150 7000 — 9500 Pre-Flush 4 Scale Squeeze 30 Over Flush 150 6. POOH to surface. 7. RDMO SLB Coiled Tubing. 8. Allow a minimum of 12 hours shut-in time for treatment. ODSN-37 Coil Tubing Scale Squeeze Treatment—version 1 (1/30/2018) • Oooguruk Wells Group • Fluff and Stuff Contingency: 1 . Make-up (MU) BHA.Install roll-on Coiled Tubing Connector (CTC) (refer to SLB SOP's on CTC installation) and pull test to 10k. Both the CTU and Well Site Supervisor must pre-approve the nozzle selection. 2. All BHA items run in the hole dimensions will be measured and posted by Well Site Supervisor and CTU Supervisor in the Op's Cab. 3. Pick up the required lubricator and stab on well. Line up and pressure test the BOP body to 250/4000 psi. Line up to diesel out of SLB pumps truck. Pressure up on the lubricator to equal the Well Head Pressure (WHP) and open the lower FV, count and record turns. Open the upper FV slowly and count and record turns. NOTE: OPEN BOTTOM VALVE FIRST AND WITH LOW PRESSURE DIFFERENTIAL BETWEEN WELLBORE AND LUBRICATOR, OPEN TOP FV SLOWLY TO REDUCE ANY POSSIBLE EROSION OF BOTTOM FV GATE. 4. Clear all reel depth counters. 5. If injectivity will allow, proceed to RIH with choke closed pumping at minimum rate. Control well pressure by opening choke while RIH if unable to inject. 6. Perform regular weight checks at 2000' intervals. 7. Once reaching 10,000', increase pump rate to between 1.5 and 2.0 BPM and perform weight checks. 8. Begin running in hole at 15' to 20' per minute. Open coil tubing by production tubing annulus valve and pump down coil with seawater. 9. Rig-up LRS to pump down coil x tubing annulus with diesel. 10.Once 11,200' (200' bites) is reached. Pull up hole 50' to disperse sand and ensure sand is strung out and not collecting around the bottom hole assembly. 11.Continue taking 200' bites and pulling up hole 50' while watching run in hole (RIH) weights and pull up hole (PUH) weights. Repeat these steps until desired depth is accomplished or signs that the well is starting to flow. If a break through event happens the well may see a sudden increase in pressure. 12.Be mindful of sudden increases or decreases over time in Coiled Tubing Pressure (CTP) and Well Head Pressure (WHP) which may indicate sand bridging off the flow path to formation and we also need to maintain a close eye on the Coiled Tubing (CT) pull out of hole (POOH) and run in hole (RIH) weights if a significant change is noted pull up hole (PUH) to above the uppermost frac sleeve to ensure sand is dispersed behind the coiled tubing (CT). 13.POOH to surface and notify the Anchorage team on results for a plan forward. Post Scale Squeeze: 1. Perform a Closure test and monitor for 15 min. ODSN-37 Coil Tubing Scale Squeeze Treatment—version 1 (1/30/2018) • Oooguruk Wells Group S ODSN-37 Nuiqsut Production Well Completion Final 2015-01-05 :i::: i Ili II RP. 1lnmfnmdetietnFtycpneeet � 1ft 1 Vec23 51 T„6tq-YKr 34 34 € k 16"Conductor 2 2-7:8'6.IXL-83 VT-1.4r LON I 3 271YHES wETRW w2313'u-Protd*IS'Pap BxPtop8Bolbm•C088WPr, ,,_ to SotLa INI 1—'4,464 © t 278-64*L-8015T-44%MO "^"' S 271Tx 1-GLIA R.MUG•/8104 tat*-11'P 4p 134P Top&Bottom 21 SZ 7' 4 6 277$64*480 ST-4,4 TAM 7 HES TI•tipple 2313-5C1rw/15"Pup 134P TOp&Batbm 2223 GLM#2 iiiii —7_10 i;i a 2T864fLa3BTa4T.oro DVS 2770'11'GUI ft,1051G wIB104 L4t11-11'Py1 BLP Topb Bottom 0538 1111 10 24:5-6 491-80 BT-4)T544- ir 11 2713x7-4782 FH Psdcet 41111'Pup TOp&5060 n-36ss*astb mine 0000 5514 -III12 27,8'6.4*Lao 0T-t•;OM 13 2-mese 1434 ri117 Mktg Peeve*2312-MX-PPM*-13'Pup Top a.Bottom 6683 0.53.4 14 2-7:8.6 4P L-60 VT-If T,erf3 9-5/8"40#L-80 15 HES XN 2 313'*7 18 Pup 04P Top 8 e0tbm , BTC Surface Casing16 27'8-6 m Lao 15T-44 Marg 17 3-t;2'Mule Snot TC-I Bas 7169 4.274 @ 3,150'MD/3,012'TVD Botbm a Mu*snoe 7£-1 6231 I 248 iiattu.p uacasal 6M1:481 F32Ux 18 WFT P58,e Sart 5,,ecce 151t Sh*2363'673.O1 7:.51 6277 m WIT NTH-L re•Top Pt• 7596 5,M1 20 WFT P1157 Ram.trg t•ydSet L+x•14 eget 7597 6281 21 4-1/2'12W*1.80*'d-1 Pups 44t(Potted*/61/2 hobs) 7766 6320 22 4-UT 1237L-80tyd,,i Pugt 4h{Ported*/61/2 howl 7592 6345 23 4-1'11266*L9Otyd^1 Plait 4ltiPortc4w16112 haesl 5063 6368 24 4-1'2'1260*L-50.id-'!Ptait 411;Potted*16112 Kaes! 515E 6378 25 4-VT 1291*O -dri2 Pupt4h(Ported w)61'2 hoesi 3311 6353 26 4.1fT 1391* 80tyd^iPupt Olt{Ported*16112 hoes! 8516 6384 27 4-VT 1237-5Ottyd•i i Pupt411;Ported w/61/2 holiest 3718 6381 28 4-VT 1350,*L-50 ttidri IPugt 4414Pated*/61/2 holes) 8917 6373 29 4-v2'116D*1-84:ydr"1 Pupjt 4h{Ported w/61/2hales) 9133 6373 30 4-112'12371-80 ryd:n l Pupt Olt{Ported 4/61/2 holes} 9343 6374 31 4-vT 1291*L-30 ttotri:t Pupt Mt Ported w/6V2hoksl 9353 6370 GLM# J® 32 4-1/2"126C¢LS0**d•tPufit Olt sPrted*16112 hoes! 9755 6356 5/16"C+ 33 4-1/T 121081-a0*ydril%lelt 4h{Porte*w/6 v21,oes) 12011 6335 34 4-1/T12674 1-80 tyde"i 11/444Oft4?1624416112 5o'es1 '3139 63228 35 4-1/T 126)*L-so ydn i Pupt it(Ported*161/2 hoes) '3345 6320 36 4-1/37126De:80tyd+i lPupt4it;Payed*161Rhoesi '355.3 6317 37 4.1/?1291'-3O*1,06i1Ptyjt at{Ported*/6112 Koss, 13756 6317 138 4-VT1260*-30tydrii Puptit 1Prted w/6112 hoesi 17963 9,313 S MA CD 1 4-1/2"12.60#L-80 39 4-VT1260*L-a0rydrilPupt41:;Prted*/61/2hoe sI 11165 6312 Sliding ppp CD Hydril Tubing .D 4-vr126O*gaol-vd-,lPl,otslt1Prt4wr5v2hoisi1363 6312 u 4111 12648.80 yd^igaitaFtiPrtc4 w16vztiaesl 11564 6320 Sleeve (Lower Completion) 42 4-vr1260e;8o+yd-ii PuFft 4124Ported 4161=2 hares! 11765 6333 Closed 45 4-vr 1237*.-aonydhi Pupjt 47t{Ported*/6112 hoes) 11966 6350 1 0 44 4-1/11267:451 I Puede at{Po-ted*/6v2ho.es) '2088 6355 45 4-VT1237*L-80tyd-i Pu tdt{Prud*16112 hoes! 123 6364 46 4-VT 1260*L-80633-"i Pupt it(Prt*d*/6112 Kaes! 12498 6362 47 4-VT 12.617 L-30rydn"i Pupt it Ported*/61/2 hoes) 12700 6358 48 4-1/T 12604..50 tydr.i Pupt it(Ported w/6112 holes) 1506 6353 49 4-1/2-1237:8o t.de f Pupt 4lt;Ported w16 V2ho1esl '3112 6342 50 4-113712628.806331%t Pupjt 4h{Ported*161/2 hates) 113'8 6323 51 d-112'12.37 801tidrii Pugt 4h{Potted w/61/2 holes! ?1W 6313 r 52 4-112'1237_80 ttyd-'I Pupt4h!Dated w/61/2hoesl 1354- 6293 7"26#L 80 BTC-M 53 4 urizea*� tdaot1PR1t41t;Ported*/6V2Kaes! 13851 5294 j 54 4-vT1237L-80ryd- P,.pt4rt{Ported w/61'2 ho..esl 14061 650 Intermediate Casing 55 4-1/11237 L-50'yd- Piet 4h}Ported w/61'2 hoes! 14233 646 I@ 7,764'MD/6,319'TVD 56 .Pay 09 Toe 5-0x•55,et Feats hoe IPLUGGED,*/4-12.6- 14281 6237 \ \ E^.,'a'A ssee,011 14283 6237 N. ....., '11141141111% 1141® ®1 c' 0 0 0 r, 0 0 0 e a o 0 0 " I1 6-1/8"Hole TD at at 14,295'MD/6302'TVD ODSN-37 Coil Tubing Scale Squeeze Treatment—version 1 (1/30/2018) 1110 • Image Project Well History File Cover Page XHVZE This page identifies those items that were not scan ned during the initial p roduction scanning phase. They are available in the original file, may be scanned during a special resca n activity or are viewable by direct inspection of the file. cA © - 4 57 Well History File Identifier Organizing (done) ❑ Two -sided 1111 I IIU ❑ Rescan Needed III II1(I II I UIIII RES DIGITAL DATA OVERSIZED (Scannable) Color Items: ❑ Diskettes, No. ❑ Maps: p yscale Items: ❑ Other, No/Type: ❑ Other Items Scannable by a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non - Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: Maria Date: 71 is/ r Project Proofing 1 lIlIlIlIll 11111 BY: Maria Date: 7/ / /13 isi 14 p 1 Scanning Preparation 7 x 30 = Q / 0 + = TOTAL PAGES al o (Count does not include cover sheet) ;^ ,, BY: Date: 7/ /s/ r � Production Scanning IH 11111 1111 11111 Stage 1 Page Count from Scanned File: O 1 l (Count does include co er sheet) Page Count Matches Number in Scanning Preparation: YES NO BY: Date: 7// /` 3 /s/ 04 F lf 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. III I 11111 11 III ReScanned ffl 11111111 11111 BY: Maria Date: /s/ Comments about this file: Quality Checked I I11111 12/22/2011 Well History File Cover Page.doc STATE OF ALASKA AL,. A OIL AND GAS CONSERVATION COMI. .ION ` REPORT OF SUNDRY WELL OPERATIONS G'T FE. 1.Operations Abandon U Repair Well U ! Plug Perforations U Perforate ❑ Other U am g . Performed: Alter Casing ❑ Pull Tubing�(ES?) Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Caelus Natural Resources Alaska, LLC Development E Exploratory ❑ 208-157 _ 3.Address: 700 G Street, Suite 600 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99501 50-703-20586-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 355036 ODSN-37 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): Oooguruk-Nuiqsut Oil P 11.Present Well Condition Summary: C E Total Depth measured feet Plugs measured feet JUAv p 14,295N/A N 1 7 2014 true vertical 6287 feet Junk measured N/A feet Effective Depth measured 14,283 feet Packer measured See Below feet AOa`CC true vertical 6287 feet true vertical feet Casing Length Size MD TVD Burst Collapse Structural Conductor 115' 16" 158' 158' N/A N/A Surface 3109' 9-5/8" 3150' 3012' 5750 psi 3090 psi Intermediate 7725' 7" 7764' 6319' 7240 psi 5410 psi Production Liner 6702' 4-1/2" 7581'-14,283' 6136'-6223' 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", 6.5# L-80, IBT-M 7601' MD 6282'TVD 'NE'TRSV©2096' NTH Liner Top Pkr Packers and SSSV(type,measured and true vertical depth) MD/2056'TVD 7596'MD/6281'ND 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): Treatment descriptions including volumes used and final pressure: ce MINED 1lil 1 02014 13. Representative Daily AvalePserrucruction or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 610 427 0 924 224 Subsequent to operation: 995 322 0 997 304 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run Exploratory Development Service ❑ Stratigaphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil Q Gas ❑ WDSPL❑ 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: 314-261 Contact Alex Vaughan, 343-2186 Email alex.vaughant caelusenergv.com I Printed Name Alex Vaughan Title Sr. Drilling Engineer Signa re �_.„_= „ Phone 343-2186 Date 6.4774,Gf IF' 1 Form 10-404 Revised 10/2012 , / / Submit Original Onlv isit 4 cif-y ( GMS JUN 7 1 • Caelus NdLural Resources Alaska, LLC ODSN-37 Page 2 AOGCC Form 10-404, Report of Sundry Well Operations Present Well Condition Summary, Box #11 Perforation Depth (MD/TVD) - Attachment 4-W, 12.6#, L-80 Liner - perforated pup jts with 6-1/2" holes @ depths listed: MD ND 7766' — 7771' 6320' — 6321' 7892' — 7897' 6345' — 6345' 8060' — 8065' 6368' — 6368' 8186' — 8191' 6378' — 6378' 8311' — 8316' 6382' — 6382' 8516' — 8521' 6384' —6384' 8718' — 8723' 6381' —6381' 8920' — 8925' 6373' —6373' 9130' — 9135' 6373' —6373' 9340' — 9345' 6374' —6374' 9550' — 9555' 6370' — 6370' 9758' — 9763' 6356' — 6355' 10011' — 10016' 6335' — 6335' 10139' — 10144' 6328' — 6328' 10348' — 10353' 6320' —6320' 10553' — 10558' 6317' —6318' 10755' — 10761' 6317' —6316' 10958' — 10963' 6313' —6313' 11165' — 11170' 6312' — 6312' 11363' — 11368' 6312' — 6313' 11564' — 11569' 6320' — 6320' 11765' — 11770' 6333' — 6334' 11966 — 11971 6350 — 6351 12088' — 12093' 6358' —6358' 12295' — 12300' 6364' —6364' 12498' — 12503' 6362' —6361' 12700' — 12705' 6358' —6357' 12906' — 12911' 6353' —6352' 13112' — 13118' 6342' — 6341' 13315' — 13320' 6323' — 6323' 13443' — 13448' 6310' — 6309' 13647' — 13852' 6298' — 6294' 13851' — 13856' 6294' — 6294' 14063' — 14068' 6290' — 6290' 14233' — 14238' 6288' —6288' Operations Summary Report - State Well Name: ODSN-37 e CAELIJ S Enercy Alaska Well Name: Contractor: Rig Number: Job Category: Start Date: End Date: Start Depth Foot/Meters Dens Last Start Date End Date (ftKB) (ft) Mud(Ib/gal) Intentionally left blank. Data pertained to jobs prior to rig workover. 5/6/2014 5/7/2014 0.0 **Accept rig onto ODSN-37 at 00:00 hrs on 5/6/14** LD final 12 stands of 4"DP from derrick.RD mousehole. RDMO ODSN-18.Move pit module& sub down well row.Move pit mod around corner. *AOGCC was notified of upcoming BOP test via website at 06:00 hrs on 5/6/2014. 5/6/2014 5/7/2014 0.0 5/7/2014 5/8/2014 0.0 Continue to move substructure around corner. Spot pit mod and substructure over ODSN-37. RU all lines, landings&beaverslide. RU all containments, lines in HUTZ&PUTZ. Pressure test same.Verify 0 psi on tree&IA. ND tree.Terminate SSSV and P.V.V.control lines. Install test dart. NU riser,BOP stack,choke&kill lines. Install trip nipple. Install 4"test joint.RU test equipment. Fill lines&stack.Perform full body test on BOPE.Good test.Load 2 7/8"tubing in pipeshed. 5/8/2014 5/9/2014 0.0 6.90 Continue to load,drift, strap&number 2 7/8"tubing.Pressure test mud line to 3500 psi.Blow down lines. Continue to load LVT in pits(236 bbls total). Spot ESP spooling unit.Prep for decompletion. Test BOPE per AOGCC Sundry: *Test upper 2 7/8"x 5"VBR rams w/4"&2 7/8" test joint to 250/3500. *Test lower 2 7/8"pipe rams to 250/3500. *Test upper and lower IBOP valves to 250 psi low/3500 psi high. *Test annular w/4"&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. *Initial system psi:3050--2000 after closure;200 psi=26 sec,full pressure in 114 sec. *HCR kill valve failed at stem packing-Replaced HCR valve, Retest.Good test. *AOGCC Rep.John Crisp witnessed tests. -RD test tools.Pull test dart.Blow down lines.Close blind rams. Bullhead 15 bbls 6.9 ppg LVT down tubing. Pull BPV. Close blind rams.Bullhead 125 bbls LVT down tubing.Monitor well. Static.MU landing joint to hanger. Pull hanger free w/140k.Work pipe and pull packer free w/ 165k. Fill hole w/10 bbls LVT.Work pipe to relax packer elements. Pull hanger to rig floor. Terminate SSSV control line and ESP cable from hanger.Observe flow. Close annular and attempt to bullhead down IA w/no success. Observe 0 psi. Open annular and pump down tubing to verify circulation possible.Close annular. Pump down tubing taking returns out IA to Operations flow back tank.Monitor well.,Static.LD hanger,landing joint&1 joint of 2 7/8" tubing. Page 1/2 Report Printed: 6/16/2014 • 1 I Operations Summary Report-State Well Name: ODSN-37 C CAELLS FYcrgy Alaska Start Depth Foot/Meters Dens Last Start Date End Date (ftKB) (ft) Mud(lb/gal) Summary 5/9/2014 5/10/2014 0.0 6.90 Continue to monitor well through IA and flow back tank while LD 4 jts.Close in IA and fill hole w/ LVT.Monitor well.Flowing.Attempt to bullhead down IA w/no success(pressured up to 2000 psi). Bleed off pressure.Monitor well static.Attempt to open floor valve. Pressure on tubing. Attempt to circulate down tubing taking returns out flow line.No returns.Bullhead tubing volume. Monitor well&tubing-Static.Pull 5 joints(attempt to slack off w/no success)and observed well flowing.Close annular and able to bullhead w/2 bpm,500-850 psi(total of 242 bbls pumped). Pressured up to 2200 psi.Bleed off.POH LD 2 7/8"completion f/7192'to 84'.LD ESP pump assembly to 50'. 5/10/2014 5/11/2014 0.0 6.90 Continue to LD ESP assembly f/50'.Spool up remaining used ESP cable over sheaves and into spooling unit.Clear/clean floor.Install wear ring junk basket.Flush stack.Clear pipeshed of all LD tubing and equipment.Install protectors on new tubing&remove from pipeshed.Load used inspected tubing into pipeshed.Drift&tally same. PU 3 1/2"muleshoe.Repair tubing tongs. 5/11/2014 5/12/2014 0.0 6.90 Hold PJSM w/midnight crew&all involved w/completion.PU 3 1/2"muleshoe.RIH w/2 7/8" Gas Lift Completion per tally to 861'(28 jts). PU"XN"nipple w/RHC-M,BOT Sliding Sleeve, BOT"FH"Hyd.set Retrievable Packer&GLM#1 to 1071'. -RIH w/2 7/8"completion f/1071'to 1341'.Tubing tongs broke down-Pull Hydraulic motor& inspect-Gear shaft stripped out&bearing bad.Lower second set of tongs down beaverslide and take to Nabors Mechanic Shop.Pull Hydraulic motor off of tongs&inspect. Keyway sheared in coupling connecting motor to gear shaft. Replace keyway and pump grease into shaft housing. Install motor&reassemble tongs.Bring tongs to rig floor.Attach to Clincher backup.RIH w/2 7/8"completion f/1341' &tag 4 1/2"liner top at 7584'.PU and work muleshoe to enter tieback. " RIH to 7601'placing muleshoe 17"inside tieback.Take spaceout measurements. LD 2 joints of �- 2 7/8"tubing. PU VG hanger assembly and landing joint.Terminate TRSV control line&feed //� through hanger. Connect control line and test to 5000 psi.Land hanger in wellhead placing lam\ muleshoe at 7601'. RILDS.Test upper&lower hanger seals to 5000 psi. Drop 1 5/16"ball&rod. Pressure up&set packer per Baker Rep.Test tubing to 3500 f/30 charted min-Good test. �LL Bleed tubing to 2500 psi.Test 7"x 2 7/8"IA/packer to 3500 psi f/30 charted min-Good test. C. Bleed all pressures(No Shear valve in GLM).LD landing joint. Install TWC. Pull trip nipple, mousehole.RD Choke&Kill lines.Remove turnbuckles. *AOGCC was given 48 hr notice via website for upcoming BOP test on ODSK-41 at 1800 hrs on 5/11/2014. **NOTE:released rig for ODSN-37 at 24:00 hrs. 5/19/2014 5/20/2014 0.0 6.90 MIRU and conduct wireline well work. *Conduct safety briefing with Wells,HES and Ops. *RIH and retrieve ball and rod at 6,721'MDrkb, *Retrieve DMY gas lift valve from GLM#1 at 6,538'MDrkb. *Set 5/16"Orifice valve in GLM#1 at 6,538'MDrkb. *Retrieve RHC-m from XN nipple at 6,721'MDrkb. Page 2/2 Report Printed: 6/16/2014 ODSN-37 Nuiqsut Production Well Completion Final 2014-06-13 r M4. Upper Completion Eauipment Mattl Ndftt 16"Conductor 1 Vetco Gray Tubing Hanger 34 34 2 2-7/8"6.4#L-80IBT-M Tubing 3 2-7/8"HES'NE'TRSV w/2.313"X"Profile 15'Pup BxP Top 8 Bottom-Control line 2096 2056 to surface iiiiii L'1wp ii 4 2-7/8"6.4#L-80 IBT-M Tubing 3 5 2-718"x 1"GLM#2,KBMG w/BK-5 Latch-11'Pup BxP Top 8 Bottom 2158 2114 6 2-7/8"6.4#L-80 IBT-M Tubing 5 7 HES"X"Nipple 2.313"9 Chr w/15'Pup BxP Top&Bottom 2223 2174 GI 8 2-7/8"8.4#L-80 IBT-M Tubing 9 2-7/8"x 1"GLM#1,KBMG w/BK-5 Latch-11'Pup BxP Top&Bottom ,6538 5899 10 2-7/8"6.4#L-80 IBT-M Tubing ..•.,. 11 2-7/8"x 7"47B2'FH'Packer w/11'Pup Top&Bottom-30k shear to release 6600 5934 ••• • '''" 12 2-7/8"6.4#L-80 IBT-M Tubing 13 2-7/8"6.50 9Cr'CMU'Sliding Sleeve w/2312""BX"Profile-13'Pup Top&Bottom 6663 5988 an 14 2-7/8"6.4#L-80 IBT-M Tubing 9-5/8"40#L-80 15 HES XN 2.313'w/15'Pup BxP Top&Bottom 5997 BTC Surface Casin 16 2-7/8"6.48 L-80 IBT-M Tubing g 17 3-1/2"Mule Shoe TC-II Box 7569 6274 @ 3,150'MD/3,012'TVD Bottom of Mule Shoe 7601 6281 3 Lower Completion Eauipment N./3a). TVD 18 WFT PBR Tie Back Sleeve 15ft SN#23682673-01 7581 6277 19 WFT"NTH"Liner Top Pkr 7596 6281 20 WFT"PHR"Rotating Hyd Set Liner Hanger 7597 6281 21 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 7766 6320 22 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 7892 6345 23 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 8060 6368 24 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 8186 6378 25 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 8311 6382 26 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 8516 6384 27 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 8718 6381 28 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 8920 6373 29 4-1/2"12.606 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 9130 6373 30 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 9340 6374 31 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 9550 6370 GLM#1 O 32 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 9758 6356 5/16"OV c J 33 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 10011 6335 I 34 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 10139 6328 35 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 10348 6320 36 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 10553 6317 37 4-1/2"12.606 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 10756 6317 S 11 38 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 10958 6313 4-1/2" 12.60# L-80 39 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/tholes) 11165 6312 Slidin - 13 Hydril Tubing 40 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 11363 6312 g �e� 41 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 11564 6320 Sleeve (Lower Completion) 42 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 11765 6333 Closed _43 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 11966 6350 © 44 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 12088 6358 0 RHC-M Plug 45 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 12295 6364 Installed 46 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 12498 6362 47 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 12700 6358 48 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 12906 6353 49 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13112 6342 50 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13315 6323 51 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13443 6310 52 4-1/2"12.604 L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13647 6298 ,. 7"26# L-80 BTC-M 53 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 13851 6294 'i 54 4-1/2"12.606L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 14063 6290 iii / iii Intermediate Casing 55 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/61/2 holes) 14233 6288 4 @ 7,764' MD/6,319' TVD 56 Ray Oil Tool Silver Bullet Float Shoe(PLUGGED)w/4-1/2 IBT 14281 6287 � End of Assembly 14283 6287 % o \ �� \,�ir,°° 0 0 0 0 0 0 - 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ° o o a 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 6-1/8"Hole TD at at 14,295'MD/6302'TVD ? / THE STATE di allki G e 333 West Seventh Avenue G0\ I RNOR SEAN FARNELI Anchorace Alaska 99501-3572 n .\T 907.279.1,,433 a � � =c;.. 9C7.2(.75<<_ Alex Vaughan SCANNED AUG 0 7 2014 Sr. Drilling Engineer Pioneer Natural Resources Alaska, LLC Q — 157 700 G Street, Suite 600 p� Anchorage, AK 99501 Re: Oooguruk Field,Nuiqsut Oil Pool, ODSN-37 Sundry Number: 314-261 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 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, Cathy P. Foerster Chair – DATED this 27 day of April, 2014. Encl. STATE OF ALASKA '' ALASKA OIL AND GAS CONSERVATION COMMISSION 4/Z5z-//4 APPLICATION FOR SUNDRY APPROVALS /A ^)1' � ; ' 20 AAC 25.280 1.Type of Request: Abandor.0 Plug for Redril 0 Perforate New Pool ❑ Repar Well ❑ Change Approved Program Suspenc❑ Plug Perforation;0 Perforate 0 Put Tubing Q• Time Extension 0 Operations Shutdowl 0 Re-enter Susp.Wel 0 Stimulate❑ Alter Casing ❑ Other.ESP Change-out 0 c 2.Operator Name: 4.Currert Well Class: 5.Permit to Drill Number. Pioneer Natural Resources Alaska LLC , Exploratory ❑ Development 0~ 208-157 3.Address: 700 G Street, Suite 600 Stratigraahic 0 Service 0 6.API Number Anchorage,AK 99501 50-703-20586-00-00 7.If perforating: 8.Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? N/A ODSN-37 Will planned perforations require a spacing exception? Yes 0 No Q J 9.Property Designation(Lease Number): 10. Field/Pool(s): ADL 355036 Oooguruk-Nuiqsut 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): 14,295' - 6287'. 14,281' , 6287' • N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 115' 16" 158' 158' N/A N/A Surface 3109' 9-5/8" 3150' 3012' 5750 psi 3090 psi Intermediate 1 7725' 7" 7764' 6319' 7240 psi 5410 psi Production Liner 6702' 4-1/2" 7581'-14,283' 6277'-6287' 8430 psi 7500 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attachment, pg. 2 1 See Attachment, pg. 2 2-7/8", 6.5# L-80, IBT-M 7482' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): TRSV; Hyd II Liner Top Pkr;WFT"NTH" Liner Top Packer 2091'MD&2051'TVD;2503'MD&2433'TVD;7596'MD&6281'TVD 12.Attachments: Description Summary of Proposal Q. 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory 0 Stratigraphic 0 Developmert Q,, Service 0 14. Estimated Date for 15.Well Status after proposed work: 5/8/2014 Commencing Operations: Oil ❑ . Gas 0 WDSPL 0 Suspended 0 16.Verbal Approval: Date: WINJ 0 GINJ 0 WAG 0 Abandoned 0 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.vaughanalcaelusenergv.com Printed Name Alex Vaughan Title Sr. Drilling Engineer Signature --- Phone Date 343-2186 x{_'12-\r{ cato �� COMMISSION USE ONLY Conditions of approval: Noti ommission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test Ed Mechanical Integrity Test 0 Location Clearance ❑ Other: ..(C. S 5 U ISL.: A60 ? 7 /. A J / `a3 MSMAY U 8 2014 Spacing Exception Required? Yes ❑ No Subsequent Form Required: /D ^ yo 1 APPROVED BY / Approved by: COMMISSIONER 7 THE COMMISSION Date: 4-�4-/l I-ZG / 77A8 'fizz/ill Submit Form and Form 10-403(Revised 10/201 it' App v + picGiiNI 2months from the date of approval. Attachments in Duplicate 1VVVVVV11 OiY�:_! (r • PIONEER NATURAL RESOURCES ALASKA �. i Pioneer Natural Resources Alaska LLC 700 G Street,Suite 600 Anchorage,Alaska 99501 Tel:(907)277-2700 Fax:(907)343-2190 April 11th 2014 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite#100 Anchorage, AK 99501 RE: ODSN-37 Sundry Application for ESP Change-Out REF: Permit To Drill #208-157 Pioneer Natural Resources, Alaska (PNRA) hereby submits an Application For Sundry request l• to pull the existing failed ESP on ODSN-37 and replace with a new ESP. See the proposed plan attachments and supporting documentation. Sincerely, Alex Vaughan Senior Drilling Engineer Attachments: Form 10-403 Supporting information cc: ODSN-37 Well File • Pioneer Natural Resources Alaska LLC ODSN-37 Page 2 AOGCC Form 10-403, Application for Sundry Approvals Present Well Condition Summary, Box #11 Perforation Depth (MD/TVD) - Attachment 4-W, 12.6#, L-80 Liner - perforated pup jts with 6-1/2" holes @ depths listed: MD TVD 7766' — 7771' 6320' — 6321' 7892' — 7897' 6345' —6345' 8060' — 8065' 6368' — 6368' 8186' — 8191' 6378' —6378' 8311' — 8316' 6382' —6382' 8516' — 8521' 6384' —6384' 8718' — 8723' 6381' —6381' 8920' — 8925' 6373' —6373' 9130' — 9135' 6373' —6373' 9340' — 9345' 6374' —6374' 9550' — 9555' 6370' — 6370' 9758' — 9763' 6356' —6355' 10011' — 10016' 6335' —6335' 10139' — 10144' 6328' —6328' 10348' — 10353' 6320' —6320' 10553' — 10558' 6317' — 6318' 10755' — 10761' 6317' — 6316' 10958' — 10963' 6313' — 6313' 11165' - 11170' 6312' - 6312' 11363' — 11368' 6312' — 6313' 11564' — 11569' 6320' — 6320' 11765' — 11770' 6333' —6334' 11966' — 11971' 6350' —6351' 12088' — 12093' 6358' —6358' 12295' — 12300' 6364' —6364' 12498' — 12503' 6362' —6361' 12700' — 12705' 6358' —6357' 12906' — 12911' 6353' —6352' 13112' — 13118' 6342' —6341' 13315' — 13320' 6323' —6323' 13443' — 13448' 6310' —6309' 13647' — 13852' 6298' —6294' 13851' — 13856' 6294' —6294' 14063' — 14068' 6290' —6290' 14233' — 14238' 6288' —6288' cAEL:u s Energy Alaska ODSN-37 RWO Program Replace ESP Completion Current Completion: 2-7/8" ESP String at 7482' MD / 6,206' TVD Planned Completion: 2-7/8" ESP String at 7,247' MD / 6,197' TVD AFE# 031-120, API # 50-703-20586-00-00 AOGCC Sundry # TBA Prepared: Date: Alex Vaughan: Operations Drilling Engineer Reviewed: 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 ODSN-37 2014 RWO ESP Replacement Program Version 1.0 1 April 21st, 2014 Pre-Rig Work to be completed prior to MIRU of Nabors 19AC: (The following workscope is to be completed as outlined in ODSN-37 Well Work Procedure Pre RWO document as coordinated by Jack Kralick) • All fluids injected into the well should be LVT or Diesel. Do not use Seawater based fluids. • Pressure test tubing hanger pack-off void in well head to 5,000 psi • Pull DV from GLM immediately below ESP packer and allow IA gas below packer to bleed out. • Close ScSSV and pressure test from below with well pressure for 15 min. a. Bleed tubing to zero psi above ScSSV • Freeze protect IA to 2000' TVD through the PVV. a. LVT should be used for freeze protection b. Lubricate and bleed as required. • Close PVV in the ESP packer. • Pressure test the IA above ESP to 1000 psi for 15 min. • Install BPV. a. Bleed tree to zero psi. • Close Surface Safety Valve. • Suspend ODSN-37 with the following well control barriers: a. 2-7/8"Tubing: i. Closed ScSSV pressure test to well pressure from below. ii. BPV b. 2-7/8" x 7" Annulus: i. Pressure tested 2-7/8" x 7" annulus above ESP Packer to 1000 psi. ii. Pressure tested Tubing hanger packoff to 5000 psi. ODSN-37 2014 RWO ESP Replacement Program Version 1.0 2 April 21st, 2014 , . L ODSN-37 ESP Completion As Run Casing Well Head: 9-5/8",5K,VetcoGray lam# Item MD(ft) TVD(rt) Tree: 41/2",5K,Horizontal A 16 Conductor 158 158 B 35/8"408 L-80 BTC,8.835"ID 3,150 3,012 C 7"26#L-80 BTC-M,6.276"ID 7,764 6.319 O D 4-1/2"12.6#L-80 Hyd 521,3.958"ID 14,283 6,287 E 2-7/8"6.4#L-80 IBT-M,2.441"ID 7,482 6,255 - CI O ,may. 1 VetcoGray Tubing Hanger 34 34 O 2 2-7/8"'NE'TRSV 2,091 2,051 3 GLM#1-2-7/8"x 1-1/2"Shear Value 2,434 2,370 4 WFT Hydro II Packer 2,503 2,433 5 GLM#2-2-7/8"x 1-1/2"w/Dummy 2,560 2,484 I 6 2-7/8"X Nipple,2.313"ID w/RHC-M 2,626 2,544 7 GLM#3-2-7/8"x 1-1/2",w/1/4"Orifice Value 6,782 6,027 8)Fprofile Nipple 6,848 6,056 Z il. 9 Automatic Divert Value(ADV) 7,409 6,238 10 ESP(Pump.Motor,and Jewelry) 7,419 6,240 4 End of Assembly 7,482 6,255 OO J 11 WFT PBR TieBa�eeue 1511 SN#23682673-01 7,581 8,277 12 WFT"NTH"Liner Top Pkr 7,596 6,281 • 13 WFT"PHR"Rotating Hyd Set Liner Hanger 7,597 6,281 CO\"/ 14 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 7,766 6,320 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 7,892 6,345 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 8,060 6,388 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 8,188 6,378 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 8,311 6,382 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 8,516 6,384 4-1/2"12.60#L-80 Hydril Pupjt 41t(Ported w/6 1/2 holes) 8,718 6,381 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 8,920 6,373 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 9,130 6,373 4-1/2"12.60#L-80 Hydril Pupjt 41t(Ported w/6 1/2 holes) 9,340 6,374 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 9,550 6,370 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 9,758 6,356 O7 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 10,011 6,335 /� 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 10,139 6,328 ■l°1 4-1/2"12.60#L-80 Hydril Pupil 4ft(Ported w/6 1/2 holes) 10,348 6,320 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 10,553 6,317 9 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 10,756 6,317 0 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 10,958 6,313 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 11,165 6,312 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 11,363 6,312 4-12"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 11,564 6,320 _ 4-1/2"12.608 L-80 Hydril Pupjt 41t(Ported w/6 1/2 holes) 11,765 6,333 4-1/2 12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 11,966 6,350 10 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 12,088 6,358 4-1/2 12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 12,295 6,364 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 12,498 6,362 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 12,700 6,358 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 12,906 6,353 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 13,112 6,342 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 13,315 6,323 11 4-12"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 13,443 6,310 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 13,647 6,298 4-1/2 12.60#L-80 Hydril Pupil 4ft(Ported w/6 1/2 holes) 13,851 6,294 ®�1 4-1/2"12.60#L-80 Hydril Pupjt 4ft(Ported w/6 1/2 holes) 14,063 6,290 0. 8 13 4-12"12.60#L-80 Hydril Pupjt 411(Ported w/6 1/2 holes) 14,233 6,288 15 Ray Oil Tool Siker Bullet Float Shoe(PLUGGED)w/4-1/21 14,281 6,287 OEnd of Assembly 14,283 6,287 C CD 00 00 00 00 00 00 00 00 1s 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 u O PIONEER Date: Revision By: Comments 7-30-2009 TWC ESP Comp!Design PostTD ODSN-37 Producer 11-19-2009 TWC Removed XN nipple,moved X nipple down NATURAL R[COURCESgl ASO 11-20-2009 TWC Item 6 revised to read X nipple,not XN nipple Well Schematic YH U fit CJ U1bCJ L11JU ESP Swap - 12-09-2009 TWC As Built Post RWO 7-16-13 KLC ESP Swap ODSN-37 2014 RWO ESP Replacement Program Version 1.0 3 April 21st, 2014 ODSN-37 2014 ESP RWO Proposed Completion ODSN-37 MD(ft) TVD(ft) Baker Hughes Halliburton 9-5/8"40#L-80 BTC,8.835"ID,Bottom 3,150 3,012 Weatherford 7"26#L-80 BTC-M,6.276"ID 7,764 6,319 Vetco Gray 4-1/2"12.6#L-80 Hyd 521,3.958"ID,Top 7,581 6,277 Schlumberger 4-1/2"12.64 L-80 Hyd 521,3.958"ID,Botto 14,283 6,287 Set Depth 7,247 Tool Description Tool/Joint Cumulative. DLS Joints Length Length , Inc(°) TVD lusft) (°/100usft) RKB 34.1 34 0.21 34 0.62 Vetco Gray Tubing Hanger 1.5 36 0.2 36 0.62 3.5"9.2#L-80 IBT-M pin X pin Pup Joint 7.4 43 0.3 43 0.62 ' 3.5"9.2#L-80 IBT-M Joints 2 62.0 105 0.29 105 0.51 Crossover 3.5"IBT x 2.875"IBT-M 0.9 106 0.3 106 0.51 -111C------1111 2.875"6.5#L-80 IBT-M space out pups tba 31.0 137 0.34 137 0.51 ___....--------- 2.875"6.5#L-80 IBT-M Joint r 61 1881.3 2,018 19.0 1982 1.66 t 12.0 2,030 ! 19.16 1994 1.66 J -7/8"NE TRSV ' 6.7 2,037 19.25 1.66 .875"6.5#L-80 IBT-M Pup Joint 12.0 2,049 19.41 2011 1.66 2g 1,, 2.875"6.5#L-80 IBT-M Joint r 15 _7.2 2,496 24.34 2426 1.2 1 2.875"6.5#L-80 IBT-M box X EUE pin XO 12.0 2,508 24.47 2437 1.2 2.875"x 1"GLM EUE w/DGLV 7.0 2,515 24.55 2444 1.2 -J Iiiiii 2.875"6.5#L-80 EUE box X IBT-M pin XO 12.0 2,527 24.68 2455 1.2 IN I 2.875"6.5#L-80 IBT-M Joint r 1 31.0 2,558 25.02 2483 1.2 X-oser coupling and pup joint 14.3 2,572 25.18 2496 1.2 WFT Hyrow II Packer 4.9 2,577 25.18 2500 1.92 Xoser coupling and pup joint 4.5 2,582 , 25.18 2504 1.92 2.875"6.5#L-80 IBT-M Joint r 1 31.0 2,613 25.17 2532 1.92 2.875"6.5#L-80 IBT-M box XEUE pin XO 12.0 2,625 25.17 2543 1.92 2.875"x 1"GLM EUE,w/DGLV 7.0 2,632 25.17 2549 1.92 2.875"6.5#L-80 EUE box X IBT-M pin X0 12.0 2,644 25.18 2560 1.92 2.875"6.5#L-80 IBT-M Joint r 1 31.0 2,675 25.35 2588 1.78 _J 11111 12.0 2,687 25.56 2599 1.78 F • • x . 1 "X profile nipple 1.5 2,688 25.59 2600 1.78 2.875"6.5#L-80 IBT-M Pup Joint 12.0 2,700 25.8 2611 1.78 O O O 2.875"6.5#L-80 IBT-M Joint r 128 i6,661 58.34 5966 3.48 2.875"6.5#L-80 IBT-M box X EUE pin XO 12.0 673 58.61 5973 3.48 2.875"x 1"GLM EUE,w/5/16"OV 7.0 ,580 58.77 5976 3.48 2.875"6.5#L-80 EUE box X IBT-M pin XO 12.0 u,692 59.05 5982 3.48 2.875"6.5#L-80 IBT-M Joint r 1 31.0 6,723 59.81 5998 4.97 2.875"6.5#L-80 IBT-M Pup Joint 12.0 6,735 60.32 6004 4.97 2.875"x 2.313"XN-profile nipple 1.5 6,736 60.39 6005 4.97 ;: ML 12.0 6,748 3 7163 0SP 68.4 7,245 74.02 6196 2.51 Baker 5.85"OD Centralizer 2.0 247 74.07 6197 2.51 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 ODSN-37 2014 RWO ESP Replacement Program Version 1.0 4 ✓ April 21st, 2014 Pre-Rig 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 ODSN-37 Approved Sundry#TBA(see program attachments). 4. Read Approved Sundry and ensure that operations are in accordance. Rig Activity: Kill ODSN-37 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. e. RWO BOPE test cycle is 7 days as per AOGCC regulations. f. Review 2013 RWO in WellView 2. MIRU Nabors 19AC over ODSN-37 3. Lubricate and bleed the 2-7/8"x 7" IA as required. 4. ND production tree with the following well control barriers in place a. 2-7/8"Tubing: i. Closed ScSSV pressure test to well pressure from below. ii. BPV b. 2-7/8"x 7"Annulus: i. Pressure tested 2-7/8"x 7" annulus above ESP Packer to 1000 psi. tl ii. Pressure tested Tubing hanger packoff. 5. Install test dart, NU BOPE &Test 250 psi low/ 00 ps high according to the test pressures outlined in the AOGCC Permit to Drill. 3o a. Install 2-7/8" rams 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 125 bbls of LVT @ 6 bpm down the tubing. a. This volume represents 150% of the tubing capacity, the IA capacity below the packer, and the 7"casing capacity to the 4-1/2" liner top. b. 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. a. Bottom hole pressure model indicates an expected 6.5 ppg EMW after a 15 day shut in period. See model below. ODSN-37 2014 RWO ESP Replacement Program Version 1.0 5 April 21st, 2014 ODSN-37 Nuiqsut Shut-In Pressure Data 10 - 9 _ 1 8 - 0 7 a v 6 - v 5 I� a 0 4 - ra sw E 3 - LVT o I LL n N-37,Post'13 Seawater Workover,1,495 bbls lost 2 - Eclipse simulation area pressure;803 MRB Voidage 1 - © ODSN-37,11/09,157 MRB Voidage(BHP measured) — — ODSN-37,4/10,222 MRB Voidage(BHP measured) 0 0 5 10 15 20 25 30 Cumulative shut-in time, days ODSN-37 2014 RWO ESP Replacement Program Version 1.0 6 April 21st, 2014 Riq 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 ODSN-37 Installation Report. d. Ensure contingency fishing equipment is inventoried and accessible. (See RWO SID). a. Ensure safety valves with XO's to 2-7/8"tubing are operational and drifted. b. Review NORM monitoring plan with HSE team. c. 5.85" ESP centralizer from the 2009 ESP completion was lost and left in hole during the 2013 ESP re-completion. WellView Report#6/09/2013. 2. Prep rig floor to pull 2-7/8" ESP completion. d. Ensure safety valves with XO's to 2-7/8"tubing are accessible and in the open position. e. Ensure ESP cable cutter is operational and accessible. f. RU HAL control line spooler post hanger pull. g. Identify a person to count and maintain Cannon Clamps. Note location of each Cannon Clamp recovered on the tally. 3. BOLDS and unseat 3-1/2"tubing hanger with use of 4" drillpipe landing joint. 4. Release 2-7/8"x 7" ESP packer with a straight pull (See RWO SID). a. Packer Shear Release: 33,000 lbs. b. 80%Tensile Limit: 115,000 lbs for 2-7/8"6.5#L-80 IBT-M. 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" shoe @ 6 bpm down the IA. 7. Pull hanger to floor and reestablish 1/4"control line connection to open the SCSSV with 4,500 psi. 8. 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 ScSSV 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 LVT every half hour. / e. If influx is observed stab floor safety valve, space out, close annular and bullhead 1.5 ✓ tubing volume to 7" 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. ODSN-37 2014 RWO ESP Replacement Program Version 1.0 7 April 21st, 2014 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 LVT every half hour. c. A scrapper/magnet run is not required on this well. ODSN-37 2014 RWO ESP Replacement Program Version 1.0 8 April 21st, 2014 INSTALLATION REPORT ,/.' AFE# 027056 BAKER DST# 000209 NEW INSTALLATION FORMATION INGLES PULLING REPORT DATE: CHANGE OUT x WELL TEST Lease Customer SAP# SAP Well Master# PO/AFE#if Applicable Sale 20016436 SAP Job Master# 50008918 CUSTOMER FIELD PAD WELL NO. COUNTY STATE COUNTRY Pioneer Oooguruk ODS N-37 Prudhoe Bay ALASKA USA TD-ORIG/NEW ART CASING SIZEIWT PERF/O.H.I(FROM-TO) TUBING SIZE NO.OF JTS. Completion Type' 14,295 7"26# 4.5"slotted liner I r 2 7/8 r 230 ESP MRTSETATMEAS MRTSET ATVERT LINER SIZE(FROM/TO) B.H.T °F BAND TYPE NO.of BANDS 7489.73' 6256.8 ' 41/2 7580-14,283 133 N/A I N/A WELLHEAD SIZE/TYPE/MFG. MRT.JKT.PN CABLE PROTECTOR TYPE NUMBER Vetco Gray Production ESP X Mas Tree N/A r-- 2 7/8 I CROSS COLLAR CLAMPS • 125 PUMP S/N P/N MODEL TYPE NEW/RERUN I DESCRIPTION LENGTH(F) r 12720538 CO23047418 400PMSSD G12 NEW M NO PNT 10.50 r 12720543 CO23056294 400PMSXD P8 NEW M NO PNT 13.40 DISCHARGE C63029 6 BOLT FPDIS NEW 2 7/8"EUE 8RD 0.52 INTAKE S/N P/N TYPE NEW/RERUN DESCRIPTION LENGTH(F) r 12793645 C426001558 GSTHVEVXH6 NEW GASSEP 5.48 TTC COMPONENTS P/N S/N PUMPEYE TUBING XOV E R COUPLING SEAL S/N P/N MODEL/TYPE " 11908723 C305928 GSB3DB H6 SB/AB PFSA NEW UPPER TANDEM 6.90 11908724 C305928 GSB3DB H6 SB/AB PFSA NEW LOWER TANDEM 6.90 MOTOR S/N P/N MODEL/HP VOLT/AMP " 12143252 C321469 562MSP1/150 2205/41 NEW MSP1 16.71 D/H SENSOR S/N CAL FILE# TYPE P/N Wellift MGU 192-00613 MGU C902928 MGU SENSOR 1.85 Misc.Components 6^6PlN CHITRILIZBt Motor Protect. Pump Protect ADV OIL TYPE P/N:PA-003477 DGU/12147013 # 63569 #-59805 #-58894 S/N:4396 CL-5 Penetrator TYPE P/N S/N BIW Wellhead BIW Vetco Supplied I Vetco Supplied Lower Connector TYPE P/N S/N BIW HL02122-KIT ' 168498 MLE S/N TYPE/PN Size/length CUT LENGTH NEW/RERUN TOTAL LING-BIM r 62.26 ° 11619310 #4/70' r 65 NEW SPLICES QTY. CABLE S/N CABLE Size I Type LENGTH REEL NO. NEW/RERUN MLE TO PWRCABLE 1 1st In 3812063A I #1 AWG/SOL 5000' r 45753 NEW HANGER r 1 2nd In 103652978A #1 AWG/SOL 2500' HD78-44917 NEW CABLE TO CABLE r 0 3rd In P/N: 4th In PFT GATOR P/N: TOTAL CABLE USED 7500' SPLICE KITS USED P/N: Cable Remaining(Length-Reel#): 2000745753 4500778-44917 P/N: CAP TUBE SIZE LENGTH REEL NO. NEW/RERUN SWAGELOK FITTINGS USED N/A N/A TOTAL CAP TUBE USED CAP TUBE Remaining(Length-Reel#) CONTROLLER SIN SIZE-KVA/AMPS MODEL MCC BREAKER TRANSFORM Ht S/N CONNECT/RATIO RATING/AMPS INSULATION READING A-B B-C A-C A-GND B-GND C-GND MOTOR 1.4 BAL 1.4 BAL 1.4 BAL 21.8G 21.8G 21.8G CABLE&MLE N/A N/A N/A N/A N/A N/A CABLE&PA TR.SURF. 3 BAL 3 BAL 3 BAL 3.256 3.25G 3.25G CABLE&MTR BOTT. 3.2 BAL 3.2 BAL 3.2 BAL 873 MOHMS 873 MOHMS 873 MOHMS CUSTOMER REP. JOE POLYA ADVISED ME TO RERUN: MOTOR PUMP SEAL OTHER MTh.LEAD CABLE GAS SEP. COMMENTS: NSTALLED-125 CROSS COLLAR CLAMPS-P/N 2875-A-24P 1ST 10175.EVERY COLLAR THEN EVERY OTHER TO SURFACE NSTALLED-6 CANNON MIO-1T.CLAMPS P/N 2875-C-24P AT HANDLING PUP ABOVE PUMP-ABOVE AND BELOW EACH GLM-ABOVE AND BELOW PACKER NSTALLED-2 CANNON MID-1T.CLAMPS P/N 2875th ON DISCHARGE ASSEMBLY NSTALLED-1 CANNON MID-1T.CLAMPS P/N 3500-C-24P AT BOTTOM Of HANGER NSTALLED-4 SEAL PROTECTOR CLAMPS P/N-5130LP-AF-03P-PUT TWO ON EACH SEAL SECTION NSTALLED-4 PUMP PROTECTOR CLAMPS P/N-4000-B-03PG1.40=2 ON EACH PUMP NSTALLED-1 CANNON SPLICE CLAMP 2875-36-24/35/03 AT MLE-ROUND PFTSPUCE NSTALLED-2 LESALLE NECK CLAMPS ON THE SEAL SECTIONS NSTALLED FOLLOWING PFT CONNECTIONS-MLE PFT SPLICE PARTS P/N GS044015-KITS/N 81112-003-P/N P1041010-10T S/N 21112-045 NSTALLED FOLLOWING PFT PACKER PENETRATOR SYSTEM S/N-51112-002 WITH FOLLOWING PARIS-P/N P1041010-Kn S/N 21112-065-P/N PS060404120000 S/N 71112-002-P/N PC1322-1010-KITS/N 61112-002 NSTALLED-1 BIW LOWER CONNECTOR P/N H102122T0-S/N 168498 NSTALLED APPROXI MARS 84'0F 1/4.TECH WIRE FROM MGU TO OGU SERVICE TECH: IS.Smith,G.Roberts,M.Campbell I START DATE: r 6/8/13 I END DATE: r 6/10/13 ODSN-37 2014 RWO ESP Replacement Program Version 1.0 9 April 21st, 2014 Rig Activity: RIH with 2-7/8" ESP Completion 1. Hold pre-job meeting a. Confirm ODSN-37 will remain shut in until ODSK-41 RWO is completed. i. No on rig slickline work will be required post ESP packer setting. b. Baker is responsible for tally at rig site. The Tally is to include: ii. Tubing measurement by joint(composite tubing tally is not acceptable) iii. Equipment type, Serial#, Length, OD, ID, Top and bottom connection. c. RWO Completion Supervisor to create independent tally as outlined in the Tally& Schematics Recommended Practice. Confirm jewelry installation and location with vender tally. d. CoMan to confirm jewelry installation and location with RWO Completion Supervisor and record in Wellview. e. Tally is to be emailed to Alex Vaughan once compiled for confirmation. f. Tally is to be confirmed by Nabors Driller during RIH. g. Review Lessons Learned from previous ESP installations (See RWO SID). h. Review Centrilift ESP running procedure. (See RWO SID) i. Review Weatherford 2-7/8"x 7" ESP packer running procedure. (See RWO SID) 2. Confirm zero pressure below blind ram and open ram a. Continue to fill hole with 5 bbl of LVT every half hour. 3. 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. Include one% clamp on pup above packer and full clamps on the next three joints above packer. Take care not to damage ESP packer splice while lowering packer through BOP stack. d. As required circ 150% tubing volume halfway between ESP and packer e. As required circ 150% tubing volume one joint before picking up the packer f. Hold 1000 psi on PVV during RIH g. Hold 4500 psi on SCSSV during RIH ODSN-37 2014 RWO ESP Replacement Program Version 1.0 10 April 21st, 2014 • 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. GE 3-1/2"Tubing Hanger Halliburton Tubing retrievable safety valve • Install at—2,000'TVD • Purpose:2-7/8"through tubing well control safety device Schlumberger 1"GLM#3 • Install 1 jt above ESP Packer. • Run with dummy GLV installed • Purpose: Freeze protection circulation point. • Requires: EUE XO pups. Weatherford Packer • Install at—2,500' MD • Primary Purpose:2-7/8"x 7"annulus well control safety device • Secondary Purpose:Allows pressure test of the 2-7/8"x 7"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. Schlumberger 1"GLM#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. • Requires: EUE XO pups. Halliburton X-Nipple • Install one joint below GLM#2 • Run with RHC 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 Schlumberger 1"GLM#1 • Install at 68°for slickline accessibility • Run with 5/16 OV installed • Purpose: Backup gas lift location • Requires: EUE XO pups. Halliburton XN-Nipple • Install one joint below GLM#1 • Primary Purpose:Allows installation of XXN plug as a junk catcher for GLV swaps vvT Centrilift ESP • Install as deep as possible in a location of less than 2° DLS • Purpose: Enhanced fluid lift to surface ODSN-37 2014 RWO ESP Replacement Program Version 1.0 11 April 21st, 2014 Riq Activity: Land 2-7/8" ESP Completion 1. With 3-1/2"drillpipe landing joint and TIW, 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. 2. Hold pre-job meeting a. LVT will freeze protection IA and tubing. Diesel freeze protection is not require. b. Review packer setting procedures 3. 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. 4. Fill tubing with LVT and set Weatherford ESP packer per Weatherford rep instructions a. 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. ii. Minimum recommended setting pressure is 2,500 psi. 5. Pressure Test 2-7/8"x 7"annulus to 3,500 si for 30 min and chart 6. 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). c. Ensure Vetco Gray personnel are present prior to lifting stack and recovering control lines so as to prevent kinking. d. Note: Centrilift tech to continue to monitor cable conductivity throughout process. 7. Install TWC. 8. ND BOP's with the following well control barriers in place a. 2-7/8"Tubing: i. Closed SCSSV ii. TWC b. 2-7/8"x 7"Annulus: i. Tested 2-7/8"x 7" ESP Packer(Closed PVV) ii. Tested Tubing hanger packoff 9. 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. 10. 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) 11. 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 5000 psi. Once tests are successfully completed, bleed pressure. 12. Pull TWC with rod 13. Hold post-job meeting ODSN-37 2014 RWO ESP Replacement Program Version 1.0 12 April 21st, 2014 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 Charlene Franklin. 14. 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. Centrilift to supply CoMan, Completions Supervisor, and Alex Vaughan with a digital copy of Tallys, Pressure tests, and Post job report prior to leaving location. c. 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. d. Schlumberger to supply CoMan, Completions Supervisor and Alex Vaughan with a digital record of strapped GLM's and GLV model's installed in well. ODSN-37 2014 RWO ESP Replacement Program Version 1.0 13 April 21st, 2014 Post Rig: Slickline 1. RU slickline on ODSN-37 2. Hold pre-job meeting 3. Hold open SCSSV 4. Pull Ball and Rod 5. Pull RHC 6. Function test SCSSV 7. Start up ESP as per Centrilift Procedures ITEM Description Vendor Field Contact Office Contact Tubing Hanger GE Vetco ODS Office Ext#6618 Andrew Cater 907-244-9427 ScSSV Halliburton Jeff/Bob 907-670-5952 Dan Brown 907-748-2674 GLM Assembly Schlumberger Jeff/Bob 907-670-5954 Chris Cooper 907-748-7525 X&XN Nipple Assembly Halliburton Jeff/Bob 907-670-5952 Dan Brown 907-748-2674 ESP Packer Weatherford Jason House 307-350-8162 ESP Baker Ryan Purcella 907-223-8200 RWO Fluid's Bariod ODS Office Ext#6639 Ethan Laufer 907-223-1697 Caelus Contacts Office Mobile Email Bob Smejkal 971-258-9656 Robert.Smejkal@caelusenergy.com Mark Meier 435-828-7722 Mark.Meier@caelusenergy.com Alex Vaughan 907-343-2186 907-748-5478 AIex.Vaughan@caelusenergy.com Rob Tirpack 907-343-2121 907-903-9454 Rob.Tirpack@caelusenergy.com Dennis Hartwig 907-343-2174 907-980-4515 Dennis.Hartwig@caelusenergy.com Rami Jasser 907-343-2182 907-230-9390 Rami.Jasser@caelusenergy.com Charlene Franklin 907-343-2172 Charlene.Franklin@caelusenergy.com Rachel Davis 907-343-2159 907-230-5982 Rachel.Davis@caelusenergy.com ODSN-37 2014 RWO ESP Replacement Program Version 1.0 14 April 21st, 2014 • Well Planning - Pioneer - Oooguruk Oooguruk Developement Oooguruk Drill Site ODSN-37 PN8 Permit to Drill: 208-157 API: 50-703-20586-00 Sperry Drilling Services Definitive Survey Report 11 June, 2009 Eimmi HALLIBURTON Sperry Drilling Services It - Halliburton Company Definitive Survey Report Company: Well Planning-Pioneer-Oooguruk Local Co-ordinate Reference: Well ODSN-37-Slot ODS-37 Project: Oooguruk Developement TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Well: ODSN-37 North Reference: True Wellbore: ODSN-37 PN8 Survey Calculation Method: Minimum Curvature Design: ODSN-37 PN8 Surveys Database: .Pioneer Alaska 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 Well ODSN-37-Slot ODS-37 1 Well Position +N/-S 0.0 ft Northing: 6,031,053.00ft Latitude: 70°29'45.273 N' +EI-W 0.0 ft Easting: 469,869.00 ft Longitude: 150°14'46.967 W Position Uncertainty 0.0 ft Wellhead Elevation: ft Ground Level: 13.5ft Wellbore ODSN-37 PN8 I Magnetics Model Name Sample Date Declination Dip Angle Field Strength I (?) (7) (nT) IGRF200510 5/20/2008 22.70 80.81 57,693 Design ODSN-37 PN8 Surveys Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 42.7 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (ft) (ft) (ft) (bearing) 1 42.7 0.0 0.0 317.46 Survey Program Date 6/11/2009 From To (ft) (ft) Survey(Wellbore) Tool Name Description Survey Date 50.0 1,488.0 ODSN-37 PN8 Gyro(ODSN-37 PN8) CB-GYRO-SS Camera based gyro single shot 10/27/2008 ' 1,530.8 14,258.5 ODSN-37 PN8 MWD(ODSN-37 PN8) MWD+SAG+CA+IIFR+M MWD+SAG+CA+IIFR+Multi Station 10/29/2008 ' Survey Map Map Vertical MD Inc Azi ND TVDSS +N/-S +EI-W Northing Easting DLS Section (ft) (?) (bearin (ft) (ft) (ft) (ft) (ft) (ft) (11001 (ft) Survey Tool Name 0.0 0.00 0.00 0.0 -56.2 0.0 0.0 6,031,053.0 469,869.0 0.0 0.00 UNDEFINED 50.0 0.31 103.88 50.0 -6.2 0.0 0.1 6,031,053.0 469,869.1 0.6 -0.11 CB-GYRO-SS(1) 100.0 0.29 208.17 100.0 43.8 -0.2 0.2 6,031,052.8 469,869.2 0.9 -0.27 CB-GYRO-SS(1) 166.0 0.43 259.13 166.0 109.8 -0.4 -0.1 6,031,052.6 469,868.9 0.5 -0.19 CB-GYRO-SS(1) 260.0 0.40 286.99 260.0 203.8 -0.3 -0.8 6,031,052.7 469,868.2 0.2 0.28 CB-GYRO-SS(1) 352.0 0.59 310.22 352.0 295.8 0.1 -1.4 6,031,053.1 469,867.6 0.3 1.02 CB-GYRO-SS(1) 442.0 0.19 84.25 442.0 385.8 0.4 -1.7 6,031,053.4 469,867.3 0.8 1.39 CB-GYRO-SS(1) 539.0 0.75 104.48 539.0 482.8 0.2 -0.9 6,031,053.2 469,868.1 0.6 0.76 CB-GYRO-SS(1) 633.0 1.51 106.27 633.0 576.8 -0.3 0.9 6,031,052.7 469,869.9 0.8 -0.81 CB-GYRO-SS(1) 727.0 3.09 119.44 726.9 670.7 -1.9 4.3 6,031,051.1 469,873.3 1.8 -4.28 CB-GYRO-SS(1) 826.0 4.94 134.90 825.6 769.4 -6.2 9.6 6,031,046.8 469,878.6 2.1 -11.08 CB-GYRO-SS(1) 919.0 5.26 132.46 918.3 862.1 -11.9 15.6 6,031,041.1 469,884.6 0.4 -19.32 CB-GYRO-SS(1) 1,014.0 6.19 135.23 1,012.8 956.6 -18.5 22.4 6,031,034.4 469,891.4 1.0 -28.78 CB-GYRO-SS(1) 6/11/2009 11:04:48AM Page 2 COMPASS 2003.16 Build 428 Halliburton Company Definitive Survey Report Company: Well Planning-Pioneer-Oooguruk Local Co-ordinate Reference: Well ODSN-37-Slot ODS-37 Project: Oooguruk Developement TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Well: ODSN-37 North Reference: True Wellbore: ODSN-37 PN8 Survey Calculation Method: Minimum Curvature Design: ODSN-37 PN8 Surveys Database: .Pioneer Alaska Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (ft) (?) (bearin (ft) (ft) (ft) (ft) (ft) (ft) (°1100') (ft) Survey Tool Name 1,110.0 9.70 141.51 1,107.9 1,051.7 -28.5 31.1 6,031,024.4 469,900.0 3.8 -42.02 CB-GYRO-SS(1) 1,205.0 11.10 137.62 1,201.3 1,145.1 -41.5 42.3 6,031,011.3 469,911.1 1.6 -59.15 CB-GYRO-SS(1) 1,300.0 12.18 141.86 1,294.4 1,238.2 -56.1 54.6 6,030,996.7 469,923.4 1.4 -78.29 CB-GYRO-SS(1) 1,392.0 14.26 145.23 1,383.9 1,327.7 -73.1 67.1 6,030,979.7 469,935.8 2.4 -99.20 CB-GYRO-SS(1) 1,488.0 15.84 149.16 1,476.6 1,420.4 -94.0 80.5 6,030,958.6 469,949.2 2.0 -123.74 CB-GYRO-SS(1) 1,530.8 15.61 145.11 1,517.8 1,461.6 -103.8 86.8 6,030,948.9 469,955.4 2.6 -135.17 MWD+SAG+CA+IIFR+MS(2 1,625.4 16.39 145.38 1,608.7 1,552.5 -125.2 101.7 6,030,927.4 469,970.2 0.8 -161.00 MWD+SAG+CA+IIFR+MS(2 1,720.6 17.57 143.64 1,699.8 1,643.6 -147.8 117.8 6,030,904.7 469,986.2 1.3 -188.60 MWD+SAG+CA+11FR+MS(2 1,814.8 18.55 143.58 1,789.3 1,733.1 -171.3 135.2 6,030,881.1 470,003.5 1.0 -217.62 MWD+SAG+CA+IIFR+MS(2 1,910.4 18.14 142.45 1,880.1 1,823.9 -195.4 153.3 6,030,857.0 470,021.5 0.6 -247.56 MWD+SAG+CA+IIFR+MS(2 2,003.9 18.81 142.48 1,968.7 1,912.5 -218.9 171.3 6,030,833.5 470,039.4 0.7 -277.08 MWD+SAG+CA+11FR+MS(2 2,098.6 20.09 139.75 2,058.1 2,001.9 -243.4 191.1 6,030,808.9 470,059.1 1.7 -308.57 MWD+SAG+CA+11FR+MS(2 2,193.5 21.18 138.57 2,146.9 2,090.7 -268.7 213.0 6,030,783.5 470,080.9 1.2 -341.99 MWD+SAG+CA+11FR+MS(2 2,288.4 21.51 136.80 2,235.3 2,179.1 -294.2 236.3 6,030,757.9 470,104.0 0.8 -376.52 MWD+SAG+CA+11FR+MS(2 2,382.1 23.03 136.43 2,322.0 2,265.8 -320.0 260.7 6,030,731.9 470,128.3 1.6 -412.04 MWD+SAG+CA+11FR+MS(2 2,476.9 24.13 134.99 2,408.9 2,352.7 -347.2 287.1 6,030,704.7 470,154.7 1.3 -449.92 MWD+SAG+CA+IIFR+MS(2 2,572.3 25.18 136.09 2,495.6 2,439.4 -375.6 315.0 6,030,676.2 470,182.5 1.2 -489.71 MWD+SAG+CA+IIFR+MS(2 2,665.7 25.19 140.31 2,580.1 2,523.9 -405.2 341.5 6,030,646.5 470,208.8 1.9 -529.42 MWD+SAG+CA+IIFR+MS(2 2,761.9 26.90 140.44 2,666.6 2,610.4 -437.7 368.4 6,030,613.8 470,235.6 1.8 -571.62 MWD+SAG+CA+IIFR+MS(2 2,856.7 26.38 140.23 2,751.3 2,695.1 -470.4 395.6 6,030,581.0 470,262.6 0.6 -614.07 MWD+SAG+CA+11FR+MS(2 2,950.9 27.49 138.22 2,835.2 2,779.0 -502.7 423.4 6,030,548.6 470,290.3 1.5 -656.69 MWD+SAG+CA+11FR+MS(2 3,044.5 27.08 141.47 2,918.4 2,862.2 -535.5 451.1 6,030,515.7 470,317.9 1.7 -699.56 MWD+SAG+CA+11FR+MS(2 3,114.2 27.19 143.40 2,980.4 2,924.2 -560.7 470.5 6,030,490.5 470,337.1 1.3 -731.21 MWD+SAG+CA+IIFR+MS(2 3,214.1 25.69 145.06 3,069.9 3,013.7 -596.8 496.5 6,030,454.3 470,363.0 1.7 -775.37 MWD+SAG+CA+IIFR+MS(2 3,308.9 25.47 148.59 3,155.4 3,099.2 -631.0 518.9 6,030,420.0 470,385.2 1.6 -815.74 MWD+SAG+CA+IIFR+MS(2 3,404.0 25.63 152.91 3,241.2 3,185.0 -666.8 538.9 6,030,384.1 470,405.1 2.0 -855.65 MWD+SAG+CA+IIFR+MS(2 3,498.9 28.01 158.37 3,325.9 3,269.7 -705.8 556.5 6,030,345.0 470,422.5 3.6 -896.26 MWD+SAG+CA+IIFR+MS(2 3,593.5 28.86 160.66 3,409.1 3,352.9 -748.0 572.2 6,030,302.8 470,438.1 1.5 -937.99 MWD+SAG+CA+11FR+MS(2 3,687.9 28.15 162.17 3,492.1 3,435.9 -790.7 586.6 6,030,260.0 470,452.3 1.1 -979.16 MWD+SAG+CA+IIFR+MS(2 3,782.5 28.01 162.84 3,575.6 3,519.4 -833.2 600.0 6,030,217.5 470,465.5 0.4 -1,019.51 MWD+SAG+CA+IIFR+MS(2 3,877.1 27.62 163.91 3,659.2 3,603.0 -875.5 612.6 6,030,175.2 470,478.0 0.7 -1,059.22 MWD+SAG+CA+11FR+MS(2 3,970.0 27.40 164.60 3,741.6 3,685.4 -916.7 624.2 6,030,133.8 470,489.4 0.4 -1,097.50 MWD+SAG+CA+IIFR+MS(2 4,064.1 26.81 164.36 3,825.3 3,769.1 -958.0 635.7 6,030,092.5 470,500.8 0.6 -1,135.69 MWD+SAG+CA+11FR+MS(2 4,159.0 27.22 168.25 3,910.0 3,853.8 -999.9 645.9 6,030,050.6 470,510.8 1.9 -1,173.45 MWD+SAG+CA+IIFR+MS(2 4,253.7 27.92 176.03 3,993.9 3,937.7 -1,043.3 651.8 6,030,007.2 470,516.6 3.9 -1,209.41 MWD+SAG+CA+IIFR+MS(2 4,347.3 28.12 182.41 4,076.6 4,020.4 -1,087.2 652.4 6,029,963.3 470,517.0 3.2 -1,242.15 MWD+SAG+CA+IIFR+MS(2 4,443.2 27.29 190.31 4,161.4 4,105.2 -1,131.4 647.6 6,029,919.1 470,511.9 3.9 -1,271.42 MWD+SAG+CA+11FR+MS(2 4,537.8 26.52 197.34 4,245.9 4,189.7 -1,172.9 637.4 6,029,877.6 470,501.5 3.5 -1,295.13 MWD+SAG+CA+IIFR+MS(2 4,632.4 26.09 210.42 4,330.7 4,274.5 -1,211.0 620.5 6,029,839.6 470,484.6 6.1 -1,311.83 MWD+SAG+CA+IIFR+MS(2 4,727.2 29.37 221.23 4,414.7 4,358.5 -1,246.5 594.6 6,029,804.2 470,458.5 6.3 -1,320.47 MWD+SAG+CA+11FR+MS(2 6/11/2009 11:04:48AM Page 3 COMPASS 2003.16 Build 428 Halliburton Company Definitive Survey Report Company: Well Planning-Pioneer-Oooguruk Local Co-ordinate Reference: Well ODSN-37-Slot ODS-37 Project: Oooguruk Developement TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Well: ODSN-37 North Reference: True Wellbore: ODSN-37 PN8 Survey Calculation Method: Minimum Curvature Design: ODSN-37 PN8 Surveys Database: .Pioneer Alaska Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (ft) (?) (bearin (ft) (ft) (ft) (ft) (ft) (ft) (°1100') (ft) Survey Tool Name 4,821.8 30.02 226.86 4,496.9 4,440.7 -1,280.2 562.1 6,029,770.7 470,425.8 3.0 -1,323.24 MWD+SAG+CA+IIFR+MS(2 4,917.5 29.59 227.03 4,580.0 4,523.8 -1,312.6 527.3 6,029,738.4 470,390.9 0.5 -1,323.67 MWD+SAG+CA+IIFR+MS(2 5,012.4 28.59 227.73 4,662.9 4,606.7 -1,343.9 493.3 6,029,707.3 470,356.8 1.1 -1,323.73 MWD+SAG+CA+IIFR+MS(2 5,107.1 27.62 230.71 4,746.4 4,690.2 -1,373.0 459.6 6,029,678.3 470,323.0 1.8 -1,322.38 MWD+SAG+CA+IIFR+MS(2 5,202.8 26.75 236.17 4,831.5 4,775.3 -1,399.0 424.5 6,029,652.4 470,287.8 2.8 -1,317.87 MWD+SAG+CA+IIFR+MS(2 5,297.2 26.56 241.72 4,915.9 4,859.7 -1,420.9 388.3 6,029,630.7 470,251.5 2.6 -1,309.45 MWD+SAG+CA+IIFR+MS(2 5,391.1 26.91 248.59 4,999.8 4,943.6 -1,438.6 350.0 6,029,613.1 470,213.1 3.3 -1,296.61 MWD+SAG+CA+IIFR+MS(2 5,486.6 25.75 262.96 5,085.5 5,029.3 -1,449.0 309.3 6,029,602.9 470,172.4 6.8 -1,276.75 MWD+SAG+CA+IIFR+MS(2 5,582.6 26.79 272.38 5,171.6 5,115.4 -1,450.7 266.9 6,029,601.4 470,130.0 4.5 -1,249.35 MWD+SAG+CA+IIFR+MS(2 5,678.0 28.45 280.32 5,256.2 5,200.0 -1,445.7 223.1 6,029,606.5 470,086.2 4.2 -1,216.03 MWD+SAG+CA+IIFR+MS(2 5,772.2 28.75 288.88 5,338.9 5,282.7 -1,434.4 179.6 6,029,618.0 470,042.7 4.4 -1,178.27 MWD+SAG+CA+IIFR+MS(2 5,867.1 29.93 294.74 5,421.6 5,365.4 -1,417.1 136.4 6,029,635.5 469,999.7 3.3 -1,136.36 MWD+SAG+CA+IIFR+MS(2 5,962.2 34.36 304.06 5,502.2 5,446.0 -1,392.1 92.6 6,029,660.7 469,956.0 7.0 -1,088.32 MWD+SAG+CA+IIFR+MS(2 1 6,057.1 38.18 308.34 5,578.7 5,522.5 -1,358.9 47.4 6,029,694.1 469,910.9 4.8 -1,033.25 MWD+SAG+CA+IIFR+MS(2 6,151.2 42.35 311.74 5,650.5 5,594.3 -1,319.7 0.9 6,029,733.4 469,864.6 5.0 -973.01 MWD+SAG+CA+IIFR+MS(2 6,245.5 46.18 316.59 5,718.0 5,661.8 -1,273.8 -46.2 6,029,779.5 469,817.6 5.4 -907.33 MWD+SAG+CA+IIFR+MS(2 6,340.6 49.91 319.45 5,781.6 5,725.4 -1,221.2 -93.5 6,029,832.3 469,770.6 4.5 -836.60 MWD+SAG+CA+IIFR+MS(2 6,435.3 54.70 323.85 5,839.5 5,783.3 -1,162.4 -139.8 6,029,891.3 469,724.5 6.3 -761.94 MWD+SAG+CA+IIFR+MS(2 6,530.1 54.51 323.70 5,894.4 5,838.2 -1,100.1 -185.5 6,029,953.8 469,679.1 0.2 -685.15 MWD+SAG+CA+IIFR+MS(2 6,624.6 57.53 328.77 5,947.3 5,891.1 -1,035.0 -229.0 6,030,019.1 469,635.8 5.5 -607.74 MWD+SAG+CA+IIFR+MS(2 6,719.8 59.70 331.71 5,996.9 5,940.7 -964.4 -269.3 6,030,089.8 469,595.8 3.5 -528.49 MWD+SAG+CA+IIFR+MS(2 6,814.3 63.73 334.45 6,041.6 5,985.4 -890.2 -306.9 6,030,164.1 469,558.5 5.0 -448.38 MWD+SAG+CA+IIFR+MS(2 6,909.9 66.50 335.68 6,081.9 6,025.7 -811.6 -343.5 6,030,242.9 469,522.3 3.1 -365.73 MWD+SAG+CA+IIFR+MS(2 7,005.3 68.64 335.44 6,118.2 6,062.0 -731.4 -379.9 6,030,323.3 469,486.1 2.3 -281.98 MWD+SAG+CA+IIFR+MS(2 7,099.0 70.17 335.90 6,151.2 6,095.0 -651.4 -416.1 6,030,403.3 469,450.3 1.7 -198.65 MWD+SAG+CA+IIFR+MS(2 7,194.1 72.76 335.62 6,181.4 6,125.2 -569.2 -453.1 6,030,485.7 469,413.7 2.7 -113.08 MWD+SAG+CA+IIFR+MS(2 7,288.5 75.09 336.06 6,207.6 6,151.4 -486.4 -490.2 6,030,568.6 469,376.8 2.5 -26.96 MWD+SAG+CA+IIFR+MS(2 7,384.9 75.80 336.22 6,231.8 6,175.6 -401.1 -528.0 6,030,654.1 469,339.4 0.8 61.46 MWD+SAG+CA+IIFR+MS(2 7,479.4 77.05 336.22 6,254.0 6,197.8 -317.0 -565.0 6,030,738.3 469,302.8 1.3 148.41 MWD+SAG+CA+IIFR+MS(2 7,573.7 76.56 335.63 6,275.5 6,219.3 -233.3 -602.4 6,030,822.2 469,265.7 0.8 235.43 MWD+SAG+CA+IIFR+MS(2 7,669.3 76.55 335.06 6,297.7 6,241.5 -148.7 -641.3 6,030,906.9 469,227.2 0.6 324.00 MWD+SAG+CA+IIFR+MS(2 7,742.1 76.74 334.66 6,314.6 6,258.4 -84.6 -671.4 6,030,971.2 469,197.4 0.6 391.59 MWD+SAG+CA+IIFR+MS(2 7,806.2 78.38 335.03 6,328.4 6,272.2 -27.9 -698.0 6,031,027.9 469,171.0 2.6 451.31 MWD+SAG+CA+IIFR+MS(2 7,849.4 79.05 334.81 6,336.8 6,280.6 10.4 -715.9 6,031,066.3 469,153.2 1.6 491.70 MWD+SAG+CA+IIFR+MS(2 7,946.6 81.05 334.85 6,353.6 6,297.4 97.0 -756.6 6,031,153.1 469,112.9 2.1 583.04 MWD+SAG+CA+IIFR+MS(2 8,001.1 83.35 335.05 6,361.0 6,304.8 146.0 -779.5 6,031,202.1 469,090.2 4.2 634.58 MWD+SAG+CA+IIFR+MS(2 8,043.2 83.22 334.65 6,365.9 6,309.7 183.8 -797.3 6,031,240.0 469,072.6 1.0 674.48 MWD+SAG+CA+IIFR+MS(2 8,136.2 86.09 332.82 6,374.6 6,318.4 266.8 -838.2 6,031,323.2 469,032.0 3.7 763.34 MWD+SAG+CA+IIFR+MS(2 8,233.2 87.57 330.41 6,380.0 6,323.8 352.0 -884.3 6,031,408.6 468,986.3 2.9 857.23 MWD+SAG+CA+IIFR+MS(2 8,328.8 90.04 327.36 6,381.9 6,325.7 433.8 -933.6 6,031,490.6 468,937.2 4.1 950.87 MWD+SAG+CA+IIFR+MS(2 6/11/2009 11:04:48AM Page 4 COMPASS 2003.16 Build 428 . - Halliburton Company Definitive Survey Report Company: Well Planning-Pioneer-Oooguruk Local Co-ordinate Reference: Well ODSN-37-Slot ODS-37 Project: Oooguruk Developement TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Well: ODSN-37 North Reference: True Wellbore: ODSN-37 PN8 Survey Calculation Method: Minimum Curvature Design: ODSN-37 PN8 Surveys Database: .Pioneer Alaska Survey Map Map Vertical MD Inc Azi ND TVDSS +NI-S +El-W Northing Easting DLS Section (ft) (7) (bearin (ft) (ft) (ft) (ft) (ft) (ft) (11001 (ft) Survey Tool Name 8,426.3 89.66 323.54 6,382.2 6,326.0 514.1 -988.9 6,031,571.1 468,882.3 3.9 1,047.43 MWD+SAG+CA+IIFR+MS(2 8,522.6 88.18 321.16 6,384.0 6,327.8 590.4 -1,047.7 6,031,647.6 468,823.8 2.9 1,143.38 MWD+SAG+CA+IIFR+MS(2 8,618.2 91.63 317.75 6,384.2 6,328.0 663.0 -1,109.8 6,031,720.4 468,762.0 5.1 1,238.84 MWD+SAG+CA+IIFR+MS(2 8,710.5 91.70 317.81 6,381.5 6,325.3 731.3 -1,171.9 6,031,789.0 468,700.2 0.1 1,331.18 MWD+SAG+CA+I1FR+MS(2 8,811.3 92.94 317.57 6,377.4 6,321.2 805.8 -1,239.7 6,031,863.7 468,632.7 1.3 1,431.87 MWD+SAG+CA+IIFR+MS(2 8,910.0 91.63 317.22 6,373.5 6,317.3 878.4 -1,306.5 6,031,936.6 468,566.3 1.4 1,530.52 MWD+SAG+CA+IIFR+MS(2 9,006.4 89.78 315.51 6,372.3 6,316.1 948.2 -1,372.9 6,032,006.6 468,500.1 2.6 1,626.85 MWD+SAG+CA+IIFR+MS(2 9,104.0 89.54 313.05 6,372.9 6,316.7 1,016.3 -1,442.8 6,032,075.0 468,430.5 2.5 1,724.28 MWD+SAG+CA+IIFR+MS(2 9,199.6 89.60 315.51 6,373.6 6,317.4 1,083.0 -1,511.3 6,032,142.1 468,362.3 2.6 1,819.76 MWD+SAG+CA+IIFR+MS(2 9,296.6 89.66 315.64 6,374.2 6,318.0 1,152.3 -1,579.1 6,032,211.6 468,294.7 0.1 1,916.67 MWD+SAG+CA+IIFR+MS(2 , 9,391.1 91.27 316.54 6,373.4 6,317.2 1,220.4 -1,644.7 6,032,279.9 468,229.5 2.0 2,011.13 MWD+SAG+CA+IIFR+MS(2 9,485.4 90.15 316.64 6,372.3 6,316.1 1,288.8 -1,709.4 6,032,348.6 468,165.0 1.2 2,105.39 MWD+SAG+CA+IIFR+MS(2 9,532.1 92.51 315.31 6,371.2 6,315.0 1,322.4 -1,741.9 6,032,382.4 468,132.6 5.8 2,152.10 MWD+SAG+CA+IIFR+MS(2 9,582.1 93.80 314.56 6,368.4 6,312.2 1,357.7 -1,777.2 6,032,417.7 468,097.5 3.0 2,201.92 MWD+SAG+CA+IIFR+MS(2 9,678.9 94.11 316.48 6,361.8 6,305.6 1,426.6 -1,844.9 6,032,486.9 468,030.1 2.0 2,298.45 MWD+SAG+CA+IIFR+MS(2 9,775.6 95.22 317.74 6,353.9 6,297.7 1,497.2 -1,910.5 6,032,557.8 467,964.8 1.7 2,394.84 MWD+SAG+CA+1IFR+MS(2 9,818.0 95.91 318.89 6,349.8 6,293.6 1,528.7 -1,938.5 6,032,589.4 467,936.9 3.2 2,437.01 MWD+SAG+CA+IIFR+MS(2 9,871.3 93.97 319.01 6,345.2 6,289.0 1,568.8 -1,973.4 6,032,629.6 467,902.1 3.6 2,490.14 MWD+SAG+CA+1IFR+MS(2 9,969.9 94.10 321.10 6,338.3 6,282.1 1,644.2 -2,036.6 6,032,705.2 467,839.3 2.1 2,588.38 MWD+SAG+CA+IIFR+MS(2 10,066.1 93.61 322.45 6,331.8 6,275.6 1,719.6 -2,096.0 6,032,780.9 467,780.2 1.5 2,684.09 MWD+SAG+CA+IIFR+MS(2 10,161.5 92.68 322.67 6,326.6 6,270.4 1,795.2 -2,153.9 6,032,856.7 467,722.6 1.0 2,778.93 MWD+SAG+CA+IIFR+MS(2 10,258.5 91.88 322.14 6,322.7 6,266.5 1,872.0 -2,213.0 6,032,933.8 467,663.8 1.0 2,875.51 MWD+SAG+CA+IIFR+MS(2 10,354.8 91.14 319.54 6,320.2 6,264.0 1,946.6 -2,273.8 6,033,008.6 467,603.3 2.8 2,971.61 MWD+SAG+CA+IIFR+MS(2 10,451.8 90.89 319.07 6,318.4 6,262.2 2,020.1 -2,337.0 6,033,082.4 467,540.4 0.5 3,068.51 MWD+SAG+CA+IIFR+MS(2 10,547.6 90.28 322.09 6,317.5 6,261.3 2,094.2 -2,397.9 6,033,156.7 467,479.9 3.2 3,164.20 MWD+SAG+CA+IIFR+MS(2 10,644.5 89.35 320.33 6,317.8 6,261.6 2,169.7 -2,458.6 6,033,232.4 467,419.5 2.1 3,260.87 MWD+SAG+CA+IIFR+MS(2 10,740.4 91.64 320.47 6,316.9 6,260.7 2,243.5 -2,519.6 6,033,306.5 467,358.7 2.4 3,356.59 MWD+SAG+CA+IIFR+MS(2 10,836.3 90.77 321.67 6,314.9 6,258.7 2,318.2 -2,579.9 6,033,381.4 467,298.7 1.5 3,452.34 MWD+SAG+CA+IIFR+MS(2 10,935.0 90.89 320.04 6,313.5 6,257.3 2,394.6 -2,642.2 6,033,458.1 467,236.8 1.7 3,550.79 MWD+SAG+CA+IIFR+MS(2 11,031.7 90.03 319.14 6,312.7 6,256.5 2,468.3 -2,704.9 6,033,532.0 467,174.4 1.3 3,647.49 MWD+SAG+CA+IIFR+MS(2 11,127.9 90.77 320.21 6,312.1 6,255.9 2,541.6 -2,767.1 6,033,605.6 467,112.5 1.4 3,743.56 MWD+SAG+CA+IIFR+MS(2 11,224.8 89.53 319.55 6,311.8 6,255.6 2,615.8 -2,829.6 6,033,679.9 467,050.3 1.4 3,840.41 MWD+SAG+CA+1IFR+MS(2 11,320.3 90.34 321.71 6,311.9 6,255.7 2,689.6 -2,890.2 6,033,754.0 466,990.1 2.4 3,935.73 MWD+SAG+CA+IIFR+MS(2 11,416.5 87.74 323.20 6,313.5 6,257.3 2,765.8 -2,948.8 6,033,830.5 466,931.8 3.1 4,031.54 MWD+SAG+CA+IIFR+MS(2 11,514.0 87.44 322.58 6,317.6 6,261.4 2,843.5 -3,007.6 6,033,908.4 466,873.3 0.7 4,128.55 MWD+SAG+CA+IIFR+MS(2 11,610.0 86.57 321.19 6,322.6 6,266.4 2,918.9 -3,066.7 6,033,984.0 466,814.4 1.7 4,224.10 MWD+SAG+CA+IIFR+MS(2 11,705.3 85.82 321.71 6,329.0 6,272.8 2,993.3 -3,126.0 6,034,058.7 466,755.5 1.0 4,318.99 MWD+SAG+CA+IIFR+MS(2 11,800.2 85.89 320.95 6,335.8 6,279.6 3,067.2 -3,185.1 6,034,132.8 466,696.7 0.8 4,413.39 MWD+SAG+CA+IIFR+MS(2 11,897.1 84.77 320.72 6,343.7 6,287.5 3,142.1 -3,246.1 6,034,207.9 466,636.0 1.2 4,509.83 MWD+SAG+CA+IIFR+MS(2 11,934.6 84.46 321.11 6,347.2 6,291.0 3,171.1 -3,269.7 6,034,237.0 466,612.6 1.3 4,547.08 MWD+SAG+CA+IIFR+MS(2 6/11/2009 11:04.:48AM Page 5 COMPASS 2003.16 Build 428 Halliburton Company Definitive Survey Report Company: Well Planning-Pioneer-Oooguruk Local Co-ordinate Reference: Well ODSN-37-Slot ODS-37 Project: Oooguruk Developement TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Well: ODSN-37 North Reference: True Wellbore: ODSN-37 PN8 Survey Calculation Method: Minimum Curvature Design: ODSN-37 PN8 Surveys Database: .Pioneer Alaska Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +El-W Northing Easting DLS Section (ft) (?) (bearin (ft) (ft) (ft) (ft) (ft) (ft) (°1100') (ft) Survey Tool Name 11,995.4 86.40 320.06 6,352.1 6,295.9 3,217.8 -3,308.1 6,034,283.9 466,574.3 3.6 4,607.55 MWD+SAG+CA+1IFR+MS(2 12,090.4 86.51 320.27 6,357.9 6,301.7 3,290.7 -3,368.9 6,034,357.0 466,513.8 0.2 4,702.30 MWD+SAG+CA+1IFR+MS(2 12,186.0 88.31 320.29 6,362.3 6,306.1 3,364.2 -3,429.9 6,034,430.7 466,453.1 1.9 4,797.70 MWD+SAG+CA+1IFR+MS(2 12,283.7 89.54 319.82 6,364.1 6,307.9 3,439.0 -3,492.6 6,034,505.8 466,390.7 1.3 4,895.26 MWD+SAG+CA+IIFR+MS(2 12,381.4 91.58 318.84 6,363.1 6,306.9 3,513.1 -3,556.3 6,034,580.1 466,327.4 2.3 4,992.87 MWD+SAG+CA+IIFR+MS(2 12,477.1 90.15 317.74 6,361.7 6,305.5 3,584.6 -3,620.0 6,034,651.9 466,263.9 1.9 5,088.63 MWD+SAG+CA+IIFR+MS(2 12,575.4 91.02 319.71 6,360.7 6,304.5 3,658.4 -3,684.8 6,034,725.9 466,199.5 2.2 5,186.81 MWD+SAG+CA+IIFR+MS(2 12,668.7 91.64 320.60 6,358.5 6,302.3 3,730.1 -3,744.6 6,034,797.8 466,140.0 1.2 5,280.05 MWD+SAG+CA+IIFR+MS(2 12,763.3 91.70 320.81 6,355.8 6,299.6 3,803.2 -3,804.4 6,034,871.2 466,080.4 0.2 5,374.44 MWD+SAG+CA+1IFR+MS(2 ' 12,860.9 90.83 322.16 6,353.6 6,297.4 3,879.6 -3,865.2 6,034,947.8 466,020.0 1.6 5,471.76 MWD+SAG+CA+IIFR+MS(2 12,958.1 92.13 321.51 6,351.1 6,294.9 3,956.0 -3,925.3 6,035,024.5 465,960.2 1.5 5,568.68 MWD+SAG+CA+IIFR+MS(2 13,052.5 93.80 321.90 6,346.2 6,290.0 4,029.9 -3,983.7 6,035,098.7 465,902.1 1.8 5,662.65 MWD+SAG+CA+IIFR+MS(2 13,152.4 94.73 321.66 6,338.8 6,282.6 4,108.2 -4,045.3 6,035,177.2 465,840.8 1.0 5,761.99 MWD+SAG+CA+IIFR+MS(2 13,248.2 95.47 321.28 6,330.3 6,274.1 4,182.9 -4,104.7 6,035,252.0 465,781.7 0.9 5,857.19 MWD+SAG+CA+IIFR+MS(2 13,318.5 96.65 320.95 6,322.9 6,266.7 4,237.2 -4,148.6 6,035,306.6 465,738.0 1.7 5,926.89 MWD+SAG+CA+IIFR+MS(2 13,343.2 96.40 321.09 6,320.1 6,263.9 4,256.4 -4,164.1 6,035,325.8 465,722.7 1.2 5,951.44 MWD+SAG+CA+IIFR+MS(2 13,440.2 95.52 321.50 6,310.0 6,253.8 4,331.7 -4,224.4 6,035,401.3 465,662.6 1.0 6,047.73 MWD+SAG+CA+IIFR+MS(2 13,507.7 93.73 319.81 6,304.5 6,248.3 4,383.6 -4,267.0 6,035,453.4 465,620.2 3.6 6,114.82 MWD+SAG+CA+IIFR+MS(2 13,538.5 93.30 319.62 6,302.6 6,246.4 4,407.1 -4,286.9 6,035,477.0 465,600.4 1.5 6,145.55 MWD+SAG+CA+IIFR+MS(2 13,635.4 91.69 319.30 6,298.4 6,242.2 4,480.7 -4,349.9 6,035,550.9 465,537.8 1.7 6,242.37 MWD+SAG+CA+1IFR+MS(2 13,731.3 90.89 317.26 6,296.3 6,240.1 4,552.2 -4,413.6 6,035,622.6 465,474.3 2.3 6,338.17 MWD+SAG+CA+IIFR+MS(2 13,828.4 91.57 318.34 6,294.2 6,238.0 4,624.2 -4,478.9 6,035,694.8 465,409.4 1.3 6,435.29 MWD+SAG+CA+IIFR+MS(2 13,924.2 90.89 318.53 6,292.1 6,235.9 4,695.8 -4,542.4 6,035,766.7 465,346.2 0.7 6,531.02 MWD+SAG+CA+IIFR+MS(2 14,020.9 91.20 319.79 6,290.4 6,234.2 4,769.0 -4,605.6 6,035,840.1 465,283.2 1.3 6,627.67 MWD+SAG+CA+IIFR+MS(2 14,117.8 90.46 318.80 6,289.0 6,232.8 4,842.4 -4,668.8 6,035,913.8 465,220.3 1.3 6,724.51 MWD+SAG+CA+IIFR+MS(2 14,214.0 90.52 320.08 6,288.1 6,231.9 4,915.5 -4,731.3 6,035,987.1 465,158.1 1.3 6,820.63 MWD+SAG+CA+IIFR+MS(2 14,258.5 91.02 321.79 6,287.5 6,231.3 4,950.0 -4,759.4 6,036,021.8 465,130.2 4.0 6,865.02 MWD+SAG+CA+1IFR+MS(2 14,295.0 91.02 321.79 6,286.9 6,230.7 4,978.7 -4,782.0 6,036,050.5 465,107.8 0.0 6,901.43 PROJECTED to TD 6/11/2009 11:04:48AM Page 6 COMPASS 2003.16 Build 428 DATA SUBMITTAL COMPLIANCE REPORT 6/14/2013 Permit to Drill 2081570 Well Name /No. 000GURUK NUQ ODSN -37 Operator PIONEER NATURAL RESOURCES AL API No. 50- 703 - 20586 -00-00 MD 14295 TVD 6287 Completion Date 6/15/2009 Completion Status 1 -OIL Current Status 1 -OIL OP REQUIRED INFORMATION Mud Log No Samples No Directional Survey DATA INFORMATION Types Electric or Other Logs Run: LWD, DIR, MWD, GR, EWR, DGR, PWD, ALD, CTN, DDS -R (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 r ED C Las 18351 duction /R Resistivity 109 14295 Open 7/27/2009 ROP, EWR, CTN, ALD, DGR, Temp, Dens w /EWR logs in PDF, EMF and CGM graphics Log ev Induction /Resistivity 2 Col 153 14295 Open 7/27/2009 MD DGR, EWR, CTN, ALD Log v Induction /Resistivity 5 Col 153 14295 Open 7/27/2009 MD DGR, EWR, CTN, ALD Log v Induction /Resistivity 2 Col 153 14295 Open 7/27/2009 TVD DGR, EWR, CTN, / ALD Log ✓ Induction /Resistivity 5 Col 153 14295 Open 7/27/2009 TVD DGR, EWR, CTN, ALD Well Cores /Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments III Cuttings • 5350 7775 1251 tt ✓// ADDITIONAL INFORMATION r Well Cored? Y6 Daily History Received? V N Chips Received? N / , Formation Tops b/ N Analysis 4 14fd--., Received? Comments: DATA SUBMITTAL COMPLIANCE REPORT 6/14/2013 Permit to Drill 2081570 Well Name /No. 000GURUK NUQ ODSN -37 Operator PIONEER NATURAL RESOURCES AL API No. 50- 703 - 20586 -00 -00 MD 14295 TVD 6287 Completion Date 6/15/2009 Completion Status 1 -OIL Current Status 1 -OIL UIC N Compliance Reviewed By: { — Date: 1 `t • i jwa(L o )-37 Regg, James B (DOA) , J 2043(S7o From: Joe Polya [joepolya @yahoo.com] 'Sent: Sunday, June 09, 2013 9:35 PM To: DOA AOGCC Prudhoe Bay Cc: Johnson, Vern; Tirpack, Robert; Hartwig, Dennis; Vaughan, Alex; Klepzig, Rod; Cortez, Joey; Haberthur, Jerry Subject: Reporting BOPE Use to Prevent the Flow of Fluids from ODSN-37 RWO Well Attachments: ODSN-37 Utube Event June 8, 2013.docx To: AOGCC Thanks, Joe Polya Drill Site Leader Pioneer Natural Resources NEB Oooguruk Drill Site i Beaufort Sea, North Slope,Alaska IN.907.670-66061 t :907 244-0668 7:907.670-6673 OoogurukDrillingSupervisor @oxd.com Positional Email Account ioe.polyariPpxd.com Personal Email Account Cccg uruK 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. Time and Date of Event: -2230 hours on June 8, 2013 -Report Comments: Date and Time of BOPE Use: -2245 hours on June 8, 2013 Well: ODSN-37 RWO on Pioneer's Oooguruk Drill Site Permit to Drill Number: 208-157 Sundry Approval roval Number: 313-265 Operator Contact: Robert Tirpack, Pioneer Drilling Superintendent BOPE Component Used: The Annular Preventer was utilized to shut the well in-the annular was re-tested on June 9th for 2-7/8" tubing prior to TIH with the ESP Completion on 2-7/8" tubing. Reason for BOPE Use: Precautionary Step Taken to Secure the Well Upon Observation of Sea Water Exiting out the Drill Pipe while preparing to break and rack back a stand of 4" Drill Pipe. Rig Name: Nabors 19AC Operations Summary: The N19AC Rig Team supporting the Pioneer ODSN-37 RWO while changing out a failed ESP experienced a flow from the drill pipe while tripping out of the hole with a scraper/magnet assembly (-1 bbl of diluted brine). The rig team immediately closed the annular on the 4" drill pipe and stabbed the top drive. SICP and SIDPP were recorded at 0 psi. The well was filled and circulated and confirmed to be static. The annular was opened and operations were resumed. After review by the Rig Team members, Pioneer has concluded that this unplanned fluid release from the drill pipe was the result of a U-Tube condition which occurred immediately after 10 bbls of 8.4 ppg sea water were pumped into the annulus while tripping out of hole--this created an imbalance between the 8.1 ppg fluid in the drill pipe and the 8.4 ppg fluid in the annulus. Details: The Rig Team was TOH with the clean out assembly (7" 26#casing scraper and magnet with an orange peeled circulating sub)with 6 stands left in the hole @ 620' md. Just after filling the hole with 10 bbls*of 8.4 ppg sea water, a stand was TOH in preparation to break out and stand back in derrick. While breaking out the stand with the iron roughneck, fluid was observed coming out of break. ✓ Rig crew made the stand back up and shortly thereafter fluid was observed flowing out of the top of the stand while in derrick. ✓ The driller immediately stabbed the Saver Sub back into the drill pipe and made up same while closing the well in on the annulus by closing the annular preventer. ✓ SICP and SIDPP were both recorded at zero pressure. ✓ The choke was opened to the gas buster and now flow was observed from the well. 30 bbls of 8.4 ppg sea water were circulated into the well when returns were observed at 33 bbls pumped-returns were measured at 8.1 ppg. Continued to circulate 20 additional barrels until the Fluid Density IN = Fluid Density OUT = 8.4 ppg. ✓ Shut down pump and observe well through open choke routed through gas buster and into flow line to pits-Well is Static. ✓ Open annular. Fluid level descended in annulus out of sight**. ✓ Contacted Drilling Manager(on week-end duty) and informed him of U-Tube Event. ✓ Discussed actions to take to prevent reoccurrence of this event in future RWOs***. Notes: *The hole is filled with 1.5 x pipe displacement(5 bbls per five stands in this case) plus 5 barrels per 30 minutes. **The reservoir pressure for the Oi N-37 well is 7.0 ppg EMW(2300 psi). The workover fluid is filtered sea water @ 8.4 ppg. In past workovers Pioneer has experienced tremendous losses throughout the workover(thousands of barrels)which have had a negative impact on the production from the RWO wells. As a result, Pioneer initially kills the well for RWO by bull heading 1.5 x the tubing and 1.5x the annulus volumes and then adding 5 bbls per 30 minutes (10 bbls per hour) to maintain well control. This has proved effective. On a couple occasions we have had down time whereby we have secured the well while repairing surface equipment—this entails closing the annular and stabbing the floor safety valve. This occurred on this well while pulling the completion while diagnosing a fluid clarity issue. The well was secured at 0800 hours and the well was opened again at 2200 hours (14 hours). Prior to opening the well 140 bbls were pumped into the well through the kill line while observing the well for returns through an open choke through the gas buster. This verifies that 10 bbls per hour fill rate (140 bbls/14 hours). ***For future wells, 1.5x the pipe capacity will be circulated prior to TOH for any clean out runs to displace any lighter fluids that enter the pipe while the tubulars are filling while TIH. Also, when TIH with the completion assembly, 1.5x the completion string volume will be circulated at half the distance to pick up packer and prior to picking up the packer to displace any lighter fluids entering the tubing while TIH—the tubing will fill with the kill weight fluids deeper in the well thereafter. Call Joe Polya, Drill Site Leader, Pioneer Natural Resources at 907-670-6606 with any comments, questions or concerns. 44 e • ▪ o I // ,,,� c v THE STATE Alaska • i and Gas w $ �•% � Of C ,- r,. 'ry tion COMMISS1011 GOVERNOR SEAN PARNELL 333 West Seventh Avenue OF Q. Anchorage, Alaska 99501 -3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Alex Vaughan Sr. Drilling Engineer Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, AK 99501 0 B a'v Re: Oooguruk Field, Nuiqsut Oil Pool, ODSN -37 Sundry Number: 313 -265 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 7 day of June, 2013. Encl. la , t ' • • 1 II STATE OF ALASKA , 1 4 ALASKA OIL AND GAS CONSERVATION COMMISSION — APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon 0 Plug for Redrill 0 Perforate New Pod 0 Repair Wen 0 Change Approved Program 0 Suspend 0 Plug Perforations 0 Perforate 0 Pull Taring J . Time Extension 0 Operations Shutdown 0 Re-enter Susp. Well 0 Stimulate 0 Alter Casing 0 Other. ESP Chtage•out 15 . 2. Operator Name: 4. Current Well Claw 5. Permit to DM Number Pioneer Natural Resources Alaska, Inc. Exploratory 0 Development in • 208-157 - 3. Address: 700 G Street, Suite 600 Stratigraphic 0 Service 0 6. API Number Anchorage, AK 99501 50 • 7. If perforating: 8. Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? NIA ODSN-37 - Will planned perforations require a spacing exception? Yes 0 No 19 9. Property Designation (Lease Number): 10. Field/Pooffs): ADL 355036 - Oooguruk - Nuiqsut 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): 14,295 • 6287' • 14,281' , 6287' . N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 115' 16" 158' 158' N/A N/A Surface 3109' 9-5/8" 3150' 3012' 5750 psi 3090 psi Intermediate 1 7725' 7" 7764' 6319' 7240 psi 5410 psi Production Liner 6702' 4-1/2" 7581' - 14,283' 6277' - 6287' 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", 6.5# L-80, IBT-M 7307' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): TRSV; 7" x 2-7/8" Pkr; Hyd II Liner Top Pkr 742' MD/742' TVD; 4040' MD/3804' TVD; 7596' MD/6281' TVD 12. Attachments: Description Summary of Proposal El 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Stratigraphic 0 Development EI • Service 0 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 6/1/2013 Oil El . Gas 0 WDSPL 0 Suspended 0 16. Verbal Approval: Date: WINJ 0 GINJ 0 WAG 0 Abandoned 0 Commission Representative: GSTOR 0 SPLUG 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Alex Vaughan, 343-2186 Email alex.vaughanaoxd.com Printed Name Title ntor, 343 Alex Vaughan Sr. Drilling Engineer Prepared By: Kathy Campoa Signature Phone Date 343-2186 5/29/2013 ..._ _ COMMISSION USE ONLY Conditions of approval: Not' mmission so that a representative may witness Sundry Number: 1 _ 2(4) Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other s •(-- 3Saf) r , t ' &r Z;r RBDMS JUN - 5 20134' Spacing Exception Required? Yes 0 No IZI Subsequent Form Required: / APPROVED BY _- Approved by: ----- COMMISSIONER THE COMMISSION Date: '73 //(. 6:3*/ Submit Form and r k) \\,• Form 10 (Revised 10/2012) ApieRpfliao it wrilid' months from date of approval. Attachments in Duplicate '`., Nir't L. c • PIONEER 20 ;3 NATURAL RESOURCES ALASKA : 1, Pioneer . , L4 4 Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, Alaska 99501 Tel: (907) 277 -2700 Fax: (907) 343 -2190 May 29 , 2013 State of Alaska Alaska 00 and Gas Conservation Commission 333 West 7 Avenue, Suite #100 Anchorage, AK 99501 RE: ODSN -37 Sundry Application for ESP Change -Out REF: Permit To Drill # 208 -157 Pioneer Natural Resources, Alaska (PNRA) hereby submits an Application For Sundry request to pull the existing failed ESP on ODSN -37 and replace with a new ESP. See the proposed plan attachments and supporting documentation. Sincerely, V Alex Vaughan Senior Drilling Engineer Attachments: Form 10-403 Supporting information cc: ODSN -37 Well File Ag eer Natural Resources Alaska Inc. ODSN -37 Page 2 AOGCC Form 10 -403, Application For Sundry Approvals Present Well Condition Summary, Box #11 Perforation Depth (MD/TVD) - Attachment 4 -' /2 ", 12.6 #, L -80 Liner - perforated pup jts with 6-1/2" holes @ depths listed: MD TVD 7766' — 7771' 6320' — 6321' 7892' — 7897' 6345' — 6345' 8060' — 8065' 6368' — 6368' 8186' — 8191' 6378' — 6378' 8311' — 8316' 6382' — 6382' 8516' — 8521' 6384' — 6384' 8718' — 8723' 6381' — 6381' 8920' — 8925' 6373' — 6373' 9130' — 9135' 6373' — 6373' 9340' — 9345' 6374' — 6374' 9550' — 9555' 6370' - 6370' 9758' — 9763' 6356' — 6355' 10011' — 10016' 6335' — 6335' 10139' — 10144' 6328' — 6328' 10348' — 10353' 6320' — 6320' 10553' — 10558' 6317' — 6318' 10755' — 10761' 6317' — 6316' 10958' — 10963' 6313' — 6313' 11165' — 11170' 6312' — 6312' 11363' — 11368' 6312' — 6313' 11564' — 11569' 6320' — 6320' 11765' — 11770' 6333' — 6334' 11966' — 11971' 6350' — 6351' 12088' — 12093' 6358' — 6358' 12295' — 12300' 6364' — 6364' 12498' — 12503' 6362' — 6361' 12700' — 12705' 6358' — 6357' 12906' — 12911' 6353' — 6352' 13112' — 13118' 6342' — 6341' 13315' — 13320' 6323' — 6323' 13443' — 13448' 6310' — 6309' 13647' — 13852' 6298' — 6294' 13851' — 13856' 6294' — 6294' 14063' — 14068' 6290' — 6290' 14233' — 14238' 6288' — 6288' Workovellbbjectives and q Plannin 9 ee uirements I Well Name: J ODSN - 37 II Date: I 25 May - 13 Location: J Oooguruk Drill Site 11 Confidential (YIN) J No Workover Type RWO + I Exploratory or Development: J Development I I Well Classification: Producer I I Proposed Start Date: I 11 Jun - 13 ' I AFE Days 8 II AFE Total I $2.6MM Team Members I Engineer Contact Info Well Engineer Alex Vaughan Name Alex Vaughan Well Work Phone Office 907 - 343 -2186 Completion Tim Crumrine Phone CeII 907 -748 -5478 Production Theresa Williams Email alex.vaughan(apxd.corg Drig Super , Tirpack Drig Manager Vem Johnson Reason for Workover: ESP Installation 1 1. Ensure safety of all personnel involved in Pre -Riq, Riq, and Post Riq Operations. Priorities 2. Protect environment from all spills /damage related to well operations. 3. Retum well to service as soon as possible A. Replace ESP B. Minimize fluid loss, Primary RWO: Unweighted brine w/ 50ppm SI and No Biok C Objectives: C. Install OV GLV 200' TVD above ADV D. Flowback through Pioneer test header into flowback tanks following ESP install 1. Well Control Hazards and Concerns 2. Delivery of equipment and tools necessary to perform operation 3. Excessive fluid loss The maximum anticipated surface pressure, assuming gas from surface to 7" shoe MASP at 7,764' MD / 6,319' TVD is estimated at 1,605 psi with a 0.11 psi /ft gas gradient Reservoir Pressure After 30 days of shut -in the anticipated ODSN -37 reservoir pressure is expected to be less than 7 ppg equivalent or 2300 psi at 6,330' TVD (average depth of the lateral section). ti Punch tubing below ESP packer Pre Operations: Bullhead IA and tubing with diesel, Lubricate and bleed accumulated IA gas. Well will be shut in with closed SCSSV, BPV, & Tested tubing hanger pack -off 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 9 g ger Approval Drilling Manager Approval Operations Manager Approval ODSN -36ESP Replacement RV. Planned MD (ft) TVD (ft) Well: ODSN -37 Baker Hughes 16" Conductor 158 158 Set Depth: 7,490 Halliburton Well Head: 9 -5/8 ", 5K, VetcoGray 9-5/8 "40# L -80 BTC, 8.835" ID 3,412 3,029 Job Completion Date: Weatherford Tree: 3 -1/2 ", 5K, Horizontal 7" 26# L -80 BTC -M, 6.276" ID 10,932 5,008 Vetco Gray 4 -1/2" 12.6# L-80 Hyd 521, 3.958" ID 15,767 5,065_ Confirm Length Tool Description Joint Tool/Joint Cumm. Final Depth Number Length Length Top of Tool Inc ( °) ND (usft) DLS ( °/100 Baker 5.85" OD Ce ntralizer 2.00 2.00 7,490.34 77.0 6256 0.8 Motor Ga uge 1.91 3.91 16.80 20.71 7.486.43 7,469.63 77.0 6256 0.8 -� Motor 76.9 6252 1.32 Lower Tandem Seal 6.90 27.61 7,462.73 76.8 6250 1.32 Upper Tandem Seal 6.90 34.51 7,455.83 76.7 6249 1.32 Gas Separator 5.47 39.98 7,450.36 76.7 6247 1.32 Adapter Kit 0.14 40.12 7,450.22 76.7 6247 1.32 J Pump 23.00 63.12 7,427.22 76.4 6242 1.32 1. Bolt on Discharge Head 0.62 63.74 7,426.60 76.4 6242 1.32 2 -7/8" EUE Handling Pup 2.00 65.74 7,424.60 76.3 6241 1.32 $ Discharge Gauge OEM 2.63 68.37 7,421.98 76.3 6241 1.32 t 2 -7/8" EUE Handling Pup 2.00 70.37 7,419.98 76.3 6240 1.32 J Auto Diverter Value 3.35 73.72 7,416.63 76.2 6240 1.32 III II 2 -7/8" EUE x IBT -M Handling Pup 10.00 83.72 7,406.63 76.1 6237 1.32 2.875" 6.5# L -80 IBT -M Joint 17 31.00 610.72 6,879.63 65.6 6070 3.12 2.875" 6.5# L -80 IBT -M Pup Joint 12.00 622.72 6,867.63 65.3 6065 3.12 2.875" x 2.313" X- profile nipple 1.50 624.22 6,866.13 65.2 6064 3.12 2.875" 6.5# L -80 IBT -M Pup Joint 12.00 636.22 6,854.13 64.9 6059 3.12 2.875" 6.5# L -80 IBT -M Joint 1 31.00 667.22 6,823.13 64.0 6046 3.12 2.875" 6.5# L -80 IBT -M Pup Joint 12.00 679.22 6,811.13 63.6 6040 4.97 2.875" x 1.50" GLM, 1/4" OV 8.65 687.87 6,802.48 63.2 6036 4.97 2.875" 6.5# L-80 IBT -M Pup Joint , 12.00 699.87 6,790.48 62.7 6031 4.97 2.875" 6.5# L -80 IBT -M Joint 134 31.00 4,853.87 2,636.48 25.2 2554 1.92 2.875" 6.5# L -80 IBT -M Pup Joint 1 12.00 4,865.87 2,624.48 25.2 2543 1.92 2.875" x 2.313" Xprofile nipple 1.50 4,867.37 2,622.98 25.2 2541 1.92 2875"$.5 #L -801BT-At_im-ltint 12.00 4,879.37 2,610.98 25.2 2531 1.92 II a 2.875" 6.5# L-80 IBT-M Joint ` 1 31.00 4,910.37 2,579.98 25.2 2503 1.92 12.00 4,922.37 2,567.98 25.1 2492 1.2 2.875" x 1.50" GLM, Dummy 8.65 4,931.02 2,559.33 25.0 2484 1.2 O O O 2.875" 6.5# L -80 IBT-M Pup Joint 12.00 4,943.02 2,547.33 24.9 2473 1.2 2.875" 6.5# L -80 IBT -M Joint ~ 1 31.00 4,974.02 2,516.33 24.6 2445 1.2 X -o>.er coupling and pup joint 4.45 4,978.47 2,511.88 24.5 2441 1.2 WFT Hyrow II Packer 4.86 4,983.33 2,507.02 24.5 2436 1.2 X-over coupling and pup joint 14.27 4,997.60 2,492.75 24.3 2423 1.2 2,875" 6 5# L -80 IBT -M Joint 1 31.00 5,028.60 2,461.75 24.0 2395 1.31 2.875" 6.5# L -80 IBT -M Pup Joint 12.00 5,040.60 2,449.75 23.8 2384 1.31 87 " GLM, Shear Valve 8.67 5,049.27 2,441.08 23.7 2376 1.31 IBT-M Pup Joint 12.00 5,061.27 2,429.08 23.6 2365 1.31 2.875" 6.5# L -80 IBT-M Joint 10 31.00 5,371.27 2,119.08 20.3 2077 1.23 L -80 IBT -M Pup Joint 12.00 5,383.27 2,107.08 20.2 2066 1.23 - TRSV 6.70 5,389.97 2,100.38 20.1 2060 1.23 " 12.00 5,401.97 2,088.38 20.0 2049 1.66 2.875" 6.5# L-80 IBT -M Joint 66 31.00 7,447.97 42.38 0.3 42 0.62 CI 2.. 5" IBT -M 0.92 7,448.89 41.46 0.3 42 0.62 5" 9.2# L 80 Pup Joint 7.36 7,456.25 34.10 0.2 34 0.62 Vetco Gray Tubing Hanger 1.54 7,457.79 32.56 0.2 33 0.62 RKB 34.09 7,491.88 -1.53 00 00 00 00 00 00 00 00 SO 00 00 00 00 00 00 00 00 00 00 001 00 00 00 o Date: Revision By: Comments P I ONE �i R 5/29/2013 Alex Vaughan ESP Replacement Original Design L ODSN -37 Producer NATURAIRESOURCESALS(A Well Schematic ESP Completion • • PIONEER NATURAL RESOURCES ODSN -37 RWO Program • Replace Failed ESP Completion Current Completion: 2 -7/8" ESP String at 7,596' MD / 6,281' ND Planned Completion: 2 -7/8" ESP String at 7,596' MD / 6,281' ND AFE# tba, API # 50- 703 - 20586 -00 -00 AOGCC PTD # 208 -157 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: Vem Johnson: Alaska Drilling Manager ODSN -37 ESP Replacement RWO Program Version 2 1 May 29 2013 • S Pre -Riq Regulatory: (Work completed with approved sundry# 313 -250) • 2 -7/8" tubing has been punched directly below the ESP packer (-4039' MD) • Bullhead into the 2 -7/8" x 7" annulus: 120 bbls seawater followed by 60 bbl diesel — • Bullhead down the 2 -7/8" tubing: 12 bbl diesel • Set a BPV in the tubing hanger • Lubricate and bled out gas that migrates to surface in the 2 -7/8" x 7" annulus. • Test tubing hanger pack -off void in well head • Suspended ODSN -37 with the following well control barriers: a. Tubing: i. Closed TRSV ii. BPV b. 2 -7/8" x 7" Annulus: i. 2 -7/8" x 7" ESP Packer (Closed PW) ii. Tested Tubing hanger packoff Pre -Rig 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 ODSN -37 Approved Sundry (PTD) #208 -157 (see program attachments). 4. Read Approved Sundry and ensure that operations are in accordance. Rig Activity: Kill ODSN -37 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 Conoco Seawater with 50 ppm scale inhibition and 0.025% NoBLOK C d. Discuss potential well control issues and ensure they are appropriately communicated to rig crew. 2. MIRU Nabors 19AC over ODSN -37 3. Ensure 2 -7/8" x 7" annulus is dead and stable. Lubricate and bleed as required 4. Install test dart (blanking plug) on top of BPV 5. ND production tree with the following well control barriers in place a. Tubing: i. Closed TRSV ii. BPV w/ Test Dart ODSN -37 ESP Replacement RWO Program Version 2 2 May 29 2013 • • b. 2 -7/8" x 7" Annulus: i. 2 -7/8" x 7" ESP Packer (Closed PVV) ii. Tested Tubing hanger packoff 6. NU BOPE & Test 250 psi low /3500 high according to the test pressures outlined in the AOGCC Permit to Drill. 3500 Ps... "eve" r..- - y' 6-3./3 a. Notify the AOGCC Field Representative 48 hours prior to the BOPE Test. 7. Retrieve the test dart and BPV 8. Open TRSV 9. Bullhead 150% 2 -7/8" tubing volume -67 bbls of seawater a. Completion fluid will be Conoco Seawater with 50 ppm scale inhibition and 0.025% NoBLOK C 10. Monitor well for 30 min and ensure well is dead or on vacuum. Rig Activity: POOH with 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. Drift FOSV. 2. Prep rig floor to pull 2 -7/8" ESP completion. - a. Rack back a joint of contingency 2 -7/8" tubing with cross over to the top drive. b. Ensure FOSV is accessible and in the open position. c. RU HAL control line spooler. d. Identify a person to count and maintain Cannon Clamps. Note on tally location of each Cannon Clamp recovered. e. Inspect 2 -7/8" tubing for scale or corrosion and report on WellView. 3. BOLDS and unseat 2 -7/8" tubing hanger 4. Release 2 -7/8" x 7" ESP packer with a straight pull (See RWO SID). a. Anticipated PU String Hook Weight - Above Packer: 72,000 lbs b. Packer Shear Release: 33,000 lbs c. Anticipated Surface Overpull for Packer Shear Release: 55,000 lbs d. Anticipated Hook weight for Shear Release: 127,000 lbs e. Anticipated Hook Weight - Full String after packer release: 103,000 lbs f. Stretch: 1.7 ft g. 80% Tensile Limit: 165,000 lbs (Contact Rig Superintendent if more than 80% is required) ' 5. Stroke ESP packer to allow elements to relax. 6. Bullhead 150% 2 -7/8" x 7" annulus volume -352 bbls of seawater 7. Monitor well for 30 min and ensure well is dead or on vacuum. • 8. 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) ODSN -37 ESP Replacement RWO Program Version 2 3 May 29 2013 • a. Maintain pressure on WRScSSSV to keep it open until it is recovered. b. Clean all completion equipment at the rig floor with water and WD40. c. Fill hole with 150% tubing displacement plus 10 bbl of seawater every hour. d. If influx is. observed PU contingency joint of 2 -7/8" tubing, close annular and bullhead 1.5 tubing volume to 7" 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. 9. Close blind rams, Clean rig floor and prep to run ESP completion. . a. Continue filling hole with 10 bbl of seawater every hour. Rig Activity: Scraper Cleanout Run 1. RIH with scraper and magnet 500' MD below ESP packer setting depth Rig Activity: RIH with 2 -7/8" ESP Completion 1. Hold pre job meeting a. Centrilift is responsible for tally at rig site. The Tally is to include: • Tubing measurement by joint (composite tubing tally is not acceptable) • Equipment type, Length, OD, ID, Drift & Fishing neck • Clamp or band location b. Tally is to be independently confirmed by Nabors or by designation of CoMan. c. Tally is to be emailed to Alex, Rob, & Tim once compiled for confirmation. 2. Confirm zero pressure below blind ram and open ram a. Continue to fill hole with 10 bbl of seawater every hour. 3. 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" ESP packer running procedure. (See RWO SID) �4. Pick & RIH up 2 -7/8" ESP completion as per tally. a. Continue to fill hole with 10 bbl of seawater every hour. 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 shear out valve installed • Purpose: Freeze protection of the 2 -7/8" x 7" annulus ODSN -37 ESP Replacement RWO Program Version 2 4 May 29th, 2013 • • Weatherford Packer • Install at - 2,500' MD • Primary Purpose: 2 -7/8" x 7" annulus well control safety device • Secondary Purpose: Allows pressure test of the 2 -7/8" x 7" 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. 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 • Primary Purpose: Primary pressure test location for the 2 -7/8" tubing ID. • Secondary Purpose: Allows installation of XXN plug as a junk catcher for GLV swap on GLM # 2 Halliburton Gas Lift Valve #3 • Install 200' TVD above ADV so as to avoid gas overshooting GLM #3 and circulating through the ADV • Run with live Xi" OV GLV installed • Purpose: Primary gas lift location as a backup to the ESP Halliburton X- Nipple • Install one joint below GLM #4 • Primary Purpose: Allows installation of XXN plug as a junk catcher for GLV swap on GLM # 3 • Note: An 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 Rio Activity: Land 2 -718" ESP Completion 1. With 3 -1/2" landing joint and FOSV, land tubing hanger while maintaining 4,500psi on control lines and 500 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. 2. Hold pre job meeting a. Double check that the RHC plug was installed in the X- Nipple below GLM #2 b. Review freeze protection procedures c. Review packer setting procedures 3. Drop ball and rod and displace down to RHC body. a. Drop ball and rod on slickline if the tubing is on vacuum. 4. Fill tubing with seawater set Weatherford GW packer per Weatherford rep instructions a. Slowly increase pressure on the tubing to 3,500 psi (4,000 psi max) and hold for at least 15 minutes. b. Packer slips engage at 1,500 psi. ODSN -37 ESP Replacement RWO Program Version 2 5 May 29 2013 • • 5. Pressure test the tubing. 6. Pressure Test 2 -7/8" x 7" annulus to 2,500 psi for 15 min. 7. Pressure up and shear shearout valve. Pump fluid both directions through the shearout valve to confirm communication. 8. Install BPV in tubing hanger. 9. 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). 10. 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. 11. 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. 12. 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) 13. 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. Secure well. 14. 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. 15. 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. Centrilift to supply CoMan, Alex, & Rob with a digital copy of Tally, Pressure tests, and Post job report prior to leaving location. Post Rid: Slickline 1. RU slickline on ODSN -37 2. Hold pre job meeting 3. RU lubricator and pull BPV 4. Hold open TRSV 5. Circulate diesel down 2 -7/8" x 7" annulus through shearout valve and up 2 -7/8" tubing to surface 6. Pull Shearout valve from GLM #1 and install Dummy 7. Pull Ball and Rod 8. Pull RHC ODSN -37 ESP Replacement RWO Program Version 2 6 May 29 2013 • • 9. Function test TRSV 10. Start up ESP as per Centrilift Procedures The following information can be found in the RWO Supplemental Information Document (RWO SID). General information • WOOPR • Directional surveys • Reservoir pressure model • BOPE schematic • Baker standby fishing tool list • Operations to Drilling handover form • Drilling to operation handover form 2 -7/8" Decompletion • ESP Packer releasing model • As -built Visio schematic • As -built WellView schematic • 2 -7/8" ESP tubing tally 2 -7/8" ESP Completion information • GLM tech sheet • X- Nipple tech sheet • Tubing retrievable safety valve tech sheet • 3 -1/2" tubing hanger tech sheet • Centrilift ESP running procedure ( Oooguruk specific) • Centrilift ESP lesson learned ( Oooguruk specific) • Weatherford ESP packer running procedure (Oooguruk specific) ODSN -37 ESP Replacement RWO Program Version 2 7 May 29 2013 OD4 -37 ESP Completion 410 Run Casing Well Head: 9 -5/8 ", 5K, VetcoGray item # Item MD (ft) TVD (ft) A 1s" Conductor 158 158 Tree: 4 -1/2 ", 5K, Horizontal B 9 -5/8" 40# L -80 BTC, 8.835" ID 3,150 3,012 - C 7" 26# L-80 BTC -M, 6.276" ID 7,764 6,319 Oj D 2 -7/8" 6.5# L-80 IBT-M, 2.441" ID 7,307 6,213 *Estimated TOC 4981' MD - 500 above Torok C All L 1 VetcoGray Tubing Hanger 34 34 -ii:Egall 2 2 -7/8" Wellstar Tubing Retrehsble ScSSSV 742 742 C i 3 GLM #1 - 2 -7/8" x 1 -1/2" (min. 3 jts abow top X nipple) 3,781 3,574 2 -7/8" X Nipple 2.313" I.D. (min. 2 jts above Gas Vent 4 Valve Packer) 3,895 3,675_ 5 WFT 7" x 2 -7/8" Gas Vent Valve Packer (max. TVD 3800') 4,040 3,804 6 GLM #2 - 2 -7/8" x 1 -1/2" (min. 2 jts above XN nipple) 6,796 6,033 7 2 -7/8" X Nipple, 2.313" ID (max. incl. 66 deg) w/ RHC-M PR, 6,909 6,082 8 Automatic Divert Valve (ADV) 7,239 6,194 111 9 ESP m (Pump, Motor, and Jewelry) 7,247 6,196 End of Assembly, 7,308 6,213 1 .. :` `o " ,' '.MD (it) TVD (ft) CBS C� item # Ite 10 WFT PBR Tie Back Sleeve 15ft SN#23682673 7,581 6,277 11 WFT "NTH" Liner Top Pkr 7,596 6,281 12 WFT "PHR" Rotating Hyd Set Liner Hanger 7,597 6,281 • OS 13 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 7,766 6,320 B' 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 7,892 6,345 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,060 6,368 + _ 4-1/2" 12.60# L -80 Hydra Pupjt Oft (Ported w/ 6 1/2 holes) 8,186 6,378 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,311 6,382 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,516 6,384 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,718 6,381 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,920 6,373 1 0 --I 4 -1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,130 6,373 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,340 6,374 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,550 6,370 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,758 6,356 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,011 6,335 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,139 6,328 C ; � 4 -1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,348_ 6,320 J 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,553 6,317 4 -1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,756 6,317 V V 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,958 6,313 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,165 6,312 4-1/2" 12.60# 1-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,363 6,312 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,564 6,320 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,765 6,333 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,966 6,350 C 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,088 6358 4-1/2" 12.60# L-80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 12,295 6, 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,498 6,362 4-1/2" 12.60# 1-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,700 6,358 4-1/2" 12.60# L-80 Hydril Pupjt 48 (Ported w/ 6 1/2 holes) 12,906 6,353 4-1/2" 12.60# L-80 Hydril Pupjt Ott (Ported w/ 6 1/2 holes) 13,112 6,342 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,315 6,323 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,443 6,310 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,647 6,298 hltt)\\%%.........__, 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,851 6,294 4-1/2" 12.60# L-80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 14,063 6,290 a 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,233 6,288 12 lr 14 Ray Oil Tool Silver Bullet Float Shoe (PLUGGED) w/ 4-1/2 I 14,281 6,287 End of Assembly 14,283 6,287 0 1s 0 0 00 00 00 00 00 00 00 ,a 00 00 00 00 00 00 00 00 �- 00 00 00 00 00 00 00 00 Date: Revision By: Comments PIONEER 7-30-2009 TWC ESP Compl Design Post TD I p�I p C p' ^pVA 11 -19 -2009 TWC Removed XN nipple, moved X nipple down ODSN -37 Producer NATUR(. RESQURCESi11ASKA 11 -20 -2009 TWC Item 6 revised to read X nipple, not XN nipple Well Schematic 12 -09 -2009 _ TWC _ As Built _ ESP Completion • ill . Schematic - State Well Name: ODSN -37 P C urrent NATURAL RESOURCES HORIZONTAL - Original Hole, 5/28/2013 3:15:15 PM Well Attributes Vertical schematic (actual) APVUWI Field Name Well Status Total Depth (ftKB) 50- 703 - 20586 -0000 000GURUK UNIT DRILLED 14,295.0 Casing Strings Conductor, 158.0ftKB Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ft. Set Depth... Grade Top Thread WVLen (I... Conductor 16 14.670 43.0 158.0 158.0 X -56 Welded 102.63 Casing Components 3-1 Top (TVO) Item # Item Des Top (ftKB) (ftKB) 00 (m) ID (in) Com 1 -1 Conductor Shoe 43.0 43.0 16 14.670 Surface, 3,149.9ftKB Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ft... Set Depth... Grade Top Thread Wt/Len (I... Surface 9 5/8 8.938 40.5 3,149.9 3,012.3 L -80 BTC 40.00 LA Casing Components Top (TVD) _ . Item # item Des Top (ftKB) (ftKB) OD (in) ID (in) Com Iii... VI 2-1 Hanger Above LOP 40.5 40.5 14 8.938 9/16 2 -2 Hanger Below LOP Pup Jt. 41.4 41.4 9 5/8 8.938 2 -3 9 5/8" 40# Casing 46.7 46.7 9 5/8 8.938 2 -4 9 5/8" Surface Shoe 3,148.3 3,010.8 9 5/8 8.938 Intermediate, 7,764.0ftKB 1 -. Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ft... Set Depth_. Grade Top Thread Wt/Len (L.. ® Intermediate 7 6.276 39.5 7,764.0 6,319.5 L -80 BTC -M 26.00 Casing Components Top (TVD) Item # Item Des Top (ftKB) (ftKB) OD (in) ID (in) Corn 3 -1 VG Hgr 39.5 39.5 7 6.276 • • 13-21 3 -2 Pupjt 40.1 40.1 7 6.276 3 -3 Casing Joints 44.5 44.5 7 6.276 3-4 HES Super Float II 7,676.3 6,299.4 7 6.276 3 -5 Casing Joints 7,677.3 6,299.6 7 6.276 3 -6 7" Intermediate Shoe 7,762.4 6,319.1 7 6.276 Liner, 14,283.0ftKB 13 -3 . Casing Description OD (in) ID (in) Top (ftKB) Set Depth (ft _. Set Depth ... Grade Top Thread WVLen (I... Liner 41/2 3.958 7,580.8 14,283.0 6,287.1 L -80 Wedge 12.60 2-21 521 Casing Components Top (TVD) Item # Item Des Top (ftKB) (ftKB) OD (m) ID (m) Corn 4 -1 WFT "PBR Tie -back Sleeve 7,580.8 6,277.2 ' 5 3.958 4 -2 WFT "NTH" Liner Top Pkr 5" 7,596.2 6,280.7 5 3.958 x 7" 4 -3 WFT "PHR" Liner Hgr 5" x 7,599.5 6,281.5 5 3.958 • 7" 4 -4 XO (5" VAM Top HT Box x 4 7,603.0 6.282.3 5 3.958 1 1-1) -1/2" Hydril 521 Pin) 4 -5 Hydril 521 Tbg 7,603.8 6,282.5 4 1/2 3.958 4 -6 4 -1/2" Perforated Pup Jt 7,765.9 6,319.9 4 1/2 3.958 13 -4 4 -7 Hydril 521 Tbg 7,770.5 6,320.9 41/2 3.958 4 -8 4 -1/2" Perforated Pup Jt 7,891.9 6,344.6 4 1/2 3.958 4 -9 Hydril 521 Tbg 7,896.6 6,345.4 4 1/2 3.958 4 -10 4 -1/2" Perforated Pup Jt 8,059.4 6,367.8 4 1/2 3.958 �3 -5 4 -11 Hydril 521 Tbg 8,064.1 6,368.3 4 1/2 3.958 4 -12 4 -1/2" Perforated Pup Jt 8,186.1 6,377.7 4 1/2 3.958 4 -13 Hydril 521 Tbg 8,190.8 6,377.9 4 1/2 3.958 3 -6 4 -14 4 -1/2" Perforated Pup Jt 8,310.5 6,381.9 4 1/2 3.958 4 -15 Hydril 521 Tbg 8,315.1 6,381.9 4 1/2 3.958 4 -16 4 -1/2" Perforated Pup Jt 8,515.6 6,383.8 4 1/2 3.958 13-71 4 -17 Hydri( 521 Tbg 8,520.3 6,383.9 4 1/2 3.958 4 -18 4 -1/2' Perforated Pup Jt 8,718.2 6,381.3 4 1/2 3.958 4 -19 Hydril 521 Tbg 8,722.9 6,381.1 4 1/2 3.958 I 3-3 4 -20 4 -1/2" Perforated Pup Jt 8,920.1 6,373.2 4 1/2 3.958 • 2 -3 13 -81 4 -21 Hydril 521 Tbg 8,924.8 6,373.1 4 1/2 3.958 Page 1/4 Report Printed: 5/28/2013 • C urrent Schematic - State • Well Name: ODSN -37 PIONEER NATURAL RESOURCES HORIZONTAL - Original Hole, 5/28/2013 3:15:19 PM Casing Components Vertical schematic (actual) Top (rVD) Item p Item Des Top (ftK8) (11KB) OD (in) ID (in) Corn 4 -22 4 -1/2" Perforated Pup Jt 9,130.1 6,373.1 4 1/2 3.958 13 2 -3 4 -23 Hydril 521 Tbg 9,134.7 6,373.1 4 1/2 3.958 4 -24 4 -1/2" Perforated Pup Jt 9,339.5 6,374.2 4 1/2 3.958 2 4 -25 Hydril 521 Tbg 9,344.1 6,374.2 4 1/2 3.958 4 -26 4 -1/2" Perforated Pup Jt 9,549.7 6,370.3 4 1/2 3.958 4 -27 Hydril 521 Tbg 9,554.4 6,370.1 4 1/2 3.958 4 -28 4 -1/2" Perforated Pup Jt 9,757.8 6,355.5 4 1/2 3.958 4 -29 Hydril 521 Tbg 9,762.5 6,355.1 4 1/2 3.958 13 -91 4 -30 4 -1/2" Perforated Pup Jt 10,010.5 6,335.4 4 1/2 3.958 4 -31 Hydril 521 Tbg 10,015.1 6,335.1 4 1/2 3.958 13- 101---. 4 -32 4 -1/2" Perforated Pup Jt 10,139.1 6,327.6 4 1/2 3.958 4 -33 Hydril 521 Tbg 10,143.8 6,327.4 4 1/2 3.958 4 -34 4 -1/2" Perforated Pup Jt 10,347.9 6,320.3 4 1/2 3.958 13-111 4 -35 Hydril 521 Tbg 10,352.6 6,320.2 4 1/2 3.958 4 -36 4 -1/2" Perforated Pup Jt 10,552.8 6,317.4 4 1/2 3.958 13 12� 4 -37 Hydril 521 Tbg 10,557.4 6,317.4 4 1/2 3.958 4 -38 4 -1/2" Perforated Pup Jt 10,755.4 6,316.5 4 1/2 3.958 3 -13 4 -39 Hydril 521 Tbg 10,760.0 6,316.4 4 1/2 3.958 4 -40 4 -1/2" Perforated Pup Jt 10,958.0 6,313.2 4 1/2 3.958 4-41 Hydril 521 Tbg 10,962 7 6,313.1 4 1/2 3.958 ISM 4 -42 4 -1/2" Perforated Pup Jt 11,164.6 6,311.7 4 1/2 3.958 4-43 Hydril 521 Tbg 11,169.2 6,311.7 4 1/2 3.958 13 -151 r 4 -44 4 -1/2" Perforated Pup Jt 11,363.0 6,312.1 4 1/2 3.958 4-45 Hydril 521 Tbg 11.367.7 6,312.2 41/2 3.958 i- 4 -46 4 -1/2" Perforated Pup Jt 11,563.5 6,320.0 4 1/2 3.958 13 -161 • �3 -31 4-47 Hydril 521 Tbg 11,568.2 6,320.3 4 1/2 3.958 4 -48 4 -1/2" Perforated Pup Jt 11,764.6 6,333.3 4 1/2 3.958 3 -17 4-49 Hydril 521 Tbg 11,769.3 965.7 6,333.6 4 1/2 3.958 4 -50 4 -1/2" Perforated Pup Jt 1111,,976695..73 1, 6,350.0 4 1/2 3.958 3 -18 ii 4-51 Hydril 521 Tbg 11,970.3 6,350 3 4 1/2 3.958 A 4 -52 4 -1/2" Perforated Pup Jt 12,087.6 6,357.8 4 1/2 3.958 4 -53 Hydril 521 Tbg 12,092.3 6.358.1 4 1/2 3.958 13 -191 4 -54 4 -1/2" Perforated Pup Jt 12,294.5 6,364.2 4 1/2 3.958 4 -55 4 -1/2" Perforated Pup Jt 12,299.2 6,364.2 4 1/2 3.958 13 -201 4 -56 Hydril 521 Tbg 12,303.9 6,364.2 4 1/2 3.958 4 -57 4 -1/2" Perforated Pup Jt 12,502.4 6,361.6 4 1/2 3.958 4 -58 Hydril 521 Tbg 12,507.1 6,361.5 41/2 3.958 13-211 4 -59 4 -1/2" Perforated Pup Jt 12,704.1 6.357.5 4 1/2 3.958 4 -60 Hydril 521 Tbg 12,708.8 6,357.4 4 1/2 3.958 13 -22I I t 4 -61 4 -1/2" Perforated Pup Jt 12,910.9 6,352.6 4 1/2 3.958 4 -62 Hydril 521 Tbg 12,915.5 6,352.5 4 1/2 3.958 13 -231 t 4 -63 4 -1/2" Perforated Pup Jt 13,116.8 6,341.6 4 1/2 3.958 4 -64 Hydril 521 Tbg 13,121.5 6,341.3 4 1/2 3.958 4 -65 4 -1/2" Perforated Pup Jt 13,319.1 6,322.8 4 1/2 3.958 13 -241 • 4 -66 Hydril 521 Tbg 13,323.8 6,322.2 4 1/2 3.958 4 -67 4 -1/2" Perforated Pup Jt 13,447.8 6,309.3 4 1/2 3.958 1 251 4 -68 Hydril 521 Tbg 13,452.4 6,308.8 4 1/2 3.958 4 -69 4 -1/2" Perforated Pup Jt 13.651.1 6.298.0 4 1/2 3.958 4 -70 Hydril 521 Tbg 13,655.8 6,297.8 41/2 3.958 ' 13 -261 4 -71 4 -1/2" Perforated Pup Jt 13,855.7 6,293.5 4 1/2 3.958 4 -72 Hydril 521 Tbg 13,860.4 6,293.3 4 1/2 3.958 ® 4 -73 Hydril 521 Tbg 13,901.7 6,292.5 4 1/2 3.958 _ 4 -74 4 -1/2" Perforated Pup Jt 14,067.1 6,289.5 4 1/2 3.958 13.281 4 -75 Hydril 521 Tbg 14,071.7 6,289.4 4 1/2 3.958 4 -76 4 -1/2" Perforated Pup Jt 14,233.2 6,287.9 4 1/2 3.958 4 -77 Hydril 521 Tbg 14,237.9 6,287.8 4 1/2 3.958 13 -291 Page 2/4 Report Printed: 5/28/2013 PIONEER Current Schematic - State Well Name: ODSN -37 NATURAL RESOURCES HORIZONTAL - Original Hole, 5/28/2013 3:15:23 PM Casing Components Vertical schematic (actual) Top (TVD) - Item # item Des Top (BKB) (MKS) OD (in) ID (in) Corn 3 -29' 4 -78 XO (Hydril 521 Box x BTC -M 14,279.3 6,287.1 4 1/2 3.958 33 30 i Pin) . 3 -31 - 4 -79 XO (IBT -M Pin x BTC -M 14,280.5 6,287.1 4 1/2 3.958 3-32 - Box) 3 -33- 4 -80 4 1/2" Production Liner Shoe 14,281.1 6,287.1 4 1/2 3.958 Silver Bullet Float 3-34 - Shoe w/Torque Ring 3 -35 1..4 , ! Tubing Strings Tubing Description String M... ID (in) Top ((KB) Set Depth (f . Set Dept... Wt (lb/ft) Grade Top Thread Tubingcti Secondary 2 7/8 2.441 33.2 7,307.0 6,212.3 6.50 L -80 IBT -M �• ® Tubing Components Item* Item Des Top (ND) • 14 _ Top (19(B) (rtKB) OD (in) ID (in) _ Corn 3 -1 Vetco Gray Hngr w /3.5' IBT- 33.2 33.2 3 1/2 2.441 ' =w , 3 -4 M box ® 3 -2 3.5" 9.3 L -80 IBT -M pup pin 34.8 34.8 3 1/2 2.441 ® x pin 3 -6 3 -3 X -O 3.5" IBT -M box x 2.875" 42.7 42.7 3 1/2 2.441 IBT pin E. 4 -6 3 -4 Tubing 44.1 44.1 2 7/8 2.441 t . 3 -5 2.875" L -80 IBT -M Pup jt 735.0 734.9 2 7/8 2.441 ft 4 -8 4-9 3 -6 HES Wellstar TRSV w/ 741.3 741.2 2 7/8 2.441 2.313 "X" nipple j; I 4 -10 3 -7 2.875" L -80 IBT -M Pup jt 745.6 745.5 2 7/8 2.441 ® 3 -8 Tubing 749.3 749.1 2 7/8 2.441 I. 3 -9 2.875" L -80 IBT -M Pup jt 3,774.6 3,568.6 2 7/8 2.441 3 -10 2.875" x 1.5" FO -2 GLM 3,780.4 3,573.7 2 7/8 2.441 44 -15 3-11 2.875" L -80 IBT -M Pup jt 3,790.0 3,582.2 2 7/8 2.441 : 4 -16 3 -12 Tubing 3,793.9 3,585.6 2 7/8 2.441 MIS 3 -13 2.875" L -80 IBT -M Pup jt 3,888.1 3,668.9 2 7/8 2.441 I 4 -18 3 -14 HES 2.313 "X" nipple w/ 3,894 2 3,674.3 2 7/8 2.441 4.19 RHC -M plug 4 -20 3 -15 2.875" L -80 IBT -M Pup jt 3,895.5 3,675.5 2 7/8 2.441 Ili UM 3 -16 Tubing 3,899.3 3,678.9 2 7/8 2.441 #; MEI 3 -17 X -O IBT -M box x New Vam 4,025.3 3,790.8 2 7/8 2.441 II 4 -23 pin •PI: 4 -24 3 -18 WFT 7" x 2.875" Hydro 2 4,039.4 3,803.3 2 7/8 2.441 al MEI Retry Pkr w. ESP gas vent #li, 4 -26 3 -19 X -O New Vam box x IBT -M 4,045.0 3,808.3 2 7/8 2.441 III {4 -271 pin f `; 4.28 3 -20 2.875" L-80 IBT-M Pup jt 4,051.5 3,814.2 2 7/8 2.441 4-29 3 -21 Tubing 4,061.7 3,823.3 2 7/8 2.441 it, 4 -30 3 -22 2.875" L -80 IBT -M Pup jt 6,789.4 6,030.4 2 7/8 2.441 ' LEI 3 -23 2.875" x 1.5" FO -2 GLM 6,795.2 6,033.1 2 7/8 2.441 i� 3 -24 2.875" L -80 IBT -M Pup jt 6,804.8 6,037.4 2 7/8 2.441 14 -331 3 -25 Tubing 6,808.7 6,039.1 2 7/8 2.441 3 -26 X -O EUE 8rd pin x IBT -M 6,902.4 6,078.8 2 7/8 2.441 MEI collar • t 4 -36 3 -27 HES 2.313 "X" nipple w/ 6,908.5 6,081.3 2 7/8 2.441 iii ME RHC -M plug 4 -38 3 -28 X -O IBT -M pin x EUE 8rd 6,909.8 6,081.8 2 7/8 2.441 III 4 -39 collar :1:1i; 4 -40 3 -29 Tubing 6,913.7 6,083.3 27/8 2.441 III 4 -41 3 -30 X -O EUE 8rd pin x IBT -M collar 7,231.8 6,192.3 2 7/8 2.441 4 -42 i 1111 4 -43 3 -31 BHI Centrilift ADV 7,237.9 6,194.0 2 7/8 2.441 !.: "' MO 3 -32 2.875" 6.5 L -80 EUE 8rd 7,241.1 6,194.9 2 7/8 2.441 III MEI Pup jt w /collar ':.:Eli 4 - 46 3 -33 BHI Centrilift Discharge 7,242.9 6,195.4 2 7/8 2.441 ii ECU gauge 4-48 3 -34 BHI Centrilift Discharge 7,245.4 6,196.1 2 7/8 2.441 � 4-49 Head Page 3/4 Report Printed: 5/28/2013 • C urrent Schematic - State Well Name: ODSN -37 PIONEER • NATURAL RESOURCES HORIZONTAL - Original Hole, 5/28/2013 3:15:47 PM Tubing Components Vertical schematic (actual) Item # Item Des Top (ftKA) T c KB D) OD (In) ID (m) Com 14 -491 3 -35 BHI Centrilift ESP Pump 7,245.9 6,196.2 2 7/8 2.441 Asst' � 14-501 14-511 4" LIES 14 -531 roAl 1 -54 IL 31 14-551 al 14 -561 : 1 i0 P. j 14 -571 ; 14 -581 C' lil �t 0 4 -59 ill 01(I 14 -601 at0i 1 0 14-611 i0t1 14 -621 1>; 4 -63 14-641 i . 4 -65 ol. 14 -661 o 14 -671 ■I,I 14 -681 101 14 -691 iol 14 -701 10 ii0i' 14 -711 101, 14 -721 14 -731 t o o t ' , 14 -741 ItO 14 -751 flOir 0 4 -76 14 -771 14 -781 14 -791 14 -801 Page 4/4 Report Printed: 5/28/2013 PIONEER • Tubing Tally • NATURAL RESOURCES Des: T ubing - Secondary Production, Set Depth: 7,307.0ftKB Well Name: ODSN -37 API /UWI Surface Legal Location LicenserLease Number Reid Name State 50 703 - 20586 - 0000 2937' FSL, 1129' FEL, Sec 11, T13N, R7E, UM 208 - 157 000GURUK UNIT ALASKA Well Profile Original KB Elevation (ft) KB -Ground Distance (ft) KB- Casing Range Balance (ft) KB-Tubing Head Distance (it) HORIZONTAL 56.20 42.70 19.19 22.30 Tubing Run Tally Item Des OD (In) Wt (Ib/ft) Grade Ref # Run? Len (ft) Centratimd? Ext Jewelry Top (11KB) Cum Len (ft) BHI Centrilift 2 7/8 6.50 L -80 Yes 61.13 No 7,245.9 61.13 ESP Pump Assy BHI Centrilift 2 7/8 6.50 L -80 Yes 0.50 No 7,245.4 61.63 Discharge Head BHI Centrilift 2 7/8 6.50 L -80 Yes 2.43 No 7,242.9 64.06 Discharge gauge 2.875" 6.5 L- 2 7/8 6.50 L -80 Yes 1.85 No 7,241.1 65.91 80 EUE 8rd Pup jt w /collar BHI Centrilift 2 7/8 6.50 L -80 Yes 3.16 No 7,237.9 69.07 ADV X -O EUE 2 7/8 6.50 L -80 Yes 6.16 No 7,231.8 75.23 8rd pin x IBT -M collar Tubing 2 7/8 6.50 L -80 1 Yes 31.98 No 7,199.8 107.21 Tubing 2 7/8 6.50 L -80 2 Yes 32.00 No 7,167.8 139.21 Tubing 2 7/8 6.50 L -80 3 Yes 31.97 No 7,135.8 171.18 Tubing 2 7/8 6.50 L -80 4 Yes 31.98 No 7,103.8 203.16 Tubing 2 7/8 6.50 L -80 5 Yes 31.97 No 7,071.9 235.13 Tubing 2 7/8 6.50 L -80 6 Yes 31.29 No 7,040.6 266.42 Tubing 2 7/8 6.50 L -80 7 Yes 31.95 No 7,008.6 298.37 Tubing 2 7/8 6.50 L-80 8 Yes 32.00 No 6,976.6 330.37 Tubing 2 7/8 6.50 L -80 9 Yes 31.50 No 6,945.1 361.87 Tubing 2 7/8 6.50 L -80 10 Yes 31.47 No 6,913.7 393.34 X -O IBT -M 2 7/8 6.50 L-80 Yes 3.87 No 6,909.8 397.21 pin x EUE 8rd collar HES 2.313 2 7/8 6.50 L -80 Yes 1.26 No 6,908.5 398.47 "X° nipple w/ RHC -M plug X -O EUE 2 7/8 6.50 L -80 Yes 6.15 No 6,902.4 404.62 8rd pin x IBT -M collar Tubing 2 7/8 6.50 L-80 11 Yes 31.08 No 6,871.3 435.70 Tubing 2 7/8 6.50 L -80 12 Yes 31.48 No 6,839.8 467.18 Tubing 2 7/8 6.50 L-80 13 Yes 31.16 No 6,808.7 498.34 2.875" L -80 2 7/8 6.50 L -80 Yes 3.84 No 6,804.8 502.18 IBT -M Pupjt 2.875" x 1.5" 2 7/8 6.50 L -80 Yes 9.57 No 6,795.2 511.75 FO -2 GLM 2.875" L -80 2 7/8 6.50 L -80 Yes 5.81 No 6,789.4 517.56 IBT -M Pup jt Tubing 2 7/8 6.50 L-80 14 Yes 31.48 No 6,758.0 549.04 Tubing 2 7/8 6.50 L -80 15 Yes 31.10 No 6,726.9 580.14 Tubing 2 7/8 6.50 L -80 16 Yes 32.00 No 6,694.9 612.14 Tubing 2 7/8 6.50 L -80 17 Yes 30.43 No 6,664.4 642.57 Tubing 2 7/8 6.50 L -80 18 Yes 31.52 No 6,632.9 674.09 Page 1/6 Report Printed: 5/28 /2013 PIONEER Tubing Tally • NATURAL RESOURCES Des: Tubing - Secondary Production, Set Depth: 7,307.0ftKB Well Name: ODSN -37 APUUWI Surface Legal Location LicenseLeaseNumber 50- 703 - 20586 -0000 Fete N 293T FSL,1129' EEL, Sec 11, T13N, R7E, UM 206 -157 000GURUK URUK UNIT s tare gL/{$Kq Well Profile Original KB Elevalion (ft) KB -Ground Distance ft HORIZONTAL 56.20 () 42 70 KB Casing Range Distance (ft) KS-Tubing Head Distance (ft) 19.19 22.30 Tubing Run Tally Item Des OD (In) Wt (IWR) Grade Ref a Run? Len (ft) Centraliad? Ext Jewelry Top (ftKB) Cum Len (ft) Tubing 2 7/8 6.50 L -80 19 Yes 30.71 No Tubing 2 7/8 6.50 L -80 6,57.0 704.80 20 Yes 31,16 No 6,571.0 735.96 Tubing 2 7/8 6.50 L -80 21 Yes 31.45 No Tubing 2 7/8 6.50 L -80 6,539.6 767.41 22 Yes 31.51 No 6,508.1 798.92 Tubing 2 7/8 6.50 L -80 23 Yes 3t15 No Tubing 2 7/8 6.50 L -80 6,476.9 86 24 Yes 31.50 No 6,445.4 8611 .57 Tubing 2 7/8 6.50 L -80 25 Yes 31.47 No Tubing 2 7/8 6.50 L -80 6,414.0 893.04 26 Yes 31.49 No 6,382.5 924.53 Tubing 2 7/8 6.50 L -80 27 Yes 32.03 No Tubing 2 7/8 6.50 L -80 6,350.4 956.56 28 Yes 31.11 No 6,319.3 987.67 Tubing 2 7/8 6.50 L -80 29 Yes 31.54 No Tubin 6,287.8 1,019.21 9 2 7/8 6.50 L -80 30 Yes 30.74 No 6,257.0 1,049.95 Tubing 2 7/8 6.50 L-80 31 Yes 31.48 No 6,225.6 1,081.43 Tubing 2 7/8 6.50 L -80 32 Yes 31.47 No 6,194.1 1,112.90 Tubing 2 7/8 6.50 L-80 33 Yes 30.80 No Tubing 2 7/8 6.50 L -80 6,163.3 1,143.70 34 Yes 31.16 No 6,132.1 1,174.86 Tubing 2 7/8 6.50 L -80 35 Yes 31.10 No Tubing 6,101.0 1,205.96 9 2 7/8 6.50 L -80 36 Yes 31.44 No 6,069.6 1,237.40 Tubing 2 7/8 6.50 L -80 37 Yes 31.51 No 6,038.1 1,268.91 Tubing 2 7!8 6.50 L -80 38 Yes 31.52 No 6,006.6 1,300.43 Tubing 2 7/8 6.50 L -80 39 Yes 31.53 No Tubin 5,975.0 1,331.96 9 2 7/8 6.50 L -80 40 Yes 31.50 No 5,943.5 1,363.46 Tubing 2 7/8 6.50 L -80 41 Yes 31.19 No Tubing 5,912.3 1,394.65 ubin 9 2 7/8 6.50 L -80 42 Yes 31.10 No 5,881.2 1,425.75 Tubing 2 7/8 6.50 L -80 43 Yes 31.49 No Tubing 5,849.8 1,457.24 9 2 7/8' 6.50 L -80 44 Yes 32.00 No 5,817.8 1,489.24 Tubing 2 7/8 6.50 L -80 45 Yes 31.50 No Tubing 2 7/8 6.50 L -80 5,786.3 1,520.74 46 Yes 31.49 No 5,754.8 1,552.23 Tubing 2 7/8 6.50 L -80 47 Yes 31.52 No Tubin 5,723.2 1,583.75 9 2 7/8 6.50 L -80 48 Yes 31.50 No 5,69t7 1,615.25 Tubing 2 7/8 6.50 ' L -80 49 Yes 31.52 No Tubing 5,660.2 1,646.77 ubin 9 2 7/8 6.50 L -80 50 Yes 31.50 No 5,628.7 1,678.27 Tubing 2 7/8 6.50 L-80 51 Yes 31.08 No Tubin 5,597.6 1,709.35 9 2 7/8 6.50 L-80 52 Yes 31.49 No 5,566.2 1,740.84 Tubing 2 7/8 6.50 L -80 53 Yes 31.53 No Tubing 5,534.6 1,772.37 ubin 9 2 7/8 6.50 L -80 54 Yes 31.51 No 5,503.1 1,803.88 Tubing 2 7/8 6.50 L -80 55 Yes 31.08 No 5,472.0 1,834.96 Tubing 2 7/8 6.50 L -80 56 Yes 31.47 No 5,440.6 1,866.43 Tubing 2 7/8 6.50 L -80 57 Yes 31.48 No 5,409.1 1,897.91 Tubing 2 7/8 6.50 L -80 58 Yes 31.55 No 5,377.5 1,929.46 Tubing 2 7/8 6.50 L-80 59 Yes 31.64 No 5,345.9 1,961.10 Tubing 2 7/8 6.50 L -80 60 Yes 31.07 No 5,314.8 1,992.17 Tubing 2 7/8 6.50 L -80 61 Yes 31.47 No 5,283.4 2,023.64 Tubing 2 7/8 6.50 L -80 62 Yes 31.48 No 5,251.9 2,055.12 Tubing 2 7/8 6.50 L -80 63 Yes 31.49 No Tubin 5,220.4 2,086.61 9 2 7/8 6.50 L -80 64 Yes 30.78 No 5,189.6 2,117.39 Tubing 2 7/8 6.50 L-80 65 Yes 31.48 No 5,158.1 2,148.87 Tubing 2 7/8 6.50 L -80 66 Yes 3t49 No 5,126.6 2,180.36 Tubing 2 7/8 6.50 L -80 67 Yes 31.15 No 5,095.5 2,211.51 Tubing 2 7/8 6.50 L-80 68 Yes 31.07 No 5,064.4 2,242.58 Tubing 27/8 6.50 L -80 69 Yes 31.46 No Tubin 5,033.0 2,274.04 9 2 718 6.50 L -80 70 Yes 31.10 No 5,001.9 2,305.14 Tubing 2 7/8 6.50 L -80 71 Yes 31.49 No 4,970.4 2,336.63 Page 2/6 Report Printed: 5/28 /2013 PIONEER • Tubing Tally S NATURAL RESOURCES Des: Tubing - Secondary Production, Set Depth: 7,307.0ftKB Well Name: ODSN -37 API/UWI Surface Legal Location LicenserLease Number Field Name State 50 703 - 20586 - 0000 2937'FSL, 1129' FEL, Sec 11, T13N, R7E, UM 208 OOOGURUK UNIT ALASKA Well Profile Original KB Elevation (ft) KB-Ground Distance (ft) KB- Casing Range Distance (ft) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 19.19_ 22.30 Tubing Run Tally Item Des OD (In) Wt (Ib/ft) Grade Ref * Run? Len (ft) Centralized? Ext Jewelry Top (11KB) Cum Len (ft) Tubing 2 7/8 6.50 L -80 72 Yes 31.48 No 4,938.9 2,368.11 Tubing 2 7/8 6.50 L -80 73 Yes 31.50 No 4,907.4 2,399.61 Tubing 2 7/8 6.50 L -80 74 Yes 31.49 No 4,875.9 2,431.10 Tubing 2 7/8 6.50 L -80 75 Yes 31.48 No 4,844.4 2,462.58 Tubing 2 7/8 6.50 L -80 76 Yes 31.49 No 4,812.9 2,494.07 Tubing 2 7/8 6.50 L -80 77 Yes 31.09 No 4,781.8 2,525.16 Tubing 2 7/8 6.50 L-80 78 Yes 31.10 No 4,750.7 2,556.26 Tubing 2 7/8 6.50 L -80 79 Yes 31.14 No 4,719.6 2,587.40 Tubing 2 7/8 6.50 L -80 80 Yes 31.52 No 4,688.1 2,618.92 Tubing 2 7/8 6.50 L -80 81 Yes 31.10 No 4,657.0 2,650.02 Tubing 2 7/8 6.50 L -80 82 Yes 31.51 No 4,625.5 2,681.53 Tubing 2 7/8 6.50 L -80 83 ' Yes 31.15 No 4,594.3 2,712.68 Tubing 2 7/8 6.50 L -80 84 Yes 31.52 No 4,562.8 2,744.20 Tubing 2 7/8 6.50 L -80 85 Yes 31.10 No 4,531.7 2,775.30 Tubing 2 7/8 6.50 L -80 86 Yes 31.09 No 4,500.6 2,806.39 Tubing 2 7/8 6.50 L -80 87 Yes 31.10 No 4,469.5 2,837.49 Tubing 2 7/8 6.50 1-80 88 Yes 31.53 No 4,438.0 2,869.02 Tubing 2 7/8 6.50 L -80 89 Yes 31.51 No 4,406.5 2,900.53 Tubing 2 7/8 6.50 L -80 90 Yes 31.10 No 4,375.4 2,931.63 Tubing 2 7/8 6.50 L -80 91 Yes 31.28 No 4,344.1 2,962.91 Tubing 2 7/8 6.50 L -80 92 Yes 31.52 No 4,312.6 2,994.43 Tubing 2 7/8 6.50 L -80 93 Yes 31.07 No 4,281.5 3,025.50 Tubing 2 7/8' 6.50 L-80 94 Yes 31.55 No 4,249.9 3,057.05 Tubing 2 7/8 6.50 L -80 95 Yes 31.13 No 4,218.8 3,088.18 Tubing 27/8 6.50 L -80 96 Yes 31.45 No 4,187.4 3,119.63 Tubing 27/8 6.50 L -80 97 Yes 31.15 No 4,156.2 3,150.78 Tubing 27/8 6.50 L -80 98 Yes 31.50 No 4,124.7 3,182.28 Tubing 2 7/8 6.50 L -80 99 Yes 31.51 No 4,093.2 3,213.79 Tubing 2 7/8 6.50 L -80 100 Yes 31.48 No 4,061.7 3,245.27 2.875" L-80 2 7/8 6.50 L-80 Yes 10.20 No 4,051.5 3,255.47 IBT -M Pup jt X -O New 2 7/8 6.50 L -80 Yes 6.55 No 4,045.0 3,262.02 Vam box x IBT-M pin WFT 7" x 2 7/8 6.50 L -80 Yes 5.58 No 4,039.4 3,267.60 2.875" Hydro 2 Retry Pkr w. ESP gas vent X-O IBT -M 2 7/8 6.50 1 -80 Yes 14.10 No 4,025.3 3,281.70 box x New Vam pin Tubing 2 7/8 6.50 L -80 101 Yes 31.53 No 3,993.8 3,313.23 Tubing 2 7/8 6.50 L-80 102 Yes 31.50 No 3,962.3 3,344.73 Tubing 2 7/8 6.50 L -80 103 Yes 31.46 No 3,930.8 3,376.19 Tubing 2 7/8 6.50 L -80 104 Yes 31.48 No 3,899.3 3,407.67 2.875" L -80 2 7/8 6.50 1-80 Yes 3.87 No 3,895.5 3,411.54 IBT -M Pup jt HES 2.313 2 7/8 6.50 1-80 Yes 1.28 No 3,894.2 3,412.82 "X" nipple w/ RHC -M plug Page 3/6 Report Printed: 5/28 /2013 PIONEER • Tubing Tally 0 NATURAL RESOURCES Des: Tubing - Secondary Production, Set Depth: 7,307.0ftKB Well Name: ODSN -37 APW W1 Surface Legal Location License .ease Number Field Name State 50 703 - 20586 - 0000 2037' FSL, 1129' FEL, Sec 11, T13N, R7E, UM 208 - 157 OOOGURUK UNIT ALASKA Well Profile Original KB Elevation (ft) KB -Ground Distance (ft) KB- Casing Range Distance (ft) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 19.19 22.30 Tubing Run Tally Item Des OD (in) Wt (Ib/R) Grade Ref # Run? Len (ft) Centralized? Ext Jewelry Top (RKB) Cum Len (ft) 2.875" L -80 2 7/8 6.50 L -80 Yes 6.12 No 3,888.1 3,418.94 IBT -M Pup jt Tubing 2 7/8 6.50 1-80 105 Yes 31.49 No 3,856.6 3,450.43 Tubing 2 7/8 6.50 L -80 106 Yes 31.54 No 3,825.0 3,481.97 Tubing 2 7/8 6.50 L -80 107 Yes 31.15 No 3,793.9 3,513.12 2.875" L -80 2 7/8 6.50 L -80 Yes 3.88 No 3,790.0 3,517.00 IBT -M Pup jt 2.875" x 1.5" 2 7/8 6.50 L -80 Yes 9.55 No 3,780.4 3,526.55 FO -2 GLM 2.875" L -80 2 7/8 6.50 1-80 Yes 5.81 No 3,774.6 3,532.36 IBT -M Pup jt Tubing 2 7/8 6.50 L -80 108 Yes 30.38 No 3,744.3 3,562.74' Tubing 2 7/8 6.50 1-80 109 Yes 31.12 No 3,713.1 3,593.86 Tubing 2 7/8 6.50 L -80 110 Yes 30.61 No 3,682.5 3,624.47 Tubing 2 7/8 6.50 L -80 111 Yes 31.12 No 3,651.4 3,655.59 Tubing 2 7/8 6.50 L -80 112 Yes 30.72 No 3,620.7 3,686.31 Tubing 2 7/8 6.50 L -80 113 Yes 31.10 No 3,589.6 3,717.41 Tubing 2 7/8 6.50 L -80 114 Yes 31.07 No 3,558.5 3,748.48 Tubing 2 7/8 6.50 L -80 115 Yes 31.11 No 3,527.4 3,779.59 Tubing 2 7/8 6.50 1-80 116 Yes 31.12 No 3,496.3 3,810.71 Tubing 2 7/8 6.50 L -80 117 Yes 31.48 No 3,464.8 3,842.19 Tubing 2 7/8 6.50 1-80 118 Yes 31.49 No 3,433.3 3,873.68 Tubing 2 7/8 6.50 L -80 119 Yes 30.70 No 3,402.6 3,904.38 Tubing 2 7/8 6.50 1-80 120 Yes 30.72 No 3,371.9 3,935.10 Tubing 2 7/8 6.50 1-80 121 Yes 30.41 No 3,341.5 3,965.51 Tubing 2 7/8 6.50 L -80 122 Yes 30.69 No 3,310.8 3,996.20 Tubing 2 7/8 6.50 L-80 123 Yes 31.15 No 3,279.6 4,027.35 Tubing 2 7/8 6.50 L -80 124 Yes 31.55 No 3,248.1 4,058.90 Tubing 2 7/8 6.50 L-80 125 Yes 31.53 No 3,216.6 4,090.43 Tubing 2 7/8 6.50 L -80 126 Yes 30.70 No 3,185.9 4,121.13 Tubing 2 7/8 6.50 L -80 127 Yes 30.74 No 3,155.1 4,151.87 Tubing 2 7/8 6.50 L-80 128 Yes 31.51 No 3,123.6 4,183.38 Tubing 2 7/8 6.50 L -80 129 Yes 31.53 No 3,092.1 4,214.91 Tubing 2 7/8 6.50 L-80 130 Yes 31.16 No 3,060.9 4,246.07 Tubing 2 7/8 6.50 1-80 131 Yes 31.17 No 3,029.8 4,277.24 Tubing 2 7/8 6.50 L -80 132 Yes 31.52 No 2,998.2 4,308.76 Tubing 2 7/8 6.50 L-80 133 Yes 31.10 No 2,967.1 4,339.86 Tubing 2 7/8 6.50 1-80 134 Yes 31.48 No 2,935.7 4,371.34 Tubing 2 7/8 6.50 L -80 135 Yes 31.10 No 2,904.6 4,402.44 Tubing 2 7/8 6.50 1-80 136 Yes 29.46 No 2,875.1 4,431.90 Tubing 2 7/8 6.50 L -80 137 Yes 31.17 No 2,843.9 4,463.07 Tubing 2 7/8 6.50 L -80 138 Yes 31.52 No 2,812.4 4,494.59 Tubing 2 7/8 6.50 L-80 139 Yes 31.12 No 2,781.3 4,525.71 Tubing 2 7/8 6.50 L-80 140 Yes 31.14 No 2,750.1 4,556.85 Tubing 2 7/8 6.50 1-80 141 Yes 31.10 No 2,719.0 4,587.95 Tubing 2 7/8 6.50 L -80 142 Yes 31.42 No 2,687.6 4,619.37 Tubing 2 7/8 6.50 L -80 143 Yes 31.16 No 2,656.5 4,650.53 Tubing 2 7/8 6.50 1-80 144 Yes 31.12 No 2,625.3 4,681.65 Tubing 2 7/8 6.50 L -80 145 Yes 31.15 No 2,594.2 4,712.80 Tubing 2 7/8 6.50 1-80 146 Yes 31.54 No 2,562.7 4,744.34 Tubing 2 7/8 6.50 1-80 147 Yes 30.68 No 2,532.0 4,775.02 Page 4/6 Report Printed: 5/28 /201 Tu • PIONEER bngTally NATURAL RESOURCES Des: Tubing - Secondary Production, Set Depth: 7,307.0ftKB Well Name: ODSN -37 APWNWI Surface Legal Location License/LeaseNumber 50 -703- 20586 -0000 Field Name A 1937• ESL, 1129' FEL, Sec 11, T13N, R7E, UM 208-157 OOOGURUK UNIT ALASKA Well Profile Original KB Elevation (ft) KB -Ground Distance (ft) KB- Casing Flange Cistance (ft) KB- Tubing Head Distance (ft) HORIZONTAL 56.20 42.70 19.19 22.30 Tubing Run Tally Item Des. OD m Tubing ( 2 7/8 Wt ( 6 ) .50 L Ref 8 148 Yes Len (ft) Centralized? Ext Jewelry Top () Cum Len (ft) 31.10 No 2,500.9 4,806.12 Tubing 2 7/8 6.50 L -80 149 Yes 31.11 No 2,469.8 4,837.23 Tubing 2 7/8 6.50 1-80 150 Yes 31.14 No 2,438.6 4,868.37 Tubing 2 7/8 6.50 L -80 151 Yes 31.10 No 2,407.5 4,899.47 Tubing 2 7/8 6.50 L -80 152 Yes 31.06 No 2,376.5 4,930.53 Tubing 2 7/8 6.50 L -80 153 Yes 31.11 No Tubin 2,345.4 4,961.64 9 2 7/8 6.50 1-80 154 Yes 31.49 No 2,313.9 4,993.13 Tubing 2 7/8 6.50 L -80 155 Yes 31.15 No 2,282.7 5,024.28 Tubing 2 7/8 6.50 L -80 156 Yes 30.75 No 2,252.0 5,055.03 Tubing 2 7/8 6.50 L -80 157 Yes 31.12 No Tubin 2,220.8 5,086.15 9 2 7/8 6.50 1-80 158 Yes 31.11 No 2,189.7 5,117.26 Tubing 2 7/8 6.50 L -80 159 Yes 31.55 No Tubing 2,158.2 5,148.81 ubin 9 2 7 /8 6.50 1-80 160 Yes 31.14 No 2,127.0 5,179.95 Tubing 2 7/8 6.50 1 -80 161 Yes 30.46 No 2,096.6 5,210.41 Tubing 2 7/8 6.50 1-80 162 Yes 31.48 No 2,065.1 5,241.89 Tubing 2 7/8 6.50 L -80 163 Yes 31.15 No 2,034.0 5,273.04 Tubing 2 7/8 6.50 1 -80 164 Yes 31.48 No 2,002.5 5,304.52 Tubing 2 7/8 6.50 L -80 165 Yes 31.50 No 1,971.0 5,336.02 Tubing 2 7/8 6.50 1-80 166 Yes 31.12 No 1,939.9 5,367.14 Tubing 2 7/8 6.50 L -80 167 Yes 31.08' No Tubing 1,908.8 5,398.22 ubin 9 2 7/8 6.50 L -80 168 Yes 31.10 No 1,877.7 5,429.32 Tubing 2 7/8 6.50 L -80 169 Yes 29.72 No 1,848.0 5,459.04 Tubing 2 7/8 6.50 L -80 170 Yes 31.15 No 1,816.8 5,490.19 Tubing 2 7/8 6.50 1 -80 171 Yes 31.55 No 1,785.3 5,521.74 Tubing 2 7/8 6.50 L -80 172 Yes 31.11 No 1,754.1 5,552.85 Tubing 2 7/8 6.50 L -80 173 Yes 31.50 No 1,722.6 5,584.35 Tubing 2 7/8 6.50 1-80 174 Yes 31.48 No 1,691.2 5,615.83 Tubing 2 7/8 6.50 L -80 175 Yes 31.53 No Tubin 1,659.6 5,647.36 9 2 7/8 6.50 1-80 176 Yes 31.52 No 1,628.1 5,678.88 Tubing 2 7/8 6.50 L -80 177 Yes 31.41 No 1.596.7 5,710.29 Tubing 2 7/8 6.50 1-80 178 Yes 31.15 No 1,565.6 5,741.44 Tubing 2 7/8 6.50 L -80 179 Yes 31.49 No 1,534.1 5,772.93 Tubing 2 7/8 6.50 L-80 180 Yes 31.50 No 1,502.6 5,804.43 Tubing 2 7/8 6.50 L -80 181 Yes 31.48 No 1,471.1 5,835.91 Tubing 2 7/8 6.50 L-80 182 Yes 30.75 No 1,440.3 5,866.66 Tubing 2 7/8 6.50 L-80 183 Yes 31.52 No Tubing 2 7/8 6.50 L -80 1,408.8 5,929. 184 Yes 31.13 No 1,377.7 5,929.31 1 Tubing 2 7/8 6.50 L -80 185 Yes 31.15 No 1,346.5 5,960.46 Tubing 2 7/8 6.50 L -80 186 Yes 31.49 No 1,315.0 5,991.95 Tubing 2 7/8 6.50 L-80 187 Yes 31.56 No Tubing 2 7/8 6.50 L-80 1,283.5 6,023.51 188 Yes 31.55 No 1,251.9 6,055.06 Tubing 2 7/8 6.50 L -80 189 Yes 31.53 No 1,220.4 6,086.59 Tubing 2 7/8 6.50 L -80 190 Yes 31.48 No 1,188.9 6,118.07 Tubing 2 7/8 6.50 L -80 191 Yes 31.51 ' No Tubing 2 7/8 6.50 L -80 1,157.4 6,18 192 Yes 31.56 No 1,125.9 6,181.14 .14 Tubing 2 7/8 6.50 L -80 193 Yes 31.10 No 1,094.8 6,212.24 Tubing 2 7/8 6.50 1-80 194 Yes 31.08 No 1,063.7 6,243.32 Tubing 2 7/8' 6.50 L -80 195 Yes 31.53 No 1,032.9 6,274.85 Tubing 2 7/8 6.50 L-80 196 Yes 31.27 No 1,000.9 6,306.12 Tubing 2 7/8 6.50 L -80 197 Yes 31.50 No 969.4 6,337.62 Tubing 2 7/8 6.50 L -80 198 Yes 31.14 No 938.2 6,368.76 Tubing 2 7/8 6.50 L -80 199 Yes 31.49 No 906.7 6,400.25 Tubing 2 7/8 6.50 L -80 200 Yes 31.48 No 875.3 6,431.73 Page 5/6 Report Printed: 5/28 /2013 P IONEER Tubing Tally • NATURAL RESOURCES Des: Tubing - Secondary Production, Set Depth: 7,307.0ftKB Well Name: ODSN -37 APUUWi Surface Legal Location LicenseA.easeNumber 50 - 703 - 20586 - 0000 0 Na St ALASKA Well Profile Original KB Elevation (ft) KB Ground Distance (ft) KB Casing Range Ostance (ft) KB Head Distance (ft) HORIZONTAL 56.20 42.70 19.19 22.30 Tubing Run Tally item Des OD (In) Wt b/ft Len Tubing 2 7/8 � 6.50 L - �* Run? (ft) CenVaHasdT Ext Jewelry Top (MB) Cum Len (ft) 201 Yes 31.73 No 843.5 6,463.46 Tubing 2 7/8 6.50 L -80 202 Yes 31.48 No Tubing 2 7/8 6.50 1-80 812.1 6,494.94 203 Yes 31.29 No 780.8 6,526.23 Tubing 2 7/8 6.50 L -80 204 Yes 31.51 No 2.875" L -80 2 7/8 6.50 1-80 749.3 6,557.74 IBT -M Pupjt Yes 3.62 No 745.6 6,561.36 HES 2 7/8 6.50 L -80 Yes 4.32 No Welistar 741.3 6,565.68 TRSV w/ 2.313 "X" nipple 2.875" L -80 2 7/8 6.50 L -80 Yes 6.27 No IBT -M Pup jt 735.0 6,571.95 Tubing 2 7/8 6.50 L -80 205 Yes 31.50 No Tubing 2 7/8 6.50 L -80 703.5 6,603.45 206 Yes 32.00 No 671.5 6,635.45 Tubing 2 7/8 6.50 �L -80 207 Yes 30.79 No 640.8 6,666.24 Tubing 2 7/8 6.50 1-80 208 Yes 32.00 No 608.8 6,698.24 Tubing 2 7/8 6.50 L -80 209 Yes 31.49 No Tubing 2 718 6.50 L-80 577.3 6,729.73 210 Yes 31.52 No 545.7 6,761.25 Tubing 2 7/8 6.50 L -80 211 Yes 31.99 No Tubing 2 7/8 6.50 L -80 513.8 6,793.24 212 Yes 31.20 No 482.6 6,824.44 Tubing 2 7/8 6.50 ' L -80 213 Yes 32.00 No Tubing 2 7/8 6.50 L -80 450.6 6,856.44 214 Yes 32.01 No 418.5 6,888.45 Tubing 2 7/8 6.50 L -80 215 Yes 32.00 No Tubing 2 7/8 6.50 L -80 386.5 6,920.45 216 Yes 31.99 No 354.6 6,952.44 Tubing 2 7/8 6.50 L-80 217 Yes 31.05 No Tubing 323.5 6,983.49 ubin 9 2 7 /8 6.50 1-80 218 Yes 31.53 No 292.0 7,015.02 Tubing 2 7/8 6.50 L -80 219 Yes 31.52 No Tubing 2 7/8 6.50 L -80 260.5 7,046.54 220 Yes 31.51 No 228.9 7,078.05 Tubing 2 7/8 6.50 L -80 221 Yes 31.00 No 197.9 7,109.05 Tubing 2 7/8 6.50 1-80 222 Yes 31.02 No 166.9 7,140.07 Tubing 2 7/8 6.50 1-80 223 Yes 31.00 No 135.9 7,171.07 Tubing 2 7/8 6.50 L-80 224 Yes 30.95 No 105.0 7,202.02 Tubing 2 7/8 6.50 L-80 225 Yes 29.92 No 75.1 7,231.94 Tubing 2 7/8 6.50 L -80 226 Yes 30.91 No 44.1 7,262.85 X -O 3.5" IBT 31/2 6.50 L -80 Yes 1.45 No -M box x 42.7 7,264.30 2.875" IBT pin 3.5" 9.3 L -80 31/2 6.50 L-80 Yes 7.93 No IBT -M pup 34.8 7,272.23 pin x pin Vetco Gray 31/2 6.50 L -80 Yes 1.54 No Hngr w/3.5" 33.2 7,273.77 IBT -M box Page 6/6 Report Printed: 5/28 /2013 Nuiqsut Pressure Build Ups (N37 & N31) 10 9 - 8 .. 1 • ao 7 - a 1 6 - .00 40.. N '' • .► 5 - I 1 Q. 0 4 1 ---- SW E 3 LVT ODSN -37, Eclipse simulation area pressure; 803 MRB Voidage LL 2 - • ODSN -37, 11/09, 157 MRB Voidage (BHP measured) ODSN -37, 4/10, 222 MRB Voidage (BHP measured) • 1 - — — ODSN -31, 10/09, 148 MRB Voidage (BHP measured) ODSN -31, 9/12, 1147 MRB Voidage (BHP Measured) 0 0 5 10 15 20 25 30 Cumulative shut -in time, days • • Well Planning - Pioneer - Oooguruk Oooguruk Developement g Oooguruk Drill Site ODSN -37 PN8 Permit to Drill: 208 -157 API: 50- 703 - 20586 -00 Sperry Drilling Services Definitive Survey Report 11 June, 2009 mase HALLIBURTON Sperry Drilling Services . • • Halli Burton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co-ordinate Reference: Well root Oooguruk Developement ODSN 37 -Slot ODS -37 Site: Oooguruk Drill Site T Reference: 42.7 + 13.5' @ 56.2ft (Nabors 19AC) : ODSN -37 Reference: 42.7 + 13.5' 56.2ft (Nabors 19AC) I YUelibore: ODSN -37 PN8 North Reference: True Design: ODSN -37 PN8 Surveys Survey Calculation Method: Minimum Curvature Database: .Pioneer Alaska Project Oooguruk Developement Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Map Zone: Alaska Zone 04 Using Well Reference Point Using geodetic scale factor i Well ODSN -37 - Slot ODS -37 Well Position +N/ -S 0.0 ft Northing: 6,031,053.00 ft +�-W 0.0 ft Eastin Latitude: 70° 29' 45.273 N i osition Uncertain 9 469,869.00ft Longitude: 150° 14' 46.967 W P tY 0.0 ft Wellhead Elevation: ft Ground Level: '- osit n -- a -- 0. --- e -head- --- 13.5 ft Welton) ODSN -37 PN8 1 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (?) 0510 ( ?) (nT) IGRF20 �__. __.- ._._. - - - - -- 051 5/20/2008 22.70 80.81 57,693 Design ODSN -37 PN8 Surveys Audit Notes: f Version: 1.0 Phase: ACTUAL Tie On Depth: 42.7 Vertic Section: ! Depth From (TVD) +W-S +E/-W Direction (ft) (ft) (bearing) 42.7 0.0 0.0 317.46 I Survey Program Date 6/1172009 -- -------_._...---------- _-- __---------- __.,_..._...__ From To (ft) (ft) Surrey (Wefbore) Tool Name Description 50.0 1,488.0 ODSN -37 PN8 Gyro (ODSN -37 PN8) CB- GYRO -SS 10/27/2008 Date C gyro 1,530.8 14,258.5 ODSN -37 PN8 MIND (ODSN -37 PN8) MWD +SAG +CA +IIFR +M MWD +SAG +CA IIFR +Multi Station 10/27/2008 10/29/2008 *1 ■ Survey MD inc An TVD TVDSS +WS ry . Map Map Vertical (ft) ( ?) (bearin (ft) (ft) (� Of) lift Lasting DLS Section 0.0 0,00 0.00 0.0 - 56.2 (ft) (ft) mow) (ft) Survey Tool Name 0.0 0.0 6,031,053.0 469,869.0 0.0 0.00 UNDEFINED 50.0 0.31 103.88 50.0 -6.2 0.0 0.1 6,031,053.0 469,869.1 0.6 -0.11 CB- GYRO -SS (1) 100.0 0.29 208.17 100.0 43.8 -0.2 0.2 6,031,052.8 469,869.2 0.9 -0.27 CB- GYRO -SS (1) 166.0 0.43 259.13 166.0 109.8 -0.4 -0.1 6,031,052.6 469,868.9 0.5 -0.19 C9- GYRO -SS (1) 260.0 0.40 286.99 260.0 203.8 -0.3 -0.8 6,031,052.7 469,868.2 0.2 0.28 CB- GYRO -SS (1) 352.0 0.59 310.22 352.0 295.8 0.1 -1.4 6,031,053.1 469,887.8 0.3 1.02 C8- GYRO -SS (1) 442.0 0.19 84.25 442.0 385.8 0.4 -1.7 6,031,053.4 469,867.3 0.8 1.39 CB- GYRO -SS (1) 539.0 0.75 104.48 539.0 482.8 0.2 -0.9 6,031,053.2 469,868.1 0.8 0.76 CB- GYRO -SS (1) 633.0 1.51 106.27 633.0 576.8 -0.3 0.9 6,031,052.7 469,869.9 0.8 -0.81 CB-GYRO-SS (1) 727.0 3.09 119.44 726.9 670.7 -1.9 4.3 6,031,051.1 469,873.3 1.8 -4.28 CB- GYRO -SS (1) 826.0 4.94 134.90 825.6 769.4 -6.2 9.6 6,031,046.8 469,878.6 2.1 -11.08 CB- GYRO-SS (1) 919.0 5.26 132.46 918.3 862.1 -11.9 15.8 6,031,041.1 469,884.6 0.4 -19.32 CB- GYRO-SS (1) 1,014.0 6.19 135.23 1,012.8 956.6 -18.5 22.4 6,031,034.4 469,891.4 1.0 -28.78 CB- GYRO -SS (1) 6/11/2009 1 1:04:48AM Page 2 COMPASS 2003.16 Build 42B • • • Hal iburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Project Oooguruk Developement Co-ordinate Reference: Well ODSN -37 - Slot ODS -37 Site: Oooguruk Drill Site TVD Reference: 42.7' + 13.5' Q 56.2ft (Nabors 19AC) Welk ODSN -37 Refenmee: 42.7' + 13.5' 56.2ft (Nabors 19AC) Wellbore: ODSN -37 PN8 North Reference: True Design: ODSN -37 PN8 Surveys Survey Cakulation Method: Minimum Curvature Database: .Pioneer Alaska i Survey Map M D Inc (bAartn V (MSS R-S +El-W Northing Fasting DLS Section (ft) (R) (ft) ( two (ft) Survey Tool Name 1,110.0 9.70 141.51 1,107.9 1,051.7 -28.5 31.1 6,031,024.4 469,900.0 3.8 -42.02 CB- GYRO -SS(1) 1,205.0 11.10 137.62 1,201.3 1,145.1 -41.5 42.3 6,031,011.3 469,911.1 1.6 -59.15 CB- GYRO -SS(1) 1,300.0 12.18 141.86 1,294.4 1,238.2 - 56.1 54.6 6,030,996.7 469,923.4 1.4 -78.29 CB- GYRO -SS (1) 1,392.0 14.26 145.23 1,383.9 1,327.7 -73.1 67.1 6,030,979.7 469,935.8 2.4 -99.20 CB- GYRO -SS (1) 1,488.0 15.84 149.16 1,476.6 1,420.4 -94.0 80.5 6,030,958.6 469,949.2 2.0 - 123.74 CB- GYRO -SS (1) 1,530.8 15.61 145.11 1,517.8 1,461 -103.8 86.8 6,030,948.9 469,955.4 2.6 - 135.17 MWD +SAG +CA +IIFR +MS (2 1,625.4 16.39 145.38 1,608.7 1,552.5 -125.2 101.7 6,030,927.4 469,970.2 0.8 - 161.00 MWD +SAG +CA +IIFR +MS (2 1,720.6 17.57 143.64 1,699.8 1,643.6 -147.8 117.8 6,030,904.7 469,986.2 1.3 1,814.8 18.55 143.58 1,789.3 1,733.1 -171.3 - 188.60 MWD +SAG +CA +IIFR +MS (2 135.2 6,030,881.1 470,003.5 1.0 - 217.62 MWD +SAG +CA +IIFR +MS (2 1,910.4 18.14 142.45 1,880.1 1,823.9 -195.4 153.3 6,030,857.0 470,021.5 0.6 - 247.56 MWD+SAG+CA +IIFR +MS (2 2,003.9 18.81 142.48 1,968.7 1,912.5 -218.9 171.3 6,030,833.5 470,039.4 0.7 - 277.08 MWD +SAG +CA +IIFR +MS (2 2,098.6 20.09 139.75 2,058.1 2,001.9 -243.4 191.1 6,030,808.9 470,059.1 1.7 - 308.57 MWD +SAG +CA +IIFR +MS (2 2,193.5 21.18 138.57 2,146.9 2,090.7 -268.7 213.0 6,030,783.5 470,080.9 1.2 - 341.99 MWD+SAG +CA +IIFR +MS (2 2,288.4 21.51 136.80 2,235.3 2,179.1 -294.2 236.3 6,030,757.9 470,104.0 0.8 - 376.52 MWD +SAG +CA +IIFR+MS (2 2,382.1 2, 23.03 136.43 2,322.0 2,265.8 -320.0 2 ,382.1 24.13 134.99 2,322.0 2262 7 260.7 6,030,731.9 470,128.3 1.6 - 412.04 MWD +SAG +CA +IIFR +MS (2 -347.2 287.1 6,030,704.7 470,154.7 1.3 - 449.92 MWD +SAG +CA +IIFR +MS (2 2,572.3 25.18 136.09 2,495.6 2,439.4 -375.6 315.0 6,030,676.2 470,182.5 1.2 - 489.71 MWD +SAG +CA +IIFR+MS (2 2,665.7 25.19 140.31 2,580.1 2,523.9 405 .2 341.5 6,030,646.5 470,208.8 1.9 - 529.42 MWD +SAG+CA +IIFR +MS (2 2,761.9 26.90 140.44 2,666.6 2,610.4 -437.7 368.4 6,030,613.8 470,235.6 1.8 - 571.62 MWD +SAG+CA +IIFR +MS (2 2,856.7 26.38 140.23 2,751.3 2,695.1 -470.4 395.6 6,030,581.0 470,262.6 0.6 - 614.07 MWD +SAG+CA +IIFR +MS (2 2,950.9 27.49 138.22 2,835.2 2,779.0 -502.7 423.4 6,030,548.6 470,290.3 1.5 - 656.69 MWD +SAG +CA +IIFR +MS (2 3,044.5 27.08 141.47 2,918.4 2,862.2 -535.5 451.1 6,030,515.7 470,317.9 1.7 - 699.56 MWD +SAG+CA +IIFR +MS (2 3,114.2 27.19 143.40 2,980.4 2,924.2 -560.7 470.5 6,030,490.5 470,337.1 1.3 - 731.21 MWD +SAG +CA +IIFR +MS (2 3,214.1 25.69 145.06 3,069.9 3,013.7 -596.8 496.5 6,030,454.3 470,363.0 1.7 - 775.37 MWD +SAG+CA +IIFR +MS (2 3,308.9 25.47 148.59 3,155.4 3,099.2 -631.0 518.9 6,030,420.0 470,385.2 1.6 - 815.74 MWD +SAG +CA +IIFR +MS (2 3,404.0 25.63 152.91 3,241.2 3,185.0 - 666.8 538.9 6,030,384.1 470,405.1 2.0 - 855.65 MWD +SAG+CA +IIFR +MS (2 3,498.9 28.01 158.37 3,325.9 3,269.7 -705.8 556.5 6,030,345.0 470,422.5 3.6 - 896.26 MWD +SAG +CA +IIFR +MS (2 3,593.5 28.86 160.66 3,409.1 3,352.9 -748.0 572.2 6,030,302.8 470,438.1 1.5 - 937.99 MWD +SAG +CA +IIFR +MS (2 3,687.9 28.15 162.17 3,492.1 3,435.9 -790.7 586.6 6,030,260.0 470,452.3 1.1 - 979.16 MWD +SAG +CA +IIFR+MS (2 3,782.5 28.01 162.84 3,575.6 3,519.4 - 833.2 600.0 6,030,217.5 470,465.5 0.4 - 1,019.51 MWD +SAG+CA +IIFR +MS (2 3,877.1 27.62 163.91 3,659.2 3,603.0 -875.5 612.6 6,030,175.2 470,478.0 0.7 - 1,059.22 MWD +SAG +CA+IIFR+MS (2 3,970.0 27.40 164.60 3,741.6 3,685.4 -916.7 624.2 6,030,133.8 470,489.4 0.4 - 1,097.50 MWD+SAG +CA+IIFR +MS (2 4,064.1 26.81 164.36 3,825.3 3,789.1 -958.0 50 635.7 6,030,092.5 470 0 . 8 0.6 - 1,135.69 MWD +SAG+CA +IIFR +MS (2 4,159.0 27.22 168.25 3,910.0 3,853.8 - 999.9 645.9 6,030,050.6 470,510.8 1.9 - 1,173.45 MWD +SAG+CA +IIFR +MS (2 4,253.7 27.92 176.03 3,993.9 3,937.7 -1,043.3 651.8 6,030,007.2 470,516.6 3.9 - 1,209.41 MWD +SAG +CA +IIFR +MS (2 4,347.3 28.12 182.41 4,076.6 4,020.4 - 1,087.2 652.4 6,029,963.3 470,517.0 3.2 - 1,242.15 MWD +SAG+CA +IIFR +MS (2 4,443.2 27.29 190.31 4,161.4 4,105.2 - 1,131.4 647.6 6,029,919.1 470,511.9 3.9 - 1,271.42 MWD+SAG+CA +IIFR +MS (2 4,537.8 26.52 197.34 4,245.9 4,189.7 - 1,172.9 637.4 6,029,877.6 470,501.5 3.5 - 1,295.13 MWD +SAG +CA +IIFR +MS (2 4,632.4 26.09 210.42 4,330.7 4,274.5 - 1,211.0 620.5 6,029,839.6 470,484.6 6.1 - 1,311.83 MWD +SAG+CA +IIFR +MS (2 4,727.2 29.37 221.23 4,414.7 4,358.5 - 1,246.5 594.6 6,029,804.2 470,458.5 6.3 - 1,320.47 MWD +SAG+CA +IIFR +MS (2 6/111 2009 11:04:48AM Page 3 COMPASS 2003.16 Build 428 III • Haliibu rton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co-ordinate Reference: Well ODSN -37 - Slot ODS -37 Project Oooguruk Developement TVD Reference: Site: Oooguruk Drill Site 42.7' + 13.5' CO 56.2ft (Nabors 19AC) Well: ODSN -37 Reference: 42.7' + 13.5' 56.2ft (Nabors 19AC) Wellborn: ODSN -37 PN8 North Reference: True 18n: ODSN -37 PN8 Surveys Survey Calculation Method: Minimum Curvature Database: Pioneer Alaska Survey MD Inc Azi TVD T1/DSS +N1-g +E/.yy Map Map Vertical (n) (T) (bearin (ft) {R) (R) (Iii ��9 Easting DLS Section H't) (ft) ('l100') (n) Survey Tool Name 4,821.8 30.02 226.86 4,496.9 4,440.7 - 1,280.2 562.1 6,029,770.7 470,425.8 3.0 - 1,323.24 MWD +SAG +CA +1IFR +MS (2 4,917.5 29.59 227.03 4,580.0 4,523.8 - 1,312.6 527.3 6,029,738.4 470,390.9 0.5 - 1,323.67 MWD +SAG +CA +IIFR +MS (2 5,012.4 28.59 227.73 4,662.9 4,606.7 - 1,343.9 493.3 6,029,707.3 470,356.8 1.1 - 1,323.73 MWD +8AG+CA +I1FR +MS (2 5,107.1 27.62 230.71 4,746.4 4,690.2 - 1,373.0 459.6 6,029,678.3 470,323.0 1.8 - 1,322.38 MWD +SAG+CA +IIFR +MS (2 5,202.8 26.75 236.17 4,831.5 4,775.3 - 1,399.0 424.5 6,029,652.4 470,287.8 2.8 - 1,317.87 MWD +SAG+CA +1IFR +MS (2 5,297.2 26.56 241.72 4,915.9 4,859.7 - 1,420.9 388.3 6,029,630.7 470,251.5 2.8 - 1,309.45 MWD +SAG +CA +IIFR +MS (2 5,391.1 26.91 248.59 4,999.8 4,943.6 - 1,438.6 350.0 6,029,613.1 470,213.1 3.3 - 1,296.61 MWD +SAG +CA+IIFR +MS (2 5,486.6 25.75 262.96 5,085.5 5,029.3 - 1,449.0 309.3 6,029,602.9 470,172.4 6.8 - 1,276.75 MWD +SAG +CA +IIFR +MS (2 5,582.6 26.79 272.38 5,171.6 5,115.4 - 1,450.7 266.9 6,029,601.4 470,130.0 4.5 - 1,249.35 MWD +SAG +CA +IIFR +MS (2 5,678.0 28.45 280.32 5,256.2 5,200.0 - 1,445.7 223.1 6,029,606.5 470,086.2 4.2 - 1,216.03 MWD +SAG +CA +IIFR +MS (2 5,772.2 28.75 288.88 5,338.9 5,282.7 - 1,434.4 179.6 6,029,618.0 470,042.7 4.4 - 1,178.27 MWD +SAG+CA +1IFR +MS (2 5,867.1 29.93 294.74 5,421.6 5,365.4 - 1,417.1 136.4 6,029,635.5 469,999,7 3.3 - 1,136.36 MWD+SAG +CA +IIFR +MS (2 5,962.2 34.36 304.06 5,502.2 5,448.0 - 1,392.1 92.6 6,029,660.7 469,956.0 7.0 - 1,088.32 MWD+SAG +CA +IIFR +MS (2 6,057.1 38.18 308.34 5,578.7 5,522.5 - 1,358.9 47.4 6,029,694.1 469,910.9 4.8 - 1,033.25 MWD+SAG +CA +IIFR +MS (2 6,151.2 42.35 311.74 5,650.5 5,594.3 - 1,319.7 0.9 6,029,733.4 469,864.6 5.0 - 973.01 MWD +SAG +CA +IIFR+MS (2 6,245.5 46.18 316.59 5,718.0 5,661.8 - 1,273.8 -46.2 6,029,779.5 469,817.6 5.4 - 907.33 MWD +SAG+CA +1IFR +MS (2 6,340.6 49.91 319.45 5,781.6 5,725.4 - 1,221.2 -93.5 6,029,832.3 469,770.6 4.5 - 836.60 MWD +SAG +CA +11FR +MS (2 6,435.3 54.70 323.85 5,839.5 5,783.3 - 1,162.4 -139.8 6,029,891.3 469,724.5 6.3 - 761.94 MWD +SAG +CA +IIFR +MS (2 6,530.1 54.51 323.70 5,894.4 5,838.2 - 1,100.1 -185.5 6,029,953.8 469,679.1 0.2 - 685.15 MWD +SAG+CA +1IFR +MS (2 6,624.6 57.53 328.77 5,947.3 5,891.1 - 1,035.0 -229.0 6,030,019.1 469,635.8 5.5 - 607.74 MWD +SAG+CA +IIFR +MS (2 6,719.8 59.70 331.71 5,996.9 5,940.7 -964.4 -269.3 6,030,089.8 469,595.8 3.5 -528.49 MWD +SAG +CA +11FR+MS (2 6,814.3 63.73 334.45 6,041.6 5,985.4 -890.2 -306.9 6,030,164.1 469,558.5 5.0 - 448.38 MWD +SAG+CA +I1FR +MS (2 6,909.9 66.50 335.68 6,081.9 6,025.7 -811.6 7,005.3 68.64 335.44 6,118.2 6,062.0 -731.4 3 6,030,323.3 469,486.1 2.3 -281.98 MWD +SAG+CA +IIFR+MS (2 7,099.0 70.17 335.90 6,151.2 6,095.0 - 651.4 -416.1 6,030,403.3 469,450.3 1.7 - 198.65 MWD +SAG +CA+IIFR +MS (2 7,194.1 72.76 335.62 6,181.4 6,125.2 -569.2 -453.1 6,030,485.7 469,413.7 • 2.7 - 113.08 MWD +SAG +CA +IIFR +MS (2 7,288.5 75.09 336.06 6,207.6 6,151.4 -486.4 -490.2 6,030,568.6 469,376.8 2.5 -26.96 MWD +SAG+CA +IIFR +MS (2 7,384.9 75.80 336.22 6,231.8 6,175.6 -401.1 -528.0 6,030,654.1 469,339.4 0.8 61.46 MWD +SAG+CA +IIFR +MS (2 I 7,479.4 77.05 336.22 6,254.0 6,197.8 -317.0 -565,0 6,030,738.3 469,302.8 1.3 148.41 MWD +SAG+CA +IIFR +MS (2 7,573.7 76.56 335.63 6,275.5 6,219.3 -233.3 -602.4 6,030,822.2 469,265.7 0.8 235.43 MWD +SAG +CA +IIFR +MS (2 7,669.3 76.55 335.06 6,297.7 6,241.5 -148.7 -641.3 6,030,906.9 469,227.2 0.6 324.00 MWD +SAG +CA +IIFR +MS (2 7,742.1 76.74 334.66 6,314.6 6,258.4 - 84.6 -671.4 6,030,971.2 469,197.4 0.6 391.59 MWD +SAG +CA +IIFR +MS (2 7,806.2 78.38 335.03 6,328.4 6,272.2 -27.9 -698.0 6,031,027.9 469,171.0 2.6 451.31 MWD +SAG+CA +IIFR +MS (2 7,849.4 79.05 334,81 6,336,8 6,280.6 10.4 -715.9 6,031,066.3 469,153.2 1.6 491.70 MWD +SAG +CA +1IFR +MS (2 7,946.6 81.05 334.85 6,353.6 6,297.4 97.0 -756.6 6,031,153.1 469,112.9 2.1 583.04 MWD +SAG +CA +IIFR +MS (2 8,001.1 83.35 335.05 6,361.0 6,304.8 146.0 -779.5 6,031,202.1 468,090.2 4.2 634.58 MWD +SAG+CA +IIFR+MS (2 8,043.2 83.22 334.65 6,365.9 6,309.7 183.8 -797.3 6,031,240.0 469,072.6 1.0 674.48 MWD +SAG +CA +IIFR +MS (2 8,136.2 86.09 332.82 6,374.6 6,318.4 266.8 -838.2 6,031,323.2 469,032.0 3.7 763.34 MWD+SAG +CA +IIFR +MS (2 8,233.2 87.57 330.41 6,380.0 6,323.8 352.0 -884.3 6,031,408.6 468,986.3 2.9 857.23 MWD +SAG +CA +1IFR+MS (2 8,328.8 90.04 327.36 6,381.9 6,325.7 433.8 -933.6 6,031,490.6 468,937.2 4.1 950.87 MWD +SAG+CA +IIFR +MS (2 6 Page 4 COMPASS 2003.16 Bulk! 426 • • Halliburton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co-ordinate Project Oooguruk Developement �: Well ODSN -37 - Slot ODS-37 Site: Oooguruk Drill Site TVD Reference: 42.7' + 13.5' @ 56.2ft (Nabors 19AC) Well: ODSN -37 Reference: 42.7' + 13.5' @ 56.2ft (Nabors 19AC) Wellbore: ODSN -37 PN8 North Reference: True Design: ODSN -37 PN8 Surveys Survey Calculation Method: Minimum Curvature Database: .Pioneer Alaska Survey MD Inc qz► DID TVDSS 04/4 MaP Map Vertical MD Inc Omen (ft) (D (ft) +E/-W wing Fasting 013 Section 1) (n) (ft) (R) ( (ft) Survey Tool Name 8,426.3 89.66 323.54 6,382.2 6,326.0 514.1 -988.9 6,031,571.1 468,882.3 3.9 1,047.43 MVVD+SAG+CA+IIFR+MS (2 8,522.6 88.18 321.16 6,384.0 6,327.8 590.4 - 1,047.7 6,031,647.6 468,823,8 2.9 1,143.38 MWD +SAG +CA +IIFR +M8 (2 8,818.2 91.63 317.75 6,384.2 6,328.0 663.0 - 1,109.8 6,031,720.4 468,762.0 5.1 1,238.84 MWD +SAG +CA +IIFR +MS (2 8,710.5 91.70 317.81 6,381.5 6,325.3 731.3 - 1,171.9 6,031,789.0 468,700.2 0.1 1,331.18 MWD +SAG +CA +IIFR +MS (2 8,811.3 92.94 317.57 6,377.4 6,321.2 805.8 - 1,239.7 6,031,863.7 468,632.7 1.3 1,431.87 MWD +SAG +CA +IIFR +MS (2 8,910.0 91.63 317.22 6,373.5 6,317.3 878.4 - 1,306.5 6,031,936.6 468,566.3 1.4 1,530.52 MWD +SAG +CA +IIFR +MS (2 9,006.4 89.78 315.51 6,372.3 6,316.1 948.2 - 1,372.9 6,032,006.6 468,500.1 2.6 1,626.85 MWD +SAG +CA +IIFR +MS (2 9,104.0 89.54 313.05 6,372.9 6,316.7 1,016.3 - 1,442.8 6,032,075.0 468,430.5 2.5 1,724.28 MWD +SAG +CA+IIFR +MS (2 9,199.6 89.60 315.51 6,373.6 6,317.4 1,083.0 - 1,511.3 6,032,142.1 468,362.3 2.6 1,819.76 MWD +SAG +CA +1IFR +MS (2 9,296.6 89.66 315.64 6,374.2 6,318.0 1,152.3 - 1,579.1 6,032,211.6 468,294.7 0.1 1,916.67 MWD+SAG+CA+IIFR+MS (2 9,391.1 91.27 316.54 6,373.4 6,317.2 1,220.4 - 1,644.7 6,032,279.9 468,229.5 2.0 2,011.13 MWD +SAG +CA +IIFR +MS (2 9,485.4 90.15 316.64 6,372.3 6,316.1 1,288.8 - 1,709.4 6,032,348.6 468,165.0 1.2 2,105.39 MWD +SAG +CA +IIFR +MS (2 9,532.1 92.51 315.31 6,371.2 6,315.0 1,322.4 - 1,741.9 6,032,382.4 468,132.6 5.8 2,152.10 MWD +SAG+CA +1IFR +MS (2 9,582.1 93.80 314.56 6,368.4 6,312.2 1,357.7 - 1,777.2 6,032,417.7 468,097.5 3.0 2,201.92 MWD +SAG +CA +IIFR +MS (2 9,678.9 94.11 316.48 6,361.8 6,305.6 1,426.6 - 1,844.9 6,032,486.9 468,030.1 2.0 2,298.45 MWD+SAG +CA +IIFR +MS (2 9,775.6 95.22 317.74 6,353.9 6,297.7 1,497.2 - 1,910.5 6,032,557.8 467,964.8 1.7 2,394.84 MWD +SAG+CA +IIFR +MS (2 9,818.0 95.91 318.89 6,349.8 6,293.6 1,528.7 - 1,938.5 6,032,589.4 467,936.9 3.2 2,437.01 MWD +SAG+CA +IIFR +MS (2 9,871.3 93.97 319.01 6,345.2 6,289.0 1,568.8 - 1,973.4 6,032,629.6 467,902.1 3.6 2,490.14 MWD +SAG+CA +IIFR +MS (2 9,969.9 94.10 321.10 6,338.3 6,282.1 1,644.2 - 2,036.6 6,032,705.2 467,839.3 2.1 2,588.38 MWD +SAG+CA +IIFR +MS (2 10,066.1 93.61 322.45 6,331.8 6,275.6 1,719.6 - 2,096.0 6,032,780.9 467,780.2 1.5 2,684.09 MWD +SAG+CA +IIFR +MS (2 10,161.5 92.68 322.67 6,326.6 6,270.4 1,795.2 - 2,153.9 6,032,856.7 467,722.6 1.0 2,778.93 MWD +SAG+CA +IIFR+MS (2 10,258.5 91.88 322.14 6,322.7 6,266.5 1,872.0 - 2,213.0 6,032,933.8 467,663.8 1.0 2,875.51 MWD +SAG +CA +IIFR +MS (2 10,354.8 91.14 319.54 6,320.2 6,264.0 1,946.6 - 2,273.8 6,033,008.6 467,603.3 2.8 2,971.61 MWD +SAG+CA +IIFR +MS (2 10,451.8 90.89 319.07 6,318.4 6,262.2 2,020.1 - 2,337.0 6,033,082.4 467,540.4 0.5 3,068.51 MWD +SAG+CA +IIFR+MS (2 10,547.6 90.28 322.09 6,317.5 6,261.3 2,094.2 - 2,397.9 6,033,156.7 467,479.9 3.2 3,164.20 MVVD+SAG+CA+1IFR+MS (2 10,644.5 89.35 320.33 6,317.8 6,261.6 2,169.7 - 2,458.6 6,033,232.4 467,419.5 2.1 3,260.87 MWD +SAG+CA +IIFR +MS (2 10,740.4 91.64 320.47 6,316.9 6,260.7 2,243.5 - 2,519.6 6,033,306.5 467,358.7 2.4 3,356.59 MWD +SAG +CA +IIFR +MS (2 10,836.3 90.77 321.67 6,314.9 6,258.7 2,318.2 - 2,579.9 6,033,381.4 467,298.7 1.5 3,452.34 MWD +SAG +CA +IIFR +MS (2 10,935.0 90.89 320.04 6,313.5 6,257.3 2,394.6 - 2,642.2 6,033,458.1 467,236.8 1.7 3,550.79 MWD +SAG +CA +IIFR +MS (2 11,031.7 90.03 319.14 6,312.7 6,256.5 2,468.3 - 2,704,9 6,033,532.0 467,174,4 1.3 3,647.49 MWD +SAG+CA+IIFR +MS (2 11,127.9 90.77 320.21 6,312.1 6,255.9 2,541.6 - 2,767.1 6,033,605.6 467,112.5 1.4 3,743.56 MWD +SAG +CA +IIFR +MS (2 11,224.8 89.53 319.55 6,311.8 6,255.6 2,615.8 - 2,829.6 6,033,679.9 467,050.3 1.4 3,840.41 MWD +SAG +CA +IIFR +MS (2 11,320.3 90.34 321.71 6,311.9 6,255.7 2,689.6 - 2,890.2 6,033,754,0 466,990.1 2.4 3,935.73 MWD +SAG+CA +IIFR +MS (2 11,416.5 87.74 323.20 6,313.5 6,257.3 2,765.8 - 2,948.8 6,033,830.5 466,931.8 3.1 4,031.54 MWD+SAG +CA +IIFR +MS (2 11,514.0 87.44 322.58 6,317.6 6,261.4 2,843.5 - 3,007.6 6,033,908.4 466,873.3 0.7 4,128.55 MWD +SAG +CA +IIFR +MS (2 11,610.0 86.57 321.19 6,322.6 6,266.4 2,918.9 - 3,066.7 6,033,984.0 466,814.4 1.7 4,224.10 MWD +SAG+CA +IIFR +MS (2 11,705.3 85.82 321.71 6,329.0 6,272.8 2,993.3 - 3,126.0 6,034,058.7 466,755.5 1.0 4,318.99 MWD +SAG +CA +IIFR +MS (2 11,800.2 85.89 320.95 6,335.8 6,279.6 3,067.2 - 3,185.1 6,034,132.8 466,696,7 0.8 4,413.39 MWD +SAG +CA +IIFR +MS (2 11,897.1 84.77 320.72 6,343.7 6,287.5 3,142.1 - 3,246.1 6,034,207.9 466,636.0 1.2 4,509.83 MWD +SAG +CA +IIFR +MS (2 11,934.6 84.46 321.11 6,347.2 6,291.0 3,171.1 - 3,269.7 6,034,237.0 466,612.6 1.3 4,547.08 MWD +SAG+CA +IIFR +MS (2 611/2009 11:04:48AM Page 5 COMPASS 2003.16 Build 42B III Haul • Burton Company Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co -ordinate Referen Project Developement TVD Reference: �: Well ODSN -37 - Slot ODS -37 Site: Oooguruk Drill Site ference: 42.7' + 13.5' @ 56.2ft (Nabors 19AC) Well: ODSN -37 Ref erence: 42.7' + 13.5' © 56.2ft (Nabors 19AC) Wellbo+e: ODSN -37 PN8 North Reference: True Design: ODSN -37 PN8 Surveys Survey Calculation mod: Minimum Curvature Database: .Pioneer Alaska Survey Map Map Vertical MD Inc Azi TVD wins +W -S +E/-W Northing Easting DLS Section (ft) ( ?) (hearth (ft) (ft) (ft) (ft) (n) (ft) ( /9110' Survey 11,995.4 86.40 320.06 6,352.1 6,295.9 3,217.8 - 3,308.1 6,034,283.9 466,574.3 a 3.6 4 MWD+SA +I (2 12,090.4 86.51 320.27 6,357.9 6,301.7 3,290.7 - 3,368.9 6,034,357.0 466,513.8 0.2 4,702.30 MWD +SAG +CA +IIFR +MS (2 12,186.0 88.31 320.29 6,362.3 6,306.1 3,364.2 - 3,429.9 6,034,430.7 466,453.1 1.9 4,797.70 MWD +SAG +CA +IIFR +MS (2 12,283.7 89.54 319.82 6,364.1 6,307.9 3,439.0 - 3,492.6 6,034,505.8 466,390.7 1.3 4,895.26 MWD +SAG+CA +IIFR +MS (2 12,381.4 91.58 318.84 6,363.1 6,306.9 3,513.1 - 3,556.3 6,034,580.1 466,327.4 2.3 4,992.87 MWD +SAG +CA +IIFR +MS (2 12,477.1 90.15 317.74 6,361.7 6,305.5 3,584.6 - 3,620.0 6,034,651.9 466,263.9 1.9 5,088.63 MWD +SAG +CA +IIFR +MS (2 12,575.4 91.02 319.71 6,360.7 6,304.5 3,658.4 - 3,684.8 6,034,725.9 466,199.5 2.2 5,186.81 MWD +SAG +CA +IIFR +MS (2 12,668.7 91.64 320.60 6,358.5 6,302.3 3,730.1 - 3,744.6 6,034,797.8 466,140.0 1.2 5,280.05 MWD +SAG +CA +IIFR +MS (2 12,763.3 91.70 320.81 6,355.8 6,299.6 3,803.2 - 3,804.4 6,034,871.2 466,080.4 0.2 5,374.44 MWD +SAG +CA +IIFR +MS (2 12,860.9 90.83 322.16 6,353.6 6,297.4 3,879.6 - 3,865.2 6,034,947.8 466,020.0 1.6 5,471.76 MWD +SAG+CA +IIFR +MS (2 12,958.1 92.13 321.51 6,351.1 6,294.9 3,956.0 - 3,925.3 6,035,024.5 465,960.2 1.5 5,568.68 MWD +SAG +CA +IIFR +MS (2 13,052.5 93.80 321.90 6,346.2 6,290.0 4,029.9 - 3,983.7 6,035,098.7 465,902.1 1.8 5,662.65 MWD +SAG+CA +IIFR +MS (2 13,152.4 94.73 321.66 6,338.8 6,282.6 4,108.2 - 4,045.3 6,035,177.2 465,840.8 1.0 5,761.99 MWD +SAG +CA +IIFR +MS (2 13,248.2 95.47 321.28 6,330.3 6,274.1 4,182.9 - 4,104.7 6,035,252.0 465,781.7 0.9 5,857.19 MWD +SAG +CA +IIFR +MS (2 13,318.5 96.65 320.95 6,322.9 6,266.7 4,237.2 - 4,148.6 6,035,306.6 465,738.0 1.7 5,926.89 MWD+SAG +CA +IIFR +MS (2 13,343.2 96.40 321.09 6,320.1 6,263.9 4,256.4 - 4,164.1 6,035,325.8 465,722.7 1.2 5,951.44 MWD +SAG+CA +IIFR+MS (2 13,440.2 95.52 321.50 6,310.0 6,253.8 4,331.7 - 4,224.4 6,035,401.3 465,662.6 1.0 6,047.73 MWD +SAG +CA +IIFR+MS (2 13,507.7 93.73 319.81 6,304.5 6,248.3 4,383.6 - 4,267.0 6,035,453.4 465,620.2 3.6 6,114.82 MWD +SAG+CA +IIFR +MS (2 13,538.5 93.30 319.62 6,302.6 6,246.4 4,407.1 - 4,286.9 6,035,477.0 465,600.4 1.5 6,145.55 MWD +SAG+CA +IIFR +MS (2 13,635.4 91.69 319.30 6,298.4 6,242.2 4,480.7 - 4,349.9 6,035,550.9 465,537.8 1.7 6,242.37 MWD +SAG+CA +IIFR+MS (2 13,731.3 90.89 317.26 6,296.3 6,240.1 4,552.2 - 4,413.6 6,035,622.6 465,474.3 2.3 8,338.17 MWD +SAG+CA +11FR+MS (2 13,828.4 91.57 318.34 6,294.2 6,238.0 4,624.2 - 4,478.9 6,035,694.8 465,409.4 1.3 6,435.29 MWD +SAG +CA +IIFR +MS (2 13,924.2 90.89 318.53 6,292.1 6,235.9 4,695.8 - 4,542.4 6,035,766.7 465,346.2 0.7 6,531.02 MWD +SAG +CA +IIFR+MS (2 14,020.9 91.20 319.79 6,290.4 6,234.2 4,769.0 - 4,605.6 6,035,840.1 465,283.2 1.3 6,627.67 MWD +SAG+CA+IIFR+MS (2 14,117.8 90.46 318.80 6,289.0 6,232.8 4,842.4 - 4,668.8 6,035,913.8 465,220.3 1.3 6,724.51 MWD +SAG+CA +IIFR +MS (2 14,214.0 90.52 320.08 6,288.1 6,231.9 4,915.5 - 4,731.3 6,035,987.1 465,158.1 1.3 6,820.63 MWD +SAG +CA +IIFR +MS (2 14,258.5 91.02 321.79 6,287.5 6,231.3 4,950.0 - 4,759.4 6,036,021.8 465,130.2 4.0 6,865.02 MWD+SAG +CA +IIFR +MS (2 14,295.0 91.02 321.79 6,286.9 6,230.7 4,978.7 - 4,782.0 6,036,050.5 465,107.8 0.0 6,901.43 PROJECTED to TD 6/11/2009 1 1:04:48AM Page 6 COMPASS 2003.16 Build 42B . r G 8 o HYDRIL ANNULAR (519 — LK, LATCHED 1 HYDRIL 44 ROX WEIGHT 200 CONNECTIONS 1 95 I ' • 111111111111.1 HYDRIL SINGLE RAM " ,, RIL I �� / CONNECTIONS 111 / 1titl�l�■1 ti 1 `. �1� ( avPRO 1rcHr ffi saoo Les ��� + 1 l • r 4/11 - MDR2 SIDLE RAM � i► I H IL , snrD /s►uo coN ■i /•1 2 APAROx WEIGHT = NEC dDOD Les / I r CHOKE LINE. ■ .. . . .. 2' KILL UNE MIND CROSS . Nail► tl► tII aft / i �. g .1i► t_► 4/11 ► = 24 AP FIANGEMANGE CONNECTIONS PROX WEIGHT I I SVRNG RADIUS --- MEI' RIL II ' HYDRNL SIUCEO 44 -5/8" \ Y I 2 A WEEIGHT CONNECTIONS t I . • I 1 HYDRIL 11 " 5,000PSI BOP STACK 95 PLAN VIEW • i I HYDRIL 11 " 5,000PSI BOP STACK ! ELEVATION ANabo t m c Aiti � tt i Wawa NG 19-AC tat &P STACK • - . moRit. 11", 5,000PS1 OWN IN zof Ws= IN M704:0 If 8 mff Wit. A i sou 'nor two. —, $TS KF9 tSt YO1J m. !n • 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 Est Depth Pumped Vol IA OA P psi Fluid Type YP (ND) (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 (ND) , Minimum ID Type Width (in) Depth (ND) 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 • • Mrvlc Oooguruk Drill Site Well Handover Form " ` PIONEER WtuBYeFHNIWFS isari To Drilling Well Name Producer New Well To rProduction API* Injector Workover To Well Work PTD/ AFE Number Sidetrack Completion Date DIRECTIONAL INFORMATION DOWNHOL.E INFORMATION Original RKB KOP Drillers TD Max angle to XN / at XN PBTD /Top of fill or Junk Date Tagged Hole Angle @ TD A SITP WELL INFOR TION OAP OAP BHP / Depth / Date / Met. DOWNH LUGS (X or r co commmeent) BPV Installed Well Bore Seaton: Description .......devils Weight 2 Way Check 9 (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 (AI Active Intervals) Top Bottom SPF /SLOT SIZE ' Gun Type / Charge / Orientation I Date KNOWN Communication (X for known comet) Tbg X IA IA X OA Other -- — - I - i - - -- -- - - --- -- -- - ---- .- ..__- - -- --- -- - -- -- Note: All boxes checked require � --- ---..- .-- --- - -- ---- - --- 1 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 Rating) IA Valve type Tree (Manufacturer / Model / Type / Pressure Rating) Tree Cap Connection Tubing Hanger Connection PackoffAssembly Barrier: NBNSfl .ra.pluedpX) Test Pressure I F Mechanical Weebore Section Test Pressure Pass? (YIN) State Wanes() Comments Integrity Tubing Tests Prod Annulus Surf Annulus I I Cmt Shoe (Y/N)I 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 Wellbay Clean of All Residual Drilling Equipment? Yes or No Comments: 4. Are the Well Bay Hatch and Slickline 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? a. Are there thugs/sleeves in the well? Yes Type of Plug? Depth? 9. Are there plugs/sleeves In the well? No Jewelry? Type of Plug? Depth? 10.1s there a DH gauge in the well? Yes Type Jewelry? Gauge? Pressure? Temperature? Fii }al l' /ellUOr'e F2e✓ cw ■ "A7F TI6�E'. -- -- _- --. -- _ Pa P°9N 177:4 ""J�1f Mill . ,, [,� Omar. Mon Other: OP[ NA !or/S DPW . r+rrd■ovE O . nmom • • et/tat/Ye: rre[e Dri119ae D ate : p?r'! n.:,t, - 1 • Well ODSN -37 ODSN -17 ODSK -14 Hydrow II Packer Depth (ft -MD) 4045 2638 4838 Angle @ Packer 27° 4r 55° ESP Depth (ft -MD) 7307 13753 9921 Block Weight (kips) 50 50 50 Anticipated PU String Hook Weight - Above Packer (kips) 72 64 79 Stretch (f 1.7 0.5 1.6 Packer Shear Release (kips) 33 33 33 Anticipated Surface Overpull for Packer Shear Release (kips) 55 47 62 Anticipated Hook weight for Shear Release (kips) 127 111 141 Anticipated Hook Weight - Full String after packer release (kips) 103 132 138 Stretch - Full string (ft) 6 9 6.4 80% Tensile Limit (kips) 165 165 165 90% Tensile Limit (kips) 180 180 180 100% Tensile Limit (kips) 195 195 195 Comments Previous ESP Run @ TD; PU 100 / SO 85 -total losses Previous ESP Run @ TO; PU Previous ESP Run @ TO; PU 1980 bbls 122 / S0 65 115 / 50 90 R ECOMMENDE•RACTICES itaits Pulling an ESP Completion 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 pulling an ESP completion. PREPARATION • Confirm spooling unit is aligned to provide a straight pull on the cable, and to provide operator clear view. ESP power cable may be damaged if rig is not positioned properly. Spooler to be spotted far enough back from the rig to allow adequate slack in the cable i.e. (Being able to see the entire derrick). Confirm Baker Hughes technician has reviewed operation of unit with operator and has signed operator off as qualified on Baker Hughes check off sheet. Confirm sheave is 54" in diameter. Confirm safety cable is attached to sheave. Normal running height shall not exceed 40' above floor. Confirm power to the ESP is locked out and cable is disconnected. All locks shall be attached in accordance with lock -out tag -out procedures. A pre job safety/planning meeting shall be held prior to pulling the pump and during crew changes to identify risks and mitigations. A Baker Hughes representative will be on the rig floor at all times during the ESP pull. Refer to previous install records and tally sheets for a list previously installed clamps. Keep an accurate count of all small parts pulled from the well. A Baker Hughes representative shall be on the rig floor to disconnect penetrator, make down -hole electrical checks, and to disassemble and inspect ESP. A Baker Hughes representative will check and record phase -to -phase and phase -to- ground conductivity for all three ESP cable legs at each electrical connection/splice. PULLING PROCEDURE 1. RU ESP cable spooling unit with empty cable spool installed. Ensure that the rig is properly centered over the well to prevent damage to the cable when pulling the ESP - remember that the tree is off center on the ESP wells and the rig must be centered with the tubing head adapter. 2. Notify Baker Hughes representative prior to releasing the hanger. A Baker Hughes representative shall be on location when the hanger penetrator is pulled. Close annular preventor. Slowly PU assembly until hanger is off tubing spool. If well is stable, open annular preventer. Record pick up and slack off weights. Continue PU until hanger is at rig floor. LD landing joint and hanger. • Check and record ESP conductivity phase- to-phase and phase - to-ground for all three Version 2.2 Page 1 of 8 This document is the property of Baker Hughes and the information contained herein is Pulling 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. o 2013 REC OMMENDE•RACTICES phases below the hanger penetrator. • High -pot the hanger penetrator prior to reusing. This test shall be performed and recorded in accordance with manufacturer's recommended procedures. • Confirm ESP cable sheave is 54" in diameter. Confirm safety cable is attached to sheave. 3. Pull ESP completion. Spool the ESP cable onto the spooling unit while pulling out of hole. Wipe the cable with absorbent to prevent oil contamination. Depending on well conditions, it may be possible to keep some diesel cap as solvent in the annulus to aid in pulling the tubing with less residual crude oil. However, under no circumstance should the well be under - balanced. • Verbal acknowledgement between driller and spooler erator is required completion is moved. °p r u each time the • Portable gas detectors shall be available on the rig floor and in the spooling shed. Detectors shall be tested for proper operation prior to pulling p p lhng cable. Gas checks shall be made rio ' pe dreally on the rig floor. Checks shall be made in the spooling unit whenever personnel enter the unit. • The entire length of the ESP cable shall be visually inspected as it comes out of the hole by the spooler operator. Flag visible bad spots in ESP cable and record approximate depths and cut out any damaged cable 5 foot above and 5 foot below the damage. Label each piece with the well, source, and depth - these will be sent to Baker Hughes at the end of the well for analysis. If there are several bad spots send the entire reel to Baker Hughes for analysis. • When bands are used they should be cut off, not twisted off as they come out of the hole. Record the number of bands suspected of being lost. • The hole shall be covered at all times when bands are being removed. • Cut out all pigtails and examine for signs of damage. Pigtails shall not be reused. 4. Pull ESP assembly but DO NOT lay it down. The ESP assembly must be inspected by section in the vertical position while on the rig floor by a Baker Hughes representative and a Pulling Inspection Report completed. 5. Lay down ESP 5.1. Discharge Assembly and Pump 5.1.1. All findings of the pump removal will be documented on the field service pull report. 5.1.2. Install the proper clamp on top of the pump. 5.1.3. Check the inside surface of the pump discharge for debris or wear. If shaft can be reached, rotate shaft(s) to check for side play and smooth shaft can be reached, rotate shaft(s) to check for side play and smooth rotation; record results on pull report. 5.1.4. Observe the pump as it is being lifted from well and look for paint scrapes, clings, scale, scratches, corrosion and scars. Check for indication of sand or scale behind protectors, flat cable and flat cable guards. Record fmdings on the pull report. 5.1.5. Place an additional clamp on the lower pump and set on the work table. Cover the wellbore and carefully separate the pump, be ready to catch Version 2.2 Page 2 of 8 This document is the property of Baker Hughes and the information contained herein is Pulling 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. 0 2013 RE COMMENDE•RACTICES the coupling. 5.1.6. After the two pumps are separated check shaft rotation of both pumps and check the condition of o- rings, coupling and shaft. 5.1.7. Put the shipping cap on upper pump and carefully lay down upper pump. 5.1.8. Check the top shaft of lower pump for shaft side play, plugging, scale, corrosion, erosion, shaft rotation. 5.1.9. Lift the lower pump to the intake and visually check the intake/gas sep. 5.1.10. Install a lifting clamp on the seal head. 5.1.11. Cover the wellhead and disconnect the pump from the seal, catch the coupling. Check shaft for side play. 5.1.12. Place the coupling on the pump shaft and then shipping cap. 5.1.13. Carefully lay down the pump and intake. 5.1.14. The procedure for checking the rotary gas separator and recirculation pump is the same as checking the pump. 5.2. Seal Section 5.2.1. Check the shaft rotation of the seal and motor coupled together using the proper coupling wrench. 5.2.2. Remove the plug from the head vent. Note: Use caution when removing the vent plug, as the oil inside the seal section could be under pressure. 5.2.3. Remove the vent plug from the upper guide drain and drain off the well fluid. The fluid that drains from this area should be well fluids. 5.2.4. Remove the vent plug from the center guide drain and drain off the contents (should be motor oil only). Record the type and quantity of fluid drained from all chambers on the pulling report. 5.2.5. Remove the vent plugs from the lower guide drain and drain the fluid from the chamber. 5.2.6. Reinstall the vent plugs in the center guide and lower guide drains. 5.2.7. Reinstall the vent plug in head vent and the upper guide drain. 5.2.8. Clean and dry off the pothead motor connection area plus about 18 5.2.9. inches above the motor head with solvent, motor oil, rags or other means. Version 2.2 Page 3 of 8 This document is the property of Baker Hughes and the information contained herein is Pulling 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. 4) 2013 RE COMMENDE•RACTICES J`• 5.2.10. Tie a rag around the bottom of the seal to prevent contamination of the pothead connection. 5.2.11. Disconnect the pothead by removing the socket head cap screws. 5.2.12. Remove the pothead with a straight pull, do not twist or bend back and forth. CAUTION: WHILE YOU ARE DISCONNECTING THE POTHEAD, MAKE SURE NO WELL FLUID, WATER, OR OTHER FOREIGN MATERIAL GETS INTO THE OPEN TERMINAL INSULATION BLOCK. 5.2.13. Use the oil pump assembly to flush any foreign material out of the terminal insulation block area. Put the pothead shipping cap on the motor head. CAUTION: The motor electrical tests must always be done a safe distance from the wellhead as a safety precaution to prevent sparks generated by a megohmmeter igniting gasses emitted from the wellhead. 5.2.14. Always perform the megohmeter test last; residual voltage charge left in the motor windings can damage motor rotation indicator and/or ohmmeter. Electrical test performed after a megohmmeter test should only be performed after the item has been shorted to ground for one (1) minute through the meter. 5.2.15. Put the correct clamp and lifting sling on the motor and set it on the wellhead. 5.2.16. Cover the wellhead to prevent fasteners or couplings from being dropped down the well. 5.2.17. Unbolt the seal section and lift it off the motor. 5.2.18. Capture a sample of the oil draining from the bottom of the seal section; note the condition of the oil on the pulling report. 5.2.19. Set the motor shipping cap on the motor head and install two hex head cap screws to hold it temporarily in place while checking the seal section shaft rotation. 5.2.20. Shaft rotation of seal section. 5.2.21. Check the seal shaft for side play the same way the pump shaft was checked. 5.2.22. With the assistance of a rig hand, hold the seal section to one side while you pull the shipping cap off and check the motor shaft rotation. 5.2.23. Flush the motor to seal coupling with clean oil and put it back on the shaft. 5.2.24. It is important to put the couplings back in the same location as shipped from the service center. Version 2.2 Page 4 of 8 This document is the property of Baker Hughes and the information contained herein is Pulling 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. 0 2013 RECOM MENDESRACTICES �� 5.2.25. Install a clean shipping cap on the seal base flange and bolt it securely with two bolts and two nuts. Carefully lay the seal down. 5.3. Motor 5.3.1. Put the shipping cap on the top of the motor and secure with bolts. 5.3.2. Lift the motor from the well and look for drag marks and corrosion. 5.3.3. Remove the lower drain from the base of the motor to remove an oil sample for inspection. 5.3.4. Note the condition of the oil on the pulling report; dark, water, brass, steel,black, etc. 5.3.5. Replace the lower drain in the base and carefully lay the motor down. 5.3.6. After the equipment has been laid down and the motor has been moved a safe distance from the wellhead, perform the following electrical tests: 5.3.7. Use an ohmmeter and measure the motor phase to phase resistance (A to B, A to C and B to C), record the results on the pulling report. 5.3.8. Use a megohmmeter to measure the motor phase to ground resistance (A to ground, B to ground, and C to ground). The megohmmeter D.C. test voltage should be 1,000 volts for one minute, record readings on pulling report. 6. Ensure Baker Hughes ESP checklists are completed. Ensure the Baker Hughes ESP Checklist has been • completed. Version 2.2 Page 5 of 8 This document is the property of Baker Hughes and the information contained herein is Pulling 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. (02013 RE CO MM BN D8 IORACT IC ES 000GURUK ESP CHECKLIST PULLING THE ESP ASSEMBLY PART 1 OF 2 WELL: BAKER HUGHES REP (INITIAL ITEMS AS THEY ARE COMPLETED) Confirm spooler operator is qualified to operate spooler. Confmn all power is disconnected and properly locked out. Safety/planning meeting held at beginning of job describing all work to be done and safety procedures to be followed. Entire length of cable visually inspected. Bad spots flagged. Depths of bad spots: ' Identify any junk left in hole while pulling ESP completion. Number of cable bands suspected lost in hole = Phase conductivity checked at the hanger penetrator and recorded on Baker Hughes pulling report. Phase conductivity checked below the hanger penetrator pigtail and recorded on Baker Hughes pulling report. Phase conductivity checked at the motor pothead and recorded on Baker Hughes pulling report. Examine areas for solids, metal, vibration, or drag marks and record: Pump Discharge: Pump Intake: Pump Body: Seal Body: Motor: Motor Pothead: Version 2.2 Page 6 of 8 This document is the property of Baker Hughes and the information contained herein is Pulling 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. B 2013 RECOMMENDE•RACTICES Motor Body: Version 2.2 Page 7 of 8 This document is the property of Baker Hughes and the information contained herein is Pulling 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. a'1 2013 iRI RECOMMENDESRACTICES OOOGURUK ESP CHECKLIST PULLING THE ESP ASSEMBLY PART 2 OF 2 WELL: BAKER HUGHES REP -- (INITIAL ITEMS AS THEY ARE COMPLETED) Attempt to manually turn. Check shaft play and coupling integrity for: Pump Discharge - Results: Pump Intake - Results: Gas Separator - Results: Seal Sections - Results: Motor - Results: Confirm Baker Hughes pulling report is completely filled out and is legible. Equipment boxed in shipping crates and ready to ship. Give completed form to Company Representative. Date: Comments: Version 2.2 Page 8 of 8 This document is the property of Baker Hughes and the information contained herein is Pulling an ESP Completion confidential and may not be distributed, either in pan or in whole, nor communicated to any competitor or potential competitor of Baker Hughes Inc. 0 2013 AGER O.D.: 5.500" MINOR 0.13.: 4.593" 11 1 ORIENTING CONNECTION 0.D.: 3.625" a SLEEVE WEIGHT: 6.4# MINIMUM I.D.: 2.365" DRIFT 1.D.: 2.347" OVERALL LENGTH: 108" CONNECTION(S): TYPE: OVAL MATERIAL: 4130 80 KSI INTERNAL YIELD PRESSURE: 6,000 PS EXTERNAL YIELD PRESSURE: 4,000 PS BODY YIELD STRENGTH: 250,000 LBI BODY PIPE BRINELL: 217 -235 ROCKWELL C: 18 -22 s KICKOVER TOOL: KOT -2, OM -1 RUNNING TOOL: RK -1 POCKET PULLING TOOL: 1 -5/8 JDS LATCH: RK, RKP 1.556" SEAL BORE VALVE: 1.5" O.D. • 1.494" SEAL BORE III 0 A I NS ` DESCRIPTION 2.8 FO -2 SWAGE MANDREL ASSEMBLY SCALE SHT OF DWG NO N/A 1 1 2112S101 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 -1 MO 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 -psl, 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. • HALLIBURTC3N S 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 MINIMUM CLOSING PRES. 8751ds/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 API /ISO VALIDATION REFESCE 7803 OPERATING ENVELOPE 478LXE11 BDMI/TECHNICAL OPERATIONS MANUAL 478LXE11 (END) (Unless specified, Dim- inches, pres -psl, 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. HALLIBURTON • May 23, 2013 Engineering Data Sheet EQUIPMENT MATERIAL NO.: 101052771 HYDR CONTRL LINE,1/4,.049,3000,316L PART NUMBER: 22SXX31300 DESIGN SPECIFICATIONS TUBING MATERIAL 316L STAINLESS STEEL TUBING TYPE WELDED AND SUNK TUBING OUTSIDE DIAMETER .25 inch TUBING WALL THICKNESS .049 inch LENGTH 3000 foot FITTING MATERIAL 316E 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. RECOMMENDE•RACTICES • e treses 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 Hughes 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. tO 2012 OEM RECOMMENDE•RACTICES 4MS • CENTRALIZFR • 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 l' 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. rt) 2012 1��■ RECOMMENDEIIIRACTICES • BUSSES 8. Attach pump(s). 8.1. When running 4" pumps, secure MLE to pump housing using 4000- B -03PG 1.40 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 % 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 "Coat 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 Balser Hughes 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. 0 2012 IM MO RECOMMENDE•RACTICES • Was half 2 -7i8" 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 naming the completion. Notes: • Review and mark on the directional survey areas where the dogleg is more than 6 °. Reduce RTH 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. The ESP penetrator can damaged when the tubing be 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. tti 2012 MAU RECOMMENDEORACTICES Ensure appropriate checklists are completed. 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. (C( 2012 MUM RECOMMENDESRACTICE$ 000GURUK ESP T CHE KLI C S 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. 0 2012 IMMO RCCOMMCNDE RAC TICCS • BAKER 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. 02012 �1♦7! RECOMMENDEDSRACTICES 411 Was 000GURUK ESP CHECKLIST RUNNING THE ESPASSEMBLY 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 pert or m whole. nor communicated to any competitor or potential competitor of Baker Hughes Inc. rfi2_012 ;.' MOM • RECOMMENDEORAC TIC ES • Wats 000GURUK ESP CHECKLIST RUNNING THE ESPASSEMBLY 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 Hughes 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 communicated to any competitor or potential competitor of Baker Hughes Inc. 47 2012 � % ,of Thy • � V/7 sA THE STATE Alask Oil and Gas - _ S Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue � 0 Anchorage, Main: 90 279.343 Fax: 907.276.7542 Alex Vaughan Sr. Drilling Engineer Pioneer Natural Resources Alaska, Inc. t 700 G Street, Suite 600 ao g "' F 5 7 Anchorage, AK 99501 Re: Oooguruk Field, Nuiqsut Oil Pool, ODSN -37 Sundry Number: 313 -250 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, , Cathy P. oerster Chair DATED this Z3 day of May, 2013. Encl. • , R RECEIVED • ' • STATE OF ALASKA • MAY 1 7 201'3 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 MC 25280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate Q ► Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ 1 Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to {hill Number. Pioneer Natural Resources Alaska, Inc. Exploratory ❑ Development IS t 208 - 157 4 3. Address: 700 G Street, Suite 600 Stratigraphic ❑ Service ❑ 6. API Number. Anchorage, AK 99501 50-703-20586-00-00' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order govems well spacing in this pool? wA ODSN -37. Will planned perforations require a spacing exception? Yes ❑ No le 9. Property Designation (Lease Number): 10. Field /Pool(s): ADL 3550364. Oooguruk - Nuiqsut 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): 14,295' • 6287'. 14,281'• 6287'• N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 115' 16" 158' 158' N/A N/A Surface 3109' 9 - 5/8" 3150' 3012' 5750 psi 3090 psi Intermediate 7725' 7" 7764' 6319' 7240 psi 5410 psi Production Liner 6702' 4 -1/2" 7581' - 14,283' 6136' - 6223' 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 ", 6.5# L -80, IBT -M 7308' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): SSSV; 7" x 2 - 7/8" Pkr; Liner Top Pkr 742' MD/742' TVD; 4040' MD/3804' TVD; 7596' MD/6281' TVD , 12. Attachments: Description Summary of Proposal ©I 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic ❑ Development D Service ❑ 14. Estimated Date for 15. Well Status after proposed work: 5/21/2013 ❑ WDSPL ❑ Suspended ❑ Commencing Operations: Oil © . 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.vauohanaDxd.com Printed Name A lex Vaughan Titl Sr. Drilling Engineer Prepared By: Kathy Campoamor, 343 -2183 Signature Phone Date ..-�,� 343 -2186 5/17/2013 <r:. COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: RBDMS MAY 2 3 201 Spacing Exception Required? Yes ❑ No Subsequent Form Required: `0 — 4 O 4- ? APPROVED BY _ Approved by: 1 i COMMISSIONER THE COMMISSION Date: v 43 /3 dam` "' , Submit Form and Form 10 -403 ( evised 10120 \VAV) pprc l 1� �d }fir 1R montV from t. date / / 3 val. • Attachments in Duplicate � ��� \ \ � PIONEER RECEIVED 2013 NATURAL RESOURCES ADGCC Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, Alaska 99501 Tel: (907) 277 -2700 Fax: (907) 343 -2190 May 17 2013 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7 Avenue, Suite #100 Anchorage, AK 99501 RE: ODSN -37 Sundry Application to Punch Tubing REF: Permit To Drill # 208 -157 Pioneer Natural Resources, Alaska (PNRA) is submitting a proposal to perforate the tubing of ODSN -37 to prep well for a forthcoming ESP Workover. The proposed plan is as follows: Pre -Rig Work: 1. RU slickline over ODSN -37 two weeks prior to ESP workover 2. Tubing punch 2 -7/8" tubing using 4 spf (45 holes total) from 4,066' - 4,077' MDrkb. 3. Sweep tubing with 1.5 tubing volume filter seawater. 4. Close ScSSSV 5. Install TWC Re- Complete ODSN -37 with ESP 1. (Sundry to recomplete ESP will be provided prior to ESP workover) A • Alaska Oil & Gas Conseglion Commission May 17 2013 Page 2 of 2 Please find attached information for your review: 1) Form 10 -403 Application for Sundry. 2) ODSN -37 Schematic The following are PNRA's designated contacts for reporting responsibilities to the Commission: 1) Completion Report Alex Vaughan, Senior Drilling Engineer (20 AAC 25.070) (907) 343 -2186 alex.vaughan(pxd.com 2) Geologic Data and Logs Paul Daggett, Operations Geologist (20 AAC 25.071) (907) 343 -2134 Paul. daggettapxd. com Sincerely, Alex Vaughan Senior Drilling Engineer Attachments: Form 10 -403 Supporting information cc: ODSN -37 Well File • Pioneer Natural Resources Alaska Inc. ODSN -37 Page 2 AOGCC Form 10 -403, Application For Sundry Approvals Present Well Condition Summary, Box #11 Perforation Depth (MD/TVD) - Attachment 4 -W, 12.6 #, L -80 Liner - perforated pup jts with 6-1/2" holes @ depths listed: MD TVD 7766' — 7771' 6320' — 6321' 7892' — 7897' 6345' — 6345' 8060' — 8065' 6368' — 6368' 8186' — 8191' 6378' — 6378' 8311' — 8316' 6382' — 6382' 8516' — 8521' 6384' — 6384' 8718' — 8723' 6381' — 6381' 8920' — 8925' 6373' — 6373' 9130' — 9135' 6373' — 6373' 9340' — 9345' 6374' — 6374' 9550' — 9555' 6370' — 6370' 9758' — 9763' 6356' — 6355' 10011' — 10016' 6335' — 6335' 10139' — 10144' 6328' — 6328' 10348' — 10353' 6320' — 6320' 10553' — 10558' 6317' — 6318' 10755' — 10761' 6317' — 6316' 10958' — 10963' 6313' — 6313' 11165' - 11170' 6312' -6312' 11363' — 11368' 6312' — 6313' 11564' — 11569' 6320' — 6320' 11765' — 11770' 6333' — 6334' 11966' — 11971' 6350' — 6351' 12088' — 12093' 6358' — 6358' 12295' — 12300' 6364' — 6364' 12498' — 12503' 6362' — 6361' 12700' — 12705' 6358' — 6357' 12906' — 12911' 6353' — 6352' 13112' — 13118' 6342' — 6341' 13315' — 13320' 6323' — 6323' 13443' — 13448' 6310' — 6309' 13647' — 13852' 6298' — 6294' 13851' — 13856' 6294' — 6294' 14063' — 14068' 6290' — 6290' 14233' — 14238' 6288' — 6288' • S ODSN -37 ESP Completion As Run Casing Item # Item MD (ft) TVD (ft) A 16" Conductor 153 153 Well Head: 9 - 5/8 ", 5K, VetcoGray B 9 -5/8" 40# L -80 BTC, 8.835" ID 3,150 3,012 Tree: 4 - 1/2 ", 5K, Horizontal C 7" 26# L -80 BTC -M, 6.276" ID 7,764 6,319 D 2 -7/8" 6.5# L-80 IBT-M, 2.441" ID 7,233 6,193 - *Estimated TOC a 4981' MD - 500' above Torok 0 -. • , 1 VetcoGray Tubing Hanger 34 34 A ' ■ 2 2 -7/8" Wellstar Tubing Retreiveble ScSSSV 742 742 3 GLM #1 - 2 -7/8" x 1 -1/2" (min. 3 jts above top X nipple) 3,781 3,574 -® 2 -7/8" X Nipple 2.313" I.D. (min. 2 jts above Gas Vent 2 4 Valve Packer) 3,895 3,675 5 WFT 7" x 2 -7/8" Gas Vent Valve Packer (max. TVD 3800') 4,040 3,804 6 GLM #2 - 2 -7/8" x 1 -1/2" (min. 2 jts above XN nipple) 6,796 6,033 7 2 -7/8" X Nipple, 2.313" ID (max. incl. 66 deg) w/ RHC -M PIG 6,909 6,082 8 Automatic Divert Valve (ADV) 7,239 6,194 D 9 ESP (Pump, Motor, and Jewelry) 7,247 6,196 End of Assembly 7,308 6,213 10 WFT PBR Tie Back Sleeve 158 SN#23682673 -01 7,581 6,277 O O 11 WFT "NTH" Liner Top Pkr 7,596 6,281 B 12 WFT "PHR" Rotating Hyd Set Liner Hanger 7,597 6,281 N ON 13 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 7,766 6,320 � 4-1/2" 12.60# L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 7,892 6,345 Iv a) 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,060 6,368 C 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,186 6,378 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,311 6,382 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,516 6,384 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,718 6,381 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,920 6,373 OJ 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,130 6,373 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,340 6,374 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,550 6,370 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,758 6,356 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,011 6,335 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,139 6,328 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,348 6,320 1 0. 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,553 6,317 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,756 6,317 Q V V 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,958 6,313 4-1/2" 12.60# L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 11,165 6,312 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,363 6,312 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,564 6,320 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,765 6,333 O 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,966 6,350 4-1/2" 12.60# L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 12,088 6,358 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,295 6,364 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,498 6,362 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,700 6,358 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,906 6,353 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,112 6,342 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,315 6,323 41/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,443 6,310 10 41/2" 12.60# L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 13,647 6,298 41/2" 12.60# L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 13,851 6,294 1 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,063 6,290 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,233 6,288 12 14 Ray Oil Tool Silver Bullet Float Shoe (PLUGGED) w/ 4-1/2 I 14,281 6,287 O End of Assembly 14,283 6,287 C 0 13 •• •• 00 00 00 00 00 00 14 0• 00 00 00 00 00 00 00 •• 00 00 00 00 00 00 00 Date: R- . Comments PIONEER 7-30-2009 ESP Comp! Design Post TD 11-19-2009 Removed XN nipple, moved X nipple down ODSN -37 Producer AIURAI. RESOURCES ALASKA 11-20-2009 Item 6 revised to read X nipple, not XN nipple Well Schematic 12-09-2009 TWC As Built ESP Completion • • Page 1 of 1 Regg, James B (DOA) Prb 206- 1 57 From: Williams, Theresa [Theresa.Williams @pxd.com] Sent: Tuesday, November 15, 2011 4:48 PM i k l it To: Regg, James B (DOA) Cc: Hart, David; Cutting, Dan; OoogurukProdSuper; Williams, Theresa Subject: ODSN -37 Annular Pressure Notification Jim, On November 13 between 1330 and 1900 we saw an increase in outer annular pressure from 480 psi to 1753 psi. This well has an open 9 -5/8" casing shoe at 3,150' MD, 3,012'TVD (Tuffaceous shales) and the OA has not been bled in the past. You can see from the trends that the OA pressure is not tracking the IA pressure. Troubleshooting over the last 48 hours pointed toward a plug of some sort very near the surface. When the OA pressure was bled off it did so very quickly and little or no fluid was recovered. Based on this hypothesis we used a heat blanket at the well head and were able remove the plug. Since then we have pumped 2 bbls of methanol for the purpose of freeze protection. Please let me know if you need any more information. Regards, Theresa Williams Staff Operations Engineer Pioneer Natural Resources Alaska (907) 343 -2104 Office ' r ` 3 ;� f; (907) 383 -3596 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. • 11/16/2011 • • Oooguruk ODSN -37 PTD 2081570 11/15/2011 TIO Pressures Plots d& LE55:C2i ODSN -37 Last 72 Hours OA psi tjj 'A Psi WHP Psi 111:: 1l l I Y2Ol1 I 115 1111 Z11 11IIZ201f 11/42011 Q011 11'1y1011 11:m0PM 11 !O 1O M 11 P5 d1OAM 115010 PM 11561»M _.. e01115155...533w AM [s — (90 day. 01 000) ODSN -37 Last 90 Oays Well Converted to Lift Gas OA psi IA psi Well SI wompiRWRINvimou WHP ps i 151 41'1011 21556P 2756P 1028 5 1 s •11 1 1:51:56 iJrt 120396 PM 11:1556 PM YI.2T:56 PM 12:]456 PM i' 1 S1:E51•M ' 1111 IP S TATE OF ALASKA RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION (FIVE D REPORT OF SUNDRY WELL OPERATIONS DEC 3 1 200 1. Operations Abandon U Repair Well U Plug Perforations U Stimulate U Alaker 1 , & nilhkip st:).' Performed: Alter Casing ❑ Pull Tubing El Perforate New Pool ❑ Waiver ❑ Time Extension 1"'Fiz ,,r< ,r, Chilnge Approved Program ❑ Operat. Shutdown ❑ Perforate ❑ Re -e er Suspended Well ❑ 2. Operator 4. Well Class Before Work:. Permit to Drill Number: Name: Pioneer Natural Resources Alaska, Inc. Development 12 Exploratory 0 208 157 3. Address: 700 G Street, Suite 600 Stratigraphic❑ Service ❑�.. API Number: Anchorage, AK 99501 50- 703 - 20586 -00 7. Property Designation (Lease Number): bWeII Name and Number: `ADL 355036 ODSN -37 9. Field /Pool(s): Oooguruk - Nuiqsut Oil Pool 10. Present Well Condition Summary: Total Depth measured \ 14,295 feet Plugs (measured) N/A feet true vertical \ 6287 feet Junk (measured) N/A feet Effective Depth measured 14,281 feet Packer (measured) see info below feet true vertical 6287 feet (true vertical) feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 158' 158' N/A N/A Surface 3109' 9 -5/8" 3150' 3012' 5750 3090 Intermediate 7725' 7" 7764' 6319' 7240 5410 Production Liner 6702' 4 -1/2" 7581' - 14,283' 6277' - 6287' N/A N/A Perforation depth: Measured depth: See Attachment, pg. 2 True Vertical depth: See Attachment, pg. 2 Tubing (size, grade, measured and true vertical depth): 2 -7/8 ", 6.5# L -80, IBT - 7308' MD 6213' TVD ' 2 -7/8" ScSSSV WFT 7" x 2 -7/8" WFT Liner Top Pkr Packers and SSSV (type, measured and true vertical depth): 742'MD / 742'TVD 4040'MD / 3804TVD 7596'MD / 6281' TVD 11. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 80 bbls freeze protect; 3500 psi 12. Representative Daily Average Production or Injection Data Oil-Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 660 417 0 840 310 Subsequent to operation: 380 120 0 260 330 13. Attachments: \4. Well Class after work: • Copies of Logs and Surveys Run Exploratory❑ Development 12 Service ❑ Daily Report of Well Operations X \Well Status after work: Oil El Gas ❑ WDSPL ❑ GSTOR ❑ WAG ❑ GINJ ❑ WINJ❑ 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: 309 -276 Contact Tim Crumrine, 343-2184 Prepared By: Kathy Campoamor, 343 - 2183 Printed Name Ver` •hnso Title Sr. Staff Drilling Engineer 1Z 3( ° I Signature Ar ---- Phone 343 -2111 Date 12/31/2009 tDMS JAN - 2 201 STh 7/ g... /- y-4 . Form 10-404 Revised 7/2009 SubmitOriginal Only '/% o • Pioneer Natural Resources Alaska Inc. ODSN -37 Page 2 AOGCC Form 10 -404, Report of Sundry Well Operations Box #10, Attachment — Perforation Depth 10. Perforation Depth (MD and TVD) 4 -1 ", 12.6 #, L -80 Liner - perforated pup jts with 6 -1/2" holes @ depths listed: MD TVD 7766' — 7771' 6320' — 6321' 7892' — 7897' 6345' — 6345' 8060' — 8065' 6368' — 6368' 8186' — 8191' 6378' — 6378' 8311' — 8316' 6382' — 6382' 8516' — 8521' 6384' — 6384' 8718' — 8723' 6381' — 6381' 8920' — 8925' 6373' — 6373' 9130' — 9135' 6373' — 6373' 9340' — 9345' 6374' — 6374' 9550' — 9555' 6370' — 6370' 9758' — 9763' 6356' — 6355' 10011' — 10016' 6335' — 6335' 10139' — 10144' 6328' — 6328' 10348' — 10353' 6320' — 6320' 10553' — 10558' 6317' — 6318' 10755' — 10761' 6317' — 6316' 10958' — 10963' 6313' — 6313' 11165' — 11170' 6312' — 6312' 11363' — 11368' 6312' — 6313' 11564' — 11569' 6320' — 6320' 11765' — 11770' 6333' — 6334' 11966' — 11971' 6350' — 6351' 12088' — 12093' 6358' — 6358' 12295' — 12300' 6364' — 6364' 12498' — 12503' 6362' — 6361' 12700' — 12705' 6358' — 6357' 12906' — 12911' 6353' — 6352' 13112' — 13118' 6342' — 6341' 13315' — 13320' 6323' — 6323' 13443' — 13448' 6310' — 6309' 13647' — 13852' 6298' — 6294' 13851' — 13856' 6294' — 6294' 14063' — 14068' 6290' — 6290' 14233' — 14238' 6288' — 6288' PIONEER O perations Summary Report NATURAL RESOURCES Well Name: ODSN -37 Contractor: NABORS DRILLING Rig Number: 19 -AC Job Category: DEVELOPMENT COMPLETION Start Date: 11/26/2009 End Date: 11/30/2009 Depth Start Foot/Meters Cat Mud Start Date End Date OMB) (e) Dens OeigeD Summary 11/26/2009 11/27/2009 0.0 8.50 Move rig onto ODSN -37 and RU same. Rig accepted @ 00:00 hrs 11/26/09. RU kill line to the IA on ODSN -37 while taking on 355 bbls of seawater into mud pits. Test lines to 1500 psi, (OK). Line up to take returns to the flowback tanks, shut in pressures - IA 655 psi, TP 900 psi. Start pumping seawater down IA and stage pumps up to 5 bpm with 650 psi taking returns to the flowback tanks. 140 total bbls pumped, shut down and monitor pressure - IA 0, TP 275 psi. Pressure rose quickly to 400 psi on IA, pumped 50 more bbls of seawater down IA and IA pressure was 0. Monitor well ISIP - IA 0, TP 0, pressure rose up to IA 272 psi, TP 31 psi. Attempt to bleed IA down without success. Line up to pump down the tubing and take returns through the IA, through the rig choke manifold and gas buster. Open IA and attempt to circulate gas bubble out the hole by pumping seawater down the tubing - no returns. Pumped tubing capacity plus 20% for 133 bbls total with no fluid returns. Shut down pumps and shut in, and monitor well for 1 hour - SIP IA 0, TP 0. Install BPV in tubing hanger, ND production tree. Install test dart in tubing hanger. Install drilling riser. Change out Vetco Gray NT -2 quick connector on BOP stack and stab same. Continued to monitor IA pressure and pump 5 bbls down IA every 30 min, max pressure seen on IA while pumping was 28 psi, (15 BBL's total). 11/27/2009 11/28/2009 0.0 8.50, NU}3QPg.390,Annular to 250 psi low / 2590 psi high Test Upper 2-7/8" x 5" Van's, Lower 4.5" Single Bore Rams with 4.5" tubing, Ch. e and Kill Line NCR's, Choke and Kill Line manual valves, Floor Safety Valve, Dart valve, Upper and Lower IBOP, 14 Choke manifold valves to 250 psi low / 3500 psi high. All low and high tests held 5 min ea. All tests charted. Accumulator test, System Pressure 3025 psi, After Closure 2200 psi, Initial 200 psi recovery 27 sec's, Full recovery 1 min 23 sec's. AOGCC representative Bob Noble waived witness of test at 17:00 hrs on 11/25/09. Change out test joint from 4,5° to 2.875 ". Test blind rams to 250 psi low / 3500 psi high. Test tipper 2 -7/8" x 5' VBR's with 2.875' tubing to 250 psi knot / 3500 psi high. Test Annular to 250 psi low / 2500 psi high - annular test failed, (attempt w /different traits). NO all MPD equipment. Change out annular preventer element. NU MK) equipment. Test Annular to 250 psi low / 2500 psi high with 2.875" tubing, (ok- chart same) and RD test equipment. NU trip nipple and air boot on same. Install flange on RCD head. Attempt to pull BPV from tubing hanger - gas cap on tubing - IA static. Attempt to bleed off as cap on tubing - unsuccessful. PU Vetco Gray landing joint with cross over an same to circulate down tubing. 11/28/2009 11/29/2009 0.0 8.50 PU Vetco Gray landing joint with cross over and RU same to circulate down tubing. Back out lock downs on tubing hanger and unseat hanger with 140k. IA was static, with 600 psi on tubing, fill IA with 90 bbls of sea water. Pump 100 bbls seawater with 30 bbl hi -vis sweep without returns. Land hanger in wellhead, back out and LD landing joint. Retrieve BPV from tubing hanger - well on vacuum. Pull tubing hanger and LD same. Consult with ODE about POOH with well on vacuum, decision was made to circulate hi -vis sweep out of the tubing before coming out the hole. Pump hi -vis sweep out of the tubing - gained full returns when sweep exited the tubing. Line up returns to the gas buster and circulate excess gas -cut fluid out of the well bore using multiple hi -vis sweeps, (recieved 50 BBL's of Oil w /BU #1 - dispose to CCU & transfer to RSC for disposal. CBU #2 -3 had no further problems & @ Hi -AV= 425 -500 FPM rate). Monitor well - 30 bbVhr loss rate. OOH laving down 4.5" frac string f/7.550' t/ stirfar.e. Install test plug, and change out bottom pipe rams from 4.5" to 2.875 ". Test same to 250 psi low / 3500 psi high on chart 5 minutes each test. RU ESP sheave in derrick and pull ESP wire over wind walls. RU 2.875" handling tools & power tongs. 11/29/2009 11/30/2009 0,0 8.50 RU HES control line spools and shieves while picking up Centrflift equipment. MU ESP pump,, motor and discharge • a e assem • and connect -. RI + ES • assembly on 2 -7/8 ", 6.5#, L -80 IB tubing 69' ,245'. Test P cable every 1,1 . • - Good. tests. PU and MU WFT T x 2.875" Hydro 2 retrievable packer with ESP gas vent valve. Cut ESP cable, make penetration through packer assembly. Install Gator -grip connector, and test same - Good test. Install HES control line to packer gas vent valve, function valve, and test line to 5000 psi for 10 min - Good test. RIH with ESP assembly on 2-7/8" tubing f/3,317' t/3,717'. Page 1/2 Report Printed: 12/28/2009 PIONEER •Operations Summary Report NATURAL RESOURCES Depth Start - Foot/Meters Last Mud Start Date End Date fay? (ft) Dens Weal) Summary 11/30/2009 12/1/2009 0.0 8.50 RIH with ESP assembly on 2 -7/8" tubing f/3,717' t/7,262'. MU tubing hanger and landing joint. Install .enetrator on tubins hanger make control line . enetrations with sacker 'as ven li - - " SSSV control line. Test packer vent line to 4000 psi and SSSV control line to 5000 psi - Good tests. Land hanger at 7 307' test tubing hanger upper and lower seals to 5000 psi for 10 min 9 9 9 Pp P each test on chart - Good tests. Change out bottom pipe rams from 2.875" to 4.5 ". ND BOPE. Make wellhead penetrations with control lines. Install production tree, test voids to 5000 psi and tree to 250 psi low and 5000 psi high on chart for 10 min - Good test. Make ESP cable pig tail up to BIW penetrator. Freeze protect by pumping down IA with 80 bbls diesel followed by 160 bbls of corrosion inhibited seawater. ,Drop roller stem ball and rod pressure un to 3500 psi held for 15 min to set packer. RU kill line on IA and test IA to 3500 psi held 30 min on chart - Good test. Rig released @ 24:00 hrs 11/30/09. Page 2/2 Report Printed: 12/28/2009 1 . ODSN -, Completion Aun Casing Item # Item MD (ft) TVD (ft) A 16" Conductor 153 153 Well Head: 9 -5/8 ", 5K, VetcoGray B 9 -5/8" 40# L -80 BTC, 8.835" ID 3,150 3,012 Tree: 4 -1/2 5K, Horizontal C 7" 26# L-80 BTC -M, 6.276" ID 7,764 6,319 D 2 -7/8" 6.5# L -80 IBT -M, 2.441" ID 7,233 6,193 *Estimated TOC @ 4981' MD - 500' above Torok C 1 VetcoGray Tubing Hanger 34 34 AA ' ` 2 2 -7/8" Wellstar Tubing Retreivable ScSSSV 742 742 3 GLM #1 - 2 -7/8" x 1 -1/2" (min. 3 jts above top X nipple) 3,781 3,574 -® 2 -7/8" X Nipple 2.313" I.D. (min. 2 jts above Gas Vent 0 4 Valve Packer) 3,895 3,675 5 WFT 7" x 2 -7/8" Gas Vent Valve Packer (max. TVD 3800') 4,040 3,804 6 GLM #2 - 2 -7/8" x 1 -1/2" (min. 2 jts above XN nipple) 6,796 6,033 7 2 -7/8" X Nipple, 2.313" ID (max. incl. 66 deg) w/ RHC -M Plu 6,909 6,082 8 Automatic Divert Valve (ADV) 7,239 6,194 D 9 ESP (Pump, Motor, and Jewelry) 7,247 6,196 End of Assembly 7,308 6,213 Lower Completion Item # Item MD (ft) ND (ft) 1 0 WFT PBR Tie Back Sleeve 15ft SN #23682673 -01 7,581 6,277 B 03 J 11 WFT "NTH" Liner Top Pkr 7,596 6,281 B 12 WFT "PHR" Rotating Hyd Set Liner Hanger 7,597 6,281 IN O 13 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 7,766 6,320 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 7,892 6,345 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,060 6,368 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,186 6,378 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,311 6,382 I 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,516 6,384 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,718 6,381 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,920 6,373 O J 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,130 6,373 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,340 6,374 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,550 6,370 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,758 6,356 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,011 6,335 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,139 6,328 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,348 6,320 1 O7 II 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,553 6,317 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,756 6,317 Q V V 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,958 6,313 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,165 6,312 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,363 6,312 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,564 6,320 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,765 6,333 O 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,966 6,350 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,088 6,358 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,295 6,364 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,498 6,362 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,700 6,358 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,906 6,353 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,112 6,342 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,315 6,323 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,443 6,310 11(114 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,647 6,298 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,851 6,294 1 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,063 6,290 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,233 6,288 12 14 Ray Oil Tool Silver Bullet Float Shoe (PLUGGED) w/ 4 -1/2 I 14,281 6,287 End of Assembly 14,283 6,287 O C 0 13 00 00 •• 00 00 00 00 00 14 00 00 00 00 00 00 00 00 00 00 00 DO 00 00 00 00 Date: Revision By: Comments P 0 N E [ 7 30 2009 TWC ESP Compl Design Post TD Remov ed 1 1 -19 2009 TWC ed XN nipple, moved X nipple down ODSN -37 Producer NATJRAL RESOURCES AIAS(A 11 -20 -2009 TWC Item 6 revised to read X nipple, not XN nipple Well Schematic 12 -09 -2009 TWC As Built ESP Completion • 1 L c'r rivriTr r r N PPP SEAN PARNELL, GOVERNOR b LIA c\ iLIE, , 11 VW U E ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION / ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Mr. Tim Crumrine Senior Completions Engineer Pioneer Natural Resources Alaska Inc. 700 G. Street, Suite 600 Anchorage, AK 99501 Re: Oooguruk, Nuiqsut Oil Pool, ODSN -37 Sundry Number: 309 -276 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. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Cathy .Foerster Commissioner 2 � a DATED this L2 day of August, 2009 Encl. 900 --15 r RECEI PIONEER ° �� NATURAL RESOURCES i ''' I `''`` Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, Alaska 99501 Tel: (907) 277 -2700 Fax: (907) 343 -2190 August 7, 2009 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite #100 Anchorage, AK 99501 RE: Application for Sundry, Recomplete with an ESP Permit to Drill # 208 -157 ' Surface Location: 2937' FSL, 1129' FEL, Sec. 11, T13N, R7E, UM X = 469869.00, Y = 6031053.00, ASP4 Pioneer Natural Resources, Alaska (PNRA) is submitting a proposal to recomplete ODSN -37 with an ESP. The proposed plan is as follows: Pre -Rig Work: 1. Provide 48 hours notice for the testing of the BOPE. 2. Post Peni+ 94I#20821€ 3a — +�7/ L I G� Re- Complete ODSN -37 with ESP 1. Kill well, Circ kill weight brine 2. MIRU ODSN -37. 3. ND Tree, NU BOPE 4. Test BOPE as per AOGCC to 250/3500 psi 5. Pull 4 %2" fracture completion string. 6. MU completion with ESP and RIH. 7. Land the tubing and RILDS. 8. Circulate corrosion inhibited brine and diesel to freeze protect the well to —2000' TVD. 9. Drop ball and rod and allow to seat. Pressure test the tubing to 3,500 psi — chart and hold for 30 minutes. Bleed off pressure and then pressure test the annulus to 3,500 psi — chart and hold for 30 minutes. Bleed off pressure. 10. Install TWC 11. ND BOPE, NU tree, test to 5,000 psi. 12. Remove TWC 13. RU Slickline and pull the ball and rod. Pull the RHC -m plug. 14. RD Slickline. RDMO to next well. • Alaska Oil & Gas Conservation Commission August 7, 2009 ODSN -37 Page 2 of 2 Please find attached information for your review: 1) Form 10 -403 Application for Sundry. The following are PNRA's designated contacts for reporting responsibilities to the Commission: 1) Completion Report Tim Crumrine, Senior Completions Engineer (20 AAC 25.070) (907) 343 -2184 tim.crumrineapxd.com 2) Geologic Data and Logs Paul Daggett, Operations Geologist (20 AAC 25.071) (907) 343 -2134 paul.daggettapxd.com Sincerely, • Tim Crumrine Senior Completions Engineer Attachments: Form 10 -403 Supporting information cc: ODSN -37 Well File 1 . RECEIVED • STATE OF ALASKA • A UG (0 11,0 ALASKA OIL AND GAS CONSERVATION COMMISSION AUG Q 7 2.009 ; APPLICATION FOR SUNDRY APPROVALS ' /\ Aiaska Gil & Gas Cons, Commission 20 AAC 25.280 1. Type of Request: Abandon I=1 Suspend ❑ Operational shutdown ❑ Perforate ❑ Waiver[f "1"h"c4L° Other El Alter casing ❑ Repair well ❑ Plug Perforations ❑ Stimulate ❑ Time Extension ❑ ESP Completion Change approved program ❑ Pull Tubing esp Perforate New Pool ❑ Re -enter Suspended Well ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Pioneer Natural Resources Alaska Inc. Development 0 . Exploratory ❑ 208 - 157 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: 700 G Street, Suite 600 Anchorage, AK 99501 50 703 - 20586 - 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: ODSN -37 . Spacing Exception Required? Yes ❑ No 0 9. Property Designation: 10. KB Elevation (ft): 11. Field /Pool(s): ADL 355036 ' 56.2' . Ooogurk - Nuiqsut Oil Pool 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 14,295' 6287' 14,281' 6287' N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 158' 158' N/A N/A Surface 3142' 9 -5/8" 3150' 3012' 5750 psi 3090 psi Intermediate 7759' 7" 7764' 6319' 7240 psi 5410 psi Production 6683' 4 -1/2" 14,283' 6287' N/A N/A Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attachment & Schematic See Attachment & Schematic 4 12.6# L - 80, Hydril 521 7593' Packers and SSSV Type: Packers and SSSV MD (ft): ScSSSV ; W FT 'NTH' Liner Top Packer 759' ; 7596' 13. Attachments: Description Summary of Proposal IN 14. Well Class after proposed work: Detailed Operations Program pi BOP Sketch ❑ Exploratory ❑ Development si , Service ❑ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: 9/28/2009 Oil 0 . Gas ❑ Plugged ❑ Abandoned ❑ 17. Verbal Approval: Date: WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Alex Vaughan, 343 -2186 Printed Name Tim Crumrine Title Senior Completions Engineer Signature ' Phone 343 -2184 Date 8/7/2009 COMMISSION USE ONLY 2 Cj Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 30 1 ',74 Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: 3500 psi 60 e fi. J 4— ..t rek) /954 ti,..N.. A ti..ti. Lam. "test Subsequent Form Required: / y . . t 4AC-- 151 o 741 (3) APPROVED BY Approved by: O MISSIONER THE COMMISSION Date: 8 3 - J t\I 7 Form 10 -403 R ised 06/2006 �. �;1�% ;i �� r)� • Pioneer Natural Resources Alaska Inc. ODSN -37 Page 2 AOGCC Form 10 -403, Application For Sundry Approvals Box #12, Attachment — Perforation Depths 4 - ", 12.6 #, L -80 Liner - perforated pup jts with 6 -1/2" holes @ depths listed: MD TVD 7766' 6320' 7892' 6345' 8060' 6368' 8186' 6378' 8311' 6382' 8516' 6384' 8718' 6381' 8920' 6373' 9130' 6373' 9340' 6374' 9550' 6370' 9758' 6356' 10,011' 6335' 10,139' 6328' 10,348' 6320' 10,553' 6317' 10,755' 6317' 10,958' 6313' 11,165' 6312' 11,363' 6312' 11,564' 6320' 11,765' 6333' 11,966' 6350' 12,088' 6358' 12,295' 6364' 12,498' 6362' 12,700' 6358' 12,906' 6353' 13,112' 6342' 13,315' 6323' 13,443' 6310' 13,647' 6298' 13,851' 6294' 14,063' 6290' 14,233' 6288' • Rig Workover to ESP Completion Well Status: 1) Well has been fracture stimulated, and flowback completed. 2) Sufficient clean up of wellbore solids has occurred and ESP recompletion is ready to be implemented. Procedure: 1) Prior to pulling the frac string, conduct the following SL Ops: a) Rig up lubricator with pump in sub and MU up to 9 -1/2" Otis Lub Adaptor b) Recover Wireline Retrievable SCSSSV c) Install CAT Standing Valve (valve catcher) @ 7005' MD (68deg,6118'TVD) d) Recover GLVs @ 1) 6833'(66deg, 6050TVD) ii) 4880'(30deg, 4547'TVD) 111) 2627'(25cleg, 2545'TVD) e) Install dummies in top two GLMs @ 1) 4880'(30deg, 45477VD) ii) 2627'(25deg, 2545'TVD). f) Using the RSC cement unit reverse circulate 2 hole volumes (IA + Tubing) 10ppga 3% KCI & NaCI down the Inner Annulus taking returns via the lowest empty GLM into the 4 -1/2" tbg up to surface and out the Prod Wing to the Prod Sales line. Note: lift gas circulated out contains 150ppm H g) Wait 90 minutes to allow any trapped gas to migrate to surface. Bleed any trapped gas to production line. h) Equalize and pull CAT Standing Valve. Confirm well is static. i) RD Slickline. 2) MI rig over well. 3) Install BPV using dry rods or lubricator (monitoring area w/ gas detectors & sniffers). 4) ND VetcoGray Frac X -mas Tree (4- 1/16 ", 5k: 9 -1/2" Otis Lubricator Adaptor, valve, & clamped hub Tubing Head Adaptor after insuring that control line pressure is 0 psi. Then remove control line hydraulic fitting from Wellhead body, and wrap sealed control line around Tubing Hanger neck. Install Blanking Plug (BP) by hand or dry rod. 5) NU the BOP onto the VetcoGray unitized clamp hub Wellhead & test BOP. Recover BP and BPV. 6) MU LJ into Tubing Hanger, BOLDS, and unseat Tubing Hanger & 4.5" Frac -Well Test Tbg String seals & CBU 3x w/ viscous pills (150ppm H2S for lift gas) via rig's gas buster using (gas detectors & sniffers). Confirm well static. a) RU HES Control Line spooling unit and hydraulic lines to spooler on Rig Floor b) Pull Tubing Hanger to rig floor and disconnect control line c) Pull adequate tubing and control line so as to be able to run control line onto spooler, d) Pull control line with tubing insuring to pull 1x1 ratio of tubing to control line, e) Count and record all HES Cannon clamps recovered on this and the next step. 7) POOH LD 4.5" Frac -Well Test String. a) Segregate and clean all HES completion equipment for re -use by washing in fresh water, spraying with WD40, and boxing same. Rig Workover to ESP Completion Procedure.doc Page 1 of 3 • • 8) Install VetcoGray Screened Wear Bushing Junk Catcher & jet BOPs thru jet sub & recover Junk Catcher. Clean out trip as reqd with Clean Out Assy (see Step 3). 9) RU Centrilift Sheave for ESP cable and HES Control Line Sheaves and Spooling units (1/4 ", .049" Wall Thickness, Stainles Steel Control Line 1000' spool for SCSSSV and 4600' spool for Gas Vent Valve Packer) 10) PU & RIH 2.875 ", 6.5ppf, L -80, IBT -M tbg consisting of: a) BHI Centrilift ESP -DH P/T Gauges -ADV- Cable- Cannon Clamps @ +7250' MD (DLS <3dph) (install ADV as close to the pump discharge so as to ensure minimal proppant fall back & build up on the top stages). • BHI Centrilift to make connections to ESP, install OTC Cannon clamps for ESP, GVV control line, and SCSSV CL, and check every 1000' to confirm comms w/ ESP DHPTGs & conductivity of electric cable b) HES [(XN w/ RHCM plug body installed @ 7055'MD (69deg ,6135'TVD) c) 2 X nipples one above and below GVV Packer) d) Weatherford Gas Vent Valve Packer @ +/- 3979' MD (3750' TVD) • PU & MU Weatherford Gas Vent Valve packer, Weatherford to install control line to GVV packer, function, test, and maintain 500psi control line pressure (less than valve functioning pressure to insure valve closed when RIH). Purge control line to ensure clean hydraulic fluid for GVV packer. e) 3 dummied GLMs: i) 6833' MD (66deg, 6050' TVD) ii) 4880' MD (30deg, 4547' TVD) iii) 2627' MD (25deg, 2545' TVD) f) HES SCSSV @ +750' • RIH to +750' & Pick up HES 2 -7/8 ", 5k Wel!star SCSSV. Purge HES control line to ensure clean SCSSV hydraulic fluid, install, and function valve. Maintain "hold open pressure" on SCSSV while RIH (4500psi). 11) PU LJ with VetcoGray Production Tubing Hanger w/ 8' long 3 -1/2" OD, IBT pup. a) With Tubing Hanger above Rotary Table, have VetcoGray and Centrilift reps present to ensure correct Tubing Hanger penetrator orientation. b) HES rep will bleed & cut control lines and VetcoGray will feed through Tubing Hanger and seal to top of Tubing Hanger. c) HES to splice to control line reels. d) VetcoGray to install the BIW penetrator into the Tubing Hanger followed by Centrilift, e) Using Centrilift BIW connectors, MU the ESP power cable to bottom of penetrator protruding below the Tubing Hanger. 12) 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. 13) ND BOPE and ensure VetcoGray personnel present prior to lifting stack and recovering control lines so as to prevent kinking. 14) Feed control lines thru WH body, install VetcoGray Wellhead hydraulic fittings, install needle valve, test control lines 5000psi. VetcoGray BIW penetrator prepped for THA installation. Rig Workover to ESP Completion Procedure.doc Page 2 of 3 • • 15) NU VetcoGray Production ESP X -mas Tree (Tubing Head Adaptor w/ ESP port, 3- 1/8 ",5k Vert valve, & 5 -3/4" Otis Lubricator Adaptor) & Swap Frac Wing Assy to Production Wing Assy (3 ", 5k Valve, 2" x 2" Double Studded Flow Cross, 3" Actuated Valve & 3" Choke). 16) VetcoGray 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 Assy against shop tested closed inner valve to 5000psi. Once tests are successfully completed, bleed pressure & recover TWC via lubricator or dry rod. 17) BHI install ESP pigtail to top of BIW penetrator protruding through the Tubing Head Adaptor. 18) Circulate 10ppg brine around packer thru the open ADV placing corrosion inhibited brine on the inner annulus between the packer and surface. Drop HES roller stem SL recoverable ball and rod. Monitor SCSSSV control line pressure to ensure adequate hold open pressure during roller stem ball drop. Set Weatherford GVV packer per Weatherford rep. Test annulus to 3500psi. 19) Slickline Ops a) Monitor HES SCSSV CL pressure to insure adequate hold open pressure b) Recover ball and rod, and recover RHCM plug body. c) Function Test SCSSSV 20) Move Drilling rig off and turn well over to Operations for production. 21) Function test BHI Centrilift ESP (start up should be against a closed valve to mitigate sand prod /damage -and minimize the initial drawdown of the well during startup. Open the valve slowly to control flow; minimizing well drawdown. Also need to balance this versus fluid speed to cool the motor and minimize pressure change of 25- 100psi /day as a function of pump intake pressure). Production Ops personnel to RU production process equipment. Leave HES SCSSV open, monitor control line pressure during initiation of ESP start up. Rig Workover to ESP Completion Procedure.doc Page 3 of 3 ODSN -3irac Strin g p Com Ietio!Final Casing Item # Item MD (ft) TVD (ft) A 16" Conductor 153 153 Well Head: 9 -5/8 ", 5K, VetcoGray B 9-5/8" 40# L -80 BTC, 8.835" ID 3,150 3,012 C 7" 26# L -80 BTC -M, 6.276" ID 7,764 6,319 Tree: 4 -1/2 5K, Horizontal D 4 -1/2" 12.6# P -110 and L -80 Hydril 521, 3.958" ID 7,593 6,280 `Estimated TOC @ 4981' MD - 500' above Torok O 1 VetcoGray Tubing Hanger 34 34 O ' ` 4 -1/2" XXO Safety Valve Landing Nipple w/ Wireline 2 Retreiveable ScSSSV @ 759' MD / 759' TVD 759 759 3 GLM #1 Brou -1A GLM 4 -1/2" x 1" 2,400 2,338 ® 4 GLM #2 Brou -1A GLM 4 -1/2" x 1" 4,162 3,913 5 GLM #3 Brou -1A GLM 4 -1/2" x 1" 5,547 5,140 6 GLM #4 Brou -1A GLM 4 -1/2" x 1" 6,857 6,060 7 4 1/2" )Cl Nipple, 3.725" ID Nogo 7,107 6,153 D End of Assembly 7,593 6,280 Lower Completion .= # Item MD (ft) TVD (ft) r_�� 8 WFT PBR Tie Back Sleeve 15ft SN #23682673 -01 7,581 6,277 ��ii//11 9 WFT "NTH" Liner Top Pkr 7,596 6,281 10 WFT "PHR" Rotating Hyd Set Liner Hanger 7,597 6,281 O 11 4 -1/2" 12.60# L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 7,766 6,320 4 -1/2" 12.60# L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 7,892 6,345 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,060 6,368 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,186 6,378 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,311 6,382 i.� 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,516 6,384 ff 44��11 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,718 6,381 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,920 6,373 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,130 6,373 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,340 6,374 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,550 6,370 5 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,758 6,356 J 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,011 6,335 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,139 6,328 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,348 6,320 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,553 6,317 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,756 6,317 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,958 6,313 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,165 6,312 __6)...i 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,363 6,312 4 -1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,564 6,320 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,765 6,333 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,966 6,350 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,088 6,358 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,295 6,364 MI 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,498 6,362 77 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,700 6,358 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,906 6,353 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,112 6,342 4-1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,315 6,323 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,443 6,310 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,647 6,298 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,851 6,294 0 8 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,063 6,290 4 -1/2" 12.60# L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 14,233 6,288 , 12 Ray Oil Tool Silver Bullet Float Shoe (PLUGGED) w/ 4 -1/2 I 14,281 6,287 End of Assembly 14,283 6,287 O 11 12 .. .41 41. 41. 41. .. .41 .. .41 .. .. 41. .. .41 .. .. .4, .. .. .• .. .. .41 .40 14295' MDrkb / 6,287' TVDrkb Date: Revision By: Comments PIONEER 7 -30 -2009 TWC Final Frac String Completion ODSN -37 Producer Well Schematic NATURAL RESQURCES ALAS (4 Frac String Completion ODSN! ESP Completion Deg n p g Casing Item # Item MD (ft) TVD (ft) A 16" Conductor 153 153 B 9 -5/8" 40# L -80 BTC, 8.835" ID 3150 3012 Well Head: 9 -5/8 ", 5K, VetcoGray c 7" 26# L -80 BTC -M, 6.276" ID 7764 6319 Tree: 4 -1/2 ", 5K, Horizontal D 2 -7/8" 6.5# L -80 IBT -M, 2.441" ID *Estimated TOC @ 4981' MD - 500' above Torok 0 1 VetcoGray Tubing Hanger 34 34 O ' ` 2 2 -7/8" Wellstar Tubing Retreivable ScSSSV 750 750 3 GLM #1 - 2 -7/8" x 1 -1/2" (min. 3 jts above top X nipple) 3,850 3,635 _® 2 -7/8" X Nipple 2.313" I.D. (min. 2 jts above Gas Vent O 4 Valve Packer) 3,940 3,715 5 WFT 7" x 2 -7/8" Gas Vent Valve Packer (max. TVD 3800') 4,000 3,768 2 -7/8" X Nipple 2.313" I.D. w/ RHC -M Plug Body (min. 2 jts 6 below Gas Vent Valve Packer) 4,060 3,821 7 GLM #2 - 2 -7/8" x 1 -1/2" (min. 2 jts above XN nipple) 6,850 6,057 8 2 -7/8" XN Nipple, 2.205" ID Nogo (max. incl. 70 deg) 7,000 6,116 D 9 Automatic Divert Valve (ADV) 7,295 6,209 I 10 ESP (Pump, Motor, and Jewelry) 7,300 6,210 End of Assembly O 0� 11 WFT PBR Tie Back Sleeve 15ft SN #23682 -01 7,581 6,277 12 WFT "NTH" Liner Top Pkr 7,596 6,281 • a 13 WFT "PHR" Rotating Hyd Set Liner Hanger 7,597 6,281 I � 14 4 -1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 7,766 6,320 Io 2g. 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 7,892 6,345 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,060 6,368 ( 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,186 6,378 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,311 6,382 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,516 6,384 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,718 6,381 07 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,920 6,373 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,130 6,373 4-1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,340 6,374 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,550 6,370 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,758 6,356 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,011 6,335 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,139 6,328 • O . 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,348 6,320 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,553 6,317 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,756 6,317 o 0 1 , 40 4 -1/2" 12.60# L -80 Hydril Pupjt 411 (Ported w/ 6 1/2 holes) 10,958 6,313 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,165 6,312 4 -1/2" 12.60# L-80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,363 6,312 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,564 6,320 i 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,765 6,333 4 -1/2" 12.60# L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 11,966 6,350 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,088 6,358 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,295 6,364 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,498 6,362 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,700 6,358 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,906 6,353 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,112 6,342 4-1/2" 12.60# L-80 Hydril Pupjt 48 (Ported w/ 6 1/2 holes) 13,315 6,323 1:C8s.........„1 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,443 6,310 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,647 6,298 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,851 6,294 � 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,063 6,290 13 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,233 6,288 15 Ray Oil Tool Silver Bullet Float Shoe (PLUGGED) w/ 4 -1/2 I 14,281 6,287 O ` End of Assembly 14,283 6,287 ` 41 41 41 41 41 41 41 41 41 41 41 41 11 41 41 41 15 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 41 11 41 14295' MDrkb / 6,287' TVDrkb Date: Revision By: Comments P 1 O N E E p „ 7 -30 -2009 TWC ESP Compl Design Post TD ODSN -37 Producer NAIURA.RESOURCESAIAS(A Well Schematic ESP Completion • • Page 1 of, Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, July 29, 2009 7:57 AM To: 'Vaughan, Alex' Cc: Johnson, Vern; Schwartz, Guy L (DOA); Regg, James B (DOA); Aubert, Winton G (DOA) Subject: RE: ODSN -37 (208 -157) Alex, Thanks for the information. Regarding the 4500 psi casing test/BOP test, it is our opinion that the BOP should be tested to the highest pressure that it will be subjected to. That is the practice employed by others. Call or message with any questions. Tom Maunder, PE AOGCC From: Vaughan, Alex [mailto:Alex.Vaughan @pxd.com] Sent: Tuesday, July 28, 2009 9:40 AM To: Maunder, Thomas E (DOA) Cc: Johnson, Vern Subject: RE: ODSN -37 (208 -157) Tom, Please see answers inserted into your questions below: Alex, Further on this well, on 5/25 the BOP rams are tested to 3500 in preparation to drill the production hole section. Immediately after the test is completed, it is reported that the 7" casing is tested to 4500 psi. Is this correct? 3500 psi is the 7" casing test value stated in the work plan provided with Sundry 309 -163 that was approved 5/7/09. If the BOP is used to hold the test pressure, the ram test pressures must equal or exceed any planned casing test pressure. Tom Maunder, PE AOGCC The test of the 7" casing to 4500 psi was a precautionary measure for the fracture stimulation job only and not for well control. The 3500 psi test on the BOP stack was sufficient for well control. It is certainly prudent to test the BOP's the highest pressure that the stack will see, as there is certainly an unknown element on the surface should the stack be subjected to a pressure greater to that which it has been tested, but this risk would be the same if we were only testing the stack or if we are testing the stack and the casing simultaneously. The BOPE tests for ODSN -31 & our current well ODSN -36 were also for 3500 psi as per PTD # 208 -003 & 309 -199 and then subsequently followed by a 4500 psi casing pressure test. If the preceding explanation is not satisfactory, the plan forward will be to implement a 4500 psi BOPE test when a 4500 psi casing pressure test is to be conducted. Alex, I am reviewing the completion report for this well and have some questions ... 1. When was the surface casing tested? It is stated that the plug was bumped to 3500 psi and held for 3 minutes when the casing was cemented (10/31/08), but I don't find anything in the operations summary regarding a 30 minute casing pressure test prior to drilling out. This was a typo the casing was actually tested to 3500 psi for a full 30 min as can be seen below on the hourly breakdown of the operations report. I have scanned and highlighted this particular section of the original report for your convenience. 7/29/2009 . • Page 2 of 17.00 '20'30 3.5O CMTPRI - Piimp seawater From aw Otenertf taxi to the rip lace to ensue the Mnesiro • • full Pressure lest Me cxrment linos to 4000 psi • good Iasi. Bleed off the :pressure and drop the 1st bottom plug. Kick out he plug wadi - 1 bbl of I wwaoer pumped Shut down and dead off the pressure band the 2nd bottom plug and the top plug in the cement heed. Pump the rest of the 40 bbls of 10.5 ppp Guar Spacer el 5 bpm. ICP - 600 pie, FCP - 435 psi, prop the Second bosom plug and pump 263 bells 0110.5 pp0 lead slurry a15 'berm, ICP . 610 pal, FCP • 360 psi, Pump 46 bbls 0115.6 pp9 tail cement ire 4.5 bpm. ICP .650 pal. FCP • 800 par. Or0p the *co plug and pump 10 blob of snawaler to Iddk out the plug and flush the corned Ones Swap Over s AO the rig one corttnue the rksialaoemeut with Seawater at 10 bpm, ICP • :1570 psi. Depiece with 9 born uMl -10 burls from bumping the Ow, FCP - ,2350 pal Pumped st 4,5 tem for the remaining 10 bbls, ICP • 1180 psi rand bumped the plug a12704 elrokes, -96% efficiency. Increase tis pressure up 10 35001 - don and hold f or 30 minuets Inc a tieing ;pressure test • good. Bleed off the pressure and check hoots • holding. CIP 1950 his, • 2. It appears that the well was fracture stimulated as planned on 6/14. No detail is provided regarding the stimulation operations or the subsequent WL work on 6/16. Please provide that information. I have included the relevant sections of the Completions Operations Summary below. 6113/2009 0.0 Schlumberger crew 16 on location two CHM12H ILL one Stinger Begin 61141 pre -mirk of gee Ig bre Knock up complete son package. Install Slinger package 0410 wellhead. Stage PNUrd Prepare frac in the AM. 6114/2009 0.0 Performing witeline operations to complete peas frac opbon5 Due to solids left in tubing we prem set catcher above bottom GLM On way 10 surface rurtninc tool svriveled off BHA Subsequently frshe4 out G3 running told catcher f came with running to01 At 21 03 hours trying to chase catch with KOT to save a run in puling bottom GLV using pump assist in setting same Pulled bottom t 2230 Begin Wesel displacement down IA 2 BP14 • 22'10 for 140 BBLS 6/1512009 0.0 Performed a 10 stage lac utfrzrng 582,18,9820140 Carbolrle (194 boxes/at an avera95 4,132 P5 injection praosury with a rate of 40 BPU 200 b$o -bats fqr 01rersp0n purposes war used to no ea not see distinctive sign of diversion launching 20 bags per stage. 2,060 P31 ISIWHP at hard shut Agar 30 min 1.805 PSI FTP. Bled IA down to 500 PSI. ROM!). 6/16/2009 0.0 Continue to run GLV staeon 2.3 & 4. Negldve draw down test pertormee on IA for varve conlerm Pullen catcher sub. Installed HES SSSV tested same teal Q000. RDMO rp STBY to fly over - 0 Taal hours today = 1261*. 6/1712009 0.0 Prepare to lbw back ODSN -37 Rig up Expro equipment and pressure lest same to 2,700 psi. OOSN -32i and rig down gas VA meter t0 rig up same on 003N -37 Hook up al Irsbumen ation a check entire system with ASRC and Expro- system checked out 0l, Open HES SSSV well head pressure cans up lip 550 psi Instantly. opened up 46 gas to IA and umneckaSuly had 1,000 psi of Well head pressure came up to 730 psi. Stwled Hosing rail al 01 :30 hrs. 153 blob total flowed t Diesel and frac water mixed) 6:18/2009 0.0 Continue flow back ODSN -37 through Expro nowbaek equipment to clean out loose has sand an from tubing and lomtatlon 112 bets 01 diesel flowed back. 1.015 6131* total water tlowb0 back- approximately 15% of the frac water pumped dunnQ frac cab At report amt-- samples are 70% 0 3D% water. I look forward to your reply. Tom Maunder, PE AOGCC If you have any further questions I can be reached with the contact information listed below. Alex Vaughan Operations Drilling Engineer 7/29/2009 .®rs4 l • STATE OF ALASKA • FIVE ?'a3 "' ALASKA OIL AND GAS CONSERVATION COMMISSION � WELL COMPLETION OR RECOMPLETION REPORT AND Ail, L7 la. Well Status: Oil 0 Gas Plugged ❑ Abandoned ❑ Suspended ❑ 1b. Well CIANka Qfj & Ga Cot) . COtnmiSSioh 20AAC 25.105 20AAC 25.110 Development 0 A9141991V ❑ GINJ❑ WINJ❑ WDSPL❑ WAG ❑ Other❑ No. of Completions: 1 Service ❑ Stratigraphic Test r� 2. Operator Name: 5. Date Comp., Susp., or 12. Permit to Drill Number: g oes. , ,/6 e Pioneer Natural Resources Alaska Inc Aband.: 6/15/2009 208 - 157 ' - 43 3. Address: 6. Date Spudded: 13. API Number: 700 G Street, Suite 600, Anchorage, AK 99501 10/27/2008 50 703 - 20586 - 00 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 2937' FSL, 1129' FEL, Sec. 11, T13N, R7E, UM 6/6/2009 - ODSN - 37 Top of Productive Horizon: 8. KB (ft above MSL): 57.5' 15. Field /Pool(s): 2872' FSL, 1810' FEL, Sec. 11, T13N, R7E, UM Ground (ft MSL): 13.50' Total Depth: 9. Plug Back Depth(MD +TVD): Oooguruk - Nuiqsut Oil Pool 2635' FSL, 628' FEL, Sec. 3, 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- 469869.00 y- 6031053.00 Zone -Aspa - 14295' MD / 6287' TVD - ADL 355036 TPI: x- 469188.31 y- 6030990.48 Zone -Aspa 11. SSSV Depth (MD + TVD): 17. Land Use Permit: Total Depth: x- 465107.07 y- 6036050.86 Zone- ASP4 759' MD / 759' TVD 417497 18. Directional Survey: Yes ❑ No ❑ 19. Water Depth, if Offshore: 20. Thickness of Permafrost (TVD): (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) 850' 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): LWD, DIR, MWD, GR, EWR, DGR, PWD, ALD, CTN, DDS -R 22. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 16" 109# X -65 Surface 158' Surface 158' 24" Driven 9 -5/8" 40# L - 80 BTC Surface 3150' Surface 3012' 12 -1/4" 357 sx PF 'L'; 216 sx Class 'G' 7" 26# L - 80 Surface 7764' Surface 6319' 8 -3/4" 142 sx 12.5ppg Class 'G'; BTC - M 192 sx 15.8ppg Class 'G' 4 -1/2" 12.6# L - 7581' 14283' 6287' 6 -1/8" Uncemented Liner 23. Open to production or injection? Yes 0 No❑ If Yes, list each 24. TUBING RECORD interval open (MD +TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD) 4 -1/2 ", 12.6 #, L -80 7593' 7596' See Attachment (page 3) ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED See perf detail, pg. 3 582,188# 20/40 Carbolite -2000' Freeze Protect w/ 60 bbls diesel 26 PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): 6/19/2009 Gas Lift Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: 6/19/2009 8 Test Period - 533.3 95,658 133.7 3" 179 Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 394.7 982.1 24 -Hour Rate -► 1600.2 286,974 401.5 21.6 27. CORE DATA Conventional Core(s) Acquired? Yes ❑ No 0 Sidewall Cores Acquired? Yes ❑ No 0 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. COMPLETION None /j!% RBDMS L. JUL_ 24 Form 10 -407 Revised 2/2007 CONTINUED ON REVERSE Ali j C,., • 0 28. GEOLOGIC MARKERS (List all formations and markers encountered): 29. FORMATION TESTS NAME MD TVD Well tested? Yes U No If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if needed, and submit detailed test information per 20 AAC 25.071. Top Permafrost 818' 818' Base Permafrost 1687' 1668' Top West Sak 2339' 2282' Top Torok 5480' 5081' Top HRZ 6327' 5773' Top Kuparuk C 6817' 6043' Top Nuiqsut 7746' 6315' None 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: James nks / Title: Sr. Staff Drilling Engineer Signature: ( cam-• 7r /`/9 Phone: 343 -2111 Date: 7/16/2009 Well No. ODSN -37 Permit No. 208 -157 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 a: 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 2/2007 • • Pioneer Natural Resources Alaska Inc. ODSN -37 Page 3 AOGCC Form 10 -407, Well Completion or Recompletion Report and Log Box #23, Attachment 23. Open to production or injection 4 - ", 12.6 #, L -80 Liner - perforated pup jts with 6 -1/2" holes @ depths listed: MD TVD 7766' — 7771' 6320' — 6321' 7892' — 7897' 6345' — 6345' 8060' — 8065' 6368' — 6368' 8186' — 8191' 6378' — 6378' 8311' — 8316' 6382' — 6382' 8516' — 8521' 6384' — 6384' 8718' — 8723' 6381' — 6381' 8920' — 8925' 6373' — 6373' 9130' — 9135' 6373' — 6373' 9340' — 9345' 6374' — 6374' 9550' — 9555' 6370' — 6370' 9758' — 9763' 6356' — 6355' 10011' — 10016' 6335' — 6335' 10139' — 10144' 6328' — 6328' 10348' — 10353' 6320' — 6320' 10553' — 10558' 6317' — 6318' 10755' — 10761' 6317' — 6316' 10958' — 10963' 6313' — 6313' 11165' — 11170' 6312' — 6312' 11363' — 11368' 6312' — 6313' 11564' — 11569' 6320' — 6320' 11765' — 11770' 6333' — 6334' 11966' — 11971' 6350' — 6351' 12088' — 12093' 6358' — 6358' 12295' — 12300' 6364' — 6364' 12498' — 12503' 6362' — 6361' 12700' — 12705' 6358' — 6357' 12906' — 12911' 6353' — 6352' 13112' — 13118' 6342' — 6341' 13315' — 13320' 6323' — 6323' 13443' — 13448' 6310' — 6309' 13647' — 13852' 6298' — 6294' 13851' — 13856' 6294' — 6294' 14063' — 14068' 6290' — 6290' 14233' — 14238' 6288' — 6288' P I O N E E R Sperations Summary Report NATURAL RESOURCES Well Ngme: ODSN-37 Contractor: NABORS DRILLING Rig Number: 19 AC Job Category: DEVELOPMENT DRILL Spud Date: 10/27/2008 Rig Release Date: 6/15/2009 Depth Start Foot/Meters Last Mud Start Date End Date (ftKB) (ft) Dens (Ib/gat) Summary 10/27/2008 10/28/2008 44.0 1,163.00 9.60 Install Herculite berming around rig. Service TDS. Held PJSM for spud. Wash conductor f/94' t/153', MU BHA #1 12 -1/4" bit & mud motor, RIH w/ BHA #1. Drill- slide - survey per program and SSDD f/153' 111207. 10/28/2008 10/29/2008 1,207.0 1,961.00 9.60 Pump hi -vis sweep 1022', Drill - slide- survey per program and SSDD 1/1207' 1/31686. 10/29/2008 10/30/2008 3,168.0 0.00 9.50 C &C f/3168' t/3007', CBU 3x @ 3168', POOH /BROH to 1380' MD, Clear plugged flowline, Continue wiper trip to the jars @ 206' and RIH to TD, C &C @ 3168' for casing run. TOH. LD 12 -1/4" BHA. 10/30/2008 10/31/2008 3,168.0 0.00- 9.50 RIH w/ 9 -5/8" 40# L -80 BTC casing 1/3150'. CBU @ 3150'. RU cement head and cement lines. Hold PJSM. Pressure test cement lines to 4000 psi- good test. Pump cement job, Kick out plug w/ 1 bbl spacer, Pump remaining 40 bbls 10.5 ppg Dual Spacer, 263 bbls of 10.5 ppg lead slurry, 46 bbls 15.8 ppg tail cement. Displace w/ seawater. Reciprocate & bump plug to 3500 psi. Hold forOK, 38 bbls of 10.5 ppg lead cementslurry returned to surface, CIP © 1950 hrs, FCP - 1180 psi. ND Riser. 10/31/2008 11/1/2008 3,168.0 0.00 9.50 ND Riser anti "spols. RIH w/ 2 -7/8" 6.4# L -80 IBT -M FP /Circ tubing to 2087'. NU tree and test to 5000 psi - good test. Pump 138 bbls of diesel freeze protection fluid, 165 psi - 0 psi following U -tube. RDMO ODSN -37. Rig released @ 2400 hrs for move to ODSK -38i. MIRU on ODSK -38i w/ MPD equipment. 11/1/2008 11/20/2008 3,168.0 0.00 9.50 Inactive 11/20/2008 11/21/2008 3,168.0 0.00 8.60 Finish slickline work and RD slickline unit. Prep rig for move, Skid rig to ODSN -37. Rig accepted @ 0630 hrs. Reconnect all lines and equip post rig move. RU lines to pump diesel out of well -bore, Circ diesel out of well bore, ND tree, Install test dart and riser, NU BOP stack, NU MPD equip to BOP stack, RU test equip & prepare to test BOPE to 250 psi low and 3500 psi high. 11/21/2008 11/22/2008 3,168.0 0.00 8.60 Test BOPE to 250 psi low and 3500 psi high, Annular 250 psi tow and 2500 psi high, Test witnessed by AOGCC rep. Chuck Sheve. RD test equip and blow down all test lines. POOH & Lavdown 2 -7/8" kill string. Install test plug, Test wellhead, RCD, and MPD lines to 250 psi low and 3500 psi high. Slip and cut drilling line. PU and RIH w/ Geo pilot and MWD /PWD t/1065'. 11/22/2008 11/23/2008 3,168.0 269.00 9.20 Level derrick and substructure. RIH 1/1064' 112964', Install RCD bearing assembly, W &R f/2964' V3062', Drill cement and float equip V3062'1/3147', Displace sea water w/ 9.2 ppg mud and transfer mud from RSC, Drill f/3147' V3188', CBU at 3147', LOT at 3147' MD V13.9 EMW. RID test equip and blowdown lines. Install RCD, Calibrate MPD equip, Drill 1/3188' V3437' maintaining 11.0 - 11.2 ppg EMW with MPD. 11/23/2008 11/24/2008 3,437.0 1,608.00 9.20 Drill 1/3437 1/3,721' while maintaining 11.0 -11.2 PM .EMW t if MPD, Pump 20 bbl hi -vis sweep and circ out same, Drill f/3721' 1/5045' while maintaining 11.0 - 11.2 ppg EMW w/ MPD. 11/24/2008 11/25/2008 5,045.0 721.00 9.20 Drill f/5045' 1/5766' while maintaining 11.0 - 11.2 EMW w/ MPD. Pumped 60 bbl hi -vis sweep and circ out same. POOH f/5,766'1/3149'. C/O kill line valve on stand pipe manifold & service TDS, Test kill line valve to 250 psi low and 3500 psi high- good test. Circ out contaminated mud @ shoe. TO-If/3149' 115766'. Circ out contaminated mud @ 5766' and replace w/ clean 10.5 ppg _ mud f/ RSC. 11/25/2008 11/26/2008 5,766.0 1,177.00 10.60 Circ raising mud wt. f/ 9,2 pm t/ 10.5 poa, Perform FIT w/ 12.5 Dna EMW- good test. Drill 1/5766' V6943' while maintaining 12.3 - 12,6 ppg EMW w/ MPD. Pumping hi -vis LCM sweep wi each connection. Page 1/4 Report Printed: 7/16/2009 P I O N E E R • perations Summary Report NATURAL RESOURCES Depth Start Foot/Meters Last Mud Stan Date End Date (ftKB) (ft) Dens (Ib /gal) Summary 11/26/2008 11/27/2008 6,943.0 832.00 10.50 Drill- survey 8 3/4" open hole section f/6943' t/7775', TD Int. Section @ 7775'. C &C hole for casing. Pump two 30 bbl hi -vis sweeps. Element on RCD bearing parted. Change out same. Close hydril and circulate thru rig choke for ECD control. POOH (/7775' 117582'. 11/27/2008 11/28/2008 7,775.0 0.00 10.50 POOH /BROH f/ 582't/6848'. Observed instantaneous fluid loss of 180 bph. Reduce back pressure from MPD to manage fluid losses. CBU. POOH 1/6848' t/3059' inside 9 -5/8" casing. CBU inside 9 -5/8" casing. Shut bottom pipe rams, Blow down choke manifold and top drive. Open rams, service rig and TDS. RIH F/ 3059' T/ 5061'. Lost MPD pressure from cement pump. Shut annular preventer to maintain ECD. Service cement pump. Fill drill pipe @ 5061'. RIH t/7027' while filling pipe, Fluid loss rate 30/40 bph. S/O and rotate V7345'1/7645'. RCD element blew out. Shut annular to hold ECD, C/O damaged RCD element. Maintain ECD w/ rig pump. 11/28/2008 11/29/2008 7,775.0 0.00 12.50 C/O damaged RCD element. RIH f/7645' t/bottom @ 7775'.Circulate and clean hole. Pump hi -vis LCM sweep, 80 bbl 10.5 ppg. Weight up mud system from 10.5 ppg to 11.7 ppg while maintaining 12.5 ppg EMW w/ MPD. Pump 40 bbls 11.7 ppg hi -vis LCM sweep. Shut down MPD operations, Pull RCD bearing assembly. Set trip nipple. Circulate and weight up mud system F/ 11.7 ppq t/ 12.5 ppq. POOH f/7775' t/6658'. 11/29/2008 11/30/2008 7,775.0 0.00 12.50 POOH f/6658' 1/BHA @ 597', LD BHA & Bit. C/O upper pipe rams to 7 ". Pull wear ring, set test plug. PT rams 250 psi low 3,500 psi high. Pull test plug. RU casing running system to RIH wl 7" casing. Held PJSM on running casing w/ all crew members. RIH w/ T 26# L -80 BTC -M intermediate casing string t/ 5600'. 11/30/2008 12/1/2008 7,775.0 0.00 8.60 RIH w/ 7" 26# L -80 BTC -M casing 117762'. RD Tesco tools, RU cement head and lines. Pump 10 bbls water, PT lines to 4,500 psi- good test. Pump 55 bbls 12 ppg dual spacer, followed by 69.5 bbls lead cement, followed by 31 bbls tail cement. Displace to FC w/ seawater. Reciprocate & bump plug to 3500 psi. Hold for 3 min, OK. FCP @ 1500 psi (no losses during job). CIP at 13:50 hrs. RD cement head, lines, landing jt. Set wellhead packoff, PT to 5000 psi - good test. Run 2 -7/8" 6.4# L -80 IBT -M tubing kill string. 12/1/2008 12/2/2008 7,775.0 0.00 8.60 Land 2 -7/8" tubing kill string. ND MPD & BOPE. NU Tree, test to 5,000 psi- good test. Freeze • • - , - . • . •. • ••- - • - `• • • • • ,'•,• - •,-. Move rig from well ODSN -37 to well ODSK -41. Released rig from operations on Well ODSN•37 @ 23:59 hrs, 12/2/2008 5/23/2009 7,775.0 0.00 8.60 Inactive 5/23/2009 5/24/2009 7,775.0 0.00 8.60 MOB T/ ODSN -37. Circ out diesel freeze protection. ND Production Tree. NU BOPE's & MPD. LD 2 -7/8" work string. AOGCC given 48 hr notice of BOPE test. 5/24/2009 5/25/2009 7,775.0 0.00 8.60 POOH w/ 2 -7/8" kill string. RIH w/ DP while testing choke manifold 250 psi low - 2500 psi high. Circ @ 2688', POOH DP stand back in derrick. Test BOPE's & MPD, pipe & blind rams, kill & choke HCR and manual valves, 14 choke manifolds valves, floor & Dart valves, upper & lower IBOPs', MPD valves 11250 psi low - 3500 psi high. Annular 11250 psi low - 2500 psi high. No failures. AOGCC rep. Lou Grimaldi waived witness of test. PT 7" casing @ 4500 psi - good test MU 6/1/8" RSS BHA. RIH 113442'. 5/25/2009 5/26/2009 7,775.0 0.00 8.60 RIH w/ BHA #3 f/3432' t/7498'. Clean out cement stringers t/7676'. Lost MWD detection. Displaced seawater 1/8.6 ppg WBM. POOH w/ BHA 43 and LD MWD tools, PU new MWD tools and BHA #4. RIH f/420' 1/1500'. 5/26/2009 5/27/2009 7,775.0 0.00 8.60 RIH w/ BHA #4 f/1500' t/7591'. Service TD, Slip & cut drilling line. Wash down t/7676'. Lost MWD signal. Drill Float Collar (/7676' 1)7677'. Clean out cement 1/7688'. CBU @ 7688'. POOH (/7688' t/420'. LD RSS BHA #4. PU RSS BHA #5. Wait on ALD F/ Prudhoe Bay. Page 2/4 Report Printed: 7/16/2009 P 1 O N E E R 4 perations Summary Report NATURAL. RESOURCES Depth Start Foot/Meters ' Last Mud Start Date End Date (ttKB) ft) Dens (Ib /gal) Summary 5/27/2009 5/28/2009 7,775.0 100.00 8.60 Recieved ALD f/ Prudhoe Bay. MU SSRS BHA #5. RIH 117688'. Clean out t/7775'. Drill 7" shoe and rat hole 117795'. CBU. Perform FIT w/ 8.6 ppq to 13.0 ppq EMW, Pumped 1.4 bbls returned 1.3 bbls. Drill f/7795' 117825' while maintaining min 9.7 ppg EMW @ shoe w/ MPD. 5/28/2009 5/29/2009 7,825.0 2,240.00 8.60 Directional drill 1/7825' V8945' while maintaining min 9.7 ppg EMW @ shoe w/ MPD. 5/29/2009 5/30/2009 8,945.0 1,138.00 8.60 Directional drill 1/8945' V9514' while maintaining min 9.7 ppg EMW @ shoe w/ MPD. 5/30/2009 5/31/2009 9,514.0 1,292.00 8.65 Directional drill f/9514' 1110160' while maintaining min 9.7 ppg EMW @ shoe w/ MPD @ 7" casing shoe. Function tested annular, upper & lower pipe rams, kill & choke HCR's - successful 5/31/2009 6/1/2009 10,160.0 3,270.00 8.65 Directional drill f/10160' V11796' while maintaining min 9.7 ppg EMW @ shoe w/ MPD. 6/1/2009 6/2/2009 11,795.0 640.00 8.65 Directional drill f/11796' V12115' while maintaining min 9.7 ppg EMW @ shoe w/ MPD. 6/2/2009 6/3/2009 12,115.0 1,058.00 8.60 Directional drill t/12115' 1112644' while maintaining min 9.7 ppg EMW @ shoe w/ MPD. 6/3/2009 6/4/2009 12,644.0 - 12,044.... 8.50 Drill 1/12644' V12966' while maintaining 10.0 ppg EMW w/ MPD. Service TDS. Drill 1/12966' V13189' maintaining min 9.7 ppg EMW @ shoe w/ MPD. Service TDS. Drill f /13189' 1113244' maintaining min 9.7 ppg EMW @ shoe w/ MPD. 6/4/2009 6/5/2009 13,244.0 - 12,386.... 8.70 Drill f/13244' V13382' maintaining min 9.7 ppg EMW @ shoe w/ MPD. Service Rig. Drill 1/13382' It/13502' maintaining min 9.7 ppg EMW @ shoe w/ MPD. C &C @ 13502'. POOH for short trip 1110500'. RIH 1/10550' 1/10778'. 6/5/2009 6/6/2009 13,502.0 - 12,011.... 8.70 RIH -Wash and Ream 1/10778' V13502'. Service TDS. Directional drill 1/13502'1/14135' while maintaining min 9.7 ppg EMW @ shoe w/ MPD. 6/6/2009 6/7/2009 12,644.0 - 12,484.... 8.70 Directional drill f/14135' V14295' while maintaining min 9.7 ppg EMW @ shoe w/ MPD. C &C @ - 14,295'. POOH to shoe. Slip and cut driling line. Circ and spot 15 bbls 10.3 ppg brine @ 7691'. POOH 117608'. Diplace well w/ 10.3 ppg WBM @ 7208' and monitor. • 6/7/2009 6/8/2009 14,295.0 10.20 Remove RCD and install trip nipple. POOH DP 117208' 1/423'. Lay down BHA. Service rig. PT choke manifold 250 psi low - 3500 psi high. Test BOP, annular, rams, valves, choke ands lines, 250 psi low - 3500 psi high. Witness waived by AOGCC rep. Chuck Scheve. RU and RIH w/ 12.6 ppf Hydril 521 Liner., 6/8/2009 6/9/2009 14,295.0 9.95 RIH w/ liner, scraper assembly, DP 1/995' V7230'. Tag at 7230' attempt to work past. TOOH w/ Iner. 6/9/2009 6/10/2009 14,295.0 - 14,295.... 9.95 TOOH w/ liner and LD damaged joints (due to handling tools). Repair tongs. PU clean out BHA RIH 1/1618'. 6/10/2009 6/11/2009 14,295.0 0.00 • • - - -- • , • . - ' • • - - -. • • •• - V7762' continue RIH 118800', POOH to casing shoe, Circulate out salt bridge. POOH w/ clean out BHA, LD BHA & RU to RIH 4 -1/2" liner per ' program. 6/11/2009 6/12/2009 14,295.0 0.00 9.95 Finish RIH w/ 4 -1/2" Liner per Program. RIH w/ liner U6808'1114283' w/ 4" DP. Mechanically, back off & set hanger per Wford Rep. & consult Town ODE, POOH w/ liner running tools & inspect same, V1625'md. Page 3/4 Report Printed: 7/16/2009 P IONEER •perations Summary Report • NATURAL RESOURCES I ' Depth Stan Foot/Meters Last Mud Start Date End Date (ftKB) (ft) Dens (Ib /gat) Summary 6/12/2009 16/13/2009 14,295.0 0.00 9.95 POOH w /4" DP, LD liner running assy. Pull wear bushing, & Change Pipe rams to 4 -1/2" types top /bott. Test rams and annular prevenfer per AOGCC: requirements, 250 psi low - 3500 psi high on both sets of rams- good test. PU & MU WRSSV, Test same to 5000 psi @ surface- good test. RU RIH w/ 4 -1/2" P110 12.6 ppf Hydril 521 Frac Completion string - tie back assy. per program. 6/13/2009 6/14/2009 14,295.0 0.00 9.95 Finish RIH w/4 -1/2" Frac String per program, t /7593'. Est. circ. above Liner top & wash into same . Test Seal assembly to 4500 psi, (ok). Unsting & circ. Hi Vis sweep, & Dirt Magnetic pill. Displace o res 9.9 ppg completion fluid. Space out & land Frac string on VG Tbg. hanger. Pressure test seals, (ok). C/O to 4' Pipe rams Top /Bott. & ND BOP stack & riser system. Test WRSSV mandrel thru tubing hanger 5,000psi (ok). NU V.G. tree and test seal to 5,000psi, (OK). Secure well head, clean up cellar area, & assist Frac Operations. Install & function test Tree (Stinger Isolation tool) 6/14/2009 6/15/2009 14,295.0 0.00 9.95 Assist w/ Performin. Frac 'ob RD tree saver, & LD same w/ Stinger Representative. RU and test wire line equip. of HES, RIH with slick line, per Rep requests. 6/15/2009 6/16/2009 14,295.0 0.00 9.95 Assist w/ Wireline operations on ODSN -37. Prepare Rig to move over to ODSN -31. Rig Released @ 24:00hrs June 15th, 2009 6/16/2009 6/17/2009 14,295.0 0.00 9.95 Page 4/4 Report Printed: 7/16/2009 ODSN -37 Ic String Completion P 20 Well Head: 9 -5/8 ", 5K, VetcoGray Tree: 4 -1/2 ", 5K, Horizontal 16" Conductor 153' MDrkb / 153' TVDrkb 4 -1/2" Wireline Retreivable ScSSSV @ -750' MD / 750' TVD w/ isolation sleeve set across control line port 9 -5/8 ", 40# L -80 BTC, 8.835" ID 4 -1/2" GLM #1 © 2411' MDrkb / 3150' MDrkb / 3012' TVDrkb 2349' TVDrkb 4 -1/2" GLM #2 @ 4148' MDrkb / 4 -1/2 ", 12.6# L -80 / P- J 3900' TVDrkb 110 Hydril 521 4 -1/2" GLM #3 @ 5558' MDrkb / 5150' TVDrkb 4 -1/2" GLM #4 @ 6833' MDrkb / 6050' TVDrkb J 4 1/2" XN Nipple, 3.725" ID Nogo 7100' MD /6151'TVD Estimated Top of Cement @ 4981' MD 500' above Torok 7" Weatherford Liner Top Packer and Tieback 7 ", 26# L -80 BTC -M, 7784' MDrkb / 6324' TVD, 6.276" ID 7764' '� 4 -1/2" Blank Liner 12.6# L -80 Hydril 521 MDrkb / 6319' ` with pre - drilled pups every +/- 200' TVDrkb 0 0 00 00 00 00 00 00 00 0 0 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 14,295' MDrkb / 6,287' TVDrkb Date: Revision By: Comments PIONEER 4 -2 -2009 TWC Frac String Completion ODSN -37 Producer 5-21-2009 Alex Vaughan Updated for wp20 WP20 NATURA[RESOJROESA.AS(A 6 -08 -2009 TWC Updated GLM depths Well Schematic U C CJ Vi Frac String Completion ODSN -37 Ftc String Completion 0 1/VP 20 Casing Item # Item MD (ft) TVD (ft) A 16" Conductor 153 153 Well Head: 9 - 5/8 ", 5K, VetcoGray B 9 -5/8" 40# L -80 BTC, 8.835" ID 3150 3012 Tree: 4 - 1/2 ", 5K, Horizontal C 7" 26# L -80 BTC -M, 6.276" ID 7764 6319 *Estimated TOC @ 4981' MD - 500' above Torok MIIIIIIMer Completion O Mt 1ftl, 1 VetcoGray Tubing Hanger 34 34 4 -1/2" XXO Safety Valve Landing Nipple w/ Wireline AA A ■ 2 Retreivable ScSSSV @ 759' MD / 759' TVD 759 759 3 GLM #1 Brou -1A GLM 4 -1/2" x 1" 2,400 2,338 4 GLM #2 Brou -1A GLM 4 -1/2" x 1" 4,162 3,913 O 5 GLM #3 Brou -1A GLM 4 -1/2" x 1" 5,547 5,140 6 GLM #4 Brou -1A GLM 4 -1/2" x 1" 6,857 6,060 7 4 1/2" XN Nipple, 3.725" ID Nogo 7,107 6,153 End of Assembly 7,593 6,280 8 WFT PBR Tie Back Sleeve 15ft SN #23682673 -01 7,581 6,277 (33_1 9 W FT "NTH" Liner Top Pkr 7,596 6,281 10 WFT "PHR" Rotating Hyd Set Liner Hanger 7,597 6,281 11 4 -1/2" 12.60# L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 7,766 6,320 ® 4 -1/2" 12.60# L -80 Hydril Pupjt Oft (Ported w/ 6 1/2 holes) 7,892 6,345 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,060 6,368 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,186 6,378 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,311 6,382 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,516 6,384 4 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,718 6,381 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 8,920 6,373 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,130 6,373 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,340 6,374 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,550 6,370 �_\ J 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 9,758 6,356 v 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,011 6,335 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,139 6,328 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,348 6,320 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,553 6,317 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,756 6,317 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 10,958 6,313 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,165 6,312 U � 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,363 6,312 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,564 6,320 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,765 6,333 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 11,966 6,350 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,088 6,358 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,295 6,364 O M 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,498 6,362 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,700 6,358 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 12,906 6,353 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,112 6,342 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,315 6,323 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,443 6,310 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,647 6,298 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 13,851 6,294 O 8 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,063 6,290 4 -1/2" 12.60# L -80 Hydril Pupjt 4ft (Ported w/ 6 1/2 holes) 14,233 6,288 00 12 Ray Oil Tool Silver Bullet Float Shoe (PLUGGED) w/ 4 -1/2 IB 14,281 6,287 End of Assembly 14,283 6,287 O 11 12 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 41 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 41 11 11 11 11 15964' MDrkb / 6,350' TVDrkb Date: Rev By: Comments PIONEEI 4-2-2009 TWC Frac String Completion ODSN -37 Producer 5-21-2009 Alex Vaughan Updated for wp20 WP2O NATURAL RESOURCES ALASKA 6 -08 -2009 TWC Updated GLM depths Well Schematic 7 -1 -2009 TWC Final Frac String Completion • Halliburton Company II Definitive Survey Report Company: Well Planning - Pioneer - Oooguruk Local Co-ordinate Reference: Well ODSN -37 - Slot ODS -37 Project: Oooguruk Developement TVD Reference: 42.7' + 13.5' @ 56.2ft (Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5' @ 56.2ft (Nabors 19AC) Well: ODSN -37 North Reference: True Wellbore: ODSN -37 PN8 Survey Calculation Method: Minimum Curvature Design: ODSN -37 PN8 Surveys Database: .Pioneer Alaska 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 Well ODSN -37 - Slot ODS -37 Well Position +N/-S 0.0 if Northing: 6,031,053.00 ft Latitude: 70° 29' 45.273 N +E/ -W 0.0 ft Easting: 469,869.00 ft Longitude: 150° 14' 46.967 W Position Uncertainty 0.0 ft Wellhead Elevation: ft Ground Level: 13.5ft Welibore ODSN -37 PN8 Magnetics Model Name Sample Date Declination Dip Angle Field Strength ( ?) ( ?) (nT) IGRF200510 5/20/2008 22.70 80.81 57,693 Design ODSN -37 PN8 Surveys Audit Notes: 1 Version: 1.0 Phase: ACTUAL Tie On Depth: 42.7 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (ft) (ft) (ft) (bearing) 42.7 0.0 0.0 317.46 Survey Program Date 6/11/2009 From To (ft) (ft) Survey (Wellbore) Tool Name Description Survey Date 50.0 1,488.0 ODSN -37 PN8 Gyro (ODSN -37 PN8) CB- GYRO -SS Camera based gyro single shot 10/27/2008 • 1,530.8 14,258.5 ODSN -37 PN8 MWD (ODSN -37 PN8) MWD +SAG +CA +IIFR +M MWD +SAG +CA +IIFR +Multi Station 10/29/2008 • Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/ -W Northing Easting DLS Section (ft) ( ?) (bearin (ft) (ft) (ft) (ft) (ft) (ft) (°/100') (ft) Survey Tool Name 0.0 0.00 0.00 0.0 -56.2 0.0 0.0 6,031,053.0 469,869.0 0.0 0.00 UNDEFINED 50.0 0.31 103.88 50.0 -6.2 0.0 0.1 6,031,053.0 469,869.1 0.6 -0.11 CB- GYRO -SS (1) 100.0 0.29 208.17 100.0 43.8 -0.2 0.2 6,031,052.8 469,869.2 0.9 -0.27 CB- GYRO -SS (1) 166.0 0.43 259.13 166.0 109.8 -0.4 -0.1 6,031,052.6 469,868.9 0.5 -0.19 CB- GYRO -SS (1) 260.0 0.40 286.99 260.0 203.8 -0.3 -0.8 6,031,052.7 469,868.2 0.2 0.28 CB- GYRO -SS (1) 352.0 0.59 310.22 352.0 295.8 0.1 -1.4 6,031,053.1 469,867.6 0.3 1.02 CB- GYRO -SS (1) 442.0 0.19 84.25 442.0 385.8 0.4 -1.7 6,031,053.4 469,867.3 0.8 1.39 CB- GYRO -SS (1) 539.0 0.75 104.48 539.0 482.8 0.2 -0.9 6,031,053.2 469,868.1 0.6 0.76 CB- GYRO -SS (1) 633.0 1.51 106.27 633.0 576.8 -0.3 0.9 6,031,052.7 469,869.9 0.8 -0.81 CB- GYRO -SS (1) 727.0 3.09 119.44 726.9 670.7 -1.9 4.3 6,031,051.1 469,873.3 1.8 -4.28 CB- GYRO -SS (1) 826.0 4.94 134.90 825.6 769.4 -6.2 9.6 6,031,046.8 469,878.6 2.1 -11.08 CB- GYRO -SS (1) 919.0 5.26 132.46 918.3 862.1 -11.9 15.6 6,031,041.1 469,884.6 0.4 -19.32 CB- GYRO -SS (1) 1,014.0 6.19 135.23 1,012.8 956.6 -18.5 22.4 6,031,034.4 469,891.4 1.0 -28.78 CB- GYRO -SS (1) 6/11/2009 11:04:48AM Page 2 COMPASS 2003.16 Build 428 • Halliburton Company II Definitive Survey Report , Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -37 - Slot ODS-37 Project: Oooguruk Developement TVD Reference: 42.7' + 13.5' @ 56.2ft (Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5' @ 56.2ft (Nabors 19AC) Well: ODSN -37 North Reference: True Wellbore: ODSN -37 PN8 Survey Calculation Method: Minimum Curvature Design: ODSN -37 PN8 Surveys Database: .Pioneer Alaska Survey • Map Map Vertical MD Inc Azi TVD TVDSS +NI-S 4- V -W Northing Easting DLS Section (ft) ( ?) (bearin (ft) (ft) (ft) (ft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,110.0 9.70 141.51 1,107.9 1,051.7 -28.5 31.1 6,031,024.4 469,900.0 3.8 -42.02 CB- GYRO -SS (1) 1,205.0 11.10 137.62 1,201.3 1,145.1 -41.5 42.3 6,031,011.3 469,911.1 1.6 -59.15 CB- GYRO -SS (1) 1,300.0 12.18 141.86 1,294.4 1,238.2 -56.1 54.6 6,030,996.7 469,923.4 1.4 -78.29 CB- GYRO -SS (1) 1,392.0 14.26 145.23 1,383.9 1,327.7 -73.1 67.1 6,030,979.7 469,935.8 2.4 -99.20 CB- GYRO -SS (1) , 1,488.0 15.84 149.16 1,476.6 1,420.4 -94.0 80.5 6,030,958.6 469,949.2 2.0 - 123.74 CB- GYRO -SS (1) 1,530.8 15.61 145.11 1,517.8 1,461.6 -103.8 86.8 6,030,948.9 469,955.4 2.6 - 135.17 MWD +SAG +CA +IIFR +MS (2 1,625.4 16.39 145.38 1,608.7 1,552.5 -125.2 101.7 6,030,927.4 469,970.2 0.8 - 161.00 MWD +SAG +CA +IIFR +MS (2 1 1,720.6 17.57 143.64 1,699.8 1,643.6 -147.8 117.8 6,030,904.7 469,986.2 1.3 - 188.60 MWD +SAG +CA +IIFR +MS (2 1,814.8 18.55 143.58 1,789.3 1,733.1 -171.3 135.2 6,030,881.1 470,003.5 1.0 - 217.62 MWD +SAG +CA +IIFR +MS (2 1,910.4 18.14 142.45 1,880.1 1,823.9 -195.4 153.3 6,030,857.0 470,021.5 0.6 - 247.56 MWD +SAG +CA +IIFR +MS (2 2,003.9 18.81 142.48 1,968.7 1,912.5 -218.9 171.3 6,030,833.5 470,039.4 0.7 - 277.08 MWD +SAG +CA +IIFR +MS (2 2,098.6 20.09 139.75 2,058.1 2,001.9 -243.4 191.1 6,030,808.9 470,059.1 1.7 - 308.57 MWD +SAG +CA +IIFR +MS (2 2,193.5 21.18 138.57 2,146.9 2,090.7 -268.7 213.0 6,030,783.5 470,080.9 1.2 - 341.99 MWD +SAG +CA +1IFR +MS (2 2,288.4 21.51 136.80 2,235.3 2,179.1 -294.2 236.3 6,030,757.9 470,104.0 0.8 - 376.52 MWD +SAG +CA +IIFR +MS (2 2,382.1 23.03 136.43 2,322.0 2,265.8 -320.0 260.7 6,030,731.9 470,128.3 1.6 - 412.04 MWD +SAG +CA +IIFR +MS (2 2,476.9 24.13 134.99 2,408.9 2,352.7 -347.2 287.1 6,030,704.7 470,154.7 1.3 - 449.92 MWD +SAG +CA +IIFR +MS (2 1 2,572.3 25.18 136.09 2,495.6 2,439.4 -375.6 315.0 6,030,676.2 470,182.5 1.2 - 489.71 MWD +SAG +CA +IIFR +MS (2 2,665.7 25.19 140.31 2,580.1 2,523.9 -405.2 341.5 6,030,646.5 470,208.8 1.9 - 529.42 MWD +SAG +CA +IIFR +MS (2 2,761.9 26.90 140.44 2,666.6 2,610.4 -437.7 368.4 6,030,613.8 470,235.6 1.8 - 571.62 MWD +SAG +CA +IIFR +MS (2 2,856.7 26.38 140.23 2,751.3 2,695.1 -470.4 395.6 6,030,581.0 470,262.6 0.6 - 614.07 MWD +SAG +CA +IIFR +MS (2 2,950.9 27.49 138.22 2,835.2 2,779.0 -502.7 423.4 6,030,548.6 470,290.3 1.5 - 656.69 MWD +SAG +CA +IIFR +MS (2 3,044.5 27.08 141.47 2,918.4 2,862.2 -535.5 451.1 6,030,515.7 470,317.9 1.7 - 699.56 MWD +SAG +CA +IIFR +MS (2 3,114.2 27.19 143.40 2,980.4 2,924.2 -560.7 470.5 6,030,490.5 470,337.1 1.3 - 731.21 MWD +SAG +CA +IIFR +MS (2 3,214.1 25.69 145.06 3,069.9 3,013.7 -596.8 496.5 6,030,454.3 470,363.0 1.7 - 775.37 MWD +SAG +CA +IIFR +MS (2 3,308.9 25.47 148.59 3,155.4 3,099.2 -631.0 518.9 6,030,420.0 470,385.2 1.6 - 815.74 MWD +SAG +CA +1IFR +MS (2 3,404.0 25.63 152.91 3,241.2 3,185.0 -666.8 538.9 6,030,384.1 470,405.1 2.0 - 855.65 MWD +SAG +CA +IIFR +MS (2 3,498.9 28.01 158.37 3,325.9 3,269.7 -705.8 556.5 6,030,345.0 470,422.5 3.6 - 896.26 MWD +SAG +CA +IIFR +MS (2 3,593.5 28.86 160.66 3,409.1 3,352.9 -748.0 572.2 6,030,302.8 470,438.1 1.5 - 937.99 MWD +SAG +CA +IIFR +MS (2 3,687.9 28.15 162.17 3,492.1 3,435.9 -790.7 586.6 6,030,260.0 470,452.3 1.1 - 979.16 MWD +SAG +CA +IIFR +MS (2 3,782.5 28.01 162.84 3,575.6 3,519.4 -833.2 600.0 6,030,217.5 470,465.5 0.4 - 1,019.51 MWD +SAG +CA +IIFR +MS (2 3,877.1 27.62 163.91 3,659.2 3,603.0 -875.5 612.6 6,030,175.2 470,478.0 0.7 - 1,059.22 MWD +SAG +CA +IIFR +MS (2 3,970.0 27.40 164.60 3,741.6 3,685.4 -916.7 624.2 6,030,133.8 470,489.4 0.4 - 1,097.50 MWD +SAG +CA +IIFR +MS (2 4,064.1 26.81 164.36 3,825.3 3,769.1 -958.0 635.7 6,030,092.5 470,500.8 0.6 - 1,135.69 MWD +SAG +CA +IIFR +MS (2 4,159.0 27.22 168.25 3,910.0 3,853.8 -999.9 645.9 6,030,050.6 470,510.8 1.9 - 1,173.45 MWD +SAG +CA +1IFR +MS (2 4,253.7 27.92 176.03 3,993.9 3,937.7 - 1,043.3 651.8 6,030,007.2 470,516.6 3.9 - 1,209.41 MWD +SAG +CA +I1FR +MS (2 4,347.3 28.12 182.41 4,076.6 4,020.4 - 1,087.2 652.4 6,029,963.3 470,517.0 3.2 - 1,242.15 MWD +SAG +CA +IIFR +MS (2 4,443.2 27.29 190.31 4,161.4 4,105.2 - 1,131.4 647.6 6,029,919.1 470,511.9 3.9 - 1,271.42 MWD +SAG +CA +IIFR +MS (2 4,537.8 26.52 197.34 4,245.9 4,189.7 - 1,172.9 637.4 6,029,877.6 470,501.5 3.5 - 1,295.13 MWD +SAG +CA +IIFR +MS (2 4,632.4 26.09 210.42 4,330.7 4,274.5 - 1,211.0 620.5 6,029,839.6 470,484.6 6.1 - 1,311.83 MWD +SAG +CA +IIFR +MS (2 4,727.2 29.37 221.23 4,414.7 4,358.5 - 1,246.5 594.6 6,029,804.2 470,458.5 6.3 - 1,320.47 MWD +SAG +CA +IIFR +MS (2 6/11/2009 11:04:48AM Page 3 COMPASS 2003.16 Build 428 • Halliburton Company III 1 Definitive Survey Report , Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -37 - Slot ODS -37 Project: Oooguruk Developement TVD Reference: 42.7' + 13.5 @ 56.2ft (Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5' @ 56.2ft (Nabors 19AC) Well: ODSN -37 North Reference: True Wellbore: ODSN -37 PN8 Survey Calculation Method: Minimum Curvature Design: ODSN -37 PN8 Surveys Database: .Pioneer Alaska Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section (ft) ( ?) (bearin (ft) (ft) (ft) (ft) (ft) (ft) ( %100') (ft) Survey Tool Name 4,821.8 30.02 226.86 4,496.9 4,440.7 - 1,280.2 562.1 6,029,770.7 470,425.8 3.0 - 1,323.24 MWD +SAG +CA +IIFR +MS (2 4,917.5 29.59 227.03 4,580.0 4,523.8 - 1,312.6 527.3 6,029,738.4 470,390.9 0.5 - 1,323.67 MWD +SAG +CA +IIFR +MS (2 5,012.4 28.59 227.73 4,662.9 4,606.7 - 1,343.9 493.3 6,029,707.3 470,356.8 1.1 - 1,323.73 MWD +SAG +CA +IIFR +MS (2 5,107.1 27.62 230.71 4,746.4 4,690.2 - 1,373.0 459.6 6,029,678.3 470,323.0 1.8 - 1,322.38 MWD +SAG +CA +IIFR +MS (2 5,202.8 26.75 236.17 4,831.5 4,775.3 - 1,399.0 424.5 6,029,652.4 470,287.8 2.8 - 1,317.87 MWD +SAG +CA +IIFR +MS (2 5,297.2 26.56 241.72 4,915.9 4,859.7 - 1,420.9 388.3 6,029,630.7 470,251.5 2.6 - 1,309.45 MWD +SAG +CA +IIFR +MS (2 5,391.1 26.91 248.59 4,999.8 4,943.6 - 1,438.6 350.0 6,029,613.1 470,213.1 3.3 - 1,296.61 MWD +SAG +CA +IIFR +MS (2 5,486.6 25.75 262.96 5,085.5 5,029.3 - 1,449.0 309.3 6,029,602.9 470,172.4 6.8 - 1,276.75 MWD +SAG +CA +IIFR +MS (2 5,582.6 26.79 272.38 5,171.6 5,115.4 - 1,450.7 266.9 6,029,601.4 470,130.0 4.5 - 1,249.35 MWD +SAG +CA +IIFR +MS (2 5,678.0 28.45 280.32 5,256.2 5,200.0 - 1,445.7 223.1 6,029,606.5 470,086.2 4.2 - 1,216.03 MWD +SAG +CA +IIFR +MS (2 5,772.2 28.75 288.88 5,338.9 5,282.7 - 1,434.4 179.6 6,029,618.0 470,042.7 4.4 - 1,178.27 MWD +SAG +CA +IIFR +MS (2 5,867.1 29.93 294.74 5,421.6 5,365.4 - 1,417.1 136.4 6,029,635.5 469,999.7 3.3 - 1,136.36 MWD +SAG +CA +IIFR +MS (2 5,962.2 34.36 304.06 5,502.2 5,446.0 - 1,392.1 92.6 6,029,660.7 469,956.0 7.0 - 1,088.32 MWD +SAG +CA +IIFR +MS (2 6,057.1 38.18 308.34 5,578.7 5,522.5 - 1,358.9 47.4 6,029,694.1 469,910.9 4.8 - 1,033.25 MWD +SAG +CA +1IFR +MS (2 6,151.2 42.35 311.74 5,650.5 5,594.3 - 1,319.7 0.9 6,029,733.4 469,864.6 5.0 - 973.01 MWD +SAG +CA +IIFR +MS (2 6,245.5 46.18 316.59 5,718.0 5,661.8 - 1,273.8 -46.2 6,029,779.5 469,817.6 5.4 - 907.33 MWD +SAG +CA +IIFR +MS (2 6,340.6 49.91 319.45 5,781.6 5,725.4 - 1,221.2 -93.5 6,029,832.3 469,770.6 4.5 - 836.60 MWD +SAG +CA +IIFR +MS (2 6,435.3 54.70 323.85 5,839.5 5,783.3 - 1,162.4 -139.8 6,029,891.3 469,724.5 6.3 - 761.94 MWD +SAG +CA +IIFR +MS (2 6,530.1 54.51 323.70 5,894.4 5,838.2 - 1,100.1 -185.5 6,029,953.8 469,679.1 0.2 - 685.15 MWD +SAG +CA +IIFR +MS (2 6,624.6 57.53 328.77 5,947.3 5,891.1 - 1,035.0 -229.0 6,030,019.1 469,635.8 5.5 - 607.74 MWD +SAG +CA +IIFR +MS (2 6,719.8 59.70 331.71 5,996.9 5,940.7 -964.4 -269.3 6,030,089.8 469,595.8 3.5 - 528.49 MWD +SAG +CA +IIFR +MS (2 6,814.3 63.73 334.45 6,041.6 5,985.4 -890.2 -306.9 6,030,164.1 469,558.5 5.0 - 448.38 MWD +SAG +CA +IIFR +MS (2 6,909.9 66.50 335.68 6,081.9 6,025.7 -811.6 -343.5 6,030,242.9 469,522.3 3.1 - 365.73 MWD +SAG +CA +IIFR +MS (2 7,005.3 68.64 335.44 6,118.2 6,062.0 -731.4 -379.9 6,030,323.3 469,486.1 2.3 - 281.98 MWD +SAG +CA +IIFR +MS (2 7,099.0 70.17 335.90 6,151.2 6,095.0 -651.4 -416.1 6,030,403.3 469,450.3 1.7 - 198.65 MWD +SAG +CA +IIFR +MS (2 7,194.1 72.76 335.62 6,181.4 6,125.2 -569.2 -453.1 6,030,485.7 469,413.7 2.7 - 113.08 MWD +SAG +CA +IIFR +MS (2 7,288.5 75.09 336.06 6,207.6 6,151.4 - 486.4 -490.2 6,030,568.6 469,376.8 2.5 -26.96 MWD +SAG +CA +IIFR +MS (2 7,384.9 75.80 336.22 6,231.8 6,175.6 -401.1 -528.0 6,030,654.1 469,339.4 0.8 61.46 MWD +SAG +CA +1IFR +MS (2 7,479.4 77.05 336.22 6,254.0 6,197.8 -317.0 -565.0 6,030,738.3 469,302.8 1.3 148.41 MWD +SAG +CA +IIFR +MS (2 7,573.7 76.56 335.63 6,275.5 6,219.3 -233.3 -602.4 6,030,822.2 469,265.7 0.8 235.43 MWD +SAG +CA +IIFR +MS (2 7,669.3 76.55 335.06 6,297.7 6,241.5 -148.7 -641.3 6,030,906.9 469,227.2 0.6 324.00 MWD +SAG +CA +IIFR +MS (2 7,742.1 76.74 334.66 6,314.6 6,258.4 -84.6 -671.4 6,030,971.2 469,197.4 0.6 391.59 MWD +SAG +CA +I1FR +MS (2 7,806.2 78.38 335.03 6,328.4 6,272.2 -27.9 -698.0 6,031,027.9 469,171.0 2.6 451.31 MWD +SAG +CA +IIFR +MS (2 7,849.4 79.05 334.81 6,336.8 6,280.6 10.4 -715.9 6,031,066.3 469,153.2 1.6 491.70 MWD +SAG +CA +IIFR +MS (2 7,946.6 81.05 334.85 6,353.6 6,297.4 97.0 -756.6 6,031,153.1 469,112.9 2.1 583.04 MWD +SAG +CA +IIFR +MS (2 8,001.1 83.35 335.05 6,361.0 6,304.8 146.0 -779.5 6,031,202.1 469,090.2 4.2 634.58 MWD +SAG +CA +IIFR +MS (2 8,043.2 83.22 334.65 6,365.9 6,309.7 183.8 -797.3 6,031,240.0 469,072.6 1.0 674.48 MWD +SAG +CA +IIFR +MS (2 8,136.2 86.09 332.82 6,374.6 6,318.4 266.8 -838.2 6,031,323.2 469,032.0 3.7 763.34 MWD +SAG +CA +1IFR +MS (2 8,233.2 87.57 330.41 6,380.0 6,323.8 352.0 -884.3 6,031,408.6 468,986.3 2.9 857.23 MWD +SAG +CA +IIFR +MS (2 8,328.8 90.04 327.36 6,381.9 6,325.7 433.8 -933.6 6,031,490.6 468,937.2 4.1 950.87 MWD +SAG +CA +IIFR +MS (2 6/11/2009 11:04:48AM Page 4 COMPASS 2003.16 Build 428 , , • Halliburton Company • Definitive Survey Report ' Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -37 - Slot ODS -37 Project: Oooguruk Developement TVD Reference: 42.7' + 13.5' @ 56.2ft (Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5' @ 56.2ft (Nabors 19AC) Well: ODSN -37 North Reference: True Wellbore: ODSN -37 PN8 Survey Calculation Method: Minimum Curvature Design: ODSN -37 PN8 Surveys Database: .Pioneer Alaska Survey Map Map Vertical MD Inc Azi TVD TVDSS 4+1/-S +E/ -W Northing Easting DLS Section (ft) ( ?) (bearin (ft) (ft) (ft) (ft) (ft) (ft) moo, (ft) Survey Tool Name 8,426.3 89.66 323.54 6,382.2 6,326.0 514.1 -988.9 6,031,571.1 468,882.3 3.9 1,047.43 MWD +SAG +CA +IIFR +MS (2 8,522.6 88.18 321.16 6,384.0 6,327.8 590.4 - 1,047.7 6,031,647.6 468,823.8 2.9 1,143.38 MWD +SAG +CA +IIFR +MS (2 8,618.2 91.63 317.75 6,384.2 6,328.0 663.0 - 1,109.8 6,031,720.4 468,762.0 5.1 1,238.84 MWD +SAG +CA +1IFR +MS (2 8,710.5 91.70 317.81 6,381.5 6,325.3 731.3 - 1,171.9 6,031,789.0 468,700.2 0.1 1,331.18 MWD +SAG +CA +IIFR +MS (2 8,811.3 92.94 317.57 6,377.4 6,321.2 805.8 - 1,239.7 6,031,863.7 468,632.7 1.3 1,431.87 MWD +SAG +CA +IIFR +MS (2 8,910.0 91.63 317.22 6,373.5 6,317.3 878.4 - 1,306.5 6,031,936.6 468,566.3 1.4 1,530.52 MWD +SAG +CA +IIFR +MS (2 9,006.4 89.78 315.51 6,372.3 6,316.1 948.2 - 1,372.9 6,032,006.6 468,500.1 2.6 1,626.85 MWD +SAG +CA +IIFR +MS (2 9,104.0 89.54 313.05 6,372.9 6,316.7 1,016.3 - 1,442.8 6,032,075.0 468,430.5 2.5 1,724.28 MWD +SAG +CA +IIFR +MS (2 9,199.6 89.60 315.51 6,373.6 6,317.4 1,083.0 - 1,511.3 6,032,142.1 468,362.3 2.6 1,819.76 MWD +SAG +CA +I1FR +MS (2 9,296.6 89.66 315.64 6,374.2 6,318.0 1,152.3 - 1,579.1 6,032,211.6 468,294.7 0.1 1,916.67 MWD +SAG +CA +IIFR +MS (2 9,391.1 91.27 316.54 6,373.4 6,317.2 1,220.4 - 1,644.7 6,032,279.9 468,229.5 2.0 2,011.13 MWD +SAG +CA +IIFR +MS (2 9,485.4 90.15 316.64 6,372.3 6,316.1 1,288.8 - 1,709.4 6,032,348.6 468,165.0 1.2 2,105.39 MWD +SAG +CA +IIFR +MS (2 9,532.1 92.51 315.31 6,371.2 6,315.0 1,322.4 - 1,741.9 6,032,382.4 468,132.6 5.8 2,152.10 MWD +SAG +CA +IIFR +MS (2 9,582.1 93.80 314.56 6,368.4 6,312.2 1,357.7 - 1,777.2 6,032,417.7 468,097.5 3.0 2,201.92 MWD +SAG +CA +IIFR +MS (2 9,678.9 94.11 316.48 6,361.8 6,305.6 1,426.6 - 1,844.9 6,032,486.9 468,030.1 2.0 2,298.45 MWD +SAG +CA +1IFR +MS (2 9,775.6 95.22 317.74 6,353.9 6,297.7 1,497.2 - 1,910.5 6,032,557.8 467,964.8 1.7 2,394.84 MWD +SAG +CA +IIFR +MS (2 9,818.0 95.91 318.89 6,349.8 6,293.6 1,528.7 - 1,938.5 6,032,589.4 467,936.9 3.2 2,437.01 MWD +SAG +CA +IIFR +MS (2 9,871.3 93.97 319.01 6,345.2 6,289.0 1,568.8 - 1,973.4 6,032,629.6 467,902.1 3.6 2,490.14 MWD +SAG +CA +IIFR +MS (2 9,969.9 94.10 321.10 6,338.3 6,282.1 1,644.2 - 2,036.6 6,032,705.2 467,839.3 2.1 2,588.38 MWD +SAG +CA +IIFR +MS (2 10,066.1 93.61 322.45 6,331.8 6,275.6 1,719.6 - 2,096.0 6,032,780.9 467,780.2 1.5 2,684.09 MWD +SAG +CA +IIFR +MS (2 10,161.5 92.68 322.67 6,326.6 6,270.4 1,795.2 - 2,153.9 6,032,856.7 467,722.6 1.0 2,778.93 MWD +SAG +CA +IIFR +MS (2 10,258.5 91.88 322.14 6,322.7 6,266.5 1,872.0 - 2,213.0 6,032,933.8 467,663.8 1.0 2,875.51 MWD +SAG +CA +IIFR +MS (2 10,354.8 91.14 319.54 6,320.2 6,264.0 1,946.6 - 2,273.8 6,033,008.6 467,603.3 2.8 2,971.61 MWD +SAG +CA +IIFR +MS (2 10,451.8 90.89 319.07 6,318.4 6,262.2 2,020.1 - 2,337.0 6,033,082.4 467,540.4 0.5 3,068.51 MWD +SAG +CA +IIFR +MS (2 10,547.6 90.28 322.09 6,317.5 6,261.3 2,094.2 - 2,397.9 6,033,156.7 467,479.9 3.2 3,164.20 MWD +SAG +CA +IIFR +MS (2 10,644.5 89.35 320.33 6,317.8 6,261.6 2,169.7 - 2,458.6 6,033,232.4 467,419.5 2.1 3,260.87 MWD +SAG +CA +IIFR +MS (2 10,740.4 91.64 320.47 6,316.9 6,260.7 2,243.5 - 2,519.6 6,033,306.5 467,358.7 2.4 3,356.59 MWD +SAG +CA +IIFR +MS (2 10,836.3 90.77 321.67 6,314.9 6,258.7 2,318.2 - 2,579.9 6,033,381.4 467,298.7 1.5 3,452.34 MWD +SAG +CA +IIFR +MS (2 10,935.0 90.89 320.04 6,313.5 6,257.3 2,394.6 - 2,642.2 6,033,458.1 467,236.8 1.7 3,550.79 MWD +SAG +CA +IIFR +MS (2 11,031.7 90.03 319.14 6,312.7 6,256.5 2,468.3 - 2,704.9 6,033,532.0 467,174.4 1.3 3,647.49 MWD +SAG +CA +IIFR +MS (2 11,127.9 90.77 320.21 6,312.1 6,255.9 2,541.6 - 2,767.1 6,033,605.6 467,112.5 1.4 3,743.56 MWD +SAG +CA +IIFR +MS (2 11,224.8 89.53 319.55 6,311.8 6,255.6 2,615.8 - 2,829.6 6,033,679.9 467,050.3 1.4 3,840.41 MWD +SAG +CA +IIFR +MS (2 11,320.3 90.34 321.71 6,311.9 6,255.7 2,689.6 - 2,890.2 6,033,754.0 466,990.1 2.4 3,935.73 MWD +SAG +CA +IIFR +MS (2 11,416.5 87.74 323.20 6,313.5 6,257.3 2,765.8 - 2,948.8 6,033,830.5 466,931.8 3.1 4,031.54 MWD +SAG +CA +IIFR +MS (2 11,514.0 87.44 322.58 6,317.6 6,261.4 2,843.5 - 3,007.6 6,033,908.4 466,873.3 0.7 4,128.55 MWD +SAG +CA +IIFR +MS (2 11,610.0 86.57 321.19 6,322.6 6,266.4 2,918.9 - 3,066.7 6,033,984.0 466,814.4 1.7 4,224.10 MWD +SAG +CA +IIFR +MS (2 11,705.3 85.82 321.71 6,329.0 6,272.8 2,993.3 - 3,126.0 6,034,058.7 466,755.5 1.0 4,318.99 MWD +SAG +CA +IIFR +MS (2 11,800.2 85.89 320.95 6,335.8 6,279.6 3,067.2 - 3,185.1 6,034,132.8 466,696.7 0.8 4,413.39 MWD +SAG +CA +IIFR +MS (2 11,897.1 84.77 320.72 6,343.7 6,287.5 3,142.1 - 3,246.1 6,034,207.9 466,636.0 1.2 4,509.83 MWD +SAG +CA +IIFR +MS (2 11,934.6 84.46 321.11 6,347.2 6,291.0 3,171.1 - 3,269.7 6,034,237.0 466,612.6 1.3 4,547.08 MWD +SAG +CA +IIFR +MS (2 6/11/2009 11:04:48AM Page 5 COMPASS 2003.16 Build 42B • Halliburton Company • Definitive Survey Report . Company: Well Planning - Pioneer - Oooguruk Local Co- ordinate Reference: Well ODSN -37 - Slot ODS -37 Project: Oooguruk Developement TVD Reference: 42.7' + 13.5' @ 56.2ft (Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5' @ 56.2ft (Nabors 19AC) Well: ODSN -37 North Reference: True Wetlbore: ODSN -37 PN8 Survey Calculation Method: Minimum Curvature Design: ODSN -37 PN8 Surveys Database: .Pioneer Alaska Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +V -W Northing Easting DLS Section (ft) ( ?) (bearin (ft) (ft) (ft) (ft) (ft) (ft) ( °11001 (ft) Survey Tool Name 11,995.4 86.40 320.06 6,352.1 6,295.9 3,217.8 - 3,308.1 6,034,283.9 466,574.3 3.6 4,607.55 MWD +SAG +CA +IIFR +MS (2 12,090.4 86.51 320.27 6,357.9 6,301.7 3,290.7 - 3,368.9 6,034,357.0 466,513.8 0.2 4,702.30 MWD +SAG +CA +IIFR +MS (2 12,186.0 88.31 320.29 6,362.3 6,306.1 3,364.2 - 3,429.9 6,034,430.7 466,453.1 1.9 4,797.70 MWD +SAG +CA +IIFR +MS (2 12,283.7 89.54 319.82 6,364.1 6,307.9 3,439.0 - 3,492.6 6,034,505.8 466,390.7 1.3 4,895.26 MWD +SAG +CA +IIFR +MS (2 12,381.4 91.58 318.84 6,363.1 6,306.9 3,513.1 - 3,556.3 6,034,580.1 466,327.4 2.3 4,992.87 MWD +SAG +CA +IIFR +MS (2 12,477.1 90.15 317.74 6,361.7 6,305.5 3,584.6 - 3,620.0 6,034,651.9 466,263.9 1.9 5,088.63 MWD +SAG +CA +IIFR +MS (2 12,575.4 91.02 319.71 6,360.7 6,304.5 3,658.4 - 3,684.8 6,034,725.9 466,199.5 2.2 5,186.81 MWD +SAG +CA +IIFR +MS (2 12,668.7 91.64 320.60 6,358.5 6,302.3 3,730.1 - 3,744.6 6,034,797.8 466,140.0 1.2 5,280.05 MWD +SAG +CA +IIFR +MS (2 1 12,763.3 91.70 320.81 6,355.8 6,299.6 3,803.2 - 3,804.4 6,034,871.2 466,080.4 0.2 5,374.44 MWD +SAG +CA +IIFR +MS (2 12,860.9 90.83 322.16 6,353.6 6,297.4 3,879.6 - 3,865.2 6,034,947.8 466,020.0 1.6 5,471.76 MWD +SAG +CA +IIFR +MS (2 12,958.1 92.13 321.51 6,351.1 6,294.9 3,956.0 - 3,925.3 6,035,024.5 465,960.2 1.5 5,568.68 MWD +SAG +CA +IIFR +MS (2 13,052.5 93.80 321.90 6,346.2 6,290.0 4,029.9 - 3,983.7 6,035,098.7 465,902.1 1.8 5,662.65 MWD +SAG +CA +IIFR +MS (2 13,152.4 94.73 321.66 6,338.8 6,282.6 4,108.2 - 4,045.3 6,035,177.2 465,840.8 1.0 5,761.99 MWD +SAG +CA +IIFR +MS (2 13,248.2 95.47 321.28 6,330.3 6,274.1 4,182.9 - 4,104.7 6,035,252.0 465,781.7 0.9 5,857.19 MWD +SAG +CA +IIFR +MS (2 13,318.5 96.65 320.95 6,322.9 6,266.7 4,237.2 - 4,148.6 6,035,306.6 465,738.0 1.7 5,926.89 MWD +SAG +CA +IIFR +MS (2 13,343.2 96.40 321.09 6,320.1 6,263.9 4,256.4 - 4,164.1 6,035,325.8 465,722.7 1.2 5,951.44 MWD +SAG +CA +IIFR +MS (2 13,440.2 95.52 321.50 6,310.0 6,253.8 4,331.7 - 4,224.4 6,035,401.3 465,662.6 1.0 6,047.73 MWD +SAG +CA +IIFR +MS (2 13,507.7 93.73 319.81 6,304.5 6,248.3 4,383.6 - 4,267.0 6,035,453.4 465,620.2 3.6 6,114.82 MWD +SAG +CA +IIFR +MS (2 13,538.5 93.30 319.62 6,302.6 6,246.4 4,407.1 - 4,286.9 6,035,477.0 465,600.4 1.5 6,145.55 MWD +SAG +CA +IIFR +MS (2 13,635.4 91.69 319.30 6,298.4 6,242.2 4,480.7 - 4,349.9 6,035,550.9 465,537.8 1.7 6,242.37 MWD +SAG +CA +IIFR +MS (2 13,731.3 90.89 317.26 6,296.3 6,240.1 4,552.2 - 4,413.6 6,035,622.6 465,474.3 2.3 6,338.17 MWD +SAG +CA +IIFR +MS (2 13,828.4 91.57 318.34 6,294.2 6,238.0 4,624.2 - 4,478.9 6,035,694.8 465,409.4 1.3 6,435.29 MWD +SAG +CA +IIFR +MS (2 13,924.2 90.89 318.53 6,292.1 6,235.9 4,695.8 - 4,542.4 6,035,766.7 465,346.2 0.7 6,531.02 MWD +SAG +CA +IIFR +MS (2 14,020.9 91.20 319.79 6,290.4 6,234.2 4,769.0 - 4,605.6 6,035,840.1 465,283.2 1.3 6,627.67 MWD +SAG +CA +IIFR +MS (2 14,117.8 90.46 318.80 6,289.0 6,232.8 4,842.4 - 4,668.8 6,035,913.8 465,220.3 1.3 6,724.51 MWD +SAG +CA +IIFR +MS (2 14,214.0 90.52 320.08 6,288.1 6,231.9 4,915.5 - 4,731.3 6,035,987.1 465,158.1 1.3 6,820.63 MWD +SAG +CA +IIFR +MS (2 14,258.5 91.02 321.79 6,287.5 6,231.3 4,950.0 - 4,759.4 6,036,021.8 465,130.2 4.0 6,865.02 MWD +SAG +CA +IIFR +MS (2 14,295.0 91.02 321.79 6,286.9 6,230.7 4,978.7 - 4,782.0 6,036,050.5 465,107.8 0.0 6,901.43 PROJECTED to TD 6/11/2009 11:04:48AM Page 6 COMPASS 2003.16 Build 428 • PIONEER July 24, 2009 AOGCC Attn: Steve Davies 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 Hello, Included in this package are the well logs /CDs for ODSN -37 with the correct API number. Please discard the previously sent set and keep these for your copy. We are sorry for the inconvenience. If you should have any questions, you can reach Paul Daggett at 907- 343 -2134. Thank you, Shannon Koh ,bs \� ® 700 G STREET, SUITE 600 - ANCHORAGE, AK 99501 - MAIN 907 - 277 -2700 - FAX 907 - 343 -2190 1 • PIONEER NATURAL RESOURCES ALASKA Letter of Transmittal Date: July 24, 2009 FROM TO Shannon Koh AOGCC Pioneer Natural Resources Attn: Steve Davies 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, 4 Well Logs ❑ Agreement DETAIL QTY DESCRIPTION 1 CD ODSN -37 (API: 50- 703 - 20586 -00) 1CD LWD Final Processed Data containing digital graphic Togs (EMF, CGM, PDF, TIFF) and digital data (LAS, DLIS) 4 Well Logs 4 Well lops DGR, EWR -Phase 4, CTN, ALD, Horizontal Presentation (1:600, 1:240) DGR, EWR -Phase 4, CTN, ALD, Invert/Revert Sections (1:600, 1:240) We request that all data 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 Onzs 4 1 1TINT �� t / SARAH PALIN, GOVERNOR OIL 7�T ` ALASKA OIL AND GAS / 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION / ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 James Franks Senior Drilling Engineer Pioneer Natural Resources Alaska Inc. 700 G Street, Ste 600 Anchorage AK 99501 Re: Oooguruk Field, Nuiqsut Oil Pool, ODSN -37 Sundry Number: 309 -163 Dear Mr. Franks: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, / Daniel T. Seamount, Jr. Chair DATED this day of May, 2009 Encl. ,, e� RECEIVED • U c STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 0 1 2009 >�.0� 1 � APPLICATION FOR SUNDRY APPROVALS AiRska Ow! & as Cons, Commission . 20 AAC 25.280 Anchorage 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown El - Perforate ❑ Waiver ❑ Other ❑ Alter casing ❑ Repair well ❑ Plug Perforations ❑ Stimulate 1151 Time Extension ❑ Change approved program Isi , Pull Tubing ❑ Perforate New Pool ❑ Re -enter Suspended Well ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Pioneer Natural Resources Alaska Inc. Development 0 _ Exploratory ❑ 208 -157 _ 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: 700 G Street, Suite 600 Anchorage, AK 99501 50- 703 - 20586 -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: • ODSN -37 - Spacing Exception Required? Yes ❑ No 0 9. Property Designation: 10. KB Elevation (ft): 11. Field / Pool(s): ADL 355036 - 57.5' MSL Ooogurk - Nuiqsut Oil Pool 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 7775' 6322' 7762' 6319' N/A n/A Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 158' 158' N/A N/A Surface 3142' 9 -5/8" 3150' 3012' 5750 3090 Intermediate 7759' 7' 7764' 6319' 7240 5410 Expandable Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type: Packers and SSSV MD (ft): 13. Attachments: . Description Summary of Proposal 0 14. Well Class after proposed work: Detailed Operations Program ID BOP Sketch ❑ Exploratory ❑ Development 0 - Service ❑ 15. Estimated Date for 16. Well Status after proposed work: 5/10/2009 Commencing Operations: Oil El - Gas ❑ Plugged ❑ Abandoned ❑ 17. Verbal Approval: Date: WAG ❑ GINJ ❑ WINJ ❑ WDSPL Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Alex Vaughan, 343 -2186 Printed Nam James Franks Title Senior Drilling Engineer Signature Phone Date 343-2179 5/1/2009 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 30 q I - I ( 3 Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: 35 - � \ \ �,A_ i — S®o v5� irsA ^\ i ikG�V \d v_ ,,,N., Subsequent Form Required: ir (� - h� S i t'L 4--■cc "1® \ 0 _\-- c_p M�\r„ t ®t...- o il- -)C \ L� r MAY 0 EC 7pp� APPROVED BY A roved b : COMMISSIONER THE COMMISSION Date: (CI PP y ru(-;,� �� )r .\.! (� a � Form 10 -403 Revised 06/2006 ti r.;\ i V 2 i i /- L Submit in Duplicate ti • PIONEER NATURAL RESOURCES May 1, 2009 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7 Avenue, Suite #100 Anchorage, AK 99501 RE: Application for Sundry, Addition of suspension following intermediate section and fracture stimulation program Permit to Drill # 208 -157 Surface Location: 2937' FSL, 1129' FEL, Sec 11, T13N, R7E, UM X = 469869.00, Y = 6031053.00, ASP4 Pioneer Natural Resources, Alaska (PNRA) is submitting a suspension and fracture stimulation proposal for AOGCC's review and approval for the ODSN -37 well. Pioneer originally permitted to drill the 6 1/8" lateral, set a 4 %2" 12.6# L -80 liner, and run an ESP completion. Pioneer has opted to add a fracture stimulation and flow back period to the approved Permit to Drill (# 208- 157). The proposed plan is as follows: Pre -Rig Work: 1. The Oooguruk Drill Site Class 1 / Class 2 Disposal Well, ODSDW1 -44, has been drilled, commissioned and operational for disposal. 2. Provide 48 hours notice for the testing of the BOPE. 3. Post Permit to Drill # 208 -157 4. 7" intermediate casing was tested to 3500 psi for 30 min on 12/1/2008. Rig Activity: Drill and Complete Remaining Well 1. MIRU to ODSN -37. RU circulation lines and circulate out the diesel freeze protection fluid and ensure the well is dead. 2. Install TWC, ND Tree and NU BOPE, Remove TWC, Test BOPE to 250/3500 psi. 3. Pull circulation tubing string from the well. • } • Alaska Oil & Gas Conservation Commission May 1, 2009 Page 2 of 3 4. MU 6 -1/8" directional drilling, MWD /LWD assembly. RIH and cieanout to landing collar. 5. Re- verify the pressure test the 7" casing to 3,500 psi. 6. Displace the well over to production hole drilling fluid. Managed Pressure Drilling will be used. 7. Drill out shoe tract, cement, rat hole and 20' of new formation below 7" shoe. Pull the bit back into the 7" casing and perform an FIT. 8. Drill the 6 -1/8" production hole to TD at — 15708' MD/ 6374' TVDrkb. POH. 9. Circulate and condition the hole to run liner. POH. 10. Run 4 -1/2" liner on 4" DP 11. Release from the liner and set the liner top packer. Displace the well over to 10.2 ppg Brine. POH. 12. Run 4' /2" fracture completion string 13. Install Wireline retrievable SSSV 14. Fracture stimulate well SQE e,t,„G\ - -pc- 15. Suspend operations yEeklke-r 16. Flowback well with gaslift. 17. RDMO ODSN -37 Complete ODSN -37 1. MIRU ODSN -37. 2. Pull 4 /2" fracture completion string. 3. MU completion with ESP and RIH. 4. Land the tubing and RILDS. Install TWC. 5. ND BOPE, NU tree and test to 5,000 psi. 6. Pull TWC and reverse circulate corrosion inhibited brine and diesel to freeze protect the well to —2000' TVD and allow to u -tube. 7. Drop ball and rod and allow to seat. Pressure test the tubing to 3,500 psi — chart and hold for 30 minutes. Bleed off pressure and then pressure test the annulus to 3,500 psi — chart and hold for 30 minutes. Bleed off pressure. 8. RU Slickline and pull the ball and rod. Pull the RHC -m plug. 9. RD Slickline. RDMO to next well. • • Alaska Oil & Gas Conservation Commission May 1, 2009 Page 3 of 3 Please find attached information for your review: 1) Form 10 -403 Application for Sundry. The following are PNRA's designated contacts for reporting responsibilities to the Commission: 1) Completion Report James Franks, Senior Drilling Engineer (20 AAC 25.070) (907) 343 -2179 james.franks@pxd.com 2) Geologic Data and Logs Paul Daggett, Operations Geologist (20 AAC 25.071) (907) 343 -2134 doud.waters @pxd.com Sincerely, James Franks Senior Drilling Engineer Attachments: Form 10 -403 Supporting information cc: ODSN -37 Well File Page 1 of 4 • • "D- Maunder, Thomas E (DOA) From: Vaughan, Alex [AIex.Vaughan @pxd.com] Sent: Wednesday, May 06, 2009 4 :57 PM To: Maunder, Thomas E (DOA) Subject: RE: ODSN -37 (208 -157) -- Use this one Tom, I have discussed the cement volume discrepancy with our Halliburton Cementing Rep. Please see the correct volumes below. You will notice that although the total cement volumes pumped according to our Supervisor and Halliburton were the same the lead and tail volumes are different. This was due to a zeroing error during the pumping break between lead and tail cement. Field Pumped Field Pumped Cement Sacks Yield Lead 60.bbI 142.sacks 2.37.cuft/sk Tail 40.bbl 192.sacks 1.17.cuft/sk Tom, - - -. � - - -- - -- -- — __ -- - - -- PXD does not reciprocate during intermediate cement jobs as a standard practice. Alex, I read the Halliburton report more thoroughly and see that the pipe was not reciprocated. I am curious if there were any difficulties moving the pipe or if it just wasn't moved. Thanks, Tom Alex Vaughan Operations Drilling Engineer PIONEER NATURAL RESOURCES 907.343.2186 (office) 907.748.5478 (mobile) 907.343.2190 (fax) From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Wednesday, May 06, 2009 11:36 AM To: Vaughan, Alex Subject: RE: ODSN -37 (208 -157) -- Use this one Alex, I am entering the information from the Halliburton report into my spreadsheet. There is some discrepancy in the sack count and slurry volumes. Your supervisor reports 69.5 bbls lead and 31 bbls tail. In the "Job Report ", Halliburton reports 70 bbls (142 sx) of lead and 31 bbls (142 sx) of tail. In the "Fluid Summary", Halliburton reports 60 bbls (142 sx) of lead and 31 bbls (142 sx) of tail. In the "Job Summary ", Halliburton reports 60.1 bbls (142 sx) of lead and 40 bbls (192 sx) of tail. In the "Job Log ", Halliburton reports 71 bbls of lead and 35 bbls of tail. Could you reconcile the sack counts and slurry volumes pumped? Thanks in advance. Tom Maunder, PE AOGCC 5/6/2009 Page 2 of 14 • • From: Maunder, Thomas E (DOA) Sent: Wednesday, May 06, 2009 11:18 AM To: 'Vaughan, Alex' Subject: RE: ODSN -37 (208 -157) Alex, I read the Halliburton report more thoroughly and see that the pipe was not reciprocated. I am curious if there were any difficulties moving the pipe or if it just wasn't moved. Thanks, Tom From: Maunder, Thomas E (DOA) Sent: Wednesday, May 06, 2009 11:05 AM To: 'Vaughan, Alex' Subject: RE: ODSN -37 (208 -157) Alex, Was the pipe reciprocated? Tom From: Vaughan, Alex [mailto:Alex.Vaughan @pxd.com] Sent: Tuesday, May 05, 2009 1:50 PM To: Maunder, Thomas E (DOA) Subject: RE: ODSN -37 (208 -157) Tom, The following is the operations summary for ODSN -37 on the day of 12/1/2008 Operations Summary Run 7" 26# L -80 BTC -M casing to 7,762'. Break circulation. Ramp up pumps to 6 BPM at 600 psi. No fluid losses. R/D Tesco tools, R/U cement head and lines. Pump 10 bbls water, PT lines to 4,500 psi. Pump 55 bbls 12 ppg dual spacer, followed by 69.5 bbls lead cement, followed by 31 bbls tail cement. Displace cement plug to FC with seawater. Bump plug. Floats held. CIP at 13:50 hrs. PT casing to 3,500 psi for 30 min. R/D cement head, lines, landing jt. Set wellhead packoff. PT to 5,000 psi. PJSM, Run 2 -7/8" Tubing Kill string. Alex Vaughan Operations Drilling Engineer PIONEER NATURAL RESOURCES 907.343.2186 (office) 907.748.5478 (mobile) 907.343.2190 (fax) From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Tuesday, May 05, 2009 9:03 AM To: Vaughan, Alex Subject: RE: ODSN -37 (208 -157) Alex, Thanks for the information. Could you provide your supervisors narrative of the casing and cementing? Tom Maunder, PE 5/6/2009 • • Page 1 of 2 Maunder, Thomas E (DOA) From: Vaughan, Alex [AIex.Vaughan @pxd.com] Sent: Monday, May 04, 2009 5:47 PM To: Maunder, Thomas E (DOA) Subject: RE: ODSN -37 (208 -157) Attachments: ODSN -37 Intermediate Csg CMT.PDF Tom, Please see following answers inserted into your original letter below. If I can be of further assistance please contact me. Alex Vaughan Operations Drilling Engineer PIONEER NATURAL RESOURCES 907.343.2186 (office) 907.748.5478 (mobile) 907.343.2190 (fax) From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Monday, May 04, 2009 4:24 PM To: Campoamor, Kathy Cc: Hall, Joey; Hazzard, Vance; Vaughan, Alex; Johnson, Vern; Franks, James Subject: RE: ODSN -37 (208 -157) Kathy, et al, I am reviewing the sundry you refer to. I will need some additional information regarding the proposed fracture stimulation. 1. Please provide the cementing operations report for the 7" casing. Please see attached ODSN -37 intermediate cement job report 2. Please provide greater detail regarding the proposed fracture stimulation. The detail should include fluid types, planned rates, an estimate of treating pressures and propant information. The proposed fracture stimulation treatment design is based on 620,000 lbs 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 Polymer — 6.25 gpt Surfactant — 2 gpt Crosslinker — 6 gpt Oxidative Breaker — 0.05 ppt 3. Is this well still planned as a development (production) well? Yes, ODSN -37 is production well. 4. Is there any plan to run a cement evaluation log? A cement evaluation log will not be run. All indications are that the cement job went as planned with 100% 5/5/2009 • • Page 2 of 2 returns and expected pressures observed at surface. This information is requested due to increased interest in hydraulic fracturing by the Federal Government. The requested information will all the Commission to do our due diligence with regard to these activities. I look forward to your response. Tom Maunder, PE AOGCC From: Campoamor, Kathy [mailto:Kathy.Campoamor@pxd.com] Sent: Monday, May 04, 2009 3:27 PM To: Maunder, Thomas E (DOA) Cc: Hall, Joey; Hazzard, Vance; Vaughan, Alex; Johnson, Vern; Franks, James Subject: ODSN -37 Hi Tom, An Application For Sundry Approval (10 -403) for ODSN -37 was delivered to the AOGCC on Friday, May 1, 2009. Here is an electronic courtesy copy. The planned date to commence requested operations is May 10, 2009. Regards, 5Cat/iy Campoamor Engineering Tech II Pioneer Natural Resources Alaska Inc. phone 907 - 343 -2183 fax 907 - 343 -2192 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. 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. 5/5/2009 End of Job Report Cementing Services ODS N -37 7 " Intermediate Casing HALLIBURTDN • • .7, Fa Pioneer Natural Resources Company, Alaska Oooguruk Drill Site ODS N -37 Cementing Report End of Job Summary Cementing Services ODSN-37 Summary of Cementing Operations A summary of the cementing operation included within this report. A summary of cementing operations for ODS N -37 are as follows: 1) Cement 7" Intermediate Casing — November 30, 2008 Pioneer Natural Resources Company ODS N -37 • Pioneer Natural Resources Company, Alaska Oooguruk Drill Site ODS N -37 Cementing Report End of Job Report Cementing Services ODSN -37— 7" Intermediate Casing (November 30, 2008) 7" Surface Casing Well Conditions Intermediate Casing Size & Wt.: 7" 26 # /ft Casing Depth: 7,764' Surface Casing Size & Wt.: 9 5/8" 40 # /ft Casing Depth: 3,064' Hole Size: 8 3 /4" Mud: 12.5 ppg WBM Planned Volume Excess: 30% Job Report 7,764' of 7" 26 #/ft casing was successfully cemented inside an 8 3/4" hole from TD to 4,891' in a planned single stage job. The well was conditioned and circulated after casing was run. 12.5 ppg mud was circulated at 6 bpm with circulating pressures noted at 600 psi. 100% returns were indicated throughout circulation of the well. A total of 10 bbls of seawater were pumped and lines were tested to 4,500 psi. The first bottom plug was dropped ahead of 55 bbls of 12.5 ppg Dual Spacer. The second bottom plug was dropped ahead of the cement. 70 bbls (142 sacks) of Premium Cement with 15 # /sk Microlite, 0.75% Halad -344, 0.2% CFR -3, 0.15% EZ -Flo and 0.35% SCR -100 mixed at 12.5 ppg, and 31 bbls (142 sacks) of Premium cement with 0.5% Halad -344, 0.2% CFR -3, 0.25% Super CBL and 0.55% SCR- 100mixed at 15.9 ppg were pumped prior to dropping the top plug. Halliburton cleaned its unit and pumped 10 bbls of seawater behind the plug. The rig pumped displacement. A total of 293 bbls of seawater was pumped prior to landing the plug. Pump pressure was increased to 3,500 psi and held for 30 minutes. Pressure was released and the floats held. Pioneer Natural Resources Company ODS N -37 • • Pioneer Natural Resources Company, Alaska Oooguruk Drill Site ODS N -37 Cementing Report Fluid Summary Fluids Pumped Preflush: 10 bbls Water Spacer: 55 bbls Dual Spacer 12.5 ppg Lead Slurry: 60 bbls (142 sacks) Premium Cement with 15 # /sk Microlite, 0.75% Halad -344, 0.2% CFR -3, 0.15% EZ- Flo and 0.35% SCR -100 mixed at 12.5 ppg yielding 2.4 cuft/sk Tail Slurry: 31 bbls (142 sacks) Premium cement with 0.5% Halad- 344, 0.2% CFR -3, 0.25% Super CBL and 0.55% SCR - 100mixed at 15.9 ppg yielding 1.17 cuft /sk Displacement: 10 bbls Seawater 283 bbls Seawater (Rig) Pioneer Natural Resources Company ODS N -37 • . HALL1BURTON J OB SUMMARY SALES 6335403 JOB DATE 11/30/08 REGION NWA STATE COUNTY North America Alaska Alaska North Slope CEMENTER /EMPLOYEE NUMBER PSL DEPARTMENT Jans 178462 Ed Jans ZI - Cementing LOCATION CUSTOMER COMPANY CUSTOMER REPRESENTATIVE / PHONE North Slope Pioneer Natural Resources Rod Klepzia / Nick Scales CONTRACT # /AFE# (or PO) RIG TYPE API # 16156 Land Drilling 50- 703 - 20586 -00 FIELD DRILLING CONTRACTOR JOB PURPOSE Kuparuk Nabors JP015 Cement Intermediate Casing DS or PAD Well No. RIG # WELL TYPE ODS N -37 IN -37 19 AC 01 Development HES EMP NAME / EMP #/ (EXPOSURE HOURS) HRS HRS H E S UNIT #S MILES MILES Jans 178462 1 120 Hall 348338 1 72 McClellan 401851 i 264 • Brady 276301 i 192 Miller 121632 . 168 . Tools and Accessories Well , DIM Type and Size QTY SIZE FROM TO WT SIZE FROM TO Float Collar 1 7 7677.3 7676.3 Casing 26 7 7764 Float Shoe 1 7 7764 7762.4 Liner SVR Centralizers 57 7 Liner Bow Centralizers Tubing Turbulators Drill Pipe Stop Rings 57 Open Hole Stage Tool Perforations Top g / //% /,: / / / /i ///, Perforations To Plug 1 7 /�� / �� f;� � Bottom Plug 2 7 � /, 2W ,,j, %/, Perforations Job Time Called Out Depart HES On Location Job Started Job Completed Leave Location Arrive HES Date 11/30/2008 11/30/2008 11/30/2008 Time 5:15 11:00 14:30 Stage Data Event Sacks Bbls Rate Pressure Additives Yield Lbs /Gal Spacer 62 55 4 1100 Dual Spacer Blend ,DSMA,D- 3000L,Barite,Stabilizer 4346 12.5 Tail Cmt 142 60.1 4 1100 MicroLite @ 15#Isk, 0.75 %Halad -344 ,0.2 %CFR -3, 0.15 %EZ -Flo, 2.40 12.5 0.35% SCR -100 Tail Cmt 192 40 3.5 1000 0.5% Halad -344, 0.2% CFR -3, 0.25% Super CBL, 0.55% SCR -100 1.17 15.8 Job Summa Circ. Prior to Cmtg: 3 Hrs BBLS Bottoms up Volume: BBI Mud Type: WBM % Returns during Conditioning 100 % Circulation Pump Rate: 6 BPM Mud Density: 12.5 Circulation pump pressure: PSI Pipe reciprocated y /n: Conditioning No Cementing No % Returns during Cementing 100 % Plugs used: Top Yes Bottom Yes Pump Rate: Circ. 4 BPM Cementing 4 BPM Displacement 3.5 BPM Cement Circ. Back to Surface No y/n How Much? BBLS Displacement Fluid Type Seawater Calc. Disp Vol: 293 BBLS Was the Plug Bumped? Yes y/n Actual Disp Volume pumped 293.2 BBLS Comments Rev 5 -13 -08 PNR Ver 1.3 • • TICKET # TICKET DATE HALLIBURTON JOB LOG 6335403 11/30/08 REGION NWA /COUNTRY BDA /STATE COUNTY North America Alaska Alaska North Slope H.E.S EMPLOYEE NAME PSL DEPARTMENT Jans 178462 Ed Jans ZI - Cementing LOCATION COMPANY CUSTOMER REP / PHONE North Slope Pioneer Natural Resources Rod Klepziq / Nick Scales WELL TYPE API# 16156 Land Drilling 50- 703 - 20586 -00 WELL LOCATION DRILLING CONTRACTOR JOB PURPOSE CODE Kuparuk Nabors JP015 Cement Intermediate Casing LEASE NAME Well NO. RIG # WELL TYPE ODS I N -37 19 AC 01 Development Time Volume Rate (BPM) Press (PSI) Job Description t Remarks {88LS)- (*VG) (MAX) (AVG) (MAX) 10:15 PJSM with rig crew 11:10 10 4.00 4.5 800 1100 Pumped first plug with 10 BBL of sea water 11:16 4500 4800 Pressure test lines 11:53 Bleed off pressure 11:54 55 4.00 4.5 800 1100 Started to pump 55 BBL of spacer 12:09 55 4.00 4.5 800 1100 Finished pumping spacer 12:10 Dropped 2nd bottom plug 12:15 71 4.00 4.5 800 1100 Started to pump lead cement 12:34 35 3.50 4.0 1000 1300 Started to pump tail cement 12:42 Finished pumping tail cement 12:42 Dropped top plug 12:45 10 3.50 4.0 800 1000 Started to pump 10 sea water behind 12:49 Turned displacement over to rig 12:53 End job on uni pro 12:54 286.20 6.00 2200 Rig displacement 13:39 3.00 1500 Slowed displacement 13:41 2.00 1380 Slowed displacement 13:49 1500 Bumped Plug 13:55 3500 Test casing 14:30 Bleed off & check floats Pionner Oooguruk ODS N -37 Intermediate Casing 11 -30 -08 Pump Pressure (psi) A Rate (bpm) B A B Density (lb /gal) C Pump Total (bbl) I) C D 5000- 8 - -18 -70 7 \ \ . r",,,,,,,,‘, -16 60 4000- - 14 - 6- PI -50 i -12 3000 _ - -40 w• r ir" -8 -30 2000- t -6 - r -20 2 — — - -4 - • 1000- _ I -- L — - 1 A 6 1 f 1 — _ I 2 10 0 0 11:20 11:40 12:00 12:20 12:40 11/30/2008 11/30/2008 Time Customer: PIONEER NATURAL RESOURCES Job Date: 30- Nov -2008 Sales Order #: 6335403 HALLIBURTON OptiCem v6.4.0 Well Description: ODS N -37 UWI: 50- 703 - 20586 -00 03- Dec -08 15:13 • • { SARAH PALIN, 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 James Franks Senior Drilling Engineer Pioneer Natural Resources Alaska Inc. 700 G Street, Suite 600 Anchorage, AK 99501 Re: Oooguruk Field, Oooguruk - Nuiqsut Oil Pool, ODSN -37 Sundry Number: 308 -381 Dear Mr. Franks: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, r Daniel T. Seamount, Jr. Chair DATED this of October, 2008 Encl. 06,vb STATE OF ALASKA • RECEIVED f a ALASITOIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS OCT 2 2 2008 20 AAC 25.280 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown ❑ Perforate ❑ Ai 1�� S Cons C�th 1 s Dr! Alter casing el Repair well ❑ Plug Perforations ❑ Stimulate ❑ Time Extension ®►CN c.S ckct Change approved program 0 Pull Tubing ❑ Perforate New Pool ❑ Re -enter Suspended Well ❑ (r 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Pioneer Natural Resources Alaska Inc. Development isi Exploratory ❑ 208 -157 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: & 700 G Street, Suite 600 Anchorage, AK 99501 50- 703 - 20586 -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: ODSN -37 Spacing Exception Required? Yes ❑ No 0 9. Property Designation: 10. KB Elevation (ft): 11. Field / Pool(s): ADL 355036 57.5' MSL Ooogurk - Nuiqsut Oil Pool 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): Casing Length Size MD TVD Burst Collapse - Structural Conductor Surface Intermediate Expandable Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type: Packers and SSSV MD (ft): 13. Attachments: Description Summary of Proposal El 14. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory ❑ Development El Service ❑ 15. Estimated Date for 16. Well Status after proposed work: 10/27/2008 Commencing Operations: Oil el Gas ❑ Plugged ❑ Abandoned ❑ 17. Verbal Approval: Date: WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Alex Vaughan, 343 -2186 Printed Name James Franks Title Senior Drilling Engineer Signature Phone Date 343 -2179 10/21/2008 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: X4 ,8._ - -/ . Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: 1 i i �OCJh�� - F �� Subsequent Form Required: \-10, (c, ,r--k- .∎ S avv 3.1(4` t V..140 \ �L ∎��YJ APPROVED BY � ( �� Approved by: ter' 1 ip !� ( f QN THE COMMISSION i Ez-) i Date: G i .a IF WL� e .LQIJR Form 10 -403 Revised 06/2006 Submit in Duplicate • • PIONEER NATURAL RESOURCES ALASKA October 21, 2008 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7 Avenue, Suite #100 Anchorage, AK 99501 RE: ODSN -37 (PTD: 208 -157) Move of 9 -5/8" Surface Casing setting depth from 5000' MD/ 4653' TVD to 3128' MD/ 3000' TVD Surface Location: 2937' FSL, 1129' FEL, Sec 11, T13N, R7E, UM X = 469869.00, Y = 6031053.00 ASP4 Pioneer Natural Resources Alaska is submitting a change of surface casing setting point proposal for AOGCC's review and approval for the ODSN -37 well. Pioneer was planning to drill surface hole to 5000' MD/ 4653' TVD and suspend this well after freeze protecting to 2000' Pioneer's intent is to move the 9 -5/8" 40# L -80 BTC surface casing point to 3128' MD / 3000' TVD. The remainder of the temporary suspension will be in accordance to the approved Permit to Drill (208 -157). The original surface setting depth of 5000' MD was due to the following reasons. • We extended the surface setting depth for ODSN -45i due the extended reach well path. Thus allowing us to use friction reducing tools while running intermediate casing through the surface casing (ex: Caledus Ezee Glider Centralizers). • Additionally, due to limited supply of 8 -5/8" expandable casing we wanted to hedge our bets if required to use it, ensuring that we had enough expandable casing length available. These measures are not required for ODSN -37. Therefore, the surface setting depth for ODSN- 37 will be moved to 3128'MD / 3000'TVD. Alaska Oil & Gas Conservation Commission October 21, 2008 Page 2of2 Please find attached information for your review: 1) Form 10 -403 Application for Sundry. 2) Documentation on current rig activity and forward plan. 3) The original permitted wellbore schematic 4) A revised as planned wellbore schematic showing new surface casing setting depth 5) A wellbore schematic showing final completion 6) Surface cement program The following are PNRA's designated contacts for reporting responsibilities to the Commission: 1) Completion Report James Franks, Senior Drilling Engineer (20 AAC 25.070) (907) 343 -2179 lames.franks(a�pxd.com 2) Geologic Data and Logs Doug Waters, Operations Geologist (20 AAC 25.071) (907) 343 -2133 douq.waters a(�pxd.com Sincerely, 4i/1 7 James Franks Senior Drilling Engineer Attachments: Form 10 -403 Supporting information cc: ODSN -37 Well File • PIONEER • A RESOURCES ALASKA Pioneer Natural Resources Well Plan ODSN -37 Move 9 -5/8" Surface Casing Depth to 3128' MD/ 3000' TVD Currently, ODSN -37 has not spudded Riq Activity: Drill 12 -1/4" surface hole to casing setting depth of 3128' MD, 3000' TVD. Set and cement 9 -5/8" casing. 1. MIRU Nabors 19AC over pre - installed 16" conductor casing. 2. NU Spacer Spool and Riser 3. MU 12 -1/4" Directional Drilling, MWD /LWD assembly. Drill surface hole to the casing point at 3128' MD / 3000' TVDrkb, making wiper trips as necessary. Circulate and condition the hole to run casing. POOH. 4. Run and cement the 9 -5/8 ", 40# surface casing - a Port Collar may be run based on hole conditions at Company Rep discretion. Displace the cement with seawater. 5. Ensure floats are holding. WOC if needed. 6. ND Spacer Spool and Riser; NU Wellhead 7. RIH with enough 2 -7/8" tubing to allow for the circulation of diesel freeze protection fluid to -2000' TVDrkb. 8. Land the tubing and RILDS. 9. NU Tree and test. 10. Rig up reverse circulating manifold and reverse circulate diesel to freeze protect the well to -2000' TVD and allow to u -tube. 11. Temporarily suspend the well. RDMO to drill next well Riq Activity: Plan forward The 9 -5/8" intermediate hole section will be temporally suspended. We will come back to drill this section at a later date. Note: With the conductors on 7' centers, the well will be temporarily suspended due to the need to batch drill the surface casing strings. Batch drilling of the surface casing strings will aid in avoiding a wellbore collision along with reducing the hazards associated with a wellbore collision, should one occur. ODSN -37 PI — Action Well Original Gtmpletion Well Head: 9 -5/8 ", 5K, VetcoGray Tree: 3 -1/2 ", 5K, Horizontal 16" Conductor 153' MDrkb / 153' TVDrkb 2 -7/8" 6.5# L -80 IBT -M, 2000' TVDrkb ► , 1111111 Diesel to —2000' TVDrkb Seawater from —2000' TVDrkb 9 -5/8 ", 40# L -80 BTC, 8.835" ID 5000' MDrkb / 4653' TVDrkb Date: Revision By: Comments \ \\ 9/30/2008 Alex Vaughan Orginal Com ODSN -37 Producer .,- Welt Schematic IONEER TURAL RESOURCES ODSN -37 Procction Well Proposed Impletion Well Head: 9 -5/8 ", 5K, VetcoGray Tree: 3 -1/2 ", 5K, Horizontal 16" Conductor A 153' MDrkb / 153' TVDrkb 2 -7/8" 6.5# L -80 IBT -M, 2000' TVDrkb ► Diesel to —2000' TVDrkb I Seawater from —2000' TVDrkb 9 -5/8 ", 40# L -80 BTC, 8.835" ID 3128' MDrkb / 3000' TVDrkb Date: Revision By: Comments 9/30/2008 Alex Vaughan Original Completion 10/20/2008 Alex Vaughan Move surface casing to 3000' TVD ODSN -37 Producer Well Schematic IONEER TURAL RESOURCES ODSN -37 PrAuction Well Proposecompletion Well Head: 9 -5/8 ", 5K, VetcoGray Tree: 2 -7/8 ", 5K, Horizontal Vent Valves Control Line 16" Conductor A ■ 158' MDrkb / 158' TVDrkb 2 -7/8 ", 6.5# L -80 IBT -M 2 -7/8" ScSSSV, 2.313" ID @ —750' 2 -7/8" GLM @ 3475' MDrkb / 3330' TVDrkb 9 -5/8 ", 40# L -80 BTC, 8.835" ID 3128' MDrkb / 3000" TVDrkb i X Nipple, 2.313" ID @ 4365' MD • ow ,411 7" x 2 -7/8" Packer @-4385' MDrkb / —4100' TVDrkb • X Nipple, 2.313" ID w RHC -M Profile @ 4405' MD 8 '/2" Un- cemented hole 2 -7/8" GLM @ 5994' MDrkb / 5510' TVDrkb • ESP Cable O O 0 li 2 -7/8" Durasleeve Sliding Sleeve, 2.313" ID @ 7458' MDrkb ■ XN Nipple, 2.205" ID Nogo @ 7498' MDrkb r ESP @ 7508' MDrkb Estimated Top of Cement @ 6708' MD I 7" Weatherford Liner Top Packer and Tieback A.. 7608' MDrkb 4 -1/2" 12.6# L -80 IBT -M Un- cemented Solid Liner 7 ", 26# L -80 BTC -M, 6.276" ID w/ Pre - Perforated Subs every 400' 7708' MDrkb / 6315' TVDrkb p 8 00 000 000 8 000 000 000 15708' MDrkb / 6374' TVDrkb Date: Revision By: Comments ,,7-4) 10/10/2008 Alex Vaughan Proposed Completion ti ODSN -37 Producer Well Schematic PIONEER NATURAL RESOURCES_ • • (41.: 141.)- Pioneer Natural Resources Company, Alaska Oooguruk Drill Site ODSN -37 Cementing Program ODSN -37 Surface Casing Well Conditions Casing Size & Wt. 9 -5/8" 40 #/ft L -80 BTC Volume Excess 100% Permafrost /30% Hole Size 12 -1/4" Mud Wt. 9.5 ppg MD 3,128' Mud PV /yP 16/24 TVD 3,000' BHST 60 ° F Prey. Csg: 16" 65 #/ft BHCT 55 ° F Previous Casing Depth: 120' Frac Gradient: 14 ppg @ 3,000' TVD Permafrost Depth: 1,681' MD & 1,662' TVD Slurry Recommendation (mixed with seawater): Preflush / Spacer 10 bbl Water, 40 bbl 10.0 ppg Dual Spacer Lead Slurry: 259.1 bbl — 351 sks. PERMAFROST L Tail Slurry: 42.7 bbl - 201 Sks. Premium Cement, 2% Calcium Chloride, + .2% CFR -3 Displacement: 230.7 bbls. Mud Spacer Lead Slurry Tail Slurry Surface/Downhole Density (ppg) 8.34 / 10.0 10.65 / 10.92 15.9 Yield (cu ft / sk) 4.25 / 4.15 1.19 Sea Water requirements (gal/sk) 20.0 5.23 Thickening Time Hr: min. 6:00+ 3:00 — 4:00 Compressive Strength - PSI 12 hr (est.) (48 Hr.) 25 1,000 24 hr (est.) (72Hr.) 150 1,800 Volumes based on: Lead Slurry: Top of Lead cement @ Surface — BOC @ 2,628' MD 120 of 16" 65 #/ft conductor cased hole @ 0% excess plus 1,561' of open hole in permafrost plus 100% excess plus 947' open hole below permafrost plus 30% excess. Tail Slurry: Top of Tail slurry — 2,628' MD 500'calculated annulus volume +30% excess + 85' shoe joint. ISO 14001 Certified HALL1BURTON Alaska Green Star Certified • • Page 1 of 3 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Thursday, October 16, 2008 3:04 PM To: 'Vaughan, Alex' Cc: Hazzard, Vance; Polya, Joe; Franks, James; Campoamor, Kathy Subject: RE: Current Oooguruk Well Status as of 10/16/2008 Alex, et al, Thanks much for the updated information. Looking at the information and cross checking our files, I only found one well that may need some paperwork filed; ODSN -39. If no activity is likely on this well until springtime, it is appropriate for Pioneer to file a 404 with attachments for the operational SD as was done with K -35, K -36 and N- 34. Thanks in advance. Call or message with any questions. Tom Maunder, PE AOGCC From: Vaughan, Alex [mailto:Alex.Vaughan @pxd.com] Sent: Thursday, October 16, 2008 2:09 PM To: Maunder, Thomas E (DOA) Cc: Hazzard, Vance; Polya, Joe; Franks, James; Campoamor, Kathy Subject: Current Oooguruk Well Status as of 10/16/2008 Tom, Well Name PTD Completion Date- Comment Status ODSDW 01-44 207 -140 1/27/2008 Active Disposal Well ODSK -35 207 -181 2/12/2008 Surface Casing Set ODSK -36i 207 -182 2/4/2008 Surface Casing Set ODSK -33 207 -183 4/29/2008 Active Kuparuk Producer ODSN -34i 207 -184 2/17/2008 Surface Casing Set ODSN -31 208 -003 n/a Not Spudded ODSN -32 208 -004 n/a Not Spudded ODSN -40 208 -039 8/1/2008 Active Nuiqsut Producer ODSN -39i 208 -040 5/7/2008 Surface Casing Set ODSN -45i 208 -100 10/15/2008 Intermediate Casing Set, temporarily abandoned, likely to be side tracked ODSN -43 208 -139 n/a Not Spudded ODSK -41 208 -147 n/a Not Spudded, Spud 10/16/2008 ODSK -38 208 -148 n/a Not Spudded ODSN -37 n/a Not Spudded �O�s \ The following is the current schedule as of 10/16/2008. We will be submitting the ODSN -37 Surface Casing Depth Change Sundry middle of next week. Drill Start Drill End Date Days Date 10/20/2008 Page 2of3 • �� �� �� ODSN45i - |N13 ' S - AOGCC approved ' 13/2/2008 ' 74.0 1 1045,209a- � ODSK-41 -�{up F(Ho�z)-S �10/1 6.4 CJOSK-381 - Kup (Slant) - S 5.8 ii ODSN-37- PN8 - S 2 5.7 11/2/2008 ODSK-38i -Kup D(S|mnt)'P.0 11/2/2008 15.1 11/17/2008 ODSN-37-PN8 '| | 11/17/2008 13.0 11/30/2008 ODSK-41 -KupF(Hmriz)-|,P.0 ' 11/30V2008 32.9 1/2/2009 Alex Vaughan Operations Drillin Engineer PIONEER u�~� 0�� �� �� �� 8 ~ 0 q�'� U�� �� �� �� NATURAL RESOURCES 907.343.2186 (office) 907.748.5478 (mobile) 907.343.2190 (fax) From: Polya, Joe Sent: Wednesday October 15, 2008 4:38 PM To: Vaughan, Alex Subject: FW: Current Oooguruk Well Status - Again Alex, Please review the attached and lets make ourselves a duplicate spreadsheet whereby we can track and ensure that we have all the applicable permits submitted and approved for our various wells in their array of stages toward completion. ,'-_~'~'~~~ 9" P Pioneer Natural Resources Alaska, Inc. Sr. Staff Drilling Engineer ] � oe.pu_-, zn lY�»x� in Main Office: (907) 277-2700 Direct: (907) 343-2111 Fax: (907) 343-2192 Mobile: (907) 244-0668 . ���� From: Maunder, Thomas E(DOA) [maUto:tonn.nnnunder©akaska.gnv] Sent: Tuesday, October 14, 2008 10:01 AM To: Maunder, Thomas E (DOA); Polya, Joe Subject: RE: Current Oooguruk Well Status - Again Joe, | know you have been busy with ODSN-45. but | would appreciate if you or one of your staff could fi||out the table below. Thanks in advance Tom Maunder, PE AOGCC 10/20/2008 • • Page 3 of 3 From: Maunder, Thomas E (DOA) Sent: Friday, October 03, 2008 12:00 PM To: Polya, Joe Subject: Current Oooguruk Well Status Joe, As you know, I am reviewing the permit applications for ODSK -41 and -38. In the course of that review, I have prepared a list of the permits issued to date for the Oooguruk project. I realize that Pioneer has encountered drilling difficulties that have resulted in halting operations on some of the wells. Also, halting operations was planned due to the seasonal drilling restriction for some of the Kuparuk wells. Would you or one of the engineers complete the following table for the ODS wells? I have included the information I have available. It is possible that I have not seen all the paperwork that has been filed. I am particularly interested in wells that have been spudded and then operations halted. I expect that we will exchange a few messages to get things all filled out. Call or message with any questions. Tom Maunder, PE AOGCC Well Name PTD Completion Date- Comment Status ODSDW 01 -44 207 -140 1/27/08 WDSP1 ODSK -35 207 -181 ODSK -36 207 -182 ODSK -33 207 -183 4/29/08 1 -oil Initial production well. ODSN -34 207 -184 ODSN -31 208 -003 ODSN -32 208 -004 ODSN -40 208 -039 8/1/08 1-oil ODSN -39 208 -040 ODSN -45 208 -100 ODSN -43 208 -139 ODSK -41 208 -147 Permit under review ODSK -38 208 -148 Permit under review 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. 10/20/2008 III !� • SARAH PALIN, GOVERNOR ALASKA OIL AND GAS 333 W 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 Joe Polya FAX (907) 276 -7542 Senior Staff Drilling Engineer Pioneer Natural Resources Alaska Inc. 700 G Street, Suite 600 Anchorage, AK 99501 Re: Oooguruk Field, Oooguruk - Nuiqsut Oil Pool, ODSN -37 Pioneer Natural Resources Alaska Inc. Permit No: 208 -157 Surface Location: 2937' FSL, 1129' FEL, Sec. 11, T13N, R7E, UM Bottomhole Location: 3812' FSL, 1495' FEL, Sec 3, T13N, UM Dear Mr. Polya: Enclosed is the approved application for permit to 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 permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). Sincerely, /&/$ Daniel T. Seamount, Jr. Chair DATED this 2 of October, 2008 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALAS.IL AND GAS CONSERVATION COMMIS PERMIT TO DRILL 20 AAC 25.005 poi � la. Type of Work: 1b. Current Well Class: Exploratory ❑ Development Oil , 0 lc. Specify if well is proposed for: Drill Ei . Redrill ❑ Stratigraphic Test ❑ Service ❑ Development Gas ❑ Coalbed Methane ❑ Gas Hydrates ❑ Re -entry ❑ Multiple Zone ❑ Single Zone ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket El Single Well ❑ 11. Well Name and Number: Pioneer Natural Resources Alaska Inc Bond No. 103655283 ' ODSN - ' 3. Address: 6. Proposed Depth: 12. Field /Pool(s): 700 G Street, Suite 600 Anchorage, AK 99501 MD: 15708 - TVD: 6374' 4a. Location of Well (Governmental Section): 7. Property Designation: Oooguruk - Nuiqsut Oil Pool • Surface: 2937' FSL, 1129' FEL, Sec. 11, T13N, R7E, UM - ADL 355036 • Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 2844' FSL, 1805' FEL, Sec. 11, T13N, R7E, UM 417497 10/20/2008 Total Depth: 9. Acres in Property: 14. Distance to Nearest 3812' FSL, 1495' FEL, Sec. 3, T13N, R7E, UM 5760 Property: 1467' 1 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation S4,. i • "..5‘. 15. Distance to Nearest Well /r Surface: x- 469869.00 - y- 6031053.00. Zone- ASP 4 (Height above GL): 44 feet 0•1 ith ly{e• 16. Deviated wells: N/A Kickoff depth: 400' feet 17. Maximum Anticipated Pressures in psig (see 20 AA 25.035) Maximum Hole Angle: 90.74 degrees Downhole: 3248 psig • Surface: 2547 psig . .46.- T.c^s$ 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) 24" 16" 109# H -40 \., Welded 109' Surface Surface 153' 153' Driven 12 -1/4" 9 -5/8" 40# L -80 BTC 5000' Surface Surface • . . v 349 sx Permafrost 'L'; 790 sx Class 'G 8 -3/4" 7" 26# L -80 BTC -M 7708' Surface Surface 7708' . 6315' • 139 sx Class 'G' 6 -1/8" 4 -1/2" 12.6# L -80 IBT -M 8100' 7608' 6287' 15708' • 6374' • Uncemented * - Sal S' \ 2 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) 4(71- Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor /Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 1 20. Attachments: Filing Fee ❑ BOP Sketch El Drilling Program 0 Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Property Plat 0 Diverter Sketch 0 Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements ❑ 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Alex Vaughan, 343 -2186 Prepared By: Kathy Campoamor, 343 - 2183 Printed Name Joe Polya Title Sr. Staff Drilling Engineer Signature -A � Phone 343 -2111 Date 10/2/2008 ` Commission Use Only Permit to Drill / '7 API Number: Permit Approval See cover letter for other Number: �8'! S / 50- '� " 4p "6 b Date: I 0 - - - �i� 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:a . Other: -t `0 S C :2 c, �� 4S `_ K� Samples req'd: Yes❑ Not Mud log req'd: Yes❑ NoRr -✓ � H measures: Vest] No[✓' Directional svy req'd: Yesg' No❑ t� cc-Q 4sic\ -- \©, \-- ri \ \ c \Di LI is - sv\0 \ - X0`3 -C7. r Os /6/2 _ 2 APPROVED BY THE COMMISSION DATE: , COMMISSIONER Form 10 -401 Revised 12/2005 Submit in Duplic a p,7,41:e 1 PIONEER NATURAL RESOURCES October 2, 2008 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7 Avenue, Suite #100 Anchorage, AK 99501 RE: Application for Permit to Drill ODSN -37 Surface Location: 2937' FSL, 1129' FEL, Sec 11, T13N, R7E, UM X = 469869.00, Y = 6031053.00, ASP4 Pioneer Natural Resources Alaska, Inc. (PNRA) hereby applies for a Permit to Drill a production well from the Oooguruk Drill Site (ODS) located within the Oooguruk Unit. The well is designed to be a producer well in the Oooguruk - Nuiqsufformation. PNRA requests the permit to drill based on approved Pool Rules. As indicated in the attachments, the drilling program will entail drilling a directional 12 -1/4" surface hole to approximately 5000' MD / 4653' TVDrkb, where surface casing will be set. A 8- 3/4" directional wellbore will be drilled into and set in the Oooguruk- Kuparuk interval at approximately 7708' MD / 6315' TVDrkb. The horizontal production interval will be drilled to 15,708' MD / 6,374' TVDrkb, the final TD of the well. The proposed casing program will utilize 9%" surface casing, 7" intermediate casing and 4 1 /2" un- cemented liner production casing. The completion will utilize 3 1 /2" to 2 7/8" tubing and an ESP. PNRA plans to implement Managed Pressure Drilling technology (MPD) while drilling the production hole of ODSN -43. At present, PNRA does not intend on drilling with a mud weight lower than the pore pressure of the exposed formations. PNRA plans to use this technique while drilling the intermediate interval as outlined below. • From the Surface Shoe to below the Base of the Torok Sands o Use -9.2 to 10 ppg fluid while using MPD to control pressure from the surface to -10.5 ppg EMW at the bottom of the hole. 600 G STREET, SUITE 600 - ANCHORAGE, ALASKA 99501 - MAIN 907 - 277 -2700 - FAX 907 - 343 -2190 Alaska Oil & Gas Conserva•Commission 0 ODSN -37 October 2, 2008 Page 2 of 4 • Open formations: • Torok Sands, -8.7 ppg Pore Pressure • • From the base of the Torok Sands to Intermediate Hole TD o Use -10.0 to 11.0 ppg fluid while using MPD to control pressure from the surface to -12.5 ppg EMW at the bottom of the hole. • Open formations: • Torok Sands, -8.7 ppg Pore Pressure • Kuparuk Sands, -9.8 ppg Pore Pressure • PNRA plans to use this technique while drilling the production interval as outlined below. • From the Intermediate Shoe to TD o Use -9.8 ppg fluid while using MPD to control pressure from the surface to -10.1 • ppg EMW at the bottom of the hole during connections and while tripping The following documents are attached to this letter and Permit to Drill request: • Flowchart of the MPD system • Procedure of how to change the element in the `rotating head' to maintain well control • Decision Tree for handling a well control event • Data illustrating operational experience from the service provider, Halliburton Utilizing the MPD process allows PNRA to reduce the materials needed for the well and increase the overall safety of the personnel on the development by having less material to handle. Unlike other wells in the Oooguruk Development, it is planned to drill and complete this well in , entirety. In the future, PNRA may provide information requesting the permitting of annular disposal of drilling wastes on this well. Based on information previously submitted to the AOGCC and included in the AOGCC Oooguruk Field File, PNRA requests an exemption from 20 AAC 25.035 (c) which requires a ----- diverter system be installed on the well while drilling the surface interval. 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: Alaska Oil & Gas Conserva•Commission ODSN -37 October 2, 2008 Page 3 of 4 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. 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 — including traveling cylinder and development layout plots 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. 7) MPD information as referred to above • Flowchart of the MPD system • Procedure of how to change the element in the `rotating head' to maintain well control • Decision Tree for handling a well control event • Data illustrating operational experience from the service provider, Halliburton The following are PNRA's designated contacts for reporting responsibilities to the Commission: Alaska Oil & Gas Conserva•Commission 40 ODSN -37 October 2, 2008 Page 4of4 1) Completion Report Joe Polya, Senior Staff Drilling Engineer (20 AAC 25.070) 907/343 -2111 ioe.polya(a�pxd.com 2) Geologic Data and Logs Doug Waters, Operations Geologist (20 AAC 25.071) 907/343 -2133 douq.waters(a�pxd.com The anticipated spud date for this well is October 20, 2008. If you have any questions or require further information, please contact Joe Polya at 907/343 -2111. Sincerely, J.e Polya Senior Staff Drilling Engineer Attachments: Form 10 -401 Supporting permit information cc: ODSN -37 Well File • • Oooguruk Well Plan Summary: Permit to Drill ODSN -37 — Nuiqsut Production Well Surface Location: 2937' FSL, 1129' FEL, Sec 11, T13N, R7E, UM ASP 4 (NAD27) projection X = 469869.00 1 Y = 6031053.00 Target: 2844' FSL, 1805' FEL, Sec 11, T13N, R7E, UM X = 469192.80 Y = 6030962.60 1 6315'TVDrkb Bottom Hole Location: 3812' FSL, 1495' FEL, Sec 3, T13N, R7E, UM X = 464,243.73 1 Y = 6,037,232.57 6,374 TVDrkb AFE Number: TBD Est. Start Date: October 20, 2008 Rig: Nabors 19AC Operating days: 6 days (surface only) 39 days (intermediate, production, completion) TD: 15,708 MD / 6,374 TVDrkb Objective: Nuigsut 1 Well Type (exp, dev, etc): Development Well Design (conventional, slimhole, etc): Ultra -slim hole — Producer Current Mechanical Condition: Well Bay Footing / ODS Ground Level: Elevation above MSL: 13.5' RKB to Ground Level: 44' Rig Elevation: RKB + MSL = 56.16' Conductor: 153' MDrkb Well Control: Based on calculations below, BOP equipment will be tested to 3,500 psi. Surface Section: • Maximum anticipated BHP: 2081 psi CP 4653' TVDss (Based on seawater gradient of 0.4472 psi /ft) • Maximum surface pressure: 1569 psi @ surface (Based on BHP and a full column of gas from TD C 0.11 psi /ft) Intermediate Section: • Maximum anticipated BHP: 3218 psi © 6315' TVDss • Maximum surface pressure: 2523 psi © surface (Based on BHP and a full column of gas from TD © 0.11 psi /ft) Production Hole Section: • Maximum anticipated BHP: '3248 psi © 6374' TVDss • Maximum surface pressure: • 2547 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: 10.2 ppg Brine /6.8 ppg Diesel Diverter (see attached schematic): Pioneer Natural Resources Last Revised: October 2, 2008 ODSN -37 Permit To Drill Page 1 of 9 Hydril 21 -1/4" 2M annular BOP 1 16" full opening knife gate valve, hydraulically actuated 16" diverter line 5000 psi BOP stack (see attached schematic): Hydril GK 11" 5M annular BOP Hydril 11" 5M single ram BOP w/ studded connections Hydril 11" 5M single ram BOP w/ studded connections Drilling cross 11" 5M x 11" 5M with 2 ea. 3 -1/8" 5M side outlets w /flanged connections 2 ea. 3 -1/8" 5M full opening inner manual gate valves mounted on drilling cross 2 ea. 3 -1/8" 5M full opening outer remote hydraulic controlled gate valves mounted on inner gate valves. Hydril 11" 5M single ram BOP w/ studded connections Formation Integrity Testing Requirements: Test Point Depth Test Type Minimum EMW 9 -5/8" Surface Shoe Rathole + 20' to 50' from 9 -5/8" shoe LOT 12.0 ppg 7" Intermediate Shoe Rathole + 20' to 50' from 7" shoe FIT 13.5 ppg Drilling Fluids Program: Surface Hole Mud Properties: 12 -1/4" hole Spud Mud Interval Density (ppg) Viscosity (secs) YP PV 10 sec gel API FL Initial 8.8 150 -200 35 - 50 15 -25 10 - 15 unrestricted Final 9.2 -9.6 70 -100 25 - 35 15 - 25 10 - 15 <12 Intermediate Hole Mud Properties: 8 -3/4" hole LSND Interval Density (ppg) Viscosity (secs) YP PV MBT API FL Initial to 9.2 -10.0 (-10.5 ppg 40 -60 15 -25 15 -20 < 6 -8 Below HRZ via MPD) From 10.5 ( -12.5 ppg via 40 - 60 15 - 25 20 - 30 < 15 3 - 5 (8 -10 Below HRZ MPD) HTHP) to TD Production Hole Mud Properties: 6 -1/8" hole LSND Interval Density (ppg) Viscosity (secs) YP PV MBT API FL Initial 10.5 ( -12.5 ppg via . 40 - 60 15 - 25 20 - 30 < 15 3 - 5 (8 -10 MPD) HTHP) 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. Pioneer Natural Resources Last Revised: October 2, 2008 ODSN -37 Permit To Drill Page 2 of 9 • Hydraulics: Surface Hole: 12 -1/4" Interval Pump Drill Pipe AV Pump ECD ppg- Motor Jet Nozzles TFA (in GPM (fpm) PSI emw ( "/32) Surf to BPRF 550 4" 15.7# 90 1800 10.0 N/A 18,18,18,16 .942 BPRF to TD 650 4" 15.7# 110 2400 10.2 N/A 18,18,18,16 .942 Intermediate Hole: 8 -3/4" Interval Pump Drill Pipe AV Pump ECD ppg- Motor Jet Nozzles TFA (in GPM (fpm) PSI emw ( "/32) Surf Shoe to TD 550 4" 15.7# 215 3500 11.0 N/A 5x16 0.982 Production Hole: 6 -1/8" Interval Pump Drill Pipe AV Pump ECD ppg- Motor Jet Nozzles TFA (in GPM (fpm) PSI emw ( "/32) Int Shoe to TD 275 4" 15.7# 275 2800 11.57 N/A 3x14 0.451 Formation Markers: TVD Pore Press. EMW Formation Tops MD (rkb) (psi) (ppg) Comments Base of Permafrost 1663 Top West Sak 2338 2283 1027 8.65 Base of fluvial sands Hue Shales 2987 2875 Tuffaceous Shales 3088 2964 Brook 2B 4567 4271 Top Torok Sand 5467 5070 2267 8.6 Top of Disposal Zone Base Torok Sand 5747 5315 Base of Disposal Zone Top HRZ 6340 5775 2597 8.65 Base HRZ 6525 5893 Kalubik Marker 6699 5990 Top Kuparuk C 6809 6044 3080 9.8 • Top of Miluveach 6905 6085 Top Nuiqsut 7693 6311 TD 15708 6375 Pioneer Natural Resources Last Revised: October 2, 2008 ODSN -37 Permit To Drill Page 3 of 9 • 1 Logging Program: 12 -1/4" Section: Drilling: Mud logging Dir / GR Open Hole: N/A Cased Hole: N/A 8 -3/4" Section: Drilling: Mud logging Dir / GR / Res / Dens / Neut Open Hole: N/A Cased Hole: N/A 6 -1/8" Section: Drilling: Mud logging Dir / GR / Res / Dens (Azm) / Neut Open Hole: N/A Cased Hole: N/A Casing Program: Hole Casing / Weight Grade Conn. Casing Csg/Tbg Top Hole Btm Size Tubing Length MDrkb/TVDrkb MDrkb/TVDrkb 24" 16" 109# H -40 Welded 109' Surface 153' / 153' 12 - 9 -5/8" 40# L -80 BTC 5000' Surface 5000' / 4653' 8 - 7" 26# L -80 BTC -M 7708' Surface 7708' / 6315' 6 -1/8" 4 -1/2" 12.6# L -80 IBT -M 8100' 7608' / 6287' 15708' / 6374' Tubing 3 -1/2" 9.3# L -80 IBT -M 3500' Surface 3500' / 3328' Tubing 2 -7/8" 6.5# L -80 IBT -M 15708' 3500' / 3328' 15708' / 6374' Casing Properties Size Weight Grade ID Drift ID Conn. Internal Collapse Tensile Yield (psi) Strength (psi) Joint 1 Body 16" 109# H -40 14.67" 14.5" Welded Conductor casing 9 -5/8" 40# L -80 8.835" 8.679" BTC 5750 3090 916 M 916 M 7" 26# L -80 6.276" 6.151" BTC -M 7240 5410 604 M 604 M 4 -1/2" 12.6# L -80 3.958" 3.833" IBT -M n/a n/a 289 M 289 M Pioneer Natural Resources Last Revised: October 2, 2008 ODSN -37 Permit To Drill Page 4 of 9 1 Cement Calculations: Casing Size: 9 -5/8" Surface Casing - single stage Basis: Lead: 100% excess over gauge hole in permafrost, 30% excess over gauge hole below permafrost Lead TOC: Surface Tail: 2375' of open hole with 30% excess, plus 85' shoe track Tail TOC: 2375' MD (500' MD above 2995' TVD) I Total Cement Volume: Preflush 10 bbl water Spacer 40 bbl 10.0 ppg Dual Spacer Lead 258.2 bbls / 349 sx of 10.9 ppg Type "L" Permafrost Cement. 4.15 cf /sk, 20.0 gps water req. Tail 258.2 bbls / 790 sx of 15.6 ppg Premium "G" + adds. 1.18 cf /sk, 5.23 gps water req. Displ 372.7 bbls Mud Temp BHST -55° F, BHCT -60° F estimated During drilling operations, should hole conditions indicate that we will have trouble getting cement to surface, a TAM Port Collar may be run in the casing string and a staged cement job will be performed, if needed. In the event that cement is not circulated to surface during the initial surface casing cement job, notify the AOGCC of the upcoming remedial cement work for possible witness of cement to surface. Casing Size: 7" Intermediate Casing - single stage Basis: Lead: 1741' of open hole 30% excess over gauge Lead TOC: 4967' MD (500' above the Tope of Torok) Tail: 1000' of open hole with 30% excess, plus 85' shoe track Tail TOC: 6708' MD (1000' MD above 7708' TVD) Total Cement Volume: Preflush 10 bbl water Spacer 40 bbl 13.0 ppg Dual Spacer Lead 60.4 bbls / 139 sx of 12.5 ppg Premium "G" + adds. 2.44 cf /sk, 13.74 gps water req. Tail 38.1 bbls / 181 sx of 15.8 ppg Premium "G" + adds. 1.18 cf /sk, 5.18 gps water req. Displ 291.7 bbls Mud Temp BHST -145° F, BHCT -120° F estimated This well is inside the 1/2 mile radius around the disposal well at the intersection with the Torok disposal zone Pioneer Natural Resources Last Revised: October 2, 2008 ODSN -37 Permit To Drill Page 5 of 9 Pioneer Natural Resources Well Plan Summary Drilling Operations Pre -Rig Work 1. 16" Conductors have been set and the Well Bay modules have been placed. 2. The Oooguruk Drill Site Class 1 / Class 2 Disposal Well, ODSDW1 -44, has been drilled and commissioned for disposal. Rig Activity: Drill Surface Hole through Case Intermediate Hole and Suspend 1. MIRU Nabors 19AC over pre - installed 16" conductor casing. 2. Nipple up and function test the 21 -1/4" diverter system prior to spud. (Notify the AOGCC Field Inspectors 48 hours prior to diverter function test). 3. MU 12 -1/4" Directional Drilling, MWD /LWD assembly. Drill surface hole to the casing point at -5000' MD / 4653' TVDrkb, making wiper trips as necessary. Circulate and condition the hole to run casing. POOH. 4. Run and cement the 9 -5/8 ", 40# surface casing - a Port Collar may be run based on hole conditions at Company Rep discretion. 5. Ensure floats are holding. WOC if needed. 6. ND Diverter, NU BOPE and test. Test BOPE to 250/3500 psi 7. MU 8 -3/4" directional drilling, MWD /LWD assembly. RIH and cleanout the casing to landing collar. Displace the well over to intermediate hole drilling fluid. 8. Test the 9 -5/8" casing to 3,500 psi for 30 min. 9. Drill out shoe tract, cement, rat hole and 20' of new formation below 9 -5/8" shoe. Pull the bit back into the 9 -5/8" casing and perform LOT. 10. Drill 8 -3/4" intermediate hole to casing point at -7708' MD/ 6315' TVDrkb. Circulate and condition the drilling fluid to run casing. 11. Run and cement the 7 ", 26# intermediate casing. Displace the cement with seawater. Ensure floats are holding. 12. RIH with enough 2 -7/8" tubing to allow for the circulation of diesel freeze protection fluid to -2000' TVDrkb. 13. Land the tubing and RILDS. Install TWC. 14. NU Tree and test. 15. Pull TWC. Test the 7" casing to 3,500 psi for 30 minutes. 16. Circulate diesel freeze protection fluid to freeze protect the well to -2000' TVDrkb. Also, freeze protect the 7" x 9 -5/8" annulus with diesel to -2000' TVDrkb. 17. Temporarily suspend the well. RDMO to slot 39 to drill the surface and intermediate hole for that well. Note: By temporarily suspending the well at this point we can minimize the risk of collision by allowing MGT tools to be run in the upper part of the hole while drilling the next well Rig Activity: Drill and Complete Remaining Well 1. MIRU to ODSN -40. RU circulation lines and circulate out the diesel freeze protection fluid and ensure the well is dead. 2. Install TWC. ND Tree and NU BOPE. Test BOPE to 250/3500 psi. 3. Pull circulation tubing string from the well. 4. MU 6 -1/8" directional drilling, MWD /LWD assembly. RIH and cleanout to landing collar. 5. Re- verify the pressure test the 7" casing to 3,500 psi. Pioneer Natural Resources Last Revised: October 2, 2008 ODSN -37 Permit To Drill Page 6 of 9 • 6. Displace the well over to production hole drilling fluid. 7. Drill out shoe tract, cement, rat hole and 20' of new formation below 7" shoe. Pull the bit back into the 7" casing and perform an FIT. 8. Drill the 6 -1/8" production hole to TD at - 15708' MD/ 6374' TVDrkb. POH. 9. Circulate and condition the hole to run liner. POH. 10. Run 4 -1/2" liner on 4" DP 11. Release from the liner and set the liner top packer. Displace the well over to 10.2 ppg Brine. POH. 12. MU completion with ESP and RIH. 13. Land the tubing and RILDS. Install TWC. 14. ND BOPE, NU tree and test to 5,000 psi. 15. Pull TWC and reverse circulate corrosion inhibited brine and diesel to freeze protect the well to -2000' TVD and allow to u -tube. 16. Drop ball and rod and allow to seat. Pressure test the tubing to 3,500 psi - chart and hold for 30 minutes. Bleed off pressure and then pressure test the annulus to 3,500 psi - chart and hold for 30 minutes. Bleed off pressure. 17. RU Slickline and pull the ball and rod. Pull the RHC -m plug. 18. RD Slickline. RDMO to next well. Pioneer Natural Resources Last Revised: October 2, 2008 ODSN -37 Permit To Drill Page 7 of 9 Casing Shoe Leak Off Test Procedure: 1. After testing BOPE, pick up the drilling assembly and RIH to the float collar. Circulate to consistent mud weight and rheology. 2. 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. 3. Bleed off pressure while taking returns to a calibrated tank and record volume recovered. 4. Drill out the shoe track. Drill 20 ft of new hole and circulate the hole clean with consistent mud weight in /out. Pull up into the casing shoe. 5. Perform a Leak Off Test: • Calculate the required test pressure to reach leak off 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. • 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 1 /4 of a bbl pumped. • Continue pumping until the pressure vs. volume curve breaks over indicating 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 Leak Off Test pressure at the shoe as EMW. • Submit the test results to the Pioneer Operations Drilling Engineer for distribution as required. Pioneer Natural Resources Last Revised: October 2, 2008 ODSN -37 Permit To Drill Page 8 of 9 • • Drilling Hazards and Contingencies POST THIS NOTICE IN THE DOGHOUSE Well Control • A ConocoPhillips well drilled to the south of the Oooguruk development showed communication with the main body of the Kuparuk field. In that well, they took an -2 ppg kick - over planned mud weight — to -12.5 ppg. Prior to drilling into the Kuparuk, hold a pre - reservoir meeting to outlined heightened awareness and kick detection o Following the Kuparuk penetration, pick up off bottom, shut off the pumps and • perform a flow check to verify there isn't any overpressure. o During the drilling of ODSDW01 -44 and ODSK -33, no increase in pressure was seen. o During the drilling of ODSK -33, no increase in pressure was seen. o This is a new fault block Lost Circulation /Breathing /Formation Stability • The Torok Shales just above the HRZ showed that they are problematic on the ODSK -33 well — causing "temporarily restricted" pipe. These shales are bentonitic (clay) and /or vitrious (volcanic) in nature and may have some coal stringers. Any loss of flow across this interval could allow the drilled solids to expand or dislodge and grab onto the BHA. While drilling this interval, o take small bites and circulate them up and away from the BHA prior to taking another bite. • Lost circulation is not expected, but if encountered, consult the Lost Circulation Decision Tree in the Halliburton Mud Program. • Breathing may be seen while drilling the Hue and Torok shales. Minimizing swab and surge on the formation is critical to reducing the impact of breathing in the wellbore. • A formation study was conducted by GMI which indicated mud weights >12.5 ppg to maintain hole stability across the HRZ above the Kuparuk. Should shale instability be observed, pay close attention to the cuttings returned to surface and attempt to make small changes to mud weight to regain stability. o Splintered shales — indicates the mud weight may be too low o Tabular shales — indicates the mud weight may be too high Kick Tolerance /Integrity Testing Kick Tolerance / Integrity Testing Summary Table Casing set / Interval Maximum Influx Mud Exp Pore Min LOT / FIT Volume Weight Press 9 -5/8" Surface / 8 -3/4" hole 81.1 bbls 10.2 3118 12.0 ppg (LOT) 7" Intermediate / 6 -1/8" hole Infinite 10.2 3148 13.5 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 • A seismically visible fault is expected to be crossed and sub seismic faults with throws <25' may be encountered. Losses may be associated with these faults. Fault Location MD TVDss Throw Direction Uncertainty Lateral section 3496 3325.0 20' North East 150' • CONSULT THE ODS DATA SHEET AND WELL PLAN FOR ADDITIONAL INFORMATION Pioneer Natural Resources Last Revised: October 2, 2008 ODSN -37 Permit To Drill Page 9 of 9 ODSN -37 Pruction Well Proposedebmpletion Well Head: 9 -5/8 ", 5K, VetcoGray Tree: 2 -7/8 ", 5K, Horizontal Vent Valves Control Line 16" Conductor — I 158' MDrkb / 158' TVDrkb 3 -1/2 ", 9.3# L -80 IBT -M to - -3500' MD 40 VA 2 -7/8" ScSSSV, 2.313" ID @ –750' ■ 2-7/8" GLM @ 3475' MDrkb / 3330' TVDrkb 9 -5/8 ", 40# L -80 BTC, 8.835" ID 5000' MDrkb / 4653" TVDrkb 111 X Nipple, 2.313" ID @ 4365' MD � 7" x 2 -7/8" Packer @ -4385' MDrkb / –4100' TVDrkb ■ X Nipple, 2.313" ID w RHC -M Profile @ 4405' MD 2 -7/8 ", 6.5# L -80 IBT -M 2 -7/8" GLM © 5994' MDrkb / 5510' TVDrkb ESP Cable O O 0 I 2 -7/8" Durasleeve Sliding Sleeve, 2.313" ID © 7600' MDrkb 1 XN Nipple, 2.205" ID Nogo © 7640' MDrkb ESP @ 7650' MDrkb Estimated Top of Cement @ 6708' MD 7" Weatherford Liner Top Packer and Tieback 7608' MDrkb 7 ", 26# L -80 BTC M, 6.276" ID 4 -1/2" 12.6# L -80 IBT -M Un- cemented Solid Liner 7708' MDrkb / 6315' TVDrkb 15708' MDrkb / 6374' TVDrkb Date: Revision By: Comments 10/2/2008 Alex Vaughan Proposed Completion ODSN -37 Producer Well Schematic PIONEER NATURAL RESOURCES 5' i 0 • M ' i , S P f 2 Well Planning - Pioneer - Oooguruk t t tt, 14 Oooguruk Developement 4 1 ',. 1 ' Oooguruk Drill Site 4 - ODSN-37 - Slot ODS-37 i 4 ODSN-37 PN8 i : N Plan: ODSN-37 PN8 wp13 1 Standard Proposal Report 4 4 25 September, 2008 i t .: 4 ',i ‘4: ' li ' 1 H . HALLIEIURTON ,.;•.= Sperry Drilling Services ;. '. t A WELL DETAILS: ODSN - REFERENCE INFORMATION is HALLIBURTt7N N/E Reference: Ground Level: 13.5 Co-ordinate (N/E) Well ODSN-37 Slot a ODS-37, True North + - W Northing Fasting Latittude Longitude Slot Vertical (TVD) Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) +N / -S g g 8 Measured Depth Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Sperry Drilling Services 0.0 0.0 6031053.00 469869.00 70° 29'45.273 N 150° 14' 46.967 W ODS -37 Calculation Method: Minimum Curvature PIONEER ._ CASING DETAILS SURVEY PROGRAM WELLBORE TARGET DETAILS (MAP CO- ORDINATES) Date: 2008 -09- 25700:00:00 validated: Yes Version: +N / -S +E / -W Northin TVD MD Name Size Depth From Depth To Survey /Plan Tool Project: Oooguruk Developement Name TVD g Eastin s Sha a p 4652.9 5000.0 9 5/8" 9.625 44.0 1500.0 ODSN - 37 PN8 wp13 CB - SS Site: Ooo uruk Drill Site PN8 v13 Ti 6314.9 -93.1 -675.9 6030962.60 469192.80 Point 6314.9 7708.0 7" 7.000 1500.0 15708.4 ODSN -37 PN8 wp13 MWD +SAG +CA +IIFR +MS g PN8 v13 T2A 6370.8 640.0 - 1192.9 6031697.75 468678.82 Point Well: ODSN -37 PN8 v13 T6 6374.4 6157.4 - 5650.9 6037232.60 464243.70 Point Wellbore: ODSN -37 PN8 PN8 v13 T3 6376.7 1519.7 -1949.7 6032580.40 467925.70 Point SECTION DETAILS PN8 v13 T4 6387.2 3074.3 - 3190.1 6034139.90 466691.70 Point Plan: ODSN -37 PN8 wp13 PN8 v13 T5 6399.9 4614.3 - 4420.3 6035684.70 465467.90 Point Sec MD Inc Azi TVD +N / -S +E / -W DLeg TFace VSec Target 11UU 1 44.0 0.00 0.00 44.0 0.0 0.0 0.00 0.00 0.0 2 400.0 0.00 0.00 400.0 0.0 0.0 0.00 0.00 0.0 COMPANY DETAILS: Well Planning - Pioneer - Oooguruk 3 900.0 5.00 140.00 899.4 -16.7 14.0 1.00 140.00 -21.8 _ - - 4 1150.0 10.00 140.00 1147.1 -41.7 35.0 2.00 0.00 -54.4 - DDI 6 Calcu Method: Minimum Curvature 5 1616.7 17.00 140.00 1600.6 -125.1 105.0 1.50 0.00 -163.1 - 600 Error System: ISCWSA 6 1772.9 17.00 140.00 1750.0 -160.1 134.3 0.00 0.00 -208.8 Scan Method: Tray. Cylinder North 7 3127.9 28.00 140.00 3000.0 -556.7 467.1 0.81 0.00 -726.0 _ Error Surface: Elliptical Conic 8 4257.9 28.00 176.16 3997.7 - 1040.7 661.9 1.50 90.00 - 1214.3 Warning Method: Rules Based 9 5000.0 28.00 231.44 4652.9 - 1347.3 526.7 3.50 90.00 - 1348.7 0 - 10 5020.0 28.00 231.44 4670.6 - 1353.1 519.4 0.00 0.00 - 1348.1 - 11 7146.9 74.32 335.96 6167.0 -591.9 -465.8 3.89 110.04 -121.1 - Start Dir 1.00/100' 400.00' MD, 400.00' TVD 12 7348.6 74.32 335.96 6221.5 - 414.6 - 544.9 0.00 0.00 63.0 - - -- -- -- 13 7408.0 75.00 338.00 6237.3 -361.8 -567.3 3.50 71.07 117.0 • 600 14 7708.0 75.00 338.00 6314.9 -93.1 -675.9 0.00 0.00 388.4 PN8 v13 T1 Start Dir 2.00/100' 900.00' MD, 899.40' TVD 15 8145.3 90.14 320.84 6371.7 277.1 - 896.0 5.20 - 49.77 810.0 _ _ _ - - - 16 8551.3 90.14 320.84 6370.7 591.9 - 1152.4 0.00 0.00 1215.3 17 8614.2 89.71 319.00 6370.8 640.0 - 1192.9 3.00 - 103.21 1278.1 PN8 v13 T2A Start Dir 1.50/100' 1150.00' MD, 1147.10' TVD 18 8621.8 89.71 319.23 6370.8 645.7 - 1197.9 3.00 89.91 1285.7 1200 - 10° 19 9701.8 89.71 319.23 6376.3 1463.6 - 1903.1 0.00 0.00 2365.1 - Base of Permafrost 20 9774.6 89.70 321.41 6376.7 1519.7 - 1949.7 3.00 90.31 2437.9 PN8 v13 T3 15° _ End Dir 1616.70' MD, 1600.70' TVD 21 9774.6 89.70 321.41 6376.7 1519.7 - 1949.7 3.00 0.00 2437.9 22 11761.0 89.70 321.41 6387.2 3072.4 - 3188.5 0.00 0.00 4419.5 1800 Top West Sak - - - - - _ 23 11763.5 89.63 321.38 6387.2 3074.3 - 3190.1 3.00 - 154.20 4422.0 PN8 v13 T4 Start Dir 0.81/100' 1772.90' MD, 1750.00' TVD 24 11763.6 89.63 321.38 6387.2 3074.3 - 3190.1 3.00 0.00 4422.0 25 13722.1 89.63 321.38 6399.9 4604.6 - 4412.5 0.00 0.00 6376.0 - H Shales 20° 26 13734.6 90.00 321.43 6399.9 4614.3 - 4420.3 3.00 7.22 6388.4 PN8 v13 T5 o - Start Dir 1.50/100' 3127.90' MD, 3000.00' TVD 27 13759.4 90.74 321.43 6399.7 4633.7 - 4435.8 3.00 0.00 6413.2 o O 2400 " " - 28 15708.4 90.74 321.43 6374.4 6157.4 - 5650.9 0.00 0.00 8357.4 PN8 v13 T6 - Tuffaceous Shales'... Start Dir 3.50/100' 4257.90' MD, 3997.70' TVD r _ , ?S° " " o - - " - " " FORMATION TOP DETAILS Q 3000- Violet 1 Fault End Dir 5000.00' MD, 4652.90' TVD End Dir 8621.80' MD, 6370.80' TVD TVDPathWDssPath MDPath Formation Start Dir 3.89/100' 5020.00' MD, 4670.60' TVD Start Dir 3.00/100' 9701.80' MD, 6376.30' TVD 1662.5 1605.0 1681.4 Base of Permafrost V, 3600- - - - 2282.8 2225.3 2337.5 Top West Sak > - Brook 2B 2874.6 2817.1 2986.6 Hue Shales N - End Dir 7146.90 MD, 6167.00 TVD End Dir 9774.60 MD, 6376.70 TVD 2964.4 2906.9 3087.7 Tuffaceous Shales 2 3324.5 3267.0 3495.4 Violet 1 Fault 1- 4200- Start Dir 3.50/100' 7348.60' MD, 6221.50' WD Start Dir 3.00/100' 11761.00' MD, 6387.20' TVD 4270.5 4213.0 4566.9 Brook 2B Top Torok Sand " " 5070.4 5012.9 5467.4 Top Torok Sand L-=.---- End Dir 7408.00' MD, 6237.30' TVD .' 5315.2 5257.7 5747.2 Base Torok Sand End Dir 11763.60' MD, 6387.20' TVD 5774.5 5717.0 6339.2 Top HRZ 4800- 9 5/8" Base Torok Sand' 5893.0 5835.5 6524.9 Base HRZ Start Dir 5.20/100' 7708.00' MD, 6314;90(TVD 5989.9 5932.4 6699.0 Kalubik Marker Start Dir 3.00/100' 13722.10' MD, 6399.90' TVD - 3 p 6043.5 5986.0 6809.2 Top Kuparuk C End Dir 8145.30' MD, 637,1 TVD , 6085.2 6027.7 6905.7 Base Kuparuk (LCU) 5400 Top HRZ 6311.2 6253.7 7693.7 Top Nuiqsut p Start Dir 3.00 /100' 8551. i0' MD, 6370.79II1Vt End Dir 13759.40' MD, 6399.70 TVD p q _ Base HRZ - - _ • . h h° , Total Depth at 15708.430' MD, 6374.40' TVD 6000 __ ... • . g ' Kalubik Marker '' / Top Kuparuk C 6600- 7 " , • Base Kuparuk (LCU) ;`Top Nuiqsut •, PN8 v13 T2A pN8w13 T4 . ' +PNS v13 T6 7200- 'Begin 300' ESP Tangent PN8 v13 T1 PN8 PN8 v13 T v13 T3 ODSN -37 PN8 wp13 1 1 I l I 1 I I I I I r_ r I . - T - I I i I I I I i I I I ri I i I I I I 1 I I I I 1 I I I I I I I F IF I I l I I I I I f I l I I I 1 1 1 i l l l I i I l I l l 1 l i 1 1 l I i l l l I i I l l l l l l l i l -2400 -1800 -1200 -600 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 Vertical Section at 317.46bearing (1500 ft/in) WALLIBURTON WELL DETAILS: ODSN-37 REFERENCE INFORMATION Co-ordinate (N/1:) Reference: Well ODSN -37 - Slot ODS -37, True North s Ground Level. 13.5 Vertical (TVD) Reference: 44' + 13.5 @ 57.55 (Nabors 19AC) { Sperry DPIlUIng Services +N / -S +E/-W Northing Easting Latittude Longitude Slot Measured Depth Reference: 44' + 13.5 @ 57.5ft (Nabors 19AC) 0.0 0.0 6031053.00 469869.00 70 29' 45.273 N 150° 14' 46.967 W ODS -37 Calculation Method: Minimum Curvature PIONEER Project: Ooo urukDevelo emenf Project: g P WELLBORE TARGET DETAILS (MAP CO-ORDINATES) COMPANY DETAILS: Well Planning - Pioneer - Oooguruk Site: Oooguruk Drill Site Name TVD +N / -S +E / -W Northing Easting Shape g 0 P Calculation Error Method: Minimum Curvature Well: ODSN -37 PN8 v13 Ti 6314.9 -93.1 -675.9 6030962.60 469192.80 Point Error System: ISCWSA Wellbore: ODSN -37 PN8 PN8 v13 T2A 6370.8 640.0 - 1192.9 6031697.75 468678.82 Point Scan Method: Tray. Cylinder North Plan: ODSN -37 PN8 w 13 PN8 v13 T6 6374.4 6157.4 - 5650.9 6037232.60 464243.70 Point Error Surface: Elliptical Conic /fl PN8 v13 T3 6376.7 1519.7 - 1949.7 6032580.40 467925.70 Point Warning Method: Rules Based 6600- PN8 v13 T4 6387.2 3074.3 - 3190.1 6034139.90 466691.70 Point I - PN8 v13 T5 6399.9 4614.3 - 4420.3 6035684.70 465467.90 Point _ Total Depth at 15708.430' MD, 6374.40' TVD • - - = SURVEY PROGRAM SECTION DETAILS 6000 1 1PN8 v13 Tf. Date: 2008 -09- 25700:00:00 Validated: Yes Version: ODSN - 37 PN8 wp13 Sec MD Inc Azi TVD +N / - S +E / - W DLeg TFace VSec Target Depth From Depth To Survey /Plan Tool - 44.0 1500.0 ODSN - 37 PN8 wp13 CB GYRO - SS 1 44.0 0.00 0.00 44.0 0.0 0.0 0.00 0.00 0.0 - 1500.0 157084 ODSN 37PN8wp13 MWD +SAG +CA +IIFR +MS 2 400.0 0.00 0.00 400.0 0.0 0.0 0.00 0.00 0.0 5400- 3 900.0 5.00 140.00 899.4 -16.7 14.0 1.00 140.00 -21.8 4 1150.0 10.00 140.00 1147.1 -41.7 35.0 2.00 0.00 -54.4 CASING DETAILS 5 1616.7 17.00 140.00 1600.6 -125.1 105.0 1.50 0.00 -163.1 - 6 1772.9 17.00 140.00 1750.0 -160.1 134.3 0.00 0.00 -208.8 4800- PN8 v13 4+ 7 3127.9 28.00 140.00 3000.0 -556.7 467.1 0.81 0.00 -726.0 End Dir 13759.40' MD, 6399.70' TVD 1 TVD MD Name Size 8 4257.9 28.00 176.16 3997.7 - 1040.7 661.9 1.50 90.00 - 1214.3 _ - 4652.9 5000.0 9 5/8" 9.625 9 5000.0 28.00 231.44 4652.9 - 1347.3 526.7 3.50 90.00 - 1348.7 II _ 1 6314.9 7708.0 7" 7.000 10 5020.0 28.00 231.44 4670.6 - 1353.1 519.4 0.00 0.00 - 1348.1 - 11 7146.9 74.32 335.96 6167.0 -591.9 -465.8 3.89 110.04 -121.1 4200- Start Dir 3.00/100' 13722.10' MD, 6399.90' ■ 12 7348.6 74.32 335.96 6221.5 -414.6 -544.9 0.00 0.00 63.0 13 7408.0 75.00 338.00 6237.3 -361.8 -567.3 3.50 71.07 117.0 14 7708.0 75.00 338.00 6314.9 -93.1 -675.9 0.00 0.00 388.4 PN8 v13 T1 15 8145.3 90.14 320.84 6371.7 277.1 -896.0 5.20 -49.77 810.0 3600- 16 8551.3 90.14 320.84 6370.7 591.9 - 1152.4 0.00 0.00 1215.3 End Dir 11763.60' MD, 6387.20' TVD 17 8614.2 89.71 319.00 6370.8 640.0 - 1192.9 3.00 - 103.21 1278.1 PN8 v13 T2A PN8 v13 T l 18 8621.8 89.71 319.23 6370.8 645.7 - 1197.9 3.00 89.91 1285.7 '..E - I T 19 9701.8 89.71 319.23 6376.3 1463.6 - 1903.1 0.00 0.00 2365.1 3000- 20 9774.6 89.70 321.41 6376.7 1519.7 - 1949.7 3.00 90.31 2437.9 PN8 v13 T3 ' I 21 9774.6 89.70 321.41 6376.7 1519.7 - 1949.7 3.00 0.00 2437.9 22 11761.0 89.70 321.41 6387.2 3072.4 - 3188.5 0.00 0.00 4419.5 O - Start Dir 3.00/100' 11761.00' MD, 6387.20' TVD 23 11763.5 89.63 321.38 6387.2 3074.3 - 3190.1 3.00 - 154.20 4422.0 PN8 v13 T4 24 11763.6 89.63 321.38 6387.2 3074.3 - 3190.1 3.00 0.00 4422.0 2400- 25 13722.1 89.63 321.38 6399.9 4604.6 - 4412.5 0.00 0.00 6376.0 + 26 13734.6 90.00 321.43 6399.9 4614.3 - 4420.3 3.00 7.22 6388.4 PN8 v13 T5 ▪ _ 27 13759.4 90.74 321.43 6399.7 4633.7 - 4435.8 3.00 0.00 6413.2 t I PN8 v13 T 1 28 15708.4 90.74 321.43 6374.4 6157.4 - 5650.9 0.00 0.00 8357.4 PN8 v13 T6 7 1800 End Dir 9774.60' MD, 6376,70_TVD _ ,y - Start Dir 3.00/100' 9701.80' MD, 6376.30' TVD _ � Start Dir 1.00 /100' 400.00' MD, 400.00' TVD ]zoo= DDI =6.20 cn I PN8 v13T2i+ i End Dir 8621.80' MD, 6370.80' TVD Start Dir 2.00/100' 900.00' MD, 899.40' TVD 600 _ Start Dir 3.00/100' 8551.30' MD, 6370.70' TVD - - �- 'pN8 vl3 TII Start Dir 1.50 /100' 1150.00' MD, 1147.10' TVD i __ - End Dir 8145.30' MD, 6371.70' TVD I - - - - End Dir 1616.70' MD, 1600.70' TVD 0 I, _ _ - -- - ' - Start Dir 5.20/100' 7708.00' MD, 6314.90' TVD - - - - - - _. Start Dir 0.81/100' 1772.90' MD, 1750.00' TVD - - - _ cA - 600 - 'Begin 300' ESP Tanger't , End Dir 7408.00' MD, 6237.30' TVD i bpi Start Dir 1.50 /100' 3127.90' MD, 3000.00' TVD _ 4000 - 1200 - 95/8" - _ - Start Dir 3.50/100' 7348.60' MD, 6221.50' TVD • - Start Dir 3.50/100' 4257.90' MD, 3997.70' TVD - , ' g 0 - 1800 - End Dir 7146.90' MD, 6167.00' TVD ` - End Dir 5000.00' MD, 4652.90' TVD - Start Dir 3.89/100' 5020.00' MD, 4670.60' TVD -2400 iipiiiliiiipiiHl i :11HiiiH. IrTrrIliiHllllIiiiiHrTIIIIIHrlliHiiiHlli liHlil I , IIIIIIII, l', -7200 -6600 -6000 -5400 -4800 -4200 -3600 -3000 -2400 -1800 -1200 -600 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 West( -) /East( +) (1500 ft/in) • Sperry Drilling Services HALLIBURTOlt Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -37 - Slot ODS -37 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Project: Oooguruk Developement MD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -37 Survey Calculation Method: Minimum Curvature Wel!bore: ODSN -37 PN8 Design: ODSN -37 PN8 wp13 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 ? Weft ODSN -37 - Slot ODS -37 Well Position +N / -S 0.0 ft Northing: 6,031,053.00 ft Latitude: 70° 29' 45.273 N +E / -W 0.0 ft Easting: 469,869.00 ft Longitude: 150° 14' 46.967 W Position Uncertainty 0.0 ft Wellhead Elevation: ft Ground Level: 13.5ft Wellbore ODSN -37 PN8 Magnetics Model Name Sample Date ,, fr Angle Field Strength ( ?) (nT) n 4 r (fJ IGRF200510 3/8/2007 23.23 80.81 57,644 Design ODSN -37 PN8 wp13 Audit Notes: Version: Phase: PLAN Tie On Depth: 44.0 1 Vertical Section: De • ? ".k +E/-W Direction (ft) (bearing) 44.0 0.0 0.0 317.46 9/25/2008 4 :46 :01PM Page 2 COMPASS 2003.16 Build 428 • Sperry Drilling Services HALL HALLIBURTOlt Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -37 - Slot ODS -37 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Project: Oooguruk Developement MD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -37 Survey Calculation Method: Minimum Curvature Wel!bore: ODSN -37 PN8 Design: ODSN -37 PN8 wp13 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/-S +E / -W Rate Rate Rate Tool Face (ft) ( ?) ( (ft) ft (ft) (ft) ( ? /100ft) ( ?400ft) ( ?/100ft) ( ?) g .r 44.0 0.00 0.00 44.0 -13.5 0.0 0.0 0.00 0.00 0.00 0.00 400.0 0.00 0.00 400.0 342.5 0.0 0.0 0.00 0.00 0.00 0.00 900.0 5.00 140.00 899.4 841.9 -16.7 14.0 1.00 1.00 0.00 140.00 1,150.0 10.00 140.00 1,147.1 1,089.6 -41.7 35.0 2.00 2.00 0.00 0.00 1,616.7 17.00 140.00 1,600.6 1,543.1 -125.1 105.0 1.50 1.50 0.00 0.00 1,772.9 17.00 140.00 1,750.0 1,692.5 -160.1 134.3 0.00 0.00 0.00 0.00 3,127.9 28.00 140.00 3,000.0 2,942.5 -556.7 467.1 0.81 0.81 0.00 0.00 4,257.9 28.00 176.16 3,997.7 3,940.2 - 1,040.7 661.9 1.50 0.00 3.20 90.00 5,000.0 28.00 231.44 4,652.9 4,595.4 - 1,347.3 526.7 3.50 0.00 7.45 90.00 5,020.0 28.00 231.44 4,670.6 4,613.1 - 1,353.1 519.4 0.00 0.00 0.00 0.00 7,146.9 74.32 335.96 6,167.0 6,109.5 -591.9 -465.8 3.89 2.18 4.91 110.04 7,348.6 74.32 335.96 6,221.5 6,164.0 -414.6 -544.9 0.00 0.00 0.00 0.00 7,408.0 75.00 338.00 6,237.3 6,179.8 -361.8 -567.3 3.50 1.15 3.43 71.07 7,708.0 75.00 338.00 6,314.9 6,257.4 -93.1 -675.9 0.00 0.00 0.00 0.00 8,145.3 90.14 320.84 6,371.7 6,314.2 277.1 -896.0 5.20 3.46 -3.93 -49.77 8,551.3 90.14 320.84 6,370.7 6,313.2 591.9 - 1,152.4 0.00 0.00 0.00 0.00 8,614.2 89.71 319.00 6,370.8 6,313.3 640.0 - 1,192.9 3.00 -0.69 -2.92 - 103.21 8,621.8 89.71 319.23 6,370.8 6,313.3 645.7 - 1,197.9 3.00 0.00 3.00 89.91 9,701.8 89.71 319.23 6,376.3 6,318.8 1,463.6 - 1,903.1 0.00 0.00 0.00 0.00 9,774.6 89.70 321.41 6,376.7 6,319.2 1,519.7 - 1,949.7 3.00 -0.02 3.00 90.31 9,774.6 89.70 321.41 6,376.7 6,319.2 1,519.7 - 1,949.7 3.00 0.00 0.00 0.00 11,761.0 89.70 321.41 6,387.2 6,329.7 3,072.4 - 3,188.5 0.00 0.00 0.00 0.00 11,763.5 89.63 321.38 6,387.2 6,329.7 3,074.3 - 3,190.1 3.00 -2.70 -1.31 - 154.20 11,763.6 89.63 321.38 6,387.2 6,329.7 3,074.3 - 3,190.1 3.00 -2.75 -1.19 0.00 13,722.1 89.63 321.38 6,399.9 6,342.4 4,604.6 - 4,412.5 0.00 0.00 0.00 0.00 13,734.6 90.00 321.43 6,399.9 6,342.4 4,614.3 - 4,420.3 3.00 2.98 0.38 7.22 13,759.4 90.74 321.43 6,399.7 6,342.2 4,633.7 - 4,435.8 3.00 3.00 0.00 0.00 15,708.4 90.74 321.43 6,374.4 6,316.9 6,157.4 - 5,650.9 0.00 0.00 0.00 0.00 9/25/2008 4:46:01PM Page 3 COMPASS 2003.16 Build 428 • Sperry Drilling Services HALL HALLIBURTOlt Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -37 - Slot ODS -37 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Project: Oooguruk Developement MD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -37 Survey Calculation Method: Minimum Curvature Wel!bore: ODSN -37 PN8 Design: ODSN -37 PN8 wp13 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N1-S +E/-W Northing Easting DLS Vert Section (ft) ( ?) (bearing) (ft) ft (ft) (ft) (ft) (ft). -13.50 44.0 0.00 0.00 44.0 -13.5 0.0 0.0 6,031,053.00 ' 469,869.00 * 0.00 0.00 100.0 0.00 0.00 100.0 42.5 0.0 0.0 6,031,053.00 469,869.00 0.00 0.00 200.0 0.00 0.00 200.0 142.5 0.0 0.0 6,031,053.00 469,869.00 0.00 0.00 300.0 0.00 0.00 300.0 242.5 0.0 0.0 6,031,053.00 469,869.00 0.00 0.00 400.0 0.00 0.00 400.0 342.5 0.0 0.0 6,031,053.00 469,869.00 0.00 0.00 Start Dir 1.00/100' 400.00' MD, 400.00' TVD 500.0 1.00 140.00 500.0 442.5 -0.7 0.6 6,031,052.33 469,869.56 1.00 -0.87 600.0 2.00 140.00 600.0 542.5 -2.7 2.2 6,031,050.32 469,871.23 1.00 -3.49 700.0 3.00 140.00 699.9 642.4 -6.0 5.0 6,031,046.97 469,874.02 1.00 -7.84 800.0 4.00 140.00 799.7 742.2 -10.7 9.0 6,031,042.27 469,877.93 1.00 -13.94 900.0 5.00 140.00 899.4 841.9 -16.7 14.0 6,031,036.24 469,882.95 1.00 -21.78 Start Dir 2.00/100' 900.00' MD, 899.40' TVD �"t 1,000.0 7.00 140.00 998.8 941.3 -24.7 20.7 6,031,028.21 469,889.63 2.00 -32.22 1,100.0 9.00 140.00 1,097.8 1,040.3 -35.4 29.7 6,031,017.51 469,898.53 2.00 -46.13 1,150.0 10.00 140.00 1,147.1 1,089.6 -41.7 35.0 6,031,011.17 469,903.81 2.00 -54.37 Start Dir 1.50/100' 1150.00' MD, 1147.10' TVD 1,200.0 10.75 140.00 1,196.3 1,138.8 -48.6 40.8 6,031,004.25 469,909.57 1.50 -63.37 1,300.0 12.25 140.00 1,294.3 1,236.8 -63.9 53.6 6,030,988.93 469,922.32 1.50 -83.28 1,400.0 13.75 140.00 1,391.8 1,334.3 -81.1 68.0 6,030,971.64 469,936.71 1.50 - 105.75 1,500.0 15.25 140.00 1,488.6 1,431.1 -100.3 84.1 6,030,952.40 469,952.72 1.50 - 130.77 1,600.0 16.75 140.00 1,584.7 1,527.2 -121.4 101.9 6,030,931.21 469,970.35 1.50 - 158.30 1,616.7 17.00 140.00 1,600.7 1,543.2 -125.1 105.0 6,030,927.49 469,973.45 1.50 - 163.15 End Dir 1616.70' MD, 1600.70' TVD 1,681.4 17.00 140.00 1,662.5 1,605.0 -139.6 117.1 6,030,912.96 469,985.54 0.00 - 182.03 Base of Permafrost 1,700.0 17.00 140.00 1,680.3 1,622.8 -143.8 120.6 6,030,908.77 469,989.03 0.00 - 187.48 1,772.9 17.00 140.00 1,750.0 1,692.5 -160.1 134.3 6,030,892.39 470,002.66 0.00 - 208.77 Start Dir 0.81/100'•,1772.90' MD, 1750.00'.TVD 1,800.0 17.22 140.00 1,775.9 1,718.4 -166.2 139.5 6,030,886.26 470,007.76 0.81 - 216.73 1,900.0 18.03 140.00 1,871.3 1,813.8 -189.4 158.9 6,030,862.99 470,027.13 0.81 - 246.99 2,000.0 18.84 140.00 1,966.1 1,908.6 -213.6 179.2 6,030,838.68 470,047.36 0.81 - 278.58 2,100.0 19.66 140.00 2,060.5 2,003.0 -238.9 200.4 6,030,813.34 470,068.45 0.81 - 311.52 2,200.0 20.47 140.00 2,154.5 2,097.0 -265.1 222.5 6,030,786.98 470,090.39 0.81 - 345.79 2,300.0 21.28 140.00 2,247.9 2,190.4 -292.4 245.4 6,030,759.59 470,113.18 0.81 - 381.38 2,337.5 21.58 140.00 2,282.8 2,225.3 -302.9 254.2 6,030,749.06 470,121.94 0.81 - 395.07 Top West Sak 2,400.0 22.09 140.00 2,340.8 2,283.3 -320.7 269.1 6,030,731.20 470,136.81 0.81 - 418.30 2,500.0 22.90 140.00 2,433.2 2,375.7 -350.1 293.7 6,030,701.79 470,161.28 0.81 - 456.52 2,600.0 23.71 140.00 2,525.0 2,467.5 -380.4 319.2 6,030,671.38 470,186.59 0.81 - 496.05 2,700.0 24.53 140.00 2,616.3 2,558.8 -411.7 345.4 6,030,639.97 470,212.73 0.81 - 536.87 2,800.0 25.34 140.00 2,707.0 2,649.5 -444.0 372.5 6,030,607.57 470,239.69 0.81 - 578.99 2,900.0 26.15 140.00 2,797.1 2,739.6 -477.2 400.5 6,030,574.19 470,267.47 0.81 - 622.38 2,986.6 26.85 140.00 2,874.6 2,817.1 -506.9 425.3 6,030,544.48 470,292.20 0.81 - 661.00 Hue Shales 3,000.0 26.96 140.00 2,886.5 2,829.0 -511.5 429.2 6,030,539.83 470,296.07 0.81 - 667.04 9/25/2008 4 :46 :01 PM Page 4 COMPASS 2003.16 Build 428 • Sperry Drilling Services HALL HALLIBURTOrt Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -37 - Slot ODS -37 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Project: Oooguruk Developement MD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -37 Survey Calculation Method: Minimum Curvature Welibore: ODSN -37 PN8 Design: ODSN -37 PN8 wp13 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/ -W Northing Easting DLS Vert Section (ft) ( ?) (bearing) (ft) ft (ft) (ft) (ft) 2,906.90 3,087.7 27.67 140.00 2,964.4 2,906.9 -542.3 455.0 6,030,508.91 470,321.80 0.81 - 707.23 Tuffaceous Shales 3,100.0 27.77 140.00 2,975.3 2,917.8 -546.7 458.7 6,030,504.50 470,325.47 0.81 - 712.96 3,127.9 28.00 140.00 3,000.0 2,942.5 -556.7 467.1 6,030,494.47 470,333.82 0.81 - 726.00 Start Dir 1.50/100' 3127.90' MD, 3000.00' TVD 3,200.0 28.00 142.31 3,063.6 3,006.1 -583.1 488.4 6,030,468.03 470,354.94 1.50 - 759.78 3,300.0 28.00 145.51 3,151.9 3,094.4 -621.0 516.0 6,030,429.99 470,382.44 1.50 - 806.42 3,400.0 28.00 148.71 3,240.2 3,182.7 -660.4 541.5 6,030,390.47 470,407.77 1.50 - 852.70 3,495.4 28.01 151.76 3,324.5 3,267.0 -699.3 563.7 6,030,351.50 470,429.85 1.50 - 896.39 Violet 1 Fault 3,500.0 28.00 151.91 3,328.5 3,271.0 -701.2 564.8 6,030,349.61 470,430.85 1.53 - 898.46 3,600.0 28.00 155.11 3,416.8 3,359.3 -743.2 585.7 6,030,307.51 470,451.62 1.50 - 943.57 3,700.0 28.00 158.31 3,505.1 3,447.6 -786.3 604.3 6,030,264.33 470,470.00 1.50 - 987.89 3,800.0 28.00 161.51 3,593.4 3,535.9 -830.4 620.4 6,030,220.18 470,485.95 1.50 - 1,031.27 3,900.0 28.00 164.71 3,681.7 3,624.2 -875.3 634.0 6,030,175.22 470,499.41 1.50 - 1,073.59 4,000.0 28.00 167.91 3,770.0 3,712.5 -920.9 645.1 6,030,129.57 470,510.33 1.50 - 1,114.70 4,100.0 28.00 171.11 3,858.3 3,800.8 -967.1 653.7 6,030,083.39 470,518.69 1.50 - 1,154.49 4,200.0 28.00 174.31 3,946.6 3,889.1 - 1,013.6 659.6 6,030,036.81 470,524.46 1.50 - 1,192.83 4,257.9 28.00 176.16 3,997.7 3,940.2 - 1,040.7 661.9 6,030,009.71 470,526.61 1.50 - 1,214.31 Start Dir 3.50/100' 4257.90' MD, 3997J09VD 4,300.0 28.00 179.29 4,034.9 3,977.4 - 1,060.5 662.7 6,029,989.96 470,527.32 3.50 - 1,229.39 4,400.0 28.00 186.74 4,123.2 4,065.7 - 1,107.3 660.2 6,029,943.13 470,524.66 3.50 - 1,262.23 4,500.0 28.00 194.19 4,211.5 4,154.0 - 1,153.4 651.7 6,029,897.04 470,515.95 3.50 - 1,290.46 4,566.9 28.02 199.17 4,270.5 4,213.0 - 1,183.5 642.7 6,029,867.03 470,506.82 3.50 - 1,306.51 Brook 2B 4,600.0 28.00 201.64 4,299.8 4,242.3 - 1,198.1 637.3 6,029,852.46 470,501.33 3.50 - 1,313.59 4,700.0 28.00 209.09 4,388.1 4,330.6 - 1,240.5 617.2 6,029,810.16 470,481.06 3.50 - 1,331.23 4,800.0 28.00 216.54 4,476.4 4,418.9 - 1,279.9 591.7 6,029,770.84 470,455.48 3.50 - 1,343.08 4,900.0 28.00 223.99 4,564.7 4,507.2 - 1,315.7 561.4 6,029,735.17 470,425.01 3.50 - 1,348.95 5,000.0 28.00 231.44 4,652.9 4,595.4 - 1,347.3 526.7 6,029,703.75 470,390.18 3.50 - 1,348.73 End Dir 5000.00' MD, 4652.9' TVD -9 518" 5,020.0 28.00 231.44 4,670.6 4,613.1 - 1,353.1 519.4 6,029,697.93 470,382.81 0.00 - 1,348.08 Start Dir 3.89/100' 5020.00' MD, 4670.60' TVD 5,100.0 27.08 237.88 4,741.6 4,684.1 - 1,374.5 489.2 6,029,676.67 470,352.61 3.89 - 1,343.48 5,200.0 26.37 246.40 4,830.9 4,773.4 - 1,395.5 449.6 6,029,655.83 470,312.89 3.89 - 1,332.15 5,300.0 26.18 255.19 4,920.6 4,863.1 - 1,410.0 407.9 6,029,641.47 470,271.15 3.89 - 1,314.67 5,400.0 26.52 263.93 5,010.3 4,952.8 - 1,418.0 364.4 6,029,633.65 470,227.58 3.89 - 1,291.12 5,467.4 27.05 269.64 5,070.4 5,012.9 - 1,419.7 334.1 6,029,632.08 470,197.30 3.89 - 1,271.89 Top Torok Sand 5,500.0 27.38 272.32 5,099.4 5,041.9 - 1,419.5 319.2 6,029,632.40 470,182.38 3.89 - 1,261.61 5,600.0 28.71 280.11 5,187.7 5,130.2 - 1,414.3 272.5 6,029,637.74 470,135.77 3.89 - 1,226.28 5,700.0 30.45 287.17 5,274.7 5,217.2 - 1,402.6 224.7 6,029,649.63 470,087.95 3.89 - 1,185.29 5,747.2 31.39 290.24 5,315.2 5,257.7 - 1,394.8 201.7 6,029,657.50 470,065.02 3.89 - 1,164.03 Base Torok Sand 5,800.0 32.52 293.48 5,360.0 5,302.5 - 1,384.4 175.8 6,029,668.02 470,039.14 3.89 - 1,138.83 9/25/2008 4:46:O1PM Page 5 COMPASS 2003.16 Build 42B 0 Sperry Drilling Services HALLIBURTOlt Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -37 - Slot ODS -37 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Project: Oooguruk Developement MD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -37 Survey Calculation Method: Minimum Curvature Welibore: ODSN -37 PN8 Design: ODSN -37 PN8 wp13 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +EJ-W Northing Easing DLS Vert Section (ft) ( ?) (bearing) (ft) ft (ft) (ft) (ft) (, 5,385.71 5,900.0 34.88 299.07 5,443.2 5,385.7 - 1,359.8 126.1 6,029,692.84 469,989.58 3.89 - 1,087.11 6,000.0 37.46 304.01 5,523.9 5,466.4 - 1,328.9 75.9 6,029,723.95 469,939.49 3.89 - 1,030.38 6,100.0 40.23 308.38 5,601.8 5,544.3 - 1,291.8 25.3 6,029,761.22 469,889.10 3.89 - 968.89 6,200.0 43.14 312.27 5,676.5 5,619.0 - 1,248.8 -25.3 6,029,804.49 469,838.64 3.89 - 902.93 6,300.0 46.17 315.75 5,747.7 5,690.2 - 1,199.9 -75.8 6,029,853.54 469,788.36 3.89 - 832.79 6,339.2 47.39 317.01 5,774.5 5,717.0 - 1,179.2 -95.5 6,029,874.29 469,768.74 3.89 - 804.24 Top HRZ 6,400.0 49.30 318.89 5,814.9 5,757.4 - 1,145.5 -125.9 6,029,908.15 469,738.47 3.89 - 758.82 6,500.0 52.50 321.74 5,878.0 5,820.5 - 1,085.8 -175.4 6,029,968.07 469,689.21 3.89 - 681.34 6,524.9 53.30 322.41 5,893.0 5,835.5 - 1,070.1 -187.6 6,029,983.77 469,677.07 3.89 - 661.56 Base HRZ 6,600.0 55.76 324.36 5,936.6 5,879.1 - 1,021.0 -224.1 6,030,033.02 469,640.81 3.89 - 600.72 6,699.0 59.05 326.75 5,989.9 5,932.4 -952.2 -271.2 6,030,101.97 469,593.96 3.89 - 518.19 Kalubik Marker 6,700.0 59.08 326.78 5,990.4 5,932.9 -951.5 -271.7 6,030,102.71 469,593.48 3.89 - 517.32 6,800.0 62.44 329.03 6,039.3 5,981.8 -877.6 -318.0 6,030,176.80 469,547.46 3.89 - 431.54 6,809.2 62.75 329.23 6,043.5 5,986.0 -870.6 -322.2 6,030,183.82 469,543.30 3.89 - 423.55 Top Kuparuk C - 6,900.0 65.83 331.15 6,082.9 6,025.4 -799.6 -362.9 6,030,254.97 469,502.95 3.89 - 343.76 6,905.7 66.02 331.27 6,085.2 6,027.7 -795.1 -365.3 6,030,259.50 469,500.48 3.89 - 338.75 Base Kuparuk (LCU) 7,000.0 69.25 333.16 6,121.1 6,063.6 -717.9 -406.0 6,030,336.85 469,460.15 3.89 - 254.40 7,100.0 72.69 335.09 6,153.7 6,096.2 -632.8 -447.2 6,030,422.05 469,419.27 3.89 - 163.86 7,146.9 74.32 335.96 6,167.0 6,109.5 -591.9 -465.8 6,030,463.05 469,400.81 3.89 - 121.11 End Dir 7146.90' MD TVD 7,200.0 74.32 335.96 6,181.4 6,123.9 -545.2 -486.7 6,030,509.82 469,380.17 0.00 -72.63 7,300.0 74.32 335.96 6,208.4 6,150.9 -457.3 -525.9 6,030,597.90 469,341.32 0.00 18.67 7,348.6 74.32 335.96 6,221.5 6,164.0 -414.6 -544.9 6,030,640.70 469,322.43 0.00 63.04 Start Dir 3.50/100' 7348,60' MD, 6221.50' TVD 7,400.0 74.91 337.73 6,235.2 6,177.7 -369.0 -564.4 6,030,686.34 469,303.14 3.50 109.79 7,408.0 75.00 338.00 6,237.3 6,179.8 -361.8 -567.3 6,030,693.51 469,300.25 3.50 117.03 End Dir 7408.00' MD, 6237.;TVD - Begin 300' ESP Tangent 7,500.0 75.00 338.00 6,261.1 6,203.6 -279.4 -600.6 6,030,776.03 469,267.30 0.00 200.24 7,600.0 75.00 338.00 6,286.9 6,229.4 -189.9 -636.8 6,030,865.72 469,231.48 0.00 290.69 7,693.7 75.00 338.00 6,311.2 6,253.7 -106.0 -670.7 6,030,949.78 469,197.92 0.00 375.45 Top Nuiqsut 7,700.0 75.00 338.00 6,312.8 6,255.3 -100.3 -673.0 6,030,955.42 469,195.67 0.00 381.14 7,708.0 75.00 338.00 6,314.9 6,257.4 -93.1 -675.9 6,030,962.60 469,192.80 0.00 388.38 Start Dir 5.20/100' 7708.00' MD, 6314.90' TVD - 7" - PN8 v13 T1 7,800.0 78.12 334.27 6,336.3 6,278.8 -11.4 -712.1 6,031,044.53 469,156.93 5.20 473.12 7,900.0 81.56 330.31 6,353.9 6,296.4 75.7 -757.9 6,031,131.81 469,111.52 5.20 568.24 8,000.0 85.04 326.42 6,365.6 6,308.1 160.3 -810.0 6,031,216.53 469,059.78 5.20 665.74 8,100.0 88.55 322.57 6,371.2 6,313.7 241.5 -867.9 6,031,298.01 469,002.15 5.20 764.79 8,145.3 90.14 320.84 6,371.7 6,314.2 277.1 -896.0 6,031,333.67 468,974.23 5.20 809.96 End Dir 8145.30' MD, 6371.70' TVD 9/25/2008 4 :46:01PM Page 6 COMPASS 2003.16 Build 428 • Sperry Drilling Services HALL HALLIBURTOrt Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -37 - Slot ODS -37 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Project: Oooguruk Developement MD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Weil: ODSN -37 Survey Calculation Method: Minimum Curvature Welibore: ODSN -37 PN8 Design: ODSN -37 PN8 wp13 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/ -W Northing Easting DLS Vert Section (ft) ( ?) (bearing) (ft) ft (ft) (ft) (ft) 6,314.07 8,200.0 90.14 320.84 6,371.6 6,314.1 319.5 -930.5 6,031,376.21 468,939.86 0.00 864.57 8,300.0 90.14 320.84 6,371.3 6,313.8 397.0 -993.7 6,031,454.00 468,877.02 0.00 964.39 8,400.0 90.14 320.84 6,371.1 6,313.6 474.5 - 1,056.8 6,031,531.78 468,814.19 0.00 1,064.22 8,500.0 90.14 320.84 6,370.8 6,313.3 552.1 - 1,120.0 6,031,609.56 468,751.36 0.00 1,164.04 8,551.3 90.14 320.84 6,370.7 6,313.2 591.9 - 1,152.4 6,031,649.46 468,719.12 0.00 1,215.25 Start Dir 3.00/100' 8551.30' MD, 6370.70' TVD 8,600.0 89.81 319.41 6,370.7 6,313.2 629.2 - 1,183.6 6,031,686.96 468,688.06 3.00 1,263.90 8,614.2 89.71 319.00 6,370.8 6,313.3 640.0 - 1,192.9 6,031,697.75 468,678.82 3.00 1,278.10 PN8 v13 T2A 8,621.8 89.71 319.23 6,370.8 6,313.3 645.7 - 1,197.9 6,031,703.51 468,673.88 2.99 1,285.69 End Dir 8621.80' MD, 6370.80' TVD , 8,700.0 89.71 319.23 6,371.2 6,313.7 704.9 - 1,248.9 6,031,762.93 468,623.05 0.00 1,363.85 8,800.0 89.71 319.23 6,371.7 6,314.2 780.7 - 1,314.2 6,031,838.92 468,558.06 0.00 1,463.80 8,900.0 89.71 319.23 6,372.3 6,314.8 856.4 - 1,379.6 6,031,914.90 468,493.07 0.00 1,563.75 9,000.0 89.71 319.23 6,372.8 6,315.3 932.1 - 1,444.9 6,031,990.89 468,428.08 0.00 1,663.70 9,100.0 89.71 - 319.23 6,373.3 6,315.8 1,007.9 - 1,510.2 6,032,066.87 468,363.09 0.00 1,763.66 9,200.0 89.71 319.23 6,373.8 6,316.3 1,083.6 - 1,575.5 6,032,142.86 468,298.10 0.00 1,863.61 9,300.0 89.71 319.23 6,374.3 6,316.8 1,159.3 - 1,640.8 6,032,218.85 468,233.11 0.00 1,963.56 9,400.0 89.71 319.23 6,374.8 6,317.3 1,235.1 - 1,706.1 6,032,294.83 468,168.12 0.00 2,063.51 9,500.0 89.71 319.23 6,375.3 6,317.8 1,310.8 - 1,771.4 6,032,370.82 468,103.13 0.00 2,163.46 9,600.0 89.71 319.23 6,375.8 6,318.3 1,386.5 - 1,836.7 6,032,446.81 468,038.13 0.00 2,263.41 9,700.0 89.71 319.23 6,376.3 6,318.8 1,462.2 - 1,902.0 6,032,522.79 467,973.14 0.00 2,363.36 9,701.8 89.71 319.23 6,376.3 6,318.8 1,463.6 - 1,903.2 6,032,524.16 467,971.97 0.00 2,365.16 Start Dir 3.00/100' 9701.80' PAD, 6376.30' TVD 9,774.6 89.70 321.41 6,376.7 6,319.2 1,519.7 - 1,949.7 6,032,580.40 467,925.70 3.00 2,437.91 End Dir 9774.60' MD, 6376.70' TVD =P1413 v13 T3 ' 9,800.0 89.70 321.41 6,376.8 6,319.3 1,539.5 - 1,965.5 6,032,600.28 467,909.97 0.01 2,463.20 9,900.0 89.70 321.41 6,377.4 6,319.9 1,617.6 - 2,027.9 6,032,678.69 467,847.92 0.00 2,562.96 10,000.0 89.70 321.41 6,377.9 6,320.4 1,695.8 - 2,090.2 6,032,757.10 467,785.88 0.00 2,662.72 10,100.0 89.70 321.41 6,378.4 6,320.9 1,774.0 - 2,152.6 6,032,835.51 467,723.83 0.00 2,762.48 10,200.0 89.70 321.41 6,378.9 6,321.4 1,852.1 - 2,215.0 6,032,913.92 467,661.79 0.00 2,862.24 1 10,300.0 89.70 321.41 6,379.5 6,322.0 1,930.3 - 2,277.3 6,032,992.33 467,599.75 0.00 2,962.00 10,400.0 89.70 321.41 6,380.0 6,322.5 2,008.5 - 2,339.7 6,033,070.74 467,537.70 0.00 3,061.76 10,500.0 89.70 321.41 6,380.5 6,323.0 2,086.6 - 2,402.1 6,033,149.15 467,475.66 0.00 3,161.52 10,600.0 89.70 321.41 6,381.1 6,323.6 2,164.8 - 2,464.4 6,033,227.56 467,413.61 0.00 3,261.28 10,700.0 89.70 321.41 6,381.6 6,324.1 2,243.0 - 2,526.8 6,033,305.98 467,351.57 0.00 3,361.04 10,800.0 89.70 321.41 6,382.1 6,324.6 2,321.1 - 2,589.2 6,033,384.39 467,289.52 0.00 3,460.80 10,900.0 89.70 321.41 6,382.6 6,325.1 2,399.3 - 2,651.5 6,033,462.80 467,227.48 0.00 3,560.56 11,000.0 89.70 321.41 6,383.2 6,325.7 2,477.5 - 2,713.9 6,033,541.21 467,165.43 0.00 3,660.32 11,100.0 89.70 321.41 6,383.7 6,326.2 2,555.6 - 2,776.3 6,033,619.62 467,103.39 0.00 3,760.08 11,200.0 89.70 321.41 6,384.2 6,326.7 2,633.8 - 2,838.6 6,033,698.03 467,041.35 0.00 3,859.84 11,300.0 89.70 321.41 6,384.8 6,327.3 2,712.0 - 2,901.0 6,033,776.44 466,979.30 0.00 3,959.60 11,400.0 89.70 321.41 6,385.3 6,327.8 2,790.1 - 2,963.4 6,033,854.85 466,917.26 0.00 4,059.36 11,500.0 89.70 321.41 6,385.8 6,328.3 2,868.3 - 3,025.7 6,033,933.26 466,855.21 0.00 4,159.12 11,600.0 89.70 321.41 6,386.3 6,328.8 2,946.5 - 3,088.1 6,034,011.67 466,793.17 0.00 4,258.88 9/25/2008 4 :46 :01PM Page 7 COMPASS 2003.16 Build 428 • • Sperry Drilling Services HALLIBURTOlt Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -37 - Slot ODS -37 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Project: Oooguruk Developement MD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Weil: ODSN -37 Survey Calculation Method: Minimum Curvature Welibore: ODSN -37 PN8 Design: ODSN -37 PN8 wp13 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +EMly Northing Easting DLS Vert Section (ft) ( ?) (bearing) (ft) ft (ft) (ft) (ft) (ft) 6,329.36 11,700.0 89.70 321.41 6,386.9. 6,329.4 3,024.6 - 3,150.5 6,034,090.08 466,731.12 0.00 4,358.64 11,761.0 89.70 321.41 6,387.2 6,329.7 3,072.3 - 3,188.5 6,034,137.91 466,693.28 0.00 4,419.50 Start Dir 3.00/100' 11761.00' MD, 6387.20' TVD 11,763.5 89.63 321.38 6,387.2 6,329.7 3,074.3 - 3,190.1 6,034,139.90 466,691.70 2.90 4,422.03 PN8 v13T4 11,763.6 89.63 321.38 6,387.2 6,329.7 3,074.4 - 3,190.1 6,034,139.95 466,691.66 2.90 4,422.09 End Dir 11763.60' MD, 6387.20' TVD 11,800.0 89.63 321.38 6,387.4 6,329.9 3,102.8 - 3,212.9 6,034,168.48 466,669.06 0.00 4,458.41 11,900.0 89.63 321.38 6,388.1 6,330.6 3,180.9 - 3,275.3 6,034,246.85 466,606.97 0.00 4,558.17 12,000.0 89.63 321.38 6,388.7 6,331.2 3,259.1 - 3,337.7 6,034,325.22 466,544.88 0.00 4,657.93 12,100.0 89.63 321.38 6,389.4 6,331.9 3,337.2 - 3,400.1 6,034,403.60 466,482.79 0.00 4,757.70 12,200.0 89.63 321.38 6,390.0 6,332.5 3,415.3 - 3,462.5 6,034,481.97 466,420.71 0.00 4,857.46 12,300.0 89.63 321.38 6,390.7 6,333.2 3,493.4 - 3,524.9 6,034,560.35 466,358.62 0.00 4,957.22 12,400.0 89.63 321.38 6,391.3 6,333.8 3,571.6 - 3,587.3 6,034,638.72 466,296.53 0.00 5,056.99 12,500.0 89.63 321.38 6,392.0 6,334.5 3,649.7 - 3,649.8 6,034,717.10 466,234.44 0.00 5,156.75 12,600.0 89.63 321.38 6,392.6 6,335.1 3,727.8 - 3,712.2 6,034,795.47 466,172.35 0.00 5,256.51 12,700.0 89.63 321.38 6,393.3 6,335.8 3,806.0 - 3,774.6 6,034,873.84 466,110.26 0.00 5,356.28 12,800.0 89.63 321.38 6,393.9 6,336.4 3,884.1 - 3,837.0 6,034,952.22 466,048.17 0.00 5,456.04 12,900.0 89.63 321.38 6,394.5 6,337.0 3,962.2 - 3,899.4 6,035,030.59 465,986.08 0.00 5,555.80 13,000.0 89.63 321.38 6,395.2 6,337.7 4,040.4 - 3,961.8 6,035,108.97 465,923.99 0.00 5,655.57 13,100.0 89.63 321.38 6,395.8 6,338.3 4,118.5 - 4,024.2 6,035,187.34 465,861.91 0.00 5,755.33 13,200.0 89.63 321.38 6,396.5 6,339.0 4,196.6 - 4,086.6 6,035,265.72 465,799.82 0.00 5,855.09 13,300.0 89.63 321.38 6,397.1 6,339.6 4,274.7 - 4,149.1 6,035,344.09 465,737.73 0.00 5,954.86 13,400.0 89.63 321.38 6,397.8 6,340.3 4,352.9 - 4,211.5 6,035,422.46 465,675.64 0.00 6,054.62 13,500.0 89.63 321.38 6,398.4 6,340.9 4,431.0 - 4,273.9 6,035,500.84 465,613.55 0.00 6,154.38 13,600.0 89.63 321.38 6,399.1 6,341.6 4,509.1 - 4,336.3 6,035,579.21 465,551.46 0.00 6,254.15 13,700.0 89.63 321.38 6,399.7 6,342.2 4,587.3 - 4,398.7 6,035,657.59 465,489.37 0.00 6,353.91 13,722.1 89.63 321.38 6,399.9 6,342.4 4,604.5 - 4,412.5 6,035,674.91 465,475.65 0.00 6,375.96 Start Dir 3.00/100' 13722.10' MD, 6399.90' TVD 13,734.6 90.00 321.43 6,399.9 6,342.4 4,614.3 - 4,420.3 6,035,684.70 465,467.90 2.99 6,388.42 PN8 v13 T5 13,759.4 90.74 321.43 6,399.7 6,342.2 4,633.7 - 4,435.8 6,035,704.16 465,452.51 3.00 6,413.17 End Dir 13759.40' MD, 6399.70'WD 13,800.0 90.74 321.43 6,399.2 6,341.7 4,665.4 - 4,461.1 6,035,736.00 465,427.33 0.00 6,453.67 13,900.0 90.74 321.43 6,397.9 6,340.4 4,743.6 - 4,523.4 6,035,814.42 465,365.31 0.00 6,553.42 14,000.0 90.74 321.43 6,396.6 6,339.1 4,821.8 - 4,585.8 6,035,892.84 465,303.29 0.00 6,653.17 14,100.0 90.74 321.43 6,395.3 6,337.8 4,900.0 - 4,648.1 6,035,971.26 465,241.27 0.00 6,752.92 14,200.0 90.74 321.43 6,394.0 6,336.5 4,978.1 - 4,710.4 6,036,049.68 465,179.25 0.00 6,852.67 14,300.0 90.74 321.43 6,392.7 6,335.2 5,056.3 - 4,772.8 6,036,128.10 465,117.23 0.00 6,952.42 14,400.0 90.74 321.43 6,391.4 6,333.9 5,134.5 - 4,835.1 6,036,206.52 465,055.21 0.00 7,052.18 14,500.0 90.74 321.43 6,390.1 6,332.6 5,212.7 - 4,897.5 6,036,284.94 464,993.19 0.00 7,151.93 14,600.0 90.74 321.43 6,388.8 6,331.3 5,290.8 - 4,959.8 6,036,363.36 464,931.16 0.00 7,251.68 14,700.0 90.74 321.43 6,387.5 6,330.0 5,369.0 - 5,022.2 6,036,441.78 464,869.14 0.00 7,351.43 14,800.0 90.74 321.43 6,386.2 6,328.7 5,447.2 - 5,084.5 6,036,520.20 464,807.12 0.00 7,451.18 14,900.0 90.74 321.43 6,384.9 6,327.4 5,525.4 - 5,146.9 6,036,598.62 464,745.10 0.00 7,550.93 9/25/2008 4:46:01PM Page 8 COMPASS 2003.16 Build 428 • Sperry Drilling Services HALL HALLIBURTOrt Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -37 - Slot ODS -37 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Project: Oooguruk Developement MD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -37 Survey Calculation Method: Minimum Curvature Welbore: ODSN -37 PN8 Design: ODSN -37 PN8 wp13 Planned Survey Measured Vertical Map Map Depth inclination Azimuth Depth TVDss +Nt-S +E/-W Northing Easting ' DLS Vert Section (ft) ( ?) (bearing) (ft) ft (ft) (ft) (ft) (ft) 6,326.11 e 15,000.0 90.74 321.43 6,383.6 6,326.1 5,603.5 - 5,209.2 6,036,677.04 464,683.08 0.00 7,650.68 15,100.0 90.74 321.43 6,382.3 6,324.8 5,681.7 - 5,271.5 6,036,755.46 464,621.06 0.00 7,750.44 15,200.0 90.74 321.43 6,381.0 6,323.5 5,759.9 - 5,333.9 6,036,833.88 464,559.04 0.00 7,850.19 15,300.0 90.74 321.43 6,379.7 6,322.2 5,838.1 - 5,396.2 6,036,912.30 464,497.02 0.00 7,949.94 15,400.0 90.74 321.43 6,378.4 6,320.9 5,916.2 - 5,458.6 6,036,990.72 464,435.00 0.00 8,049.69 15,500.0 90.74 321.43 6,377.1 6,319.6 5,994.4 - 5,520.9 6,037,069.14 464,372.98 0.00 8,149.44 15,600.0 90.74 321.43 6,375.8 6,318.3 6,072.6 - 5,583.3 6,037,147.56 464,310.96 0.00 8,249.19 15,700.0 90.74 321.43 6,374.5 6,317.0 6,150.8 - 5,645.6 6,037,225.98 464,248.94 0.00 8,348.94 15,708.4 • 90.74 321.43 6,374.4 • 6,316.9 6,157.3 - 5,650.8 6,037,232.57 464,243.73 0.00 8,357.32 Total Depth at 15708.430' MD, 6374.40' TVD - PN8 v13 T6 Targets Target Name - hit/miss target Dip Angie Dip Di x +N/-S -W Northing Fasting - Shape (?) (bearin v {ft) `,<; ( ft) (ft) (ft) PN8 v13 T2A 0.00 0.00 6,370.8 640.0 - 1,192.9 6,031,697.75 468,678.82 - plan hits target - Point PN8 v13 T4 0.00 0.00 6,387.2 3,074.3 - 3,190.1 6,034,139.90 466,691.70 - plan hits target - Point PN8 v13 T6 0.00 0.00 6,374.4 6,157.4 - 5,650.9 6,037,232.60 464,243.70 - plan hits target - Point PN8 v13 T5 0.00 0.00 6,399.9 4,614.3 - 4,420.3 6,035,684.70 465,467.90 - plan hits target - Point PN8 v13 T3 0.00 0.00 6,376.7 1,519.7 - 1,949.7 6,032,580.40 467,925.70 - plan hits target - Point PN8 v13 T1 0.00 0.00 6,314.9 -93.1 -675.9 6,030,962.60 469,192.80 - plan hits target - Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (in) (in) 5,000.0 4,652.9 9 5/8" 9.625 12.250 7,708.0 6,314.9 7" 7.000 8.750 9/25/2008 4:46:01PM Page 9 COMPASS 2003.16 Build 428 • Sperry Drilling Services H ALLIBURTO Standard Proposal Report Database: ..EDM_Alaska Local Co- ordinate Reference: Well ODSN -37 - Slot ODS -37 Company: Well Planning - Pioneer - Oooguruk TVD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Project: Oooguruk Developement MD Reference: 44' + 13.5' @ 57.5ft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN -37 Survey Calculation Method: Minimum Curvature Wel'bore; ODSN -37 PN8 Design: ODSN -37 PN8 wp13 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (ft) (ft) ft Name Lithol ( ?) (bearing) 6,524.9 5,893.0 Base HRZ 0.00 2,986.6 2,874.6 Hue Shales 0.00 6,905.7 6,085.2 Base Kuparuk (LCU) 0.00 6,699.0 5,989.9 Kalubik Marker 0.00 1,681.4 1,662.5 Base of Permafrost 0.00 6,809.2 6,043.5 Top Kuparuk C 0.00 5,467.4 5,070.4 Top Torok Sand 0.00 3,495.4 3,324.5 Violet 1 Fault 0.00 2,337.5 2,282.8 Top West Sak 0.00 5,747.2 5,315.2 Base Torok Sand 0.00 4,566.9 4,270.5 Brook 2B 0.00 7,693.7 6,311.2 Top Nuiqsut 0.00 6,339.2 5,774.5 Top HRZ 0.00 3,087.7 2,964.4 Tuffaceous Shales 0.00 Plan Annotations Measured Vertical Local Coordinates Depth Depth +Nj-S aiii (ft) (ft) (ft) , rat 400.0 400.0 0.0 0.0 Start Dir 1.00/100' 400.00' MD, 400.00' TVD 900.0 899.4 -16.7 14.0 Start Dir 2.00/100' 900.00' MD, 899.40' TVD 1,150.0 1,147.1 - 41.7 35.0 Start Dir 1.50/100' 1150.00' MD, 1147.10' TVD 1,616.7 1,600.7 -125.1 105.0 End Dir 1616.70' MD, 1600.70' TVD 1,772.9 1,750.0 -160.1 134.3 Start Dir 0.81/100' 1772.90' MD, 1750.00' TVD 3,127.9 3,000.0 -556.7 467.1 Start Dir 1.50/100' 3127.90' MD, 3000.00' TVD 4,257.9 3,997.7 - 1,040.7 661.9 Start Dir 3.50/100' 4257.90' MD, 3997.70' TVD 5,000.0 4,652.9 - 1,347.3 526.7 End Dir 5000.00' MD, 4652.90' TVD 5,020.0 4,670.6 - 1,353.1 519.4 Start Dir 3.89/100' 5020.00' MD, 4670.60' TVD 7,146.9 6,167.0 -591.9 -465.8 End Dir 7146.90' MD, 6167.00' TVD 7,348.6 6,221.5 -414.6 -544.9 Start Dir 3.50/100' 7348.60' MD, 6221.50' TVD 7,408.0 6,237.3 -361.8 -567.3 End Dir 7408.00' MD, 6237.30' TVD 7,408.0 6,237.3 -361.8 -567.3 Begin 300' ESP Tangent 7,708.0 6,314.9 -93.2 -675.9 Start Dir 5.20/100' 7708.00' MD, 6314.90' TVD 8,145.3 6,371.7 277.1 -896.0 End Dir 8145.30' MD, 6371.70' TVD 8,551.3 6,370.7 591.9 - 1,152.4 Start Dir 3.00/100' 8551.30' MD, 6370.70' TVD 8,621.8 6,370.8 645.7 - 1,197.9 End Dir 8621.80' MD, 6370.80' TVD 9,701.8 6,376.3 1,463.6 - 1,903.2 Start Dir 3.00/100' 9701.80' MD, 6376.30' TVD 9,774.6 6,376.7 1,519.6 - 1,949.6 End Dir 9774.60' MD, 6376.70' TVD 11,761.0 6,387.2 3,072.3 - 3,188.5 Start Dir 3.00/100' 11761.00' MD, 6387.20' TVD 11,763.6 6,387.2 3,074.4 - 3,190.1 End Dir 11763.60' MD, 6387.20' TVD 13,722.1 6,399.9 4,604.5 - 4,412.5 Start Dir 3.00/100' 13722.10' MD, 6399.90' TVD 13,759.4 6,399.7 4,633.7 - 4,435.8 End Dir 13759.40' MD, 6399.70' TVD 15,708.4 6,374.4 6,157.3 - 5,650.8 Total Depth at 15708.430' MD, 6374.40' TVD 9/25/2008 4:46:01PM Page 10 COMPASS 2003.16 Build 428 I MEN 1D I I D4 D4 ® ad - II�X1E1 EgOnaa ' O ra - rag�� I1�YL ®0 BrA/VPIPE , —® MP= I - ©I O Q{ a TANKS - Al 0 . 1 DI ■ 4 MA ► 4 NIL ► AV 4 EMT V -0 arm D4 1u- - �Q OOP w ® O MOT MT O% O Y Y " O 11 Q = ® ' A ' KyO* 2 2 U 0 H 0 MIBIMTOH — i mmix., APO COICIP _ Rate _ Gal /lnln i Q I IC] � Irk' VA ;ol /sik ��w :cei. O E F . � 3 . 0 ® 3 Rls ' " Arl yl ©; " 1i1►P7 ] O IVo ROVI-I K 0 I .i >E NEE RIG ] 11 roc — PIMP VoriableRam9 0 ► ■i I —I- ® �/ .. ■ O vl I — :d�slk 5K ® : DQ Luopus 81 nd ©: 3,i. 4 SHAKERS 0 ® ► ® I® SEPARATOR I I © O �� a 1© IaLL LINE ® M C zi `, O W O 1VLb1 I I Pipe Rens O 5 5 4 � ', ' mapl F. err =Wm men FLOMM TD SWIMS - Woks L r C E N 0 i IwCarwlosuGOM�b�wu43Lr�iFsnuuiww�nra�apwaE ilwor�rtOsaiIRCO�IYwei I% llt 0aaf eAl i6Vr OFlIE. aNfA1 - AWf AILECIIAIEONG►IiWW!♦ ■- -. M w LIRNIM ri 1 ItA WYAMQK# Lla•INII01I17 w Ili new CIIt1at - 44 - NCRNALLY O_CSEO VALVE 7. E9D VALVE 99 SENSOR ANC GUM • == MO= - IM IJUURI'CN HALLIOURSON ENERGY SERVICES 8 Y MANUAL as:KE . -M-- VALVE a1 COPoDLIS murER f REUEF VALVE ii mu l imam =II n Aw al TITLE Plow" MEW Itinewass 8 M ■■■■■■1 Immo... ■IRw mom me mum Cloopruk Elospd Prossin Meg lsc Auma�ee A- HCR VALVE Q9 MIME Min •• ■� II= IN MINI VALVE NUNIIIIENII MAMRAN(W . —.--_■ sae IYNa ��� I■V _ ■ —FS Y■k,�, _ ou 0 -N- CHECK VALVE 1 4- ALE VALVE le MCC LEPER ■■•■• REV. oame nON mg Its RIR IQ •■■■ SUM NONE ,ME.111 I OF i A I B I C I n I I F I n I H • . Installing of RCD Flow Diverter Body: • Lift and place RFD body onto top flange of RIG BOP stack using safest method available to ensure Body & fittings are not damaged. • Nipple up any adapter spools, studded adapters • Install all required valves and flow line components as required. • Install equalization lines as required. • Check alignment of the BOP stack to ensure the stack is in alignment with the Halliburton RFD. • Pressure test BOP to oil company policy.. Installation of Bearing Assembly: • Run pipe into hole two stands off bottom or to company program. • Install stabbing mandrel to bottom of stand, Grease stabber, and stab through bearing. • Lower stand with bearing assembly and through the rotary table. • Lower drill string until bearing assembly is seated properly in the RFD body. • Install oil supply lines • Start up HPU and start drilling. • Change RCD Bearing Assembly Procedure 02/09/2008 • Good communication between the RCD Operator and the drill floor is CRITICAL. Clear instructions must be relayed between the RCD Operator (working on the RCD beneath the drill floor) and the Driller, MPD Supervisor and air hoist operator. • In preparation for changing out a bearing seal assembly, ensure the 6 ft lifting slings, stabbing stand and starting mandrel are all on the drill floor • The RCD 5000 is a passive head, meaning it closes solely on well bore pressure. • It is rated for 3500psi at 5ORPM in a dynamic state and 5000psi in static mode. • To change out the RCD Bearing Assembly the stack should be in a clean and safe working condition with a STURDY WORK PLATFORM from which to work off. NOTE: If the bearing assembly is pulled, but not being changed out, and the forward plan is to re -run it, it must always be positioned at the bottom of a stand for racking back, or removed completely. 1. Position the element in the centre of the top single, and stop rotating. 2. Stop injection. 3. Close the Annular. 4. Bleed off standpipe pressure as per Connection Procedure. 5. Monitor wellhead pressure. 6. Bleed off pressure between annular and rotating head through MPD choke. Bleed off remaining pressure through to Rig shakers. 7. Open bleed valve on rotating head body, to confirm there is no trapped pressure. CONFIRM 0 PSI WITH MPD SUPERVISOR Note: Do not unlatch bearing assembly without checking for trapped pressure. 8. Stop cooling system, and remove circulating and pressure lines on the rotating head assembly. 9. Open clamp on rotating head body. 10. Remove the rotary table split bushing. Note: NEVER Connect lanyard to ANY portion of the RCD Note: NEVER put your body between the RCD and the rotating table 11. Install 6 ft lifting sling on rotating head assembly lifting eyes. 12. Slowly lift drill pipe, tagged line and seal bearing assembly approximately 3 ft above table. Move bearing assembly directly below top tool joint. 13. Reinstall rotary table split bushing. 14. Set drill pipe slips. Remove elevators. 15. Install 18 ft lifting slings thru the bell eyes, hook slings on the rotating head assembly lifting eyes and remove rotating head assembly. 16. Screw top drive into the pipe. Strip out single thru the Annular. 17. Break connection on the first single. Screw starting mandrel on the single. 18. Position bearing assembly into 3 ft by 16" stabbing casing on rotary table next to stump. 19. Lubricate the starting mandrel and inside of rubber, then push the single through the rubber until the mandrel is completely through the rubber. 4 Change RCD Bearing Assembly Procedure 02/09/2008 20. Remove starting mandrel to make up top drive and single to drill string. 21. Pull out of the slips and remove split table bushing to allow the rotating head assembly to pass through the rotary table. BE CAREFUL TO NOT DAMAGE HYDRAULIC CONNECTIONS. 22. Lower the drill string down stopping to position the anti - rotation block RCD clamp. (If this is not in the correct position the clamp can't be closed properly). 23. Finish lowering the rotating head assembly in to the bowl and close clamp. 24. Connect lubricating lines to the rotating head. 25. Restart HCU and confirm differential pressure is 150- 200psi higher than well bore pressure.. 26. Pressure up to below BOP pressure, slowly with the cement pump below the RCD via the primary MPD line. Note: Ensure pressures are equalized on the pressure gauges and they don't exceed rotating head limitations (5000 psi). 27. Inflow test the RCD element, seals and housing. 28. Open the annular. 29. Continue with MPD operations. Well Control Decision Tree "NDICATIONS OF AN UNSTABLE WELL • INCREASED or REDUCED MUD FLOW • PIT GAIN or LOSS • CIRCULATING PRESSURE DROP • GAS or WATER CUT MUD • I s loss GAIN NORMAL Losses down Gain <10bbls, OPERATIO above normal trends Gas <15% r. iNorrnal = +r_ tbblfirl ID • Ghee BOP .• YES - HA OVER • Open Rig Choke HCR mid • Space out tool joint lime up to closed Rig Choke • Shut down. the mud pumps according to MPD YO NABOBS • Observe BBOP fart 0 n�irs procedure & capture friction pressure, utilising MPD choke • Observe RCD Pressure for 10 mitts I Evaluate Kill Method w above On i Off bottom au pres5k�i '*.. b- press . Losses N ON BOTTOM Acx.eptabl NO • Adjust chokes beck pressairrr b SICP NO • Flom check well: d r ,ate t: ut x i g • Lower WHP to previous I t irr elate out YE Pr eso c o star+ Have thc�ra . Fsoav Checic j Kik? .F (Drllers method} bean Irsssas? YES► Resume ciroulatmr, OFF BOTTOM • Circulate battart�s up - dose, monitor - ` flow rate. pit volumes & gas levels I NO Continue • Be prepared to Shut -in on any other °Peratirar s Ref indications of influx Prrx eer to Lost Circrslatir YES Bullhead N decision tree Monitor 8 adjust system °M°YES Well Stable? j as required to investigate r' Evaluate .r` rein stability transferring from Continue Well control to rncxutorirg well MPD NO V stable? • Strip to bottom & Evaluate; • Drilling ahead _► Continue drilling ahead 4 YES circulate out Kick Fork E.valuete further • Bullhead at off Pmr�rp procedures bottom position Mud Weight HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History The following case histories summarise the Underbalanced & Managed Pressure Drilling Projects Performed by Halliburton GBA. In the table below the UBD and MPD projects are summarized which are described in further detail in the following pages. We have worked in 14 countries drilling 234 wells to date. Total incidents over the past 10 years have been limited to 10 reportable. There have been 3 mechanical incidents involving RCD element leak/failure, 6 minor injuries (3 finger, 1 head, 1 knee, 1 rib) all none recordable, and one environmental spill that was contained. Note that none of these incidence resulted in lost time, hindered operations or had environmental impact. We attribute this low incidence rate to HMS /HSE policies /practices and competence of our personnel. • • • Country el Company ....... ....... Field Number of Wells to dalEaStart C End .............. QUBDrMPD C0n/01isFroreRig or CTD Ongoing? • India Reliance Industries Ltd NEC 1 1- Oct-07 1- Dec -07 UBD & MPD Offshore Rig ongoing • . USA American Oil and Gas Powder River•Basin 3 1- Apr -07 1- Feb -08 UBD Onshore Rig End Indonesia EMP Sepanjang Island 2 10- Nov -04 30- Nov -04 UBD Onshore rig End Mexico Pemex (ride, Samaria, Cunduacan, Juj 77 1- Jun -04 1-Aug-08 MPD Onshore Rig ongoing • Mexico Pemex (ride, Samaria, Cunduacan, Jut 12 1- May -06 1- Aug -08 MPD Onshore Rig ongoing • • Mexico Pemex (ride, Samaria, Cunduacan,Juj 34 1- May -06 1-Aug-08 Iv1PD Onshore Rig ongoing Mexico Pemex hide, Samaria,Cunduacan,Juj 3 1- May -06 1- Aug -08 MPD Onshore Rig ongoing • • Thialand Hess Phu Horm 6 1- Mar -03 1- Dec -07 UBD Onshore Rig End • • Austrailia Santos Strezelecki, Marabooka, Delta, 1 4 1- Sep -04 1- Dec -04 UBD Onshore CTD End • Algeria Sonatrach 10 1- Mar -03 1- Mar -06 UBD Onshore Rig End Saudi Arabia Aramco Khurais 1 1- Nov -06 1- Aug -OB UBD Onshore CTD ongoing UAE Margham Margham 5 1- Apr -06 1- Aug -07 UBD Onshore CTD ongoing • UAE BP Sajaa 40 1- Mar -03 1- Mar -06 UBD Onshore CTD End Norway Statoil Gulfaks 3 18-Apr-05 19- May -05 MPD Offshore Rig End • • Norway Hydro Grane 4 7- Jan -08 1- Aug -08 MPD Offshore Rig ongoing Norway Statoil Gulfaks 1 6- Dec -06 , 8- Aug -08 1v1PD Offshore Rig ongoing • Brunei Shell Rasau 3 1- Jul -02 1- Jan -03 UB D Onshore Rig End • • • Indonesia ExxonMobile Arun 8 1- Aug -02 1- Sep -03 UBD Onshore Rig End • • • Indonesia Kufpec Seram 2 1- Mar -02 1- Aug -02 UBD Onshore Rig End • • Malaysia Shell 1 1- Oct -01 1- Feb -02 1_ Offshore Rig End • • Malaysia Shell Si Joseph 2 1- Feb -02 1- Aug -02 UBD Offshore Rig End • Austrailia Santos Barrolka 3 1- Aug -00 1- Feb -01 UBD Onshore Rig End Ilk Portugal Mohave Aljubarrota 1 1- Mar -00 1- May -00 UBD Onshore Rig End • • • Colombia GHK - Tres Pesos 1 1- Dec -98 30- Dec -98 UBD Onshore Rig End • Indonesia Kufpec Oseil 2 1- May -98 1- Oct -98 UBD Onshore Rig End • • USA Bryan Woodbine Oil Co Woodbine sand 5 1- May -97 1- Aug -97 UBD Onshore Rig End • • • Wells Totals 234 • Page 1 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Reliance Industries Ltd No. of Wells: 1 Fields: NEC completed, ongoing UBD and MPD wells Address: Offshore Eastern India Solution: HES MPD System to drill stacked sand HPHT well Range of Services: Feasibility Study, Candidate Selection, UBD Engineering and FEED, Project Management, HSE, Onsite MPD Supervision, MPD Autochoke system, Surface Separation, Data Acquisition with INSITE, . Contact: Ramdass Karavadi Telephone: email: Ramdass.karavadi @r il.com Start Date: Oct 2007 End Date: Ongoing Narrative: NEC -25 -B3 well was drilled utilizing MPD techniques with choke control. Drilling operations where very successful by enabling operator to drill deeper without setting additional casing string. RIL will continue to use this technology on all their wells where similar drilling problems are encountered. Page 2 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: American Oil and Gas No. of Wells: 3 Fields: Powder River Basin Address: Wyoming, USA Solution: HES UBD System to drill fractured sandstone, with high pressure fractures Range of Services: Feasibility Study, Candidate Selection, UBD Engineering and FEED, Project Management, HSE, Onsite UBD 410 Supervision, UBD choke system, Surface Separation, Data Acquisition with INSITE, . Contact: Aaron Miller Telephone: email: Aaron.miller @Hallibu rton.com Start Date: April 2006 End Date: February 2008 Narrative: Three wells drilled utilizing MPD techniques to drill pilot hole and then utilized UBD for drilling lateral in reservoir section RTRE was utilized to determine location of fractures. Gas and condensate were sold on last 2 wells during drilling operation. Incidents RCD element failure, gas vented, but was quickly contained utilizing the annular's within first few seconds of problem, no spills or environmental issues. Page 3 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Energi Mega Persada Kangean Ltd No. of Wells: 2 Fields: Sepanjang Island Address: Onshore Sepanjang Island, one of Kangean Islands, North of Bali, Indonesia Solution: HES UBD System used to Solve Drilling Problems and Formation Damage in Fractured Carbonate Reservoir Range of Feasibility Study, Candidate Selection, UBD Engineering and FEED, Project Management, HSE, Onsite UBD Supervision, Surface Separation, Data Services: Acquisition with INSITE, Tank Farm with Steam Heating, Drilling Fluids, Completion Equipment, Cement Unit, Bits, Sperry BHA and MWD. Contact: Ross Prasser, EMP Telephone: Jakarta Office +62 21 2550 email: Ross.prasser@energi - 4880 mp.com Start Date: February 2006 End Date: December 2006 Narrative: A previous well drilled overbalanced (in 1990) in this slightly over pressured (8.7 ppg EMW) fractured carbonate reservoir had experienced lost circulation problems, resulting in reservoir damage and NPT. The project was particularly challenging as the reservoir produces oil with a Pour Point of 115 deg F. The wells are low GOR at 110 scf /bbl, and Water Cut at 0 %. The wells were drilled underbalanced using flow drilling techniques. The drilling fluid used was initially diesel, which became diluted with native crude oil as the reservoir produced during UBD. The diesel was pre- heated and the crude oil was kept hot, and above its Pour Point, using steam coils in an enclosed oil tank farm. The steam coils were heated using steam generators. Oil produced during UBD was exported into pre installed production facilities and an insulated pipe line. Crude oil had to be heated prior to exporting. The production facilities and 5 km pipe line were preheated using water and a direct fired heater, prior to oil exporting. The oil was then exported down the pipe line to an FSO offshore. Oil pumped down hole had to be cooled using a mud cooler, so as not to damage the rig pumps or Kelly hoses. Pre heated diesel was used to flush all lines and the pipe line after oil flow down any line had ceased. Solids were centrifuged out of the enclosed tank farm, then treated in a lined pit on the island. The wells have an IADC classification of 4B5. The project was a commercial and operational success. Reservoir damage was eliminated, resulting in significant oil production rate improvement. The reservoir produced crude oil with a PI of over 1000 bbl /day /psi during UBD, and after the wells were put on production. Lost circulation and slow ROP problems were solved, meaning the reservoir sections were drilled faster. All produced oil was successfully exported to the FSO offshore during UBD operations. The wells were successfully completed underbalanced. Page 4 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Halliburton IS Pemex Bermudez & Jujo Projects No. of Wells: 126 Fields: Iride, Samaria, Cunduacan, Jujo, & ongoing Tecominoacan Address: Onshore Southern Mexico Solution: HES UBA System (Low Head) to solve Drilling Problems in Under - pressured Fractured Carbonate Reservoirs Range of Services: Recyclable foam products & testing, Surface separation, MPD Engineering, Project Management support, MPD Supervision, Rotating Flow Diverter, Mist pump, Membrane Nitrogen, Cryogenic Nitrogen, Corrosion Control & Monitoring, DAS & real -time data transmission with INSITE, Completion Products, Cementing, MWD /DD. Contact: Avram Lopez Telephone: (52) 9173282100 email: Avram.lopez @hallibu rton.com Start Date IS Turn Key Project: June 2004 End Date: May 2006 Start Date: Discrete Contract May 2006 End Date: Ongoing, 2010 Narrative: Halliburton IS turn key drilling project responsible for large scope of work from spud to completion. 4 Separation (LRT) packages operated in the reservoir section of the 33 wells which were drilled by 7 drilling rigs, in the initial project. MPD services utilized in the pay zone section of the wells to provide a low density, LCM -free, near - balanced fluid system ranging from 2.9 to 7.0 ppg ECD. Fluid systems that were used were a recyclable foam in the 2.9 to 4.5 ppg range and two -phase (nitrogen and drilling fluid without a foaming surfactant) in the 4.5 to 7.0 ppg range. Well depths range from 11,000 to 20,000 ft in the pay zone. High Temperature Recyclable Foam drilling fluid system was a designed & tested specifically for this application in Reforma Mexico & the Duncan Technology Centre. Initially the project started with cryogenic nitrogen which was later phased out by membrane nitrogen injection equipment which lowered costs and provided a more reliable supply of nitrogen. Halliburton now has 4 membrane Nitrogen packages working with the LRT separation packages. Drilling time in the pay zone was reduced by an average of 50% compared to previous wells. Page 5 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Halliburton Discrete Contract drilling project responsible for large scope of work from spud to completion. 4 Separation (LRT) packages operated in the reservoir section of the 44 wells drilled with full Sigma Service (Separator, Choke system, Nitrogen in lower pressure reservoirs, RCD), 12 wells drilled for kick control, 34 wells drilled with RCD and 3 wells with N2 only.. The project is now ongoing and further wells are being drilled using MPD technologies. MPD services utilized in the intermediate and pay zone section of the wells to provide a low density, LCM -free, near- balanced fluid system ranging from low pressures to very high ECD's (2.9 to 8.0 ppg ECD in the low pressure reservoirs and (8 to 18ppg in the high pressure formations) . Fluid systems that were used were a recyclable foam in the 2.9 to 4.5 ppg range and two -phase (nitrogen and drilling fluid without a foaming surfactant) in the 4.5 to 7.0 ppg range and single phase WBM and OBM in the higher pressured formations. Well depths range from 11,000 to 20,000 ft. Incidents: Two RCD incidents due to leak no spill and incident was contained. One environmental incident shown below.. LOC - s ACI Incident Type # INC Date PSL /SS ON DESCRIPCION Environmental 4633 5- Dec -06 SDS Sam While breaking circulation at casing shoe in Samaria 1081, pumping 300 GPM Recordable 73 (UBA) aria of oil base mud and 25 m3 of N2. Sample Catcher's PSV relieved at 60 psi 1081 (it is set at 250 psi), diverting mud to the flare stack, and dumped an estimated of 3.77bbls to the ground. Immediately shut down rig pumps and bypass N2, closing chokes. All operations were stopped to contain the spill, no environmental impact Drilling time in the pay zone was reduced by an average of 50% compared to previous wells. • • Page6of37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: HESS Thailand Limited No. of Wells: 6 Well: Phu Horm 3 drilled in 2003; Appraisal wells Phu Horm 4 & 5 drilled in 2004; Wells PH6, 7 & 10 drilled in 2007 Address: Onshore NE Thailand Solution: HES UBA • Range of Services: Front End Engineering and Design, UBD Engineering, UBD Project Management, Onsite UBD Supervision, Separation System (HRT), Data management (Insite), Nitrogen services, Condensate Tank Farm, Completion Equipment, Reservoir Evaluation, Real Time Data Transmition Contact: Andy Timms Telephone: (66) 2636 1936 Fax: Start Date: March 2003 End Date: Dec 2007 Narrative: HESS drilled conventionally into a marginally over - pressured fractured carbonate reservoir and encountered well control problems while trying to drill the reservoir section. The Phu Horm 3 well was killed and secured until a solution could be found. Halliburton assisted with a design to drill the reservoir section utilizing UBD techniques to control the well while drilling and to eliminate any potential damage to reservoir. After substantial upfront engineering and preparation, the well was safely drilled without any well control problems and resulted in flow rates far exceeding expectations. Subsequent post - completion extended flow tests confirmed a large reserve base with this accumulation. Successful operational and production outcome. Appraisal wells Phu Horm 4 & 5 were successfully drilled utilizing UBA techniques. Real Time Reservoir Evaluation (RTRE) was performed on both wells with outstanding results from the application. The RTRE has allowed for early evaluation on the well before well was TD. This allowed for early project sanctioning by HESS and decreased time line for decision making. Phu Horm 5 produced 40 MMscf /day gas during UB drilling at minimal drawdown. Phu Horm 4 produced 65 -70 MMscf /day during UB drilling at minimal drawdown (has proved to be the largest sustained gas rates in the world to -date for this type of operation). PH 6 and 7 where dry holes, PH 10 was drilled conventionally and was deemed to be damaged and produces 10 mmscfd. Page7of37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Santos, Adelaide Australia No. of Wells: 4 Fields: Strezelecki, Marabooka, Della and Moomba. Address: Cooper Basin, South Australia Solution: Integrated UBD and CTD delivery to reduce unit production cost in depleted tight oil and gas fields by remediation of wellbore damage and increasing permeability by exposing new formation. Identify new opportunities in low quality reservoirs Range of Services: Project Management, Front End Engineering and Design, UBD Engineering, Onsite UBD Supervision, Cryogenic Nitrogen, Twin Panther Pumps, 80k Coil Tubing Rig with 2 -3/8" coil and tower, LRT Surface Separation, INSITE /Scan3 Data Acquisition. Contact: Rick Doll / Kevin Welsh Telephone: email: Start Date: September 2004 End Date: December 2004 Narrative: Four wells increasing in complexity to implement CTD UBD technology in a step wise approach. Strezelecki 14 (gas) underbalanced deepening in low pressure well, production came in above expectation. Marabooka 8 (gas) underbalanced lateral into undamaged formation, exceeded expectations. Della 24 (gas) low angle side track into un damaged reservoir, field record producer Moomba 117 (oil) dual lateral sidetrack into un damaged reservoir, dual casing exit and flow drilled with crude. Page 8 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Customer: Sonatrach (ENTP) No. of Wells: 8 wells plus — MD 352, MD 199, MD 418, MD 10 430, OMM 731, MD 322 & OMO 13 completed. Address: Hassi - Messaoud, Algeria Solution: HES UBA • Range of Services: Contractor for Underbalanced Drilling Services providing short radius directional re -entry sidetracks for increased productivity in existing production wells. Halliburton provided services includes Upfront Engineering and Job Design, Project Management, kick -off and directional sidetrack drilling, MWD and Underbalanced Site Supervision and Engineers, Surface Separation Package, Rotating Control Head, Insite / SCAN 3 data acquisition, Safety System, Nitrogen Delivery, Solids Treatment and Site Storage and Transfer of Produced oil (Tank Farm and Export Pump). Contact: Mohamed YAHMI Telephone: 213 29 73 88 50 Fax: 213 29 73 80 88 Start Date: Commenced; March 2003 End Date: 2006 Narrative: Successfully completed 7 wells of a 10 well programme, with two wells providing record productivity for their areas. No safety or operational incidents. • Page 9 of 37 HALL!BURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Saudi Aramco, Saudi Arabia No. of Wells: Wells: Khurais Field 1, ongoing • Address: Onshore Saudi Arabia Solution: HES UBD, Schlumberger Coil tubing and cryogenic N2, Baker Inteq BHA Range of Services: Front End Engineering and Design, UBD Engineering, Onsite UBD Supervision, INSITE /Scan3 Data Acquisition, UBD Separation System, Choke System, High pressure separation system Contact: Alain Belainger Telephone: Fax: Start Date: 11/2006 End Date: Ongoing 2009 Narrative: Aramco wished to emulate BP and Margham UBD operations conducted with coiled tubing in depleted carbonate gas reservoir. A gas conservation /compression system and high pressure separator allows the produced gas to be processed, recompressed and exported back into the sales line making a significant contribution to maintaining and optimising daily production levels; and also to address and conform to flaring restrictions. Condensate was also processed and re- injected back into the production header maintaining 100% recovery and further enhancing the economic viability of the project. Produced formation and drilling fluid /solid returns were separated, processed and checked for conformity before disposal. In the first well a four fold increase in production was seen compared with previous conventionally drilled and stimulated wells. • Page 10 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Margham Dubai Establishment (MDE) # of Wells to Wells: GAS RE ENTRY PROGRAM — date: 5 Margham Field Address: Onshore - Dubai, United Arab Emirates Solution: HES UBA Range of Services: Front End Engineering and Design, UBD Engineering, Onsite UBD Supervision, INSITE /Scan3 Data Acquisition, UBD Separation System Contact: John Capps Telephone: Fax: Start Date: April 2006 End Date: 8/2007 Narrative: MDE were interested in utilizing the same multilateral re entry approach that had proved so successful for BP Sharjah because there were many similarities and challenges with their gas field. The driver for this campaign revolved around the need to increase gas production from the MDE field to cope with Dubai's ever increasing development / expansion. Dubai's electrical power was being generated via the burning of liquid fuel at approximately 6 times the cost of natural gas. The initial goal was to add 60 MMSCFD to the field's current production with 5 re —entry wells. This goal was significantly surpassed by the first three wells (approx. 75 MMSCFD). This success has led to the recognition of this technology as being an efficient and cost effective method of increasing production without a large capital investment. Phase 1 (5 wells) were completed in Q4 -2006. Phase 2 (5 wells) are being drilled in 2007, and Phase 3 (3 -5 wells) is being evaluated and considered in conjunction with a work over campaign for some of the older wells in the field. This project is a 2 phase (N2 & water) coiled tubing underbalanced multi lateral drilling campaign in a depleted limestone gas reservoir. A gas conservation /compression system has enabled produced gas to be processed, recompressed and exported back into the sales line making a significant contribution to maintaining and optimising daily production levels. Condensate has been processed and re- injected back into the production header maintaining a high percentage of recovery and further enhancing the economic viability of the project. Produced formation and drilling fluid /solid returns are processed in the vertical two stage 4 phase separation unit and checked for conformity before disposal. There have been no lost time incidents since the beginning of this project. Page 11 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: BP Amoco Sharjah No. of Wells: Wells: Sajaa Field 40 Address: Sharjah, Onshore United Arab Emirates Solution: HES UBA Range of Services: Front End Engineering and Design, UBD Engineering, Onsite UBD Supervision, INSITE /Scan3 Data Acquisition, UBD Separation System Contact: Randy Pruitt Telephone: Fax: Start Date: March 2003 End Date: March 2006 Narrative: BP conducted coiled tubing underbalanced drilling campaign in this depleted carbonate gas reservoir. A gas conservation /compression system enabled produced gas to be processed, recompressed and exported back into the sales line making a significant contribution to maintaining and optimising daily production levels; and also to address and conform to flaring restrictions. Condensate was also processed and re- injected back into the production header maintaining 100% recovery and further enhancing the economic viability of the project. Produced formation and drilling fluid /solid returns were separated, processed and checked for conformity before disposal. Over 340,000 feet were drilled in 163 laterals in 40 wells. Average initial increases in production were @ 3 -fold. The project achieved >1.2 million man -hours without a DAFWC. Over 5 BCF of gas was compressed to the plant while drilling! BP discontinued the project 1Q06 to re- evaluate the reservoir drainage patterns. Drilling is expected to re- commence in 2007. Page 12 of 37 HALLIBURTON . GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Statoil - Gullfaks No. of Wells: C -05A, CO9A and C47 Address: Offshore, Norway Solution: HES UBA Range of Services: Halliburton services include Upfront Engineering and Job Design, Project Management, Offshore UBA Supervision and 9 P 9 9 9 1 9 P UBA Drilling Engineering, Surface Separation Package, INSITE / SCAN 3 data acquisition and PLC safety system monitoring downstream UB parameters. Contact: Tim Tennessen Telephone: (47) 51837638 Fax: (47) 51838383 Start Date: Commenced; November 2003 End Date: 2007 Renewed MPD contract started 2007 Narrative: In recent years, increasing difficulty in drilling the Shetland cap rock has prompted Statoil to investigate the use of alternative drilling methods. Over - pressure in the Shetland cap rock has been created by local water injection opening microfractures allowing charging of carbonate stringers that run through the cap rock. The resulting overpressure can run very close to formation fracture pressure. Increasing mud weight to the density required to control the overpressure will result in ECD exceeding formation fracture pressure. If mud density is reduced so that ECD is below fracture pressure, then static fluid density will be below pore pressure and a kick situation can reoccur. An Underbalanced system allows the section to be drilled with a fluid density that is intentionally designed to be below pore pressure allowing the well to flow if abnormally high formation pressure is encountered. • C -05A: UBA of side -track using clear 1.55 sg KCOOH brine • C -09A: MPD of 8 -1/2 "section in the cap rock and 6" section in the reservoir. Using 1.55 sg clear brine, a solids - weighted water -based fluid and a 1.45 sg solids- weighted oil -based drilling fluid. • C47: MPD in 12 -1/4" section in the cap rock using 1.55 sg solids - weighted oil -based mud. Page 13 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Hydro - Grane No. of Wells: G -2, G -1, G -39, G -16 Address: Offshore, Norway Solution: HES UBA Range of Services: Halliburton services include Upfront Engineering and Job Design, Project Management, Offshore UBA Supervision and UBA Drilling Engineering, data acquisition and RCD services. • Contact: Tim Tonnessen Telephone: (47) 51837638. Fax: (47) 51838383 Start Date: Commenced; 2007 End Date: TBD Ongoing Narrative: • In recent years, increasing difficulty in completing the wells on Grane to the planned TD due to instable shale stringers and lost circulation issues led Hydro to investigate further solutions on how to optimize bottom hole conditions. MPD presented by Halliburton was found to be the most viable solution and the summer of 2007 the first well was drilled keeping open over 150m of shale and still being able to complete the reservoir section successfully. Third party RCD services problems occurring delayed project progress until summer of 2008 when a new RCD solution utilizing a passive head operated by HES was introduced on well G -16. The use of MPD to increase length of horizontal reservoir laterals together with Halliburton MLT solutions is expected to greatly increase production from this field. • Page 14 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: StatoilHydro — Gullfaks (Renewed contract) No. of Wells: C -01 • Address: Offshore, Norway Solution: HES Geobalance automated MPD Range of Services: Halliburton services include Upfront Engineering and Job Design, Project Management, design and delivery of purpose build equipment, Offshore Supervision and Drilling Engineering. Contact: Tim Tennessen Telephone: (47) 51837638 Fax: (47) 51838383 Start Date: Commenced; December 2006 End Date: Dec 2010 + 2 Advanced automated MPD years equipment Narrative: • In recent years, increasing difficulty in drilling the Shetland cap rock has led StatoilHydro to utilize UBD /MPD services from Halliburton to gain access to certain reservoirs as described above. The need for full underbalanced services was not present as the produced fluid was primarily water and reservoir production and permability is so high that keeping a slight overbalance while drilling the formations was adequate to achieve all the customer objectives. • Currently new advanced automated control MPD equipment will be implemented on the C -01 well in November 2008. Page 15 of 37 HALLIBURTDN GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Brunei Shell Petroleum No. of Wells: 3 Wells Rasau 34, 39 & 40 Address: Seria, Onshore Brunei Solution: HES UBA Range of Services: Halliburton services included Upfront Engineering and Job Design, UBA Supervision and UBA Drilling Engineers, BRT 4 • phase separation unit, Rotating Control Head, INSITE / SCAN 3 data acquisition and PLC safety system monitoring all downstream UB parameters. Imported third party downhole and mud logging data for single source data base and monitoring of all UBA data, crews and technicians, base oil supplement, tank farm and shaker equipment / solids control, gas compression. Contact: Mike Ward Telephone: (67) 3 337 2785 Fax: Start Date: July 2002 End Date: January 2003 Narrative: A three -well underbalanced drilling trial was conducted in the Rasau shallow oil field, located onshore in Kuala Belait, Brunei (first ever UBD in Brunei). UBD was chosen to reduce or eliminate formation damage normally experienced using traditional drilling methods in this field (typical skins of +80 -100 on conventional wells). Native crude and field gas were chosen as the drilling fluids, thereby increasing the complexity of the operation as well as equipment requirements. The target reservoirs were shallow (circa 1800m) thin, stacked, inter - bedded sand /shale units. The program was to drill high - angle, sub - horizontal wells cutting through the many sand layers to maximize formation exposure. The stability of the inter - bedded shales caused significant problems due to "borehole breakout" and collapse (one well could not be drilled UBD). The 1 well in the campaign (where the reservoir pressure was highly depleted) and the 3 well (where up to 60% of the drilled section was shale) were expected to be at greater risk. Production rates observed after drilling to TD and prior to running completions indicated zero formation impairment and higher than anticipated Pi's. Post completion well tests indicated productivity reductions of 60 to 70 %. These reductions were attributed to mechanical problems incurred during the completion and near wellbore impairment (hole collapse or screen plugging). The wells are now on production and are being evaluated for long -term benefits. The pilot project showed UBD potential; a regional borehole stability study was subsequently conducted to establish criteria and further candidates for UBD in this area. Page 16 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Exxon Mobil Indonesia No. of Wells: 8 C111— 16C, 5A, 16B, 17 CIV —16, 2A, 22, 6A Address: Arun Field, Sumatra, Onshore Indonesia Solution: HES UBA • Range of Services: Halliburton services included Upfront Engineering and Job Design for surface separation systems and equipment which consisted of BRT 4 phase separation unit, Automatic Choke control, PLC chokes control, SCAN 3 data acquisition and PLC safety system monitoring all downstream UB parameters. Performed single source data base and monitoring of all UBA data. Contact: Chuck Reibi Telephone: (62) 21 574 7070 Fax: Start Date: August 2002 End Date: September, 2003 Narrative: This formation in the Arun field is a highly productive and highly depleted (2ppg) carbonate gas reservoir. The main reason for drilling underbalanced was to increase production. Additionally, due to the depleted pressure it was not possible to drill conventionally with a full fluid column. Halliburton designed and built a high flow rate UBA process package to be able to flow the wells while drilling with minimal pressure drop through equipment; using core design criteria from existing UBA packages and changing to fit for purpose equipment. Gas production targets were met after drilling only 6 of the planned 10 wells (total of 8 were drilled). Production results were 46% higher than the expected UBD results. The wells were drilled in record time allowing for a substantial decrease in cost to drilling operations. No LTI's or first aid cases were recorded over the 1.57 year project. Non- Productive Time (NPT) during the UBD operations accounted for just 0.9% of total well time. • Page 17 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Kufpec (Indonesia) Ltd No. of Wells: 2 Wells Oseil 2 and Lola Kecil 1 Address: Seram Island, Onshore Indonesia Solution: HES UBA Range of Services: Halliburton services included Upfront Engineering and Job Design, UBA Supervision and UBA Drilling Engineers, BRT 4 phase separation unit, Shaffer Rotating Control Head (PCWD), Insite / SCAN 3 data acquisition and PLC safety system monitoring all downstream UB parameters. Imported third party downhole and mud logging data for single source data base and monitoring of all UBA data, crews and technicians, base oil supplement, tank farm and shaker equipment / solids control. Contact: Simon Shaw (Drilling Telephone: (62) 21 766 2840 Fax: (62) 21 766 2845 Manager) Start Date: March 2002 End Date: August, 2002 Narrative: The Oseil field is an under - pressured, fractured carbonate oil reservoir. The crude contains high wax and H2S content and is prolific where macro fractures are encountered. Conventional wells were damaged and experienced massive fluid losses. Osiel 2 was side tracked with a 7" liner set in top of carbonate reservoir section. It was then drilled underbalanced utilizing native crude oil and Membrane generated N2. The well initially flow approx 1000 BOPD. After intersecting macro fractures in the reservoir, the well was completed after flowing 10,000 BOPD. Kufpec are planning an addition 15 UBD well program to increase their production to a meet market demand by late 2004. • Lola Kecil 1 (exploration well) - was drilled to 6000' dry and was P &A'd Page 18 of 37 • HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Sarawak Shell Berhad (SSB) No. of Wells: 1 El 1 -SC2 Address: Sarawak, Offshore East Malaysia Solution: HES UBA Range of Services: Halliburton provided a wide scope of services for this integrated offshore underbalanced drilling program, including Project Management, upfront engineering, planning, well design, Site Supervision and UBD Engineering, Advanced four - phase separation & Data acquisition system, Electronic PLC Based Surface Safety Shut -in System, Rotating Control Device, Cryogenic Nitrogen Injection, hydraulic workover (HWO) Snubbing and Security DBS's Near Bit Reamer (NBR). Sperry-Sun provided MWD /PWD /LWD and directional drilling services. Additionally, Halliburton supplied real -time data transmission to Shell's local office in Miri (via INSITE ANYWHERE) a nd ultimately provided Reservoir Analysis while drilling, using a proprietary analytical model developed specifically for this application. Halliburton's new downhole isolation valve called the "Quick Trip Valve" (QTV) was also run to facilitate the deployment of Expandable sand screens into the well without having to perform a well -kill. Contact: Jan Terwogt Telephone: (60) 85 453 972 Fax: Start Date: October 2001 End Date: February, 2002 Narrative: The E11 -SC2 Shallow Clastics Underbalanced drilling project included many industry firsts, such as; First offshore UBD well in Malaysia, First run of the QTV offshore and first UBD well using a tender assist Drilling Rig. The Shallow Clastics formation is a normally pressured gas reservoir with moderate permeability. The well was drilled underbalanced to maximise well production through impairment reduction. The well was drilled utilising a nitrified water based drilling fluid. The well was evaluated to have resulted in 2.5 times increased production from the conventionally • drilled well in the same formation. Further Field Development is being evaluated utilising UBD technology. **This UBD well was designed, executed, and completed on a fast -track program in less time than any one previous Shell (Global) offshore UBA projects ** Page 19 of 37 HALLIBURTDN GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Sabah Shell Petroleum Company (SSPC) No. of Wells: 2 St Josephs H3 & H5 Address: Sabah, Offshore East Malaysia Solution: HES UBA Range of Services: Halliburton provided a wide scope of services for this integrated offshore underbalanced drilling program, including Project Management, upfront engineering, planning, well design, Site Supervision and UBD Engineering, Advanced four - phase separation & Data acquisition system, Electronic PLC Based Surface Safety Shut -in System, Rotating Control Device, Gas Compression, solids control and storage system, zone rated oil injection pumps and all control and interface systems to link all of the UBD equipment together. Sperry-Sun provided directional drilling services. Additionally, Halliburton supplied real -time data transmission to Shell's local office in Miri (via INSITE ANYWHERE) and ultimately provided Reservoir Analysis while drilling, using a proprietary analytical model developed specifically for this application. Contact: Jan Terwogt Telephone: (60) 85 453 972 Fax: Start Date: February, 2002 End Date: August, 2002 Narrative: These two wells were drilled and completed underbalanced from a small jackup rig. This was the first offshore application of crude oil and hydrocarbon gas injection as drilling fluid in jointed pipe operations conducted in the Asia Pacific region, and was successfully carried out without any HSE incidents. The St. Josephs "H" Sands are depleted sandstone / shale layered formations. Conventional drilling resulted in formation damage (average +5 in horizontal wells). Prior to the UBD campaign, a geomechanical study suggested a moderate to high risk of borehole instability would be expected while drilling underbalanced in these shallow sands. The 1st well was drilled partially overbalanced due to borehole stability concerns. No problems were experienced during • the drilling or completion operations in this well. Due to the mitigation of borehole stability risk, the second well was drilled fully underbalanced, and was evaluated to have 50% higher than expected production. Further Field Development is being evaluated utilising UBD technology. Page 20 of 37 HALLIBURTQN GeoBalance Applications: Underbatanced and Managed Pressure Drilling Job History Client: Santos Oil Pty. Ltd No. of Wells: 3 Wells: Barrolka 4, 5 and 7 Address: Barrolka Field; Cooper Basin, SW Queensland, Onshore Australia Solution: Lead UB Contractor Range of Services: Halliburton services included Upfront Engineering and Job Design, UBA Supervision and UBA Drilling Engineers, BRT 4 • phase separation unit, Shaffer Rotating Control Head (PCWD), lnsite / SCAN 3 data acquisition and PLC safety system monitoring all downstream UB parameters. Imported third party downhole and mudlogging data for single source database and monitoring of all UBA data, crews and technicians, base oil supplement, tank farm and shaker equipment / solids control. Halliburton also provided reservoir evaluation of the underbalanced drilled section in Barrolka 5. Contact: Jim Carr Telephone: Fax: Start Date: August, 2000 End Date: February, 2001 Narrative: This three -well underbalanced drilling pilot program featured one vertical and two horizontal wells using base oil as the drilling fluid. The normally pressured sandstone gas reservoir was characterized by tight -gas sandstone and matrix permeability of 0 -1 md, and random higher permeability crevasse splay sand lenses throughout. The reservoir also had coal sections above and below. The plan was to drill horizontal wells underbalanced to maximize possibility of intersecting the higher permeability lenses while protecting the formation from near wellbore damage. Conventional wells were sub - economic. Four (4) air drilled vertical wells produced 1 -3 MMscfd but had experienced problems with downhole fires and wellbore stability. Barrolka 4 - The program for the first well was to drill a vertical pilot hole to determine the location of coal sections and run logs to enhance the geo- mechanical model. A vertical sidetrack was then drilled underbalanced into the reservoir. • This first well would also provide the opportunity to proof test the new underbalanced drilling 4 -phase surface- separation system and crews, provide training for the drilling crews, and observe the skin damaging effects of the base oil on the reservoir. At the same time, this would provide an opportunity to review whether there were significant added complications of drilling a directionally complex, high angle well. During the wireline logging operations on the pilot hole, the coal seam underlying the reservoir collapsed, making it impossible to run the logs over most of the reservoir. As planned, the well was cement plugged back, and then an 8% -in. vertical sidetrack was drilled conventionally (sidetrack Page 21 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History and main bore being separated laterally by 70 ft). A 7 -in. liner was then run and cemented, and the underbalanced section was then drilled out with a 6 -in. bit. The underbalanced hole section was successfully drilled from 8483' to 8567' thereby proving the mechanical integrity of the system and process. Unfortunately, no significant gas sections were encountered through this short, vertical section. Barrolka 5 — was the first horizontal flow - drilled well in the field. Due to coal instability and washouts, the 7 "casing could not be run to planned depth and was set high (i.e; above the main target). The well was then underbalance drilled horizontally into the upper secondary zone. Due to drilling motor failures and steering problems in the horizontal section, three open hole sidetracks were drilled. Ultimately, 1,517 feet of reservoir in the well was drilled underbalanced. The new advanced four -phase UBD Separation system was able to successfully manage all returned fluids /solids while • drilling this well, and was subjected to instantaneous rates of up to 50 MMscf /day gas and 25,000 BOPD during well surges at various stages of the operation. This well was also used as a test case for Halliburton's latest generation of a new UBD reservoir- modeling tool. The modeling indicated that contrary to general consensus the reservoir section did not appear to consist of relatively long lengths of net pay, but rather production was from a few point sources of high permeability along the length of the reservoir section. The well was completed as one of the field's only economic wells at 1.5 MMscfd. Barrolka 7 - This third well location was chosen in an area of the field considered to be less fractured and subject to lower stress variations. The main technical objective of this well was to drill a mechanically and operationally successful horizontal well. This was fully achieved, and ultimately, a total of 1706 feet was drilled underbalanced. The well did not encounter any commercial zones and produced only at marginal gas rates. The UBD project was considered an operational success, however due to geological uncertainty in the field, the program was discontinued. Santos are presently reviewing feasibility of performing a Coiled Tubing UBD pilot program in another field in 2004. • Page 22 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Mohave Oil and Gas No. of Wells: 1 Well — Aljubarrota 3 (exploration) Address: Aljubarrota Field; Alcobaca, Onshore Portugal Solution: Integrated Solutions • Range of Services: Halliburton services included Project Management, Upfront Engineering and Job Design, UBA Supervision and UBA Drilling Engineers, Sperry Sun Electromagnetic MWD, LWD, DWD and Mudlogging, Insite Command Unit and technicians, Tools and Testing sensor package on N2 injection equipment . Also responsible for co- ordinating third party services such as separation package, drilling fluids, nitrogen injection services, rotating heads, DBS Drill Bits and BHA Equipment. Contact: Mike Stern Telephone: (1) 713 975 1725 Fax: Start Date: March 2000 End Date: May 2000 Narrative: Vertical well, drilled in carbonate formations, Drilled well underbalanced from 17 ' /2" section. 17 1 /2" drilled with N2 foam @ 2 — 3 ppg until a water influx was taken at 135m, section completed with water. 12 ' /:" section drilled with N2 aerated water UB system @ 5 — 7 ppg, drilling near balance. 8 %" section drilled with foam until water influx taken at 1075m, drilled to TD overbalanced with water. Well TD @ 2480m, no gas shows / production over entire well. Operational success. Page 23 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: GHK Company Columbia No. of Wells: 1 Well — Tres Pasos 1W Address: Guaduas Field Rio Seco Block; Onshore Columbia, S. America Solution: Lead Contractor Range of Services: Halliburton services included directional drilling systems, MWD, LWD, Geosteering, cementing, testing and UBD project personnel. Also responsible for co- ordinating third party services for drilling fluids, air drilling services, drill bits and nitrogen services. Contact: Gary Wallen Telephone: (57)(1) 629 -1580 Fax: (57)(1) 629 -5637 Start Date: December 1998 End Date: December 1998 Narrative: After setting 9 -5/8" casing at 5958', installed 4500' of 7" casing (concentric string), drilled 9 -5/8" shoe with 6 -1/8" bit, tripped for UBD assembly and drilled a lateral with 8.5 ppg brine down the drill string and nitrogen injection in the micro - annulus. The lateral was drilled to 10,780' MD and 6,286' TVD. During the drilling operation, the well produced 5363 Bbls of 21 API gravity, sweet crude and a total of 12.9 MMCF of gas. A two -phase separator and oil- skimming system were utilized. Oil was transported by truck, and the gas was flared. Successful operational and production outcome. • Page 24 of 37 HALLIBURTQN GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Kufpec (Indonesia) Ltd No. of Wells: 2 Wells — Oseil 2 and 4 Address: Oseil Field Seram Island, Onshore Indonesia Solution: Integrated Solutions 411 Range of Services: Project Management and Lead Contractor for underbalanced services. This included supply of rotating control diverter, choke manifold, four -phase separation system, air compressors /nitrogen membrane units, enclosed H2S oil storage tanks, solids separation equipment and flare system. Contact: Ian P. Moyle Telephone: (62)(21) 766 -2840 Ext.15 Fax: (62)(21) 766 -2845 Start Date: Commenced UBD, Oseil 2; May, 1998 End Date: Completed UBD, Oseil 2; July 1998 Commenced UBD, Oseil 4; Sept, 1998 Completed UBD, Oseil 4; Oct, 1998 Narrative: The purpose for conducting UBD operations was to prove up reserves discovered on Oseil 1. Oseil 1 had been drilled overbalanced and experienced up to 30,000 Bbls of drilling fluid losses (under - pressured fractured carbonate zone). On Oseil 2 and 4, after drilling out of 9 -5/8" casing the wells were drilled and cored underbalanced in 8 -1/2" hole, starting with nitrified diesel and finishing with nitrified sour crude oil. The wells were then tested with considerably higher PI's ranging between 200 -700 Bbls /psi (16 API gravity, sour crude). Successful operational and production outcome. • Page 25 of 37 HALLIBURTON GeoBalance Applications: Underbalanced and Managed Pressure Drilling Job History Client: Bryan Woodbine Oil Corporation No. of Wells: 5 Wells 36 -H, 29 -H, 48 -H, 38 -H & 1 -H Address: Bryan Woodbine Unit; Brazos County, Onshore Texas, USA Solution: Integrated Solutions • Range of Services: Project Management; provided all services including rig to re -enter and plug -back existing wells, mill window, sidetrack with lateral(s) in Austin Chalk utilizing a flow - drilling technique and perform open hole completions. Halliburton was compensated from well production. Contact: Tony Dyson, President Telephone: (409) 776 -0121 Fax: (409) 776 -1312 Start Date: Commenced; May, 1997 End Date: Completed; August, 1997 Narrative: All five wells were non - producers in the Woodbine sand. Project required plugging back in 5 -1/2" casing and drilling a total of eight laterals. Three wells had up -dip and down -dip laterals, and two wells had one lateral only. KOP was at 8600' TVD and utilized a build rate of 30 degrees /100'. Laterals measured from 1900' to 3700'. During drilling operations, gas production of approximately 500 Mscf /day was being sold into an existing gas gathering line and oil was being recovered and transported by truck to the operator's tank battery. Initial production from all five wells was approximately 1400 BOPD of 37 API gravity, sweet crude. Successful operational and production outcome. • I I Page 26 of 37 • • HALLIBURTON Underbalanced Drilling Performance Testimonials c...nlAubil 011 artY.- t- 41 44fal 4/taants 10:10, fklotoo- 62 t ttrtzr T4o4r".> E7 September 17. ;XIX run Biz /Lore 1 ow 17' E>go nMobil Emoi. Cr Ftcuiacuoi: C4C 3?a Pm-I.:Lem! Scr orr.. Teara. 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V•citioo PrrAirrnomt Rale Re-Axed Tix -maim cr rain irtin.:t ii tir rl■ Ora Eir Burr Carnpozip. • The leigrx tare mivee-,11,n& e raze by :ornat 1 eat,: oiier r c. Sam* raipctase: ottributoS 6itatv,tg I.Alse. weer Jre...,' rrtam".=nr.E tarytt 'neat. nye /204.'pentortnitag talt- oareavai 131>D orcratittr,.. We are troorl arA mecLai-aer Yew v1114atar t:ttrzn DU:V. in MAIM this welt; it. 'A glicomme Dig flare '%tI1 :ZS ;r4.1.0rXtpli attC JriI V "fi41,1 / / 1 V" 1 R ht.braart Semi- c.::liarit F40.= liemv tit-Jhvg Opu Sup. Dnibtr Ern.-. Wearer • Page 27 of 37 • • • HALLIBURTON Underbalanced Drilling Performance Testimonials July 3, 2003 Arun Big Bore Drilling Team EMOI Drilling, Production & G &G Staff Daya Turangga /OD &E Personnel Service Companies & Suppliers Dear Team: On behalf of the ExxonMobil Indonesia Onshore Drill Team, 1 would like to congratulate each and every member of the Arun Big Bore Team for the outstanding performance delivered on the Arun CIV - 2a well just completed today. The overall performance on this well and the continuous improvement exhibited from previous wells is truly world class and is undoubtedly one of the highlights for ExxonMobil Drilling worldwide this year. You should be extremely proud of what has been achieved and in recognition of your efforts you will be receiving an Arun Big Bore carry bag as a token of our appreciation. There were several outstanding achievements and the following are a selection of the most noteworthy. • "Incident Free Well" This well was drilled incident free. In fact this well continued to build on the incident free days which now stand at 82. In addition you have achieved 2 consecutive months without an incident of any kind. Our goal is "Nobody gets hurt" and nobody was on the CIV -2a. • Execution of the well from spud to TD and completion in a total of 19.9 days. This is over 14 days (42 %) faster than the previous best which was the CIII -16c. It is important to note that the CIII -16c was a pacesetting well itself earlier this year. The major contributors to drilling time reduction were: 17 -1/2" Interval- New APO record of 3068' in 24 hours Overall Improvement of 2 Days over previous best 10" full string- Resulted in overall savings of 8 days over previous best • Achievement of the highest feet per day progress rate ever achieved in a Big Bore well. At 531 fpd - this is 68% faster than the previous benchmark set earlier this year. • Realization of the lowest Big Bore NPT ever at 0.5 days and below 2 %. • Flawless execution of the drill -in liner and UBD phases of the well We have believed as a team that we could significantly improve our safety and operational performance to a level many believed unachievable. Your tireless pursuit of excellence, exceptionally high safety standards and expectations, and your willingness to continually improve have all contributed to the success that has been achieved. Again, 1 would like offer my profound thanks for a job well done and look forward to what we can achieve on the CIV -22 and the CIV -6a. Charles R. (Chuck) Riebe Drilling Operations Supt. Page 28 of 37 • • • RALLIBURTDN Underbalanced Drilling Performance Testimonials BP Amoco Press Release March 04 on 2 year Extension of Halliburton UBA Contract BP Amoco Sharjah has extended by two years an existing contract for Halliburton's Energy Services Group to provide underbalanced drilling (UBD) services in BP's Sajaa Field in Sharjah, United Arab Emirates. The extended contract capitalizes on the safe and dependable application of underbalanced services already provided by Halliburton. BP recently completed its 10th well in a very successful application of underbalanced drilling in the Sajaa field. A consortium is providing services for the BP project where Halliburton is facilitating the underbalanced portion with its advanced Four Phase Separation System, a key component in the delivery of the Halliburton Underbalanced Applications service. Using Halliburton's technology, well stream fluid returns are processed to optimize use and conform to stringent environmental requirements. Hydrocarbon recovery entails the compression and re- injection of gas and the pumping of condensate into the production line. Solids and produced water, once confirmed environmentally compatible, are disposed of to dedicated land farms. On the project, Halliburton is also using its SCAN TM3 and INSITETM Data Acquisition and Management System, which gathers and processes data from all sources and presents them in a common format throughout the onsite SCAN network system. Randy Pruitt, BP Sharjah Oil Company's drilling manager, said: "BP greatly appreciates Halliburton for the effort in the Sharjah UB CTD program, which has helped BP Sharjah reach the five million man -hours and five years without a DAFWC lost -time incident." "We are excited by the success BP is enjoying in Sharjah and are pleased that underbalanced drilling technology is enabling them to outperform benchmark production values in the field," said Gary Godwin, division vice president, Tools, Testing & Tubing Conveyed Perforating product service line, Halliburton. "Our UBA team has proactively supported a successful safety program led and committed to by BP, and we have been recognized for our leading role. We are also pleased with the opportunity to provide our reservoir- focused approach as the project moves from an initial prototype investigation to a longer term project. As the industry recognizes the value of this reservoir performance- centered approach, Halliburton looks forward to providing UBA services to a wider array of reservoirs such as fractured carbonates, reverse condensate drives, lower pressure maturing fields, and others." Page 29 of 37 • • HALLIBURT 3N Underbalanced Drilling Performance Testimonials Statoil Press Release on completion of Well C - 05A, August 04 New drilling method on Gullfaks Underbalanced drilling technology has been used for the first time on the Norwegian continental shelf to implement a Statoil well on the Gullfaks field in the North Sea. This method was employed to bore through the cap rock in well C -05, which has been drilled from the Gullfaks C platform. The job was done by Halliburton, which has long experience internationally with underbalanced drilling, in cooperation with drilling contractor Prosafe. "Oil worth about NOK 1.2 billion is unrecoverable from Gullfaks with conventional drilling methods," explains Johan Eck - Olsen, project manager for underbalanced operations in Statoil. Now that we've succeeded in applying this technology, the accessibility of these reserves could help to extend the producing life of the field." A second underbalanced well is due to be drilled from Gullfaks C later this autumn. The new technology is needed because the upper section of the cap rock in the Shetland structure has fractured as a result of water injection. Since the difference between pore and fracture pressure is small, drilling this rock with conventional methods would be difficult. During regular drilling, a well is filled with heavy mud which creates a downhole pressure higher than the formation pressure to prevent any inflow of water, oil and gas. Underbalanced drilling uses a lighter mud, giving a downhole pressure below that of the formation being drilled. This allows formation fluids to flow into the well in a controlled manner. The fluid can then be collected and conducted to the platform's process facilities during the drilling phase. in the longer term, adopting underbalanced technology could allow us to get more resources out of fields like Kvitebjern in the North Sea," says Mr Eck - Olsen. "This development comes on stream during the autumn, and its reservoir pressure will have sunk so much after just one year that underbalanced drilling could be appropriate." He adds that Statoil is looking at international opportunities for using the technique to optimise recovery and producing life on fields it operates in such countries as Algeria and Iran. By Bente Bergfay Miljeteig Published 24/08/2004 10:05:00 Copyright © Statoil. Page 30 of 37 • • HALLIBURTON Underbalanced Drilling Performance Testimonials 2003 Press Releases FOR IMMEDIATE RELEASE: July 7, 2003 HALLIBURTON TECHNOLOGY USED TO COMPLETE FIRST UNDERBALANCED DRILLING PROJECT IN THAILAND HOUSTON, Texas - Amerada Hess recently completed the Phu Horrrr 3 Sidetrack well in northeast Thailand using Halliburton's (NYSE: HAL) underbalanced drilling technology. Utilizing Underbalanced Drilling (UBD) technology was a first for Thailand. The primary objective of implementing UBD was to drill the well safely while maintaining pressure control and minimizing the severe fluid losses experienced while drilling the over - pressured reservoir section of the Phu Horm 3 well. Other objectives were to reduce formation damage and to be able to evaluate productivity and reservoir characteristics as the well was drilled. As part of the UBD contract, Haliiburton's Underbalanced Applications (USA) group provided upfront engineering and site supervision, including USA drilling and reservoir engineering, and a highly trained team of on -site underbalanced drilling specialists and operators. Other services Halliburton provided include cryogenic nitrogen, the uniquely designed Four Phase Separation System, SCAN" and INSITE" Data Acquisition and Management system, condensate handling and storage, gas flare system, completion equipment and ancillary equipment such as downhole gauges and non - return valves. "We are delighted to support Amerada Hess on this very exciting project," said Gary Godwin, division vice president, Tools, Testing & Tubing Conveyed Perforating, Halliburton Energy Services. "Using Underbalanced Drilling technology enabled Amerada Hess to successfully drill the Phu Horm well. This would not have been possible using conventional drilling techniques and confirms that this technology has real application in drilling fractured carbonate reservoirs of this type. The future potential for growth of USA in the international arena is very promising, as more and more major operators start to discover the significant benefits of this technology in terms of production enhancement, accessibility of incremental reserves, and the reduction or elimination of drilling problems." Halliburton Energy Services, a business unit of Halliburton, provides products, services, and integrated solutions for oil and gas_ exploration, development, and production. Capabilities range from initial evaluation of producing formations to drilling, completion, stimulation, and well maintenance - for a single well or an entire field. With more than 300 service centers in more than 100 countries, Halliburton possesses the global perspective that is increasingly important for energy exploration and production. Halliburton, founded in 1919, is one of the world's largest providers of products and services to the petroleum and energy industries, The company serves its customers with a broad range of products and services through its Energy Services Group and Engineering and Construction Group business segments. The company's World Wide Web site can be accessed at www.halliburton.com. Contact Zelma Branch zelma. brancht5ihalliburton.com Public Relations (p) 713.759.2601 Page 31 of 37 • • • HALLIBURTDN Underbalanced Drilling Performance Testimonials 2004 Press Releases FOR IMMEDIATE RELEASE: May 3, 2004 HALLIBURTON WINS SIX E &P MERITORIOUS ENGINEERING INNOVATION AWARDS HOUSTON, Texas - Halliburton (NYSE:HAL) announced today that it has won 6 E &P meritorious engineering awards for 2004. Bin Pike, editor in chief for E &P presented the awards today at the Offshore Technology Conference in Houston. "These awards represent the hard work and cedication of Halliburton employees and our commitment to staying at the forefront of technology development," said John Gibson, president and chief executive officer of Halliburton's Energy Services Group. "It is an honor for Halliburton technology to be recognized year after year by this prestigious committee. This is another example that our employees are hard at work developing solutions to ensure a sustainable future." Halliburton technologies won in several categories. Halliburton's DrillAhead® services won in welibore construction systems. Halliburton's G- Force" precision- oriented perforating system won in completions equipment. Halliburton's MicroPolymer; service won in completions systems. Halliburton's Underbalanced Applications reservoir analysis service won in subsurface characterization and analysis systems. Halliburton's Water Web" treatment services won in production equipment. Landmark Graphics` ProMAGIC'" system won in exploration systems. "The receipt of a E &P Meritorious Engineering Award marks a company as a technological leader in the upstream oil and as industry. The award program, now in its 33rd year, is judged independently by a panel of recognized industry experts who rank the technologies tor their potential to improve efficiency, cost effectiveness, safety, and technological progress in upstream operations. Previous award winning technologies have been instrumental in the continuing technical and economic success of the upstream industry," said William Pike, editor -in -chief of E &P. DrillAhead services provides fully engineered solutions that can help increase welibore pressure containment by creating flexible stress cages around the welibore while sealing natural and induced fractures and fissures. This new technology can help a welibore contain pressures higher than the natural fracture gradient of the formations through which it is drilled, and DrillAhead services engineering analyses, predicting achievable increases in wellbore- pressure containment, can be used to design treatments that help optimize well plans to reduce casing and liner installations. The new technology can be used to improve leakoff tests and save time regardless of whether there is a mud channel or a weak zone at the casing shoe. DrillAhead services' Widen the Mud Weight Window' '' concept can help eliminate drilling casings or liners, which will result in deceases in both well construction costs and lost time. Unlike cement squeezes, which require tripping the drill string out of the hole, DrillAhead service treatments are designed to run through the bit. Eliminating tripping further reduces rig time and can decrease accident exposure for the rig crew, There is no waiting time for DrillAhead sealants to set, and drilling operations can continue immediately. The G-Force precision - oriented perforating system is an internal orienting gun system that is able to go through restrictions not possible with older systems. It can align perforations in deviated and horizontal wells in a controlled manner, greatly enhancing productivity potential from perforated intervals. Because the orienting rotational devices in the G -Force precision - oriented perforating system are inside the protective environment of the gun carrier, the orientation device does not need to overcome friction forces imposed by the casing. Eliminating multiple orientation subs increases shot efficiency to more than 90 %. Because verification can be made when shooting only one gun with all exit holes on a oiven gun alioned, successful perforation orientation can be confirmed, eliminating the need for post - perforation loosing. The Halliburton MicroPotymer® (HMP" ") service provides a premium water -based fracturing fluid that can be easily reciarmed and reused multiple times, dramatically reducing the need for water supply and disposal. Reusing HMP'" fluid recovered by flowback helps relieve the water supply and disposal problems because the same fluid is used on successive stimulation jobs. Because of its robust nature, HMP fluid enables successful fracture stimulation of historically difficult -to- fracture reservoirs. Excellent cleanup, about twice as efficient and effective as conventional fluids, is achieved without the use of gel breakers. Field results_ demonstrate that effective fracture lengths can increase three- to five -fold over fracture lengths resulting from the use of conventional fluids. Fracture - length increases usually make significant increases in production rates and reserves. Ultimately, HMP service may help increase the world's reserves by enabling more hydrocarbon production at lower cost. Halliburton's Underbalanced Applications reservoir analysis service is a comprehensive engineering process that integrates and sequences surface and subsurface data obtained during underbalanced drilling and then evaluates this data to characterize the reservoir and yield valuable production data such as productivity index and permeability. Measurements are taken from Ha lliburton's advanced data acquisition system, which acquires data, compiles and processes information, and submits the data for transmission. Halliburton's state-of-the-art, four -phase separation equipment and downhole equipment provide the data. This "testing while drilling" methodology yields important reservoir information that can greatly change reservoir knowledge. Halliburton is creating a process to test wells during the drilling phase based on data obtained while drilling and from testing designed to fit into the underbalanced application. Reservoirs not considered sufficiently economic to merit testing are automatically tested during the drilling phase, giving an abundance of reservoir knowledge to the asset manager. WaterWeb service uses unique polymer chemistry to help create oil- water separation in the reservoir, impeding Pace 32 of 37 • • i HALLIBURTDN Underbalanced Drilling Performance Testimonials water at the source and enhancing hydrocarbon flow to the welibore. The resulting improved oilioas recovery potential stems from a reduced water column giving improved natural lift for the residual oil andior gas. In addition, it helps justify prolonged and sustained production by enhancing reservoir drainage. WaterWeb service works by adsorbing onto the rock surface, reducing permeability to water seven to ten times more than it does to hydrocarbons. in effect, WaterWeb service creates a barrier that holds back water while allowing oil and gas to pass freely. PrcMAGIC software application links the functionality of the ProMAX® seismic data processing system to the GeoProbe® 3D volume visualization and interpretation system. This application maps the additional dimension of pre -stack seismic data into an interpretation environment for the first time, integrating the tools and technologies of • two historically independent G &G disciplines to enable more accurate seismic processing results. ProMAG1C software makes it possible for ceoscientists to simultaneously view terabytes of data from various perspectives or domains to identify complex geologic trends, destructive noise patterns, or anomalies that could potentially go undetected in a conventional seismic processing workflow. ProMAGIC system integrates the visualization speed and precision of the GeoProbe volume interpretation system with the processing algorithms of the ProMAX 3D seismic processing system, eliminating barriers to rapid and accurate prospect generation. The E&P Meritorious Awards for Engineering Innovation, established in 1971, honor the world's best new tools and techniques for finding, drilling, and producing oil and gas wells. Entries are judged on their innovation of concept or resign, their ability to solve a real, practical oilfield problem and their potential for improving profitability, safety, or efficiency. The judging committee is composed of experienced industry personnel from around the world with respected engineering backgrounds and oilfield expertise. Halhburton, founded in 1919, is one of the world's largest providers of products and services to the petroleum and energy industries. The company serves its customers with a broad range of products and services through its Energy Services and Engineering and Construction Groups. The company's World Wide Web site can be accessed at www.halliburton.com. Contact Beverly Scippa hcvcrly. sc ippa(±lhal t i bunon.com Public Relations (p) 713.759.2601 • Page 33 of 37 • 4111 • • HALLtBURTON Underbalanced Drilling Performance Testimonials 2003 Success Summary for overbalanced benchmark occurred in a near - balanced operation. Near balance does not by design, achieve Underbalanced Applications underbalanced pressures throughout the pay interval and therefore does not offer the potential to success as does true underbalanced operations. Underbalanced Applications Continues Setting Records, Out of five projects, three or 60% of the reservoirs Receiving Commendations were re evaluated for increased reserves due to much higher than expect production rates (up to 10 fold higher) coupled with significantly reduced decline rates. This increase in reserves estimates for Kent Ostroot, Global Business Manager, UBA. 60% of the projects has lead a lot of asset managers Ron Hyden, BD Marketing Manager, UBA to take another look at UBA. Industry Adoption Cycle Halliburton's Underbalanced Applications team Observing the growth of a new product in our continues to set records and receive accolades industry can be an interesting lesson in the common for lowering cost, increasing production, and characteristics of our oil field operators. This is meeting safety goals. Since becoming a Sub- particularly true for underbalanced drilling. Each PSL offering, the UBA team has been involved operator begins the tendering process with the goal of in major success stories involving both fully achieving the lowest price, but a significant issue managed project services as well as in areas quickly arises with the safety aspects involved. where UBA provided discrete equipment Operators at this stage of development look to a services. service provider with a proven safety record. As mentioned before, Halliburton UBA has an excellent record to show and that has an impact on service Safety First provider selection. In some ways it is a minimum The most impressive lesson ]earned by the requirement to be allowed to entire the service Halliburton UBA team is the value of great selection process. equipment, extensive engineered planning, and expert Next comes the requirement to reduce drilling personnel. These three items have lead to a costs, usually associated with a reservoir where consistent track record of safety that has been conventional drilling techniques make the recognized multiple times in 2003 by multiple construction of a competent wellbore all but operators. The UBA team has received special impossible. While these are good opportunities, they bonuses paid directly to personnel paid by the do not necessarily take full advantage of what operating companies as well as multiple letters of Halliburton's UBA process could do to positively commendation from such operators as ExxonMobil impact an operators bottom line. Nevertheless, and BP. This in spite of the fact that 3 times this year Halliburton UBA did indeed receive multiple the UBA team experienced sustain production rates commendations for reducing the overall Non of over 40 mmscf /d being produced up the back side Productive Time associated with drilling by using while drilling operations were underway. Make no underbalanced techniques to avoid the common • mistake, the UBA team was properly humbled by the problems of stuck drill pipe and uncontrolled fluid experience. But as we close out the year, our UBA losses. In one case, the records set were broken by crews are justifiably proud of the fact that every one each of three successive wells. The overall drilling of the high end Class 5 wells performed in the last 18 curve summary is presented in Figure 1 below. months were done by Halliburton. Latest Scorecard Results In the most recent 5 projects where UBA provided full project management as well as equipment, the operators experienced 6 out of 7 wells (86 %) where production exceeded the conventional overbalanced benchmark in their respective fields. In these campaigns three production records were set in as many different countries. The one failure to beat the Page 34 of 37 . • 0 HAL.L.IBURTDN Underbalanced Drilling Performance Testimonials Days vs Depth including Hallibunon, the project was kicked off on P Hn in early Drilling operations s pro the gressed hu sonmoothly 3 ear as scheduled 2003. to first cut of pay. -- 0 -20 Mar 92) 1 — I 21re2) 1 The initial upper pay horizon previously deemed non - ■ -•- C0.90 l0.se2) PP er P Y P rev Y -- Crv20 (Sep 92) i commercial began contributing significant flow rates 2.000 7 4 ' — C111.17 0,092) i — CIII.10 1,." : as flow - drilling progressed. Upon entering the — C111.20 (Mar93) j 0.000 " - 0,18 (May 95) i secondary pay objective the production rates — C1V.721.1109 93) 1 De (Jun 92) st abilized at 45 mmcf/day with a minimal reservoir 4.000 •---' C3-1613 (Jul 02) '1 zone 5•0102) drawdown. The target one was completed o en ^ C3-5R (Dan 02) 1 g P P ..� . i ..... ..............................._... ......_......._...............' :;5" hole. . ; I/mdle5) — "= 2A """°" 6.000 The success of this well has now opened the door € ° to a new $ 200 million five year development plan for b 2.000 $ p� 1 the Phu Horm field. This development could also 4444 ' lead to a major pipeline project by the Electric i 'r I A . Generating Authority of Thailand to transport the gas eaa. `' y from Phu Horm to the generating plant at Nam 10..00 . . Phon __ g Li t �, The Underbalanced Applications (UBA) approach by Amerada Hess and Hallibunon produced a total . \ i— reservoir solution that was made possible by an omo ...............at.»5« 4444. ...............,.....; .......................... ......... integrated delivery of underbalanced services along 11.6 days from 5°"° 1 with exclusive separator technology developed "'°°° specifically for the underbalanced environment. The 15000 p 40 e. 00 w 11. results yielded an underbalanced well construction process that provided all the traditional benefits while Days from spud offering the operator extremely useful information Figure I and knowledge about the reservoir that would not After meeting the overall drilling objectives which otherwise been available. • usually were the basis of the underbalanced project, The standard approach to underbalanced well the impact on production rates begins to garner construction allows: significant visibility. As mentioned in the scorecard • Reduce formation damage during the drilling and summary above, operators are having great success completion phase on underbalanced campaigns when they rely on • Increase future reservoir recoverables by 30 to Halliburton's UBA team provide and insure a true 50% underbalanced environment throughout the pay interval. In the case illustrated by the drilling chart of • Increase ROP by up to 50% or more Figure I, record production rates were achieved even • Increase value by producing hydrocarbons while though the well was in the lowest pressured section of drilling the reservoir! The reservoir pressures experienced • Reduce lost - circulation costs were below 50 bar. In one of the most impressive • Reduce risk of lost -in -hole equipment cases this year, the production outcome effected not • Reduce rig time associated with sidetracking only the operators bottom line, an entire country The Phu Norm project raised this approach one received a direct benefit. level by offering a reservoir analysis solution while drilling underbalanced. Thailand Power Generation Wildly Successful The Electric Generating Authority of Thailand's Industry Finds the Value 660 megawatt generating plant serving the northeast The industry therefore is exhibiting a clear adoption Udon Thani Province had been cut to 240 megawatts cycle for UBA. Expressed in Figure 2, the cycle due to declining gas supplies in the area. With gas initiates with safety and overall HSE performance supply rates cut from the original 100 mmcf /day to 50 plateau. Next comes the desire to solve an expensive mmcf /day, power generation for the area was in drilling challenge economically. In a surprisingly jeopardy. consistent pattern, the operator yields a successful Amerada Hess chose to evaluate the local Phu production result, usually involving record production Horm field with the unconventional approach of rates. At this point an asset level awareness results underbalanced drilling for the objective of increasing and major field development plans are changed. production potential and increasing reserves. While not allowing Hallibunon to publish some key Working with consulting and service companies well information, Shell Exploration and Technology Page 35 of 37 III 411 • • HALLIBURTON Underbalanced Drilling Performance Testimonials has published in their own external publication, reservoirs, with substantial capital savings as a "Changes" (volume 4 May 2003), a very informative result." This quote says it all. The financial gains quote from Brian Truelove, Global implementation seen by the oil companies have far outstripped the Manager for Underbalanced Drilling. Brian is quoted incremental increase in daily rates for drilling as, "What we're getting is a real -time well test whilst services including UBA vs. without UBA. drilling. which is giving us information we never had Hallibunon's UBA offering is already following before and for several fields this has completely the pattern of classic disruptive technology and the changed the way we go about developing these industry is starting to respond. Figure 2 Maximize Asset Value w e Reservo>Ir = ,AFE Cos HSE Page 36 of 37 11 • • HALLIBURTON Underbalanced Drilling Performance Testimonials Halliburton Published SPE Papers and Articles SPE 59743 — Reservoir Characterization During Underbalanced Drilling: A New Model. SPE 81625 — Comparison of Wellbore Hydraulics Models To Maximize Control of BHP and Minimize Risk of Formation Damage. SPE 85294 — A Safe Approach to Drilling Underbalanced Starts With Project Management. SPE 85319 — Underbalanced Drilling for Production Enhancement in the Rasau Oilfield Brunei. SPE 72513 — New Generation Underbalanced Drilling 4 -Phase Surface Separation Technique Improves Operational Safety, Efficiency and Data Management Capabilities. SPE 90196 — Maximising Reservoir Potential Using Enhanced Analytical Techniques with Underbalanced Drilling. SPE 90185 - Underbalanced Drilling Of Fractured Carbonates In Northern Thailand Overcomes Conventional Drilling Problems Leading To A Major Gas Discovery • • 11111 Page 37 of 37 • • • • . 1. YcLVQY TYPE C 3 1/8'-5000 PSI CA1E WYE • 2. 1kEVOY TYPE C 2 9/18' -5000 PSI GATE'WALLE • • • • CHOKE MANIFOLD SC EMATIC 2 1/16-10000 PSI REMOTE a+aKE 4. 1110 RMILL- CBAYER 3 1/6 -5000 PSI MANUAL CHOKE NABOBS ALASKA RIG 19AC s RANGED TEE 21/16' X 2 t/11 X 2 I/16' -5000 PSI • 6. 5 WAY FIOW BLOCK 3 1 /8' X 3 I /8' X 2 I/16' X Z I /16' X 2 1/16' -5000 PSI • 7. 5 WAY ROW BLOCK-3 1 /0' X 3 1 /8' X 3 I /6' X 3 1/6' X 2 1/18 -5000 P9 • • 3 . 6. 4 NAY Flow BLOCK 2 1/18' X 2 1/16' X 2 1/16' X 2 1/16 -5000 PSI • TQ 9. 2 1/16 -5000 PSI soma 1LOCX • • 10. 2 1/16 1Q000P5I X.2 1/16 -5000 PSI SPOOL • $ E . / 11. 3 1/6' X 2 1/16' -500 SPOOL . 0 PSI SPO . 10 - . T2. 2 T/;5 X 2 1/16 -5o00 PSI SPOOL • • R 13. 3 1/6' -5000 PSI X 2 I /Ir -5000 PSI SPOOL 15 . 14. 2 1/16' - 10.000 PSI X 2 1/16' -5000 PSI 000BLE SAD ADAPTOR 2 15 15. 2 1/16' -5000 PSI Dam FLANGE )1 • 16. 3 I/8' -5000 PSI TARGET RANGE • 3 , - 20 © : 17. 3 1 /6' -5000 PSI X 2 1/16' -5000 PSI DOUBLE SAD ADAPTOR I& 3 1/8' X 3 1/8 5000 PSI SPOOL P�lC Illitil • 19. 3 NAY FLOW BLOCK 3 1 /B' X 3 1 /8' X 3 1/6' -5000 PSI Ne $4) I, ' 20. 5 WAY FLOW BLOCK 2 9/16' X 2 9/16' X 2 9/18' X 2 9/18' X 2 9/18' -5000 PSI ! op • • i 3� TO • ' •� , is � .• F R ©� 4>. / g c\ 13 © . • . . . : --,_ . 0 .....-..- 6 0 --,,,,,,,ei,; c„:i00006 , • 1 1 . . ; . e 3° • • d d • • 1 • i .....�_ ,.....ate,,; ,.,...a, • . NABORS RIASKA R4 'RAC . PORE NAREOLO SCRERROC • 09/0 is MOM NO MORD O. y, LiliihrMillialMr.ji - .w it °X` 7 norm Ili .24 .w. 09 • ooce t w L • • • • • • • • . f : HYDRIL 11 " 5k PSI • I • ' • CK ANNULAR 80P -us i 3' -11i" FLANGED BOnQM C NGT CONNECTION 47 3/4 LEH • ---- - - - - -� - -- 11' 5000/' y ., FLA NGED HYDRIL • 4 -7 • DOUBLE GATE PREVENTOR • 13' -10' 3' 1/8 50001 HC VALVE - ------- - - -• -- _ 55" LENGTH 1 . .1 3 1/8" 5000/ NCR VALVE • N Ma ■ i KILL LINE 1 , - 3 CHOK LNE�._ = Agi,i L iit . 411 , 411 „, r - - - - -� K - ---- • i i . 3 1/8' 5000/ GATE VALVE - 3 5000] GATE VALVE • HYDRIL 11" 5k PSI 3'_ - -- - -- . • HYDRAULIC RAM SINGLE GATE • FLANGED CONNECTION r 1 5 41 3/4 LENGTH i . • . NABORS ALASKA RIG 19AC . . BOP STACK CONFIGURATION • • • s • IM 6 .,,�OI�I. m :" • I : III we= NY�0f5 4JI fl C I1rC • • i i 00 FOL. -QUI NEItwI�t IO Spot (OAfQ It PL'3Q7� m ®�qo mo a eta • �a tae 4 • an I Mt .w AO+ I.(' -YON • O • !; • 1 , 1 '— 1 Io �1 Sil 1111; \ 4 II 12 ur a. I . � _ VC; MP 1 t 1 1; 4 . . . , 1 1 1* ----.. f .- — — 0 i 4; 1 11 i 0 o . : Al 1 I ti Y' " III i K " ; 1 ill r iii! I , ! • W . . . . . . . •*. . . . 1 . ' • , ...- . . . . . . . • . . . . . • . . L. . Legend . 4, • • 1. t • I. • ...7.. . . As —butt Conductor si win* - v ". . 0 , • • . • . . ,..z. 1::.,. . rts‘... . - i• • . .. • . ° 5 ..• .} 0 . a . • e . • A • ,to, 4 : . . to •• • • • • • fP ..44...‘1 • 1 • 112. ... is C l. . is.. 1 . • • • . . .. • . • 4 • ' . 4 • : . . . • , • 41 I; • iiiiir liell \ • • Location Mop • •P . •tt • • GRAPHIC BC= • . , • 1 so SS 0 30 • , ;; ,. .. % 701 q 4Vin ioh . . 1 ;1 4 &pct.,. ' • ... . • • • (mown) . N u • . • • ? ... • • 4 . ... 4 1 :i: 4 1 16 i • , •4 •• .. ....I- 1 . $ 4... •• a - e 440 • h • ; • 4) • 4. ' .3 a *l • •P • • 44, • . % • 413 '. 0 • • fees Al f / •••••• i I • 4 • • . . /001 • • 4° • . ot A l i r.• 0 • • ....1 . • 0 , • . to • tr,..; % Iliii G. Davis . . • • 4 No.4110 I • rt IP,. •._ ••• t .,_ ... og 4 • • 4; i h cO , 4) . P • 4• • : • ' ■ v: `• 41. its • .. 0 . ■■••.......• .0 . • • it. . : , P • • . • .e • ., 4 • . . • it . '' Iti.* . • • • • 0 : . • • • • • 0. i i ti, Al '. 4-": ,. . •2. i Of • • • v. t 4, • • • ,p . - • • • i s - .•. • . •- . • . . ! IP 1 : . Planner Natural RO•014044 . JOB NAME: oeopuruk Dal Ma I DRAWN BY: si. !CHECKED BY: I4JD • LOCATION: Protracted Section 31 • SCALE: 1 • Township S3 Marti? : Range 7 Ease.' i DATE: 7-12-07 • . limed. Meridian ii . NA: •4UQ JOB NO. SKEET . Coordinates are listed an shoots 3 and 4i DESCRIPTION: Alaska Mad 27. Zone 4 Canduatar Aa—built Plan I 05204 1 ol 4 1 . 1 I ' • . . • .. I . ' . . • . , , . • ' • • • • \ • 1 — 3 . I - 1 . co . . •1 1 -cc 1 z 1 • a • • s 1 • 1 1 •doirtact Faun ' i • i . S orner o ul 000a.JR X SITE Protracted Section 11 w .• A o n • - 1 1 . it Cor din a t es 1 . .. I /..% N 60281 I 47 i 1 E 4 /* • •.• g I' • . . e l 11-. 254 • • . . Ref. AK BLM = }- 1 • . re - • • N Nisa. . Harrison. Bay Tract! "A" cord Drcwi . 1: . 1 \\‘• hie r ----- . z . f s' ' ri .. ...7 - • i-r-12.0 n i • 0 • • ps--`sz -.), 6,,,. • ''' 4 : r.-- .-- --''' r la l e k. % C`th-hore Ictroce.-!....9.9 saes !Of s ‘... - r Sh I Doi 3.82 • s, I Pi 20 ie Doe,cvrak Dts 1• • P1 7 io P. ,.. •:t ) a Vr. •% . \ NNE t si d r all ‘, ' - 111 - 17 D uri S dr° S j • • Roods to' WO : i Pi■ . , 1 1){..1§ . _ 111 . .4 1 Ff. S ' . rr co ! • ... .,...... : ,,.........g,.., , p . ; :,L - • . . L Basis of Location • . - • . 7 • . DS-3H West Monument \ i l 0 ..... f . IC ■ Coordinates , Addill1111 Mit i • b ir \ i 1 34-316,... .. N 6001016.61 ILINIMMEnummionmimmIllI - . :—)--- . -, E 496081.23 • STAKED P1 INFORWAllON ON 1 — -...:,-r :4 1 . . . ...3 ;Is . - t . i . . *!,:..;_____ . "iEri ‘: Ref. Lownsbury & Assoc. • D : , . . v Drawing No. • cc • • NSK 6.01-c1672 . -............. , ...... ......... ... ; ....... ...... ..4 j , l ... 4 . .• ••• # w i ■• CO .? - v i *O" - %V • ./"Iri al. * a.. •a.0 • •• • • 0 ..., . .7 41allatr3.9 ,.... , jectIV.'• . it • sea. 0 . • • • b " 100101111. : $ ' r...:*3+17421,4:,..4,...- -a.c.,-,D tY.Y..L 0 I, 110 G. Davis •, 1• :5, Ne. 4110.5 /eV % N 1 ii.... . ow • I - &A„, ••...... „,„„" ----.=z--- , 4 % ff., orasionAty .... -.............■ Pioneer Natural Resouces • JOB NAME: Ooogui Drill Site Conductors DRAWN 6Y: BL I CHECKED BY: MJD LOCATION: Protracted Section 11 SCALE: N/A Township 13 North • Range 7 Eost DATE: 7-12-07 Umiot Meridian • NANUQ JOB NO. SHEET DESCRIPTION: Basis of Location 05204 • 2 of 4 • . . • • _ . WeIl 111101. aitude (N) - L-crli: `.' • 0 - X - 1 5,081,10,82 469,920,45 70 29 40 150 14 45,40 8035 1077 18,80 IWIEM 5481,146A 4.0,916,.2. 70 40:1W.* -- 100 14 3.030 1062 13,50 MEM 5,031,14i 7 1504T-4 3025 1 - 0 - 5 - 7 -7----- 1 - 360 4 ,. 6,081,4 469,905,67 7029 45.0455 '15014 40:89799 - 3020 ---- 18.00 • - 455,900,74 ' 70 29 46,04588 100 1440,04202 301 1097 13,50 111111M11 4 69,89580 10 2945,99660 • 150 * I - 4 - 14 - 6 - ,1 . 675 wo ---- 1°2 1350 * MN 6,031,113,73 09,55 02970 150 14 45 - - 29.'97 1115 13,50 8 5,08110071 - 6•9 -- , - 6 - 7 - 5 - :21 71) 29 45,a:102 150 14 40,70303 2992 1120 •13 • 0 6,081,108.70 4 70 294577164 150 14 40.54014 2987 1125 - 18,50 '10 6:081,091179 - 409,86585 - 70 2040,722.56 150 140,99179 29821l30 - 18,50 MEI 5,081,098,84 469,808,89 70 29 45,67895 • 1601447137'0 2977i135 18,50 • . - analtatlia • • .1_,..08 :. irmazuri 1 - 0 irii7:26I771 2972 1140 13,50 •1.11 6,081,076,05 409,545,5T 7029 45,49040 100 1447.05215 2950 1152 13,50 1111M - - 400.50,57 70 29444982 . 100 14 41,79770 2955 ---1 1157 13.50 .110111 608006-15 - 409,885,96 70 29 45,4000$ 160 14 47,94105 2950 1162 13,50 le 6,031,061 )8 - 40;831 , 01 - - - 70 29 45,851.4 . 160 1445,0805 2945 1167 13,50 1111111M1 6,031006,25 469,626,11 70 29 40,80277 1 14 4528042 2940 _ 1172150 - 1111M11 - 5,031 ;06 ---- 46.9,621 ,9f - 1429 - 45,26809 150 14407495 2935 1177 • 13,50 19 6,081 ,085,02 409,505.00 70 29 40,12768 150 14 45,74666 2922 1159 13,50 - 20 6,03 4.60,808,00 70 29 45,0761 . 100 14 459001 2917 1194 1 Mall 6,051,025,58 409,70,62 - 70 29 - 100)44 - 9,08032 2912 1198 18,60 • 6,0 1,023,05 - 469,798,67 70 29 44,9014 100 14 49, 2907 1204 13,50 25 6,081,015,57 - 409,755,76 70 29 44,98057 100 14 40,82037 2902 .: 1200 1350 • 24 - 6,031,018,00 409.788,64 70 29 44,55159 100 14 40,40960 26e - 1214 13,50 • ...-a"Z OF AQII • ' • Ar ...... ‘ 5,- Its . .. .... .. .. ....... . .. . . IFAI ge :WA % P • "4 * •••• ,-, -. if As I t . Philip G D Ovis 4 i "1 4 4 0-5 : -it.° • t od, . No. 11 0 . 4 t . a r : .4 . 1 . !:;ALtin; : " -- . i ;' " 4 4 6 7' 0 •,.... ..... ` '* m. ::•i - .:.. t u At 1 "' Air ‘‘•%,114,.•■•■•"4"P :ii7 .- . is ..Z:` # 4' 1410.2; • ‘4.4 V" ".!. is rieyotions ore biased on VP meon • .. - 2, Coordinotes ore tosed Qn Alc.5kci Sicte Pine Nod 27, Zr 4, 3. AO conductors ore within Protrocted Section 11, Pioneer Nicivrel Resoudes JOE NAME: OcogurLA Drill Site C9n0Yet9rg DRAWN BY: 0 t. CHECKED BY MJD LOCATION: Protrocted Section 11 SCALE: N/A Township 13 North Ronge 7 Et • DATE: 7.-12-07 Vrniot Meridian -------- -. " NANUQ JOE3 NO, SHEET • DESCRIPTJOi■ii --- -v.- ----------- -- As-built Coordinotes 05204 3 of 4 w i► • • Alaska Stete Plane • ' Section Line Offset _ - Well -No. Y -- X = IFet41434e - cooiludf- - FSL FEt- mad -E-I - 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 2 . 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 150 14 45.50137 2988 1079 13.50, 31 6,031,090.65 . 469,906.38 70 29 45.64431 150 14 45.87163 2975 1092. 13.50 32 6,031,085.68 469,901.39 70 29 45.59523 ' 150 14 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 15014 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 0 2950 1116 13.50 • ,13 - 4C9,8E5. • 7 7 . 1 1 1 9 13.50 .� • 38 6,031;047.99 469,864.14 70 29 45.22304 0 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 4 0 6,031,038.10 4E9,854.21 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 . 6,031,005.53 489,821.86 •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 2944.70469 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 '..` 11 % SURVEYOR'S CERTIFICATE • _ -- :.. •+±1p- .•`•' I HEREBY CERTIF TH A 0.111 f . -7...i s'9 1 PROPERLY REGtSTEREtf ANIS � " - ` _ i ,, 4 : T ; * l . LICENSED TO PRACTICE LAND . •F - / SURVEYING 1N THE STATE OF .� . '= • • • • .... ALASKA AN0 THAT TH•tIS PLAT " ' � T-, (% � vim•". '��{'s:w. rs+' T REPRESENTS A SURVEY DONE BY - e nip G; Dovia o I a ka ,.r r! J 1 No. a1 104 a''. ■ ME OR UNDER MY SUPERVISION . :.E- W , � ` E . . •.. . AND THAT 1 BELIEVE THAT ALL r G = I -••- . -I . d DI ME NSIONS AND OTHER DETAILS � �'- .. ' 1���,,��..a ARE CORRECT AS " SUEMITTED TO , = _ r� ' • ME BY .NANUO, INC. AS OF JULY 1211-i, 2007. Pioneer Notura! Resouces JOB NAME:' Oocguruk Drill Site Conductors DRAWN BY: BL I CHECKED BY: MJD. LOCATION: Protracted Section 11 SCALE: N/A Township 13 North Range 7 Eost DATE: 7 -12 -07 • Umiot Meridion . • NANUQ JOB NO. SHEET DESCRIPTION: • • As- -built Coordinates 05204 4 of 4 • Page 1 of 3 Maunder, Thomas E (DOA) From: Vaughan, Alex [AIex.Vaughan @pxd.com] Sent: Tuesday, October 14, 2008 2:14 PM To: Maunder, Thomas E (DOA) Cc: Polya, Joe; Franks, James Subject: RE: ODSN -37 Tom, We will not be using swell packers on ODSN -37. Alex Vaughan Operations Drilling Engineer PIONEER NATURAL RESOURCES 907.343.2186 (office) 907.748.5478 (mobile) 907.343.2190 (fax) From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Tuesday, October 14, 2008 1:40 PM To: Vaughan, Alex Cc: Polya, Joe; Franks, James Subject: RE: ODSN -37 What about ODSN -37? From: Vaughan, Alex [mailto:Alex.Vaughan @pxd.com] Sent: Tuesday, October 14, 2008 1:30 PM To: Maunder, Thomas E (DOA) Cc: Polya, Joe; Franks, James Subject: RE: ODSN -37 Tom, Currently the answer is no. We are not planning on use swell packers on ODSK -41. Alex Vaughan Operations Drilling Engineer PIONEER NATURAL RESOURCES 907.343.2186 (office) 907.748.5478 (mobile) 907.343.2190 (fax) From: Maunder, Thomas E (DOA) [mailto:tom.maunder @ alaska.gov] Sent: Tuesday, October 14, 2008 10:13 AM To: Vaughan, Alex Cc: Polya, Joe; Franks, James Subject: RE: ODSN -37 10/16/2008 Page 2 of 3 • Alex, et al, One further question, will swell packers be employed on the liner? Tom From: Vaughan, Alex [mailto:Alex.Vaughan @pxd.comj Sent: Monday, October 13, 2008 2:44 PM To: Maunder, Thomas E (DOA) Cc: Polya, Joe; Franks, James Subject: RE: ODSN -37 Tom, Please see answers to you questions below. Alex Vaughan Operations Drilling Engineer PIONEER NATURAL RESOURCES 907.343.2186 (office) 907.748.5478 (mobile) 907.343.2190 (fax) From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Monday, October 13, 2008 12:37 PM To: Vaughan, Alex Cc: Polya, Joe Subject: ODSN -37 Alex, I am reviewing the permit application for this well and have a couple of questions. 1. In the cover letter, desiring a diverter waiver (as on other recent wells) is listed however in the actual operations steps it says NU and function test diverter. Is a diverter waiver desired? This was an over site on my part, We would like a diverter waiver for ODSN -37. 2. Is it intended to bring the 7" cement up into the 9 -5/8" surface casing? It is stated that the intended TOC is 500' above the Torok disposal interval, however that will bring the cement into the surface casing. If this is accomplished, it is unlikely that you will be able to freeze protect the annulus as directed in step 16. Later this week you will receive an Application for Sundry Approval to move the surface casing setting points for ODSN -37 & ODSK -41 from 5000' MD to 3000' TVD. We extended the surface setting depth for ODSN -45i due the extended reach well path. Thus allowing us to use friction reducing tools while running intermediate casing through the surface casing (ex: Caledus Ezee Glider Centralizers). Additionally, due to limited supply of 8 5/8" expandable casing we wanted to hedge our bets if required to use it, ensuring that we had enough length. These measures are not required for ODSN -37. Therefore, the surface setting depth for ODSN -37 will be moved to 3128'MD / 3000'TVD 3. What type of liner be run? It is stated that the liner will not be cemented which usually implies a slotted liner, however on the wellbore drawing the liner is noted to be solid. We will be using a solid liner with perforated pup joints for use with fracturing diversion techniques. 4. In the interest of reducing the paper volume, it is not necessary to include all the references for MPD. For future permit applications, it is appropriate to eliminate the 37 pages of Halliburton job histories. Absolutely, we will leave this out in the future. I look forward to your reply. Tom Maunder, PE AOGCC 10/16/2008 • TRANSMITTAL LETTER CHECKLIST WELL NAME �Dp (� /-644 254/- 77 t'T D# -fs7 Development, Service Exploratory Stratigraphic Test Non - Conventional Well FIELD: Le lr'L -C lam- POOL: AZ, / D; / t 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 fora new welibore 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 togs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non - Conventional Please note the following special condition of this permit: Well production or production testing of coal bed mejhane is not allowed for (name of well) until after (Comoanv Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Comnanv Name) must contact the Commission to obtain advance approval of such water well testing program. Rev: 1/11/2008 WELL PERMIT CHECKLIST Field & Pool 000GURUK, NUIQSUT OIL - 576150 Well Name: 000GURUK NUQ ODSN -37 Program DEV Well bore seg ❑ PTD#: 2081570 Company PIONEER NATURAL R SOURCES ALASKA INC Initial Class/Type DEV / PEND Geo Area 973 Unit 11550 On /Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached _ NA 2 Lease number appropriate _ Yes Entire well in AOL 0355036 3 Unique well name and number Yes 4 Well located in a definedpool Yes 000GURUK, NUIQSUT OIL - 575150,governed by Conservation order No. 597 and AIO No. 34 5 Well located proper distance from drilling unit boundary Yes CO 597 specifies no restrictions as to well spacing except no pay open within 500' 6 Well located proper distance from other welts Yes of external property line. of external property line. Well will be >2000' from exterior boundary of 7 Sufficient acreage available in_drilling unit Yes Oooguruk Unit. 8 If deviated, is weilbore plat included Yes 9 Operator only affected party Yes 10 Operator has_appropriate bond in force Yes 11 Permit can be issue¢ without conservation order Yes _ Appr Date 12 Permit can be issued without administrative approval Yes SFD 10/7/2008 13 Can permit be approved before 15-day waft Yes 14 _Well located within area and_strataauthorized by_injection Order # (put 1O# in_comments)_(For_ NA 15 All wells_within 1 /4mile_area_of review identified (For service well only) NA • 16 Pre - produced injector; duration of pre production less than 3 months_ (For service welt only) _ _ _NA 17 Nonconven, gas conforms to A$31.05.030(0 .A),(j_.2.A -D) NA Engineering 18 Conductor string provided Yes 19 SurFace_casing_ protects all known USDWS NA Surface location is offshore. No known_USDWs. 20 CMT circulate on conductor & surf csg _ Yes 21 CMT_vol_ adequate to tie -in long string to surf csg No _ 22 CMT will cover ail known_ productive horizons No Pre - perforated liner planned. 23 Casing designs adequate for C,_T, B &_ permafrost _ Yes 24 Adequate_tankage reserve pit Yes 25 If a re- drill, has a 10 -403 for abando nment been approved NA _ 26 Adequate wellbore separation proposed Yes Proximity analysis performed, Traveling cylinder path calculated. Gyros possible in surface hole, 27 If diverter required, does it meet regulations _ NA PXO filed surface hole _information _& seeks a diverter waiver. No issues identified drilling prior wells. Appr Date 28 Drifting fluid_ program schematic & equip list adequate Yes Maximum expected formation pressure 9.8EMW._ Managed pressure drilling planned with - 9.2 ppg and applied TEM 10/22/2008 29 BOPl=s,_do they meet regulation Yes pressure to give ECD between 10.5 and 12,5 EMW. 30 BOPE_press rating appropriate; test to_(put psig in comments) Yes MASP calculated at 2547 psi. 3500psi_BOP test planned. 31 Choke_ manifold complies w /APiRP -53 (May 84) Yes _ 32 Work will occur without operation shutdown No Surface section of 3 wells will be batch drilled._ Time off well should not be tong. • 33 Is presence of H2$ gas probable No H2S has not been reported in offset wells. Rig equipped with sensors_ and alarms. _ 34 Mechanicalcondition of wells within AOR verified (For service well only) NA Geology 35 Permit cart be issued _w/o_ hydrogen sulfide measures Yes None expected,,but H2S monitors will be operational. _ 36 Data _presented on potential overpressure zones Yes Expected max. pressure_ is 9.8 ppg EMW; will be drilled using_9.8 +_ppg mud and managed pressure drilling_to _ Appr Date 37 Seismic_ analysis of shallow gas zones NA keep equivalent circulating density between 10.1 and 12.5 ppg as required. SFD 10/7/2008 38 Seabed condition survey_(if off - shore) _ NA 39 Contact name /phone for week_ly_progress reports_ (exploratory only] NA _ Geologic Engineering Public Commissioner: Date: Commissioner: Date Commissioner Date ac2e, 0-22--ae
