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210-032
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, January 25, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Josh Hunt P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Eni US Operating Co. Inc. ODSN-15 OOOGURUK NUQ ODSN-15 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/25/2024 ODSN-15 50-703-20618-00-00 210-032-0 W SPT 5525 2100320 1500 3311 3312 3312 3312 171 180 180 180 4YRTST P Josh Hunt 12/16/2023 I traveled to ODS and met with Mike McDonald and Craig Smith. The hot oil truck was rigged up and ready to go. Discussed the operation and checked the paperwork and gauges. Everything went very well. It was a good test. They were missing a well schematic, I informed them that this is not a request, it’s a requirement to have the proper paperwork ready to go upon arrival. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:OOOGURUK NUQ ODSN-15 Inspection Date: Tubing OA Packer Depth 877 1740 1663 1654IA 45 Min 60 Min Rel Insp Num: Insp Num:mitJDH231216183816 BBL Pumped:1.8 BBL Returned:1.6 Thursday, January 25, 2024 Page 1 of 1 9 9 9 ² 9 9 9 9 9 9 9 9 9 9 missing a well schematic, James B. Regg Digitally signed by James B. Regg Date: 2024.01.25 14:43:50 -09'00' MEMORANDUM TO: Jim Regg. P.I. Supervisor FROM: Jeff Jones Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, January 7, 2020 SUBJECT: Mechanical Integrity Tests Eni US Operating Company Inc. ODSN-15 OOOGURUK NUQ ODSN-15 Ste: Inspector Reviewed By: P.I. Supry Comm Well Name OOOGURUK NUQ ODSN-15 API Well Number 50-703-20618-00-00 Inspector Name: Jeff Jones Permit Number: 210-032-0 Inspection Date: 1229/2019 ' Insp Num: mitiJ200101121443 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well ODSN-15 "'Type Inj G TVD 5525 'Tubing 4133 4134 4135 ' 4135 PTD 2100Type Test SPT Test psi Is00 IA 1089 1672 1632 1623320 " BBL Pumped: 1 ' BBL Returned: I . OA 204 211 211 " 211 Interval arRTST p/p R Notes: I well inspected Tuesday, January 7, 2020 Page l of 1 Wallace, Chris D (CED) From: Wallace, Chris D (CED) Sent: Wednesday, November 13, 2019 8:29 AM To: Lopez Keith Cc: Regg, James B (CED); Rupert Stephanie Subject: RE: ODSK-35A (PTD#2100120) TAA Communication Keith, Extension as requested below for shut in wells ODSK-35A and ODSN-40 is granted. Please add ODSK-35A (PTD 2100120), ODSN-40 (PTD 2080390), and ODSN-15 (PTD 2100320) to the monthly TIO report list that includes AIO 34.009 (ODSN-03) and A1034.010 (ODSN-07) until we get these wells compliant with their MIT's. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallacepalaska gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient (s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Lopez Keith <Keith.Lopez@enLcom> Sent: Tuesday, November 12, 2019 3:07 PM To: Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: Regg, James B (CED) <jim.regg@alaska.gov>; Rupert Stephanie <Stephanie.Rupert@eni.com> Subject: RE: ODSK-35A (PTD#2100120) TxIA Communication The path forward is to perform diagnostics and hopefully repair the leak on ODSK-35A before the end of the year. We currently have an extension on ODSN-15's 4 year MITIA until we have injection water supply back to the island and the well is back online (—January 2020). ENI would propose the same extension for ODSK-35A so we can conduct the MITIA's when the wells are on stable injection. Also please consider: ODSN-40 is a long-term shut in injector that is due for its 4 year MITIA this month as well. Having injection water back is not an issue since the well is a LTSI and the MITIA will be conducted cold. However, being shoulder season it may make logistical sense to have the inspector flown out once in January to witness all three MITIA's. Please let us know if the AOGCC will grant an extension for ODSK-35A and/or ODSN-40 until we have seawater injection back to Oooguruk. Thank you. Keith Lopez Senior Production Engineer Eni Petroleum, Alaska w -wk- cbs:�-15 �ro 21L1c'r Zt: Rr?gg, James B (CED) From: Lopez Keith <Keith.Lopez@eni.com> Sent: Wednesday, August 21, 2019 11:22 AM )Zy ' b/ZI't J To: Regg, James B (CED) Cc: Wallace, Chris D (CED); DOA AOGCC Prudhoe Bay; Lopez Keith Subject: RE: ODSN-15 (PTD# 210-032) Attachments: ODSN-15 TIO 8-21-19.xlsx Attached is the TIO 90 day plot and 30 minute data. Keith Lopez Senior Production Engineer Eni Petroleum, Alaska 3800 Centerpoint Drive, Anchorage, AK 99503 Direct 907-865-3316 Mobile 907-903-5432 Keith. L opez(o)en i. com eni From: Regg, James B (CED) <jim.reR¢C@alaska.eov> Sent: Wednesday, August 21, 2019 10:25 AM To: Lopez Keith <Keith.LooezOeni.com> Cc: Wallace, Chris D (CED) <chris.wallacePalaska.izov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bav alaska.gov> Subject: RE: ODSN-15 (PTD# 210-032) AOGCC grants an extension to complete the required MIT on ODSN-15 (PTD 2100320) until it is back on injection. Please submit a TIO Pressure plot covering the past three months. Jim Regg Supervisor, Inspections AOGCC 333 W.7`h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.reee@alaska.¢ov. From: Lopez Keith <Keith.Looez()eni.com> Sent: Wednesday, August 21, 2019 10:04 AM To: Regg, James B (CED) <iim.reggPalaska.gov> Cc: Tredway Tommy <Tommv.Tredwav eni.com>; Joel Disel d <Joel.DlselrodOcaelusenergy.COm>; Dexheimer Stephen <Stephen.Dexheimer(cDeni.com>; Lyden Dan <Da den eni.com> Subject: ODSN-15 (PTD# 210-032) N 0mw00 S .. • v ,q8 o� •N 0 �p S 88g8g: g8g g8 8 6 8 & I cc 00 9 t I � F G a ■333 8019®m cL(rw� ©ns -J - 15 P� Zie�ay2o Regg, James B (CED) From: Regg, James B (CED) Sent: Wednesday, August 21, 2019 10:25 AM �eq q 617-t/fr To: Lopez Keith Cc: Wallace, Chris D (CED); DOA AOGCC Prudhoe Bay Subject: RE: ODSN-15 (PTD# 210-032) AOGCC grants an extension to complete the required MIT on ODSN-15 (PTD 2100320) until it is back on injection. Please submit a TIO Pressure plot covering the past three months. Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.¢ov. From: Lopez Keith <Keith.Lopez@eni.com> Sent: Wednesday, August 21, 2019 10:04 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Cc: Tredway Tommy <Tommy.Tredway@eni.com>; Joel Diselrod <Joel.Diselrod@caelusenergy.com>; Dexheimer Stephen <Stephen.Dexheimer@eni.com>; Lyden Dan <Dan.Lyden@eni.com> Subject: ODSN-15 (PTD# 210-032) Mr. Regg, Oooguruk currently relies on CPF3 to supply the island with high pressure seawater for injection. CPF3 is no longer able to supply the water to the island and we will have no water injection till late November when our own project is completed to receive seawater directly from STP. All water injectors were shut in and freeze protected on 7/4/19. We have a 4 -year MITIA on ODSN-15 due this month. Would the AOGCC like Eni to conduct this MITIA on the well cold or prefer to grant an extension till December when the well is online? Any guidance would be appreciated. Thank you. Keith Lopez Senior Production Engineer Eni Petroleum, Alaska 3800 Centerpoint Drive, Anchorage, AK 99503 Direct 907-865-3316 Mobile 907-903-5432 Keith. Looez(o)eni. com • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: DATE: Thursday,August 06,2015 Jim Regg3 13/6 P.I.Supervisor �� SUBJECT: Mechanical Integrity Tests CAELUS NATURAL RESOURCES ALASK ODSN-15 FROM: Chuck Scheve 000GURUK NUQ ODSN-15 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name OOOGURUK NUQ ODSN-15API Well Number 50-703-20618-00-00 Inspector Name: Chuck Scheve Permit Number: 210-032-0 Inspection Date: 8/1/2015 Insp Num: mitCS150802184800 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min GDSN-15 Te Inj W' ,TVD 5525 - 1 Tubing 2671 .1- 2762 r 2762 - 2762 PTell'__. Type 2100320 SPT i 1500 971 1990- 1923 1913 Type Test Test psi - IA Interval 4YRTST . P/F P / OA 336 359 358 . L 358 . Notes: CO I SCA Thursday,August 06,2015 Page 1 of 1 Brooks, Phoebe L (DOA) Mit. 2-10039-D From: Keith Lopez <Keith.Lopez@caelusenergy.com> Sent: Thursday, August 06, 2015 11:09 AM To: Brooks, Phoebe L (DOA) Subject: RE: ODSN-15 (PTD 2100320) MITIA 08-01-15 Attachments: Visio-ODSN-15i Final Schematic 2014-04-11.pdf Attached is the well schematic for ODSN-15. Keith Lopez Production Engineer, Subsurface Direct 907.343.2142 I Cell 907.903.5432 Caelus Energy Alaska 3700 Centerpoint Dr I Ste 500 I Anchorage, AK 99503S��f1'1� ' Keith.Lopez@caelusenergy.com I www.CaelusEnergy.com CGCAL1IIS From: Brooks, Phoebe L (DOA) [mailto:phoebe.brooks@>alaska.gov] Sent: Wednesday, August 05, 2015 11:23 AM To: Keith Lopez Subject: RE: ODSN-15 (PTD 2100320) MITIA 08-01-15 Keith, Will you send me the well schematic so I can verify the Packer TVD? Thank you, Phoebe Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you,contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. 1 ODSN-15i Injection Well Final Completion Well Head: 11-3/4",5K,VetcoGray No Caste MD(ft) TVD(ft) Tree: 3-1/2",5K,Horizontal A 16"Conductor 158 lsg B 11-3/4"609 1-80 Hydril 511,10.772"ID 3,589 2,982 C 9-5/8"409 Hydril 521,8.835"ID' 3870 5,301 D 7"268 L-80 BTC-M,6.276"ID"" 11,348 6,165 I ` E 4558 12.609 L-80Hydril 521 17,140 6,117 --11..›. -11 O C) F 3X"9.38 L-80TCII 11,206 6,120 Up,rpe Comn_letion MOJf11 WOOL} 1 VetcoGray Tubing Hanger 34 34 2.813"ID 2 3-1/Y9.21-80TC-IlTubing TRSSSV InstalledHES Wellstar TR5556 w/3%'9.28 TC-I I Box x Pin 9 Chr w/2.813"X"Profile w/1/4"x.049 SS CL 3 to Surface 1995 1870 4 3-1/2"9.2 L-80 TC-Il Tubing ' 5 GLM 81 HES Vanoil 3X"x 1X"Gas Lift Mandrel w/3X"9.28TC-11 Box x Pin 3556 2968 112\ II 6 3-1/2"9.21-80TC-IlTubing • 7 GLM 82 HES Vanoil 3X"x 1X"Gas Lift Mandrel w/37."9.2#TC-II Box x Pin 9199 5437 C51\� 8 3-1/2'9.2 1.80TC-Il Tubing / 9 HES ROC Gauge&Carrier w/3X^9.2#TSHP Box x Pin 9285 5472 O 10 3.1/2"9.21-80TC-IlTubing 11 HES 2.813"X"Nipple 9 Chr w/3X^9.28 TC-II Boxx Pin 9333 5492 GLM#2 DUN 12 3-1/2"9.21-80TC-IlTubing Installer! Weatherford 414 13.580 7"23-324 Model"Ultra Pak-TH"Hydraulic Set Permanent Production 13 Packer w/4&13.59 New Vow Pin x Pin 9,413 5,525 14 3-1/2"9.21-B0 TC-I I Tubing 15 HES 2.813"X"Nipple 9 Chr w/3X"9.2#TC-Il Boxx Pin 9433 5533 16 3-1/2"9.21-80TC-II Tubing HES 2.813"XN"Nipple w/2.750^No-Go 9Chr w/3X"TCII Box x Pin w/"RCH-M"Plug in Piac 17 (Set r 65 deg Ind.) 9507 5563 18 3-1/2"9.21-80TC-II Tubing ik.i 19 WLEGw/3X"TCII Box 11,206 6,120 114, Lower Completion =au TVD 1ft) 20 WFT PBR Tie Back Sleeve 15ft 11,195 6,117 21 WFT"NTH"Liner Top Pkr w/Hold Down Slips 5"184x 7"26#w/Vam Top Hi Pin 11,210 6,121 // 22 WFT"PHR"Rotating Liner Hanger 5"18#x7"268w/5"Vam Top HT Pin x Pin and XOw/5"New 11,214 6,123 ` Vam HT Box 4X"Hydril 521 Pin 23 WFT ZoneSelect Sliding Sleeve w/6 1/2 holes w/4-1/2 Hydril 521 Box x Pin(OPEN Position) 11,381 6,176 WFT ZoneSelect Sliding Sleeve w/2.20 Carbide Nozzles w/4-1/2 Hydril 521 Box x Pin(Closed 24 Position) 11,470 6,199 • O 25 WFT Genesis 5.750 OD x 4-1/212.60 x 1.5 Ft Oil Base Swell Pkr w/4-1/2 Hydril 521 Box x Pin L-80 11,520 6,209 7 26 WFT ZoneSelect Sliding Sleeve w/61/2 holes w/4-1/2 Hydril 521 Box x Pin(OPEN Position) 11,742 6,232 GLM#1 DGI 27 WFT ZoneSelect Sliding Sleeve w/2.20 Carbide Nozzles w/4-1/2 Hydri I 521 Box x Pin(Closed 12,065 6,248 Installed Position) 28 WET ZoneSelect Sliding Sleeve w/61/2 holes w/4-1/2 Hydril 521 Box x Pin(OPEN Position) 12,625 6,236 O 29 WFT Genesis 5.7500D x 4-1/21260 x 15 Ft Oil Base Swell Pkr w/4-1/2 Hydril 521 Box x Pin L-80 13,348 6,221 O 30 4-1/212,601-80 Hydril 521 Pup Joint w/(6)1/2 Holes 13,922 6,189 O 31 4-1/212.60L-80Hydril 521 Pup Jointw/(6)1/2 Holes 14,3% 6,182 32 4-1/212.601-80 Hydri1521 Pup Joint w/(6)1/2 Holes 14,790 6,184 1110 33 WFT Genesis 5.75000x4-1/21260 x 15 Ft Oil Base Swell Pkrw/4-1/2 Hydril 521 Box x Pin L-80 15,392 6,203 O 34 WFT Genesis 5.75000x4-1/212.60u 15 Ft Oil Base Swell Pkr w/4-112 Hydril 521 Boon Pin 1-80 16,047 6,203 O ® 35 4-1/212,601-80 Hydril 521 Pup Joint w/(6)1/2 Holes 16,891 6,137 • 36 Solid Eccentric Shoe w/4-1/2"IBT-M Box 17,140 6,117 ID 17,382 6,096 m (���J 26 29 1 33 \ Q I I II I CE1 0 0 0 •. .. .. •. •• •S. •• •• 0 0 0 • O Open • • Closed 23 z4 IIO 27 20 II , , (36) Pt E E 2000 o 03 ReviRMo�n By: Commentsl ON R Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. aD - 0 3WelI History File Identifier Organizing(done) ❑ Two-sided II HiIIIIl I III ❑ Rescan Needed I I I III III RES DIGITAL DATA OVERSIZED (Scannable) Color Items: ❑ Diskettes, No. ❑ Maps: Greyscale Items: ❑ Other, No/Type: ❑ Other Items Scannable by a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non-Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: BY: Maria Date: 1 3 /s/ 1 't f Project Proofing 111111111D I BY: Maria Date: ' 13 /4 /s/ Scanning Preparation W x 30 = 1 So + = TOTAL PAGES / `4. Count does not include cover sheet) 64 BY: Maria Date: ` 3 Lt /sl Production Scanning 11111111111111111 Stage 1 Page Count from Scanned File: J (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: LYES NO BY: Date: /!3//q, /s/ p 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. I ReScanned I BY: Maria Date: /s/ Comments about this file: Quality Checked 11111111111111 12/22/2011 Well History File Cover Page.doc STATE OF ALASKA AL A OIL AND GAS CONSERVATION COMM. SON • REPORT OF SUNDRY WELL OPERATIONS 1 1.Operations Abandon U Repair Well ❑ Plug Perforations U Perforate U Other U HPBD Performed: Alter Casing 9 Pull Tubing 9 Stimulate-Frac SIAWaiver 9 Time Extension 0 Change Approved Program 9 Operat.Shutdown 9 Stimulate-Other / Re-enter Suspended Well 9 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Pioneer Natural Resources Alaska LLC Development 0 Exploratory 9 210-032 3.Address: 700 G Street,Suite 600 Stratigraphic❑ Service ❑., 6.API Number: Anchorage,AK 99501 50-703-20618-00-00 ' 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 355036/ADL 355037 ' ODSN-1§i Ft EC E I V 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Oooguruk-Nuiqsut Oil Pool MAY 0 8 2014 11.Present Well Condition Summary: AOGCG Total Depth measured 17,383 . feet Plugs measured N/A feet true vertical 6,096 feet Junk measured N/A feet Effective Depth measured 17,139 • feet Packer measured See Below feet true vertical 6,117 feet true vertical feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 158' 158' N/A N/A Surface 3550' 11-3/4" 3589' 2982' 5830 psi 3180 psi Intermediate 5493' 9-5/8" 3377'-8870' 2880'-5301' 5750 psi 3090 psi Production 11,314' 7" 11,348' 6165' 7240 psi 5410 psi Liner 5945' 4-1/2" 11,195'-17,140' 6117-6117' N/A N/A Perforation depth Measured depth See attachment,pg 2 feet True Vertical depth feet MAY 2 9 2014 SCANNED Tubing(size,grade,measured and true vertical depth) 3-1/2",9.3# L-80,TCII 11,207'MD 6121'TVD Packers and SSSV(type,measured and true vertical depth) 5"x 7"Lnr Tp Pkr 11210'MD/6124'TVD Wellstar TRSSSV 1995'MD/1870'TVD 12.Stimulation or cement summa squeeze : SEE ATTACHED POST JOB REPORTS FROM VENDOR q summary: Intervals treated(measured): RSDM MAY 1 2014 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: 0 0 963 797 2701 Subsequent to operation: 0 0 0 536 12 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run Exploratory 9 Development 0 Service 9 Straratigraphic 9 Daily Report of Well Operations x 16.Well Status after work: Oil 9 Gas 0 WDSPL❑ GSTOR 0 WINJ 0 WAG 2 GINJ 0 SUSP 9 SPLUG 9 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: 314-154 Contact Jack Kralick,343-2185 Email iack.kralickCapcaeluseneray.com Printed Name Jack Kralick Title Wells Supervisor Signature ', Phone 343-2185 Date 517/i q Sly?11� yiL s-,;-„z -,--( Form 10-404 Revised 10/2012 L1363 Submit Original Only Pioneer Natural Resources Alaska LLC ODSN-15i Page 2 Form 10-404, Report of Sundry Operations Present Well Condition Summary, Box #11 Perforation Depth (MD/TVD) - Attachment 4-'/2", 12.6#, L-80 Hyd 521 Uncemented Liner Sliding Sleeves w/ 6ea. 1/2" Ports — open @ depths listed: MD TVD 11,381' — 11,387' 6176' — 6177' 11,742' — 11,747' 6232' — 6232' 12,625' — 12,630' 6235' — 6235' Sliding Sleeves w/2 - .20 Jets — closed @ depths listed: MD TVD 11,470' — 11,475' 6199' — 6200' 12,065' — 12,070' 6248' — 6248' Perforated Pups w/ 6-1/2" Holes @ depths listed: MD TVD 13,922' — 13,927' 6189' — 6189' 14,396' — 14,401' 6182' — 6182' 14,790' — 14,795' 6184' — 6184' 16,891' — 16,896' 6137' — 6136' PIONEER ')perations Summary Report - Ste Well Name: ODSN-15i NATURAL RESOURCES Well Name: ODSN-15i Contractor: SCHLUMBERGER Rig Number: 19AC Job Category: WORKOVER Start Date: 3/24/2014 End Date: Start Depth Foot/Meters Dens Last Start Date End Date (ftKB) (ft) Mud(lb/gal) Summary 3/24/2014 3/25/2014 17,383.0 Prep frac and support equipment for the HPBD. 3/25/2014 3/26/2014 17,383.0 *Total proppant end of stage 32702 lbs per FracCat *Total BH proppant 32715 lbs per FracCat. *Total proppant on location 32200 lbs *Total Slurry 4636 bbls *Drop a total of 70 green bio balls. *30 BBLs freeze protect past wellhead. *Final shut in pressure 16:20 0 3125 500 5341 Page 1/1 Report Printed: 5/7/2014 Schlumberger FracCAT Treatment Report High Pressure Breakdown Well :ODSN-15i Field :Oooguruk Formation :Nuiqsut Prepared for Client :Pioneer Natural Resources Client Rep :Mike Martin Date Prepared :April 14,2014 Prepared by Name :Jimmy Kelley Phone :907-659-2434 Division :Schlumberger-Well Services AK Service Point :Prudhoe Bay East Camp Pressure(All Zones) Initial Wellhead Pressure(psi) 2600 Initial BHP at Gauge(psi) 4902 Final Surface ISIP(psi) 3070 Final ISIP at Gauge(psi) 5250 Surface Shut in Pressure(psi) 3125 BH Shut in Pressure(psi) 5341 Maximum Treating Pressure(psi) 7096 BH Gauge at 9,285,5,472 TVD Treatment Totals(All Zones) Total Slurry Pumped 4636 Total Freeze Protect Past Wellhead 34 Water+Adds+Pro.'ant bbls bbls Total Proppant Pumped(lbs) 32,200 Total Proppant in Formation(lbs) 32,200 Total Chemical Additives Invoiced Past WH Invoiced Past WH F103(gal) 189 189 M275(lbs) 66 61 B145(gal) 199 199 Disclaimer Notice This information is presented in good faith,but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service.The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment.The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model,the assumptions and such input data.The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values.The quality of input data,and hence results,may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well,the reservoir,the field and conditions affecting them.If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue.Actual charges may vary depending upon time,equipment,and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Schiomberger Client:Pioneer Natural Resources Well:ODSN-15i Formation:Nuiqsut Country:United States Section 1 : Summary on High Pressure Breakdown SUMMARY The Fracture treatment for Well ODSN-15i,Nuiqsut,at Oooguruk was performed on March 26,2014. The treatment consisted of 4 scour stages where 40 bio balls were dropped after the first three scour stages. A total of 32,200 lbs of proppant(as measured by load tickets),4,636 bbls of slurry(as measured by FracCAT)was pumped and 120 bio balls were dropped. Job data was transmitted P P PP real time via a dedicated internet line to the Anchorage office. PRESSURE AND PUMP CHECK STAGE On March 26th the pressure test was performed to 9,000 psi and the annulus line was then pressured pressure tested to 3,700 psi. During the pressure tests we did not have any problems or concerns that arose with the equipment. A 120 bbl Pump Check stage was pumped into in the well to predict the treating pressures,ensure that the well could be pumped into,and to confirm pumps were in good operating order. HIGH PRESSURE BREAKDOWN The high pressure breakdown treatment on ODSN-15i had a total of 4,516 bbls of slurry(Breakdown+PPA+Flush stages)with 32,200 lbs of 20/40 CarboLite(as per load tickets). The stimulation was designed as a four stage high pressure breakdown treatment with 40 bio balls being dropped in the first 3 drops. Each of the stages consisted of a Breakdown, .5 PPA, 1 PPA,and Overflush. The designed rate for all the stages was 20 bpm.The rate was increased to 25 bpm by client request on the 2nd and 3`"stage and 29 bpm for the 4th stage. The intial WH pressure observed after the Swab and Master valves were opened was 2,596 psi. The initial BHP,measured at the guage,was 4,911 psi,and the initial BHT was 116F. The first pump stage was a Pump Check stage and consisted of 120 bbls. This stage started out at a pump rate of 15 bpm and was slowly increased to 20 bpm as the WH pressure declined. A hard shutdown was performed at the end of the stage and an ISIP of 5136 psi was observed at the BHG corresponding to a F.G. of 0.88 psi/ft.After the 4 scour stages were pumped and the final shutdown occurred,a F.G. of 0.90 was calculated from a BH ISIP of 5,268 psi. The initial treating BHP was 5600 psi at 20 bpm and the final treating BHP was 6600 psi at 29 bpm. A maximum BHP of 7780 psi was observed during the 4th stage at 29 bpm. The following diversion signatures were noted during the job: • After the 1"ball drop a BHP signature of 5790 to 6050 psi was observed at 157 bbls after the ball drop. This was in the area of the Pup 8 section of the well. • After the 2"°ball drop a BHP signature of 6300 to 6790 psi was observed at 140 bbls after the ball drop. This was in the area of the Pup 6 section of the well. • During the third and forth scour stages,the treating and BHP had a steady decline as the proppant was going into the formation indicating that the proppant was"scouring"the near wellbore area. • After the 3rd ball drop a BHP signature of 6720 to 7040 psi was observed at 119 bbls after the ball drop. This was in the area of the 5"'sleeve section of the well. Materials Actual (Design) Slurry Volume-All Volumes(bbl) 4,636(4,662) Clean Fluid-All volumes(bbl) 4,602(4,600) Proppant,lbs 32,200(32,525) RATE - bbl/min & PROP. CONC. - bbl/min Li O O O CD O CD CO Lf) Nr M N N- O• E ED n 1 CO I: W 12 x a = Z , E 1- a` m7aa I I I I I I u N U) d co i Ln 7 O ai N co a) .- E o N r N Y. Q @ V CO v' 113 Z 0 in =i.--,, L aOZ = G) . c) .T = C co ` IsT%-.-1-47.--4—*----"*".--0 co E . Ln E h N L 92 2 0 CI cg a i= ii 1.-----/ 3 CD LA O N x- r N . CD N O N Cii a SW m QOd co a I- L L 9 a • • 1 0 0 0 0 0 0 0 0 • o • O o7. 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o O O O CO O Ln M N y a ._ O !sd-2 f1SSald S. • ' RATE - bbl/min & PROP. CONC. - bbl/min L. 0 0 0 0 0 0 m to V co N r- O 03 N N IA a s 8qT j N C ] R 1111 C a ; a d gaIy, aq 111111 7 141 u 4 ,1 y a> a) 2 a) O c 1-2 0 o U N U N N I Z Lf) 65 2 N v, 01 d _ Zi ��+ C n ry op � c rN - U) EO Z= 2 _m d m o = C� V m 8 YOBHCO t6 E E -O .' N -C a> 0 a E m 6 U lL N 6 d O E M cs CN N O N N 7 an aJTT . tL0 .'1 . i s1 _ O O O O O O O O O O N r O O O O O O O O O O v O O) CO I- O in MCV , N O ISd-3bf1SS32Id RATE - bbl/min & PROP. CONC. - bbl/min 0 o O o 0 0 v : L) 4 Cr) N s OCO CD I IMm N 1. 4 .CiAls: ---J E 111111 z Ca d ea 1 (_,,,_ dm I T , o S d M .n a m 70 7dC o z i, (41 =N m E Z iO le) CO `m c(n 0 CI .Q d N aoz= d�N a) N y m o C(n V 4 �' v E a OQ !C E LL N Y E o ` E o _ QN n = R I 4J N Q v ld a m M n 00 ri C N E 3 M CP Y co d m V N = UN O ILI 16 L st. L f 111 a E 1 r .. a a O Oi - * irr'irl ._ N r' © !sd- 32if1SS32,d • RATE - bbl/min & PROP. CONC. - bbl/min O O O O O COC C CD E 5 U) CO N ,— O co— d N rn K = f. 2z � a .5 .5 % e) 5 aE 111111j ift- 11- = - v ti H c G1 4 O o L U N U N N coc o CeN U 0M O N L W d Z 0 r N R i N N N Z Q y Z 6 (i / N c (n .Cr H ctoz= C>�N E E . D oo Cu) ` Y U m o C0 MI LLU a02 0 Lo .a N _c a r . O i .t a m �p C y Ea' E. I Q .9- 02 Om C N (n 3 66 v o i-- ED. Y ca LL ML W ` • Y 3 V N y d o co N en I O I .. = • ._ C2 . . • . . , • • • i O O O O O O O O O O OM 5 O O O O O O O O O O N O O O O O O O O O O uO O) CO I,- (D I.0N CO N O aIsd- 321f1SS32id CO Schlumberger Client:Pioneer Natural Resources Well:ODSN-15i Formation:Nuigsut Country:United States Section 1 : High Pressure Breakdown Section la: Summary & Job Messages Summary Total Proppant Pumped(lbs) 32,200 Max pumping Rate(bpm) 29.4 Total Proppant in Formation(lbs) 32,200 Average Pumping Rate(bpm) 24.8 Total Slurry Pumped(bbls) 4636 Maximum Treating Pressure(psi) 7096 Total Clean Fluid Pumped(bbls) 4602 Average Treating Pressure(psi) 4921 Average Water Temperature(F) 85 Message Log Message Treating Annulus Total Slurry Slurry Rate Prop.Conc. # Time Pressure Pressure (psi) (psi) (bbl) (bbl/min) (PPA) 1 8:47:33 Priming POD 0 0 0.0 0.0 0.0 2 9:04:53 _Start Priming Pumps 36 _-1 0.0 0.0 0.0 3 9:17:19 _Pumps Primed 94 0 0.0 0.0 0.0 4 9:38:23 Little Red pressure testing lines 92 -0 0.0 0.0 0.0 5 9:45:25 _Little Red Pressure Test good 92 424 0.0 0.0 0.0 6 9:45:35 Little Red Popoff to 3700 92 415 0.0 0.0 0.0 7 10:00:56 On Standby for Little Red 93 42 0.0 0.0 0.0 8 10:10:18 On Standby for Vac truck for 200bbl tank 93 42 0.0 0.0 0.0 9 11:03:22 Start Priming Lines 10 41 0.0 0.0 0.0 10 11:11:07 _Finished Priming and heating lines 19 3667 0.0 0.0 0.0 11 11:15:53 Little Red Finished 15 12 0.0 0.0 0.0 12 11:20:24 _Low Pressure Stall 47 5 0.0 0.5 0.0 13 11:23:03 Starting High Pressure Stall 1665 5 0.0 0.2 0.0 14 11:26:40 Trip Test Good 8710 6 0.0 0.0 0.0 15 11:29:18 _Pressure Test Good 12 6 0.0 0.0 0.0 16 11:29:25 Prejob Safety Meeting 12 5 0.0 0.0 0.0 17 12:07:55 IA to 3000 psi 5 1463 0.0 0.0 0.0 18 12:16:12 Opening Master Valve 5 2999 0.0 0.0 0.0 19 12:17:59 POD Priming with Slickwater 5 2979 0.0 0.0 0.0 20 12:20:29 _Equalizing to well 432 2960 0.0 0.5 0.0 21 12:21:23 Opening Swab Valve 3017 2954 0.0 0.0 0.0 22 12:22:58 Initial WHP 2600 BHP 4902 2619 2946 0.0 0.0 0.0 23 12:23:44 _Displacing Freeze Protect 3085 2950 0.0 4.9 0.0 24 12:27:55 Finished Displacing Freeze Protect 2272 2804 0.0 0.0 0.0 25 12:32:59 IA to 3000 psi 0.4 bbl 2303 2744 0.0 0.0 0.0 , • Schlumberger Client:Pioneer Natural Resources Well:ODSN-15i Formation:Nuigsut Country:United States Message Log Message Treating Annulus Total Slurry Slurry Rate Prop.Conc. # Time Pressure Pressure (psi) (psi) (bbl) (bbl/min) (PPA) 26 12:38:04 Start Propped Frac Automatically 2353 3012 0.0 0.0 0.0 27 12:38:04 Start ODSN-15i Automatically 2353 3012 0.0 0.0 0.0 28 12:38:04 Started Pumping 2353 3012 0.0 0.0 0.0 29 12:38:21 Start pumping pump check 3021 3022 0.1 2.7 0.0 30 12:43:27 Activated Extend Stage 6307 3350 78.0 19.4 0.0 31 12:44:54 IA to 3500 psi, 0.7 bbl 5039 3566 107.2 20.0 0.0 32 12:45:56 Shut down 1287 3562 119.5 0.0 0.0 33 12:48:37 25 Bioballs loaded 1251 3585 119.5 0.0 0.0 34 12:56:19 Deactivated Extend Stage 1049 3597 119.5 0.0 0.0 35 12:56:35 start pumping breakdown 2571 3607 119.9 2.4 0.0 36 13:03:29 PCM on tank 8 3985 3614 251.8 20.0 0.0 37 13:06:49 Started Pumping Prop 4015 3654 318.5 20.0 0.0 38 13:22:07 Stopped Pumping Prop 3993 3393 625.3 20.1 0.2 39 13:24:30 PCM on tank 9 4074 3309 673.4 20.3 0.0 40 13:26:05 IA to 3500 4105 3307 705.5 20.3 0.0 41 13:47:46 PCM on tank 10 4145 3603 1145.9 20.3 0.0 42 13:52:10 1225 tot slurry 25 balls dropped 4259 3601 1235.2 20.3 0.0 43 13:59:11 25 bioballs loaded 4202 3638 1377.8 20.3 0.0 44 13:59:48 Balls hit 1382 total slurry 4445 3658 1390.3 20.3 0.0 45 14:02:05 Started Pumping Prop 5065 3659 1438.3 25.3 0.0 46 14:02:23 increase rate to 25 bpm 5094 3666 1445.8 25.1 0.4 47 14:09:38 PCM on tank 10 5268 3672 1626.7 24.9 0.5 48 14:14:27 Stopped Pumping Prop 5246 3612 1745.7 24.9 0.2 49 14:26:52 PCM on tank 12 5181 3512 2057.1 25.1 0.0 50 14:35:44 Cement Van to 5500 5190 3609 2279.9 25.1 0.0 51 14:39:41 Bioballs dropped at 2345 tot slurry 5226 3566 2379.1 25.1 0.0 52 14:44:31 Balls hit 2485 tot slurry 5619 3563 2500.5 25.0 0.0 53 14:46:03 20 bioballs loaded 5597 3563 2538.9 25.1 0.0 1 54 14:46:58 Started Pumping Prop 5568 3561 2561.9 25.1 0.0 55 14:49:31 14:47 More Bioballs hit 5570 3560 2625.4 24.9 0.5 56 14:51:20 PCM on tank 13 5515 3554 2670.7 24.9 0.5 57 14:59:10 Stopped Pumping Prop 5285 3530 2865.4 24.8 0.2 58 15:01:46 PCM on tank 14 5432 3530 2930.5 25.1 0.0 59 15:19:03 PCM on tank 15 5566 3559 3363.8 25.1 0.0 60 15:23:38 Dropped Bioballs 3465 tot slurry 5737 3575 3478.8 25.0 0.0 61 15:28:23 balls hit 3984 total slurry 5739 3611 3597.8 25.1 0.0 62 15:31:54 Started Pumping Prop 5883 3635 3685.9 24.6 0.0 63 15:32:29 increasing rate to 30 bpm 6064 3575 3700.4 25.0 0.5 6 • Schlumberger Client:Pioneer Natural Resources Well:ODSN-15i Formation:Nuiqsut Country:United States Message Log Message Treating Annulus Total Slurry Slurry Rate Prop.Conc. # Time Pressure Pressure (psi) (psi) (bbl) (bbl/min) IPPA) 64 15:35:56 Trips set to 7500 6916 3589 3797.9 28.4 0.5 65 15:40:20 Activated Extend Stage 6582 3619 3922.7 28.3 1.0 66 15:42:47 Stopped Pumping Prop 6515 3582 3992.0 28.4 0.2 67 15:42:49 Deactivated Extend Stage 6533 3585 3993.0 28.2 0.0 68 16:08:53 Stopped pumping 3054 3494 4636.0 0.0 0.0 69 16:24:27 Closing Master Valve 3125 3296 4636.0 0.0 0.0 70 16:24:59 WHP 3125 BHP 5341 3125 3281 4636.0 0.0 0.0 71 16:28:03 Swab Valve Closed 5 2030 4636.0 0.0 0.0 Schlumberger Client:Pioneer Natural Resources Well:ODSN-15i Formation:Nuiqsut Country:United States Section 1 b: As Measured Pump Schedule As Measured Pump Schedule Ste Slur. Slurry Pump Fluid MaxrProp Prop p Step Name Vol. Rate Time Fluid Name Volume Proppant Name Conc Conc Mass (bbl) (bbl/min) (min) (gal) (PPA) (PPA) (lb) 1 Pump Check 119.5 0.0 7.3 Slick Water 5020 0.0 0.0 0 2 Breakdown 200.0 0.0 10.5 Slick Water 8386 0.0 0.0 1 3 0.5 PPA Scour 200.3 0.0 10.0 Slick Water 8235 CarboLite 20/40 0.5 0.5 4045 4 1.0 PPA Scour 100.0 0.0 5.0 Slick Water 4027 CarboLite 20/40 1.1 1.0 3975 5 Overflush 600.0 0.0 29.6 Slick Water 25193 1.0 0.0 0 6 Drop 25 Ball 20.0 0.0 1.0 Slick Water 840 0.0 0.0 0 7 Breakdown 200.0 0.0 9.8 Slick Water 8396 0.0 0.0 2 8 0.5 PPA Scour 200.0 0.0 8.0 Slick Water /8224 CarboLite 20/40 0.5 0.5 4020 9 1.0 PPA Scour 100.0 0.0 4.1 Slick Water 4028 CarboLite 20/40 1.1 1.0 3925 10 Overflush 600.0 0.0 23.9 Slick Water 5192 1.0 0.0 0 11 Drop 25 Ball 20.0 0.0 0.8 Slick Water 840 0.0 0.0 0 12 Breakdown 200.0 0.0 8.0 Slick Water 8400 0.0 0.0 0 13 0.5 PPA Scour 200.0 0.0 8.0 Slick Water 8224 CarboLite 20/40 0.5 0.5 4012 14 1.0 PPA Scour 100.0 0.0 4.0 Slick Water 4028 CarboLite 20/40 1.0 1.0 3932 15 Overflush 600.0 0.0 23.9 Slick Water 25192 1.0 0.0 0 16 Drop 20 Ball 20.0 0.0 0.8 Slick Water 840 0.0 0.0 0 17 Breakdown 200.0 0.0 8.0 Slick Water 8400 0.0 0.0 0 18 0.5 PPA Scour 200.0 0.0 7.2 Slick Water 8224 CarboLite 20/40 0.5 0.5 3970 19 1.0 PPA Scour 113.2 0.0 4.0 Slick Water 4564 CarboLite 20/40 1.1 1.0 4318 120 Overflush 600.0 0.0 21.1 Slick Water 25207 0.3 0.0 0 21 Freeze Protect 43.0 0.0 2.9 Freeze Protect 1817 0.0 0.0 0 Schlumberger Client:Pioneer Natural Resources Well:ODSN-15i Formation:Nuigsut Country:United States l Stage Pressures & Rates Maximum Slurry Maximum Treating Minimum Treating Step# Step Name Rate Pressure Pressure (bbl/min) (psi) (psi) 1 Pump Check 20.9 6710 1051 2 Breakdown 20.5 4205 1050 3 0.5 PPA Scour 20.1 4026 3987 4 1.0 PPA Scour 20.2 4009 3987 5 Overflush 20.4 4154 3989 i 6 Drop 25 Ball 20.3 4265 4148 7 Breakdown 25.2 5100 4165 8 0.5 PPA Scour 25.2 5279 5085 9 1.0 PPA Scour 24.9 5277 4959 10 Overflush 25.2 5335 5171 11 Drop 25 Ball 25.2 5338 5187 12 Breakdown 25.2 5638 5172 13 0.5 PPA Scour 25.1 5937 5371 14 1.0 PPA Scour 24.9 5389 5285 15 Overflush 25.1 5680 5283 16 Drop 20 Ball 25.1 5727 5562 17 Breakdown 25.1 5912 5597 18 0.5 PPA Scour 29.4 7096 5878 19 1.0 PPA Scour 28.5 6663 6492 20 Overflush 28.8 6581 3905 21 Freeze Protect 15.0 4625 2867 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) _ (gap (Ib) 4636.0 197.8 193276 32,200 Schlumberger Client:Pioneer Natural Resources Well:ODSN-15i Formation:Nuiqsut Country:United States Section lc: Designed Pump Schedule Designed Pump Schedule Slurry Pump Fluid Prop Step Volum Pump Rate Prop Conc Step Name e (bbl/min) Time Fluid Name Volume Prop Name (PPA) Mass (bbl) (min) (gal) (lb) 1 Pump Check 120.0 20.0 6.0 Slick Water 5040 0.0 0 2 Breakdown 200.0 20.0 10.0 Slick Water 8400 0.0 0 3 0.5 PPA Scour 200.3 20.0 10.0 Slick Water 8232 CarboLite 20/40 0.5 4116 4 1.0 PPA Scour 100.0 20.0 5.0 Slick Water 4024 CarboLite 20/40 1.0 4024 5 Overflush 600.0 20.0 30.0 Slick Water 25200 0.0 0 6 Drop 25 Ball 20.0 20.0 1.0 Slick Water 840 0.0 0 7 Breakdown 200.0 20.0 10.0 Slick Water 8400 0.0 0 8 0.5 PPA Scour 200.0 20.0 10.0 Slick Water 8220 CarboLite 20/40 0.5 4110 9 1.0 PPA Scour 100.0 20.0 5.0 Slick Water 4024 CarboLite 20/40 1.0 4024 10 Overflush 600.0 20.0 30.0 Slick Water 25200 0.0 0 11 Drop 25 Ball 20.0 20.0 1.0 Slick Water 840 0.0 0 12 Breakdown 200.0 20.0 10.0 Slick Water 8400 0.0 0 13 0.5 PPA Scour 200.0 20.0 10.0 Slick Water 8220 CarboLite 20/40 0.5 4110 14 1.0 PPA Scour 100.0 20.0 5.0 Slick Water 4024 CarboLite 20/40 1.0 4024 15 Overflush 600.0 20.0 30.0 Slick Water 25200 0.0 0 16 Drop 20 Ball 20.0 20.0 1.0 Slick Water 840 0.0 0 17 Breakdown 200.0 20.0 10.0 Slick Water 8400 0.0 0 18 0.5 PPA Scour 200.0 20.0 10.0 Slick Water 8220 CarboLite 20/40 0.5 4110 19 1.0 PPA Scour 100.0 20.0 5.0 Slick Water 4024 CarboLite 20/40 1.0 4024 20 Overflush 600.0 20.0 30.0 Slick Water 25200 0.0 0 21 Freeze Protect 50.0 20.0 2.5 Freeze Protect 2100 0.0 0 1 Pump Check 120.0 20.0 6.0 Slick Water 5040 0.0 0 2 Breakdown 200.0 20.0 10.0 Slick Water 8400 0.0 0 3 0.5 PPA Scour 200.3 20.0 10.0 Slick Water 8232 CarboLite 20/40 0.5 4116 4 1.0 PPA Scour 100.0 20.0 5.0 Slick Water 4024 CarboLite 20/40 1.0 4024 5 Overflush 600.0 20.0 30.0 Slick Water 25200 0.0 0 6 Drop 25 Ball 20.0 20.0 1.0 Slick Water 840 0.0 0 7 Breakdown 200.0 20.0 10.0 Slick Water 8400 0.0 0 8 0.5 PPA Scour 200.0 20.0 10.0 Slick Water 8220 CarboLite 20/40 0.5 4110 9 1.0 PPA Scour 100.0 20.0 5.0 Slick Water 4024 CarboLite 20/40 1.0 4024 10 Overflush 600.0 20.0 30.0 Slick Water 25200 0.0 0 11 Drop 25 Ball 20.0 20.0 1.0 Slick Water 840 0.0 0 12 Breakdown 200.0 20.0 10.0 Slick Water 8400 0.0 0 13 0.5 PPA Scour 200.0 20.0 10.0 Slick Water 8220 CarboLite 20/40 0.5 4110 14 1.0 PPA Scour 100.0 20.0 5.0 Slick Water 4024 CarboLite 20/40 1.0 4024 15 Overflush 600.0 20.0 30.0 Slick Water 25200 0.0 0 Designed Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (lb) 4630.3 231.5 193048 32542 y • 4,„1 ,„ /7 , THE STATE fiF c J,< _ c c , a2 j F �, ,R 1 ,/. _J J Z . _i- S � i _ 333 West Sever-11h Avenue 4+ "`KCiC)i-'1:1:NC)�: SI AN PiARN1:!.L Anchorage, /Alaska 99501-3572 lean: 907.279.1433 mss , -J s,Y 9 ;/ ? „A Jack Kralick Well Work Supervisor alo— (2______3D— Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, AK 99501 Re: Oooguruk Field,Nuiqsut Oil Pool, ODSN-15i Sundry Number: 314-154 SCANNED A U 1:' 1 9 2 14. Dear Mr. Kralick: 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, 0 ,, Daniel T. Seamount, Jr. Commissioner DATED this�7day of March, 2014. Encl. RECEIVE.. . • STATE OF ALASKAK �� • ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25280 A C C 1.Type of Request: Abandon❑ Plug for Redrill ❑ Perforate New Pool❑ Repair Well❑ Change Approved Program ❑ Suspend❑ Plug Perforations ❑ Perforate❑ Pull Tubing❑ Time Extension ❑ Operations Shutdown❑ Re-enter Susp.Well ❑ Stimulate Q Alter Casing❑ I Other: ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Pioneer Natural Resources Alaska,Inc. Exploratory ❑ Development ❑ 210-032• 3.Address: 700 G Street,Suite 600 Stratigraphic 0 Service El . 6.API Number: Anchorage,AK 99501 50-703-20618-00-00 i 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? WA `•' ODSN-15i Will planned perforations require a spacing exception? Yes ❑ No 0• 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 355036/ADL 355037 • 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): 17,383' • 6096' - 17,139' 6117' N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 158' 158' N/A N/A Surface 3550' 11-3/4" 3589' 2982' 5830 psi 3180 psi Intermediate 1 5493' 9-5/8" 3377'-8870' 2881'-5301' 5750 psi _ 3090 psi Intermediate 2 11,314' 7" 11,348' 6165' 7240 psi 5410 psi Liner 5945' 4-1/2" 11,195'-17,140' 6117'-6117' 8430 psi 7500 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attachment,pg.2 • See Attachment,pg.2 3-1/2",9.3# L-80,TCII 11,206' Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): 9/I Wellstar TRSSSV 3.5"X Profile .1995'MD/1870'TVD f y/3/s SAS 12.Attachments: Description Summary of Proposal Q - 13.Well Class after proposed work: Detailed Operations Program Q BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development❑ Service 0, 14.Estimated Date for 15.Well Status after proposed work: Operations: 3/31/2014 CommencingOil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16..Verbal Approval: Date: 3j/2...1//°( WINJ ❑ GINJ ❑ WAG 0. Abandoned ❑ Commission Representative: C S-;--14-c..,w-j- GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true'and correct to the best of my knowledge. Contact Jack Kralick,343-2185 Email jack.kralick(a)oxd.com Printed Name Jack Kralick Title Well Work Supervisor Signature ' Phone 343-2185 Date 3/11/2014 iiiiCOMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: l`--E.- \S I-4 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other 4( ar c. F 5c.,.,b .-,i s i RBDMMAY 10 2014 r� Spacing Exception R-.uired? Yes ❑ NoSubsequent Form Required: /0-- Loy 77 APPROVED BY / Approved by: COMMISSIONER THE COMMISSION Date: /i7I I 3 -13•/Y 77K13 3/13// Submit Form and Form 10-403(Revis 10(2012) + ApOPJGThTAt QliImonths from t�to Oa�dyal. Attachments in Duplicate 1� �� Pioneer Natural Resources Alaska Inc. ODSN-15i Page 2 Form 10-403, Application For Sundry Approvals Present Well Condition Summary, Box #11 Perforation Depth (MD/TVD) - Attachment 4-%2", 12.6#, L-80 Hyd 521 Uncemented Liner Sliding Sleeves w/6ea. 1/2" Ports — open @ depths listed: MD ND 11,381' — 11,387' 6176' —6177' 11,742' — 11,747' 6232' —6232' 12,625' — 12,630' 6235' — 6235' Sliding Sleeves w/2 - .20 Jets — closed @ depths listed: MD ND 11,470' — 11,475' 6199' — 6200' 12,065' — 12,070' 6248' — 6248' Perfed Pups w/6-1/2" Holes @ depths listed: MD ND 13,922' — 13,927' 6189' — 6189' 14,396' — 14,401' 6182' — 6182' 14,790' — 14,795' 6184' — 6184' 16,891' — 16,896' 6137' — 6136' Pioneer Natural Resources Alaska as a Inc. ODSN-15i Page 3 AOGCC Form 10-403, Application For Sundry Approvals Present Well Condition Summary, Box #11 Packers and SSSV Type (MD/TVD) - Attachment SSSV w/ 2.813 x Profile TCII BxP MD ND 1995' 1870' 7" UltraPak TH Hyd Perm Packer MD ND 9413' 5525' Liner Top Packer MD ND 11,210' 6121' Swell Packers MD ND 11,520' - 11,537' 6,209' - 6,212' 13,348' - 13,366' 6,221' - 6,220' 15,392' - 15,409' 6,203' - 6,204' 16,047' - 16,064' 6,203' - 6,201' PIONEER NATURAL RESOURCES ALASKA ODSN-15i HPBD Ref: PTD 210-032 Ref: Sundry 313-032 Current Status and Overview: ODSN-15i was completed as a Nuiqsut injector. The horizontal OH section has a -5900' solid, uncemented 4 %" liner. There are 4 swellable packers isolating 5 areas along the lateral that will be broken down. There are 7 open subs each with 6 x1/2" pre drilled perfs distributed along the lateral. 3 stages will be pumped with diversion to attempt to stimulate as much of the interval as possible. Pumping Procedure: 1) Move in and berm 9 frac tanks with a minimum volume capacity of 10% greater than the largest tank. Load the tanks with seawater from the Conoco seawater injection system 2) Rig up Schlumberger equipment to goat head. 3) Pressure test surface lines to 5000 psi`p 4) Tie in Little Red Service pump to IA and �maintain;--3000 psi on the IA adjusting up or down as necessary during the treatment -- 1• � . .34 5) Pump 100 bbl stage to clear tubing/liner of well bore fluids 6) Shut down, final line up and readiness check for main treatment. 7) Pump all stages using slick seawater at 20-30 BPM with a maximum pressure limit of-4500 1. 200 bbls slick seawater 2. 200 bbls w/0.5 ppa 20/40 prop 3. 100 bbls w/ 1.0 ppa 20/40 prop 4. 600 bbls slick seawater 5. Drop 30 bioballs 6. Repeat Steps 1 -5 8) Pump last stage using slick seawater at 20-30 BPM with a maximum pressure limit of-4500 1. 200 bbls slick seawater 2. 200 bbls w/0.5 ppa 20/40 prop 3. 100 bbls w/ 1.0 ppa 20/40 prop 4. 600 bbls slick seawater 9) Flush with seawater and freeze protect fluid Total Prop: -25,000 lbs PIONEER NATURAL RESOURCES ALASKA 10) Monitor the surface pressure fall off at the end of the job for 30 minutes 11) Rig down frac equipment, move to next well 12) MIRU equipment as necessary to return well to injection Slick Seawater Composition • Friction reducer @ lgpt • Surfactant @1 gpt • Biocide @ 0.25 gpt General Well Info: MASP 4500 psi Reservoir Pressure/TVD 3200 psi/6,164' Wellhead Type/Pressure Rating GE Vetco Gray MB-233 system/4-1/16" 5,000 psi Tree Configuration Dual valve tree 10K Frac Tree Comments: The 7" casing was cemented with 34 bbls 12.5 ppg Cement with adds and 19 bbls 15.8 ppg Class G cement with adds. Displace with 20 bbls seawater and 411 bbls of 11.0 ppg mud. Bump plug and increase pressure to 4500 psi & held same for 30 minutes. Floats did not hold, pumped pressure up to 600 psi, shut in well and WOC. Well Type Nuiqsut Injector 343•iy Estimated Start Date March 31, 2014 Completion Engineer Rami Jasser Well Site Supervisor Jamey Bowman/Lou Lyles (907)670-6602 OoogurukWellworkSupervisora,pxd.com • ODSN-15i Injection Well Final Completion Well Head: 11-3/4",5K,VetcoGray No. Casing MD(ft) TVD(ft) Tree: 3-1/2",5K,Horizontal A 16"Conductor 158 158 B 11-3/4"60#L-80 Hydril 511,10.772"ID 3,589 2,982 C 9-5/8"40#Hydril 521,8.835"ID* 8,870 5,301 D 7"26#L-80 BTC-M,6.276"ID** 11,348 6,165 ' • ` E 4'A#12.60#L-80Hydril 521 17,140 6,117 EDF 3'h"9.38 L-80 TCII 11,350 6,166 IO (3p, Jloorr Comoletipp MD(fO NDjf$ I VetcoGray Tubing Hanger 34 34 2 3-1/2"9.2 L-80TC-II Tubing 3 HES Wellstar TRSSSV w/3W 9.2#TC-Il Boxx Pin 9 Chr w/2.813"X"Profile w/1/4"x.049 SS CL 1995 1870 to Surface 4 3-1/2"9.2 L-80 TC-I1 Tubing 5 GLM#1 HES Vanoil3'h"xL'S"Gas Lift Mandrel w/3W'9.2#TC-Il Box Pin w/DV 3556 2968 li 6 31/2"9.2 L-80 TC-I1 Tubing 1 7 M#2 HES Vanoil 354"x 154"Gas Lift Mandrel w/3X"9.2#TC-II Box x Pin w/DV 9199 5437 \\ 8 31/2"9.2 L-80 TC-Il Tubing CSJJ 9 HES ROC Gauge&Carrier w/354"9.2#TSHP Bonn Pin 9285 5472 0 GL 10 31/2"9.2 L-80 TC-I1 Tubing -_ 11 HES 2.813"X"Nipple 9 Chr w/354"9.2#TC-Il Bonn Pin 9333 5492 -�'�7/�/ 12 3-1/2"9.2 L-80 TC-I1 Tubing 13 Weatherford 4'h 13.5#x 7"23-32#Model"Ultra Pak-TH"Hydraulic Set Permanent Production 9,413 5,525 .„..'"-'` Packer w/4%13.59 New Vam Pin x Pin 14 3-1/2"9.2 L-80 TC-I1 Tubing "^ IOC 15 HES2.813"X"Nipple9Chrw/354"9.2#TC-Il Box Pin 9433 5533 16 3-1/2"9.2L-80TC-II Tubing 063SM9 17 HES 2.813"XN"Nipple w/2.750"No-Go 9Chrw/3X"TCII Box x Pin w/"RCH-M"Plug in Place 9507 5563 (Set @ 65 deg Incl.) 18 31/2"9.2 L-80 TC-II Tubing 19 WLEG w/354"TCII Box 11,206 6,120 lis, )Lower Completion MD(ft) TVD(ft.), 20 WFT PBR Tie Back Sleeve 15ft 11,195 6,117 21 WFT"NTH"Liner Top Pkr w/Hold Down Slips 5"18#x7"26#w/Vam Top HT Pin 11,210 6,121 22 WFT"PHR"Rotating Liner Hanger 5"18#x7"26#w/5"Vam Top HT Pin x Pin and XO w/5"New 11,214 6,123 O Vam HT Box 4,4"Hydril 521 Pin 23 WFTZoneSelect Sliding Sleeve w/61/2 holes w/4-1/2 Hydril 521 Box x Pin(OPEN Position) 11,381 6,176 WFTZoneSelect Sliding Sleeve w/2.20 Carbide Nozzles w/4-1/2 Hydril 521 Box x Pin(Closed 24 Position) 11,470 6,199 O 25 WFT Genesis 5.7500D x 4-1/212.60 x 15 Ft Oil Base Swell Pkr w/4-1/2 Hydril 521 Box x Pin L-80 11,520 6,209 (7)--J 26 WFTZoneSelect Sliding Sleeve w/61/2 holes w/4-1/2 Hydril 521 Box x Pin(OPEN Position) 11,742 6,232 27 WFT ZoneSelect Sliding Sleeve w/2.20 Carbide Nozzles w/4-1/2 Hydril 521 Box x Pin(Closed 12,065 6,248 Position) 28 WFT ZoneSelect Sliding Sleeve w/61/2 holes w/4-1/2 Hydril 521 Box x Pin(OPEN Position) 12,625 6,236 O 29 WFT Genesis 5.750 OD 4-1/212.60x15 Ft Oil Base Swell Pkr w/4-1/2 Hydril 521 Box x Pin L-80 13,348 6,221 30 4-1/2 12.60 L-80 Hydril 521 Pup Joint w/(6)1/2 Holes 13,922 6,189 �ffl® 31 4-1/2 12.60 L-80 Hydril 521 Pup Joint w/(6)1/2 Holes 14,396 6,182 7� �1 - 32 41/212.60L-80 Hydril 521 Pup Joint w/(6)1/2 Holes 14,790 6,184 1�J��i.0V 33 WFTGenesis5.7500Dx4-1/2112.60x15Ft)OiIBase Swell Pkr w/4-1/2Hydril 521Box xPin L-80 15,392 6,203_ ® .74 34 WFT Genesis 5.7500D x 4-1/212.60 x 15 Ft Oil Base Swell Pkrw/4-1/2 Hydril 521 Box x Pin L-80 16,047 6,203 35 4-1/2 12.60 L-80 Hydril 521 Pup Joint w/(6)1/2 Holes 16,891 6,137 0 DI . ® 11)) 36 Solid Eccentric Shoe w/4-1/2"IBT-M Box 17,140 6,117 TD 17,382 6,096 CI ih ® 25 29 33 34 0 \• I I I I O 0 0' 0 .. .. .. .. 0 Open z3 2a I 2s 27 28 , , , 36 • Closed O OO O O O PIONEERDate: Revision By: Comments 2013-10-03 RMD Final NATURAL RESOURCES ALASU\ • g; ' . ; ! 1 • , 1 ttolir , 1 1 CV 1Hi t f , 1 1 I ,_, Iif ,..• , C I I t of b 1 ' g g if [ , , 2 1 I 1 t .. 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Z z 10 40,„ 0 .---. l OD W11:1(10000 Plaid 0 E = co lig c? 843 acic-i8211.-03m ,12. 01 -1 .. eog g 3dOlS RWON Om% . a i DEPTH SUMMARY LISTING Date Created 17-MAY-2010 1 06 12 Depth System Equipment Depth Measuring Device Tension Device i Logging Cable Type Type Type 'Serial Number N A Serial Number N A Serial Number N A Calibration Date Calibration Date length Calibrator Serial Number Calibrator Serial Number Calibration Cable Type Number of Calibration Points Conveyance Method DrillPipe (TLC Wheel Correction 1 Rig Type LAND Wheel Correction 2 Depth Control Parameters og Sequence Subsequent Trip To the Welt Reference t og Name SCHLUMBERGER VISION SERVICES• Reference Log Run Number ONE Reference Log Date 13-MAY 2010 Subsequent Trip Down Log Correction 75 50 FT Depth Control Remarks 1 CONVEYED ON DRILL PIPE BY NABORS 19AC 2 3 4 D SC-A MER THE USE OF AND REL ANCE UPON THIS RECORDED-DATA BV HE HEREIN NAMED COMPANY ANO ANY OF "S AFF L ATES PARTNERS REPRESENTATIVES AGENTS CONS TANTS AND EMPLOYEES S SUBJECT TO THE 'ERMS AND COND T ONS AGREED UPON BETWEEN SCHLUMBERGER AND THE COMPANY NCLJD NG a RESTR C"ONS ON USE OF THE RECORDED-DATA (b)DISCLAIMERS AND WAVERS OF WARRANTIES AND REPRESENTA-ONS REGARDING COMPANYS USE OF AND REJANCE UPON THE RECORDED DA A ANC c CUSTOMERS FUL_AND SOLE RES°CNS B= 'Y FOR ANY NFERENCE DRAWN OR DECISION MADE N CONNE ON WITH T-IE USE OF TH S RECORDED-DATA :.'CHER SERV CES' OTHER SER!CES2 CS NONE OSI CS2 OS2 :'S3 0S3 CS4 0S4 CS5 0S5 REMARKS RUN NUMBER 1 + REMARKS RJN N N..MBER 2 SEE MEMORY REMARKS SECTION RUNRUN2 SERVICE ORDER# AW/Z-00019 SERVICE ORDER # PROGRAM VERSION '7C0-'54 PROGRAM VERS ON ` U;D._EVEL r:LU;D LEVEL _OGGED NTERVA, START STO0 LOGGED NTERVAL STAR' I STOP EQUIPMENT DESCRIPTION RUN 1 RUN 2 SURFACE EQUIPMENT DOWNHOLE EQUIPMENT AH-3 4 SR KNUCKLE 31 7 AH-3 4 SR KNUCKLE PSRP-A B 28 7 PRMC32 933 PSRP A PBMS A 3814 10k Sapphire ManL RTD Thermorttetei GR CCL GR 25 0 Wel; Temp 21 9 Manometer 218 CCL 21 2 PBMS _ 20 5 SCMT-CB 20 5 SCMC CA 8126 SECH-CA SCMS•CB 8156 SCMX-CA 812.) AH 278 TTG-C CrPi 3 14 9 CRL5 DISC 1 13 4 CB 3 ` 24 MAN 11 9 AuX 1C 9 CJ Tension SCMI 0 0 TOOL ZERO MAXIMUM STRING DIAMETER 1 75 IN MEASUREMENTS RELATIVE TO TOOL ZERO ALL LENGTHS IN FEET ODSN-15i Injection Well Proposed Completion :Y.-pw•.! 1 t.3.4 Sx l�Almy + .._._ __.T_.__.,_ ... Tie* 3.17 So( Howes•a! }' . - .'� t n L. • .. . t : a ) .. s } } �C. •• VS . ti —: is ' 2 ..- .-_ :er_ (•) -t :—..! -Ie S . •; ips• . .f • •c« x. B• C Z€.•a.f , . --is A ' ' • =". ',It* = . •; 1+1,4 : . 7 f t f .:i.*I f• _1'ff i ` .: • .• f►'1. •i- T.I II _. _. . I' , .•.`:f f-: .!"" trite,. t f 1'. •.!'•f! i_ '!!•' • f• •i'! •• . 1 0 --. 0 ,„, - 4 0 ee 1 1 Date T Rewsion By Comments pioNEERc3iC r.Y Co ctkr ODSN 151 Injector r- 'ZEJti .1..! Proposed Completion WPO7a - _ aCr�mreP�' MEMORY SCMT REMARKS SECTION MAXIS Field Linc] Schlumberger Memory Cement Bond Log 1. Genera; Information A. AFE: 18277 B. SO # : AWYZ-00019 C. Treatment Ii : 12259 D. Date: 16-MAY-2010 2. Test Objective A. The objective of this log is to evaluate the primary cement job in 7" liner. 3. Correlation Log Company: Schlumberger Title : VISION Services* Dated: 13-May-10 Log Tied in at: 10384' 4. Well Fluid A. Log interval fluid Packed with 10. 1 ppg brine. 5. Logging Program Start Stop Comments 11068.0 @ 07 :37 : 12 10188.5 @ 08:43: 20 30 fpm up 11114. 2 @ 09 :30:00 10191 . 7 @ 10: 28:00 30 fpm up 6. Expected CBL in 7" Casing Free Pipe : 63 mV 80% Bond: 5.75 mV 7. Expected Transit Times TT1 5 ' VDL: 404 us TT2 3 ' CBL: 292 us 8. Notes A. All depths listed in remarks section are Coil Tubing Measured Depth (CT-MD) . B. Bottom not tagged during logging run. C. Field interpretation of top of good bond to casing is 10640' ft. D. A microannulus is suspected to have caused the high CBL amplitude and poor VDL image. Client did not desire to pressurize the well and log the program once again. = Warp' MEMORY SCMT MAIN PASS 30 FPM UP i Company:PIONEER NATURAL RESOURCES ALASKA Well:OOSN-15� Input DLIS Files DEFAULT SCMT PSP_042PUP FN:59 PRODUCER 17-May-2010 07:52 11114.2 FT 10186.7 FT Output DLIS Files DEFAULT SCMT_PSP 043PUP FN:61 PRODUCER 17-May-2010 07:57 11186.0 FT 10238.5 FT CUSTOMER_DUS SCMT PSP 043PUC FN:62 CUSTOMER 17-May-2010 07:57 11186.0 FT 10238.5 FT OP System Version: 17C0-154 SCMT-CB 17C0-154 PSRP-A B 17C0-154 PIP SUMMARY CliTime Mark Every 60 S Transit Time(TI) Good Bond(GOBO) 300 (US) 260 0 (MV) 10 remm+t Roy!GR! Fluid Compensated CBL Amplitude 0 (GAPI) 100 (Cala) 0 (MV) 100 Discriminated CCL(CCLD) Amplified CBL Amplitude(Fluid 3 M .1 Compensated)1CBLF) O (MV) 10 Min Amplitude Max - - Cable Speed(CS) GOBO I - me -200 (F MN) 200 From ACBLF to GOBO VDL VariableDensity(VDL) 200 (US) 1200 :-�- r , 1 : , . 1 , . I 11 !__. 1 1 : .1 11111111111111111111111 I . 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CBL_VDL Vertical Scale. 5 per 100 Graphics File Created: 17-May-2010 07'57 OP System Version: 17C0-154 SCMT-CB 17C0-154 PSRP-A B 17C0-154 «<SCMT Cement Evaluation Information Summary>>> Sonde Serial Number SCMS-CB 8156 Current Casing Size 7.0 IN Casing Weight 26 0 LB F Expected CBL Amplitude 62 MV Minimum Sonic Amplitude 1 99348 MV(100°°Cements in Free Pipe Section 3.98428 MV(80°°Cement) MAP Minimum Sonic Amplitude 11.5946 MV(100%Cement) 17.8404 MV(80%Cement, Master Calibration(Normalization) Before Calibration ;Adjustment) Date of Master Calibration 20-MAY-2009 CBL Correction Factor 0.0684425 CBI. Adjustment Factor(CBAF) 1 0 MAP 1 Correction Factor 0.0840018 MAP Adjustment Factor (MPAF) 1.0 MAP 2 Correction Factor 0.100561 MAP 3 Correction Factor 0.0902777 MAP 4 Correction Factor 0 0931073 MAP 5 Correction Factor 0 0970001 MAP 6 Correction Factor 0 104581 MAD 7 r neree•Nnn Carinr n fQ11lOa9 MAP 8 Correction Factor 0.0751099 Parameters DLIS Name Description Value SCMT CB•Slim Cement Mapping Tool, 1-11 16 OD C83D SCMT CBL 3 ft Peak Detection Mode PEAK CB3G SCMT CBL 3 ft Peak Detection TO Delay and Noise Gate 249 726 US CB3T SCMT CBL 3 ft Fixed Threshold Level 20 MV CBSD SCMT CBL 5 ft Peak Detection Mode PEAK CB5G SCMT CBL 5 ft Peak Detection TO Delay and Noise Gate 363.726 US CB5T SCMT CBL 5 ft Fixed Threshold Level 20 MV CBLG CBL Gate Width 40 US CMTC SCMT Slow Channel Multiplexer Mode SCAN CMTM SCMT Operating Mode LOG CSCS SCMT Slow Channel Index VCC CTHI Casing Thickness 0.366591 IN DTF Della-T Fluid 169 US F FATT Acoustic Attenuation due to Fluid 0 DB F FCF CBL Fluid Compensation Factor 0.687361 GOBO Good Bond 6.68 MV MAPD SCMT MAP Peak Detection Mode PEAK MAPG SCMT MAP Peak Detection TO Delay and Noise Gate 192.726 US MAPT SCMT MAP Fixed Threshold Level 30 MV MATT Maximum Attenuation 8 19161 DB F VDLG VDL Manual Gain 5 ZCMT Acoustic Impedance of Cement 4 3 MRAY PSRP-A B- Production Services Recorder Platform Description of this pass System and Miscellaneous CSIZ Current Casing Size 7.000 IN CWEI Casing Weight 26 00 LB F DFD Drilling Fluid Density 10.10 LB G DO Depth Offset for Playback 72 0 FT PP Playback Processing NORMAL TD Total Depth -50000 FT Input DLIS Files DEFAULT SCMT PSP 042PUP FN:59 PRODUCER 17 May-2010 0752 11114 2 FT 10166.7 FT Output DLIS Files DEFAULT SCMT PSP 043PUP FN:61 PRODUCER 17May-201007:57 CUSTOMER DUS SCMT PSP 043PUC FN:62 CUSTOMER 17-May-2010 07.57 ScdlUDbeppP MEMORY SCMT REPEAT PASS 30 FPM UP MAXIS Field Loy Company: PIONEER NATURAL RESOURCES ALASKA Well:ODSN-15 Input DLIS Files DEFAULT SCMT_PSP_032PUP FN.49 PRODUCER 17-May-2010 06:36 11068.0 FT 10163.5 FT Output DLIS Files DEFAULT SCMT PSP 037PUP FN:54 PRODUCER 17-May-2010 07 21 11134.5 FT 10230 0 FT , OP System Version: 17C0-154 SCMT-CB 17C0-154 PSRP-A B 17C0.154 PIP SUMMARY ca Time Mark Every 60 S Transit Time (TT) G..•4.4 Bond(GOBO) 300 (US) 260 0 (MV) 10 Gamma Ray (GR) Fluid Compensated CBL Amplitude (CBLF) (GAPI) 100 0 (MV)(MV) 100 Discriminated CCL(CCLD) Amplified CBL Amplitude(Fluid 3 - M 1 Compensated)ICBM) -f) (MV) 10 Min Amplitude Max Cable Speed -CS) .... ... 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Discriminated CCL(CCLO� AmpUMed CBL Amplitude((Fluid Compensated)SCBLF) 3 - (V) -1 0 (MV) 10 Gamma Ray(GR) Fluid Compensated CBL Amplitude (CBLF) 0 (GAPI) 100 0 (MV) 100 Transit Time(TT) Good Bond(GOBO) 300 (US) 260 0 (MV) 10 PIP SUMMARY =Time Mark Every 60 S Format:CBL_VDL Vertical Scale. 5 per 100 Graphics File Created: 17-May-2010 0721 OP System Version: 17C0-154 SCMT-CB 17C0-154 PSRP-A B 17C0-154 «<SCMT Cement Evaluation Information Summary>>> Sonde Serial Number SCMS-CB 8156 Current Casing Size 7.0 IN Casing Weight 28.0 LB F Expected CBL Amplitude 62 MV Minimum Sonic Amplitude 1.99346 MV+100°°Cement) in Free Pipe Section 3.96428 MV(80°°Cement) MAP M nimum Sonic Amplitude 11.5946 MV(100°°Cement) 17.8404 MV(80°°Cement) Master Calibration(Normalization) Before Calibration(Adjustment) Date of Master Calibration 20-MAY-2009 CBL Correction Factor 0 0684425 CBL Ad ustment Factor)CBAF) 1.0 MAP I Correction Factor 0.0840018 MAP Adiustment Factor+MPAF1 1 0 PIONEER NATURAL RESOURCES ALASKA Pioneer Natural Resources Alaska. Inc. 700 G Street,Suite 000 Anchorage,Alaska 99501 Tel- (907)2772700 Fax(907)343 2190 January 5, 2013 Mr. Guy Schwartz State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite#100 Anchorage, AK 99501 RE: Submission of Fracture Modeling Study Data Attached please find the results of the fracture modeling studies performed by Pioneer Natural Resources Alaska, Inc. subsequent to our discussion of December 17, 2012. Fracture modeling studies were completed for both the Nuiqsut and Torok reservoirs, and all data studied has been included herein. If you have any further questions or comments, please do not hesitate to contact me. Sincerely, Tim Crumrine Senior Staff Completion Engineer Attachments: Fracture Modeling Study— Nuiqsut Fracture Modeling Study-Torok Pioneer Natural Resources Inc.Alaska Asset Fracture Modeling Study-Nuiqsut Background, The Alaska Oil and Gas Conservation Commission (AOGCC) has requested that fracture modeling is conducted on the Nuiqsut reservoir to determine height growth. Height growth of the induced hydraulic fracture is an important parameter to determine whether the fracture grows beyond the defined oil pool confining sedimentary rock layers violating pool rules (Oooguruk-Nuiqsut Pool) or Area Injection Order 034 in order to ensure protection of surrounding reserves. Pioneer has contracted a third party, Barree and Associates, LLC to conduct the fracture modeling study using the software program GOHFER. A meeting was held on December 17, 2012 at the AOGCC office in Anchorage, Alaska with AOGCC representatives, Chris Wallace, Guy Schwartz, Patricia Bettis, and Steve Davies, and Pioneer representatives Tim Crumrine, Andy Bond, Pat Foley, and Vern Johnson. The meeting discussion centered on conducting a fracture study that would be inclusive of all potential fracture stimulation rates and pressures, so that each individual well would not be modeled, but instead one model could be built in which the rates and pressures would exceed the capabilities of fracturing equipment hydraulic horsepower on location at the time of the fracture stimulation. This study is intended to cover all hydraulic fracture stimulations in the Nuiqsut oil pool, propped and unpropped (often referred to as high pressure breakdowns) in either producing or water injection wells. The following sections discuss the model input assumptions and the results from the induced hydraulic fracture study. Model Inputs and Assumptions Nuiqsut producing wells will be stimulated with two-million lbs of 16/20 mesh Carbolite ceramic proppant with approximately 200,000 lbs per stage for a total of 10 stages. Each producer well completion is set up to be mechanically or dynamically diverted, with some wells having a combination design. The greatest likelihood for a fracture to grow out of its confining intervals comes from a well with a vertical wellbore and a limited entry single perforation near the top or bottom of the interval being stimulated. Pioneer Alaska's wells are horizontal wells with multiple entry points that are landed in the middle of the zone. Essentially fractures in this type of wellbore are much less prone to fracturing out of zone. Each stage will contain approximately 200,000 lbs of 16/20 mesh Carbolite ramped from 0.5—10 ppa concentration with a 25 ppt cross-linked borate gel. The hydraulic horsepower on location during a fracture stimulation is approximately 12,000 HHP — based on anticipated pressures and rates. This equates to a rate limit of 60 barrels per minute based on expected pressures. Rates for the fracture modeling study were set at a limit of 80 barrels per minute: well above the available hydraulic horsepower on location. High pressure breakdown/scour treatments will be performed on injector wells with no more than 20,000 — 50,000 lbs of 20/40 mesh Carbolite proppant per stage. The injector well completions have smaller upper completions that limit the rate to 25 barrels per minute and are dynamically diverted. The fracture model geological input parameters were based on the Kalubik-1 well log data. Log data from the Kalubik-1 well were processed to derive rock mechanical properties and a stress profile for the fracture growth modeling. Based on previous MDT/RFT measurements, the pore pressure in the Nuiqsut was assumed to be on an effective 0.51 psi/ft gradient. No tectonic boundary conditions were applied to the stress profile. The Nuiqsut zone is shown in the figure below by the blue box. The two arrows indicate the upper and lower landing positions assumed for the modeling. These two fracture initiation sites are expected to represent any landing point in the zone. Kalubik 1 Processed Log Summary .. ,„„ . n: » irr ., • M • OM■ 1tKy.Trt!■ smo row •.•.•.' . M M . ..� s 6300.00 _... . r — =----"----,r-,_--,"" 6325.00 r^ ■► � ~ • _.�. . , 6350-00 _ � . ; 6375 00 dom. aikari 6400.00 2 .••: ? --- 6425.00 •_ I.. .t t 6450.00 — :•:•: . . . 6475.004, — 6500 00 - —n-ry•:–.r �. �Wa,...-. Nechelik r., .,_..;„ ? 6525-00 _ 6575.00ii __ ____ ........„,,,.__,=..., --",�. 6600 00 • 6625.00 - ---____--.7.7---.--,—.---' . .� _ -- .--t. F 2 12 6650.00 ••—,� _ ,A .---=--...--,...":4---, Figure 1. Kalubik-1 Processed Log Summary Modeling Results The proppant profile (side view) of the created vertical fracture in the upper part of the Nuiqsut is shown in the color-filled plot below. See Figure 2. The scale is 0-3 lb/ft2,shown at right.The fracture stays contained in the Nuiqsut at a maximum 80 bpm pump rate. A near-well concentration of 2-3 lb/ft2 is established,with a propped half-length of 300 feet.Vertical node resolution is 5 feet in the grid. ■i ' "1" gi3ii " it11ta : t-r `" .i11u irdcrd:iaiiiir■ *s' Mall r .c z tttut:gttttttttta: us MUM.:at aatttat ........ ..r.t.-_.. t.a�_. r..f.;.' :. Ye �;..,Yt ;-74 1 .I. i“ 1{1. •F • /4• ‘11V. ii it :•Y• b.wsr.0 ' •tt tttttiliiii i=i iUnnta 1 ' t; .""■"" s's'sii:=`satsiaEua�t::=r...• ..i ailaae' '�" -''.._' t1:::alllllftllnnllllllll�! l!!lllh'n11nnla'11!E la!!!! !!!!!1,'''LI Z4 —.v.: • 1r . . M••■• .:1.-"::..w.r...w:a' rrrrw M i fF ::#0,0040.0.00460,00 •....'-T• le ■ „..rM...r r.sss.rsr. It i 1 1111 ■...:r -..rte.. 111:11:::1MUI :e11u1r1: IH EEElEEMBE!!!H!!EE!!llEE!EE11t111ElEEllMIIMMININl -'°` ;.:i. tri : '°Minn::..rorr:=i -."' 'r't" r rn::::::CWrrrrir►iii r::N::.pr:::::: .. }1� iii �+AI 1�1 •1I� w =:: 1+Z� - : ::::::::::rr.............r w.r....... ill■ f r r FEN C 2012 A Figure 2. Proppant profile in the upper Nuiqsut Figure 3 is the proppant profile of an additional modeling run with the fracture initiated in the lower part of the Nuiqsut. As in Figure 2,the scale is 0-3 lb/ft2 with a vertical node resolution of 5 feet.The fracture stays contained in the Nuiqsut at a maximum 80 bpm pump rate. Pmp.wr Ca.c0.4,04n I�R'I a. . 6.4* :*KO Ill/1111H IIII Ii11i1111II1111111IIl 11 i 11111111 IIIIIi11i 11111ilili IIIIII lil i Illillll lit iiiiilIII Ili IIllhI IiIiiiiiiiilll Ii IIIIIIiHlliiiilili _ 1 Biiiiis ii 1 1111:1ii siuiiii111aii 111 111111.iai1111i111Ni1�11u111s111!_1111i11Bi1 i 1 E `~' '' Ilii11llli ui•II.1Ii.eIas ls o1a.oIaa ig11.Iiila o1Iia .. 11.N w .-, ...... , r:sas: aau :a:::::::: rs s : :: : :- �: .: — - aaarr ra. - Z. r.'.V • aura ' rr 11111111111111E1111111111111111I11111111111111111111111111111111111111111111111111111111113 r Jr. R�.wRtRRR�L1�rRR�Ii■..RFfirR,R .RR.�...R ■RRfRRrr.A��IRrw.R+11LRRRr�IrR.•R..R••••R uR ■Rlu,R. r.lrrrrrrr'raiYLlldr.krrrllii....hrrhr111111111111.rl:::::lll'r.rrirlIYrrrrr.a.. rr::::::�l °'i' , ■:r�RRR,:,.RrRa•RRR.Rr,sR..■r.....RR,S...u.RR,R•.RR,RRu•R.R.RRRUR.RRRRFlRRUURRR... ■i iiii..}�f R+RR.R PiP `aLa .: ' 1rra�ra�1■alLrrrrrlRrr111a1aaaaa..rr.1 1111.rr�rlyrrrarrri.hlU. rraaUl i�L....I�fllra�erra'�'�LYrrG� - ::::::::::::::a::a:::::::: :mum: a _---:-.-Y-° I'*1IIIIii!a�lliiijn eI 1 IH 1 UI1I imusii1*tII 'ii$flhIEf lU I U_lU l ` $ «' -, . ;Ia'alaaalfiilfi�rulllll.rrlllflrraS 1I I Alar .a I..ilaa a as c aar Y .ra ILlillilllEi 111iEEIIIIIR11111E 111111lilll 1111111 i ili ii ilhIIlliii' Ili 1111111111 : IIlIIIIIIII :I HhIl III I IlIII IIIIM.:, II1OOIIII1I H, IIIllh1IMO IIID HI O WOO 20 C 201 ' A Figure 3. Proppant profile in the lower Nuiqsut Conclusion Kalubik-1 well log data were processed to derive rock mechanical properties and a stress profile for the fracture growth modeling in the Nuiqsut reservoir. Two fracture initiation points were examined: one in the upper and one in lower sections of the Nuiqsut formation. A schedule placing 200,000 lbs of 16/20 CarboLite was run at the "worst-case" for height growth of 80 bpm. The current limitation for the maximum rate is based on the available horsepower on location. In either initiation point the fracture height is contained to the Nuiqsut at the maximum specified rate of 80 bpm. The most likely avenue for height growth is downward to the Nechelik, and this is not predicted to occur under any planned treating conditions. All treatments conducted below the maximum specified rates, pressures, and proppant concentrations are considered a subset of the models presented here in the study. Pioneer Natural Resources Inc.Alaska Asset Fracture Modeling Study-Torok Background The Alaska Oil and Gas Conservation Commission (AOGCC) has requested that fracture modeling is conducted on the Torok reservoir to determine height growth. Height growth of the induced hydraulic fracture is an important parameter to determine whether the fracture grows beyond the defined oil pool confining sedimentary rock layers violating pool rules (Oooguruk-Torok Pool) or Area Injection Order 037 in order to ensure protection of surrounding reserves. Pioneer has contracted a third party, Barree and Associates, LLC to conduct the fracture modeling study using the software program GOHFER. A meeting was held on December 17, 2012 at the AOGCC office in Anchorage, Alaska with AOGCC representatives, Chris Wallace, Guy Schwartz, Patricia Bettis, and Steve Davies, and Pioneer representatives Tim Crumrine, Andy Bond, Pat Foley, and Vern Johnson. The meeting discussion centered on conducting a fracture study that would be inclusive of all potential fracture stimulation rates and pressures, so that each individual well would not be modeled, but instead one model could be built in which the rates and pressures would exceed the capabilities of fracturing equipment hydraulic horsepower on location at the time of the fracture stimulation. This study is intended to cover all hydraulic fracture stimulations in the Torok oil pool, in both producing or water injection wells. The following sections discuss the model input assumptions and the results from the induced hydraulic fracture study. Model Inputs and Assumptions Torok water injection and production wells will be stimulated with two-million lbs. of 16/20 mesh CarboLite ceramic proppant with approximately 200,000 lbs. per stage for a total of 10 stages. Each well completion is set up to be mechanically or dynamically diverted, with some wells having a combination design. The greatest likelihood for a fracture to grow out of its confining intervals comes from a well with a vertical wellbore and a limited entry single perforation near the top or bottom of the interval being stimulated. Pioneer Alaska's wells are horizontal wells with multiple entry points that are landed in the middle of the zone. Essentially fractures in this type of wellbore are much less prone to fracturing out of zone. Each stage will contain approximately 200,000 lbs. of 16/20 mesh CarboLite ramped from 0.5—10 ppa concentration with a 25 ppt cross-linked borate gel. The hydraulic horsepower on location during a fracture stimulation is approximately 12,000 HHP — based on anticipated pressures and rates. This equates to a rate limit of 60 barrels per minute based on expected pressures. Rates for the fracture modeling study were set at a limit of 65 barrels per minute: well above the available hydraulic horsepower on location. The fracture model geological input parameters were based on the ODSN-45 (later recompleted and renamed to ODST-45A) well log data. Log data from the ODSN-45A well were processed to derive rock mechanical properties and a stress profile for the fracture growth modeling. No tectonic boundary c conditions were applied to the stress profile. The Torok zone is shown in the figure below. Two fracture initiation sites were modeled: one just above the middle Torok and one just below the middle Torok. These fracture initiation points are expected to represent any landing point in the zone. — — —i 02929. -Poesin's Ratio--------03556 0----.._._...Pereeeeiv OM) 291243 0----------Pamir Otetin)---------c 19 3539072-------.P1 Sees 0,6; KO j 35523----raa See$s(88)----4407 18914E-06-.vomit*lout*CIE-38797E-06 1-----------An Buys-----------2 0 Paurl 0aa'Ie(*Wont-----046117 216834PmPessae(881----234428 3756207-- Cf0PrestueIDs0---5057 OS Vert.48 s 0.8847 .4.509#37&14-Pacer4 tm69ne(M,An)-0484 4513t 4915 -- 4•W' __J_ -- 4• 49124 �. I , 1 I 1 1 1-11111-1111i ton' --- 501 ', 5018( r 50181 I ■ I r _ _LP _ ' iirt, ,,, 7 r ! 1 1 1 J ) ' 1 U f 1 If [--I 5 =M111••••1151111 1 5 51T26 ri fij flI I e , r L 4 Z { 1 1 1 511 52121 21 2 W r i 1, r 1 , 1 Figure 1. ODSN-45 Processed Log Summary Modeling Results The proppant profile (side view) of the created vertical fracture in the upper part of the Torok is shown in the color-filled plot below. See Figure 2. The scale is 0-1.2 lb/ft2, shown at right. The fracture stays contained in the Torok at a maximum 65 bpm pump rate. A near-well concentration of 0.6—1.2 lb/ft2 is established,with an effective propped half-length of 500 feet.Vertical node resolution is 5 feet in the grid. Proppant Concentration IbIR2 J 27.90 Minutes ro TVD.ft ascan 5031h .arc- 5097h 5116 516th r 5231h 'fi CGG] Igo, MIF I -E Figure 2. Proppant profile in the upper Torok Figure 3 is the proppant profile of an additional modeling run with the fracture initiated in the lower part of the Torok. The scale is 0-1.17 lb/ft2 with a vertical node resolution of 5 feet.The effective fracture half-length is 575 feet. The fracture stays contained in the Torok at a maximum 65 bpm pump rate. provn•ntconartrmol JIM 1 MO TWA 496111 503151 509711 • • 516111 523111 lair 1,1111 C831L D. Figure 3. Proppant profile in the lower Torok Conclusion ODSN-45 well log data were processed to derive rock mechanical properties and a stress profile for the fracture growth modeling in the Torok reservoir. Two fracture initiation points were examined: one in the upper and one in lower sections of the Torok formation. A schedule placing 200,000 lbs. of 16/20 CarboLite was run at the "worst-case" for height growth of 65 bpm. The current limitation for the maximum rate is based on the available horsepower on location in which 65 bpm exceeds the capabilities available. In either initiation point the fracture height is contained to the Torok at the maximum specified rate of 65 bpm. The most likely avenue for height growth is downward and this is not predicted to occur under any planned treating conditions. All treatments conducted below the maximum specified rates, pressures, and proppant concentrations are considered a subset of the models presented here in the study. Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Friday, March 21, 2014 1:25 PM To: 'Kralick,Jack' Cc: Bettis, Patricia K(DOA);Wallace, Chris D(DOA) Subject: RE:ODSN-15i (PTD 210-032) Jack, I reviewed the WFL data and agree no water upflow is seen so the cement is competent at the 7" casing shoe. The Fracture Model Study (from January 2013) provided does includes both injector and producer information though is specific to the larger fracture stimulations of production wells. You have verbal approval to fracture stimulate well ODSN-15i. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-7934226 office From: Kralick, Jack [mailto:Jack.Kralick Upxci.co°n.] Sent: Friday, March 21, 2014 12:48 PM To: Schwartz, Guy L(DOA) Subject: ODSN-15i Hello Guy, Attached are the recent WFL(SpectraFlo)done by Halliburton for well ODSN-15i and a study done for both the Torok and the Nuiqsut. We were hoping for a verbal on 15i for a HPBD. Let us know if there's anything else you need. Thanks, Jack Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error,please notify the sender by reply e-mail and delete the message and any attachments. 1 ' STATE OF ALASKA RECEIVED AL A OIL AND GAS CONSERVATION COMI h-SION REPORT OF SUNDRY WELL OPERATIONS DEC- 17 2013 1.Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Stimulate is Other A GC Performed: Alter Casing ❑ Pull Tubing❑ Perforate New Pool ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Perforate ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Pioneer Natural Resources Alaska Inc Development❑ Exploratory❑ 210-032, 3.Address: 700 G Street, Suite 600 Stratigraphic❑ Service Is 6.API Number: Anchorage,AK 99501 50-703-20618-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 355036/ADL 355037 • ODSN-15i . 9.Field/Pool(s): Oooguruk-Nuiqsut Oil Pool. 10.Present Well Condition Summary: Total Depth measured 17,383 feet Plugs measured N/A feet true vertical 6,096 feet Junk measured N/A feet Effective Depth measured 17,139 feet Packer measured See below feet true vertical 6,117 feet true vertical feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 158' 158' N/A N/A Surface 3550' 11-3/4" 3589' 2982' 5830 psi 3180 psi Intermediate 5493' 9-5/8" 3377'-8870' 2880'-5301' 5750 psi 3090 psi 1 Production 11,314' 7" 11,348' 6165' 7240 psi 5410 psi Liner 5945' 4-1/2" 11,195'-17,140' 6117'-6117' N/A N/A I Perforation depth Measured depth See Attachment feet True Vertical depth feet SC~ Tubing(size,grade,measured and true vertical depth) 3-1/2", 9.3# L-80,TCII 11,207'MD 6121'TVD 11210'MD/6124' 1995'MD/1870' j Packers and SSSV(type,measured and true vertical depth) 5"x7"Lnr Tp Pkr ND Wellstar TRSSSV TVD 11.Stimulation or cement squeeze summary:High Pressure Break Down Intervals treated(measured): Treatment descriptions including volumes used and final pressure: See attached operation summary report I 12. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: - - 877 827 2651 - Subsequent to operation: - - 1950 574 2530 13.Attachments: 14.Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development❑ Service IS• Stratigraphic ❑ Daily Report of Well Operations X 15.Well Status after work: Oil ❑ Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG Ell. GINJ ❑ SUSP❑ 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: 313-032 Contact Jack Kralick Printed Name '/ ! Jack Kralick Title Well Work Supervisor Signature V �—c' Phone 343-2185 Date I2 13/13 yi__ a2-. -ly RSA'SAS DEC 2 0 2Q Form 10-404 Revised 10/2010 Submit Original Only A 74-K7 • Pioneer Natural Resources Alaska Inc. ODSN-15i Page 2 Form 10-404, Report of Sundry Operations Attachment - Box #10 & 11 10 and 11. Open to production or injection 4-'/Z", 12.6#, L-80 Hyd 521 Uncemented Liner Sliding Sleeves w/6ea. '/2" Ports — open @ depths listed: MD TVD 11,381' — 11,387' 6176' — 6177' 11,742' — 11,747' 6232' — 6232' 12,625' — 12,630' 6235' — 6235' Sliding Sleeves w/2 - .20 Jets — closed @ depths listed: MD TVD 11,470' — 11,475' 6199' — 6200' 12,065' — 12,070' 6248' — 6248' Perfed Pups w/6-1/2" Holes @ depths listed: MD TVD 13,922' — 13,927' 6189' —6189' 14,396' — 14,401' 6182' —6182' 14,790' — 14,795' 6184' —6184' 16,891' — 16,896' 6137' —6136' p1ONEER )perations Summary Report - Sta Well Name: ODSN-15i NATURAL RESOURCES Well Name: Contractor: Rig Number: Job Category: Start Date: End Date: Start Depth Foot/Meters Dens Last Start Date End Date (ftKB) (ft) Mud(lb/gal) Summary 4/14/2013 4/15/2013 17,383.0 R/U stinger and frac lines.Pressure test lines to 8,500(psi). IA=1,000(psi),BHP=4,688(psi). Little Red Services pressured up IA=3,500(psi).Pumped as per frac design,Frac Fluid= slickwater w/.5(gpt)of FR, Proppant=carbolite 16/20,ball size=.875".ASTP=6,700(psi), APR=23(bpm),Total Slickwater=5,580 (bbl),Total proppant=28,360(Ibs),Total balls dropped=36.Sand pumped into each stage=4,236(Ibs)into 1,3,998(Ibs)into 2,3,946(Ibs) into 3,4,040(Ibs)into 4,4,060(Ibs)into 5,4,050(Ibs)into 6,4,030(Ibs)into 7.Freeze protect lines and well with 55(bbl)of LVT.Shut well in.R/D Stinger and frac lines.Handover well to production.Will be performing preventative maintenance until further instruction are provided. Further details on the frac provided on the section below. 4/15/2013 4/16/2013 17,383.0 Rig down all frac iron from ODS,and move same to frac pad.Move frac bleed off tank from ODS to frac pad.Rig down stinger,service same and release personnel.Prep Stinger tools for demob. Empty all frac tanks in preparation for rig down.Rig down LRS lake heater and release same. Begin offloading Scale-Sorb from sand castle.Perform general maintenance and housekeeping on frac equipment. 4/16/2013 4/17/2013 17,383.0 Rig down frac equipment including;growler,hydro tank,2 chem-add trailers,blender,all frac pumps from missile(6),and move all rigged down equipment to the parking lot in preparation of demob.Finish offloading Scale-Sorb from sand castle.Perform general housekeeping on frac \t) pad. 4,nv 4/17/2013 4/18/2013 17,383.0 Continue rigging down frac equipment;missile and remaining 4"frac line,frac tank manifolds, and move all frac tanks to the parking lot,rig down QC shack,and TSS.Rig down sand castle and offload remaining 16/20 Carbolite into bulk hauler.Move all frac equipment from frac pad to the parking lot in preparation for demob.Load extra equipment from AIC shop into mechanics trailer.Frac equipment is 100%rigged down,and 30%demobed to Deadhorse. 4/18/2013 4/19/2013 17,383.0 Demob 4 loads of frac equipment to Deadhorse;2 Mountain Movers,Sand Castle and 100 bbl blender.Demob 9 frac tanks and hydro-tank to Deadhorse,frac equipment is 60%demobed. Finished loading all loose equipment into HES connex. Frac crew performed general housekeeping on frac pad and parking lot. Nanuq maintainer came out and tight bladed frac pad. 4/19/2013 4/20/2013 17,383.0 Finish demobing all of HES frac equipment to Deadhorse.Finish demobing all frac tanks to Deadhorse,and continue demobing rental equipment to same.Continue ice pad clean up.Rig up snow melter,mechanic here to service same. 4/20/2013 4/21/2013 17,383.0 Demob AIC shop and Enviro-Vac.Continue melting snow and pad clean up.Rig down all communications to frac camp and office.Move PNR owned furniture out of frac office and prep same for demob.Shut down all food services in frac camp and begin clean up procedure in preparation for demob. 4/21/2013 4/22/2013 17,383.0 Demob frac office building back to AIC in Deadhorse.Continue ice pad clean up and snow melting.Continue clean up on frac camp and prep same for demob. 5/1/2013 5/2/2013 17,383.0 Cost place holder 10/16/2013 10/17/2013 17,383.0 10/17/2013 10/18/2013 17,383.0 10/18/2013 10/19/2013 17,383.0 10/19/2013 10/20/2013 17,383.0 10/21/2013 10/22/2013 17,383.0 10/22/2013 10/23/2013 17,383.0 Page 1/3 Report Printed: 12/12/2013 O = U >. ,. > oo X00 �w0 N J 0 w ' m y m a ?� o Cl) 0 o CO } t- af oa�o c o 0 0) 'Z .Z rn N ' a a) 7 a a) N d a) Cl.) 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Q.' 0 I- J 0 H w W J J J J J J J J J ___ 0 9 0 O ) co 1 o >- - N c U ,; o N Z a z a 0 Ili > > ci O m o i— w cn cn 0 Ce _j O g z_ 0 Om I- r 6 1 W z I W v W o V a O u Z W a Q I°- ■ y 7 N O I J a z O E I /� cn —' E I CL N co o 2 g ° o LL O if a H 0 V H J Q Z o F— 0 o a o C Z N CO Z rn Y ic-) MCl)vI 00 p Q O O o o �1 Z p Z , • co 0 co M i 1 9 m O d O \ I d Z m M N d' C Z a�i v c o 0 a a.0 E a £ 0 m c, E E a Q U <a 0 ' 0 • of T w ��AIy%y c THE STATE A'aska i t and Gas TT ^^ r GOVERNOR SEAN PARNELL 333 West Seventh Avenue ALAS Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Judy Golding Well Work Supervisor Pioneer Natural Resources Alaska, Inc. — 0 3 700 G Street, Suite 600 Anchorage, AK 99501 Re: Oooguruk Field,Nuiqsut Oil Pool, ODSN-15i Sundry Number: 313-032 Dear Ms. Golding: 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 day of February, 2013. End. p.. STATE OF ALASKA ": • '2, 4 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION OTS z1 2-°APPLICATION FOR SUNDRY APPROVALS „ 20 AAC 25280 "' 1.Type of Request: Abandon❑ Plug for Redrill ❑ Perforate New Pool❑ Repair Well❑ Change Approved Program ❑ Suspend❑ Plug Perforations❑ Perforate❑ Pull Tubing❑ Time Extension ❑ Operations Shutdown❑ Re-enter Susp.Well ❑ Stimulate in Alter Casing❑ I Other. ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Pioneer Natural Resources Alaska,Inc. Exploratory [] Development ❑ 210-032 3.Address: 700 G Street,Suite 600 Stratigraphic ❑ Service Q , 6.API Number. Anchorage,AK 99501 50-703-20618-00-00 • -- 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? NA ODSN-15i- Will planned perforations require a spacing exception? Yes ❑ No io 9.Property Designation(Lease Number): _ 10.Field/Pool(s): ADL 355036/ADL 355037 Oooguruk-Nuiqsut Oil Pool- 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): ft 17,383' 6096' - 17,139' 6117' N/A N/A Casing Length Size MD ND Burst Collapse Structural Conductor 110' 16" 158' 158' N/A N/A Surface 3550' 11-3/4" 3589' 2982' 5830 psi 3180 psi Intermediate 1 5493' 9-5/8" 3377'-8870' 2881'-5301' 5750 psi 3090 psi Intermediate 2 11,314' 7" 11,348' 6165' 7240 psi 5410 psi Liner 5945' 4-1/2" 11,195'-17,140' 6117'-6117' 8430 psi 7500 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attachment,pg.2 • See Attachment,pg.2 _ 3-1/2",9.3# L-80,TCII 11,207' Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): See Attachment,pg.3 ' See Attachment,pg.3 12.Attachments: Description Summary of Proposal 0 13.Well Class after proposed work: Detailed Operations Program 151 BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development❑ Service 14.Estimated Date for 15.Well Status after proposed work: Operations: 4/10/2013 Commencing Oil g O pe ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG el. Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact July Golding,343-2179 Email judy.golding@pxd.com Printed Name Judy Golding 'Title Well Work Supervisor Prepared By Kathy Campoamor,343-2183 Signature Phone Date 343-2179 1/22/2013 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ?13 -(_ 32 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: RBDMS FEB 21 ?. Spacing Exception Required? Yes ❑ No Subsequent Form Required: /0 _zi 0 V APPROVED BY Approved by: 44 COMMISSIONER THE COMMISSION Date: c,2 —a0— (/ 3 0 Rtatti7divi.2_, Approved application is valid for 12 months from the date of approval. ♦♦hritetsait!ate� A L , lif'1,3 ,,\, Pioneer Natural Resources Alaska Inc. ODSN-15i Page 2 Form 10-403, Application For Sundry Approvals Present Well Condition Summary, Box #11 Perforation Depth (MD/TVD) - Attachment 4-W, 12.6#, L-80 Hyd 521 Uncemented Liner Sliding Sleeves w/ 6ea. '/z" Ports—open @ depths listed: MD TVD 11,381' - 11,387' 6176' -6177' 11,742' — 11,747' 6232' — 6232' 12,625' — 12,630' 6235' —6235' Sliding Sleeves w/ 2 - .20 Jets— closed @ depths listed: MD TVD 11,470' — 11,475' 6199' —6200' 12,065' — 12,070' 6248' —6248' Perfed Pups w/6-1/2" Holes @ depths listed: MD TVD 13,922' — 13,927' 6189' —6189' 14,396' — 14,401' 6182' —6182' 14,790' — 14,795' 6184' —6184' 16,891' — 16,896' 6137' —6136' Pioneer Natural Resources Alaska Inc. ODSN-15i Page 3 AOGCC Form 10-403, Application For Sundry Approvals Present Well Condition Summary, Box #11 Packers and SSSV Type (M DITVD) - Attachment SSSV w/ 2.813 x Profile TCII BxP MD ND 1995' 1870' 7" UltraPak TH Hyd Perm Packer MD ND 9413' 5525' Liner Top Packer MD ND 11,210' 6121' Swell Packers MD ND 11,520' - 11,537' 6,209' - 6,212' 13,348' - 13,366' 6,221' - 6,220' 15,392' - 15,409' 6,203' - 6,204' 16,047' - 16,064' 6,203' - 6,201' PIONEER NATURAL RESOURCES ALASKA ODSN-15i HPBD Ref: Permit To Drill: 210-032 Current Status: ODSN-15i was recently converted from gas injection to water injection. At present,the well is taking 2500 b/d of injection water. Trends in the Nuiqsuit show that as the BHP rises due to water injection and the amount of fluid injected to replace voidage, in general, drops to the 1200- 1500 b/d range. The HPBD is proposed at this point in time to maintain the injection rate in the 2500 b/d range. Scope of work: 1. MIT-IA to 2800 psi. Ensure the test is recorded on the DCS system. 2. MIRU frac tanks. Load tanks with Conoco seawater(estimated 13 tanks). Maintain water temperature around 70° F. 3. MIRU Halliburton frac pumps and associated equipment. 4. Rig up second swab valve and well head isolation tool. (See diagram,Attachment 'A'). 5. Rig up treating lines to well and pressure test treating iron. 6. Tie hot oil truck into IA and pressure up IA to 2500 psi. Maintain this pressure during all pumping operations. (Based on tube move calculations, Attachment 'B'). 7. Pump the following at a max rate allowable to maintain the WH treating pressure is below 6600 psi. It is assumed that due to the 3.5" tubing,the maximum rate will be 20-25 bpm. a. 100 bbls slick water b. 200 bbls slick water with 0.5 ppg 20/40 Carbolite c. 480 bbls slick water d. 20 bbls LVT with 12-7/8" bio balls i. Repeat steps (7a)—(7d)six times ii. On the seventh and final stage, do not drop the bio-balls but instead swap to 20 bbl LVT freeze protect for the well. 8. Rig down frac equipment, WH isolation tool, and secondary swab valve. 9. Return well to injection. General Well Info: MASP- 6600 psi.There will be a tree saver installed across the tree and set below the pup joint attached to the tubing hanger.The tree saver is rated to 10,000 psi. Reservoir pressure/TVD- 4000 psi/6,200' Wellhead Type/pressure rating Vetco injection system/5K Tree configuration Vetco 3-1/8" 5K tree with isolation tool MIT-IA/Mit OA - MIT-IA passed on 07/25/2011 MIT-OA passed—N/A open annulus Cement - The 7" casing was cemented using 43 bbls (206 sx) Lead slurry of 12.5 ppg Class 'G' cement with additives. The Tail slurry was 19 bbls (91 sx) of 15.8 ppg Class 'G'with additives. The plug was dropped and displaced with 411 bbls of 11 ppg mud. The plug was bumped and pressured up to 4500 psi for 30 minutes. A CBL was run and a copy is attached. Flowback- This well is an injector so there will be no flowback. Well Type- Injector Estimated Start Date- April 10,2013 Completion Engineer Tim Crumrine Wells Supervisor Judy Golding Work phone 907-343-2179 Cell phone 907-231-0872 iudv.golding @pxd.com . Attachment A OPEN POSITION CLOSED POSITION (PRIOR TO MANDREL INSERTION( ■MANDREL INSERTED' FRAC IRON ~-- / CONNECTION 1 I 'r ,Y i i Remote Valve • . TT �� REMOTE OPERATED TT T� from center 28" - MASTER VALVE •1 �O/ wuwult OPERATED .0. MASTER VALVE i /.�h I 128"total `J Tool Width \ i length 212"total length ��t9 in open position Slinger Stinger Bottom of remote —lir ' ' valve to bottom of . ' \SAANOBEI wellhead flange 59" 1` \ T ^ j ' Bottom of manual Li VENT valve to bottom of I 1 ,Y I 6"Greyloc ró1 -yLL flange 40" 4 k.• OPEN ,_...t i •"'is- 7,4. 41/16 wellhead ___N„ ` 11, 1• 8" .\ ___.rte flange %, 11.-•��. FLOW TEE AND / .• 4Y,Setup • ,!■7`,' VENT VALVE WFI 1 HEAD length 18" ' —alit VALVES zoo*A OPEN N WELLHEAD ___.i. i3` VALVES . . CLOSED Ii [ �71r11•, - y k ~•.• Y}- . - •1 OUAD PACKOFE r--�. ASSEMBLY IN ' ..r ve 2r PLACE IN TUBING r 1E' $1 i 1 . f 4.d Universal Tool and Box 10,840 lbs (184"L X 49"W X 43"H) Hydraulic Power Pack 2500 lbs ( 61"L X 61"W X 53"H) Attachment B IV Weatherford' Completion Systems Tubing String Analysis Force: Negative implies Tension Output Data Length:Negative implies shorter p Buckling Calculations are made Top(or only) Packer Middle(or 2nd)Packer 1 Bottom (or 3rd) Packer Length(inches) Force(Ibs) Length(inches) Force(Ibs) Length(inches) Force(Ibs) Piston Effect -43.37 -29,616 Does Not Apply Does Not Apply Does Not Apply Does Not Apply Buckling Effect -9.82 0 Does Not Apply 0 Does Not Apply 0 Ballooning Effect -22.30 -15,229 Does Not Apply Does Not Apply Does Not Apply Does Not Apply Temperature Effect 17 78 12,140 Does Not Apply Does Not Apply Does Not Apply ,Does Not Apply Slackoff Effect 0.00 0 Does Not Apply Does Not Apply Does Not Apply Does Not Apply Total -57.711 -32,705 0.00 0 0.00 0 (Force change if anchored; Length change if free to move) Maximum Tubing Stress,psi 36,615 Does Not Apply Does Not Apply, Tubing safety margin Average,% 45.77% Does Not Apply Does Not Apply Force on Top Joint(initial)lbs 81,616 Does Not Apply Does Not Apply Force on Top Joint(final)lbs 84,705 Does Not Apply Does Not Apply Tbg to Packer Force(initial)lbs 0 Does Not Apply Does Not Apply Tbg to Packer Force(final)lbs -32,705 Does Not Apply Does Not Apply Slackoff Reaching Packer lbs 0 Does Not Apply Does Not Apply Delta P _,ss Tubing below Packer NA NA NA Delta P Across Packer(final)psi 4,650 Does Not Apply Does Not Apply Delta P Across Tubing above Packer 4,650 Does Not Apply Does Not Apply Max Wireline Tool Length(in) 320 Does Not Apply Does Not Apply Positive pressure is from BELOW the Packer Stress on Top Joint(initial)(psi) 31,510 Does Not Apply Does Not Apply Stress on Top Joint(final)(psi) 32,702 Does Not Apply Does Not Apply Burst Tendency Packer(psi) 36,615 Does Not Apply Does Not Apply, Tubing Tri-Axial Stress(final) Outside(psi) 27,765 Does Not Apply Does Not Apply Inside(psi) 33,892 Does Not Apply Does Not Apply Tubing Weight(air)(Ibs) 87,234 Does Not Apply Does Not Apply Tubing Weight(initial fluid)(Ibs) 78,431 Does Not Apply Does Not Apply Neutral Point Abv.Pkr.(initial;ft) 0 Does Not Apply Does Not Apply Neutral Point Abv.Pkr.(final;ft) 2,596 Does Not Apply Does Not Apply Buckle Pitch(intial;ft) 0.00 Does Not Apply Does Not Apply Buckle Pitch(final;ft) 49.41 Does Not Apply Does Not Apply Helix Angle(initial;deg) 0.00 Does Not Apply Does Not Apply Helix Angle(final;deg) 0.84 Does Not Apply Does Not Apply This Program is Copyrighted January 31,2000 by Weatherford The information and results computed by this program are based on generally accepted data and physical International and embodies the proprietary and confidential information relationships described within papers presented to the Society of Petroleum Engineers. Because of evolving of Weatherford International The recipient agrees that this Program is well conditions and other unknown information,no warranty is given by Weatherford International,expressed loaned in confidence with the understanding that neither it nor the or implied,concerning the results obtained from the use of this program. information in d will be reproduced,used or disclosed in whole or in part for any purpose except the limited purpose for which it is loaned.This Program shall be returned to Weatherford International upon demand. lSequence No 41296.4196 I ver 10102001 Pioneer Natural Resources Inc.Alaska Asset Fracture Modeling Study-Nuiqsut Background The Alaska Oil and Gas Conservation Commission (AOGCC) has requested that fracture modeling is conducted on the Nuiqsut reservoir to determine height growth. Height growth of the induced hydraulic fracture is an important parameter to determine whether the fracture grows beyond the defined oil pool confining sedimentary rock layers violating pool rules (Oooguruk-Nuiqsut Pool) or Area Injection Order 034 in order to ensure protection of surrounding reserves. Pioneer has contracted a third party, Barree and Associates, LLC to conduct the fracture modeling study using the software program GOHFER. A meeting was held on December 17, 2012 at the AOGCC office in Anchorage, Alaska with AOGCC representatives, Chris Wallace, Guy Schwartz, Patricia Bettis, and Steve Davies, and Pioneer representatives Tim Crumrine, Andy Bond, Pat Foley, and Vern Johnson. The meeting discussion centered on conducting a fracture study that would be inclusive of all potential fracture stimulation rates and pressures,so that each individual well would not be modeled, but instead one model could be built in which the rates and pressures would exceed the capabilities of fracturing equipment hydraulic horsepower on location at the time of the fracture stimulation. This study is intended to cover all hydraulic fracture stimulations in the Nuiqsut oil pool, propped and unpropped(often referred to as high pressure breakdowns)in either producing or water injection wells. The following sections discuss the model input assumptions and the results from the induced hydraulic fracture study. Model Inputs and Assumptions Nuiqsut producing wells will be stimulated with two-million lbs of 16/20 mesh Carbolite ceramic proppant with approximately 200,000 lbs per stage for a total of 10 stages. Each producer well completion is set up to be mechanically or dynamically diverted,with some wells having a combination design. The greatest likelihood for a fracture to grow out of its confining intervals comes from a well with a vertical wellbore and a limited entry single perforation near the top or bottom of the interval being stimulated. Pioneer Alaska's wells are horizontal wells with multiple entry points that are landed in the middle of the zone. Essentially fractures in this type of wellbore are much less prone to fracturing out of zone. Each stage will contain approximately 200,000 lbs of 16/20 mesh Carbolite ramped from 0.5—10 ppa concentration with a 25 ppt cross-linked borate gel. The hydraulic horsepower on location during a fracture stimulation is approximately 12,000 HHP— based on anticipated pressures and rates. This equates to a rate limit of 60 barrels per minute based on expected pressures. Rates for the fracture modeling study were set at a limit of 80 barrels per minute: well above the available hydraulic horsepower on location. High pressure breakdown/scour treatments will be performed on injector wells with no more than 20,000 — 50,000 lbs of 20/40 mesh Carbolite proppant per stage. The injector well completions have smaller upper completions that limit the rate to 25 barrels per minute and are dynamically diverted. The fracture model geological input parameters were based on the Kalubik-1 well log data. Log data from the Kalubik-1 well were processed to derive rock mechanical properties and a stress profile for the fracture growth modeling. Based on previous MDT/RFT measurements, the pore pressure in the Nuiqsut was assumed to be on an effective 0.51 psi/ft gradient. No tectonic boundary conditions were applied to the stress profile. The Nuiqsut zone is shown in the figure below by the blue box. The two arrows indicate the upper and lower landing positions assumed for the modeling. These two fracture initiation sites are expected to represent any landing point in the zone. Kalubik 1 Processed Log Summary _ .. ...„„ ORR It ..- F n 1/J. 1 Ite ,..ID .”. ............ ... . ...a... N f ....•. _ --- -__..._..... .. ._ .. ■ :M • - - 6300.00 imp ► _ .�^ � — --1 G� 8925.00 ,....„,...r... .^_1.,, - .. 1 O►�iii i ! --- rI 636000 t _..:_ � =_---- --.::;.:::::: r---.--- iiiimmummio - A-m:::::: .o 6975 00 .rte∎"iZ"" r.=„ • 2:'�:;�;IrwMillki 6400 a0 ,`;.f ...: dB 111•1111111111111111111111 : s.:....:.:.:.:.:.. , Nuigsut "' 642500 ,� ��"'."� "` . ▪ • •:;`. . 1 ' 6450.00 - . . :o' -illy ��� — �' 647500 4"41` 650000 r � � .-•••; i „ a_� M2 r:r. Nechelik :: .rte 6525.00 `�. ■.� . . T art air �..._ =ws_a"' •'. �J: .4 I: mow MEE RAE I ' :';t:, .:i 1 — 6575.00 !' 6 �_ r ' ��. �' ` 2012 lbaciA 6650 00 Figure 1. Kalubik-1 Processed Log Summary Modeling Results The proppant profile(side view)of the created vertical fracture in the upper part of the Nuiqsut is shown in the color-filled plot below. See Figure 2. The scale is 0-3 lb/ft2, shown at right.The fracture stays contained in the Nuiqsut at a maximum 80 bpm pump rate. A near-well concentration of 2-3 lb/ft2 is established,with a propped half-length of 300 feet.Vertical node resolution is 5 feet in the grid. i rnUW2I iiiaii�aiiiiiipiiiaaaanuni7aiissaiaiatilaa!"a laaaaali 2aaaaa=t'paaasa�7iiilaica _`• ' s' ssiasa»is cilia:a:aaaii's`ssass as muiisasaaaaaaassiiiisais�siiiass`saaasaaasi:sib • " . N. .w.Y ..u!N..E.E ti::::::S.3..aw N:. .:.Y wS. raw ia.: • +1 y G ....o. .w. �••'� •. niumiiiia93iii:i ai:initu raiGi:iia:ii: • tC. ....rw..... w.....1.....•..r....w..•.....N.N....r..w .-��.•�a a«� :. r..«. - " ",«::iaaaaa:a3iaiia3:iCiaaai3aiaGii p10:a3iiiaaaii 1 ? �..: .'°�=-° •o:aaaasaiiiaiinaiiitaaaiiisaiiea .w..Y....N..Y '�:�:;:�•,. T »:guar-= •a�sasaaaaaaiiii'SSeasiii�ii3aiissaia�aaesaui:aasaa .•f•. rw....1.Nt.N.r r.Y..Y w rwr.. .� :saaaca. : . ...:r..sn . ::.:aa staa at s. e r.i.iw.N.iii.w.woori. '+ t ,y- w • ..«iriaaii::• ;n?::i�....r�wr�.;rrr...a.rrra OA.4:11•••• w...... "aaiai::ttiu:i::GiG3::ii3 �.. r. N..ww. . .r.w.u.Yw• aimiaaiagaaiiu truiiaiii:iiiatun$aiun iiiiia33aa0iRgiaitaaiai9"aii�Ztiiiiiai7i :� ..rs.NUww.ruu wrw.w.Y ur.w .w.r..wrw.ro.aN.rwr y' a i��aiania�ggttaii tiai�naiitra:isccet%�iia�sini:aiaiiasaaca:gaiia:a�seesininiin 1•M isaaansiigunu nsfaaa sasansiaaaaiaiiaarnansquisaiaasassaeiassia ii cnnu:a as iintx :a:iii iiiaaaii:aaai�iiiaiiaiii:i iiiinia iiaisium iai i"rii:aparaz ::iihii !�• . . .w. r�w.wr. 3:.ww.r.o.'w�.w . u..l . . LG. . w..•.. . .r iataitaaaituis aaitaannumaaiii aamint�iaaa iiisiuisiiaturiiaaaashu iiiiiisiaaaiwiiii .rrr•'r.r..q..w....r .w...rri ..rN.N...wr .Orrr w.wr.r..w.N...ww.w...• ssari aiassaaissastta�ia si sanas:assaoisaaaiaaisaitsisissasma isasssassssa:iaaissais }; iiiistaiianiiiiiisassssaiiiia�iiaiiisaiuiailaisst iaataiis�is aiiissaira9ii aiisitsaa a...a^ a n u .a...w s.ws..w.o.w.N.u.N. ■u • .w...Nw.• seaiaeiwmaaaaasanaas 'si'scaaaasaaaaaa aassasaus:saaasst�s s3aiaaass ziu.m;=etiris:a i=s??:eiaa MIMIIM l aisa:siai.= Ziuz; arsYZiii : ::e:uic 9e.c :s=ue=�:;zs itata6ta:isiaiiaiaisRa3iiii:aAiiitCaaa i: trait:i:ttla a a:iiii3Sa3iasaiiii -a..,. ..w.r. wr..NOSUru.rar .w.r. .rrw.rw.r .rrr taazniiaatniE isiaiiisiiaa aiaanaiaa mnut aanten niiiiiiimiiiEiiiiiiin its C 2012 tiZkiiik Figure 2. Proppant profile in the upper Nuiqsut Figure 3 is the proppant profile of an additional modeling run with the fracture initiated in the lower part of the Nuiqsut. As in Figure 2,the scale is 0-3 lb/ft2 with a vertical node resolution of 5 feet.The fracture stays contained in the Nuiqsut at a maximum 80 bpm pump rate. n. 1. rr:: •_ ly " .. ;: ,x.89.111.Yi.MM.pMp1r&9wttt tt■ ::,,a' .:::'t ""°`' t.-:::::::3::5::::::::::::::: i:i::33333 931111::::::::::l:33313333::::.......:333:3: . —.......*4 ,p.:9.::tiSi:L::«s. .3911 3131113311:iSii3::i133313333l13::S::3iiLSSI�++ �, �' °:313!!!3 333: 11,13:3113133333333:11111111111213:: �^ ghr y, - "!331333311:113::1::3133131311333iii::i:hill!! 1.x—, . "' 'S3S333 31333:MU33ii33331395353333SS:111 MI91 ''— 33 S11SH1131 1333S11SMSSSii:3333135331S1SSSSSii3 S:333M3313311MUSi:9iiS3133933ISS:3iiSR3iSl 1118111212122331113ti 1:1115311311011:1tiiili:1131131=1121:111aSS:11131311/33SS5SSSS:SSS::SSS31S3 ,,M — �g.,,;,'; PHIMOMMENIEHMEMEMIIMMEHREMEHRE SS:SSSSSSS33Sl 333351 113115111111SS113331551536SEi1:tiitilyi�l{3+:E MEt11i MIIMiEiBE1EE1iE1t1 13:31 ii`13i: '':'f'r SSSS333333S3113S11SS3S3SSSSS3SS3SSS333SSSSSSSSSii:3flS311S33 133:SSnSSSSSi:135::335:33:S:::1::::iliiyyi�l�5 1 ':i' i11111iI111111Si11111E E1E1111111111111111il111131111 11iEE1E1 1111111iE11111111111111111 ; :::: ∎ 33SS1353351119:Siiiia::S:::513::5::535:::11:11:SSS5SS3:SS335SSS555.t5 SS:::::::::::11111::::: — 3:::C:9:::5:: :S••:•3SS3S:S:::: :::::t:•IStt:::tt::t... r--" ;:Sin;;;::: S:SSSSilS:=1:::: :::•13::SS1M:I + -; : I::ii:: :9;19•.3• ::•S:•••:i:: - :: :• : :ut: _ : :sue." . t2O12 M.'6 Figure 3. Proppant profile in the lower Nuiqsut Conclusion Kalubik-1 well log data were processed to derive rock mechanical properties and a stress profile for the fracture growth modeling in the Nuiqsut reservoir. Two fracture initiation points were examined: one in the upper and one in lower sections of the Nuiqsut formation. A schedule placing 200,000 lbs of 16/20 CarboLite was run at the "worst-case" for height growth of 80 bpm. The current limitation for the maximum rate is based on the available horsepower on location. In either initiation point the fracture height is contained to the Nuiqsut at the maximum specified rate of 80 bpm. The most likely avenue for height growth is downward to the Nechelik, and this is not predicted to occur under any planned treating conditions. All treatments conducted below the maximum specified rates, pressures, and proppant concentrations are considered a subset of the models presented here in the study. s r. o� u • rC e � CO N 3 r -w..-z o 1, C m X 0o D M. N p O 0 v Co r N ccoo N O_ N I O cn r . .l`7 rn r N Co Iv O Co cNo 0 Z w N N `i/ JCØiII V N /. I.Cl' ' % 701111Ijll o 01 YAP' NV G Z • co ra is ,o/rAjoi, , .N N v� ----- " ■1 Z er N N _+ r / t,� N CT A W N �j N o cr oo v rn o O — IV - 0 O �^ Z Imo i _ VJ C TT �� -a r - 1 O _ z z N m m °° m w C) o 7 K 13 xi U, co CTS N PIONEERCurrent Schematic -State Well Name: ODSN-15i NATURAL RESOURCES HORIZONTAL-Original Hole, 1/22/2013 10:45:54 AM Well Attributes Vertical schematic(actual) API/UW Field Name Well Status Total Depth(ftKB) 50-703-20618-00-00 _Oooguruk Unit DRILLED _ 17,383.0 Casing Strings 16"Welded Conductor,158.0ftKB Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ft.. Set Depth...Grade Top Thread WULen(I.. -B 16"Welded 16 14.670 47.7 158.0 158.0 H40 Welded 109.00 1 1-1 l---. I 1 Conductor U Casing Components Top(TVD) Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Corn 1-1 Conductor Shoe 47 7 47.7 16 14.670 11-3/4"Hyd 521 Surface,3,589.0ftKB Casing Demription OD(in) ID(in) Top(ftKB) Set Depth(ft.. Set Depth...Grade Top Thread Wt/Len(I.. 11-3/4"Hyd 521 11 3/4 10.772 39.4 3,589.0 2,982.3 L-80 HYD 521 60.00 Surface 27 Casing Components J Top(TVD) Item a Item Des Top(ftKB) (ftKB) OD(in) ID(in) Corn 2-1 Rathole 39.4 39.4 113/4 10.772 2-2 VG Casing Hanger 39.4 39.4 11 3/4 10.772 2-3I 2-3 11-3/4"Casing Pup 40.7 40.7 11 3/4 10.772 2-4 11 3/4"Casing jt 43.8 43.8 11 3/4 10 772 2-5 Tam Port Collar 528.2 527.4 11 3/4 10.772 • 14-21 2-6 X-O pin x pin 530.1 529.3 11 3/4 10.772 2-7 11 3/4"Casing jt 533.3 532.5 11 3/4 10.772 2-8 HES Float Collar 3,508.7 2,946.4 11 3/4 10.772 2-9 11 3/4"Casing jt 3,510.3 2,947.2 11 3/4 10.772 2-10 11 3/4"Surface Shoe 3,587 1 2,981.4 11 3/4 10.772 HES Float Shoe 9-5/8"40#Hyd 521 Drilling Liner#1,8,870.0ftKB Casing Dexription OD(In) ID(in) Top(ftKB) Set Depth(ft. Set Depth..Grade Top Thread Wt/Len(I .' 9-5/8"40#Hyd 521 9 5/8 8.835 3,376.9 8,870.0 5,301.3 L-80 HYD 521 40.00 Drilling Liner#1 Casing Components Top(TVD) Item* Item Des Top(ftKB) (ftKB) OD(in) ID(in) Corn i--�1 1 3-1 Tie Back Sleeve 3,376.9 2,880.7 10 1/4 9.687 3-2 WFT 9-5/8"x11-3/4""TSPR" 3.398.6 2,892.3 10.43 8.750 Liner Top Pkr 3-3 WFT 9-5/8"x11-3/4""PHS" 3,400.7 2,893.4 10 1/2 8.750 12-41 Hyd Liner Hgr 3-4 X-O 3.404.7 2,895.5 9 5/8 8.875 3-5 9 5/8"casing joint 3,406.2 2,896.3 9 5/8 8.835 2-5 3-6 WFT Ldg Collar 8,744.6 5,247.0 9 5/8 3-7 9 5/8"casing joint 8,745.5 5,247.4 9 5/8 8.835 3-8 Float collar 8,786.2 5,265.0 9 5/8 2-6 3-9 9 5/8"casing joint 8,788.1 5,265.8 9 5/8 8.835 3-10 9 5/8"Intermediate 1 Shoe 8,867.7 5.300.3 9 5/8 7"26#BTC-M Intermediate Csg,11,348.0ftKB Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ft.. Set Depth Grade Top Thread WULen(I 4-3 7"26#BTC-M 7 6.276 34.2 11,348.0 6,165.4 L-80 BTC-M 26.00 2-7 Intermediate Csg Casing Components Top(TVD) Item# Item Des Top(ftKB) (ftKB) OD(n) ID(in) Corn 4-1 Casing Joint 34.2 34.2 7 6.276 4-2 Casing Joint(cut down due 34.2 34.2 7 6.276 to emergancy slips) 4-3 Casing Joint 57.1 57.1 7 6.276 f" 4-4 Auto Fill Float Collar 11,264.8 6,139.0 7 6.276 i) 4-5 Casing Joint 11,265.8 6,139.3 7 6.276 4-6 7"Intermediate 2 Shoe 11,346.3 6,164.9 7 6.276 Auto fill Shoe HES 4 1/2"12.6#Hyd 521,17,140.0ftKB Casing Dewripton OD(in) ID(in) Top(ftKB) Set Depth(ft.. Set Depth...Grade Top Thread Wt/Len(I.. 4 1/2"12.6#Hyd 4 1/2 3.958 11,194.7 17,140.0 6,117.2 L-80 HYD 521 12.60 521 . Page 1/4 Report Printed: 1/22/2013 • PIONEERCurrent Schematic -State Well Name: ODSN-15i NATURAL RESOURCES HORIZONTAL-Original Hole,1/22/2013 10:45:58 AM Casing Components Vertical schematic(actual) Top tN°) Item# Itam Des Top(RKB) (RKB) OD(in) ID(in) Com o 5-1 Blank Liner 11,194.7 6,116.6 4 1/2 3.958 5-2 WFT Tie Back Sleeve 11 194 7 6.116.6 5 77 5.250 [2-71 5-3 WFT"NHT"Liner top Pkr 5" 11,210.1 6,121.5 5.96 4.375 x 7" 5-4 WFT"PHR"Hyd Hgr 5"x 7" 11,213.5 6.122.6 6.1 4.375 i 0 I 13-11 5-5 X-0 5"Vam top HT box x 11,218.8 6,124.3 4 1/2 3.958 4.5"Hyd 521 pin 5-6 4 1/2"Tubing 11,219.7 6.124.6 4 1/2 3.958 5-7 Pup Jt w/5 7/8"Spira Glider 11,375.8 6,174.1 4 1/2 3.958 13-21 5-8 WFT Zone Select SS w/6- 11,381.4 6,175.8 5.63 3 920 1 1/2"ports 5-9 4 1/2"Tubing 11,386.6 6,177.4 4 1/2 3.958 5-10 Pup Jt w/5 7/8"Spira Glider 11,464.6 6,197.8 4 1/2 3.958 13-31 5-11 WFT Zone Select SS w/2 11,470.2 6,199.1 5.63 3.920 _ -.197 jets 5-12 4 1/2"Tubing 11 475 4 6,200.2 4 1/2 3.958 5-13 Pup Jt w/5 7/8"Spira Glider 11,514.3 6,208.1 4 1/2 3.958 5-14 WFT 5 3/4 Genisis Oil base 11,519 9 6,209.2 5 3/4 3.958 Swell Pkr 5-15 Pup Jt wl 5 7/8"Spira Glider 11,537.3 6,212.2 4 112 3.958 5-16 4 1/2"Tubing 11,540.9 6,212.8 4 1/2 3.958 5-17 Pup Jt w/5 7/8"Spira Glider 11,736.0 6,231.6 4 1/2 3.958 5-18 WFT Zone Select SS w/6- 11,741.6 6,231 9 5.63 3.920 ' 2-8 1/2"ports 5-19 4 1/2"Tubing 11,746.8 6,232.2 4 1/2 3.958 5-20 Pup Jt w/5 7/8"Spira Glider 12,059.7 6,248.2 4 1/2 3.958 5-21 WET Zone Select SS w/2 12,065.3 6,248.1 5.63 3.920 -.197 jets - • 12-91 5-22 4 1/2"Tubing 12.070.5 6.248.1 4 1/2 3.958 5-23 Pup Jt w/5 7/8"Spira Glider 12,619.0 6,235.7 4 1/2 3.958 5-24 WFT Zone Select SS w/6- 12,624.6 6,235.5 5.63 3.920 1/2"ports 5-25 4 1/2"Tubing 12,629.8 6,235.3 4 1/2 3.958 5-26 Pup Jt w/5 7/8"Spira Glider 13,342.7 6,221.8 4 1/2 3 958 11-121 5-27 WFT 5 3/4 Genisis Oil base 13,348.3 6,221.4 5 3/4 3.958 Swell Pkr 5-28 Pup Jt w/5 7/8"Spira Glider 13,365.6 6.220 0 4 1/2 3.958 5-29 4 1/2"Tubing 13,369.3 6,219.7 4 1/2 3.958 5-30 Perfed Pup w/6-1/2"holes 13,922.0 6,189.3 4 1/2 3.958 5-31 4 1/2"Tubing 13,926.6 6,189.1 4 1/2 3.958 5-32 Perfed Pup w/6-1/2"holes 14.396.4 6.182.0 4 1/2 3.958 5-33 4 1/2"Tubing 14,401.1 6,182.1 4 1/2 3.958 5-34 Perfed Pup w/6-1/2"holes 14,790.3 6,183.6 4 1/2 3.958 5-35 41/2"Tubing 14,795.0 6,183.6 41/2 3.958 5-36 Pup Jt w/5 7/8"Spira Glider 15.386 4 6 202.8 4 1/2 3.958 • 12-101 5-37 WFT 5 3/4 Genisis Oil base 15,392.0 6,203.0 5 3/4 3.958 Swell Pkr 4-3 5-38 Pup Jt w/5 7/8"Spira Glider 15,409.4 6,203.5 4 1/2 3.958 33-5 5-39 4 1/2"Tubing 15,413.0 6,203.7 4 1/2 3.958 Page 2/4 Report Printed: 1/22/2013 PIONEERCurrent Schematic -State Well Name: ODSN-15i NATURAL RESOURCES HORIZONTAL-Original Hole,1/22/2013 10:46:03 AM Casing Components Vertical schematic(actual) Top(TVD) I 11 ) Item# Item Des Top(rtKB) (ttKB) OD(in) ID(in) Corn '1 3-5 5-40 Pup Jt w/5 7/8"Spira Glider 16,041.1 6,203.2 4 1/2 3.958 1i i , , / 33--67 5-41 WFT 5 3/4 Genisis Oil base 16.046 7 6,202.7 5 3/4 3.958 Swell Pkr 3 g 5-42 Pup Jt w/5 7/8"Spira Glider 16,064.0 6,201.1 4 1/2 3.958 3-9 3-10 5-43 4 1/2"Tubing 16,067.7 6,200.8 4 1/2 3.958 5-44 Perfed Pup w/6-1/2"holes 16,891.3 6,136.6 4 1/2 3.958 1-16 T `C 5-45 4 1/2"Tubing 16,895 9 6.136.3 4 1/2 3.958 l5-46 Xover 4-1/2"BTC x Hyril 17,137.1 6,117.4 4 1/2 3.958 521 5-47 4 1/2"Production Liner Shoe 17,138.7 6,117.3 4 1/2 3.958 Float Shoe Plugged 11-201 . Tubing Strings Tubing Description String M. ID(in) Top(ftKB) Set Depth It Set Dept...Wt(lb/ft) Grade Top Thread Tubing 3 1/2 2.992 34.2 11,207.2 6,120.5 9.30 L-80 TC II Tubing Components ® Top(TVD) Item# Item Des Top(ftKB) ((KB) OD(in) ID(in) Corn 1-1 Vetco Gray 3-1/2"Tbg 34.2 34.2 10 2.992 Hanger w.Acme B x TC-II 13/16 Pin [f1 . t 1-2 3 1/2"Tubing Pup Joint Pin 35.7 35.7 3 1/2 2.992 l x Pin 1-3 3 1/2"Tubing 40.0 40 0 3 1/2 2.992 ® 1-4 3 1/2"Tubing Pup Joint 72.4 72.4 3 1/2 2.992 86.5 3 1/2 2.992 1-5 3 1/2"Tubing 86.5 1-6 3 1/2"Tubing Pup Joint 1,985.6 1,862.5 3 1/2 2.992 1-7 3 1/2"Crossover TC-II Box x 1,991.3 1,867.1 3 1/2 2.992 1-36 CS Hydril Pin 1-8 HES Wellstar TRSSSV w/ 1,995.1 1,870.2 5.2 2.813 2.813 X Profile TC-II BxP 1-9 3 1/2"Tubing Pup Joint 2,001.9 1,875.7 3 1/2 2.992 15-2I 1-10 3 1/2"Tubing 2,005.5 1,878.6 3 1/2 2.992 1-39 1-11 3 1/2"Tubing Pup Joint 3,549.7 2,964.8 3 1/2 2.992 5-3 1-12 Vanoil 3-1/2"x 1-1/2"GLM 3,555.5 2,967.4 5.45 2.992 5 4 TC-II BxP 1-13 3 1/2"Tubing Pup Joint 3,564 4 2,971.4 3 1/2 2.992 1-14 31/2"Tubing 3,570.2 2,973.9 31/2 2.992 14-41 1-15 3 1/2"Tubing Pup Joint 9,193.6 5,434.4 3 1/2 2.992 I4-51 1-16 Vanoil 3-1/2"x 1-1/2"GLM 9,199.4 5,436.8 545 2.992 4-6 TC-II BxP 1-17 3 1/2"Tubing Pup Joint 9,208.3 5,440.4 3 1/2 2.992 1-18 3 1/2"Tubing 9,214.1 5,442.8 3 1/2 2.992 C 5-8 1-19 3 1/2"Tubing Pup Joint 9,278.8 5,469.3 3 1/2 2.992 1-20 HES Roc Gauge&Carrier TC 9,284.5 5,471.7 5 2.992 -II BxP I-Wire to Surface ' ` ® 1-21 3 1/2"Tubing Pup Joint 9,289.3 5,473.6 3 1/2 2.992 1-22 3 1/2"Tubing 9,295.1 5,476.0 3 1/2 2.992 1-23 3 1/2"Tubing Pup Joint 9,327.3 5,489.3 3 1/2 2.992 ! E 15-141 1-24 3 1/2"HES 2.813 X Nipple 9,333.0 5,491.6 3.95 2.813 1-25 3 1/2"Tubing Pup Joint 9,334.3 5,492.2 3 1/2 2.992 1-26 3 1/2"Tubing 9,338.1 5,493.7 3 1/2 2.992 1-27 3 1/2"Tubing Pup Joint 9,401.9 5,520.0 3 1/2 2.992 i ` 5-18 1-28 Crossover 4-1/2"New Vam 9,411 7 5,524.1 3 1/2 2.992 Box X 3-1/2"TC-II Pin 1-29 WFT 7"UltraPak TH Hyd 9,412.7 5,524 5 5.896 3.910 C ® Perm Pkr 4-1/2"NewVam PxP 1-30 Crossover 3-1/2"TC-II Box 9,417.2 5,526.3 3 1/2 2.992 { MI X 4-1/2"New Vam Pin Page 3/4 Report Printed: 1/22/2013 R Current Schematic -State Well Name: ODSN-15i P I O N E E NATURAL RESOURCES HORIZONTAL-Original Hole,1/22/2013 10:46:11 AM Tubing Components Vertical schematic(actual) I Top(TVD)Item# Item Des Top(RKe) (ttKe) OD(in) ID(in) Corn 1-31 3 1/2"Tubing Pup Joint 9,417.9 5,526.6 3 1/2 2.992 1-32 3 1/2 HES 2.813 X Nipple 9,433.4 5,533.0 3.95 2.813 1-33 3 1/2"Tubing Pup Joint 9,434.6 5,533.5 3 1/2 2.992 1-34 31/2"Tubing 9,438.4 5,535.0 31/2 2.992 1-35 3 1/2"Tubing Pup Joint 9,501.0 5,560.6 3 1/2 2.992 15-271 1-36 3 1/2" HES 2.813 XN Nipple 9,506.8 5,562.9 3.98 2.750 m , wl 2.750 NoGo 1-37 3 1/2"Tubing Pup Joint 9,508.2 5,563.5 3 1/2 2.992 1-38 31/2"Tubing 9,512.0 5,565.0 31/2 2.992 1-39 3.5"TC-II Tubing Tail 11,205.9 6,120.1 3.9 2.992 HES 3-1/2"WLEG 5-30 1CdJ 0i Eta 0101 1!101 5-34 1101 ® t 5-37 H e o s 15-411 ICA U i } 15-471 Page 4/4 Report Printed: 1/22/2013 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO Jim Regg I DATE:Monday,September 19,2011 P.I.Supervisor l� ( C1I uO(s( SUBJECT:Mechanical Integrity Tests PIONEER NATURAL RESOURCES ALASK ODSN-15 FROM: Chuck Scheve OOOGURUK NUQ ODSN-15 Petroleum Inspector Src: Inspector Reviewed By: P.I.Suprv'6(2--- NON-CONFIDENTIAL Comm Well Name: OOOGURUK NUQ ODSN-15 API Well Number: 50-703-20618-00-00 Inspector Name: Chuck Scheve Insp Num: mitCS110816064849 Permit Number: 210-032-0 Inspection Date: 8/15/2011 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well ODSN-I5 Type Inj. W TVD 5525 IA 270 2100 • 2055 2043 P.T.D 2100320 TypeTest SPT Test psi 1500 -I OA 690 755 755 752 Interval INITAL P/F P ' Tubing 2650 2650 2650 2650 -- Notes: Well converted from producer to injector. Monday,September 19,2011 Page 1 of 1 .ti Brooks, Phoebe L (DOA) Fro t* 2.100320 From: Williams, Theresa [Theresa.Williams @pxd.com] Sent: Monday, September 19, 2011 11:11 AM To: Brooks, Phoebe L (DOA) Subject: RE: ODSN-15 MIT IA PTD 2100320 Attachments: MIT ODSN-15 08-15-11.xIs; Current Schematic-State Revised 13Sept2011.pdf Categories: Operator follow up Phoebe, Attached is the revised form and the schematic. Checking with our Wellview guys, the original depth was fat-fingered. All depths on the schematic are TVD-RKB, so I subtracted 56'to put at TVDSS. Theresa Williams-Staff Ops Engr 0: (907)343-2104 C: (907)382-3596 From: Brooks, Phoebe L (DOA) [mailto:phoebe.brooks @alaska.gov] Sent: Friday, September 16, 2011 10:43 AM To: Williams, Theresa Subject: RE: ODSN-15 MIT IA PTD 2100320 ,. Theresa, Were you able to track down the Packer TVD info we talked about (well schematic has 6110' but, the front page of the 404 has 6121')? Based on the MD provided of 11210',we calculated the Packer TVD at 6121'. Thanks for your help, Phoebe Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 From: Williams, Theresa [mailto:Theresa.Williams @ pxd.com] Sent: Tuesday, August 23, 2011 5:02 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA); Brooks, Phoebe L (DOA); DOA AOGCC Prudhoe Bay Cc: OoogurukProdSuper; Belanger, Ward; Hart, David; Williams,Theresa Subject: ODSN-15 MIT IA PTD 2100320 Attached are post-injection start up MIT results for ODSN-15. Theresa Williams-Staff Ops Engr Pioneer Natural Resources 0:(907)343-2104 C:(907)382-3596 Theresa.Williams@oxcl.com 1 PIONEERCurrent Schematic - State Well Name: ODSN-15i NATURAL RFSOURG.FS HORIZONTAL-Original Hole,9/13/2011 4:19:42 PM Well Attributes Vertical schematic(actual) API/UWI Field Name Well Status Total Depth(ftKB) 50-703-20618-00-00 Oooguruk Unit DRILLED 17,383.0 11-2- • 4.1 Casing Strings }I i 16"Welded Conductor,158.0ftKB Description OD(in) ID(in) Top(ftKB) Set Depth(ft. Set Dept... Grade Top Connection Wt/Len(Ib/ft) 16"Welded 16 14.670 47.7 158.0 158.0 H40 Welded 109.00 Conductor J 1-1 Casing Components Top(TVD) Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Com 1-1 Conductor Shoe 47.7 47.7 16 14.670 11-3/4"Hyd 521 Surface,3,589.0ftKB 11-91 a Description OD(in) ID(in) Top(ftKB) Set Depth(ft... Set Dept... Grade Top Connection Wt/Len(lb/ft) IL, /3_4 11-3/4"Hyd 11 3/4 10.772 39.4 3,589.0 2,982.3 L-80 HYD 521 60.00 3-5 521 Surface 3-6 Casing Components Top(TVD) Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Com 2-11 11 3/4"Surface Shoe 3,587.1 2,981.4. 11 3/4 10.772'HES Float Shoe 1-13 9-5/8"40#Hyd 521 Drilling Liner#1,8,870.0ftKB Description OD(in) ID(in) Top(ftKB) Set Depth(ft... Set Dept... Grade Top Connection Wt/Len(lb/ft) 12-11 I 9-5/8"40#Hyd 9 5/8 8.835 3,376.9 8,870.0 5,301.3 L-80 HYD 521 40.00 521 Dolling I Liner#1 i Casing Components ' 1 13-131 Top(TVD) t Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Com 11-171 3-4 Tie Back Sleeve 3,376.9 2,880.7 10 1/4 9.687 3-5 WFT 9-5/8"x11-3/4" 3,398.6 2,892.3 10.43 8.750 11-211 - "TSPR"Liner Top Pkr Ili 3-6 WFT 9-5/8"x11-3/4""PHS" 3,400.7 2,893.4 10 1/2 8.750 Hyd Liner Hgr 11-251 3-13 9 5/8"Intermediate 1 Shoe 8,867.7 5,300.3 9 5/8 7"26#BTC-M Intermediate Csg,11,348.OftKB 11-301 Description OD(in) ID(in) Top(ftKB) Set Depth(ft... Set Dept... Grade Top Connection Wt/Len(lb/ft) 7"26#BTC-M 7 6.276 34.2 11,348.0 6,168.3 L-80 BTC-M 26.00 i® a Intermediate Csg Ij Casing Components 1-37 Top(TVD) II: Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Com 5-2 4-8 7"Intermediate 2 Shoe 11,346.3 6,167.7 7 6.276 Auto fill Shoe HES inS 1-40 i.+> 5-3 4 1/2"12.6#Hyd 521,17,140.0ftKB 5-4 Description OD(in) ID(in) Top(ftKB) Set Depth(ft.. Set Dept... Grade Top Connection Wt/Len(lb/ft) 4 1/2"12.6# 4 1/2 3.958 11,194.7 17,140.0 6,117.6 L-80 HYD 521 12.60 Hyd 521 14-81 Casing Components Top(TVD) Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Com [ Ii 15-81 5-2 WFT Tie Back Sleeve 11,194.7 6,118.9 5.77 5.250 [ • 15-111 5-3 WFT"NHT"Liner top Pkr 5" 11,210.1 6,123.8 5.96 4.375 x 7" ■ a 15-141 5-4 WET"PHR"Hyd Hgr 5"x 7" 11,213.5 6,125.0 6.1 4.375 f 5-18 5-8 WFT Zone Select SS w/6- 11,381.4 6,178.7 5.63 3.920 1/2"ports I t ® 5-11 WFT Zone Select SS w/2 11,470.2 6,201.9 5.63 3.920 -.197 jets I t 5-24 5-14 WFT 5 3/4 Genisis Oil base 11,519.9 6,212.0 5 3/4 3.958 ▪ • 15-271 Swell Pkr 5-18 WFT Zone Select SS w/6- 11,741.6 6,234.7 5.63 3.920 M:' 5-30 1/2"ports BIM E 5-34 • I• 15-371 • it 15-411 . . MD I } -15-471 Page 1/2 Report Printed: 9/13/2011 * PIONEER Current Schematic - State Well Name: ODSN-15i NATUBAI_RFSOURCLFS HORIZONTAL-Original Hole,9/13/2011 4:19:45 PM Casing Components Vertical schematic(actual) Top(ND) Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Corn 11-21- Ars.,:r 5-21 WFT Zone Select SS w/2 12,065.3 6,251.0 5.63 3.920 -.197 jets ti .{ 5-24 WFT Zone Select SS w/6- 12,624.6 6,238.4 5.63 3.920 1/2"ports 5-27 WFT 5 3/4 Genisis Oil base 13,348.3 6,224.1 5 3/4 3.958 1—LI-11 Swell Pkr 5-30 Perfed Pup w/6-1/2"holes 13,922.0 6,192.0 4 1/2 3.958 5-32 Perfed Pupw/6-1/2"holes 14,396.4 6,184.7 4 1/2 3.958 1-9 EC 5-34 Perfed Pupw/6-1/2"holes 14,790.3 6,186.2 4 1/2 3.958 3-6 5-37 WFT 5 3/4 Genisis Oil base 15,392.0 6,205.6 5 3/4 3.958 Swell Pkr 5-41 WFT 5 3/4 Genisis Oil base 16,046.7 6,203.1 5 3/4 3.958 Swell Pkr 1-13 5-44 Perfed Pup w/6-1/2"holes 16,891.3 6,137.0 4 1/2 3.958 12-11 5-47 4 1/2"Production Liner 17,138.7 6,117.7 4 1/2 3.958 Float Shoe Plugged j Shoe lY Tubing Strings ,, [ 13-131 Tubing Description Strang M... ID(In) Top(f1KB) Set Depth(f...Set Dept...Wt(Ib/ft) Grade Top Thread Tubing 3 1/2 2.992 34.2 11,207.2 6,122.9 9.30 L-80 TC II 1-17 ! Tubing Components II■ I Top(TVD) 11 21 I . Item#. Item Des Top(ftKB) (ftKB) OD(In) ID(in) Corn 1-2 Vetco Gray 3-1/2"Tbg 34.2 34.2 10 2.992 Hanger w.Acme B x TC-II 13/16 11-25 Pin I 1-9 HES Wellstar TRSSSV w/ 1,995.1 1,870.2 5.2 2.813 2.813 X Profile TC-II BxP 11-301 1 s 1-13 Vanoil 3-1/2"x 1-1/2"GLM 3,555.5 2,967.4 5.45 2.992 a TC-II BxP 1-33 1-. 1-17 Vanoil 3-1/2"x 1-1/2"GLM 9,199.4 5,437.5 5.45 2.992 TC-I1 BxP 11-37 1-21 HES Roc Gauge&Carrier 9,284.5 5,472.3 5 2.992 EIS TC-11 BxP I-Wire to Surface 1-40 I 5_3 1-25 3 1/2"HES 2.813 X Nipple 9,333.0 5,492.3 3.95 2.813 5-4 1-30 WFT 7"UltraPak TH Hyd 9,412.7 5,525.2 5.896 3.910 I I Perm Pkr 4-1/2"NewVam PxP 14-8I 1-33 3 1/2"HES 2.813 X Nipple 9,433.4 5,533.7 3.95 2.813 1 5-8 1-37 3 1/2" HES 2.813 XN 9,506.8 5,563.7 3.98 2.750 Nipple w/2.750 NoGo I ® 1-40 3.5"TC-II Tubing Tail 11,205.9 6,122.5 3.9 2.992 HES 3-1/2"WLEG 0 • 15-141 1 } 15-181 -Y 15-211 } 15-241 s . 15-271 PHi: 5-30 In is 5-34 �0 15-371 1 ! 15-411 11E.,: 5-44 1 } -15-471 Page 2/2 Report Printed: 9/13/2011 STATE OF ALASKA ALASKA AND GAS CONSERVATION COMMISSI( REPOR1 OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Repair Well❑ Plug Perforations ❑ Stimulate ❑ Other El Convert to Injector Performed: Alter Casing ❑ Pull Tubing Perforate New Pool ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdowns Perforate ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Pioneer Natural Resources Alaska Inc Development El Exploratory❑ 210-032 3.Address: 700 G Street,Suite 600 Stratigraphic Service ❑ 6.API Number: Anchorage,AK 99501 50-703-20618-00-00 7.Property Designation(Lease Number):, 8.Well Name and Number: ADL 355036/ADL 355037 ODSN-15i 9.Field/Pool(s): • Oooguruk-Nuiqsut Oil Pool 10.Present Well Condition Summary: Total Depth measured' 17,383 feet Plugs measured N/A feet true vertical 6096 feet Junk measured feet Effective Depth measured 17,139 feet Packer measured See Below feet true vertical 6117 feet true vertical feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 158' 158' N/A N/A Surface 3550' 11-3/4" 3589' 2982' 5830 psi 3180 psi Intermediate 5493' 9-5/8" 3377'-8870' 2880'-5301' 5750 psi 3090 psi Production 11,314' 7' 11,348' 6165' 7240 psi 5410 psi Liner 5945' 4-1/2" 11,195'- 17,140' 6117'-6117' N/A N/A Perforation depth Measured depth See Attachment,pg 2 feet True Vertical depth See Attachmen,pg 2 feet Tubing(size,grade,measured and true vertical depth) 3-1/2",9.3# L-80,TCII 11,207'MD 6121'TVD 7"Hyd Perm Pkr @ Liner Top Pkr @ Packers and SSSV(type,measured and true vertical depth) ScSSSV @ 1995' 9413'MD/5525' 11,210'MD/6121' MD/1870'ND TVD TVD 11.Stimulation or cement squeeze summary: a?j CEP d' Intervals treated(measured): �A AUG 2 5 2011 Treatment descriptions including volumes used and final pressure: Mesh ON&Gag Cog. Commission 12. Representative Daily Average Production or Injectig ar& Oil-Bbl Gas-Mcf Water-Bbl Casing Pressur Tubing Pressure Prior to well operation: 312 162 0 775 799 Subsequent to operation:_ 0 0 6287 572 2656 13.Attachments: 14.Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development❑ Service 0 Stratigraphic ❑ Daily Report of Well Operations X 15.Well Status after work: Oil ❑ Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG 1151 GINJ ❑ SUSP❑ 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: 310-430 Contact Tim Crumrine,343-2184 Prepared By:Kathy Campoamor,343-2183 Printed Name Tim Crum" Title Completions Engineer Signature— '� �;� _ Phone 343-2184 Date 8/24/2011 RBDMS AUG 2 5 '2011 is/.'/N.t:orm 10 404 Revised 10/2010 iv/ Submit Original Only Pioneer Natural Rest‘rces Alaska Inc. ODSN-15i Page 2 Form 10-404, Report of Sundry Well Operations Present Well Condition Summary, Box 10 Perforation Depth Attachment 10. Perforation Depth 4-W, 12.6#, L-80 Hyd 521 Uncemented Liner Sliding Sleeves w/ 6ea. '/2" Ports— open @ depths listed: MD TVD 11,381' — 11,387' 6176' — 6177' 11,742' — 11,747' 6232' — 6232' 12,625' — 12,630' 6235' — 6235' Sliding Sleeves w/ 2 - .20 Jets — closed @ depths listed: MD TVD 11,470' — 11,475' 6199' — 6200' 12,065' — 12,070' 6248' — 6248' Perfed Pups w/ 6-1/2" Holes @ depths listed: MD TVD 13,922' — 13,927' 6189' — 6189' 14,396' — 14,401' 6182' — 6182' 14,790' — 14,795' 6184' — 6184' 16,891' — 16,896' 6137' — 6136' PI O N E E R Operations Summary Report - State Well Name: ODSN-15i NATURAL RESOURCES Well Name: Contractor: Rig Number: Job Category: Start Date: End Date: Start Depth Foot/Meters Dens Last Start Date End Date (RKB) (ft) Mud(lb/gal) Summary 7/23/2011 7/24/2011 17,383.0 MI&RU slickline unit,PT lubricator with gas.RIH with 3.5 GS and XN catcher sub,Jar down for 40 minutes.POOH w/catcher sub.Re-pin GS w/half 1/8"brass set catcher sub in XN nipple at 9,506'RKB MD,POOH.RIH w/3.5"OM-1 &1-5/8"JDS to station @ 9,199'RKB,set down Jar- up,POOH with OV.POOH,line-up P6 to circulate 250 bbls diesel down back side taking returns up tubing to production line 7/24/2011 7/25/2011 17,383.0 Finish circulating well. RIH 1,12"DMY to station 2,unable to set.POOH,lower arm of KOT sheared.Re-pin and RIH with same,Locate and set down In station#2 at 9,176'SLM,see 1' travel.Draw down IA initial t/IA 250/278 psi.Shear off-No increase IAP. Perform MITA to 2500 psi.Loose 63 psi,1st 15 min,28 psi 2nd 15 min,MITA"Pass".RIH with 3-1/2"GR Latch catcher at 9,477'SLM, POOH no catcher sub.RIH with same.Latch up POOH.RD and move to ODSN-23i. 7/25/2011 7/26/2011 17,383.0 RIH w/3/5"OM-1,RK-1, 1.5"dummy valve to 9,176 WLMD.Unable to sit down.POOH.Lower arm sheared.Re-pin and rerun.Locate and set dummy valve.MIT IA to 2500 psi.Lose a total of 91 psi in 30 minutes.Pass.RIy with 3.5"GS and latch catcher at 9,477 WLMD.POOH.Function test SSSV.Good test.RD. ✓ Page 1/1 Report Printed: 8/24/2011 PI 0 N E E R Current Schematic - State Well Name: ODSN-15i NATURAL RESOURCES HORIZONTAL-Original Hole, 8/24/2011 2:39:02 PM Well Attributes Vertical schematic(actual) API/UWI Field Name Well Status Total Depth(ftKB) 50-703-20618-00-00 Oooguruk Unit DRILLED 17,383.0 11-21- • ski- Casing Strings 16"Welded Conductor,158.0ftKB Description OD(in) ID(in) Top(ftKB) Set Depth(ft... Set Dept... Grade Top Connection Wt/Len(lb/ft) 16"Welded 16 14.670 47.7 158.0 158.0 H40 Welded 109.00 Conductor 1-1 Casing Components Top(TVD) Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Com 1-1 Conductor Shoe 47.7 47.7 16 14.670 11-3/4"Hyd 521 Surface,3,589.0ftKB 11-91 6 r Description OD(in) ID(in) Top(ftKB) Set Depth(ft_. Set Dept... Grade Top Connection Wt/Len(lb/ft) I /3-45 11-3/4"Hyd 11 3/4 10.772 39.4 3,589.0 2,982.3 L-80 HYD 521 60.00 _ 33- 521 Surface 3-6 Casing Components Top(TVD) Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Corn 2-11 11 3/4"Surface Shoe 3,587.1 2,981.4 11 3/4 10.772 HES Float Shoe 11-13 ,• 9-5/8"40#Hyd 521 Drilling Liner#1,8,870.0ftKB Description OD(in) ID(in) Top(ftKB) Set Depth(ft_. Set Dept... Grade Top Connection Wt/Len(lb/ft) 2-111 9-5/8"40#Hyd 9 5/8 8.835 3,376.9 8,870.0 5,287.8 L-80 HYD 521 40.00 521 Drilling Liner#1 I Casing Components . ® Top(TVD) Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Corn 11-17 t 3-4 Tie Back Sleeve 3,376.9' 2,880.7 10 1/4 9.687 3-5 WFT 9-5/8"x11-3/4" 3,398.6 2,892.3 10.43 8.750 11-211 "TSPR"Liner Top Pkr I3-6 WFT 9-5/8"x11-3/4""PHS" 3,400.7 2,893.4 10 1/2 8.750 _ Hyd Liner Hgr 11-251 3-13 9 5/8"Intermediate 1 Shoe 8,867.7 5,286.8 9 5/8 7"26#BTC-M Intermediate Csg,11,348.0ftKB 11-301 _ Description OD(in) ID(in) Top(ftKB) Set Depth(ft.. Set Dept... Grade Top Connection Wt/Len(lb/ft) 7"26#BTC-M 7 6.276 34.2 11,348.0 6,154.8 L-80 BTC-M 26.00 1-33 _ Intermediate Csg Casing Components I1-37 Top(TVD) Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Corn I5-21 4-8 7"Intermediate 2 Shoe 11,346.3 6,154.2 7 6.276 Auto fill Shoe HES 1-40 15 3 4 1/2"12.6#Hyd 521,17,140.0ftKB 5-4 Description OD(in) ID(in) Top(ftKB) Set Depth(ft_ Set Dept... Grade •Top Connection Wt/Len(lb/ft) 4 1/2" 12.6# 4 1/2 3.958 11,194.7 17,140.0 6,104.1 L-80 HYD 521 12.60 Hyd 521 t IT T Casing Components Top(TVD) Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Corn 5-8 5-2 WFT Tie Back Sleeve 11,194.7 6,105.4 5.77 5.250 t t ® 5-3 WFT"NHT"Liner top Pkr 5" 11,210.1 6,110.3 5.96 4.375 x 7" a • 15-141 5-4 WET"PHR"Hyd Hgr 5"x 7" 11,213.5 6,111.5 6.1 4.375 t> t 5-18 5-8 WFT Zone Select SS w/6- 11,381.4 6,165.2 5.63 3.920 •t 1/2"ports ® 5-11 WFT Zone Select SS w/2 11,470.2 6,188.4 5.63 3.920 -.197 jets t 5-24 5-14 WFT 5 3/4 Genisis Oil base 11,519.9 6,198.5 5 3/4 3.958 • • 15-271 Swell Pkr 5-18 WFT Zone Select SS w/6- 11,741.6 6,221.2 5.63 3.920 ill 5-30 1/2"ports a ESE 5 34 • • 15-371 a a 15-411 . 5-44 5-47 Page 1/2 Report Printed: 8/24/2011 PI O N E E R Current Schematic - State Well Name: ODSN-15i NATURAL RESOURCES HORIZONTAL-Original Hole,8/24/2011 2:39:13 PM Casing Components Vertical schematic actual Top(TVD) Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Com 1-2 „?% 5-21 WFT Zone Select SS w/2 12,065.3 6,237.5 5.63 3.920 to I -.197 jets `� ti 5-24 WFT Zone Select SS w/6- 12,624.6 6,224.8 5.63 3.920 1/2"ports j I 5-27 WFT 5 3/4 Genisis Oil base 13,348.3 6,210.6 5 3/4 3.958 LSwell Pkr 5-30 Perfed Pup w/6-1/2"holes 13,922.0 6,178.5 4 1/2 3.958 5-32 Perfed Pup w/6-1/2"holes 14,396.4 6,171.2 4 1/2 3.958 I1-91 h r_ 3-4 5-34 Perfed Pup w/6-1/2"holes 14,790.3 6,172.7 4 1/2 3.958 11-13 I 3-6 5-37 WFT 5 3/4 Genisis Oil base 15,392.0 6,192.1 5 3/4 3.958 Swell Pkr 5-41 WFT 5 3/4 Genisis Oil base 16,046.7 6,189.6 5 3/4 3.958 Swell Pkr i 5-44 Perfed Pup w/6-1/2"holes 16,891.3 6,123.5 4 1/2 3.958 12-111 5-47 4 1/2"Production Liner 17,138.7 6,104.2 4 1/2 3.958 Float Shoe Plugged Shoe I ® Tubing Strings - Tubing Description String M._ ID(in) Top(ftKB) Set Depth If Set Dept_. Wt(Ib/ft) Grade Top Thread Tubing 31/2 2.992 34.2 11,207.2 6,109.4 9.30 L-80 TC II 1-171 Tubing Components Top(TVD) 1-21 JJJ Item# Item Des Top(ftKB) (ftKB) OD(in) ID(in) Corn I 1-2 Vetco Gray 3-1/2"Tbg 34.2 34.2 10 2.992 Hanger w.Acme B x TC-I I 13/16 11-25 7. Pin 1-9 HES Wellstar TRSSSV w/ 1,995.1 1,870.2 5.2 2.813 I 2.813 X Profile TC-II BxP 11-301 I L 1-13 Vanoil 3-1/2"x 1-1/2"GLM 3,555.5 2,967.4 5.45 2.992 S TC-II BxP 11-33 1-17 Vanoil 3-1/2"x 1-1/2"GLM 9,199.4 5,423.9 5.45 2.992 TC-ll BxP 11-37 1-21 HES Roc Gau 9 e&Carrier 9,284.5 5,458.8 5 2.992 TC-II BxP I-Wire to Surface 1-40 5-2 - ,55-33 1-25 3 1/2"HES 2.813 X Nipple 9,333.0 5,478.8 3.95 2.813 5-4 1-30 WFT 7"UltraPak TH Hyd 9,412.7 5,511.7 5.896 3.910 Perm Pkr 4-1/2"NewVam PxP t 14-81 1-33 3 1/2"HES 2.813 X Nipple 9,433.4 5,520.2 3.95 2.813 5-8 1-37 3 1/2" HES 2.813 XN 9,506.8 5,550.1 3.98 2.750 Nipple w/2.750 NoGo it ® 1-40 3.5"TC-II Tubing Tail 11,205.9 6,109.0 3.9 2.992 HES 3-1/2"WLEG tf • 15-141 5-18 crt Mil tit 5-24 i tt 15-271 Al 5-30 a EM 5-34 4 ti 15-371 3 • I5-41] i .. 5-44 5-47 Page 2/2 Report Printed: 8/24/2011 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.reaolalalaska.aov; doa.aoacc.orudhoe.bavCalalaska.gov: phoebe.brooks(S alaska.aov: tom.maunder@alaska.gov OPERATOR: Pioneer Natural Resources FIELD I UNIT/PAD: Oooguruk DATE: 08/15/11 OPERATOR REP: Christopher AOGCC REP: Scheve Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well ODSN-15 Type Inj. W TVD 6,110' Tubing 2,650 2,650 2,650 2,656 Interval i P.T.D. 2100320 Type test P Test psi 1527.5 Casing 270 2,100 2,055 2,043 P/F P Notes: OA 690 755 755 752 Well Type Inj. TVD Tubing Interval P.T.D._ _Type test Test psi Casing P/F_ Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. _ Type test_ Test psi Casing P/F Notes: OA Well Type Inj. ND Tubing Interval P.T.D. Type test _ Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test _ Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL.Codes D=Drilling Waste M=Annulus Monitoring I=Initial Test G=Gas P=Standard Pressure Test 4=Four Year Cycle I=Industrial Wastewater R=Internal Radioactive Tracer Survey V=Required by Variance N=Not Injecting A=Temperature Anomaly Survey T=Test during Workover W=Water D=Differential Temperature Test 0=Other(describe in notes) Form 10-426(Revised 06/2010) MIT ODSN-15 08-15-11.xIs MID m/� t$ ƒ 2 ,; ) §( ` § § \} 7 / j k k §§ § : §( { { kf \ 7-12 0 0 f 00 . . . . II i 111 §; © )$ ° 0 $ O d§ / - ,, � § F \• 2 ) a ■ 0 _ / O 2 —I . . > / » � B -0 73 BBB § ■■ 1 \ ;g -® £ ) ! | _.\ E ° . m\ E 6 ko . §$ . \ r—— ■ ® 1 , etu AlAsil,\KA SEAN PARNELL,GOVERNOR ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMMISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 Tim Crumrine Completions Engineer Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, AK 99501 Re: Oooguruk Field, Nuiqsut Oil Pool, ODSN-15i Sundry Number: 311-061 Dear Mr. Crumrine: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 4141° Daniel T. Seamount, Jr. Chair DATED this day of March, 2011. Encl. ,5 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrill❑ Perforate New Pool❑ Repair Well❑ Change Approved Program ❑ Suspend❑ Plug Perforations❑ Perforate❑ Pull Tubing❑ Time Extension ❑ Operations Shutdown❑ Re-enter Susp.Well❑ Stimulate El' Alter Casing❑ Other: ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Pioneer Natural Resourcs Alaska, Inc. Development p , Exploratory ❑ 210-032 ' 3.Address: 700 G Street, Suite 600 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99501 50-703-20618-00-00 . 7.If perforating,closest approach in pool(s)opened by this operation to nearest 8.Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No 0 'ODSN-15u 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 355036'/ADL 355037• Oooguruk-Nuiqsut Oil Pool , 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 17,383' - 6096' , 17,139' 6117' N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 158' 158' N/A N/A Surface 3550' 11-3/4" 3589' 2982' 5830 psi 3180 psi Intermediate 5439' 9-5/8" 3377'-8870' 2880'-5301' 5750 psi 3090 psi Production 11,314' 7" 11,348' 6165' 7240 psi 5410 psi Liner 5945' 4-1/2" 11,195'-17,140' 6117'-6117' N/A N/A Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attachment, pg.2 See Attachment, pg.2 3-1/2",9.3# L-80,TCII 11,207' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): SSSV;7"Hyd Perm Packer; Liner Top Packer 1995'MD/1870'ND;9413'MD/5525'ND; 11,210'MD/6121'ND 12.Attachments: Description Summary of Proposal El 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development ❑ Service eg 14.Estimated Date for 15.Well Status after proposed work: Operations: 3/9/2011 Commencing Oil g O p ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG IS • Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Tim Crumrine, 343-2184 Printed Name Tim Crumrine, 343-2184 Title Completions Engineer Signatu Phone Date Prepared By:Kathy Campoamor,343-2183 J 3/1/2011 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: )( (i n Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ RECEIVED' Other: {•+ V i� tl MAR 0 2 2011 Alaska 00&Gas um&commission Subsequent Form Required: / d' ! O I filittlierage APPROVED BY Approved by: A / COMMISSIONER THE COMMISSION Date: ..3/ /J Form 10-403 Revised 1/2010 + 11AR, 0( -q U K I GI N J{ 3 3 Submit in Du licat (/ Pioneer Natural Resources Alaska Inc. ODSN-15i Page 2 Form 10-403, Application For Sundry Approvals Present Well Condition Summary, Box #11 Perforation Depth Attachment 24. Open to production or injection 4-1/2", 12.6#, L-80 Hyd 521 Uncemented Liner Sliding Sleeves w/ 6ea. 1" Ports— open @ depths listed: MD TVD 11,381' — 11,387' 6176' — 6177' 11,742' — 11,747' 6232' — 6232' 12,625' — 12,630' 6235' — 6235' Sliding Sleeves w/ 2 - .20 Jets — closed @ depths listed: MD TVD 11,470' — 11,475' 6199' — 6200' 12,065' — 12,070' 6248' — 6248' Perfed Pups w/ 6-1/2" Holes @ depths listed: MD TVD 13,922' — 13,927' 6189' — 6189' 14,396' — 14,401' 6182' — 6182' 14,790' — 14,795' 6184' — 6184' 16,891' — 16,896' 6137' — 6136' PIONEElt NATURAL RESOURCES ALASKA ODSN-15i High Pressure Breakdown Objective: `l' wF . 1. Well is under injecting, attempt HPBD to increase injectivity t‘,-r`� , Procedure: 1. MIRU Schlumberger tanks. Load tanks with seawater. (Estimate 15 tanks for fluids) 2. Heat fluids to 100 deg. Using hot oil truck. 3. MIRU Schlumberger frac pumps and associated equipment. 4. Rig up tree saver and associated lines to tree. Pressure test treating iron. 5. Line up Hot oil truck and pressure up IA using diesel to 2500 psi. Hot oil truck will remain tied into annulus to record and maintain IAP during HPBD. 6. Pump the following at max rate allowable to maintain the WH treating pressure of 6000. It is assumed that due to the 3.5"tubing a maximum of 20-25 b/m will be the treating rate. a. 100 bbls slick water. b. 200 bbls slick water with 0.5 ppa 16/30 carbolite. c. 500 bbls slick water with,12 bio balls (to seal 6 0.5" holes) in the last few bbls. i. Repeat steps a -c seven times. ii. On the eighth and final stage delete the balls and instead swap to a 20 bbl diesel freeze protect. 7. SD pumping and monitor WHP fall-off for 1 hour. 8. Record WHP, BHP, and BHT. 9. Bleed IA down to 200 psi. 10. Return well to injection. • ZETE o ALASEA SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMMISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 Tim Crumrine Staff Completions Engineer Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, AK 99501 (7) 0 Re: Oooguruk Field, Nuiqsut Oil Pool, ODSN-15i Sundry Number: 310-430 Dear Mr. Crumrine: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. a f Chair DATED this 3 day of January, 2011. Encl. cekt,11 -0 RECEIVED STATE OF ALASKA DEC 1 7 2010 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS Alaska Oil&Gas Cons.Commission 20 AAC 25.280 Anchorage 1.Type of Request: Abandon❑ Plug for Redrill❑ Perforate New Pool❑ Repair Well❑ Change Approved Program ❑ Suspend❑ Plug Perforations❑ Perforate❑ Pull Tubing❑ Time Extension❑ Operations Shutdown❑ Re-enter Susp.Well❑ Stimulate❑ Alter Casing❑ Other: Convert to Injector El ' 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Pioneer Natural Resourcs Alaska, Inc. Development p Exploratory ❑ ' 210-032 • 3.Address: 700 G Street,Suite 600 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99501 50-703-20618-00-00• 7.If perforating,closest approach in pool(s)opened by this operation to nearest 8.Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No 0 ODSN-15i 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 355036/ADL 355037 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): 17,383' , 6096' 17,139' 6117' N/A N/A Casing Length Size MD TVD Burst Collapse - Structural Conductor 110' 16" 158' 158' N/A N/A Surface 3550' 11-3/4" 3589' 2982' 5830 psi 3180 psi Intermediate 5493' 9-5/8" 3377'-8870' 2880'-5301' 5750 psi 3090 psi Production 11,314' 7" 11,348' 6165' 7240 psi 5410 psi Liner 5945' 4-1/2" 11,195'- 17,140' 6117'-6117' N/A N/A Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attachment,pg.2 See Attachment,pg.2 3-1/2",9.3# L-80,TCII 11,207' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): ScSSSV;7"Hyd Perm Packer;Liner Top Packer 1995'MD/1870'TVD;9413'MD/5525'TVD; 11,210'MD/6121'TVD 12.Attachments: Description Summary of Proposal El 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development ❑ Service El 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 1/15/2010 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG E Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Tim Crumrine,343-2184 Printed Name Tim Crumrine,343-2184 Title Staff Completions Engineer Signature — Phone Date Prepared By:Kathy Campoamor,343-2183 12/16/2010 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 610-(-130 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test Location Clearance ❑ Other: // LL n d u H i Ns 0 re is j 6 IN ■K c-c-.c.or.Y 4>/ �1 I 0 34-? Subsequent Form Required: /D 411 044 elAPPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: (/...3(//R= IMS JAN 04201'p` ORIGINAL / Rz •30•'0 /,-,-\-- ,>.z, , Form 10-403 Revised 1/2010 Submit in Duplicate ,ad' /44e//D Pioneer Natural Resources Alaska Inc. ODSN-15i Page 2 Form 10-403, Application For Sundry Approvals Attachment Perforations - Present Well Condition Summary, Box 11 11 . Perforation Depth 4-'/2", 12.6#, L-80 Hyd 521 Uncemented Liner Sliding Sleeves w/ 6ea. 1/2" Ports — open @ depths listed: MD TVD 11,381' - 11,387' 6176' - 6177' 11,742' — 11,747' 6232' — 6232' 12,625' — 12,630' 6235' — 6235' Sliding Sleeves w/ 2 - .20 Jets — closed @ depths listed: MD TVD 11,470' — 11,475' 6199' — 6200' 12,065' — 12,070' 6248' — 6248' Perfed Pups w/ 6-1/2" Holes @ depths listed: MD TVD 13,922' — 13,927' 6189' — 6189' 14,396' — 14,401' 6182' — 6182' 14,790' — 14,795' 6184' — 6184' 16,891' — 16,896' 6137' — 6136' PIONEER NATURAL RESOURCES ODSN-15i Oooquruk - Nuigsut Infection Well Well Conversion Slickline Work AFE# Gen Sub 050.314 Name Title Phone Judy Golding Wellwork Supervisor 907-670-6602 Tim Crumrine Staff Completions Engineer 907-240-4295 Vern Johnson Drilling Superintendent 907-575-9430 Vance Hazzard Drilling Manager 907-830-4645 Joe Polya / Rig Wellsite Leader 907-670-6606 Rodney Klepzig Scott Larsen / NS Travel / Security 907-670-6600 Greg Smith Control Room Operations 907-670-6642 1. MIRU slickline unit. SI lift gas and let well de-pressure through open wing. 2. Set catcher sub in XN nipple @ 9507' MD. 3. Pull screened orifice from GLM @ 9200' MD. 4. Set dummy GLV in same. Bleed IA pressure down to ensure valve is set. — 5. Pull the catcher sub. 6. RD Slickline. 7. HPBD 8. Freeze protect well if not yet ready for injection. 9. If well is ready to put on injection and the necessary Sundry Notice has been approved, pump 10 bbls 50/50 MEOH and swap to water. 10.After 10 days of injection, shoot FL in IA. Notify Sate representative of intention to do initial MIT-IA 24 hours prior to test. 11.Fluid pack IA using diesel and C-H2O based on the FL shot. — ODSN-15i Page 1 12.MIT-IA to 1500 psi. Ensure trend is set up and recording during this pressure test. 13.Fill out the appropriate form and forward both form and trend to Theresa Williams. MIT-IA Prior to beginning injection a MIT-IA must be performed to a minimum of 1500psi. Please contact AOGCC representative for state witnessing of pressure test. The AOGCC must also be notified at least 10 days prior to beginning injection. Verify that Form 10-403 Application for Sundry Approval has been signed or that verbal authorization from state has been granted prior to injection. Area Injection Order 34 Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. A Commission-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter (except at least once every two years in the case of a slurry injection well). The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30- minute period. Results of mechanical integrity tests must be readily available for Commission inspection. • ODSN-15i 2 PIONEER Current Schematic-State Well Name: ODSN-15i NATUPAL RESOURCES IlVell, :FION17ANTAl-011rtrlal-low,8.'242010 2:.. Well Attrtbutee &lear&-ADWat A...1-N 'eaNene WW1 Pee. r LOP u.ghln'n1 1 IN 50-703-206-3-0E-00 Coag.lydk Lint DR LL_G 17.393.0 Casino Winne 16"Welded Conductor,i58.dttKB Cam-g Lbc•Au- n•'p(Y) M.g ID Itpin<ai set Dub",74. %.t 24 MIN C:' nib;'up"Ire PI.nu ill I - 15'V.elde3 1E '4.572 477 •550 '550 t-4C Neded -03 OE 2cniu:tcr 1-1] Casln Components ben •a:.p17 Pk INC.Dam.Iq.n -wR(al OW>);'e) CD OP, ID IN -unvat 1-1 Coadactor Sroe 47.7 47 7 -5 14.570 0 C 11-314"HYd 521 furtaoo,3,5a3.O11KB is C-v-7 Lbc•ge- n.up CO bring ID 14,(TAM MP Cub.,t Pt:pl. blurb Cu ''ens"up Ste be up WI II 11-3:4'I-pd •1 3:4 '0'72 33 4 1.559.0 2,9522 L-80 HYD 521 60112 L 52'SLrfaCe Cash Components .111 a.. Isar D.aalpm 'up anti row ELI pro ID MI Zomba 11-13I----Q 2-1' 1`14'SU13c6 Shoe 3.567.1 2,961 3 11 3,4 10 772 1E5 Flub'.Shoe - 0-firs"401111y0 521 0e111102 Liner 41,a 870.alticB 12-1-I Co-a D•Fc-pOr 'SY.e CD SIAM ID. I OP Vital bb boor m se.7411. SUN GI 5111nroppl.d -gimp wt II 9-6'6'434 HYS 9 5.8 a 535 3376.5 5.670.0 5,257' L-80 HYD 521 40.03. 521 Crtlirg BIB Liner r71 Casing Components PoppO0..pp�, I{] INe INC Da.algm TaCrbbi INC3IOCgD nD pip ID MI _unmrt 1. 1 ' 3-4 T:e Back Sleeve 3.3769 2837 0 10 1/4 9 587 �' ttt---"`•••n 3-5 WF-9-S'9'x11-34' 5PR• 3.393.E 2,692.1 10.43 6793 IM1 Jaw Top Pkr i r 3-6 WFT9-5113'x11-34"DHS' 3.4E0.7 2,693 3 101,2 a 750 i Hyd Laser Hgr 11 3-13 9 5J0'it lermedtate 1 Shoe 5.•3E7.7 5,286 7 9 5.3 III T 20!OTC-M�lh,sm cSyn 11,348.011K6 • Caubb Dre■ySNC se.%co. glop 16 'I op ln<si .L'. '.e :.t_r. =1,•%1G, n,n;;-.>'h 51,110.111 '4 7"26*BTC-W E 275 34 2 1-.343.3 5,154-° L-a3 13 -N 26.07 • M1enedtale s ceo '' Casln Components • Pen ''y C.r:, -43 Is m Ne boa D.amfgb, -41 a: I I VD)iVCb) 31 Mb ID IN :drt.nn• I ` 4-8 7'Inte-ne0ale251De 1'.343.3 6,'542 7 6276 Auk)tinShoetiES 8I 41 f2"12.64 $yd 521.17,110.O11:KB Cal-7 Lbc•Feu- n''p CI) MIN ID I op IIPCM nle D.q.t -Sat:iQ Slug C ant Top he e.•. Nl I 4'/2''2.64 4'.2 5 953 '1,19... 17.141).[ 5,1741 L-83 11Y0621 12.67 H53 521 Casing Components ��p�' Mb LE! 5-1' N. nr 08010.11/41 TaM1W I1'MCiteta) C0114 ID lel :.wraa 5-2 'WF-Tie Bad sleeve '11,194.7 6,105.4 .5.77' 5.253 HIS 5-3 WFT"NW"Liner top Pkr 5' 11,210.1 6,112 3 5.56 4.375 x7' m mail 5-4 WFT'PHR'h3 HT 5 x 7' 11,213.5 6,111 5 6.1 4.375 I• 5-6 WFTZOne Seleel 55'r'6- 11,381.5 6,163.0 5.63 3.920 ® 1f2"puEs • ® 5-11 WFT Zone Select SS'4'2- 11,470.2 6,168.3 5.63 3.920 .197 Jets .1 Ellts1 6-14 WF`53,'4 Genlals 011 Case 11,519.9 6,199.0 5 314 3.958 Swell Pkr ® 5.19 WF-Zane Select SS's,'6- 11.741.E 6,221.2 5.63 3.920 ® 12'parts I ® 5-21 1YF'Zone Selea SS e.'2- 12,065.4 6,237.4 5.63 3.920 ElEal 1971e:6 ® 5-24 WF"-Zone Selec SS'w16- 12,624.7 6,224 8 .5.63 3.920 1,2'parts 5-27 WF-S 3,4 Gentsle ON base 13,343.3 6,210 9 5 3,4 3.953 lb l Swell Pkr Ezu 6.37 Petted Pupa'E-1 22'hales 13.922.' 6,179 0 41,2 3 963 J 1 45-4'I 5-32 Derred Pup'N'6-112'holes 14,395.4 6,171.2 41,2 3.953 Page 1/2 Report Printed: B(2412010 ODSN-15i 3 >n) Z.l 0- 3Z • • - K.E.CRARICKT, IKTEGRITY REPORT • . . EPUD DATE ! : __V/c5,L2-0/0 OPER E FIELD RIG R EL F.1....F.E : • ////Z.-4/•e) WELL NUMBER 0 bi-Ai- 15 c. ,-- '!aLL DATA 'f.b I 17, 3 .s3n).. 6M 6 m).; PBTD : 64/1^ 1D TVD —.h..— _ _ Si . Casing : 7 ig,......_, Shoe : P70 J.D) 53D/ VD 1 DV -----. -MD —. .TVD Troi :.ine, : 7 " Shoe : laYrits ‘145. TVD ; TOP : HD TVD , ... . _uoing : -) ckor ta) TVD ; Set at , Hole Se - ariet ; Perfs ji/VI'S to 4.../Lio lot . _____ sfei /-;"•1 IS CRAM Cgla, INTEGRITY - ?MIT (1 . A.X1T1U-.).1).E ?17 C S S :4:E s t: a I-ICU : 15 Mill ___• ; ::',0 Min . . Comments : *, , )....b.At.,th...i .. j5,C.....C411(.7... , 1 • . CHA1ICA-14 INTEGRII.'T - PART e 2 1-4,..*- z• has ammeamr.•••••■••1111•10a001.- ...., ii ./. ..7' Cement Volumcsr Amt. Liner ( — Gig ; DV- . . . • Cmt vol to cover perfs '.._.21i3:06.,F .,4, 5-5L...-.- ye...-4 Theoretics.). TOC M 4- La/ 36 • -* .., ---P-2----- L., -,-.1P----2-3c _ LI C az-- . Cement Bond. Log ig50.r No) Ptent,.....1 ; In AOGCC File • 77--c-- CBI. Evalus.tion, zone above perfs a_,./L::Z•2___ l ( & e-,,,, ).J-. Production Log: Typ AJIA-- 1 Evaluation . — CONCLUSIONS : . . fl :: 1,0i±-..!,S5G.0 M I 7-- --TA Zitiltssad..0 . ?,art i 2 c.:. :.,: CAL- ah_ itpcd-ec-, . P/1. 4 . .. . (±74 it.-34)•1 _ MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg Karr -1177 I io DATE: July 3, 2010 P. I. Supervisor ( 1 FROM: John Crisp, SUBJECT: Pioneer Natural Resources Petroleum Inspector Oooguruk ODSN-15 PTD 2100320 - Temporary Flowline Test Nabors 19AC Inspection July 3, 2010 ODSN-15 Temporary Flowline Test: I traveled to PNR Oooguruk Island Well ODSN-15 to witness the pressure tests of the flow line required by AOGCC. The AOGCC determined that the temporary piping utilizing threaded connections with hammer unions did not have integrity to produce the States natural resources to custody transfer. Hydro-test of acceptable production piping with flanges, pipe spools & Grayloc connections was witnessed by AOGCC Field Inspector. This hydro-test was performed to a pressure of 4800 psi. for 30 minutes & was documented on a test chart. Nabors 19AC Rig Inspection: Unannounced Rig Inspection was performed while waiting for PNR to install ODSN-15's hydro-tested piping on the well to perform pressure test. 19AC's 11" 5K stack was clean & dry with no hydraulic leaks found. The cellar area around the Stack was tidy & hydraulic hoses for the BOP's were bundled with a strap & off the floor. BOP Accumulator was found to have proper pressures for the accumulator, manifold & annular preventer. Electric switch for tri-plex pump was in auto position & air was on to the accumulator air pumps. All 4 way valve handles were found to be in the correct position for drilling. No hydraulic leaks found. Rig operation during my Inspection was preparing to RIH with excess DP to be L/D. FOSV with D/P threads was racked in a position for easy access & the closing tool was placed in a very accessible place. Closing tool was sized correctly. ODSN-15 Temporary Flowline Test Nabors 19AC Unannounced Rig Inspection Casing liner had just been set. The liner top packer along with the liner itself had been positively pressure tested. Hole fill pump was on & the well bore was being monitored for stability. Pipe displacement while RIH was measured & announced over the Rig's intercom. Obvious that PNR & Nabors Alaska Drilling were treating this cased & tested well bore just like a live well. My Inspection conclusion was that this Rig was in very good shape & the Drill Crews were operating in a safe & efficient manner. Well control on this Rig at the time of my inspection was definitely a priority. 7 ODSN-15 well piping arrangement: I witnessed a production piping test on ODSN- 15 after installation on the well. Piping along with flanges & Grayloc connections were tested to 1800 psi. & documented on a test chart. Summary: 3 Inspections performed at Pioneer's Oooguruk ODS — 1) Successful production piping tests (2) of ODSN-15 2) Nabors 19AC unannounced Rig inspection performed. Attachments: none Non-Confidential ODSN-15 Temporary Flowline Test Nabors 19AC Unannounced Rig Inspection STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG la.Well Status: Oil 1151 Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 1b.Well Class: 2OAAC 25.105 20AAC 25.110 Development 0 Exploratory ❑ GINJ ❑ WINJ❑ WAG ❑ WDSPL❑ No.of Completions: _One Service ❑ Stratigraphic Test ❑ 2.Operator Name: 5.Date Comp.,Susp.,or 12.Permit to Drill Number: Pioneer Natural Resources Alaska, Inc. Aband.: 5/19/2010 210-032 3.Address: 700 G Street,Suite 600 6.Date Spudded: 13.API Number: Anchorage,AK 99501 4/10/2010 50-703-20618-00-00 4a.Location of Well(Governmental Section): 7.Date TD Reached: 14.Well Name and Number: Surface: 2950'FSL, 1162'FEL, Sec. 11,T13N, R7E, UM 5/13/2010 ODSN-15i Top of Productive Horizon: 8.KB(ft above MSL): 56.2' 15.Field/Pool(s): 1098'FSL,3759'FEL,Sec. 10,T13N, R7E, UM GL(ft above MSL): 13.5' Total Depth: 9.Plug Back Depth(MD+TVD): Oooguruk-Nuiqsut Oil Pool 266'FSL,2536'FEL,Sec.4,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- 469835.96 y- 6031066.15 Zone-ASP 4 17,383'MD/6096'TVD ADL 355036/ADL 355037 TPI: x- 461953.58 y- 6029249.96 Zone-ASP 4 11.SSSV Depth(MD+TVD): 17.Land Use Permit: Total Depth: x- 457911.69 y- 6033680.52 Zone-Asp 4 1995'MD/1870'TVD 417497 18.Directional Survey: Yes a No U 19.Water Depth,if Offshore: 20.Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) 901'MD/830'TVD 21.Logs Obtained(List all logs here and submit electronic and printed information per 20AAC25.071): 22.Re-drill/Lateral Top Window MD/TVD: Gyro,GR, DIR, GABI, D&I, PWD, RES, DEN, NEUT,CBL N/A 23. 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# H-40 Surface 158' Surface 158' 24" Driven 11-3/4" 60# L-8 2HYD Surface 3589' Surface 2982' 14-1/2" 545 sx PF'L';261 sx Class'G' 9-5/8" 40# L-80 3377' 8870' 2880' 5301' 11-3/4" 318 sx Class'G' HYD 521 7" 26# L-80 Surface 11,348' Surface 6165' 8-1/2" 206 sx Class'G';91 sx Class'G' BTC-M 4-1/2" 12.6# L-80 11,195' 17,140' 6117' 6117' 6-1/8" Uncemented HYD 521 24.Open to production or injection? Yesk Noll If Yes,list each 25. TUBING RECORD interval open(MD+TVD of Top&Bottom;Perforation Size and Number): SIZE DEPTH SET(MD) PACKER SET(MD/TVD)• �v 7"Hyd Perm Packer hr�-fi ro leu,cc-.1 htj t r`z' 3-1/2",9.3#, 9413'MD/5525'TVD; L-80,TCII 11'207 Liner Top Packer See Attachment, Pg.3 ( t:i:fJ "L-Ti4 11,210'MD/6121'TVD t i 26. ACID,FRACTURE,CEMENT SQUEEZE,ETC. p7 DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED dSI at . ..„.le 1996' Freeze protect 11-3/4'x 7'annulus w/130 bbls diesel �.' 'rte► 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 6/3/2010 Gas Lift Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 6/3/2010 8 Test Period -+ 236 583.6 0 3" 528 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 598 1281 24-Hour Rate �► 709 1751.1 0 25 28. CORE DATA Conventional Core(s)Acquired? Yes ❑ No 0 Sidewall Cores Acquired? Yes ❑ No El 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. RECEIVED i/ED None JUN 1 4 2010 Alaska Oil&;as Ceps.Commissicff 4nphsnr1Qe Form 10-407 Revised 12/2009 (.3 CONTINUED Q AA S JUN 16 2010 Submit original only v 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? ❑ Yes 21 No If yes,list intervals and formations tested, briefly summarizing test results.Attach separate sheets to this form,if needed, Permafrost-Top 841' 838' and submit detailed test information per 20 AAC 25.071. Permafrost-Base 1742' 1668' Top West Sak 2512' 2287' Top Torok 8149' 4991' None Top HRZ 9984' 5743' Top Kuparuk C 10,859' 6013' Top Nuiqsut 11,325' 6158' Formation at total depth: 17,383' 6096' 31. List of Attachments: Summary of Daily Drilling Operations,Well Schematic Diagram, Survey 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Alex Vaughan,343-2186 Printed Name: Ver nson Title: Drilling Superintendent &//i Signatur : e___,__ 1 Phone: 343-2111 Date: 6/11/2010 Well Name:ODSN-15 Permit No.:210-032 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 1b: Classification of Service wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection,Observation,or Other.Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI(Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift,Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 12/2009 Pioneer Natural Resources Alaska Inc. ODSN-15i Page 3 Form 10-407, Well Completion or Recompletion Report and Log Attachment - Box #24 24. Open to production or injection 4-1/2", 12.6#, L-80 Hyd 521 Uncemented Liner Sliding Sleeves w/ 6ea. 1" Ports— open @ depths listed: MD TVD 11,381' — 11,387' 6176' — 6177' 11,742' — 11,747' 6232' — 6232' 12,625' — 12,630' 6235' — 6235' Sliding Sleeves w/2 - .20 Jets — closed @ depths listed: MD TVD 11,470' — 11,475' 6199' — 6200' 12,065' — 12,070' 6248' — 6248' Perfed Pups w/ 6-1/2" Holes @ depths listed: MD TVD 13,922' — 13,927' 6189' — 6189' 14,396' — 14,401' 6182' — 6182' 14,790' — 14,795' 6184' — 6184' 16,891' — 16,896' 6137' — 6136' PIONEER Operations Summary Report NATURAL RESOURCES Well Name: ODSN-15i Contractor: NABORS DRILLING Rig Number: 19 AC Job Category: DEVELOPMENT DRILL Start Date: 4/6/2010 End Date: Depth Start Foot/Meters Last Mud Start Date End Date (ftKB) (it) Dens(lb/gal) Summary 4/6/2010 4/7/2010 0.0 Move ve side. ODSN-31.- 1. LDo end from m derrick. Prep rig for move from South side of Wellbays to o .II - Rig accepted on ODSN-15i at 00:01 on 04/06/10.- 4/7/2010 4/8/2010 0.0 (Skid rig to the end of the well row and fuel rig. Remove kill line and choke line valves,ND and remove NT-2 quick connect and RCD head. LD T3 BOP stack.Assemble Hydril BOP stack, including annular,double ram,mud cross,single ram and hoist same into cellar.NU NT-2 quick connect and rack back BOP stack on stump.Take on neccessary fuel and water for rig move. Skid rig around east end of the well row in route to ODSN-15i. 4/8/2010 4/9/2010 0.0, Skid rig around east end of the well row from ODSN-31 in route to ODSN-15i.Connect electrical lines and communication lines from rig pits to rig floor. Move rig onto ODSN-15i, level and shim same. Align service module with substructure, level and shim same. Install and NU starting head. 4/9/2010 4/10/2010 60.0 50.001 9.00 Finish rigging up HUTZ/PUTZ,all stairs,landings.NU drilling riser.Change out lower IBOP on top drive from XT-39 to 4-1/2 I.F.Spot SLB MWD unit and RU same.Slip and cut drill line.RU SLB MWD/LWD pressure transducer on stand pipe.PU and MU 27 stands of drill pipe in mouse hole and rack back same in derrick. Establish northern bearing for gyro surveys. PU and MU 5 stands of DP in mouse hole and rack back same in derrick. PU and MU 6 stands of HWDP with jars in mouse hole and rack back same in derrick.MU 1 stand of 8"drill collars with 1 stab and rack back same in derrick.Hold PJSM with all involved personnel.Calibrate drawworks for MWD/LWD depth tracking.Hang shieve and RU wireline unit for gyro surveys.PU bit,motor, 14.5"non mag stab,pony collar and MWD.Tag ice plug at 60'.Nash and ream out conductor f/60't/110'. '4/10/2010 4/11/2010 153.0 894.00 9.20',Wash and ream out conductor f/110'U153'. MU MWD and orient same. Drilling,sliding and surveying f/153'U269'. POOH f/269't/100'. RIH with 1 stand 8"DC and 1 stand HWDP to 269'. Drilling,sliding and surveying f/269'U366'.Take gyro, MWD and MGT surveys at 304',and send results into Sperry ROC for anti-collision with ODSK-14.Drilling,sliding,and surveying f/366' U457'.Take gyro,MWD and MGT surveys at 394'and send results into Sperry ROC for anti-collision with ODSK-14. Drilling,sliding and surveying f/457't/1,047'. POOH f/1,047'U275' 4/11/2010 4/12/2010 1,047.0 634.00 9.30'Continue to POOH f/275'to surface.Adjust motor bend from 1.83 to 2.12 degree bend,and rearrange BHA. PU new MWD and lead collar,orient same.TIH f/175't/1,015'.Troubleshoot ,MWD.Wash and ream f/1,015'U1,047'--no fill. Drilling,sliding and surveying f/1,047't/1,681'. 1 POOH f/1,681'to surface,and adjust motor bend from 2.12 to 1.83 degrees.Orient MWD and TIH from surface U175'. 4/12/2010 4/13/2010 1,681.0 -349.00 9.10,TIH f/175'U1,648'-tagged tight spot.Wash and ream f/1,648'U1,681'. Drilling,sliding and surveying f/1,681'U2,823'. Discovered leak in the adapter for MWD transducer on stand pipe. Disconnect kelly hose and replace hammer union gasket. Drilling,sliding,and surveying f/2,823'!, t/3,013'. 4/13/2010 4/14/2010 3,013.0 583.00. 9.50'Drilling,sliding and surveying f/3,013'U3,596'. Pump hi-vis,weighted sweep and circulate hole clean with same. POOH f/3,596't/175'.TIH f/175'b3,596'.Pump hi-vis,weighted sweep and circulate hole clean with same. POOH f/3,596'to surface racking back HWDP and laying down remainder of BHA. Page 1/6 Report Printed: 6/11/2010 1, �i r P l O 1.V E E R Operations Summary Report NATURAL RESOURCES Depth Start Foot/Meters, LSSt Mud Start Date' End.Date (ttKe3 i Dena(lb/Sal) x • Summary 4/14/2010 4/15/2010 3,596.0 0.00 9.50 LD remainder of BHA. RU 11-3/4"casing equipment. MU float equipment and circ thru same, RIH w/11-3/4"60#L-80 Hydril 521 Csg 1/3,545'.MU landing joint and hanger,land casing at 3.589'„RD fill up tool and RU cement head and lines.Fill Pipe,Break circulation with 1/2 bpm, Increase pump rate in 1/2 bpm increments to 5 bpm and 1 bpm increments until 10 bpm established w/o losses. Pump 20 bbls seawater.Test cement lines to 4000 psi.Pump 60 bbls 10.0 ppg Dual Spacer.Released 2nd Bottom Plug. Pump 403 bbls(545 sx)10.7 ppg Lead PF L'cement followed by 55.4 bbls(261 sx)15.9 ppg Tail Class'G'cement.Pump 1 bbl seawater, Drop Top Cement Plug,pump 20 bbls seawater.Switched to rig and displaced cement w/384 bbls mud at 8.5 bpm w/ICP of 1700 psi,FCP 2200 psi,bump plug w/3500 psi,held pressure 30 min on chart--Good test.CIP CO 21:51 hrs. 107 bbls cement returns to surface,bled off pressure and floats held--3.6 bbls bled back.RD cement head and lines.LD landing joint. Flush flow line and riser with citric acid water while preparing for ND. 4/1 4/15/2010 416/2010' 3 RD 11-3/4"casing tools.ND drilling riser and starting head.Install 5M drilling spool and test ' ,596.0 0.00 9.40 same to 5000 psi held 10 min--Good test,NU BOPE. Function test BOPE. Install 5"pipe rams in lower rams and 2-7/8"x 5"VBR's in upper rams. RU test equipment,fill stack with water, close annular preventer and perform body test on BOPE due to the fact that this stack was �QQ disassembled for inspection--found one flange loose and tightened same. Break in upper (�U► VBR's as per manufacturer recommendation.Test Annular to 250 psi low/2500 psi high with DP.Test Upper 2-7/8"x 5"VBR's, 'Lower 5"'Single Bore Rams, Blind Rams,Choke and Kill Line HCR's,Choke and Kill Line Manual Valves,Floor Safety valve,Dart valve,Upper IBOP, 14 Manifold valves to 250 psi low/4500 psi high. All low and high tests held 5 min ea.All tests charted.Accumulator test,System Pressure 3000 psi,After Closer 2100 psi,Initial 200 psi recovery 17 sec's,Full recovery 1 min 30 sec's. RD test equipment.AOGCC representative • Chuck Scheve waived witness of test at 18:00 hrs on 04/14/10.Clean and clear rig floor while preparing to PU 5'DP from pipe shed.TIH picking up 5"DP singles from pipe shed from surface t/578'. 4/16/2010 4/17/2010 3,511.0 85.00 9.20 TIH picking up 5"DP singles from pipe shed f/578'1/2,862'.Circulate 1.25x drill pipe capacity to ensure pipe has no obstructions.POOH racking back clean DP in derrick f/2,862'to surface.PU clean out BHA#4.TIFt_f/109't/i 440 Wasj down f/3,440'tag cement at 3,511'.Drill cement and float equipment f/3,511't13,596'. POOH ff ,596't/T08'.LD BHA 1/1 U to surface.PU rotary steerable BHA#5 from surface 1/81'.Shallow pulse test MWD/LWD,break in Power Drive bearings. 4/17/2010 4/18/2010 , 3,596.0 1,774.00 9.50 PU remainder of BHA#5 f/81't/734'.TIH 1/734'1/3,515'.Perform MAD pass f/3,515"1/3,596'. Drilling f/3,596't/3,616'. CBU and.perform L.O.T.at 3,587'MD/2,984'TVD with 9.2 ppg leaked off at 1060 psi,EMW=16.0 ppg.Drilling 1/34616'1/3,725'. Drop 1-5/8'ball and pump ball on ' seat in 6 min,pressure up and sheer ball seat to engage under reamer cutters and confirm same.Drilling 10-5/8"hole and underreaming to 11-3/4' f/3,725'1/5,370'. , 4/18/2010 4/19/2010 5,370.0 1,646.00 9.80 •rilling_(1 /8"hole and under reaming to 11-3/4"f/5,370'1/6,192'.Had 500 psi pressure drop in stand pipe pressure--indicating a wash out.POOH f/6,192't/5,683'.Stage up pumps to 400 • gpm and back ream through tight spot at 5,683'.Back ream f/5,683't/5,207'. POOH f15,207' 1/4,300'-found washout.Layout washed out joint and replace same.Circulate at 800 gpm to ensure no more wash outs.TIH f/4,300'1/6,095'.Circulate hole clean while reaming f/6,095' 1/6,192'.Drilling 10-5/8"hole and under reaming to 11-3/4"f/6,192'1/7,016'. 4/19/2010 4/20/2010 7,016.0 1,618.00 9.90 Drilling 10-5/8"hole and under reaming to 11-3/4'f/7,016'V8,634'. 4/20/2010 4/21/2010 8,634.0 248.00 9.90 Drilling 10-5/8"hole and under reaming to 11-3/4"f/8,634'1/8,882'. Pump 80 bbls hi-vis sweep and circulate hole clean with 3x bottoms up strokes. POOH f/8,882'1/7,968'.Establish circulation and pump dry job.POOH f/7,968'1/3,430'--saw 50k over pull as under reamer came into casing shoe,and 100k over pull as bit came into casing shoe.TIH f/3,430'1/3,780'. Establish circulation,stage pumps up and CBU strokes while working tight hole conditions. POOH f/3,780'1/180'--hole swabbing,had to pump displacement down DP. POOH f/180'1/44' with 1 stand of DC and rack back same. Page 2/6 Report Printed: 6/11/2010 P I O N E E R Operations Summary Report NATURAL RESOURCES Depth Start Foot/Meters 1 Last Mud Start Date End Date (ftKB) {ft) ° Dens(Ib/gal) Summary 4/21/2010 4/22/2010 8,882.0 0.00 10.00 Finish LD BHA#5 f/44'to surface. PU BHA#6 from surface t/640',functioned Rhino reamer at surface and thread locked bull nose to reamer.TIH f/640'V3,580'.CBU at 3,580'.TIH f/3,580' t/8,730'.Circulate at 8,730'--packed off. POOH attempting to circulate each stand,and was able to establish circulation at 6,922'. Stage up pumps to 760 gpm,wash and ream in the hole f/6,922't/8,779'. Underream 10-5/8"rat hole to 11-3/4"f/8,779't/8,875'. 4/22/2010 4/23/2010 8,882.0 0.00 9.80 Pump 80 bbls hi-vis sweep and circulate hole clean with 3x bottoms up. POOH f/8,882't17,113'. Pump out the hole(/7,113't/4,733'.CBU at 4,733'. Back ream out the hole f/4,733't/3,589'. Drop 2"Rhino reamer deactivation ball and shear ball seat at 1500 psi. Reciprocate pipe (/3,589'V3,495'to establish circulation after pack off event at 3,589'and circulate hole clean with 2x bottoms up strokes.Drop 2.75"rabbit and POOH f/3,495't/735'--tight at 2,600'. Drain stack and function test BOPE. POOH with BHA racking back HWDP f/735't/216'. NOTE:Contacted AOGCC for 48 hr notice of BOPE test. 4/23/2010 14/24/2010 8,882.0 0.00 9.90'POOH laying down BHA. Install test plug. Remove VBR's from top ram cavity and install 9-5/8" JJI f ,single bore rams. RU BOPE test equipment Test Annular to 250 psi low/2500 psi high.Test 1� top 9-5/8" rams to 250 psi low/4500 psi high.All test held 5 min each and charted. RD BOPE test equipment. RU 9-5/8"Casing equipment and fill up tool. RIH w/9-5/8"40#L-80 Hydril 521 Casing f/surface t/3,583'.CBU at 3,583'. RIH with casing(/3,583't15,463'. RD casing equipment. PU 10-1/2" Liner Top Hanger/Packer assembly.Tie back sleeve @ 3377', 9-5/8"x11"Liner top packer @ 3399'and 9-5/8"x11"liner hanger @ 3401'. RD casing spiders and RIH w/9-5/8",40#, L-80 HYD 521 Drilling Liner on 5"DP f/5,463'V6,373'. NOTE:Contacted AOGCC for 24 hr notice of BOPE test. '4/24/2010 4/25/2010 8,882.0 0.00 10.001RIH w/9-5/8",40#, L-80 HYD 521 Drilling Liner f/6,373 U8,847'PPU&MU Cement Head. RIH U8,870. Break circulation and circulate 9-5/8 liner volume. Drop 1-3/4"Liner Hanger setting ball and pump down same.Set down 85K to set Hanger. PU to 180K and obseved free travel to verify Hanger set. Pump 10 bbls water.Test cement lines to 4000 psi. Pump 60 bbls 12.5 ppg Dual Spacer at 3.5 bpm at 1000 psi. Pump 66.2 bbls(318 sx) 15.8 ppg Class'G'cement with at 4 bpm at 900 psi. Drop DP Wiper Dart. Pump 17 bbls water and switch to rig for displacement. Displace cement with 9.8 ppg mud at 6.5 bpm. Slowed pumps to 2 bpm,3 bbls prior to bumping plug. Pressure up to 3500 psi, held 5 min.CIP @ 0920 hrs. PU to expose Packer setting dogs. S/O to 40K applying 80K to Packer setting dogs.Closed Annular and pressured up 5"x 11-3/4" annulus to 3500 psi to test Packer. Held pressure 5 min. Circulated BU. RD Cement Head. POOH f/3,354'V surface and LD running tool. Remove 9-5/8"single bore rams from top ram cavity and install 2-7/8" X 5"VBR's. ND BOPE and drilling riser. 14/25/2010 4/26/2010 8,882.0 0.00 10.00 ND BOPE and drilling riser. ND Intermediate casing spool,.NU Multi-bowl and test same to 5000 psi for 10 min on chart.NU BOPE and drilling riser.Install MPD test flange and test all lines to 250 psi low/3000 psi high. Remove test flange and install trip nipple.Test Annular to 250 psi low/2500 psi high with 5" DP.Test Upper and Lower 2-7/8"x 5"VBR's, Blind Rams,Choke and Kill Line HCR's, Choke and Kill Line Manual valves, Floor Safety valve,Dart valve, Upper IBOP, 14 Choke Manifold valves to 250 psi low/4500 psi high. All low and high tests held 5 min ea.All tests charted.Accumulator test,System Pressure 3050 psi,After Closer 2100 psi, Initial 200 psi recovery 21 sec's, Full recovery 1 min 35 sec's. RD test equipment.Test witnessed by AOGCC rep Lou Grimaldi. Install wear bushing.TIH from surface t/1,900' picking up 60 singles from pipe shed.Circulate 1.5x drill pipe capacity. POOH(/1,900'to surface. PU rotary steerable BHA#7 from surface t/720'.TIH 1/720't/1,091'. Pulse test MWD and Power Drive-Good test.TIH f/1,091't14,050'. 4/26/2010 4/27/2010 8,882.0 269.00 10.001ITIH(/4,050't/8,704'.Pressuretest 11-3/4"casin_gx 9.5/8"liner to 3500 psi.Test held 30 min and charted. Drill cement and float equipment f/8,704't%8,865'. Pump 80 bbls hi-vis sweep and circulate same surface to surface. Remove trip nipple and install RCD bearing.Drill float shoe land 20'of new hole f/8,865't18,902'.CBU at 8,902'. Perform L.O.T.at 8,870'md/5,301'tvd,with 10.0 ppg mud wt.Leaked off at 1900 psi and bled down to 667 psi for EMW of 12.4 ppg.Drilling 8-1/2"hole f/8,902't19,151'. Page 3/6 Report Printed: 6/11/2010 PIONEER Operations Summary Report NATURAL RESOURCES Depth Start Foot/Meters 1 Last Mud Start Date End Date (f1K8) (ft) i Dens fib/gal) Summary 4/27/2010 4/28/2010 9,151.0 749.00 10.00 Drill 8-1/2"hole f/9,151 t/9,900,Observed intermittent losses f/300-30 bph. Reduce MPD WHP f/12.5ppg EMW V 10.1ppg EMW to control.POOH f/9,900' t18,810'and circ&cond hole to spot DOB2C pill. 4/28/2010 4/29/2010 9,900.0 480:00 10.00 POOH f/9,030' t/8,550'laying DOB2C Stop Loss Pill.Perform hesitation squeeze with MPD applying WHP for EMW f/10.1 -12.75 ppg EMW with 8 bbls total lost. CBU. Increased EMW to 13 ppg with no losses.Wash&ream f/8,550' t/9,900'with no losses.Drill 8-1/2"hole f/9,900' t/10;380'with 30 bph loss.Maintain 12.75 ppg EMW using MPD. 4/29/2010 4/30/2010 10,380.0 999.00 10.00 Drill 8-1/2"hole f/10,380' t/11,379'maintaining 13.0 ppg EMW using MPD. Reach hole section TD. Circ&Cond hole. 4/30/2010 5/1/2010 11,379.0 0.00 10.00 Circ&cond hole at 11,379'. Backream t/9,952'.POOH on elevators t18,860':Wash and ream in hole t/11,379'.Circ&cond hole.POOH on elevators t/11,000'.Circ&cond hole. 5/1/2010 5/2/2010 1 11,379.0 0.00 12.80 POOH(/11,000' t/10,428'on elevators with 60 bph losses. RIH t/11,369'.Circ&cond hole.Spot 40 bbl 13.0 ppg LCM pill while POOH(/11,369' t/10,808'. Displace 10.0 ppg mud to 12.8 ppg mud. POOH to surface. LD BHA. i 5/2/2010 5/3/2010 11,379.0 0.00 12.80 Remove 2-7/8"x 5"VBR's. Install a"rams in upper ram body and test to 250/4500 psi.Test annular to 250/2500 psi.Tests passed&charted.RIH with 7"26#1-80 BTCM casing t/8.870'. 5/3/2010 5/4/2010 11,379.0 0.00 11.00 RIH 7"26#L-80 BTCM casing with autofill floats f/8,870' t/11,348'. Observed the hole flowing.The annular preventer was shut in to monitor pressures. 7"x 11-3/4" annulus pressure elevated and stabilized at 150 psi.The stand pipe pressure elevated and stabilized at 100 psi. Annular choke was opened for 15 min to bleed and monitor pressures with 3 bbl flowing back. Standpipe was bled off.Determined well was ballooning.Bled back total of 11 bbl. PJSM. Pump 10 bbls seawater.Test cement lines to 5000 psi. Pump 20 bbls 12.5 ppg Dual )<• Spacer. Drop 1st plug. Pump 20 bbls 12.5 ppg Dual Spacer. Drop 2nd Plug. Load Top Plug. P m.4 b.l 1. 1 . ... I-:s -ment.glass G with 15#/sk MicroLite.0.75%Halad-344. 2%CFR-3.0.15%EZ Flow.0.5%SCR-100. Pump 19 bbls(91 sx) 15.8 ppg tail cement.Class G with 0.7%Halad-344.0.2%CRR-3.0.25 lb/sk Super CBL.0.4%SCR-100. Drop Top Plug. Pump 20 bbls seawater.Switch to Rig pumps and displace with 411 bbl of 11 ppg mud at 5 bpm.Lift was indicated by an increase in the displacement pressure of 60-100 psi prior to bumping plug. Bumped plug at 3.5 bbl/min.CIP @ 00:00 hrs. Pressure up to 4500 psi and held 30 min. Bled off pressure. Bled back 6.6 bbls followed by 4 additional bbls at 1 bbl/min.Closed bleeder and monitor. Pressure built to 120 psi. Floats not holding.Pump 52 stks to push plugs back to bottom. Pressure up to 600 psi and held. 5/4/2010 5/5/2010 11,379.0 0.00 11.00 Maintain 600 psi on floats and W/O cement to set.Bled pressure with 2 bbls back.No additional returns from 7" ID. Flow check 7"x 11-3/4"annulus while RD non-well-control essential equipment. Diminishing returns from 55-0.25 gph.PU 235k on 7"casing and set in emergency slips.Install pack-off&test to 4350 psi for 10 min.Test passed&charted. , 5/5/2010 5/6/2010 11,379.0 0.00 7.80IChange out elevators, install iron roughneck track. LD 17 joints HWDP,jars,and all 5"DP to ipipe shed utilizing mousehole.Slip and cut drill line.Change out all handling equipment from 5" to 4". Install wear bushing.TIH picking up 4"singles from the pipe shed to+/-2,700'. "Note" Freeze protected 11-3/4"x 7"annulus with 130 bbls diesel. 5/6/2010 5/7/2010 11,379.0 0.00 10.80 TIH picking up 4"singles from the pipe shed f/2,700't/9,054'.Circulate 1.25x DP capacity to ensure no obstructions in drill pipe. POOH f/9,054'to surface racking back clean 4"DP in derrick.TIH picking up 4"singles from the pipe shed from surface t/9,000'.Circulate 1.25x DP capacity to ensure no obstructions in drill pipe.POOH f/9,000't/4,815 racking back clean 4"DP in derrick. Page 4/6 Report Printed: 6/11/2010 PIONEER Operations Summary Report NATURAL RESOURCES Depth Start Foot/Meters `Last Mud Start Date End Date (ttKB) (ft) Dens(lb/gal) Summary 5/7/2010 5/8/2010 11,379.0 0.00 10.20[POOH f/4,815'to surface. Remove wear bushing and install test plug.Change out upper and_ lower pipe rams. RU testing equipment.Test Annular to 250 psi low/2500 psi high with 4"DP. Test Upper 2-7/8"x 5"VBR's and Lower 4"single bore rams, Blind Rams,Choke and Kill Line HCR's,Choke and Kill Line Manual valves, Floor Safety valve, Dart valve, Upper IBOP, 14 Choke Manifold valves to 250 psi low/4500 psi high. All low and high tests held 5 min ea.All tests charted.Accumulator test, System Pressure 3100 psi,After Closer 2100 psi, Initial 200 psi recovery 21 sec's. Full recovery 1 min 32 sec's.Test witness waived by AOGCC rep Chuck Scheve at 20:15 hrs on 05/07/10.Test all MPD lines to 250 psi low/3000 psi high-Good tests. PU BHA from surface 11223'.TIH(/223'1111,208'.Wash and ream cement stringers(/11,208' it/11,265'. Drilling float equipment and cement f/11,265't/11,304'. cII '5/8/2010 5/9/2010 11,379.0 754.00 7.85 Drilling float equipment and cement(/11,304'1/11,348'and clean out rathole t/11 3 79'.Drilling • f/11,379'1/11,399'. Perform F.IT.at 6,165'tvd with 10.4 ppq mud weight to 700 psi for EMW of 12.5,bled down to 610 psi after 5 min for EMW 12.3 ppg.Transfer WBM from rig to RSC,clean rig mud pits,transfer MOBM to rig pits from RSC.Installed RCD bearing. (7jsplace well from 10.4 ppg WBM to 7.6 ppg MOBM while maintaining 9.8 ppg PWD_Eon Directional drill(/11,399' it/12,133'while maintaining 9.8 ppg BCD with MPD equipment. 5/9/2010 5/10/2010 12,133.0 719.00 Drill 6-1/8"hole f/12,133'1/12,852'maintaining 9.9 ppg EMW w/MPD. I ' 5/10/2010 5/11/2010 12,852.0 575.00 7.80 Drill 6-1/8"hole f/12,852 t113,427'maintaining 9.8 ppg EMW at 7"shoe utilizing MPD equipment. • 5/11/2010 5/12/2010 13,427.0' 2,123.00 7.95 Drill 6-1/8" hole f/13,427'1/15,550'maintaining 10.1 ppg EMW at 7"shoe utilizing MPD equipment. 15/12/2010 5/13/2010 15,550.0 1,300.00 8.001Drill 6-1/8"hole f/15,550'V16,225'maintaining 9.8 ppg EMW at 7"shoe utilizing MPD equipment.Circulate open hole volume prior to check trip. POOH f/16,225'V15,454'.TIH f/15,454'V16,225'. Drill f/16,225'1116,850'maintaining 9.8 ppg EMW at 7"shoe utilizing MPD l i I equipment. • 5/13/2010 5/14/2010 ' 16,850.0 533.00 8.00 Drilled f/16,850'and to TD maintaining 9.8 ppq EMW w/MPD of the 6-1/8"lateral at 17,383'md. CBUx3 and TOH to 7"casing shoe @ 11,348'md.Slip&Cut Drill Line.TIH to 16,322'md. Wash and ream to 17,093'md. '5/14/2010 5/15/2010 17,383.0 0.00 10.20 Stage pumps up and circ hole clean.Wash&ream in the hole f/17,093 V17,150'.Pump 20 bbl Hi-Vis Sweep and circ same out the hole.Spot 220 bbls of new 7.2 ppg MOBM across open hole. POOH f/17,150'V12,050'. Pump 49 bbls 10.2 ppg MOBM to displace open hole from 8.1 ppg MOBM while maintaining 9.8 ppg EMW w/MPD. POOH f/12,050'V11,304'.Displace casing volume from 8.1 ppg with 10.2 ppg MOBM. Monitor well,remove RCD bearing,and install trip nipple.Circ and condition mud weight to 10.2 ppg. POOH f/11,304'11416'. Function test BOPE. I 5/15/2010 5/16/2010 17,383.0 0.00' 10.20,POOH f/416'11223'. Remove nuclear sources and LD BHA. RU testing equipment.Test Annular to 250 psi low/2500 psi high with 4.5"test joint.Test Upper 2-7/8"x 5"VBR's with 4.5"test joint to 250 psi low/4500 psi high. All tests held 5 min ea.All tests charted. RU 4-1/2"casing equipment. RIH with 4-1/2", 12.6#, L-80 HYD 521 casing from surface 115,290'. PU WFT hyd hanger, liner top packer,and tie back sleeve(/5,920'V5,945'. MU SLB memory cement bond log tool.TIH with 4-1/2" liner on 4"DP(/5,945'1111,285'. Pump lx drill pipe capacity.TIH with 4-1/2" [ liner on 4"DP f/11,285'V14,123'. 5/16/2010 5/17/2010 17,383.0 0.00 10.10'TIH with 4-1/2"liner on 4"DP f/14,123'V17,140'. Drop 1-3/4" Hgr Setting Ball. Pump on seat at 1 bpm. Pressure up to 1500 psi to set Hgr. Slack down to 75k and lock in Hgr slips. Pressure up n ball seat sheared out at 3400 psi.Slack down to 65k on dogs to set Pkr.Liner top packer @ !CD 11,210'. Displace well from 10.2 ppg MOBM to 10.1 ppg brine. POOH at 30'per min for cement "A bond log with SCMT tool f/11,068'1110,200'.TIH f/10,200'V11,110'. POOH at 30'per min for repeat cement bond log f/11,110'1110,200'. POOH f/10,200'V6,979'. Slip and cut drill line. 'POOH f/6,979'to surface laying down 4"drill pipe and BHA. Page 5/6 Report Printed: 6/11/2010 PIONEER Operations Summary Report NATURAL RESOURCES Depth Start Foot/Meters Last Mud Start Date End Date MKS) (ft) Dens(Ib/gal); Summary 5/17/2010 5/18/2010 17,383.0 0.00 10.10 Remove MWD pressure transducer from standpipe, reconnect kelly hose and test same to 4500 psi-Good test. Re-orient RCD head, NU same and install trip nipple.TIH f/surface t/1,930'. POOH f/1,930'V surface laying down 4"drill pipe.PU a-line tools and spot e-line unit.Change out handling equipment from 4"to 5". MU and PU 5"drill pipe,33 stands total using the mousehole and rack back same in derrick.TIH f/surface t/9,269'. POOH f/9,269'V surface laying down 4"drill pipe. 5/18/2010 5/19/2010 17,383.0 0.00 10.10 C,/O lower rams to 3.5".Test Annular to 250 psi low and 2500 psi high.Test VBR's and 3.5" lower rams to 250 low/4500 high.Lower rams failed.CIO same retest.All tests held 5 min each and charted.RU&run 3-1/2",9.3#,L-80 TCII completion tubing per program U9253'.MU TRSSSV and land @ 1995'md.Install control lines&test to 5000 psi for 10 min-OK. 5/19/2010 5/20/2010 17,383.0 0.00 10.10 Finish running 3-1/2",9.3#, L-80 TC11 tubing f/9253'V11,167'. Land tubing hanger w/TWC. • on f uf"�"ISg anger and t I s es a s to 5000 psi for 10 min-charted same,WLEG @ 11,207'. ND BOPE,NU tree-Test to 5000 psi.Spot inhibited brine-Drop B&R,Set packer. Test tubing&IA to 4500 psi for 30 min_each. RU Slickline, Retrieve B&R. Rig released @ 23:59 hrs on 05/19/10. • • Page 6/6 Report Printed: 6/11/2010 PIONEER Current Schematic - State Well Name: ODSN-15i NATURAL RESOURCES Well Profile:HORIZONTAL-Original Hole,6/10/2010 4...Well Attributes Schematic-Actual API/UWI Field Name Well Status Total Depth(ftKB) 1 2f 50-703-20618-00-00 Oooguruk Unit DRILLED 17,383.0 Casing Strin s Casing Description String 0... String ID...Top(ftKB) Set Depth(ft... Set Dept... String Gr... String Top Thrd String Wt(I... I16"Welded 16 14.670 47.7 158.0 158.0 H40 Welded 109.00 ll i.I Conductor 1 1-1 1 Casin Components Item Top Depth No. Item Description Top(ftKB) (TVD)(ftKB) OD(in) ID(in) Comment 1-1 Conductor Shoe 47.7 47.7 16 14.670 11-91 11-3/4"Hyd 521 Surface,3,589.0ftKB 3-4 Casing Description String 0... String ID...Top(ftKB) Set Depth(ft... Set Dept... String Gr... String Top Thrd String Wt(I... _,3-5 11-3/4"Hyd 11 3/4 10.772 39.4 3,589.0 2,982.2 L-80 HYD 521 60.00 13-6 521 Surface Casin Components Item Top Depth No. Item Description Top(ftKB) (ND)(ftKB) OD(in) ID(in) Comment 11-13 1 2-11 11 3/4"Surface Shoe 3,587.1 2,981.3 11 3/4 10.772 HES Float Shoe 9-5/8"40#Hyd 521 Drilling Liner#1,8,870.0ftKB " —i 2-11 Casing Description !String 0... !String ID...ITop(ftKB) Set Depth(ft... Set Dept... String Gr... String Top Thrd String Wt(I... 9-5/8"40#Hyd 9 5/8 8.835 3,376.9 8,870.0 5,287.7 L-80 HYD 521 40.00 521 Drilling • 13-13 Liner#1 L Casing Components 1 1-171 Item Top Depth No. Item Description Top(ftKB) (ND)(ftKB) OD(in) ID(in) Comment 1 21 3-4 Tie Back Sleeve 3,376.9 2,880.0 10 1/4 9.687 3-5 WFT 9-5/8"x11-3/4" 3,398.6 2,892.1 10.43 8.750 "TSPR"Liner Top Pkr [1-25k 1 3-6 WFT 9-5/8"x11-3/4""PHS" 3,400.7 2,893.3 10 1/2 8.750 ■ Hyd Liner Hgr 1-30 �fl 3-13 9 5/8"Intermediate 1 Shoe 8,867.7' 5,286.7 9 5/8 7"26#BTC-M Intermediate Csg,11,348.0ftKB 11-331 Casing Description String 0... String ID...Top(ftKB) Set Depth(ft... Set Dept... String Gr... String Top Thrd String Wt(I... 7"26#BTC-M 7 6.276 34.2 11,348.0 6,154.8 L-80 BTC-M 26.00 Intermediate 11-371 Csg Casing Components 1■LQ 5-2 Item Top Depth 5 3 No. Item Description Top(ftKB) (ND)(ftKB) OD(in) ID(in) Comment 5-4 4-8 7"Intermediate 2 Shoe 11,346.3 6,154.21 7 6.276 Auto fill Shoe HES 41/2"12.6#H d 521,17,140.0ftKB Casing Description String 0... !String ID...Top(ftKB) Set Depth(ft... Set Dept... String Gr... String Top Thrd String Wt(I... 6-14-81 14-81 4 1/2"12.6# 4 1/2 3.958 11,194.7 17,140.0 6,104.1 L-80 HYD 521 12.60 Hyd 521 IIK 15-8 Casing Components Item Top Depth It .I {5-11 No. Item Description Top(ftKB) (ND)(ftKB) OD(in) ID(in) Comment I 5-2 WFT Tie Back Sleeve 11,194.7 6,105.4 5.77 5.250 4 t --15-141 5-3 WFT"NHT"Liner top Pkr 11,210.1 6,110.3 5.96 4.375 5"x 7" �5-181 5-4 WFT"PHR"Hyd Hgr 5"x 11,213.5 6,111.5 6.1 4.375 7" 1 '+ 15-211 5-8 WFT Zone Select SS w/6- 11,381.5 6,163.0 5.63 3.920 'P i 5-24 1 1/2"ports 5-11 WFT Zone Select SS w/2- 11,470.2 6,188.3 5.63 3.920 1 15-271 .197 jets Hi 5-14 WFT 5 3/4 Genisis Oil base 11,519.9 6,198.0 5 3/4 3.958 • 5-30 Swell Pkr EN ® 5-18 WFT Zone Select SS w/6- 11,741.6 6,221.2 5.63 3.920 EMI 1/2"ports 5-21 WFT Zone Select SS w/2- 12,065.4 6,237.4 5.63 3.920 t 57.37 .197 jets 5-24 WFT Zone Select SS w/6- 12,624.7 6,224.8 5.63 3.920 * i 5- 1 1/2"ports ;T ICI 5-27 WFT 5 3/4 Genisis Oil base 13,348.3 6,210.9 53/4 3.958 Swell Pkr 1 1 -15-471 5-30 Perfed Pup w/6-1/2"holes 13,922.0 6,178.0 4 1/2 3.958 Page 1/2 Report Printed: 6/10/2010 PIONEER Current Schematic - State Well Name: ODSN-15i [NATURAL RESOURCES Well Profile:HORIZONTAL-Original Hole,6/10/2010 4... Casing Components Schematic-Actual • Item Top Depth No. Item Description Top(ftKB) (TVD)(ftKB) OD(in) ID(in) i Comment 1 1-2 1 5-32 Perfed Pup w/6-1/2"holes 14,396.4 6,171.2 4 1/2' 3.958 c 5-34 Perfed Pup w/6-1/2"holes 14,790.3 6,172.9 4 1/2 3.958 5-37 WFT 5 3/4 Genisis Oil base 15,392.0 6,192.1 5 3/4 3.958 I I Swell Pkr 5-41 WFT 5 3/4 Genisis Oil base 16,046.7 6,189.8 5 3/4 3.958 1-1 Swell Pkr 5-44 Perfed Pup w/6-1/2"holes 16,891.3 6,123.8 4 1/2 3.958 5-47 4 1/2"Production Liner 17,138.7 6,104.2 4 1/2 3.958 Float Shoe Plugged Shoe 11-9 Tubing Strings 3-4 Tubing Description String 0... String I... Top(ftKB)Set Depth(... Set Dep... String Wt...TString G... String Top T. —. 3-5 Tubing 3 1/2 2.992 34.2 [Set 2 16,109.41 9.30 L-80 TC II I 3-6 Tubin;_Components Item Top Depth No. Item Description Top(ftKB) (TVD)(ftKB) OD(in) ID(in) Comment f 1-2 Vetco Gray 3-1/2"Tbg 34.2 34.2 10 2.992 1-13 Hanger w.Acme B x TC-I1 13/16 Pin •---1 2-11 1-9 HES WellstarTRSSSV w/ 1,995.1 1,870.2 5.2 2.813 2.813 X Profile TC-I1 BxP J 1-13 Vanoil 3-1/2"x 1-1/2"GLM 3,555.5 2,967.4 5.45 2.992 " 0-1 3-13 1 TC-I1 BxP 11-171 1-17 Vanoil 3-1/2"x 1-1/2"GLM 9,199.4 5,424.0 5.45 2.992 TC-ll BxP 11-211 1-21 HES Roc Gauge&Carrier 9,284.5 5,458.8 5 2.992 TC-II BxP I-Wire to Surface 1-25 1-25 3 1/2"HES 2.813 X Nipple 9,333.0 5,478.3 3.95 2.813 0 1-30 WFT 7"UltraPak TH Hyd 9,412.7 5,511.7' 5.896 3.910 r Perm Pkr 4-1/2"NewVam 11-301 j PxP t 1-33 3 1/2"HES 2.813 X Nipple 9,433.4 5,519.6 3.95 2.813 11-331 1-37 3 1/2" HES 2.813 XN 9,506.8 5,550.1 3.98 2.750 I Nipple w/2.750 NoGo 11-371 i 1-40 3.5"TC-II Tubing Tail 11,205.9 6,109.0 3.9 2.992 HES 3-1/2"WLEG 1-40 .2 55-3 5-4 • • 14-81 15-81 15-11] i E 5-141 15-181 15-211 15-241 • * t 5-27 a MI 5 30 tot Mg I tar m * 3 5-37 1 j 5-41 15-441 1 -15-47! 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(Z Z Z Z Z N N N N N N N N N p O O x V'N(n N(T N(T N O(T o(T N o N =y 00000000000000 N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 c N N co co co N 0 0 N 0 N N N N Z Z Z Z Z Z Z Z Z Z Z Z Z Z m U CD U Cn(n N fT N U Cn N(n N U M S. 0 0 IN N Z p 3 s m m C a N C . m 0) W N _Q o g N E' •g cn K r 0 0 m (D c 0, .g 0 01 s 1,01, [E, [IF O SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMMISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 June 22, 2010 CERTIFIED MAIL RETURN RECEIPT REQUESTED 7009 2250 0004 3911 4214 Kenneth Sheffield, Jr. President Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, AK 99501 Re: Shut-in Order Oooguruk ODSK -35A (PTD 210-012) Oooguruk ODSN-15 (PTD 210-032) Dear Mr. Sheffield: The Alaska Oil and Gas Conservation Commission (Commission) has determined that two wells operated by Pioneer — ODSK-35A and ODSN-15 — are not in compliance with the Commission's regulations covering good oilfield engineering practice for production equipment. Pioneer is directed to immediately shut in both ODSK-35A and ODSN-15 immediately I/ pending replacement of the temporary pipe with an acceptable piping arrangement. The basis for this action is set forth below. Oooguruk injection well ODSK-35A has been producing (Pre-injection) through temporary chicksan pipe since early April 2010. During safety valve system inspections on May 12, 2010, a Commission Inspector observed the piping arrangement and instructed Pioneer field personnel to replace the chicksan pipe with a more permanent arrangement. A follow-up email to Pioneer on May 18, 2010 requested the timing for resolution of the temporary pipe at ODSK-35A. Pioneer did not comply. On May 27, Pioneer suggested a meeting to discuss the use of temporary pipe for pre-producing injection wells. However, no such meeting was scheduled. On June 9, the Commission again requested Pioneer provide a time frame for compliance and reiterated that the use of chicksan pipe for pre-producing an injection well was inconsistent with good oilfield practice. On June 16, 2010, the Commission again inquired about the status of Oooguruk ODSK-35A. When Mr. Pat Foley noted that the well was still producing and that Pioneer would continue pre- production of ODSK-35A for an additional 3 to 4 months, Mr. Foley was verbally instructed to s • Kenneth Sheffield,PNR June 22,2010 Page 2 of 2 shut the well in immediately. Pioneer did not comply. An email from Mr. David Hart on Friday, June 18, 2010 asserted that use of chicksan pipe for temporary pre-production is believed by Pioneer to abide by good oilfield practice. Oooguruk ODSN-15 was brought to the Commission's attention as another injection well that is pre-producing through temporary chicksan pipe, having been started May 25, 2010. The Commission recognizes there have been unexpected conflicts that have prevented direct communication between appropriate personnel of the Commission and Pioneer. However, for over a month, Pioneer has clearly and repeatedly been instructed to correct the problem or shut in well ODSK-35A. Pioneer's failure to resolve this matter constitutes serious non-compliance and must be resolved immediately. In accordance with your phone conversation with Commissioner Foerster earlier today, Pioneer is instructed to shut-in both wells immediately. Within 24 hours of receipt of this letter, please confirm that Oooguruk wells ODSK-35A and ODSN-15 were shut in today, June 22, 2010. The Commission expressly reserves the right to take any further actions it deems necessary. Sincerely, Daniel T. Seamount, Jr. Chair, Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a),within 20 days after written notice of the entry of this order or decision,or such further time as the Commission grants for good cause shown,a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed,then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration,upon denial,this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails,OR 30 days if the Commission otherwise distributes,the order or decision denying reconsideration,UNLESS the denial is by inaction,in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was tiled. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission,and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails,OR 30 days if the Commission otherwise distributes,the order or decision on reconsideration. As provided in AS 31.05.080(b),"Nile questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period;the last day of the period is included,unless it falls on a weekend or state holiday,in which event the period runs until 5:00 p.m.on the next day that does not fall on a weekend or state holiday. PIONEER , , 1 NATURAL RESOURCES ALASKA Letter of Transmittal y '` Date: June 8, 2010 FROM TO Shannon Koh AOGCC Pioneer Natural Resources Attn: Christine Mahnken 700 G Street, Suite 600 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 Anchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑ Maps ❑ Report X Other—logs, CD ❑ Agreement DETAIL QTY DESCRIPTION O D S N- `I 5I (API: 50-703-20618-0000) 1 CD-Rom ODSN-15i Well logs in CD-Rom 5 Well Logs 5 Well Logs Borehole Profile Log Measured Depth Log (1:600) Measured Depth Log (1:240) True Vertical Depth Log (1:600) True Vertical Depth Log (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 G 1 o-d30 i cY k(( 1 PIONEER ; C- I VEL± NATURAL RESOURCES ALASKA 4k1uJ.& j Letter of Transittal Date: June 1, 2010 FROM TO Shannon Koh AOGCC Pioneer Natural Resources Attn: Christine Mahnken 700 G Street, Suite 600 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 Anchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑ Maps X Report X Other- logs ❑ Agreement DETAIL QTY DESCRIPTION ODSN- 15i (API: 50-703-20618-0000) 1 Report ODSN-15i End of Well Report 4 Well Logs 4 Well Logs 2" MD Combination Mud Log 2" MD Engineering Log 2" MD Gas Ratio Log 5" MD Combination Mud Log We request that all data be treated as confidential information. Thank you. Received by: 0/ 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 aio-o3 1.9913 �at1e. vt 4pT - `Plea5e- (eda Page 1 of 4 Schwartz, Guy L (DOA) From: Franks, James[James.Franks @pxd.com] Sent: Wednesday, May 12, 2010 9:43 AM To: Schwartz, Guy L(DOA) Subject: RE: Magnetic ranging to ODSN-15i (PTD 210-032)while drilling surface of ODSN-16 (PTD 210- 053) Guy, Thanks for all your time and consideration. james James Franks Pioneer Natural Resources Alaska 907.343.2179 From: Schwartz, Guy L(DOA) [mailto:guy.schwartz @alaska.gov] Sent: Wednesday, May 12, 2010 9:39 AM To: Franks,James Subject: RE: Magnetic ranging to ODSN-15i (PTD 210-032)while drilling surface of ODSN-16 (PTD 210-053) James, You have approval to perform the operation as outlined without lubricator or BOP rams per 20 AAC 25.287 (f) Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Franks, James [mailto:James.Franks @pxd.com] Sent: Wednesday, May 12, 2010 9:25 AM To: Schwartz, Guy L (DOA) Subject: RE: Magnetic ranging to ODSN-15i (PTD 210-032) while drilling surface of ODSN-16 (PTD 210-053) Guy, We had not planned to run a junk catcher on top of the plug, but I will into the possibility. Might I assume that we have approval for the exemption from 20AAC25.587(b)(1)and (2)? james James Franks Pioneer Natural Resources Alaska 907.343.2179 From: Schwartz, Guy L(DOA) [mailto:guy.schwartz @alaska.gov] Sent: Wednesday, May 12, 2010 8:44 AM To: Franks, James Subject: RE: Magnetic ranging to ODSN-15i (PTD 210-032) while drilling surface of ODSN-16 (PTD 210-053) 5/12/2010 Page 2 of 4 OK... thought I would check. I assume you are putting a junk catcher on top of the plug to protect it from tools falling or debris? Other than that , I don't see a problem with the operation as outlined. With a tested PX plug, Kill weight fluid , and the SSSV as a backup valve ( making the tubing the lubricator) you should be fine. Thanks, Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Franks, James [mailto:James.Franks @pxd.com] Sent: Wednesday, May 12, 2010 8:29 AM To: Schwartz, Guy L (DOA) Subject: RE: Magnetic ranging to ODSN-15i (PTD 210-032)while drilling surface of ODSN-16 (PTD 210-053) Guy, Unfortunately we do not have the space for the rams. Our barriers are the kill weight fluid in the well and the PXX plug. Additionally, we will have the ScSSSV as an additional barrier, but we are not counting it as a barrier for this operation. james James Franks Pioneer Natural Resources Alaska 907.343.2179 From: Schwartz, Guy L(DOA) [mailto:guy.schwartz @alaska.gov] Sent: Wednesday, May 12, 2010 8:23 AM To: Franks,James Subject: RE: Magnetic ranging to ODSN-15i (PTD 210-032)while drilling surface of ODSN-16 (PTD 210-053) James, One more question... is It possible to add one set of WL BOP rams? Just in case we had something happen and the packoff failed. This should only add about 3 feet of length or so. Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Franks, James [mailto:James.Franks @pxd.com] Sent: Tuesday, May 11, 2010 2:44 PM To: Schwartz, Guy L (DOA) Cc: Johnson, Vern Subject: RE: Magnetic ranging to ODSN-15i (PTD 210-032)while drilling surface of ODSN-16 (PTD 210-053) Guy, 5/12/2010 Page 3 of 4 No problem getting a pump-in sub below the packoff. I have attached a picture. Please let me know what you need to see to be able to get a waiver finalized. Take care, james James Franks Pioneer Natural Resources Alaska 907.343.2179 From: Franks, James Sent: Tuesday, May 11, 2010 9:52 AM To: 'Schwartz, Guy L(DOA)' Subject: RE: Magnetic ranging to ODSN-15i (PTD 210-032) while drilling surface of ODSN-16 (PTD 210-053) Yup. Talking about a PXX plug in the ScSSSV profile. We have looked at a cost analysis and it is actually less expensive to lower the freeze point of the completion brine instead of putting diesel in the well. As such, we will have kill weight fluid and the plug in the tubing and on the backside. Once the plug is set, we can pressure test the plug from above for the positive test and then open up at the surface to check for flow as a negative test. I'm heading to a meeting. I'll give you a shout later this afternoon. james James Franks Pioneer Natural Resources Alaska 907.343.2179 From: Schwartz, Guy L (DOA) [mailto:guy.schwartz @alaska.gov] Sent: Tuesday, May 11, 2010 8:37 AM To: Franks, James Subject: RE: Magnetic ranging to ODSN-15i (PTD 210-032) while drilling surface of ODSN-16 (PTD 210-053) James, I assume you are talking about a positive sealing plug and not a RHC body with ball/rod? As long as the plug is pressure tested (drawndown and positive pressure) I think the plan as proposed would be safe. Give me a call later today to discuss the details Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Franks, James [mailto:James.Franks @pxd.com] Sent: Monday, May 10, 2010 10:01 AM To: Schwartz, Guy L (DOA) Cc: Johnson, Vern; Vaughan, Alex; Delmonico, Joe; Crumrine,Tim Subject: Magnetic ranging to ODSN-15i (PTD 210-032) while drilling surface of ODSN-16 (PTD 210-053) Guy, 5/12/2010 Page 4 of 4 While drilling the surface hole of ODSN-16,we would like to magnetically range to ODSN-15i. We propose that when we run the completion on ODSN-15i, we leave a plug in the completion string in the X profile of the ScSSSV so we can run the MGT coil in that well without using a lubricator(as this is not possible due to the rig covering the well) but with a packoff. I have attached a drawing illustrating the planned secured condition of the ODSN-15i well. Based on the setting of the downhole plug,we are requesting an exemption from 20AAC25.587(b)(1)and (2) requiring wireline operations to have wireline BOP's and a lubricator or pressure deployment system installed on ODSN-15i while running the MGT coil. Once we are done drilling and casing the surface hole of ODSN-16,we will move off the well and perform rig maintenance,during which time,we will place the ODSN-15i on pre-production. The temporary stoppage of operations on ODSN-16 will be addressed in another e-mail and with a 10-403, as the permit to drill was not approved with this pause in drilling operations. Call me if there are any questions or concerns. Thanks! james James Franks Pioneer Natural Resources Alaska 907.343.2179 Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. 5/12/2010 Page 1 of 1 Regg, James B (DOA) From: Vaughan, Alex [AIex.Vaughan @pxd.com] 47i CJ Z 0 03z,- Sent: Monday, May 03, 2010 10:29 PM To: DOA AOGCC Prudhoe Bay Cc: OoogurukDrillingSupervisor Subject: Synopsis of events concerning the shut in of the annular preventer on PXD ODSN-15i John Crisp, The following is a synopsis of events concerning the shut in of the annular preventer on ODSN-15i on the evening of May 3rd,2010. The intermediate section of ODSN-15i was drilled with a 10.0 ppg mud with an ECD of 13.0 ppg applied via MPD. 2,700 bbls was lost to the hole in the last three days. Prior to pulling out of hole with 5" DP the mud was displaced to 12.8 ppg mud to maintain hole stability. 7" casing was run in hole to casing point and mud was displaced from 12.8 ppg to 11.0 ppg. During the circulation of a hole conditioning sweep pumps were shut down. It was observed the hole continued to flow. The annular preventer was shut in to monitor pressures. 7"x 11-3/4" annulus pressure elevated and stabilized at 150 psi.The stand pipe pressure elevated and stabilized at 100 psi. Annular choke was opened for 30 min to bleed and monitor pressures with 3 bbl flowing back. Standpipe was bled off. The well was then shut in a second time to monitor pressures. 7"x 11-3/4" annulus pressure elevated and stabilized at 130 psi.The stand pipe pressure elevated and stabilized at 15 psi. Annular choke was opened for 15 min to bleed and monitor pressures with 3 bbl flowing back. Standpipe was bled off. The well was then shut in a third time to monitor pressures. 7" x 11-3/4" annulus pressure elevated and stabilized at 130 psi.The stand pipe pressure elevated and stabilized at 15 psi. Annular choke was opened for 15 min to bleed and monitor pressures with 2 bbl flowing back. We suspect the well is ballooning and therefore flowing back mud lost while drilling the intermediate hole at an EMW of 12.8 ppg when we displaced to a 11.0 ppg mud. As such we opened the annular preventer and commenced operations. We subsequently contacted John Crisp with the AOGCC to update him on events. Please contact myself or Rodney Klepzig at 670-6606 if further information is required. Alex Vaughan Operations Drilling Engineer PIONEER NATURAL RESOURCES 907.226.2180 (Cosmo Rig) 907.343.2186 (office) 907.748.5478 (mobile) 907.343.2190 (fax) 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. 5/4/2010 HALLI BU RT N .lv -05 z-_ Laboratory Report Prudhoe Bay,Alaska To: Pioneer Report No: 015-2010 Date: 04/28/2010 Submitted by: Halliburton Energy Services Rig: Nabors 19AC Field: Oooguruk Island Well: ODSN-15i Borough: North Slope Job Type: Intermediate Casing / State: Alaska Csg Size: 7 " Hole Size: 8 1/2 " MD: 11,065' BHST: 165°F TVD: 6,109' BHCT: 135°F Purpose: Field Blend Test Comments: Cement from Tank#14 with 0.25#/sk of Super CBL was used for testing for the Tail Slurry. 0.40% SCR- 100 was added to achieve the desired pump time.0.20% Halad-344 was added to meet the required Fluid Loss. Cement from Tank#10 with 0.5% SCR-100 was used for testing the Lead Slurry. Conoco Phillips water with a SG of 1.030 was used for both Tail and Lead. Report prepared by: Lorie Talbott&Raphael Dreier This report was prepared by and is the property of Halliburton Services,a Division of Halliburton Company. The data reported,is intended for the private use of the above named party,is limited to the sample or samples described; accordingly,any user of this report agrees that Halliburton shall not be liable for any loss or damage,regardless of cause,including any act or omission of Halliburton,resulting from the use of the data reported herein;and Halliburton makes no warranties,express or implied,whether of fitness for a particular purpose,merchantability or otherwise,as to the accuracy of the data reported. This report is the property of Halliburton Services and neither it nor any part thereof nor a copy thereof is to be published or disclosed without first securing the express written approval of laboratory management;it may,however, be used in the course of regular business operation by any person or concern and employee thereof receiving such report from Halliburton Services. Cement test accuracy data indicate that an average range of confidence for cement testing is+/-20 depending on specific well conditions. Although standard API cement testing procedures are followed as closely as possible, deviations from these procedures are made as dictated by specific well parameters. Slurry: Tail Slurry Parameters Water Requirement: 5.13 gal/sk Water Type: CP Water Slurry Volume: 1.18 cu ft/sk Specific Gravity: 1.030 Slurry Density: 15.8 lbs/gal Slurry Composition and Weights Additives % • Water Sample ID#014-10 5.15 GPS Premium Cement 94.0 lbs/sk Halad-344 0.50% CFR-3 0.20% Super CBL 0.25% SCR-100 0.40% Halad-344 0.20% SLURRY DATA Slurry Thickening Time (Hrs:min) Fluid Loss(cc) #1 4:05 76API RHEOLOGIES Slurry 300 200 100 6 3 #1 230 178 115 20 12 COMPRESSIVE STRENGTH Time Temp UCA(PSI) 12 hr 165 558 24 hr 165 1979 sTt HALLIBURTON ISO 14001 HAL.LIBURT(SN Slurry: Lead Slurry Parameters Water Requirement: 13.83 gallsk Water Type: CP Water Slurry Volume:2.45 cu ft/sk Specific Gravity: 1.030 Slurry Density: 12.5 lbs/gal Slurry Composition and Weights Additives Water Sample ID#014-10 13.83 GPS Premium Cement 94.00 lbs/sk Microlite 15.00 lbs/sk Halad-344 0.75 % CFR-3 0.20 % EZ-FLO 0.15 lbs/sk SCR-100 0.50 % SLURRY DATA Slurry Thickening Time (Hrs:min) Fluid Loss(cc) Lead 4:27 94 API RHEOLOGIES Slurry 300 200 100 6 3 Lead 25 19 12 2 1 COMPRESSIVE STRENGTH Time Temp UCA(PSI) 12 hr 165 842 24 hr 165 1155 • 1 1 8 ! ! ! ! : ! 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CO 10 ii■ _ 8 I g 0,-, o o ..i. •-■ con I-1 .4 i. fo E i u 8vI \\784? 8 z rtj E , e 0 z !" a; L r,'j 67'7- 0 Q) 2 i 1 C) , .tai 111.. -kw a I— W F r 73 3 [ IX L.. 8 1 ' a I ,.. 6 , 3 -- . fill g 5 ‘ A 6 ....1 CL ....- W E -o , . . . ; , . . " . " . . . " . " . . . " . . " . „ . . . , . . . i . "-; .. .5 ,,, .., .- E , rl II 1.1 90 1.1 :41 0 ^I Ch CO I, CI 1 LA .. 2' "' (j,,)atmeaadwai Lunis l, c. 4, 0 , i i st i II i i i4 i II i i . o 14 a i ('S441uaaS gthissaiu03 ,o• 6 1— 13 6 *6 ›..'' t t 1 O ir) 6 6 ,il, ;. ik I 6'It, 6 - z e.1 N N r 0 1 E 7,, I (sd)atuu*supai A i ODSN-15i Injection Well Well Head: 11-3/4", 5K,VetcoGray Tree: 3-1/2", 5K, Horizontal �'� 16"Conductor A,44 ` 158'MDrkb/158'TVDrkb NO. 'f 1, 11 11-3/4",60#L-80 Hyd 521, 10.772"ID 3,589'MD/2,982'TVD Estimated Top of Cement (66 bbls 15.8 ppg cement) @7516'MD 9-5/8",40#L-80 Hydril 521,8.835"ID 8,870'MD/5,288'TVD — Estimated Top of Lead Cement (43 bbls 12.5 ppg cement) @ 8746'MD @ 9787'MD,w/o 40%excess Estimated Top of Tail Cement (19 bbls 15.8 ppg cement) @ 10650'MD @ 10929'MD,w/o 40%excess . 9-5/8",40#L-80 Hydril 521,8.835"ID 11,348'MD/6,155'TVD 4-1/2", 12.6#L-80 Hydril 521 Liner ODSN-15i TD: 17,140'MD Date: Revision By: Comments PIONEER NATURAL RESOURCESUSKA ODSN-15i Injector sRic r -1 -n05n -i mW �-n ° cn 0 rAcn ° r Borough: NORTH SLOPE 3 cQ 'x o a v m a o ° ' ° D w. 3 -0 0 c°o Field: 000GURUK o " c° 3 a cfl 5- 3 (n --I a 0 7 5.. E 3 ' O O Q o O 3 ° m D `< ''`< T cQ 0 F cQ Location: X=469,835.96;Y=6,031,066 p Q CD 3 0- O c Cn m C o m - 0- ° c . . -o co m W 7 7 z a m c° m m m m Well: ODSN-15 (p CD 0 o co G) --I z 5.- ° N c m v CD 0 Company: PIONEER NATURAL RESOUR• 3 �G a CD W °-' s LOCATION — -I z co 0 ° r X n Z Q Q r o cn o m ✓ 1:3 - `° n Ii W m � Q �_ C Q 173 p Z 0• � 0 00 Z c D m W , . 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CONVEYED ON DRILL PIPE BY NABORS 19AC 2. 3. 4. 5. 6. DISCLAIMER THE USE OF AND RELIANCE UPON THIS RECORDED-DATA BY THE HEREIN NAMED COMPANY(AND ANY OF ITS AFFILIATES, PARTNERS, REPRESENTATIVES,AGENTS,CONSULTANTS AND EMPLOYEES)IS SUBJECT TO THE TERMS AND CONDITIONS AGREED UPON BETWEEN SCHLUMBERGER AND THE COMPANY, INCLUDING:(a)RESTRICTIONS ON USE OF THE RECORDED-DATA; (b)DISCLAIMERS AND WAIVERS OF WARRANTIES AND REPRESENTATIONS REGARDING COMPANY'S USE OF AND RELIANCE UPON THE RECORDED-DATA;AND(c)CUSTOMER'S FULL AND SOLE RESPONSIBILITY FOR ANY INFERENCE DRAWN OR DECISION MADE IN CONNECTION WITH THE USE OF THIS RECORDED-DATA. OTHER SERVICES1 OTHER SERVICES2 OS1: NONE OS1: 0S2: OS2: DS3: OS3: 0S4: OS4: OS5: OS5: REMARKS: RUN NUMBER 1 REMARKS: RUN NUMBER 2 SEE MEMORY REMARKS SECTION RUN 1 RUN 2 SERVICE ORDER#: AWYZ-00019 SERVICE ORDER#: PROGRAM VERSION: 17C0-154 PROGRAM VERSION: FLUID LEVEL: FLUID LEVEL: LOGGED INTERVAL START STOP LOGGED INTERVAL START STOP EQUIPMENT DESCRIPTION RUN 1 RUN 2 SURFACE EQUIPMENT DOWNHOLE EQUIPMENT kH-3/4" SR KNUCKLE 31.7 \H-3/4"SR KNUCKLE 'SRP-NB - 28.7 'RMC32 933 'SRP-A 'BMS-A 3814 Ok Sapphire_Mano tT6 Thermometer 3R - 'BMS GR _ 25.0 Well Temp 21.9 Manometer - 21.8 CCL 21.2 PBMS _ 20.5 3CMT-CB 20.5 >CMC-CA 8126 >ECH-CA ;CMS-CB 8156 >CMX-CA 8125 .H-278 TG-C DT = 14.9 CBL5 DTSC 13.4 • • AUX I .9 I Tension SCM 1 1 0 TOOL ZERO MAXIMUM STRING DIAMETER 1.75 IN MEASUREMENTS RELATIVE TO TOOL ZERO ALL LENGTHS IN FEET Schlumberger MEMORY SCMT REMARKS SECTION MAXIS Field Log Schlumberger Memory Cement Bond Log 1 . General Information A. AFE : 18277 B . SO # : AWYZ-00019 C . Treatment # : D . Date : 16-MAY-2010 2 . Test Objective A. The objective of this log is to evaluate the primary cement job in 7" liner . Company: Schlu arger Title : VISION Services* Dated: 13-May-10 Log Tied in at : 10384 ' 4 . Well Fluid A. Log interval fluid Packed with 10 . 1 ppg brine . 5 . Logging Program Start Stop Comments 11068 . 0 @ 07 : 37 : 12 10188 . 5 @ 08 : 43 : 20 30 fpm up 11114 . 2 @ 09 : 30 : 00 10191 . 7 @ 10 : 28 : 00 30 fpm up 6 . Expected CBL in 7" Casing Free Pipe : 63 mV 80% Bond: 5 . 75 mV 7 . Expected Transit Times TT1 5' VDL: 404 us TT2 3 ' CBL : 292 us 8 . Notes A. All depths listed in remarks section are Coil Tubing Measured Depth (CT-MD) . B . Bottom not tagged during logging run. C . Field interpretation of top of good bond to casing is 10640' ft . • Schlumberger MEMORY SCMT MAIN PASS 30 FPM UP MAXIS Field Log 3mpany: PIONEER NATURAL RESOURCES ALASKA Well: ODSN-15 Input DLIS Files )EFAULT SCMT_PSP_042PUP FN:59 PRODUCER 17-May-2010 07:52 11114.2 FT 10166.7 FT Output DLIS Files )EFAULT SCMT_PSP_043PUP FN:61 PRODUCER 17-May-2010 07:57 11186.0 FT 10238.5 FT :USTOMER_DLIS SCMT_PSP_043PUC FN:62 CUSTOMER 17-May-2010 07:57 11186.0 FT 10238.5 FT OP System Version: 17C0-154 CMT-CB 17C0-154 PSRP-A/B 17C0-154 PIP SUMMARY Time Mark Every 60 S Transit Time(TT) Good Bond (GOBO) 0 (US) 260 0 (MV) 10 Gamma Ray(GR) Fluid Compensated CBL Amplitude (GAPI) 10(' (CBLF) 0 (MV) 100 Discriminated CCL (CCLD) Amplified CBL Amplitude(Fluid (V) _1 Compensated SCBLF) 0 (MV) 10 Min Amplitude Max Cable Speed (CS) GOBO............ ::•: MI• M, ............. :..:.:.::.:.:.::.:.:. 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P,�` t•I _ t 1' t r,. trim 1 `1 I� �• , i t__1 illE -.- _ i { tA� ■ % ` team 4 ►. 10600 a7_ _@� �........, 11 ...... ‘ ,....... ..„ . , , ,piii.,,,, _ ,!_ _ # - P=RUM Nig 1 __t_ r lo ......., ...n.. .. mum. = 1 _, r: I i ; e -- -� . 111 il 1- :15 ill :, IIP �� I IM - jj wTOP OF GOOD CEMENT �C��� r f.F r ViM�1 III b. -.2 i o I___ v _ 1_____,,P L.,.... .1. . _I_�____ s _ : c ■ tt_►�tt__ __� I ��� �� - F11-117114 e r _tl1_t____ 1 c t•�_____ T 1. i , i v �__ L� � `_____ AllallaCreeNIU _II_■___ IIIM■Mll M. 1110 I Z L�=� ►7_ 4� .1— i ii 1 . 1■11=1•1•11MM Mil we I2 a____ttl,� ag m-^'Fag 1 10700 __ IIMIIIIIMMEINE , 1 111_tt_� t<�__ II , , Lo t<a____aa - ' ttt•—tt_____ t�t�l rl tall -1.-1. .1.,..-1.1.,'''; .... • . VII b P• 1 4 s, ; 11 1 I . Mag,..71 IP 111111 - - EME l ..,:% -.1•:. 0 110 0, i ■...0 1 , p MMIIIIP■ I III 1 . I V 1 h j . 1.■ I 1 , I li 1 II .. 11111 1 I AI • ..._ =1.■ nos-•..,..7--------- •.- 1 '--- . e.......? 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'00 (F/MN) 200 From ACBLF to GOBO :::::::::::: VDL Variable Density (VDL) 200 (US) 1200 Discriminated CCL (CCLD) Amplified CBL Amplitude (Fluid (V) _1 Compensatedt SCBLF) 0 (MV) 10 Gamma Ray(GR) Fluid Compensated CBL Amplitude (CBLF) (GAPI) 100 0 (MV) 100 Transit Time (TT) Good Bond (GOBO) 0 (US) 260 0 (MV) 10 PIP SUMMARY 'Time Mark Every 60 S )rmat: CBL_VDL Vertical Scale: 5" per 100' Graphics File Created: 17-May-2010 07:57 OP System Version: 17C0-154 CMT-CB 17C0-154 PSRP-A/B 17C0-154 <<<SCMT Cement Evaluation Information Summary>>> Sonde Serial Number SCMS-CB 8156 Current Casing Size 7.0 IN Casing Weight 26.0 LB/F Expected CBL Amplitude 62 MV Minimum Sonic Amplitude 1.99346 MV(100% Cement) in Free Pipe Section 3.96428 MV(80% Cement) MAP Minimum Sonic Amplitude 11.5946 MV(100% Cement) 17.8404 MV(80% Cement) Master Calibration (Normalization) Before Calibration (Adjustment) Date of Master Calibration 20-MAY-2009 CBL Correction Factor 0.0684425 CBL Adjustment Factor(CBAF) 1.0 MAP 1 Correction Factor 0.0840018 MAP Adjustment Factor(MPAF) 1.0 MAP 2 Correction Factor 0.100561 MAP 3 Correction Factor 0.0902777 MAP 4 Correction Factor 0.0931073 MAP 5 Correction Factor 0.0970001 MAP 6 Correction Factor 0.104581 MAP 7 Correction Factor 0.0901942 MAP 8 Correction Factor 0.0751099 Parameters DLIS Name Description Value SCMT-CB: Slim Cement Mapping Tool, 1-11/16 OD CB3D SCMT CBL 3 ft Peak Detection Mode PEAK CB3G SCMT CBL 3 ft Peak Detection TO_Delay and Noise Gate 249.726 US CB3T SCMT CBL 3 ft Fixed Threshold Level 20 MV CB5D SCMT CBL 5 ft Peak Detection Mode PEAK CB5G SCMT CBL 5 ft Peak Detection TO_Delay and Noise Gate 363.726 US CR5T SCMT CRI 5 ft rived Threchnlrl I aveI 7n MV CMTM SCMT Operating Mode LOG CSCS. SCMT Slow nnel Index VCC CTHI Casing Thic is 0.366591 IN DTF Delta-T Fluid 169 US/F FATT Acoustic Attenuation due to Fluid 0 DB/F FCF CBL Fluid Compensation Factor 0.687361 GOBO Good Bond 6.68 MV MAPD SCMT MAP Peak Detection Mode PEAK MAPG SCMT MAP Peak Detection TO Delay and Noise Gate 192.726 US MAPT SCMT MAP Fixed Threshold Level 30 MV MATT Maximum Attenuation 8.19161 DB/F VDLG VDL Manual Gain 5 ZCMT Acoustic Impedance of Cement 4.3 MRAY PSRP-A/B: Production Services Recorder Platform Description of this pass System and Miscellaneous CSIZ Current Casing Size 7.000 IN CWEI Casing Weight 26.00 LB/F DFD Drilling Fluid Density 10.10 LB/G DO Depth Offset for Playback 72.0 FT PP Playback Processing NORMAL TD Total Depth -50000 FT Input DLIS Files )EFAULT SCMT_PSP_042PUP FN:59 PRODUCER 17-May-2010 07:52 11114.2 FT 10166.7 FT Output DLIS Files )EFAULT SCMT_PSP_043PUP FN:61 PRODUCER 17-May-2010 07:57 :USTOMER_DLIS SCMT_PSP_043PUC FN:62 CUSTOMER 17-May-2010 07:57 Schlumberger MEMORY SCMT REPEAT PASS 30 FPM UP MAXIS Field Log )mpany: PIONEER NATURAL RESOURCES ALASKA Well: ODSN-15 Input DLIS Files )EFAULT SCMT_PSP_032PUP FN:49 PRODUCER 17-May-2010 06:36 11068.0 FT 10163.5 FT Output DLIS Files )EFAULT SCMT_PSP_037PUP FN:54 PRODUCER 17-May-2010 07:21 11134.5 FT 10230.0 FT OP System Version: 17C0-154 CMT-CB 17C0-154 PSRP-A/B 17C0-154 PIP SUMMARY 'Time Mark Every 60 S Transit Time(TT) Good Bond (GOBO) 0 (US) 260 0 (MV) 10 Gamma Ray(GR) Fluid Compensated CBL Amplitude (GAPI) 100 (CBLF) 0 (MV) 100 Discriminated CCL (CCLD) Amplified CBL Amplitude(Fluid n Amplitude Max Cable Speed (CS) ::: ::::' GOBO ■■ I�diliVll9� ....... ..... 200 From ACBLF to GOBO :•:•:•:•:•:•:•:•:::: VOL VariableDensity(VDL) 200 (US) 1200 !!I l MMI II Last Real �2 ih0, .$ �►� 1111 II � .a'. r�Iz --� �-� . , ■r „ =, . ......... 1 .i. , , Imo ,..: . -...............t ___ - I� , ,, i , ,.- .L. 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From.ACBLF.to,GOBO,:::::::.:::.:.:.:::::.::: VDL VariableDensity(VDL) :.:.:.:.:.:.:.:.:.:.:.:.:.:200 (US) 1200 Discriminated CCL(CCLD) Amplified CBL Amplitude(Fluid (V) _1 CompensatedlfCBLF) 0 (MV) 10 Gamma Ray (GR) Fluid Compensated CBL Amplitude (GAPI) 100 (CBLF) 0 (MV) 100 Transit Time (TT) Good Bond (GOBO) 0 (US) 260 0 (MV) 10 PIP SUMMARY ,Time Mark Every 60 S )rmat: CBL_VDL Vertical Scale: 5" per 100' Graphics File Created: 17-May-2010 07:21 OP System Version: 17C0-154 CMT-CB 17C0-154 PSRP-A/B 17C0-154 <<<SCMT Cement Evaluation Information Summary>>> Sonde Serial Number SCMS-CB 8156 Current Casing Size 7.0 IN Casing Weight 26.0 LB/F Expected CBL Amplitude 62 MV Minimum Sonic Amplitude 1.99346 MV(100% Cement) in Free Pipe Section 3.96428 MV(80%Cement) MAP Minimum Sonic Amplitude 11.5946 MV(100% Cement) 17.8404 MV(80% Cement) Master Calibration (Normalization) Before Calibration (Adjustment) Date of Master Calibration 20-MAY-2009 CBL Correction Factor 0.0684425 CBL Adjustment Factor(CBAF) 1.0 MAP 1 Correction Factor 0.0840018 MAP Adjustment Factor(MPAF) 1.0 MAP 2 Correction Factor 0.100561 MAP 3 Correction Factor 0.0902777 MAP 4 Correction Factor 0.0931073 MAP 5 Correction Factor 0.0970001 MAP 6 Correction Factor 0.104581 MAP 7 Correction Factor 0.0901942 MAP 8 Correction Factor 0.0751099 Parameters SCMT-CB: Slim Cement Mapping Tool, 1-11/16 OD CB3D SCMT CBL 3 eak Detection Mode PEAK CB3G SCMT CBL 3 eak Detection TO_Delay and Noise Gate 249.726 US CB3T SCMT CBL 3 ft Fixed Threshold Level 20 MV CB5D SCMT CBL 5 ft Peak Detection Mode PEAK CB5G SCMT CBL 5 ft Peak Detection TO_Delay and Noise Gate 363.726 US CB5T SCMT CBL 5 ft Fixed Threshold Level 20 MV CBLG CBL Gate Width 40 US CMTC SCMT Slow Channel Multiplexer Mode SCAN CMTM SCMT Operating Mode LOG CSCS SCMT Slow Channel Index VCC CTHI Casing Thickness 0.366591 IN DTF Delta-T Fluid 169 US/F FATT Acoustic Attenuation due to Fluid 0 DB/F FCF CBL Fluid Compensation Factor 0.69 GOBO Good Bond 6.68 MV MAPD SCMT MAP Peak Detection Mode PEAK MAPG SCMT MAP Peak Detection TO_Delay and Noise Gate 192.726 US MAPT SCMT MAP Fixed Threshold Level 30 MV MATT Maximum Attenuation 8.19161 DB/F VDLG VDL Manual Gain 5 ZCMT Acoustic Impedance of Cement 4.3 MRAY PSRP-A/B: Production Services Recorder Platform Description of this pass System and Miscellaneous CSIZ Current Casing Size 7.000 IN CWEI Casing Weight 26.00 LB/F DFD Drilling Fluid Density 10.10 LB/G DO Depth Offset for Playback 66.5 FT PP Playback Processing NORMAL TD Total Depth -50000 FT Input DLIS Files )EFAULT SCMT_PSP_032PUP FN:49 PRODUCER 17-May-2010 06:36 11068.0 FT 10163.5 FT Output DLIS Files )EFAULT SCMT_PSP_037PUP FN:54 PRODUCER 17-May-2010 07:21 Company: PIONEER NATURAL RESOURCES ALASKA Schlumberger Well: ODSN-15 Field: 000GURUK Borough: NORTH SLOPE State: ALASKA MEMORY SCMT CBL/VDL/GR/CCL 16-MAY-201C PIONEER Operations Summary Report 2/0 -03� NATURAL RESOURCES Well Name: ODSN-15i Contractor: NABORS DRILLING Rig Number: 19 AC Job Category: DEVELOPMENT DRILL Spud Date: 4/9/2010 Rig Release Date: Last Mud Dens End Date Depth Start(ftKB) Foot/Meters(ft) (Ib/gal) Summary 4/7/2010 0.0 Move rig off ODSN-31.LD 4"DP from derrick.Prep rig for move from South side of Wellbays to North side. Move rig East to end of Wellbays. **Rig accepted on ODSN-15i at 00:01 on 04/06/10.** 4/8/2010 0.0 Skid rig to the end of the well row and fuel rig.Remove kill line and choke line valves,ND and remove NT-2 quick connect and RCD head. LD T3 BOP stack.Assemble Hydril BOP stack,including annular, double ram,mud cross,single ram and hoist same into cellar.NU NT-2 quick connect and rack back BOP stack on stump.Take on neccessary fuel and water for rig move.Skid rig around east end of the well row in route to ODSN-15i. 4/9/2010 0.0 Skid rig around east end of the well row from ODSN-31 in route to ODSN-15i.Connect electrical lines and communication lines from rig pits to rig floor. Move rig onto ODSN-15i, level and shim same. Align service module with substructure,level and shim same. Install and NU starting head. 4/10/2010 60.0 50.00 9.00 Finish rigging up HUTZ/PUTZ,all stairs,landings. NU drilling riser.Change out lower IBOP on top drive from XT-39 to 4-1/2 I.F.Spot SLB MWD unit and RU same.Slip and cut drill line.RU SLB MWD/LWD pressure transducer on stand pipe. PU and MU 27 stands of drill pipe in mouse hole and rack back same in derrick. Establish northern bearing for gyro surveys.PU and MU 5 stands of drill pipe in mouse hole and rack back same in derrick. PU and MU 6 stands of HWDP with jars in mouse hole and rack back same in derrick.MU 1 stand of 8"drill collars with 1 stab and rack back same in derrick. Hold prespud meeting with all involved personnel.Calibrate drawworks for MWD/LWD depth tracking.Hang shieve and RU wireline unit for gyro surveys.PU bit,motor, 14.5"non mag stab,pony collar and MWD. Tag ice plug at 60'.Wash and ream out conductor f/60't/110'. 4/11/2010 153.0 894.00 9.20 Wash and ream out conductor f/110't/153'. MU MWD and orient same. Drilling,sliding and surveying f/153't/269'.POOH f/269't/100'. RIH with 1 stand 8"DC and 1 stand HWDP to 269'. Drilling,sliding and surveying f/269't/366'.Take gyro, MWD and MGT surveys at 304',and send results into Sperry ROC for anti-collision with ODSK-14.Drilling,sliding,and surveying f/366't/457'.Take gyro, MWD and MGT surveys at 394'and send results into Sperry ROC for anti-collision with ODSK-14. Drilling,sliding and surveying f/457't/1,047'.POOH f/1,047't/275' 4/12/2010 1,047.0 634.00 9.30 Continue to POOH f/275'to surface.Adjust motor bend from 1.83 to 2.12 degree bend,and rearrange BHA. PU new MWD and lead collar,orient same.TIH f/175't/1,015'.Troubleshoot MWD.Wash and ream f/1,015't/1,047'--no fill. Drilling,sliding and surveying f/1,047't/1,681'. POOH f/1,681'to surface, and adjust motor bend from 2.12 to 1.83 degrees.Orient MWD and TIH from surface t/175'. 4/13/2010 1,681.0 -349.00 9.10 TIH f/175't/1,648'--tagged tight spot.Wash and ream f/1,648't/1,681'.Drilling,sliding,and surveying f/1,681't12,823'.Discovered leak in the adapter for MWD transducer on stand pipe. Disconnect kelly hose and replace hammer union gasket. Drilling,sliding,and surveying f/2,823't13,013'. 4/14/2010 3,013.0 583.00 9.50 Drilling,sliding,and surveying f/3,013't/3,596'. Pump hi-vis,weighted sweep and circulate hole clean with same. POOH f/3,596't/175'.TIH f/175't/3,596'.Pump hi-vis,weighted sweep and circulate hole clean with same.POOH f/3,596'to surface racking back HWDP and laying down remainder of BHA. 4/15/2010 3,596.0 0.00 9.50 LD remainder of BHA. RU 11-3/4"casing equipment. MU float equipment and circ thru same, RIH w/ 11-3/4"60#L-80 Hydril 521 Csg t/3,545'. MU landing joint and hanger, land casing at 3,589'. RD fill up tool and RU cement head and lines. Fill Pipe,Break circulation with 1/2 bpm, Increase pump rate in 1/2 bpm increments to 5 bpm and 1 bpm increments until 10 bpm established w/o losses.Pump 20 bbls seawater.Test cement lines to 4000 psi.Pump 60 bbls 10.0 ppg Dual Spacer. Released 2nd Bottom Plug. Pump 403 bbls(545 sx)10.7 ppg Lead PF'L'cement followed by 55.4 bbls(261 sx)15.9 ppg Tail Class'G'cement.Pump 1 bbl seawater, Drop Top Cement Plug,pump 20 bbls seawater.Switched to rig and displaced cement w/384 bbls mud at 8.5 bpm w/ICP of 1700 psi, FCP 2200 psi,bump plug w/ 3500 psi,held pressure 30 min on chart--Good test.CIP @ 21:51 hrs. 107 bbls cement returns to surface,bled off pressure and floats held--3.6 bbls bled back.RD cement head and lines.LD landing joint. Flush flow line and riser with citric acid water while preparing for ND. Page 1/5 Report Printed: 5/17/2010 PIONEER Operations Summary Report NATURAL RESOURCES Last Mud Dens End Date Depth Start(ftKB) Foot/Meters(ft) (Ib/gal) Summary 4/16/2010 3,596.0 0.00 9.40 RD 11-3/4"casing tools.ND drilling riser and starting head. Install 5M drilling spool and test same to 5000 psi held 10 min--Good test, NU BOPE. Function test BOPE. Install 5"pipe rams in lower rams and 2-7/8"x 5"VBR's in upper rams. RU test equipment,fill stack with water,close annular preventer and perform body test on BOPE due to the fact that this stack was disassembled for inspection--found one flange loose and tightened same. Break in upper VBR's as per manufacturer recommendation. ,Test Annular to 250 psi low/2500 psi high with 5"DP.Test Upper 2-7/8"x 5"VBR's, Lower 5"Single Bore Rams,Blind Rams,Choke and Kill Line HCR's,Choke and Kill Line Manual valves, Floor Safety valve, Dart valve, Upper IBOP, 14 Choke Manifold valves to 250 psi low/4500 psi high. All low and high tests held 5 min ea.All tests charted.Accumulator test,System Pressure 3000 psi,After Closer 2100 psi, Initial 200 psi recovery 17 sec's, Full recovery 1 min 30 sec's.RD test equipment.AOGCC representative Chuck Sheave waived witness of test at 18:00 hrs on 04/14/10.Clean and clear rig floor while preparing to PU 5"DP from pipe shed.TIH picking up 5"DP singles from pipe shed from surface t/578'. 4/17/2010 3,511.0 85.00 9.20 TIH picking up 5"DP singles from pipe shed f/578't/2,862'.Circulate 1.25x drill pipe capacity to ensure pipe has no obstructions.POOH racking back clean DP in derrick f/2,862'to surface.PU clean out BHA #4.TIH f/109't/3,440'.Wash down f/3,440'tag cement at 3,511'. Drill cement and float equipment f/3,511't/3,596'.POOH f/3,596't/108'.LD BHA f/108'to surface.PU rotary steerable BHA#5 from surface t/81'.Shallow pulse test MWD/LWD,break in Power Drive bearings. 4/18/2010 3,596.0 1,774.00 9.50 PU remainder of BHA#5 f/81't/734'.TIH f/734't/3,515'.Perform MAD pass f/3,515't/3,596'. Drilling f/3,596't/3,616'. CBU and perform L.O.T.at 3,587'MD/2,984'TVD with 9.2 ppg leaked off at 1060 psi, EMW=16.0 ppg. Drilling f/3,616't/3,725'. Drop 1-5/8"ball and pump ball on seat in 6 min,pressure up and sheer ball seat to engage under reamer cutters and confirm same.Drilling 10-5/8"hole and underreaming to 11-3/4" f/3,725't/5,370'. 4/19/2010 5,370.0 1,646.00 9.80 Drilling 10-5/8"hole and under reaming to 11-3/4"f/5,370't/6,192'.Had 500 psi pressure drop in stand pipe pressure--indicating a wash out. POOH f/6,192't/5,683'.Stage up pumps to 400 gpm and back ream through tight spot at 5,683'. Back ream f/5,683't/5,207'.POOH f/5,207't14,300'--found washout. Layout washed out joint and replace same.Circulate at 800 gpm to ensure no more wash outs.TIH f/4,300't/6,095'.Circulate hole clean while reaming f/6,095't/6,192'.Drilling 10-5/8"hole and under reaming to 11-3/4"f/6,192't/7,016'. 4/20/2010 7,016.0 1,618.00 9.90 Drilling 10-5/8"hole and under reaming to 11-3/4"f/7,016't/8,634'. 4/21/2010 8,634.0 248.00 9.90 Drilling 10-5/8"hole and under reaming to 11-3/4"f/8,634't/8,882'. Pump 80 bbls hi-vis sweep and circulate hole clean with 3x bottoms up strokes.POOH f/8,882't/7,968'. Establish circulation and pump dry job. POOH f/7,968't/3,430'--saw 50k over pull as under reamer came into casing shoe,and 100k over pull as bit came into casing shoe.TIH f/3,430't/3,780'. Establish circulation,stage pumps up and CBU strokes while working tight hole conditions.POOH f/3,780't/180'--hole swabbing,had to pump displacement down DP. POOH f/180't/44'with 1 stand of DC and rack back same. 4/22/2010 8,882.0 0.00 10.00 Finish LD BHA#5 f/44'to surface.PU BHA#6 from surface t/640',functioned Rhino reamer at surface and thread locked bull nose to reamer.TIH f/640't/3,580'.CBU at 3,580'.TIH f/3,580't/8,730'.Circulate at 8,730'--packed off.POOH attempting to circulate each stand,and was able to establish circulation at 6,922'.Stage up pumps to 760 gpm,wash and ream in the hole f/6,922't/8,779'.Underream 10-5/8"rat hole to 11-3/4"f/8,779't18,875'. 4/23/2010 8,882.0 0.00 9.80 Pump 80 bbls hi-vis sweep and circulate hole clean with 3x bottoms up.POOH f/8,882't/7,113'. Pump out the hole f/7,113't/4,733'.CBU at 4,733'.Back ream out the hole f/4,733't/3,589'.Drop 2"Rhino reamer deactivation ball and shear ball seat at 1500 psi.Reciprocate pipe f/3,589't/3,495'to establish circulation after pack off event at 3,589'and circulate hole clean with 2x bottoms up strokes. Drop 2.75" rabbit and POOH f/3,495't/735'--tight at 2,600'. Drain stack and function test BOPE.POOH with BHA racking back HWDP f/735't/216'. NOTE:Contacted AOGCC for 48 hr notice of BOPE test. Page 2/5 Report Printed: 5/17/2010 PIONEER Operations Summary Report NATURAL RESOURCES Last Mud Dens End Date Depth Start(ftKB) Foot/Meters(ft) (lb/gal) Summary 4/24/2010 8,882.0 0.00, 9.90 POOH laying down BHA. Install test plug.Remove VBR's from top ram cavity and install 9-5/8"single bore rams. RU BOPE test equipment.Test Annular to 250 psi low/2500 psi high.Test top 9-5/8"rams to 250 psi low/4500 psi high.All test held 5 min each and charted. RD BOPE test equipment. RU 9-5/8" Casing equipment and fill up tool. RIH w/9-5/8"40#L-80 Hydril 521 Casing f/surface t13,583'.CBU at 3,583'.RIH with casing f/3,583't/5,463'. RD casing equipment. PU WFT 10-1/2"Liner Top Hanger/Packer assembly. RD casing spiders and RIH w/9-5/8"Drilling Liner on 5"DP f/5,463't/6,373'. NOTE:Contacted AOGCC for 24 hr notice of BOPE test. 4/25/2010 8,882.0 0.00 10.00 RIH w/9-5/8"Drilling Liner f/6,373't/8,847'.PU&MU Cement Head. RIH t/8,870.Break circulation and circulate 9-5/8"liner volume. Drop 1-3/4"Liner Hanger setting ball and pump down same.Set down 85K to set Hanger. PU to 180K and obseved free travel to verify Hanger set.Pump 10 bbls water.Test cement lines to 4000 psi.Pump 60 bbls 12.5 ppg DUAI Spacer at 3.5 bpm at 1000 psi.Pump 66.2 bbls 15.8 ppg cement with at 4 bpm at 900 psi. Drop DP Wiper Dart.Pump 17 bbls water and switch to rig for dispalcement.Displace cement with 9.8 ppg mud at 6.5 bpm.Slowed pumps to 2 bpm 3 bbls prior to bumping plug.Pressure up to 3500 psi,held 5 min.CIP @ 0920 hrs.PU to expose Packer setting dogs. S/O to 40K applying 80K to Packer setting dogs.Closed Annular and pressured up 5"x 11-3/4"annulus to 3500 psi to test Packer.Held pressure 5 min.Circulated BU.RD Cement Head.POOH f/3,354't/ surface and LD running tool. Remove 9-5/8"single bore rams from top ram cavity and install 2 7/8" X 5"VBR's.ND BOPE and drilling riser. 4/26/2010 8,882.0 0.00 10.00 N/D BOPE and drilling riser.N/D Intermediate casing spool, N/U Multi-bowl and test same to 5,000 psi for 10 min on chart. N/U BOPE and drilling riser. Install MPD test flange and test all lines to 250 psi low and 3,000 psi high.Remove test flange and install trip nipple.Test Annular to 250 psi low/2,500 psi high with 5"DP.Test Upper and Lower 2-7/8"x 5"VBR's,Blind Rams,Choke and Kill Line HCR's, Choke and Kill Line Manual valves, Floor Safety valve,Dart valve, Upper IBOP, 14 Choke Manifold valves to 250 psi low/4,500 psi high. All low and high tests held 5 min ea.All tests charted. Accumulator test,System Pressure 3,050 psi,After Closer 2,100 psi, Initial 200 psi recovery 21 sec's, Full recovery 1 min 35 sec's. Rig down test equipment.Test witnessed by AOGCC rep Lou Grimaldi. Install wear bushing.TIH from surface to 1,900' picking up 60 singles from pipe shed.Circulate 1.5x drill pipe capacity. POH from 1,900'to surface. P/U rotary steerable BHA#7 from surface to 720'.Trip in the hole from 720'to 1,091'. Pulse test MWD and Power Drive--Good test.TIH from 1,091'to 4,050'. 4/27/2010 8,882.0 269.00 10.00 TIH from 4,050'to 8,704'.Pressure test 11-3/4"casing x 9-5/8"liner to 3,500 psi.Test held 30 min and charted.Drill cement and float equipment from 8,704'to 8,865'.Pump 80 bbls hi-vis sweep and circulate same surface to surface.Remove trip nipple and install RCD bearing.Drill float shoe and 20'of new hole from 8,865'to 8,902'.Circulate bottoms up at 8,902'.Perform L.O.T.at 8,870'md,5,301.29' tvd,with 10.0 ppg mud wt.Leaked off at 1,900 psi and bled down to 667 psi for EMW of 12.4 ppg. Drilling from 8,902'to 9,151'. 4/28/2010 9,151.0 749.00 10.001Drill f/9,151-'t/9,900,Observed intermittent losses f/300-30 bph. Reduce MPD WHP f/12.5ppg EMW t/10.1 ppg EMW to control. POH f/9,900'-t/8,810'and circ&cond hole to spot DOB2C pill. 4/29/2010 9,900.0 480.00 10.00 POH f/9,030'-t/8,550'laying DOB2C Stop Loss Pill.Perform hesitation squeeze with MPD applying WHP for EMW f/10.1-12.75 ppg EMW with 8 bbls total lost. Circ btms up. Increased EMW to 13 ppg with no losses.Wash&ream f/8,550'-t/9,900'with no losses.Drill f/9,900'-t/10,380'with 30 bph loss. Maintain 12.75 ppg EMW 4/30/2010 10,380.0 999.00 10.00 Drill f/10,380'-t/11,379'8-1/2"TD. Circ&Cond hole. 5/1/2010 11,379.0 0.00 10.00 Circ&cond hole at 11,379'.Backream t/9,952'.POH on elevators t/8,860'.Wash and ream in hole to 11,379'.Circ&cond hole.POH on elevators t/11,000'.Circ&cond hole. 5/2/2010 11,379.0 0.00 12.80 POH f/11,000'-t/10,428'on elevators with 60 bph losses. RIH t/11,369'.Circ&cond hole.Spot 40 bbl 13.0 ppg LCM pill while POH f/11,369'-t/10,808'.Displace 10.0 ppg mud to 12.8 ppg mud. POH to surface.L/D BHA. Page 3/5 Report Printed: 5/17/2010 PIONEER Operations Summary Report ! NATURAL RESOURCES Last Mud Dens End Date Depth Start(ftKB) Foot/Meters(ft) (1b/gal) Summary 5/3/2010 11,379.0 0.001 12.80 Remove 2-7/8"x 5"VBR's. Install 7"rams in upper ram body and test to 250/4500 psi.Test annular to 250/2500 psi.Tests passed&charted. RIH with 7"26#L-80 BTCM casing t/8,870'. i 5/4/2010 11,379.0 0.00 11.00 RIH 7"26#L-80 BTCM casing with autofill floats f/8,870'-U11,348'. /4_w46_4- 20 Observed the hole flowing.The annular preventer was shut in to monitor pressures. 7"x 11-3/4" annulus pressure elevated and stabilized at 150 psi.The stand pipe pressure elevated and stabilized at 100 psi. Annular choke was opened for 15 min to bleed and monitor pressures with 3 bbl flowing back. Standpipe was bled off.Determined well was ballooning. Bled back total of 11 bbl. PJSM. Pump 10 bbls seawater.Test cement lines to 5,000 psi. Pump 20 bbls 12.5 ppg Dual Spacer. Drop 1st plug. Pump 20 bbls 12.5 ppg Dual Spacer. Drop 2nd Plug. Load Top Plug. Pump 43 bbl 12.5 ppg lead cement.Class G with15#/sk MicroLite.0.75%Halad-344.2%CFR-3.0.15%EZ Flow.0.5% SCR-100. Pump 19 bbls 15.8 ppg tail cement.Class G with 0.7% Halad-344.0.2%CRR-3.0.25 lb/sk Super CBL.0.4%SCR-100. Drop Top Plug. Pump 20 bbls seawater. Switch to Rig pumps and displace with 411 bbl of 11 ppg mud at 5 bpm. Lift was indicated by an increase in the displacement pressure of 60-100 psi prior to bumping plug. Bumped plug at 3.5 bbl/min.CIP @ 00:00 hrs. Pressure up to 4,500 psi and held 30 min. Bled off pressure. Bled back 6.6 bbls followed by 4 additional bbls at 1 bbl/min. Closed bleeder and monitor. Pressure built to 120 psi. Floats not holding.Pump 52 stks to push plugs back to bottom. Pressure up to 600 psi and held. 5/5/2010 11,379.0 0.00 11.00 Maintain 600 psi on floats and W/O cement to set.Bled pressure with 2 bbls back. No additional returns from 7"ID. Flow check 7"x 11-3/4"annulus while RID non-well-control essential equipment. Diminishing returns from 55-0.25 gph.P/U 235k on 7"casing and set in emergency slips.Install pack-off&test to 4350 psi for 10 min.Test passed&charted. 5/6/2010 11,379.0 0.00 7.80''Change out elevators,install iron roughneck track. L/D 17 joints HWDP,jars,and all 5"DP to pipe shed utilizing mousehole. Slip and cut drill line.Change out all handling equipment from 5"to 4". Install wear bushing.TIH picking up 4"singles from the pipe shed to+/-2,700'. **Note**Freeze protected 11 3/4"x 7"annulus with 130 bbls diesel. 5/7/2010 11,379.0 0.00 10.80 TIH picking up 4"singles from the pipe shed from 2,700'to 9,054'.Circulate 1.25x DP capacity to ensure no obstructions in drill pipe. POH from 9,054'to surface racking back clean 4"DP in derrick.TIH picking up 4"singles from the pipe shed from surface to 9,000'.Circulate 1.25x DP capacity to ensure no obstructions in drill pipe.POH from 9,000'to 4,815'racking back clean 4"DP in derrick. 5/8/2010 11,379.0 0.00 10.20 POH from 4,815'to surface. Remove wear bushing and install test plug.Change out upper and lower pipe rams.Rig up testing equipment.Test Annular to 250 psi low/2,500 psi high with 4"DP.Test Upper 2-7/8"x 5"VBR's and Lower 4"single bore rams, Blind Rams,Choke and Kill Line NCR's, Choke and Kill Line Manual valves, Floor Safety valve, Dart valve, Upper IBOP, 14 Choke Manifold valves to 250 psi low/4,500 psi high. All low and high tests held 5 min ea.All tests charted. Accumulator test,System Pressure 3,100 psi,After Closer 2,100 psi, Initial 200 psi recovery 21 sec's, Full recovery 1 min 32 sec's.Test witness waived by AOGCC rep Chuck Scheve at 20:15 hrs on 5-7-10. Test all MPD lines to 250 psi low and 3,000 psi high--Good tests. Pick up BHA from surface to 223'. Trip in the hole from 223'to 11,208'.Wash and ream cement stringers from 11,208'to 11,265'. Drilling float equipment and cement from 11,265'to 11,304'. 5/9/2010 11,379.0 754.00 7.85 Drilling float equipment and cement from 11,304'to 11,348'and clean out rathole to 11,379'.Drilling from 11,379'to 11,399'. Perform F.I.T.at 6,165'tvd with 10.4 ppg mud weight to 700 psi for EMW of 12.5, bled down to 610 psi after 5 min for EMW 12.3 ppg.Transfer WBM from rig to RSC,clean rig mud pits,transfer MOBM to rig pits from RSC. Installed RCD bearing. Displace well from 10.4 ppg WBM to 7.6 ppg MOBM while maintaining 9.8 ppg PWD ECD. Directional drill from 11,399'to 12,133'while maintaining 9.8 ppg ECD with MPD equipment. 5/10/2010 12,133.0 719.00 7.85 Drill from 12,133'to 12,852'. Page 4/5 Report Printed: 5/17/2010 PIONEER Operations Summary Report NATURAL RESOURCES Last Mud Dens End Date Depth Start(ftKB) Foot/Meters(ft) (lb/gal) Summary 5/11/2010 12,852.0 575.00 7.80 Drill from 12,852 to 13,427'maintaining 9.8 ppg EMW at 7"shoe utilizing MPD equipment. 5/12/2010 13,427.0 2,123.00 7.95 Drill from 13,427'to 15,550'maintaining 10.1 ppg EMW at 7"shoe utilizing MPD equipment. 5/13/2010 15,550.0 1,300.00 8.00 Drill from 15,550'to 16,225'maintaining 9.8 ppg EMW at 7"shoe utilizing MPD equipment.Circulate open hole volume prior to check trip.Pull out of the hole from 16,225'to 15,454'.Trip in the hole from 15,454'to 16,225'. Drill from 16,225'to 16,850'maintaining 9.8 ppg EMW at 7"shoe utilizing MPD equipment. 5/14/2010 16,850.0 533.00 8.05 Drilled from 16850'and to TD of the 6-1/8"lateral at 17383'md. CBUx3 and TOH to 7"casing shoe @ 11348'md. Slip&Cut Drill Line. TIH to 16322'and and Wash and Ream to 17093'md. 5/15/2010 17,383.0 0.00 10.20 Stage pumps up and circ hole clean.W&R in the hole from 17,093 to 17,150'. Pump 20 bbl Hi-Vis Sweep and circ same out the hole.Spot 220 bbls of new 7.2 ppg MOBM across open hole.POH from 17,150'to 12,050'. Pump 49 bbls 10.2 ppg MOBM to displace open hole from 8.1 ppg MOBM while maintaining 9.8 ppg EMW.POH from 12,050'to 11,304'. Displace casing volume from 8.1 ppg with 10.2 ppg MOBM.Monitor well,remove RCD bearing,and install trip nipple.Circ and condition mud weight to 10.2 ppg. POH from 11,304'to 416'. Function test BOPE. 5/16/2010 17,383.0 0.00 10.20 POH from 416'to 223'. Remove nuclear sources,and lay down BHA. Rig up testing equipment.Test Annular to 250 psi low/2,500 psi high with 4.5"test joint.Test Upper 2-7/8"x 5"VBR's with 4.5"test joint to 250 psi low/4,500 psi high. All tests held 5 min ea.All tests charted. Rig up 4 1/2"casing equipment.RIH with 4.5"casing from surface to 5,290'.Pick up WFT hyd hanger,liner top packer,and tie back sleeve from 5,920'to 5,945'.Make up SLB memory cement bond log tool.TIH with 4.5"liner on 4"DP from 5,945'to 11,285'.Pump lx drill pipe capacity.TIH with 4.5"liner on 4"DP from 11,285'to 14,123'. it 5/17/2010 17,383.0 0.00 10.10 TIH with 4.5"liner on 4"DP from 14,123'to 17,140'. Drop 1-3/4"Hgr Setting Ball.Pump on seat at 1 bpm. Pressure up to 1,500 psi to set Hgr.Slack down to 75k and lock in Hgr slips.Pressure up ball seat sheared out at 3,400 psi.Slack down to 65k on dogs to set Pkr. Displace well from 10.2 ppg MOBM to 10.1 ppg brine. POH at 30'per min for cement bond log with SCMT tool from 11,068'to 10,200'.TIH from 10,200'to 11,110'. POH at 30'per min for repeat cement bond log from 11,110'to 10,200'. POH from 10,200'to 6,979'.Slip and cut drill line.POH from 6,979'to surface laying down 4"drill pipe and BHA. Page 5/5 Report Printed: 5/17/2010 s ....„. Cementing n SilicaliteTM pri/ ZOO ' o3z- Cement Additive SilicaliteTM cement additive is made from a finely divided, Features high surface-area silica. Silicalite additive is available as a powder,a liquid,a Pozmix®cement blend,or a compacted material. Applications Compacted Silicalite additive does not have the same performance properties as the liquid or powder forms. Silicalite additive can be used as an extender for lightweight Therefore,designs including compacted Silicalite additive cements and a compressive strength enhancer for low should be subjected to laboratory testing before being temperature,lightweight cements.This product also imparts used in the field. thixotropy to some cement slurries.Silicalite additive can be used in wells with bottomhole circulating temperatures (BHCTs)between 50°and 500°F(10°and 260°C). Sulical,teTM Additive (Powder Form)—Product Specifications Part No. 100003722 Bulk Density 18.00 lb/ft3 Form Solid,black powder pH 6 to 8 ISpecific Gravity 2.300 Packaging 50-lb bag SilicaliteTM Ad.7..'ve (Liquid Form)—Product '-cifications' dimill Part No. 120007346 Bulk Density 11.6 lb/gal Form Black liquid pH 6 to 8 Specific Gravity 1.39 Packaging 55-gal drum SilicaliteTM Additive (50:50 Pozmix® Cement Blend)—Product Specifications Part No. 100012222 Bulk Density 35 lb/ft3 Form Solid,black powder pH 6 to 8 Specific Gravity 2.49 Packaging 50-lb bag limmisip 1 Part No. 100012223 Bulk Density 44 Ib/ft3 IForm Solid,black powder pH 6 to 8 Specific Gravity 2.52 Packaging 50-lb bag I HALLIBURTON J Silicalite'''has a viscosifying effect in most compositions. Benefits This additive is frequently used with CFR-2'friction reducer or CFR-3'friction reducer.At static temperatures Because Silicalite additive imparts thixotropy to the slurry,it above 230°F(110°C),a strength-stabilizing agent,such as can help control lost circulation and gas migration.In SSA 1'"`fine silica flour or SSA-2 coarse silica flour should addition,this product can provide a degree of fluid-loss control and can act as a low-temperature accelerator for be incorporated into the slurry design. saturated salt slurries. For more information on the benefits Silicalite' Cement Additive can bring to your cementing operations, contact your local Halliburton representative. www.halliburton.com HALLIBURTON H01484 08/07 Sales of Halliburton products and services will ©2007 Halliburton be in accord solely with the terms and conditions All Rights Reserved contained in the contract between Halliburton and Printed in U.S.A. the customer that is applicable to the sale. Page l of l Regg, James B (DOA) From: Vaughan, Alex[AIex.Vaughan @pxd.com] Sent: Monday, May 03, 2010 10:29 PM Q Zl`ic ham ' 2 l 0 —d Z � l7 To: DOA AOGCC Prudhoe Bay Cc: OoogurukDrillingSupervisor Subject: Synopsis of events concerning the shut in of the annular preventer on PXD ODSN-15i John Crisp, The following is a synopsis of events concerning the shut in of the annular preventer on ODSN-15i on the evening of May 3rd'2010. The intermediate section of ODSN-15i was drilled with a 10.0 ppg mud with an ECD of 13.0 ppg applied via MPD. 2,700 bbls was lost to the hole in the last three days. Prior to pulling out of hole with 5" DP the mud was displaced to 12.8 ppg mud to maintain hole stability. 7" casing was run in hole to casing point and mud was displaced from 12.8 ppg to 11.0 ppg. During the circulation of a hole conditioning sweep pumps were shut down. It was observed the hole continued to flow. The annular preventer was shut in to monitor pressures. 7" x 11-3/4" annulus pressure elevated and stabilized at 150 psi.The stand pipe pressure elevated and stabilized at 100 psi. Annular choke was opened for 30 min to bleed and monitor pressures with 3 bbl flowing back. Standpipe was bled off. — The well was then shut in a second time to monitor pressures. 7"x 11-3/4" annulus pressure elevated and stabilized at 130 psi.The stand pipe pressure elevated and stabilized at 15 psi. Annular choke was opened for 15 min to bleed and monitor pressures with 3 bbl flowing back. Standpipe was bled off. The well was then shut in a third time to monitor pressures. 7"x 11-3/4" annulus pressure elevated and stabilized at 130 psi.The stand pipe pressure elevated and stabilized at 15 psi. Annular choke was opened for 15 min to bleed and monitor pressures with 2 bbl flowing back. We suspect the well is ballooning and therefore flowing back mud lost while drilling the intermediate hole at an EMW of 12.8 ppg when we displaced to a 11.0 ppg mud. As such we opened the annular preventer and commenced operations. We subsequently contacted John Crisp with the AOGCC to update him on events. Please contact myself or Rodney Klepzig at 670-6606 if further information is required. Alex Vaughan Operations Drilling Engineer PIONEER NATURAL RESOURCES 907.226.2180 (Cosmo Rig) 907.343.2186 (office) 907.748.5478 (mobile) 907.343.2190 (fax) 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. 5/21/2010 STIATfE ALASEA SEAN PARNELL,GOVERNOR D ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMMIISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 Vern Johnson Drilling Superintendent Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, AK 99501 Re: Oooguruk Field, Nuiqsut Oil Pool, ODSN-15i Pioneer Natural Resources Alaska, Inc. Permit No: 210-032 Surface Location: 2950' FSL, 1162' FEL, Sec. 11, T13N, R7E, UM Bottomhole Location: 682' FSL, 3087' FEL, Sec. 4, T13N, R7E, UM Dear Mr. Johnson: Enclosed is the approved application for permit to drill the above referenced service well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Daniel T. Seamount, Jr. Chair DATED this day of April, 2010. cc: Department of Fish & Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) PIONEER NATURAL RESOURCES RECEIVED March 18, 2010 MAR 1 9 2010 411160181GesCora.Comnts" Andiaele State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite #100 Anchorage, AK 99501 RE: Application for Permit to Drill ODSN-15i Surface Location: 2950' FSL, 1162' FEL, Sec 11, T13N, R7E, UM X = 469835.96, Y = 6031066.15, ASP4 Pioneer Natural Resources Alaska, Inc. (PNRA) hereby applies for a Permit to Drill a development well from the Oooguruk Drill Site (ODS) located within the Oooguruk Unit. The well is designed to be an injection well in the Oooguruk-Nuiqsut formation. PNRA requests the Permit to Drill based on approved Pool Rules. PNRA intends to pre-produce ODSN-15i prior to injection. As indicated in the attachments, the drilling and well construction program includes the following: • Surface Hole: o Drill 14-1/2" to -3558' MD /3000' TVDrkb and set 11-3/4"flush joint casing. • Intermediate Hole 1: o Drill 10-5/8" and under-ream while drilling (UWD) to 11-3/4" to -8688' MD / 5236' TVDrkb. Run and set a 9-5/8" Flush Joint Drilling Liner. • Intermediate Hole 2: o Drill 8-1/2" to -11065' MD / 6109' TVDrkb and set a 7" Intermediate casing into the top of the Oooguruk-Nuiqsut formation. • Production Hole: o Drill 6-1/8" horizontally to -18,026' MD / 6001' TVDrkb and set a 4-1/2" solid liner with perforated pups. • Completion: o 3-1/2" tubing PNRA will implement Managed Pressure Drilling technology (MPD) while drilling the Intermediate 2 and Production hole sections of ODSN-15i. Alaska Oil & Gas Conservation Commission March 17th, 2009 Page 2 of 3 PNRA plans to use this technique while drilling the Intermediate 2 and Production intervals as outlined below. • From TD of Intermediate 1 until Intermediate 2 TD o Use -9.8-10.5 ppg fluid while using MPD to control pressure from the surface to -12.5 ppg EMW at the bottom of the hole. • Open formations: • Kuparuk Sands, -9.8 ppg Pore Pressure • Nuiqsut Sands, -9.8 ppg Pore Pressure • From the Intermediate 2 Shoe to TD o Use -7.2-8.2 ppg fluid while using MPD to control pressure from the surface to -9.8-10.2 ppg EMW at the bottom of the hole during connections and while tripping Utilizing the MPD process described above allows PNRA to reduce the materials needed for the well, increasing the overall safety of the personnel on the development by handling less material. In addition the lower solids in the production section mud system will reduce formation damage along the sandface of the 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. In the future, PNRA may provide information and permitting requesting annular disposal of drilling wastes on this well. Please find attached information as required by 20 AAC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill per 20 AAC 25.005 (a). 2) A 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 summary of the drilling operations. e. A summary of drilling hazards per 20 AAC 25.005 (c) (4). f. A wellbore schematic is also attached visually depicting the proposed well. 3) A copy of the Planned Directional Well Path - including traveling cylinder and development layout plots. The following items are on file with the AOGCC: Alaska Oil & Gas Conservation Commission March 17th, 2009 Page 3 of 3 1) A plat showing the surface location proposed for the well per 20 AAC 25.005 (c) (2). 2) 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). 3) A description of the procedure for conducting formation integrity tests per 20 AAC 25.035 (c) (5). 4) 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. The following are PNRA's designated contacts for reporting responsibilities to the Commission: 1) Completion Report Vern Johnson, Drilling Superintendent (20 AAC 25.070) 907.343.2111 vern.johnson @pxd.com 2) Geologic Data and Logs Paul Daggett, Senior Staff Geophysicist (20 AAC 25.071) 907.343.2134 paul.daggett @pxd.com The anticipated spud date for this well is April 22"d, 2010. If you have any questions or require further information, please contact Alex Vaughan at 907.343.2186. Sincere 3 / I '7(1° Vern Johnson Drilling Superintendent Attachments: Form 10-401 Supporting permit information cc: ODSN-15i Well File STATE OF ALASKA RECEIVED ALA ■OIL AND GAS CONSERVATION COMMI--,ON PERMIT TO DRILL MAR 1 9 2010 20 AAC 25.005 la.Type of Work: 1 b.Proposed Well Class: Development-Oil ❑ Service- Winj ❑ Single Zone • RIORtlilor: Drill El Redrill ❑ Stratigraphic Test ❑ Development-Gas❑ Service-Supply ❑ Multiple Zone CoalbM1100 Gas Hydrates ❑ Re-entry ❑ _ Exploratory ❑ Service- WAG El• Service-Disp ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket isi . Single Well ❑ '11.Well Name and Number: Pioneer Natural Resources Alaska, Inc. Bond No. 103655283 , ODSN-15i ' 3.Address: 700 G Street,Suite 600 6.Proposed Depth: 12.Field/Pool(s): Anchorage,AK 99501 MD: 18,026' • TVD: 6001' 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Oooguruk- Nuiqsut Oil Pool Surface: 2950'FSL, 1162'FEL,Sec. 11,T13N, R7E, UM / ADL 355036/ADL 355037 Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 986'FSL, 3529'FEL,Sec. 10,T13N, R7E, UM 417497 4/22/2010 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 682'FSL,3087'FEL,Sec.4,T13N, R7E, UM 5760/5724 4597' 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: . 56.2 feet 15.Distance to Nearest Well Open Surface: x-469835.96 - y-6031066.15 , Zone-ASP 4 GL Elevation above MSL: to Same fool: • 13.5 feet e,. .5/∎(--YD 4 5-6 4,A_.)zi, 16.Deviated wells: Kickoff depth: 300 feet 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) �� /t Maximum Hole Angle: 99.35 degrees Downhole: 3113 Surface: 2441 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 115' Surface Surface 158' 158' Driven 14-1/2" 11-3/4" 60# L-80 Hyd 521 3515' Surface Surface 3558' , 3000' '506 sx PF'L';259 sx Class'G' 11-3/4" 9-5/8" 40# L-80 Hyd 521 5280' 3408' 2933' 8688' 5236' 237 sx Class'G' 8-1/2" 7" 26# L-80 _ BTC-M 11,022' Surface Surface 11,065' • 6109' •227 sx Class'G' 6-1/8" 4-1/2" 12.6# L-80 Hyd 521 7111' 10,915' 6070' 18,026'. 6001' Uncemented 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth TVD(ft): Junk(measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate)-Drlg Liner Intermediate 2 Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 20. Attachments: Property Plat ig BOP Sketch❑ Drilling Program 0 Time v.Depth Plot ❑ Shallow Hazard Analysis Diverter Sketch❑ Seabed Report ❑ Drilling Fluid Program 12 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 Vern Johnson Title Drilling Superintendent /" ,, 3//97co Signature (C�� Phone 343-2111 Date 3/18/2010 Commission Use Only Permit to Drill / API Number: Permit Appr vpl 1 See cover letter for other Number: 2-! i 3/( - 50-7( '21-_--)6 l i,-CZ,'(mate: \� 1 b requirements. Conditions of approval: If box Qiss checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: EK Other: 4 y 560 /03.1- P 6 P (;:S.1--- Samples req'd: Yes❑ No[] Mud log req'd: Yes ❑ [o " -,t om 00 tor,. ,4& ',L.,. r.S M' ) H25 measures: Yes❑ No[✓]/ Directional svy req'd: Yes E No❑ - Dived- -r (sickiace.P ZO AAc.. 2 S. 63500(z) - M t T"i4 £ 14 A-l 0 3N Lcf� ✓ - u(1`'irr,w�� Olr.lLra.tL:e,-. (h 4cGOr•Q w;'�. ' /75// APPROVED BY THE COMMISSION /O DATE: 0- ,COMMISSIONER ORIGINAL 1L ewe) •J.5C).(c) Form 10-401(Revised 7/2009) This permit is valid for 24 months from the date of approval(20 AAC 25.005(g)) Submit in D ate Permit to Drill Well Plan Summary ODSN-15i Oooguruk - Nuiqsut Injection Well Surface TD @ 3,558' MD / 3,000' TVD Drilling Liner TD @ 8,688' MD / 5,236' TVD Intermediate TD @ 11 ,065' MD / 6,109' TVD • Production TD @ 18,026' MD / 6,001' TVD Surface Location: 2950' FSL, 1162' FEL, Sec 11, T13N, R7E, UM ASP 4 (NAD27) projection X =469835.96 Y = 6031066.15' Target: Oooguruk-Nuiqsut 986' FSL, 3529' FEL, Sec.10, T13N, R7E, Umiat X = 462174.75 Y = 6029143.53 6109' TVDrkb Bottom Hole Location: 682' FSL, 3087' FEL, Sec. 4, T13N, R7E, Umiat X = 457361.89 Y = 6034138.37 6001' TVDrkb AFE Number: TBA Est. Start Date: April 22, 2010 Rig: Nabors 19AC Operating days: 55 days to Drill and Complete TD: 18026' MD/6001 TVDrkb Objective: Nuiqsut Well Type (exp, dev, etc): Development Well Design: Modified Slimhole (11-3/4" x 9-5/8" liner x 7"x 4-1/2" liner)— Injector—wp07 Current Mechanical Condition: Well Bay Footing/ODS Ground Level: Elevation above MSL: 13.5' , RKB to Ground Level: 42.66' Rig Elevation: RKB + MSL = 56.16' Conductor: 158' MDrkb Pioneer Natural Resources Last Revised: March 17,2010 ODSN-15i Permit To Drill Page 1 of 10 Well Control: 14-1/2" Surface Section: • Maximum anticipated BHP: 1342 psi @ 3000'TVD (Based on seawater gradient of 0.4472 psi/ft) • Maximum surface pressure: 1012 psi @ surface (Based on BHP and a full column of gas from TD @ 0.11 psi/ft) 10-5/8" x 11-3/4" Drilling Liner Hole Section: • Maximum anticipated BHP: 2342 psi @ 5236' TVD (Based on seawater gradient of 0.4472 psi/ft) • Maximum surface pressure: 1766 psi @ surface (Based on BHP and a full column of gas from TD @ 0.11 psi/ft) 8-1/2" Intermediate Casing Hole Section: • Maximum anticipated BHP: 3113 psi @ 6109'TVD (Based on 9.8 ppg Oooguruk-Kuparuk pore pressure) • Maximum surface pressure: 2441 psi @ surface (Based on BHP and a full column of gas from TD @ 0.11 psi/ft) 6-1/8" Production Liner Hole Section: • Maximum anticipated BHP: 3058 psi @ 6001' TVD (Based on 9.8 ppg Oooguruk-Nuiqsut pore pressure) • Maximum surface pressure: 2398 psi @ surface (Based on BHP and a full column of gas from TD @ 0.11 psi/ft) Maximum casing pressure: 4500 psi @ surface Planned BOP test pressure: 4500 psi (annular to 2500 psi) 7 Due to required 4500 psi casing pressure test. Planned completion fluid: 10.2 ppg Brine/6.8 ppg Diesel Diverter (see attached schematic)— Note: Requesting Diverter Exemption on a Well by Well Basis): 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 Pioneer Natural Resources Last Revised: March 17,2010 ODSN-15i Permit To Drill Page 2 of 10 Formation Integrity Testing Requirements: Test Point Depth Test Type Minimum EMW 11-3/4" Surface Shoe Rathole+ 20' to 50' from shoe LOT 12.5 ppg 9-5/8" Drilling Liner Shoe Rathole+ 20' from shoe LOT 12.5 ppg (15.0 ppg max) 7" Intermediate Shoe Rathole+ 20' from shoe FIT 12.5 ppg Drilling Fluids Program: Surface Hole Mud Properties: 14-1/2" 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 Drilling Liner Mud Properties: 10-5/8" x 11-3/4" hole LSND Interval Density(ppg) Viscosity(secs) YP PV MBT API FL Initial to TD 9.8 ppg 40 - 60 15 - 25 12-20 < 12 8- 10 Intermediate Hole Mud Properties: 8-1/2" hole LSND Interval Density(ppg) Viscosity(secs) YP PV MBT API FL Initial to TD 9.8 - 10.5 ppg 50-70 15 - 25 15 -25 < 10 3-5 (8-10 (-12.5 ppg via HTHP) MPD) Production Hole Mud Properties: 6-1/8" hole MOBM Interval Density(ppg) Viscosity(secs) YP PV ES HTHP 0/W Initial to TD 7.2 - 8.2 ppg , 55 - 80 12 - 25 10 - 20 800-2000 <6 94/6 (-9.8 ppg via MPD) Formation Markers: Formation Tops MD (ft) TVDrkb(ft) Pore Press. EMW Comments (psi) (Ppg) Base of Permafrost 1707 1666 Top West Sak 2430 2290 1030 8.65 Base of fluvial sands Tuffaceous Shales 3330 2894 Brook 2b 6475 4271 Top Torok Ss 8130 4993 2246 8.65 Base Torok Ss 8665 5226 Top Hrz 9872 5738 Base Hrz 10263 5881 Kalubik Mkr 10514 5962 Top Kuparuk 10733 6023 Base Kuparuk 10765 6032 3074 9.8 Top Nuiqsut 11051 6106 3112 9.8 TD 18026 6001 . Pioneer Natural Resources Last Revised: March 17,2010 ODSN-15i Permit To Drill Page 3 of 10 • Logging Program: 14-1/2" Section: Drilling: Dir/GR Open Hole: N/A Cased Hole: N/A 10-5/8" x 11-3/4" Section: Drilling: Dir/GR Open Hole: N/A Cased Hole: N/A 8-1/2" Section: Drilling: Dir/GR/ Res/Dens/Neut Open Hole: N/A Cased Hole: Bat Sonic - 6-1/8" Section: Drilling: Mud logging Dir/GR /Azm Res/ALD/Neut/ PWD/Bat Sonic , Open Hole: N/A Cased Hole: N/A Pioneer Natural Resources Last Revised: March 17,2010 ODSN-15i Permit To Drill Page 4 of 10 Casing Program: Hole Casing/ Weight Grade Conn. Casing Csg/Tbg Top Hole Btm Size Tubing Length MDrkb MDrkb/TVDrkb 24" 16" 109# H-40 Welded 115' Surface 158'/ 158' . 14-1/2" 11-3/4" 60# L-80 Hydril 521 3,515' Surface 3,558'/3,000' 11-3/4" 9-5/8" 40# L-80 Hydril 521 5,280' 3,408' 8,688'/5,236' 8-1/2" 7" 26# L-80 BTC-M 11,022' Surface 11,065'/6.109' 6-1/8" 4-1/2" 12.6# L-80 Hydril 521 7,111' 10,915' 18,026'/6,001' Tubing _ 3-1/2" 9.3# L-80 TCII 10,872' Surface 10,915'/6,126' Casing Properties Size Weight Grade ID Drift Conn. Internal Collapse Tensile Strength ID Yield (psi) (psi) Joint Body 16" 109# H-40 14.67" 14.5" Welded Conductor casing 11-3/4" 60# L-80 10.772" 10.62" Hydril 521 5830 3180 1384M 1384M 9-5/8" 40# L-80 8.835' 8.75" Hydril 521 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" Hydril 521 na na 289 M 289 M Pioneer Natural Resources Last Revised: March 17,2010 ODSN-15i Permit To Drill Page 5 of 10 Cement Calculations: Casing Size: 111-3/4" Surface Casing-single stage Basis: Lead: 75% excess over gauge hole in permafrost+ 50 bbls. 30% excess over gauge hole below permafrost Lead TOC: Surface Tail: 500' of open hole with 30%excess, plus 85' shoe track Tail TOC: 3058' MD Total Cement Volume: Preflush 10 bbl water Spacer 40 bbl 10.0 ppg Dual Spacer Lead 374 bbls/506 sx of 10.92 ppg Type "L" Permafrost Cement. 4.15 cf/sk, 20.0 gps water req. Tail 55 bbls/259 sx of 15.9 ppg Premium "G" + adds. 1.19 cf/sk. 5.23 gps water req. Displ 381 bbls Mud Temp BHST -55° F, BHCT -60° F estimated 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. 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: ( 9-5/8" Intermediate 1 - Drilling Liner-single stage 1 Basis: TOC: 8081' MD-The greater of 500' MD of open hole or 50' above top of Torok 60%excess, plus 85' shoe track Total Cement Volume: Preflush 10 bbl water Spacer 60 bbl 10 ppg Dual Spacer Primary 49 bbls/237 sx Premium "G" + adds. 1.17 cf/sk Displ 454 bbls mud Temp BHST - 135° F at 5366' TVDrkb, -110° F BHCT Casing Size: 1 7" Intermediate 2-single stage Basis: TOC: -9672'MD-The greater of 500' MD above the top of the Kuparuk or 200' above 679 inclination depth of 9872' 40%excess, plus 85' shoe track Total Cement Volume: Preflush 10 bbl water Spacer 40 bbl 12.5 ppg Dual Spacer Primary 47 bbls/227 sx Premium "G" + adds. 1.17 cf/sk Displ 420 bbls mud Temp BHST - 165° F at 6100' TVDrkb, -135° F BHCT This well is outside the 1/2 mile radius around the disposal well at the intersection with the Torok disposal zone. Disposal: Annular Infection: 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: March 17,2010 ODSN-15i Permit To Drill Page 6 of 10 Pioneer Natural Resources Well Plan Summary Drilling Operations Pre-Riq Work 1. 16" Conductors have been set and the Well Bay modules have been placed. Rig Activity: Drill and Complete 1. MIRU Nabors 19AC over pre-installed 16" conductor casing. 2. Nipple up spacer spools and riser. 3. MU 14-1/2" Directional Drilling, MWD/LWD assembly. Drill surface hole to the casing point. making wiper trips as necessary. Circulate and condition the hole to run casing. POOH. 4. Run and cement the 11-3/4" surface casing. Bump the plug and bring the pressure up to 3500 psi—chart and hold for 30 minute pressure test. Send chart to ODE. Note: A Port Collar may be run based on hole conditions at Company Rep discretion. 5. Ensure floats are holding. WOC if needed. 6. ND Riser, NU Drilling Spool and BOPE and test. Test BOPE to 250/4500 psi - Notify AOGCC 48 hours in advance of test. 7. MU 10-5/8" x 11-3/4" RSS. MWD/LWD (BHA will be a 10-5/8" pilot hole opened to 11-3/4" while drilling). 8. RIH and cleanout casing to landing collar. Displace well over to Intermediate 1 drilling fluid. 9. Drill through surface shoe, rathole + 20' of new hole and perform LOT to a minimum of 12.5 ppg. 10. Drill 10-5/8"x 11-3/4" Intermediate 1 to casing point. 11. Change one set of pipe rams to 9-5/8" and test BOPE as required. 12. Run 9-5/8"drilling liner on 5" DP. Set liner hanger, release from liner and cement. 13. Bump the plug, increase pressure to 3500 psi and hold pressure for 5 minutes • This will provide a quick integrity test of the 9-5/8" liner • Note the pressure test in the morning report 14. Release pressure and ensure floats are holding • This will check the integrity of the floats to ensure there isn't a flow path through the / liner shoe 15. Set liner top packer and test the liner top and the liner top to 3500 psi for 5 minutes • This will check the integrity of the liner top packer to ensure isolation between the liner and the surface casing • Note the pressure test of the liner top in the morning report Note: The surface casing was pressure tested to 3500 psi for 30 minutes prior to drilling out the surface casing shoe 16. POOH w/5" DP. 17. ND Drilling spool, NU BOPE and test to 250/4500 psi - Notify AOGCC 48 hours in advance of test. • Ensure integrity of the liner and the liner top has been verified by a pressure . test prior to performing this step 18. MU 8-1/2" RSS, MWD/LWD on 5" DP. RU MPD trip nipple. 19. RIH and cleanout casing to landing collar. 20. Close pipe rams and combo pressure test the Drilling Liner and the Surface Casing to 3500 psi • for 30 minutes -- chart and send to ODE. 21. Drill through drilling liner shoe + 20' of new hole and perform LOT to a minimum of 12.5 ppg. Do not exceed a 15.0 ppg EMW FIT. Pioneer Natural Resources Last Revised: March 17,2010 ODSN-15i Permit To Drill Page 7 of 10 22. RD MPD trip nipple and RU bearing assembly. Drill 8-1/2" Intermediate 2 to casing point. 23. Circulate and condition the well to run 7" intermediate casing. Displace the well over to -12.5 ppg mud for shale stability. RD the MPD bearing assembly and RU MPD trip nipple. POH. 24. Change one set of pipe rams to 7"and test BOPE as required. 25. Run and cement the 7" intermediate casing. 26. Bump the plug and bring the pressure up to 3500 psi-hold for 5 minute pressure test. Release pressure and ensure floats are holding. 27. LD 5" DP 28. Change pipe rams to 4" and test BOPE to 250/4500 psi- Notify AOGCC 48 hours in advance of test. 29. PU 4" DP as needed to TD the Production hole section. 30. MU 6-1/8" RSS, MWD/LWD/BatSonic drilling assembly on 4" DP. RU MPD trip nipple. RIH and • cleanout to landing collar. RD MPD trip nipple and RU bearing assembly. 31. Log cased hole cement with BatSonic for cement bond evaluation as per AOGCC regulation. 32. Displace to drill-in-fluid for production lateral. 33. Pressure test casing to 4500 psi-chart and hold for 30 minute pressure test. Send chart to ODE. 34. Drill through Intermediate 2 shoe, rathole + 20' of new hole and perform FIT to 12.5 ppg. 35. Drill 6-1/8" lateral production hole to TD. 36. Circulate and condition the hole to run liner. 37. POH to intermediate shoe and set heavy weight balance brine pill. Cont POH to surface. 38. Change one set of pipe rams to 4-1/2"and test BOPE as required. 39. RIH w/4-1/2" solid production liner w/outflow control devices and sliding sleeves from 150' inside the intermediate shoe to TD. 40. Release from the liner and set the liner top packer. Displace the well over to 10.2 ppg Brine and POOH. 41. MU and RIH w/3-1/2" injection completion w/packer, ROC gauge, GLM, SSSV. 42. Space out, Land the tubing and RILDS. Install TWC. 43. ND BOPE, NU tree and test to 5,000 psi. 44. Pull TWC and reverse circulate corrosion inhibited brine and diesel to freeze protect the well to -2000'TVD and allow to u-tube. 45. 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. 46. RDMO to next well. Post-Riq Work 1. RU Slickline and pull the ball and rod. Pull the RHC-m plug. 2. RD Slickline. Pioneer Natural Resources Last Revised: March 17,2010 ODSN-15i Permit To Drill Page 8 of 10 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 It 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 (or Formation Integrity Test): • Calculate the required test pressure to reach leak off (or formation integrity test limit) with the actual mud weight and the estimated fracture EMW. • Plot the casing test data and the calculated leak off on appropriate scale coordinate paper. As a guide. use the data from the casing test to determine the approximate volume of mud required to reach the calculated LOT/FIT. • Shut the well in. R/U the test pump. • Bring the pump on line at 0.25—0.50 bpm. Maintain a constant rate. • Record the pressure for every 1/4 of a bbl pumped. • Continue pumping until the pressure vs. volume curve breaks over indicating leak off. Note: For FIT, do not take to leak off • Discontinue pumping and shut in the well. Record the shut in pressure in 1 minute increments for 10 minutes or until pressure shows stabilization. • Bleed off the pressure and record the volume of mud recovered. • Plot the data to determine the LOT/FIT pressure at the shoe as EMW. • Submit the test results to the Pioneer drilling engineer for distribution as required. Pioneer Natural Resources Last Revised: March 17,2010 ODSN-15i Permit To Drill Page 9 of 10 ODSN-15i Drilling Hazards and Contingencies POST THIS NOTICE IN THE DOGHOUSE Well Control • Prior to drilling into the Kuparuk, hold a pre-reservoir meeting to outline heightened awareness for kick detection and lost circulation. 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. Hydrates and Shallow gas • No hydrates are expected in this area. Lost Circulation/Breathing/Formation Stability/Stuck Pipe Events • • Breathing may be seen while drilling the Hue shale. Minimizing swab and surge on the formation is critical to reducing the impact of breathing in the wellbore. Breathing was seen in the ODSN-40 well, but only after substantial time in trying to solve the lost circulation problems in the fault seen in and below the Torok Sands. • Lost Circulation was seen in drilling the ODSN-36 across this same interval. Review the DOB2C pill procedure prior to penetrating the Kuparuk. Follow the Lost Circulation Decision Tree and combat losses accordingly • During the attempt to retrieve a fish from the ODSK-33 well, an un-centralized BHA got stuck from differential sticking across the Torok due to the increase in mud weight needed to hold back the shales below. Differential sticking indications were not noted with the drilling BHA and drill pipe. In any event, keep the pipe moving and avoid allowing the pipe to remain stationary any longer than necessary to minimize the chances of differential sticking. • There is a small section of formation above the Top of the HRZ that is volcanic in nature (TUFFS) and can either have "glassy" material, swelling clays or both while drilling, which produced a pack off on ODSK-33 and ODSN-45 - close attention while drilling this interval is advised. Kick Tolerance/Integrity Testing Kick Tolerance/Integrity Testing Summary Table Casing set/ Maximum Mud Weight Exp Pore Min LOT/FIT Interval Influx Volume Press 11-3/4" Surface/ 507 bbls 10 ppg 2342 12.5 ppg (LOT) 10-5/8" x 11-3/4" •9-5/8" Drilling Liner/ Infinite 10.0 ppg 3113 12.5 ppg (LOT). 8-1/2' (12.5 EMW w/MPD) 14.0 ppg Max 7" Intermediate/ Infinite 8.6 ppg 3058 12.5 ppg (FIT) 6-1/8" (10.2 EMW w/MPD) 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 H2S site, however Standard Operating Procedures for H2S precautions should be followed at all times. Faults • Three seismic faults with expected throws of 20' may be encountered. Losses may be associated with these faults. • Sub seismic faults with throws <25' may be encountered. Losses may be associated with these faults. CONSULT THE ODS DATA SHEET FOR ADDITIONAL INFORMATION (still in development) Pioneer Natural Resources Last Revised: March 17,2010 ODSN-15i Permit To Drill Page 10 of 10 ODSN-15i Injection Well Proposed Completion Well Head: 11-3/4", 5K,VetcoGray O Tree: 3-1/2", 5K, Horizontal Casing Item# Item MD(ft) TVD(ft) A 16"Conductor 158 158 A ` B 11-3/4"60#L-80 Hydril 511,10.772"ID 3,558 3,000 C 9-5/8"40#Hydril 521,8.835"ID" 8,688 5,236 -- >-J O 0 D 7"26#L-80 BTC-M,6.276"ID** 11,065 6,109 E 4%#12.60#L-80 Hydril 521 18,026 6,001 F 3W 9.3#L-80 TCII 10,915 6,066 'Estimated TOC @ 7631'MD **Estimated TOC @ 9872'MD 1 VetcoGray Tubing Hanger 34 34 HES Wellstar TRSSSV w/3W 9.2#TGII Box x Pin 9 Chr O w/2.813"X'Profile w/1/4"x.049 SS CL to Surface 3) GLM#1 HES Vanoil 3W x 1W Gas Lift Mandrel w/3W J 3 9.2#TC-II Box x Pin w/Dummy in place 3,558 3,000 B GLM#2 HES Vanoil 3W x 1W Gas Lift Mandrel w/3W 4 9.2#TGII Box x Pin w/Dummy in place(min 2 jts above 10,600 5,987 ROC) 5 HES ROC Gauge&Carrier w/3W 9.2#TSHP Box x Pin 10,681 6,009 (min.1 joint above X nipple) 6 HES 2.813"X'Nipple 9 Chr w/3W 9.2#TGII Box x Pin 10,731 6,023 (min 2 jts above packer) Weatherford 41/2 13.5#x 7"23-32#Model"Ultra Pak-71" P 7 Hydraulic Set Permanent Production Packer w/4%13.5# 10,801 6,040 New Vam Pin x Pin HES 2.813"X'Nipple 9 Chr w/3W 9.2#TGII Box x Pin 8 10,821 6,046 (min 2 jts above)QV nipple) 9 HES 2.813")Qd"Nipple w/2.750"No-Go 9Chr w/3W TCII 10,891 6,064 Box x Pin w/"RCH-M"Plug in Place(Set @ 65 deg Incl.) /� 10 WLEG w/3W TCII Box 10,896 6,065 C I End of Assembly 10,897 6,065 MMIIiilmW O 11 WFT PBR lie Back Sleeve 158 10,897 6,065 12 WFT"NTH"Liner Top Pkr w/Hold Down Slips 5"18#x 7" Cal-'I 26#w/Vam Top HT Pin WET"PHR"Rotating Liner Hanger 5"18#x 7"26#w/5" 10,912 6,070 13 Vam Top HT Pin x Pin and XO w/5"New Vam HT Box 10,915 6,070 O 4W Hydril 521 Pin 14a WFT ZoneSelect Sliding Sleeve w/6 1/2 holes w/4-1/2 TBD* TBD` O 0 Hydril 521 Box x Pin(OPEN Position) 14b WFT ZoneSelect Sliding Sleeve w/2.20 Carbide Nozzles TBD` TBD` w/4-1/2 Hydril 521 Box x Pin(Closed Position) O 11111 14c WFT Genesis 5.750 OD x 4-1/2 12.60 x 15 Ft Oil Base TBD` TBD' O ■ ® Swell Pkr w/4-1/2 Hydril 521 Box x Pin L-80 • 15 4-1/2 12.60 L-80 Hydril 521 Pup Joint w/(6)1/2 Holes 18,006 6,001 16 Liner Shoe(PLUGGED) 18,011 6,001 ® TD 18,026 6,001 `Number and quantity of sleees/swellable packers TBD based on res data during drilling O I I I , I I 0 0 0 0 0 0 0 •• p Open eel I 0 0 • Closed 14 is 1s c Date: Revision By: Comments PIONEER 3/8/2010 jdf Proposed Completion NA1URAlRESOURCESAIAS(A ODSN-15i Injector Proposed Completion Well Planning - Pioneer - Oooguruk Oooguruk Development Oooguruk Drill Site ODSN-151 - Slot ODS-15 ODSN-15i IN12 Plan: ODSN-15i IN12 wp07 Standard Proposal Report 09 March, 2010 HALLIBURTON -: - Sperry Drilling Services ❑ ❑ > _ o p > r _ O �QQ ~ r H H 1- H r O O 0°o Oo_ _—M n > > > i > > > > ❑ p (D O o _ N - m N N N N N N N N > > NO 40 O N _ )ZZ ~ Z Z Z Z Z Z Z Z H H (0 0 Q , Z - 0 Igg E o o07t0O4-O W m 7 LOMoWN N7<o MMWON N NN NN W W LON-.- 00 L°O ❑ co 2 / „..„---,._3 _ M (snoo y fn 000(00 N(CDU(U)NO M 001(C0))ON a-CNOO)W 6Ct`m')V QM O�N M W MOO ❑ O ❑ b / Z r > MMV�MO(ornrnlnrnrnolncocoMVaCCC000MVlno0 CC CC ❑ o _ a Z Nag[ ■�.-u')(000NN N W W W W 000000.- N NNNNN > > (OD O O - _ (O ) P F 0 ZiO inU H H O O__p NO --I h ❑O —co Q Co C)C 000000 00) M O OD 0000 N M O W m 00 O)0 N CO 0 a 000000o O O ❑ ❑ -ao _ > - N O+ a 000 0000 0 00)01�00U)0(O 0)O 7WO 0CC0 .-OCCON0000 0) 2 2 N _ r - - N - �00(�0000NM0.-0000(Oh OCM00i00(n00000(00000 p r M O OFF- N NNN O M (0 N,- NN NN W M N W 0 N_ 0_- Z H _ 34'4��444444 CD _ N ° - ° CD 0000000 M 0000000000000000000000000000 Q M N D ❑ y > 0 W 01 d "1S m000o(llO(00000000000000000000000000000 ❑ O Z y�y�yy'H ACC�N�O(\It7 t7O(700170t7(7Ot7MGt7170 Mt7O MMOMt70(70 > r r •p ❑ N _ N O LL CI C C W H O o_ O_- ..---,..„=--L_ W _ CO Z 1 J_ >00 O (OMIO(O(n NLn W OMN MCOMN N WN UN(n CN NNN CCN7'N O O O --_ _ O GT. 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Q NNONNN NN N Q LT U CO000000O-LOC)O C1 e �p 1 - m �OOOOON aNO)N N O O La \ \ \ `I \\ _ F N - _1 0000 COCOCO00 CO C�C^p�-O� �0 \O yq \ - \ z 3 Cq 0 z h b Cn\ W \\ \\ I\ s _O 2 }p� e iG b ,1 M \ \\ \I N °Cq° 7. r F0-HIiHFF�NrIL N ^q L N vMi t \\ \ I\ \\!� _ a aoo } w r s OO NN�NNN NNN .Op r\ 8\4 \ \ \\\ _ \ N _ a zzz�jzzzzzzj ,z,;, o \\o `\\` I` \\ E - F ° ) — _ Q - - __ _ m 9 g N\ \\ \ I\\ I\\ lCrV N g M 5 - •y .� ,N \ .\ \ I h n - QQ cn � G 1 O t \ M _ k..- • z a % d.....- ♦ \ \I I\ 1 O ; C W \ \ _ _ C - d' U AVVVq . • N \�/ I1 \ - Ce N 8 U-1 s go>�m CNI sd = a e \\- _'^ _ ^ • 1 38 _ - Li� d 4499 N 0 ._ S 0 Q —M Z w e W Q - J u I I I I I I I I I I I I I I IIII I I I I II 1 1 1 1 1 1 1 1 1 1 1 1 1 111 1 1 1 1 1 11 1 11 11 11 1 1 � 1 1 1 1 1 1 1 1 1 1 1 11 3 pQ\D O U $ $ ° $ a ,c 0 sc . g°CE -u N/ unos li■I Lr z ( j 000Z)(+)uuo Halliburton Company HALLIBURTON Standard Proposal Report Database: .Pioneer Alaska Local Co-ordinate Reference: Well ODSN-15i-Slot ODS-15 Company: Well Planning-Pioneer-Oooguruk TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-15i Survey Calculation Method: Minimum Curvature Wellbore: ODSN-15i IN12 Design: ODSN-15i IN12 wp07 Project Oooguruk Development Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Oooguruk Drill Site Site Position: Northing: 6,031,151.32ft Latitude: 70°29'46.242 N From: Map Easting: 469,920.45ft Longitude: 150° 14'45.465 W Position Uncertainty: 0.0 ft Slot Radius: in Grid Convergence: -0.23? Well ODSN-15i-Slot ODS-15 Well Position +N/-S 0.0 ft Northing: 6,031,066.15 ft Latitude: 70°29'45.401 N +E/-W 0.0 ft Easting: 469,835.96 ft Longitude: 150°14'47.942 W Position Uncertainty 0.0 ft Wellhead Elevation: ft Ground Level: 13.5ft " Wellbore ODSN-15i IN12 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (?) (?) (nT) IGRF200510 3/7/2007 23.24 80.81 57,644 Design ODSN-15i IN12 wp07 Audit Notes: Version: Phase: PLAN Tie On Depth: 42.7 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (ft) (ft) (ft) (?) 42.7 0.0 0.0 283.60 3/9/2010 5:03:12PM Page 2 COMPASS 2003.16 Build 428 Halliburton Company HALLIBURTOR Standard Proposal Report Database: .Pioneer Alaska Local Co-ordinate Reference: Well ODSN-15i-Slot ODS-15 Company: Well Planning-Pioneer-Oooguruk TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-15i Survey Calculation Method: Minimum Curvature Wellbore: ODSN-15i IN12 Design: ODSN-15i IN12 wp07 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) (?/100ft) (?/100ft) (?) 42.7 0.00 0.00 42.7 -13.5 0.0 0.0 0.00 0.00 0.00 0.00 230.0 0.00 0.00 230.0 173.8 0.0 0.0 0.00 0.00 0.00 0.00 300.0 0.70 285.50 300.0 243.8 0.1 -0.4 1.00 1.00 0.00 285.50 854.1 11.78 285.50 850.0 793.8 16.2 -58.4 2.00 2.00 0.00 0.00 1,697.5 24.43 285.50 1,650.0 1,593.8 86.1 -310.5 1.50 1.50 0.00 0.00 1,807.4 24.43 285.50 1,750.0 1,693.8 98.2 -354.3 0.00 0.00 0.00 0.00 2,007.4 27.03 275.50 1,930.1 1,873.9 113.9 -439.5 2.53 1.30 -5.00 -59.09 3,232.9 56.77 240.91 2,843.3 2,787.1 -116.6 -1,190.6 3.00 2.43 -2.82 -52.51 3,499.4 64.16 244.42 2,974.6 2,918.4 -222.7 -1,396.5 3.00 2.77 1.32 23.33 8,842.2 64.16 244.42 5,303.2 5,247.0 -2,299.3 -5,733.7 0.00 0.00 0.00 0.00 10,753.3 75.00 305.00 6,028.6 5,972.4 -2,126.6 -7,407.5 3.00 0.57 3.17 91.78 11,053.3 75.00 305.00 6,106.2 6,050.0 -1,960.4 -7,644.8 0.00 0.00 0.00 0.00 11,085.0 75.00 305.00 6,114.4 6,058.2 -1,942.8 -7,670.0 0.00 0.00 0.00 0.00 11,653.9 89.81 313.58 6,189.5 6,133.3 -1,586.5 -8,104.3 3.00 2.60 1.51 30.56 12,143.8 89.81 313.58 6,191.2 6,135.0 -1,248.8 -8,459.2 0.00 0.00 0.00 0.00 12,159.2 90.00 314.00 6,191.2 6,135.0 -1,238.1 -8,470.3 3.00 1.24 2.73 65.57 12,245.9 92.58 314.36 6,189.3 6,133.1 -1,177.7 -8,532.5 3.00 2.97 0.41 7.93 12,914.9 92.58 314.36 6,159.2 6,103.0 -710.5 -9,010.3 0.00 0.00 0.00 0.00 12,966.9 94.00 315.00 6,156.2 6,100.0 -673.9 -9,047.2 3.00 2.74 1.23 24.18 13,043.4 93.07 317.10 6,151.5 6,095.3 -619.0 -9,100.2 3.00 -1.22 2.75 113.89 13,838.4 93.07 317.10 6,108.9 6,052.7 -37.4 -9,640.6 0.00 0.00 0.00 0.00 13,940.7 90.00 317.08 6,106.2 6,050.0 37.5 -9,710.2 3.00 -3.00 -0.02 -179.65 13,967.5 89.19 317.08 6,106.4 6,050.2 57.1 -9,728.5 3.00 -3.00 0.00 179.99 15,371.3 89.19 317.08 6,126.1 6,069.9 1,085.1 -10,684.2 0.00 0.00 0.00 0.00 15,376.2 89.06 317.02 6,126.2 6,070.0 1,088.6 -10,687.5 3.00 -2.73 -1.25 -155.47 15,376.7 89.05 317.02 6,126.2 6,070.0 1,089.0 -10,687.9 3.00 -3.00 -0.04 -179.16 16,261.0 89.05 317.02 6,140.9 6,084.7 1,735.9 -11,290.7 0.00 0.00 0.00 0.00 16,292.8 90.00 317.04 6,141.2 6,085.0 1,759.1 -11,312.3 3.00 3.00 0.04 0.84 16,417.5 93.74 317.04 6,137.1 6,080.9 1,850.3 -11,397.3 3.00 3.00 0.00 0.00 17,035.7 93.74 317.04 6,096.8 6,040.6 2,301.8 -11,817.7 0.00 0.00 0.00 0.00 17,044.4 94.00 317.06 6,096.2 6,040.0 2,308.1 -11,823.6 3.00 2.98 0.33 6.29 17,222.8 99.35 317.06 6,075.5 6,019.3 2,437.8 -11,944.2 3.00 3.00 0.00 0.00 17,526.0 99.35 317.06 6,026.2 5,970.0 2,656.8 -12,148.1 0.00 0.00 0.00 0.00 17,837.7 90.00 317.06 6,000.8 5,944.6 2,884.0 -12,359.4 3.00 -3.00 0.00 180.00 18,026.0 90.00 317.06 6,000.8 5,944.6 3,021.9 -12,487.7 0.00 0.00 0.00 0.00 3/9/2010 5:03:12PM Page 3 COMPASS 2003.16 Build 428 Halliburton Company HALLIBURTON Standard Proposal Report Database: .Pioneer Alaska Local Co-ordinate Reference: Well ODSN-15i-Slot ODS-15 Company: Well Planning-Pioneer-Oooguruk TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-15i Survey Calculation Method: Minimum Curvature Wellbore: ODSN-15i IN12 Design: ODSN-15i IN12 wp07 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (ft) (?) (?) (ft) ft (ft) (ft) (ft) (ft) -13.50 42.7 0.00 0.00 42.7 -13.5 0.0 0.0 6,031,066.15 469,835.96 0.00 0.00 100.0 0.00 0.00 100.0 43.8 0.0 0.0 6,031,066.15 469,835.96 0.00 0.00 200.0 0.00 0.00 200.0 143.8 0.0 0.0 6,031,066.15 469,835.96 0.00 0.00 230.0 0.00 0.00 230.0 173.8 0.0 0.0 6,031,066.15 469,835.96 0.00 0.00 Start Dir 1.00/100'230.00'MD,230.00'TVD 300.0 0.70 285.50 300.0 243.8 0.1 -0.4 6,031,066.27 469,835.55 1.00 0.43 Start Dir 2.00/100'300.00'MD,300.00'TVD 400.0 2.70 285.50 399.9 343.7 0.9 -3.3 6,031,067.07 469,832.69 2.00 3.39 500.0 4.70 285.50 499.7 443.5 2.6 -9.5 6,031,068.82 469,826.48 2.00 9.84 600.0 6.70 285.50 599.2 543.0 5.3 -19.1 6,031,071.51 469,816.92 2.00 19.77 700.0 8.70 285.50 698.3 642.1 8.9 -32.0 6,031,075.15 469,804.03 2.00 33.16 800.0 10.70 285.50 796.9 740.7 13.4 -48.2 6,031,079.71 469,787.81 2.00 50.00 854.1 11.78 285.50 850.0 793.8 16.2 -58.4 6,031,082.58 469,777.65 2.00 60.55 Start Dir 1.50/100'854.10'MD,850.00'TVD 900.0 12.47 285.50 894.8 838.6 18.8 -67.7 6,031,085.19 469,768.38 1.50 70.17 1,000.0 13.97 285.50 992.2 936.0 24.9 -89.7 6,031,091.39 469,746.37 1.50 93.03 1,100.0 15.47 285.50 1,088.9 1,032.7 31.7 -114.2 6,031,098.28 469,721.92 1.50 118.43 1,200.0 16.97 285.50 1,184.9 1,128.7 39.1 -141.1 6,031,105.85 469,695.03 1.50 146.34 1,300.0 18.47 285.50 1,280.2 1,224.0 47.3 -170.4 6,031,114.10 469,665.74 1.50 176.76 1,400.0 19.97 285.50 1,374.6 1,318.4 56.1 -202.2 6,031,123.03 469,634.06 1.50 209.67 1,500.0 21.47 285.50 1,468.1 1,411.9 65.5 -236.2 6,031,132.62 469,600.01 1.50 245.03 1,600.0 22.97 285.50 1,560.7 1,504.5 75.6 -272.7 6,031,142.87 469,563.61 1.50 282.82 1,697.5 24.43 285.50 1,650.0 1,593.8 86.1 -310.5 6,031,153.50 469,525.87 1.50 322.01 End Dir 1697.50'MD,1650.00'TVD 1,700.0 24.43 285.50 1,652.2 1,596.0 86.4 -311.5 6,031,153.78 469,524.89 0.00 323.03 1,800.0 24.43 285.50 1,743.3 1,687.1 97.4 -351.3 6,031,164.99 469,485.08 0.00 364.37 1,807.4 24.43 285.50 1,750.0 1,693.8 98.2 -354.3 6,031,165.82 469,482.14 0.00 367.42 Start Dir 2.53/100'1807.40'MD,1750.00'TVD 1,900.0 25.64 280.87 1,833.9 1,777.7 107.2 -392.4 6,031,174.90 469,444.03 2.48 406.60 2,000.0 26.93 275.85 1,923.6 1,867.4 113.6 -436.2 6,031,181.47 469,400.28 2.57 450.66 2,007.4 27.03 275.50 1,930.2 1,874.0 113.9 -439.5 6,031,181.81 469,396.95 2.57 453.98 Start Dir 3.0/100'2007.40'MD,1930.10'TVD 2,100.0 28.80 270.92 2,012.0 1,955.8 116.3 -482.8 6,031,184.40 469,353.67 3.00 496.62 2,200.0 30.87 266.54 2,098.7 2,042.5 115.1 -532.5 6,031,183.44 469,303.97 3.00 544.66 2,300.0 33.06 262.68 2,183.6 2,127.4 110.1 -585.2 6,031,178.63 469,251.28 3.00 594.67 2,400.0 35.36 259.25 2,266.3 2,210.1 101.2 -640.7 6,031,169.98 469,195.76 3.00 646.52 2,429.5 36.06 258.31 2,290.2 2,234.0 97.9 -657.5 6,031,166.70 469,178.89 3.00 662.12 Top West Sak 2,500.0 37.75 256.19 2,346.6 2,290.4 88.5 -698.9 6,031,157.51 469,137.54 3.00 700.07 2,600.0 40.21 253.46 2,424.4 2,368.2 72.0 -759.5 6,031,141.26 469,076.81 3.00 755.17 2,700.0 42.72 250.99 2,499.3 2,443.1 51.8 -822.6 6,031,121.27 469,013.70 3.00 811.66 2,800.0 45.28 248.74 2,571.2 2,515.0 27.9 -887.8 6,031,097.60 468,948.42 3.00 869.40 2,900.0 47.89 246.69 2,639.9 2,583.7 0.3 -954.9 6,031,070.31 468,881.12 3.00 928.22 3,000.0 50.53 244.80 2,705.3 2,649.1 -30.8 -1,024.0 6,031,039.48 468,812.00 3.00 987.97 3,100.0 53.19 243.05 2,767.0 2,710.8 -65.4 -1,094.6 6,031,005.19 468,741.24 3.00 1,048.48 3/9/2010 5:03:12PM Page 4 COMPASS 2003.16 Build 428 Halliburton Company HALLIBURTOIN Standard Proposal Report Database: .Pioneer Alaska Local Co-ordinate Reference: Well ODSN-15i-Slot ODS-15 Company: Well Planning-Pioneer-Oooguruk TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-15i Survey Calculation Method: Minimum Curvature Wellbore: ODSN-15i IN12 Design: ODSN-15i IN12 wp07 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (ft) (?) (?) (ft) ft (ft) (ft) (ft) (ft) 2,768.85 3,200.0 55.88 241.42 2,825.0 2,768.8 -103.4 -1,166.6 6,030,967.53 468,669.04 3.00 1,109.59 3,232.9 56.77 240.91 2,843.3 2,787.1 -116.6 -1,190.6 6,030,954.44 468,645.03 3.00 1,129.77 3,300.0 58.62 241.84 2,879.1 2,822.9 -143.7 -1,240.4 6,030,927.46 468,595.12 3.00 1,171.79 3,329.2 59.43 242.24 2,894.2 2,838.0 -155.5 -1,262.5 6,030,915.80 468,572.92 3.00 1,190.55 Tuffaceous Shales 3,400.0 61.39 243.17 2,929.1 2,872.9 -183.7 -1,317.2 6,030,887.81 468,518.14 3.00 1,237.05 3,499.4 64.16 244.42 2,974.6 2,918.4 -222.7 -1,396.5 6,030,849.12 468,438.69 3.00 1,304.95 End Dir 3499.40'MD,2974.60'TVD 3,500.0 64.16 244.42 2,974.9 2,918.7 -223.0 -1,397.0 6,030,848.88 468,438.21 0.00 1,305.37 3,557.7 64.16 244.42 3,000.0 2,943.8 -245.4 -1,443.8 6,030,826.66 468,391.30 0.00 1,345.61 11 3/4" 3,600.0 64.16 244.42 3,018.4 2,962.2 -261.8 -1,478.2 6,030,810.35 468,356.88 0.00 1,375.13 3,700.0 64.16 244.42 3,062.0 3,005.8 -300.7 -1,559.4 6,030,771.82 468,275.55 0.00 1,444.89 3,800.0 64.16 244.42 3,105.6 3,049.4 -339.6 -1,640.5 6,030,733.29 468,194.23 0.00 1,514.65 3,900.0 64.16 244.42 3,149.2 3,093.0 -378.4 -1,721.7 6,030,694.76 468,112.90 0.00 1,584.41 4,000.0 64.16 244.42 3,192.8 3,136.6 -417.3 -1,802.9 6,030,656.22 468,031.57 0.00 1,654.17 4,100.0 64.16 244.42 3,236.4 3,180.2 -456.2 -1,884.1 6,030,617.69 467,950.25 0.00 1,723.93 4,200.0 64.16 244.42 3,280.0 3,223.8 -495.0 -1,965.2 6,030,579.16 467,868.92 0.00 1,793.68 4,300.0 64.16 244.42 3,323.5 3,267.3 -533.9 -2,046.4 6,030,540.63 467,787.59 0.00 1,863.44 4,400.0 64.16 244.42 3,367.1 3,310.9 -572.7 -2,127.6 6,030,502.10 467,706.27 0.00 1,933.20 4,500.0 64.16 244.42 3,410.7 3,354.5 -611.6 -2,208.8 6,030,463.56 467,624.94 0.00 2,002.96 4,600.0 64.16 244.42 3,454.3 3,398.1 -650.5 -2,290.0 6,030,425.03 467,543.61 0.00 2,072.72 4,700.0 64.16 244.42 3,497.9 3,441.7 -689.3 -2,371.1 6,030,386.50 467,462.29 0.00 2,142.48 4,800.0 64.16 244.42 3,541.5 3,485.3 -728.2 -2,452.3 6,030,347.97 467,380.96 0.00 2,212.24 4,900.0 64.16 244.42 3,585.0 3,528.8 -767.1 -2,533.5 6,030,309.43 467,299.63 0.00 2,282.00 5,000.0 64.16 244.42 3,628.6 3,572.4 -805.9 -2,614.7 6,030,270.90 467,218.31 0.00 2,351.76 5,100.0 64.16 244.42 3,672.2 3,616.0 -844.8 -2,695.8 6,030,232.37 467,136.98 0.00 2,421.52 5,200.0 64.16 244.42 3,715.8 3,659.6 -883.7 -2,777.0 6,030,193.84 467,055.65 0.00 2,491.28 5,300.0 64.16 244.42 3,759.4 3,703.2 -922.5 -2,858.2 6,030,155.31 466,974.33 0.00 2,561.04 5,400.0 64.16 244.42 3,803.0 3,746.8 -961.4 -2,939.4 6,030,116.77 466,893.00 0.00 2,630.80 5,500.0 64.16 244.42 3,846.5 3,790.3 -1,000.3 -3,020.6 6,030,078.24 466,811.67 0.00 2,700.56 5,600.0 64.16 244.42 3,890.1 3,833.9 -1,039.1 -3,101.7 6,030,039.71 466,730.35 0.00 2,770.31 5,700.0 64.16 244.42 3,933.7 3,877.5 -1,078.0 -3,182.9 6,030,001.18 466,649.02 0.00 2,840.07 5,800.0 64.16 244.42 3,977.3 3,921.1 -1,116.9 -3,264.1 6,029,962.64 466,567.69 0.00 2,909.83 5,900.0 64.16 244.42 4,020.9 3,964.7 -1,155.7 -3,345.3 6,029,924.11 466,486.36 0.00 2,979.59 6,000.0 64.16 244.42 4,064.5 4,008.3 -1,194.6 -3,426.4 6,029,885.58 466,405.04 0.00 3,049.35 6,100.0 64.16 244.42 4,108.1 4,051.9 -1,233.5 -3,507.6 6,029,847.05 466,323.71 0.00 3,119.11 6,200.0 64.16 244.42 4,151.6 4,095.4 -1,272.3 -3,588.8 6,029,808.52 466,242.38 0.00 3,188.87 6,300.0 64.16 244.42 4,195.2 4,139.0 -1,311.2 -3,670.0 6,029,769.98 466,161.06 0.00 3,258.63 6,400.0 64.16 244.42 4,238.8 4,182.6 -1,350.1 -3,751.2 6,029,731.45 466,079.73 0.00 3,328.39 6,474.3 64.16 244.42 4,271.2 4,215.0 -1,379.0 -3,811.5 6,029,702.81 466,019.29 0.00 3,380.24 Brook 2b 6,500.0 64.16 244.42 4,282.4 4,226.2 -1,388.9 -3,832.3 6,029,692.92 465,998.40 0.00 3,398.15 6,600.0 64.16 244.42 4,326.0 4,269.8 -1,427.8 -3,913.5 6,029,654.39 465,917.08 0.00 3,467.91 6,700.0 64.16 244.42 4,369.6 4,313.4 -1,466.7 -3,994.7 6,029,615.86 465,835.75 0.00 3,537.67 3/9/2010 5:03:12PM Page 5 COMPASS 2003.16 Build 42B Halliburton Company HALL HALLIBURTOlt Standard Proposal Report Database: .Pioneer Alaska Local Co-ordinate Reference: Well ODSN-15i-Slot ODS-15 Company: Well Planning-Pioneer-Oooguruk TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-15i Survey Calculation Method: Minimum Curvature Wellbore: ODSN-15i IN12 Design: ODSN-15i IN12 wp07 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (ft) (?) (?) (ft) ft (ft) (ft) (ft) (ft) 4,356.94 6,800.0 64.16 244.42 4,413.1 4,356.9 -1,505.5 -4,075.9 6,029,577.32 465,754.42 0.00 3,607.43 6,900.0 64.16 244.42 4,456.7 4,400.5 -1,544.4 -4,157.1 6,029,538.79 465,673.10 0.00 3,677.19 7,000.0 64.16 244.42 4,500.3 4,444.1 -1,583.3 -4,238.2 6,029,500.26 465,591.77 0.00 3,746.95 7,100.0 64.16 244.42 4,543.9 4,487.7 -1,622.1 -4,319.4 6,029,461.73 465,510.44 0.00 3,816.70 7,200.0 64.16 244.42 4,587.5 4,531.3 -1,661.0 -4,400.6 6,029,423.19 465,429.12 0.00 3,886.46 7,300.0 64.16 244.42 4,631.1 4,574.9 -1,699.9 -4,481.8 6,029,384.66 465,347.79 0.00 3,956.22 7,400.0 64.16 244.42 4,674.7 4,618.5 -1,738.7 -4,562.9 6,029,346.13 465,266.46 0.00 4,025.98 7,500.0 64.16 244.42 4,718.2 4,662.0 -1,777.6 -4,644.1 6,029,307.60 465,185.14 0.00 4,095.74 7,600.0 64.16 244.42 4,761.8 4,705.6 -1,816.5 -4,725.3 6,029,269.07 465,103.81 0.00 4,165.50 7,700.0 64.16 244.42 4,805.4 4,749.2 -1,855.3 -4,806.5 6,029,230.53 465,022.48 0.00 4,235.26 7,800.0 64.16 244.42 4,849.0 4,792.8 -1,894.2 -4,887.7 6,029,192.00 464,941.16 0.00 4,305.02 7,900.0 64.16 244.42 4,892.6 4,836.4 -1,933.1 -4,968.8 6,029,153.47 464,859.83 0.00 4,374.78 8,000.0 64.16 244.42 4,936.2 4,880.0 -1,971.9 -5,050.0 6,029,114.94 464,778.50 0.00 4,444.54 8,100.0 64.16 244.42 4,979.7 4,923.5 -2,010.8 -5,131.2 6,029,076.40 464,697.18 0.00 4,514.30 8,130.9 64.16 244.42 4,993.2 4,937.0 -2,022.8 -5,156.3 6,029,064.51 464,672.06 0.00 4,535.84 Top Torok Ss 8,200.0 64.16 244.42 5,023.3 4,967.1 -2,049.7 -5,212.4 6,029,037.87 464,615.85 0.00 4,584.06 8,300.0 64.16 244.42 5,066.9 5,010.7 -2,088.5 -5,293.5 6,028,999.34 464,534.52 0.00 4,653.82 8,400.0 64.16 244.42 5,110.5 5,054.3 -2,127.4 -5,374.7 6,028,960.81 464,453.20 0.00 4,723.58 8,500.0 64.16 244.42 5,154.1 5,097.9 -2,166.2 -5,455.9 6,028,922.28 464,371.87 0.00 4,793.33 8,600.0 64.16 244.42 5,197.7 5,141.5 -2,205.1 -5,537.1 6,028,883.74 464,290.54 0.00 4,863.09 8,665.5 64.16 244.42 5,226.2 5,170.0 -2,230.6 -5,590.2 6,028,858.51 464,237.29 0.00 4,908.77 Base Torok Ss 8,688.4 64.16 244.42 5,236.2 5,180.0 -2,239.5 -5,608.9 6,028,849.67 464,218.63 0.00 4,924.78 9 5/8" 8,700.0 64.16 244.42 5,241.2 5,185.0 -2,244.0 -5,618.3 6,028,845.21 464,209.22 0.00 4,932.85 8,800.0 64.16 244.42 5,284.8 5,228.6 -2,282.8 -5,699.4 6,028,806.68 464,127.89 0.00 5,002.61 8,842.2 64.16 244.42 5,303.2 5,247.0 -2,299.2 -5,733.7 6,028,790.42 464,093.57 0.00 5,032.05 Start Dir 3.0/100'8842.20'MD,5303.20'TVD 8,900.0 64.12 246.34 5,328.4 5,272.2 -2,320.9 -5,781.0 6,028,768.94 464,046.21 3.00 5,072.91 9,000.0 64.11 249.68 5,372.1 5,315.9 -2,354.6 -5,864.4 6,028,735.60 463,962.67 3.00 5,146.05 9,100.0 64.17 253.01 5,415.7 5,359.5 -2,383.4 -5,949.6 6,028,707.17 463,877.33 3.00 5,222.13 9,200.0 64.31 256.34 5,459.2 5,403.0 -2,407.2 -6,036.5 6,028,683.72 463,790.39 3.00 5,300.94 9,300.0 64.53 259.65 5,502.4 5,446.2 -2,425.9 -6,124.7 6,028,665.33 463,702.12 3.00 5,382.27 9,400.0 64.82 262.96 5,545.2 5,489.0 -2,439.6 -6,214.0 6,028,652.03 463,612.74 3.00 5,465.88 9,500.0 65.18 266.24 5,587.4 5,531.2 -2,448.1 -6,304.2 6,028,643.88 463,522.50 3.00 5,551.56 9,600.0 65.62 269.51 5,629.1 5,572.9 -2,451.5 -6,395.1 6,028,640.88 463,431.65 3.00 5,639.07 9,700.0 66.12 272.75 5,669.9 5,613.7 -2,449.7 -6,486.3 6,028,643.05 463,340.44 3.00 5,728.16 9,800.0 66.69 275.96 5,710.0 5,653.8 -2,442.7 -6,577.7 6,028,650.38 463,249.11 3.00 5,818.60 9,859.1 67.06 277.85 5,733.2 5,677.0 -2,436.2 -6,631.6 6,028,657.14 463,195.16 3.00 5,872.61 Violet 4 Fault-Violet 4 Fault 9,872.0 67.15 278.26 5,738.2 5,682.0 -2,434.5 -6,643.4 6,028,658.85 463,183.44 3.00 5,884.39 Top Hrz 9,900.0 67.33 279.15 5,749.0 5,692.8 -2,430.6 -6,668.9 6,028,662.86 463,157.93 3.00 5,910.13 10,000.0 68.03 282.30 5,787.0 5,730.8 -2,413.4 -6,759.8 6,028,680.44 463,067.13 3.00 6,002.50 3/9/2010 5:03:12PM Page 6 COMPASS 2003.16 Build 428 Halliburton Company HALL HALLIBURT01111 Standard Proposal Report Database: .Pioneer Alaska Local Co-ordinate Reference: Well ODSN-15i-Slot ODS-15 Company: Well Planning-Pioneer-Oooguruk TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-15i Survey Calculation Method: Minimum Curvature Wellbore: ODSN-15i IN12 Design: ODSN-15i IN12 wp07 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +El-W Northing Easting DLS Vert Section (ft) (?) (?) (ft) ft (ft) (ft) (ft) (ft) 5,767.63 10,100.0 68.79 285.42 5,823.8 5,767.6 -2,391.1 -6,850.0 6,028,703.08 462,976.97 3.00 6,095.47 10,200.0 69.60 288.51 5,859.4 5,803.2 -2,363.8 -6,939.4 6,028,730.72 462,887.70 3.00 6,188.77 10,263.5 70.15 290.45 5,881.2 5,825.0 -2,344.0 -6,995.6 6,028,750.83 462,831.59 3.00 6,248.07 Base Hrz 10,300.0 70.47 291.57 5,893.5 5,837.3 -2,331.6 -7,027.7 6,028,763.29 462,799.55 3.00 6,282.16 10,400.0 71.39 294.59 5,926.2 5,870.0 -2,294.6 -7,114.6 6,028,800.68 462,712.78 3.00 6,375.37 10,500.0 72.36 297.58 5,957.3 5,901.1 -2,252.8 -7,200.0 6,028,842.81 462,627.61 3.00 6,468.14 10,512.9 72.49 297.96 5,961.2 5,905.0 -2,247.1 -7,210.9 6,028,848.59 462,616.73 3.00 6,480.10 Kalubik Mkr 10,600.0 73.37 300.53 5,986.8 5,930.6 -2,206.4 -7,283.5 6,028,889.55 462,544.29 3.00 6,560.24 10,700.0 74.42 303.45 6,014.5 5,958.3 -2,155.5 -7,365.0 6,028,940.77 462,463.04 3.00 6,651.39 10,732.7 74.78 304.41 6,023.2 5,967.0 -2,137.9 -7,391.2 6,028,958.49 462,436.92 3.00 6,680.99 Top Kup C 10,753.3 75.00 305.00 6,028.6 5,972.4 -2,126.6 -7,407.5 6,028,969.86 462,420.65 3.00 6,699.51 End Dir 10753.30'MD,6028.60'TVD 10,779.0 75.00 305.00 6,035.2 5,979.0 -2,112.4 -7,427.8 6,028,984.15 462,400.41 0.00 6,722.58 Base Kuparuk 10,800.0 75.00 305.00 6,040.6 5,984.4 -2,100.7 -7,444.4 6,028,995.88 462,383.81 0.00 6,741.51 10,900.0 75.00 305.00 6,066.5 6,010.3 -2,045.3 -7,523.6 6,029,051.60 462,304.92 0.00 6,831.44 10,929.6 75.00 305.00 6,074.2 6,018.0 -2,028.9 -7,547.0 6,029,068.11 462,281.54 0.00 6,858.10 BCU 11,000.0 75.00 305.00 6,092.4 6,036.2 -1,989.9 -7,602.7 6,029,107.32 462,226.03 0.00 6,921.38 I 11,053.3 75.00 305.00 6,106.2 6,050.0 -1,960.4 -7,644.8 6,029,137.00 462,184.00 0.00 6,969.29 Top Nuiqsut-IN12 v7 T1 11,065.0 75.00 305.00 6,109.2 6,053.0 -1,953.9 -7,654.1 6,029,143.53 462,174.75 0.00 6,979.84 7" 11,085.0 75.00 305.00 6,114.4 6,058.2 -1,942.8 -7,669.9 6,029,154.68 462,158.97 0.00 6,997.82 Start Dir 3.0/100'11085.00'MD,6114.40'TVD 11,100.0 75.39 305.24 6,118.2 6,062.0 -1,934.5 -7,681.8 6,029,163.07 462,147.14 2.99 7,011.32 11,200.0 77.98 306.79 6,141.3 6,085.1 -1,877.2 -7,760.5 6,029,220.60 462,068.69 3.00 7,101.26 11,300.0 80.57 308.32 6,159.9 6,103.7 -1,817.4 -7,838.4 6,029,280.79 461,991.06 3.00 7,191.04 11,400.0 83.18 309.82 6,174.0 6,117.8 -1,755.0 -7,915.2 6,029,343.48 461,914.47 3.00 7,280.41 11,500.0 85.79 311.31 6,183.6 6,127.4 -1,690.2 -7,990.8 6,029,408.51 461,839.14 3.00 7,369.12 11,600.0 88.40 312.79 6,188.7 6,132.5 -1,623.4 -8,065.0 6,029,475.68 461,765.26 3.00 7,456.92 11,653.9 89.81 313.58 6,189.5 6,133.3 -1,586.5 -8,104.3 6,029,512.72 461,726.12 3.00 7,503.79 End Dir 11653.90'MD,6189.50'TVD 11,700.0 89.81 313.58 6,189.7 6,133.5 -1,554.7 -8,137.7 6,029,544.63 461,692.86 0.00 7,543.72 11,800.0 89.81 313.58 6,190.0 6,133.8 -1,485.8 -8,210.1 6,029,613.85 461,620.70 0.00 7,630.35 11,900.0 89.81 313.58 6,190.4 6,134.2 -1,416.8 -8,282.6 6,029,683.07 461,548.55 0.00 7,716.97 12,000.0 89.81 313.58 6,190.7 6,134.5 -1,347.9 -8,355.0 6,029,752.30 461,476.40 0.00 7,803.59 12,100.0 89.81 313.58 6,191.0 6,134.8 -1,279.0 -8,427.4 6,029,821.52 461,404.24 0.00 7,890.21 12,143.8 89.81 313.58 6,191.2 6,135.0 -1,248.8 -8,459.2 6,029,851.84 461,372.64 0.00 7,928.16 Start Dir 3.0/100'12143.80'MD,6191.20'TVD 12,159.2 90.00 314.00 6,191.2 6,135.0 -1,238.1 -8,470.3 6,029,862.55 461,361.55 2.99 7,941.49 1N12 v7 T3 3/9/2010 5:03:12PM Page 7 COMPASS 2003.16 Build 42B Halliburton Company HALLIBURTON Standard Proposal Report Database: .Pioneer Alaska Local Co-ordinate Reference: Well ODSN-15i-Slot ODS-15 Company: Well Planning-Pioneer-Oooguruk TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-15i Survey Calculation Method: Minimum Curvature Wellbore: ODSN-15i IN12 Design: ODSN-15i IN12 wp07 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (ft) (?) (?) (ft) ft (ft) (ft) (ft) (ft) 6,134.57 12,200.0 91.21 314.17 6,190.8 6,134.6 -1,209.7 -8,499.6 6,029,891.04 461,332.38 3.00 7,976.63 12,245.9 92.58 314.36 6,189.3 6,133.1 -1,177.7 -8,532.5 6,029,923.19 461,299.66 3.00 8,016.09 End Dir 12245.90'MD,6189.30'TVD 12,300.0 92.58 314.36 6,186.8 6,130.6 -1,139.9 -8,571.1 6,029,961.12 461,261.18 0.00 8,062.53 12,400.0 92.58 314.36 6,182.3 6,126.1 -1,070.1 -8,642.5 6,030,031.25 461,190.04 0.00 8,148.38 12,500.0 92.58 314.36 6,177.8 6,121.6 -1,000.2 -8,713.9 6,030,101.38 461,118.91 0.00 8,234.23 12,600.0 92.58 314.36 6,173.3 6,117.1 -930.4 -8,785.4 6,030,171.51 461,047.78 0.00 8,320.08 12,700.0 92.58 314.36 6,168.8 6,112.6 -860.5 -8,856.8 6,030,241.63 460,976.64 0.00 8,405.93 12,800.0 92.58 314.36 6,164.3 6,108.1 -790.7 -8,928.2 6,030,311.76 460,905.51 0.00 8,491.77 12,900.0 92.58 314.36 6,159.9 6,103.7 -720.9 -8,999.6 6,030,381.89 460,834.38 0.00 8,577.62 12,914.9 92.58 314.36 6,159.2 6,103.0 -710.5 -9,010.3 6,030,392.34 460,823.78 0.00 8,590.41 Start Dir 3.0/100'12914.90'MD,6159.20'TVD 12,966.9 94.00 315.00 6,156.2 6,100.0 -673.9 -9,047.2 6,030,429.00 460,787.00 3.00 8,634.90 IN12 v7 T4 13,000.0 93.60 315.91 6,154.0 6,097.8 -650.4 -9,070.4 6,030,452.61 460,763.95 3.00 8,662.93 13,043.4 93.07 317.10 6,151.5 6,095.3 -619.0 -9,100.2 6,030,484.16 460,734.26 3.00 8,699.31 End Dir 13043.40'MD,6151.50'TVD 13,100.0 93.07 317.10 6,148.5 6,092.3 -577.6 -9,138.7 6,030,525.71 460,695.96 0.00 8,746.44 13,200.0 93.07 317.10 6,143.1 6,086.9 -504.4 -9,206.6 6,030,599.13 460,628.29 0.00 8,829.71 13,300.0 93.07 317.10 6,137.8 6,081.6 -431.3 -9,274.6 6,030,672.55 460,560.62 0.00 8,912.98 13,400.0 93.07 317.10 6,132.4 6,076.2 -358.1 -9,342.6 6,030,745.97 460,492.95 0.00 8,996.25 13,500.0 93.07 317.10 6,127.0 6,070.8 -285.0 -9,410.5 6,030,819.39 460,425.28 0.00 9,079.52 13,600.0 93.07 317.10 6,121.7 6,065.5 -211.8 -9,478.5 6,030,892.81 460,357.62 0.00 9,162.79 13,700.0 93.07 317.10 6,116.3 6,060.1 -138.7 -9,546.5 6,030,966.23 460,289.95 0.00 9,246.06 13,800.0 93.07 317.10 6,111.0 6,054.8 -65.5 -9,614.5 6,031,039.65 460,222.28 0.00 9,329.34 13,838.4 93.07 317.10 6,108.9 6,052.7 -37.4 -9,640.6 6,031,067.84 460,196.29 0.00 9,361.31 Start Dir 3.0/100'13838.40'MD,6108.90'TVD 13,900.0 91.22 317.09 6,106.6 6,050.4 7.7 -9,682.5 6,031,113.09 460,154.58 3.00 9,412.64 13,940.7 90.00 317.08 6,106.2 6,050.0 37.5 -9,710.2 6,031,143.00 460,127.00 3.00 9,446.58 IN12 v7 T5 13,967.5 89.20 317.08 6,106.4 6,050.2 57.1 -9,728.4 6,031,162.71 460,108.82 3.00 9,468.94 End Dir 13967.50'MD,6106.40'TVD 14,000.0 89.19 317.08 6,106.8 6,050.6 80.9 -9,750.6 6,031,186.59 460,086.80 0.00 9,496.05 14,100.0 89.19 317.08 6,108.3 6,052.1 154.1 -9,818.6 6,031,260.09 460,019.01 0.00 9,579.45 14,200.0 89.19 317.08 6,109.7 6,053.5 227.3 -9,886.7 6,031,333.58 459,951.23 0.00 9,662.85 14,300.0 89.19 317.08 6,111.1 6,054.9 300.6 -9,954.8 6,031,407.08 459,883.45 0.00 9,746.25 14,400.0 89.19 317.08 6,112.5 6,056.3 373.8 -10,022.9 6,031,480.57 459,815.67 0.00 9,829.65 14,500.0 89.19 317.08 6,113.9 6,057.7 447.0 -10,091.0 6,031,554.07 459,747.88 0.00 9,913.05 14,600.0 89.19 317.08 6,115.3 6,059.1 520.3 -10,159.1 6,031,627.56 459,680.10 0.00 9,996.45 14,700.0 89.19 317.08 6,116.7 6,060.5 593.5 -10,227.2 6,031,701.06 459,612.32 0.00 10,079.85 14,800.0 89.19 317.08 6,118.1 6,061.9 666.7 -10,295.3 6,031,774.55 459,544.54 0.00 10,163.25 14,900.0 89.19 317.08 6,119.5 6,063.3 739.9 -10,363.3 6,031,848.05 459,476.75 0.00 10,246.65 15,000.0 89.19 317.08 6,120.9 6,064.7 813.2 -10,431.4 6,031,921.54 459,408.97 0.00 10,330.05 15,100.0 89.19 317.08 6,122.3 6,066.1 886.4 -10,499.5 6,031,995.04 459,341.19 0.00 10,413.45 15,200.0 89.19 317.08 6,123.7 6,067.5 959.6 -10,567.6 6,032,068.53 459,273.41 0.00 10,496.85 3/9/2010 5:03:12PM Page 8 COMPASS 2003.16 Build 428 Halliburton Company HALLIBURTOle Standard Proposal Report Database: .Pioneer Alaska Local Co-ordinate Reference: Well ODSN-15i-Slot ODS-15 Company: Well Planning-Pioneer-Oooguruk TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-15i Survey Calculation Method: Minimum Curvature Wellbore: ODSN-15i IN12 Design: ODSN-15i IN12 wp07 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (ft) (?) (?) (ft) ft (ft) (ft) (ft) (ft) 6,068.92 15,300.0 89.19 317.08 6,125.1 6,068.9 1,032.8 -10,635.7 6,032,142.03 459,205.62 0.00 10,580.25 15,371.3 89.19 317.08 6,126.1 6,069.9 1,085.0 -10,684.2 6,032,194.43 459,157.29 0.00 10,639.71 Start Dir 3.0/100'15371.30'MD,6126.10'TVD 15,376.2 89.06 317.02 6,126.2 6,070.0 1,088.6 -10,687.5 6,032,198.00 459,154.00 2.99 10,643.76 IN12 v7 T6 15,376.7 89.05 317.02 6,126.2 6,070.0 1,089.0 -10,687.9 6,032,198.40 459,153.63 3.00 10,644.22 End Dir 15376.70'MD,6126.20'TVD 15,400.0 89.05 317.02 6,126.6 6,070.4 1,106.0 -10,703.8 6,032,215.51 459,137.82 0.00 10,663.66 15,435.0 89.05 317.02 6,127.2 6,071.0 1,131.6 -10,727.7 6,032,241.20 459,114.07 0.00 10,692.87 Green 3 Fault-Green 3 Fault 15,500.0 89.05 317.02 6,128.3 6,072.1 1,179.2 -10,772.0 6,032,288.93 459,069.96 0.00 10,747.12 15,600.0 89.05 317.02 6,129.9 6,073.7 1,252.3 -10,840.1 6,032,362.35 459,002.11 0.00 10,830.57 15,700.0 89.05 317.02 6,131.6 6,075.4 1,325.5 -10,908.3 6,032,435.77 458,934.25 0.00 10,914.03 15,800.0 89.05 317.02 6,133.3 6,077.1 1,398.7 -10,976.4 6,032,509.19 458,866.39 0.00 10,997.48 15,900.0 89.05 317.02 6,134.9 6,078.7 1,471.8 -11,044.6 6,032,582.61 458,798.53 0.00 11,080.94 16,000.0 89.05 317.02 6,136.6 6,080.4 1,545.0 -11,112.8 6,032,656.03 458,730.68 0.00 11,164.39 16,100.0 89.05 317.02 6,138.3 6,082.1 1,618.1 -11,180.9 6,032,729.45 458,662.82 0.00 11,247.85 16,200.0 89.05 317.02 6,139.9 6,083.7 1,691.3 -11,249.1 6,032,802.87 458,594.96 0.00 11,331.30 16,261.0 89.05 317.02 6,140.9 6,084.7 1,735.9 -11,290.7 6,032,847.66 458,553.57 0.00 11,382.21 Start Dir 3.0/100'16261.00'MD,6140.90'TVD 16,292.8 90.00 317.04 6,141.2 6,085.0 1,759.1 -11,312.3 6,032,871.00 458,532.00 3.00 11,408.74 IN12v7T7 16,300.0 90.22 317.04 6,141.2 6,085.0 1,764.4 -11,317.2 6,032,876.30 458,527.11 3.00 11,414.76 16,400.0 93.22 317.04 6,138.2 6,082.0 1,837.6 -11,385.4 6,032,949.70 458,459.30 3.00 11,498.16 16,417.5 93.74 317.04 6,137.1 6,080.9 1,850.3 -11,397.3 6,032,962.53 458,447.44 3.00 11,512.74 End Dir 16417.50'MD,6137.10'TVD 16,500.0 93.74 317.04 6,131.7 6,075.5 1,910.6 -11,453.4 6,033,023.00 458,391.59 0.00 11,581.44 16,600.0 93.74 317.04 6,125.2 6,069.0 1,983.6 -11,521.4 6,033,096.29 458,323.88 0.00 11,664.72 16,700.0 93.74 317.04 6,118.7 6,062.5 2,056.6 -11,589.4 6,033,169.58 458,256.18 0.00 11,747.99 16,800.0 93.74 317.04 6,112.2 6,056.0 2,129.7 -11,657.4 6,033,242.87 458,188.47 0.00 11,831.27 16,900.0 93.74 317.04 6,105.6 6,049.4 2,202.7 -11,725.4 6,033,316.16 458,120.77 0.00 11,914.54 17,000.0 93.74 317.04 6,099.1 6,042.9 2,275.7 -11,793.4 6,033,389.45 458,053.07 0.00 11,997.82 17,035.7 93.74 317.04 6,096.8 6,040.6 2,301.8 -11,817.7 6,033,415.62 458,028.89 0.00 12,027.55 Start Dir 3.0/100'17035.70'MD,6096.80'TVD 17,044.4 94.00 317.06 6,096.2 6,040.0 2,308.1 -11,823.6 6,033,422.00 458,023.00 2.98 12,034.80 IN12v7T8 17,100.0 95.67 317.06 6,091.5 6,035.3 2,348.7 -11,861.3 6,033,462.70 457,985.44 3.00 12,081.01 17,200.0 98.67 317.06 6,079.0 6,022.8 2,421.3 -11,928.9 6,033,535.60 457,918.16 3.00 12,163.77 17,222.8 99.35 317.06 6,075.5 6,019.3 2,437.8 -11,944.3 6,033,552.15 457,902.89 3.00 12,182.56 End Dir 17222.80'MD,6075.50'TVD 17,300.0 99.35 317.06 6,062.9 6,006.7 2,493.6 -11,996.1 6,033,608.12 457,851.24 0.00 12,246.11 17,400.0 99.35 317.06 6,046.7 5,990.5 2,565.8 -12,063.4 6,033,680.62 457,784.33 0.00 12,328.42 17,500.0 99.35 317.06 6,030.4 5,974.2 2,638.0 -12,130.6 6,033,753.13 457,717.42 0.00 12,410.74 17,526.0 99.35 317.06 6,026.2 5,970.0 2,656.8 -12,148.1 6,033,772.00 457,700.00 0.00 12,432.17 Start Dir 3.0/100'17526.00'MD,6026.20'TVD-IN12 v7 T9 3/9/2010 5:03:12PM Page 9 COMPASS 2003.16 Build 428 Halliburton Company HALLIBURTON Standard Proposal Report Database: .Pioneer Alaska Local Co-ordinate Reference: Well ODSN-15i-Slot ODS-15 Company: Well Planning-Pioneer-Oooguruk TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) ' Site: Oooguruk Drill Site North Reference: True Well: ODSN-15i Survey Calculation Method: Minimum Curvature , Weilbore: ODSN-15i IN12 Design: ODSN-15i IN12 wp07 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +E/-W Northing Easting DLS Vert Section (ft) (?) (?) (ft) ft (ft) (ft) (ft) (ft) 5,959.40 17,600.0 97.13 317.06 6,015.6 5,959.4 2,710.4 -12,197.9 6,033,825.79 457,650.36 3.00 12,493.24 17,700.0 94.13 317.06 6,005.8 5,949.6 2,783.3 -12,265.7 6,033,898.91 457,582.88 3.00 12,576.25 17,800.0 91.13 317.06 6,001.2 5,945.0 2,856.4 -12,333.7 6,033,972.30 457,515.15 3.00 12,659.58 17,837.7 90.00 317.06 6,000.8 5,944.6 2,884.0 -12,359.4 6,034,000.00 457,489.58 3.00 12,691.03 End Dir 17837.70'MD,6000.80'TVD 17,900.0 90.00 317.06 6,000.8 5,944.6 2,929.6 -12,401.9 6,034,045.78 457,447.34 0.00 12,743.00 18,000.0 90.00 317.06 6,000.8 5,944.6 3,002.8 -12,470.0 6,034,119.26 457,379.52 0.00 12,826.43 18,026.0 90.00 317.06 6,000.8 • 5,944.6 3,021.9 -12,487.7 6,034,138.37 457,361.89 0.00 12,848.12 Total Depth at 18026.00'MD,6000.80'TVD-4 1/2" 3/9/2010 5:03:12PM Page 10 COMPASS 2003.16 Build 428 Halliburton Company H HALLIBURTOle Standard Proposal Report Database: .Pioneer Alaska Local Co-ordinate Reference: Well ODSN-15i-Slot ODS-15 Company: Well Planning-Pioneer-Oooguruk TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-15i Survey Calculation Method: Minimum Curvature Wellbore: ODSN-15i IN12 Design: ODSN-15i IN12 wp07 Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting -Shape (?) (?) (ft) (ft) (ft) (ft) (ft) 0.00 0.00 6,106.2 -1,960.4 -7,644.8 6,029,137.00 462,184.00 -plan hits target -Point IN12 v7 T4 0.00 0.00 6,156.2 -673.9 -9,047.2 6,030,429.00 460,787.00 -plan hits target -Point Violet 4 Fault 0.00 0.00 6,209.2 -4,487.2 -5,557.8 6,026,602.00 464,260.52 -plan misses by 2249.8ft at 9377.6ft MD(5535.6 TVD,-2437.0 N,-6193.9 E) -Polygon Point 1 6,209.2 -5,146.4 -5,353.6 6,025,942.04 464,462.02 Point2 6,209.2 -2,509.5 -6,170.3 6,028,581.97 463,656.11 Point 3 6,209.2 -1,850.8 -6,525.4 6,029,242.04 463,303.72 Point4 6,209.2 -1,191.8 -6,785.7 6,029,902.02 463,046.12 Point 5 6,209.2 -1,850.6 -6,473.2 6,029,242.03 463,355.91 Point 6 6,209.2 -2,509.4 -6,154.2 6,028,582.00 463,672.21 Point 7 6,209.2 -2,948.6 -5,955.9 6,028,142.05 463,868.70 Point 8 6,209.2 -3,827.9 -5,738.0 6,027,261.96 464,083.01 Point 9 6,209.2 -4,706.9 -5,468.1 6,026,381.96 464,349.31 IN12 v7 T3 0.00 0.00 6,191.2 -1,238.1 -8,470.3 6,029,862.55 461,361.55 -plan hits target -Point IN12 v7 T7 0.00 0.00 6,141.2 1,759.1 -11,312.3 6,032,871.00 458,532.00 -plan hits target -Point IN12 v7 T6 0.00 0.00 6,126.2 1,088.6 -10,687.5 6,032,198.00 459,154.00 -plan hits target -Point IN12 v7 T5 0.00 0.00 6,106.2 37.5 -9,710.2 6,031,143.00 460,127.00 -plan hits target -Point IN12 v7 T8 0.00 0.00 6,096.2 2,308.1 -11,823.6 6,033,422.00 458,023.00 -plan hits target -Point 1N12v7T9 0.00 0.00 6,026.2 2,656.8 -12,148.1 6,033,772.00 457,700.00 -plan hits target -Point Green 3 Fault 0.00 0.00 6,100.0 550.0 -10,627.9 6,031,659.22 459,211.44 -plan misses by 323.7ft at 14940.8ft MD(6120.1 TVD,769.8 N,-10391.1 E) -Polygon Point 1 6,100.0 550.0 -10,627.9 6,031,659.22 459,211.44 Point2 6,100.0 1,021.9 -10,779.8 6,032,131.68 459,061.47 Point 3 6,100.0 1,995.1 -10,914.3 6,033,105.32 458,930.93 Point 4 6,100.0 2,305.5 -11,025.9 6,033,416.14 458,820.61 Point 5 6,100.0 2,970.2 -11,411.8 6,034,082.34 458,437.45 Point 6 6,100.0 3,629.0 -11,807.0 6,034,742.67 458,044.96 Point 7 6,100.0 4,068.0 -11,988.2 6,035,182.36 457,865.56 Point 8 6,100.0 3,408.9 -11,666.3 6,034,522.02 458,184.75 Point9 6,100.0 2,531.7 -11,117.8 6,033,642.69 458,729.63 Point 10 6,100.0 2,092.0 -10,898.6 6,033,202.15 458,947.03 Point 11 6,100.0 1,872.4 -10,858.2 6,032,982.41 458,986.53 Point 12 6,100.0 992.6 -10,745.1 6,032,102.25 459,096.05 Point 13 6,100.0 550.0 -10,627.9 6,031,659.22 459,211.44 3/9/2010 5:03:12PM Page 11 COMPASS 2003.16 Build 428 Halliburton Company HALLIBURTON Standard Proposal Report Database: .Pioneer Alaska Local Co-ordinate Reference: Well ODSN-15i-Slot ODS-15 Company: Well Planning-Pioneer-Oooguruk TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-15i Survey Calculation Method: Minimum Curvature Wellbore: ODSN-15i 1N12 Design: ODSN-15i IN12 wp07 Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (in) (in) 3,557.7 3,000.0 11 3/4" 11.750 13.500 8,688.4 5,236.2 9 5/8" 9.625 11.750 11,065.0 6,109.2 7" 7.000 8.500 18,026.0 6,000.8 4 1/2" 4.500 6.125 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (ft) (ft) ft Name Lithology (7) (7) 11,053.3 6,106.2 Top Nuiqsut 0.00 10,263.5 5,881.2 Base Hrz 0.00 9,872.0 5,738.2 Top Hrz 0.00 2,429.5 2,290.2 Top West Sak 0.00 10,512.9 5,961.2 Kalubik Mkr 0.00 8,130.9 4,993.2 Top Torok Ss 0.00 10,732.7 6,023.2 Top Kup C 0.00 10,929.6 6,074.2 BCU 0.00 15,435.0 6,127.2 Green 3 Fault 0.00 8,665.5 5,226.2 Base Torok Ss 0.00 10,779.0 6,035.2 Base Kuparuk 0.00 3,329.2 2,894.2 Tuffaceous Shales 0.00 6,474.3 4,271.2 Brook 2b 0.00 9,859.1 5,733.2 Violet 4 Fault 0.00 3/9/2010 5:03:12PM Page 12 COMPASS 2003.16 Build 428 Halliburton Company HALLIBURTON Standard Proposal Report Database: .Pioneer Alaska Local Co-ordinate Reference: Well ODSN-15i-Slot ODS-15 Company: Well Planning-Pioneer-Oooguruk TVD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+13.5'@ 56.2ft(Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-15i Survey Calculation Method: Minimum Curvature Wellbore: ODSN-15i IN12 Design: ODSN-15i IN12wp07 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (ft) (ft) (ft) (ft) Comment 230.0 230.0 0.0 0.0 Start Dir 1.00/100'230.00'MD,230.00'TVD 300.0 300.0 0.1 -0.4 Start Dir 2.00/100'300.00'MD,300.00'TVD 854.1 850.0 16.2 -58.4 Start Dir 1.50/100'854.10'MD,850.00'TVD 1,697.5 1,650.0 86.1 -310.5 End Dir 1697.50'MD, 1650.00'TVD 1,807.4 1,750.0 98.2 -354.3 Start Dir 2.53/100'1807.40'MD, 1750.00'TVD 2,007.4 1,930.2 113.9 -439.5 Start Dir 3.0/100'2007.40'MD, 1930.10'TVD 3,499.4 2,974.6 -222.7 -1,396.5 End Dir 3499.40'MD,2974.60'TVD 8,842.2 5,303.2 -2,299.2 -5,733.7 Start Dir 3.0/100'8842.20'MD,5303.20'TVD 9,859.1 5,733.2 -2,436.2 -6,631.6 Violet 4 Fault 10,753.3 6,028.6 -2,126.6 -7,407.5 End Dir 10753.30'MD,6028.60'TVD 11,085.0 6,114.4 -1,942.8 -7,669.9 Start Dir 3.0/100'11085.00'MD,6114.40'TVD 11,653.9 6,189.5 -1,586.5 -8,104.3 End Dir 11653.90'MD,6189.50'TVD 12,143.8 6,191.2 -1,248.8 -8,459.2 Start Dir 3.0/100'12143.80'MD,6191.20'TVD 12,245.9 6,189.3 -1,177.7 -8,532.5 End Dir 12245.90'MD,6189.30'TVD 12,914.9 6,159.2 -710.5 -9,010.3 Start Dir 3.0/100'12914.90'MD,6159.20'TVD 13,043.4 6,151.5 -619.0 -9,100.2 End Dir 13043.40'MD,6151.50'TVD 13,838.4 6,108.9 -37.4 -9,640.6 Start Dir 3.0/100'13838.40'MD,6108.90'TVD 13,967.5 6,106.4 57.1 -9,728.4 End Dir 13967.50'MD,6106.40'TVD 15,371.3 6,126.1 1,085.0 -10,684.2 Start Dir 3.0/100'15371.30'MD,6126.10'TVD 15,376.7 6,126.2 1,089.0 -10,687.9 End Dir 15376.70'MD,6126.20'TVD 15,435.0 6,127.2 1,131.6 -10,727.7 Green 3 Fault 16,261.0 6,140.9 1,735.9 -11,290.7 Start Dir 3.0/100'16261.00'MD,6140.90'TVD 16,417.5 6,137.1 1,850.3 -11,397.3 End Dir 16417.50'MD,6137.10'TVD 17,035.7 6,096.8 2,301.8 -11,817.7 Start Dir 3.0/100'17035.70'MD,6096.80'TVD 17,222.8 6,075.5 2,437.8 -11,944.3 End Dir 17222.80'MD,6075.50'TVD 17,526.0 6,026.2 2,656.8 -12,148.0 Start Dir 3.0/100'17526.00'MD,6026.20'TVD 17,837.7 6,000.8 2,884.0 -12,359.4 End Dir 17837.70'MD,6000.80'TVD 18,026.0 6,000.8 3,021.9 -12,487.7 Total Depth at 18026.00'MD,6000.80'TVD 3/9/2010 5:03:12PM Page 13 COMPASS 2003.16 Build 428 S 0 LAJ 4 ! P f #,rr : ; j z4 d o e • -'.' i ' (5 r o • o n 4. s I 1 O S r I m N I� • y�� m O-) p sz filed. IP ti. �' s f �o ° 0 cz 0� P10,,0 ' •ti,;, cavn o o s� `�"�' ° °F. 0 0 ! ° !� o F 0 C- m a Y o o. Ff+ to ^Ci 7 s 0 to m o - a d O 0 o OL rn" ` CCj«o j o O °�3 C C o fp o O a"— 0° '94' E ° 00_F 6` ° �+O! ° ` ' ! o °it !! ° ■ 0 !Y Z o c", lil O ° 0 < O n- E,! o Z I 6 o FY m V [n !s> 0 o YY O O Q 9! ° ° 9Y C! o ° 3 eflz ° ° ° d R— 6'1 a c O� o ° M !e. 0 n te. o c ._. _°Fe. ° c°°c... _B mum S °a lc ° d N m °N O ng O Z /�� C O r 0 0 'J zQ I is • , _ I _ i 1 t I a { '•)istrici Soundry V j SE Corner of T `\,r k RUK SITE Protracted Section) 11 �� „ E 1 �� Coordinates I I i I N 6028111.04 �) i \ I E 470989.01 1 �, \I -i I PI- 4- ■ m ! Ref. AK BLM — er i 4. �\16 Harrison: Bay Tract; "A" 1 1 P1-24`\e '-r• . Irewin. I. 4 \sue I . +_ \.4 ti , 1 V 1, F_• ' I. Aj»/ �1 '�j G. j ;x(121 i S _I • �. e` / I- _--_-- '� Offshore Icerood=-5-99 )files 1 ■ +. PI-1S x Pl 20 to •... ruk Site N• �,, . n n y% \ r - v = ��Ill' ,� 1\ PJ-14 ,S ' ^ W-1 I luncro !Caro[ DS 3N B.O.R. m n ♦ P�- ' i' . . Roods to i-d, j �• Pi 31 8 `" 1w . I 7/3N i -Al .iIu1' '1.--i.�✓/ .pi . �:'- f waorc +5" .. r C` Basis of Location 117 III Bur 'E � / ; 1- DS-3H West Monument -i j Coordinates l :.R�- N 6001016.61 STAKED PI INFORMATION ONLY j I �,. A E 498081.23 (� aC ! (e- 12 .. „ '1. Ref. Lownsbury & Assoc. n I ID < Drawing No. I NSK 6.01—d672 � of Si. ` 0 ' • A fil i� eforr dov.'1110 :140017 1/0 ..:12-.4,4:12.1-11,...-2, ,'..•''--,::•.•r•o•,- I* • flipG.Dads Jo ,..* j` 4: I.J'; s. No.4110-$ tea'`*a tS . i• k t::,,..DFESSION4 4. Pioneer Natural Resouces JOB NAME: Oooguruk Drill Site Conductors DRAWN BY: BL CHECKED BY: MJD LOCATION: Protracted Section 11 SCALE: N/A Township 13 North Range 7 East DATE: 7-12-07 Umiat Meridian NANUQ JOB NO. SHEET DESCRIPTION: Basis of Location 05204 2 of 4 -- --A1- .S-kj-Sljte--P L Well Nsp. ----......-- -•••■---•-•-•..-- ...--5.( Latitude (N) Longitude tvv) _FSL -FEL Pad Elev, • . . • - 1 6,031,181,32 459,920,45 70 29 46,24160 150 14 45,40400 3035 10f7 - 1$ 5Q . ,. . 2 6,031,10,35 469,915,52 70 29 46,19252 150 14 4.5,60922 3030 1082 13,50 -- '7-3 . 6,031,141,39 469,910,59 . 7• 0 29 46,14354 150 14 45,75375 3025 1067 13.50 • -• 4 .. 6.,031,136,46 460905,67 - 70 29 46.0948-5 150 14 45,89799 3020 1092- 13-50 ' ,... 5 6,031,131,45 469,900,74 ' 70 29 460453U150 14 46,04252 3015 109-7-----13,50 6 6,031,126,51 469,895,00 70 29 45,99660 150 14 46,10735 3010 . 1102 13.50 7 6,031,113,73 469,683,13 . 7• 0 29 45,87039 150 14 46 H ,55079 2997 115 4-7-13,50 ,• . 8 6,081,108,73 67V29 4882-1 .02 -151)-T4 46,70303 2992 1120 13,50 i • 9 6,031,103.75 469;878:26 7029140,71184 150 14 46,84814 2.987 1125 ; 13.50 10 6,031,098,79 469,868,36 70 29 45,72286 150 14 46,99179 2982 1130 13,50 • • . •'.7 ifi 6,031,093,84 469,863,39 7• 0 29 45,67398 150 14 47,13750 29r 1135 - 13,50 . -. 12 6,031,000,87 - 469,858,47 70 29 45,62490 150 14 47,26174 2972 1140 13,50 -.-13- 0,081,076,06 469,845.81 170 29 45,49840 150 14 47,55288 2960 1152 13,50 -- _ 14 6,031,071,09 469,840,87 . 70 29 45,44932 150 14_47,79770 2955 1157 -13;50 - 15 6,031,066,15 469,835,96. 70 29 45,40053 .150 14 47,94165 2950 1162 • 13,50 16 6,031,061,18 469,831,04 70 29 45,35145 - 150 14 408588 . 2945 1167 13.50 17 6,031,056,25 469,826,11 70 29 45,30277 150 14 40.23042 2940 1172 13.50 . ---14 -6;031,051:271409,821,10 70 29 45,25359 150 14 48,37491--2935 1177 11-570- • 19. 6,031,038,52 469,80850 70 29 45,12768 150 14 48,74668 2922 1189 13,50 20. - 6,031,033,50 469d803,59 . 70 29 45,07811 . 150 14 0,09061 2917 • 1194 13,50 - . . " 21 . .6,031,028,83 469,798,62 70 29 45,02903 150 14 49,03632 2912 1190 13,50 ---22 6,031,023,58 469,793,67 70 29 44,98014 ' 150 14 49.18144 • 2907 1204 • - 13.50 : . 23 6,031,018.57 469,708,76 70 29 44,93067 150. 1449-.-32537 2902 1209 7-f3,507 • • 24 6,031,013.60 469,783.84 - TO20 44,8815U 150144f9.4-6960 2807 1214 18,50 . . , . 1452779.7-::::16:6"9:4•60. ,4 • . .. .,..7'.>,...:...:7r77-71, ,:,.,_. s:P.41:17.D.vills ::.,./ .O ..::::,..faf,,:i..,1: ••-..7;:t-.. 4-1-p,5.. No.41104 .!44',...0- 1'to.••• ......-/cP''' . i -:.t.141.V.H.i....1:7,... • • N‘'. " 1 II PRopE"' O• 4°' ilk., SSIGNAV ..er '7-:.f‘.-1;■-...:•t -= ',Z.:.. .. . .'.;;:%;;;V:Akk t7:7.:.:•.. :Z7 nlob"..10:1•411' .....*-7-:.--, .,1-1z.tat:;&-_:,:..._. •. n'4,,,, ..'••-,..I'-i;=.,,,-;.-..,•;.•• Notes: 1. Elovotions or hosed on BP Moon Soo .Levol, - ._,_..._-- 2, Coordinotes ore hosed on Alosko Stote Plone Nod 27> Zane 4, 3, All conductors ore within Protrocted Section 11, Pioneer Natural Resouaes . - . • . ■ JOB NAME; OQQ9uruk Drill Site cipno.wctors DRAWN SY; St_ CHECKED SY: MA) LOCATION; Protrocted Section 11 $CALE; N/A Township 13 North Ronge 7 Ecist DATE; 7=12=07 Umiot Meridion -NAN-OCTJOB NQ, SHEET _ .._ • • •)ESCRIPTION: As-built Coordinot*$ . . 05204 3 of 4 - ____ 1 seal @@?Ill&ililli. 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' y O m t' % r�'1 J!' j = `=s ue =s a a *N. e � J / : e,..,...:. ;fir ', N y• �z \�� - O• mom' ����'_= --- ��� r` `'� i O .-0 'rnm•■ tits.� ^ z w . .� ■1.' � , o u ° ?a a No z oCY5 •,,.....%,..;--,,,,, 1 _ v' Frn ��' ' ��O�� '_ O b OZOZ Cup '3o ° 3 ' `;';" ate r zzthiV - c rn,c Ix a > � n� \ E o�o�E c ocm ‘‘.- / %`%` . "`= C U U U U t N Z Z 7 >'6'A i1,x` �``` •-. W .,-.72 N W._.. 1 L" �. `` CD W KK d'K p p ,• G^ " m •, C U U V U 0' 41.0---• __ O L E,0 N HOY > 2 Y. Ows ce Page 1 of 2 I* Schwartz, Guy L (DOA) From: Franks, James[James.Franks @pxd.com] Sent: Thursday, April 01, 2010 5:02 PM To: Schwartz, Guy L(DOA) Cc: Vaughan, Alex; Johnson, Vern Subject: FW: ODSN-15i & N-40 wells Attachments: Spider Plot 15 Letter Size.pdf; Visio-ODSN-40 Schematic Well Status Final.pdf; ODSN-15i I N 12 wp07 Section.pdf Guy, As requested, here is a bit of history on the ODSN-40 well and ODSN-15i and why they overlap. ODSN-40 was the first Oooguruk-Nuiqsut well we drilled in the development. At the time of drilling,this location was identified as a production location. This made the location to the northeast of this BHL an injector. ODSN-40 was planned to be drilled and completed as an open hole completion, however, during the drilling operations we had a fault displace the reservoir upward by a greater amount than predicted and we chose to run a short liner to cover the fault and the shale section that was exposed while leaving the remaining wellbore as an open hole completion. During the time ODSN-40 was on production, the rate was very low. This was determined to be from either wellbore damage or from a wellbore collapse—we have never investigated which it is, but believe a wellbore collapse is very likely. Upon further analysis of the reservoir and the production seen from ODSK-33 (across a major fault from the planned injector and closely juxtaposed to the planned injector BHL) it was deemed that having the injection location adjacent to this fault was too risky should the fault turn out to be communicative and cause water breakthrough to ODSK-33. Based on this perceived risk, we decided to change the well service pattern in the fault block containing ODSN-40. This now places the ODSN-40 in an injector location,which we will convert at some date in the future. Additionally,we have had tremendous difficulty in drilling and completing our planned 8000' laterals and have decided to shorten our laterals to 6000'. This shortening of the laterals required us to change the well layout and increases the number of wells in the fault block where ODSN-40 is located. To offset this additional well count,we have adjusted the development to extend further to the north allowing us to gain reserves. Believing the wellbore of ODSN-40 to be partially collapsed, what we did was start from the toe of a planned ODSN-15i BHL and worked back to a heel location >6000' back(permit to drill request is for a lateral length greater than 6000' on the chance that drilling is going well and we can drill farther). The process in working from the toe back to the heel caused the overlap of the open hole section of ODSN-40 by ODSN-15i. I hope that helps to clear up a bit on why the 2 wells overlap. Let me know if you have further questions or my verbiage is not clear. I find that it works good in my head, but sometimes translates as jibberish©. Take care! 4/2/2010 Page 2 of 2 james James Franks Pioneer Natural Resources Alaska 907.343.2179 From: Hoffman, Dale Sent: Thursday, April 01, 2010 3:31 PM To: Franks, James Subject: FW: ODSN-15i &N-40 wells From: Hoffman, Dale Sent: Thursday, March 25, 2010 8:46 AM To: Davies, Stephen F (DOA) Cc: Vaughan, Alex Subject: ODSN-15i &N-40 wells Steve, Thanks for taking time to hear our explanation of the N-40 and N15i wells. Here is info for your file. Hope you're feeling better soon and your son's visit to the doc was uneventful. Dale Hoffman, CPL I Sr.Staff Landman Pioneer Natural Resources Alaska, Inc. 700 G St.,Suite 600 I Anchorage, AK 99501 907 343 2108 voice I 907 830 2571 cell dale.hoffman@pxd.com Statement of Confidentiality: This message may contain information that is privileged or confidential. 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I'-c( c Circle Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in Permit No. ,API No. 50- - - API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. 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No special effort has been made to chronologically organize this category of infoi ration. 1 i HALLI BU RTD Sperry Drilling I I END OF WELL REPORT Oaf/4706y 1 ODSN-15i Oooguruk Development 4 1 1 I _ , . , I . . . ., I - _ . , . _ . . , , } ,'\_. .... I f lir A* ;^ . , .7 • l I & I 1 Surface Data Logging Services 1 1 ,%,, 00-t30 1T9'3 1 ' HALLIBURTON I Sperry Drilling ' TABLE OF CONTENTS i 1. General Information ' 2. Daily Summary 3. Morning Reports 4. Bit Record i5. Mud Record 6. Formation Tops 7. Survey Report 8. Days vs. Depth Digital Data to include: Formation Evaluation Logs Halliburton Log Viewer EMF Log Viewer End of Well Report in PDF format ADI Backup 1 I PIONEER NATURAL RESOURCES i tHALLIBURTON I Sperry Drilling GENERAL WELL INFORMATION Company: Pioneer Natural Resources AK Rig: Nabors 19AC Well: ODSK-15i Field: Oooguruk Borough: North Slope Borough State: Alaska ' Country: United States API Number: 50-703-20618-00 Sperry Job Number: AK-AM-0007262433 Job Start Date: 08 April 2010 Spud Date: 6-Apr-2010 ' Total Depth: Production Section to 17.383 MD, 6,095.48' TVD North Reference: True ' Declination: 21.527° Dip Angle: 80.024° Total Field Strength: 57656.58nT ' Date of Magnetic Data: 09 Apr 2010 Wellhead Coordinates N: North 70° 29' 45.401" Wellhead Coordinates W: West 150° 14' 47.942" ' Drill Floor Elevation 56.20' Ground Elevation: 13.5 Permanent Datum: Mean Sea Level SDL Engineers: Daniel Kane, Daniel Sherwood Colby Marks ' SDL Sample Catchers: Samantha Jemison, David Mckechnie Company Geologist: Paul Cozma, Mindaugas Kuzminskas, Jim Stewart, Jaque Ledbetter Company Representatives: Joe Polya Rod Klepzig, Joey Cortez SSDS Unit Number: 123 PIONEER NATURAL RESOURCI_S 1 1 1 HALLIBURTON I Sperry Drilling DAILY SUMMARY Begin ODSN-15i 1 04/25/2010 Complete BOP test, install wear bushing and RIH to 1,900' MD picking up singles of 5" drill pipe. Circulate 1.5 pipe capacity to clear any possible debris. POOH from 1,900'to surface. Assemble BHA and RIH to 720' and shallow pulse test MWD. Continue to RIH to 4,050' observing correct displacement. 4/26/2010 1 Continue to RIH from 4,050' to 8,704'. Pressure test 11 'A" casing and 9 5/8" liner to 3,500 psi. Drill cement and float equipment from 8,704'to 8,865'. Pump 80 bbls hi-vis sweep and circulate same surface to surface. Remove trip nipple and install RCD bearing. Drill float shoe and 20' of new hole from 8,865'to 8,902'. Circulate bottoms up at 8,902'. Perform LOT at 8,870' MD, 5,301.29'TVD, with 10.0 ppg mud 1 weight. Leaked off at 1,900 psi and bled down to 667 psi for EMW of 12.4 ppg. Drilled from 8,902'to 9,151'. Sperry began to observe losses at 8,995' at which point the ECD was lowered to 12.5 ppg. Total losses for the 24hr period were 370 bbls. Max gas for 24 hr period was 225 units @ 9,003' MD. 1 4/27/2010 Drilled from 9,151' to 9,900'. At 9,528' experienced losses of 200 bbl/hr, pumped LCM pill and lowered ECD to 12.1 ppg, reducing loss rate to 35 bbl/hr. Drilled to 9,900' and circulated bottoms up. Pumped 30 1 bbls hi-vis pill with high cutting load observed on surface. POOH to 8,810' and held pre-job for DOBC2 lost circulation pill. Total losses observed to the hole for this period were 577 bbl. Max gas observed during the past 24 hour period was 1,159 units. 1 4/28/2010 POOH from 9,030' to 8,550' laying DOB2C S Pill @ rate of 2.4bbls/stnd. Perform hesitation squeeze with MPD applying WHP for 10.1-12.75 ppg ECD. Circulate bottoms up. Increased EMW to 13 and wash & ream from 8,550'to 9,900'. Drill from 9,900'to 10,142' excessive stick slip encountered. Troubleshoot 1 MWD survey equipment. Pumped lubes and torque and stick slip fell to acceptable levels. Returned to drilling ahead to a depth of 10,380'. Sperry recorded 358 bbl loss and max gas of 846 units over 24 hr period. 4/29/2010 Drilled to section TD for 8.5" hole of 11,379' MD. Pumped 2 hi vis sweeps with an average of 25% increase in return between the two sweeps. Back reamed to 11,188', hole packed off, RIH 2 stands and 1 circulate two more hi vis sweeps, with a minimal increase in cuttings. Began POOH, encountered more pack off at 10,984'. Worked through and POOH to casing shoe. Max gas for the past 24 hours was 711 units. Total losses observed to the hole were 277 bbl 1 4/30/2010 POOH pumping up to the HRZ. Back reamed and pumped slowly to avoid pack off with losses varying between 50-170 bbl/hr. Reamed through HRZ. Pulled out of hole to shoe on elevators. Pump LCM pill 1 outside of shoe, losses continued. RIH spotted LCM pill at 11000', losses slowed to 60 bbl/hr. Pulled 10 stands than ran back to bottom to pump 13 ppg pill. Pulled out of hole 10 stands while pumping pill. Total losses observed to the hole for the past 24 hours were 1,079 bbl. Max gas was 862 units. 1 5/1/2010 POOH from 11,000'to 10,428'on elevators. RIH to 11,369'. Spotted 35 bbl 13.0 ppg LCM pill in open hole while POOH from 11,369'to 10,808'. Displaced 10.0 ppg mud to 12.8 ppg mud. POOH to surface and laid down BHA. Total losses to the hole were 181 bbls with a max gas of 364 units. 1 PIONEER NATURAL RESOURCES 1 ' HALLIBURTON I Sperry Drilling 5/2/2010 ' Installed 7" rams and tested, RIH with 7"26#L-80 BTCM casing to a depth of 8,870'. No reportable gas or losses were recorded. ' 5/3/2010 RIH with 7"casing from 8,870'to 11,342'could not get landing joint to bottom. Displaced 12.8 ppg to 11 ppg for cement job. R/U for cement job. Pumped 50 bbls, 11.0 ppg, 20% lube pill. While pumping H2S detected at flow line and#1 pit. Evacuated rig and vented pits. Observed well flowing during rig ' evacuation and shut in well accordingly. Bled off pressure, H2S and flow back possibly due to well bore breathing. Continued to pump LCM and lube pill and conducted cement job. Losses to the hole observed for the 24 hour period was 476 bbl; with a max gas of 528 units. Maximum H2S recorded in sample line was 60 PPM. ' 5/4/2010 Pressure tested casing and observed floats not holding, Observed well until static, nipple down stack and ' MPD head and installed emergency slips. 5/6/2010 Lay down 5" drill pipe, slip and cut drill line. Begin picking up and RIH with 4" drill pipe for 6 1/8" production section. 5/7/2010 POOH with 4" drill pipe, rack back in derrick, and test BOP's. Pick up new BHA assembly, RIH, and begin ' drilling float equipment to 11,304' MD. 5/8/2010 ' Continue to drill out float equipment and cement to 11,348' and drill out 20' of new rat hole to 11,399' MD. Conducted FIT at 6,165' TVD with 10.4 ppg to 700 psi for a equivalent mud weight of 12.5 ppg. Bled off to 610 psi for equivalent mud weight of 12.3 ppg. Install RCD bearing and displace well with 7.6 ppg OBM. Drill ahead to 12,133' maintaining a 9.8 ppg ECD with MPD. No losses occurred while drilling this interval ' max gas recorded was a connection gas 1,258 units. Connection gasses were recorded throughout interval drilled with very small increases over background gasses. 5/9/2010 ' Drill from 12,133' to 12,848' and tag siderite stringer. Time drill from 12,848' to 12,857' at 1.25 ft/hr. Increase rate to 1.67 ft/hr to 12,863'. No losses were observed and a max gas of 615 units was recorded. Calculated annulus correction was 11 bbls. 5/10/2010 Control drill to 12,928' at 15' per hour, unable to breach siderite with directional assembly pull off bottom and adjust well plan accordingly. Decision is made to attempt to address siderite at a higher angle. Drilled from 12,928' to 13,205' and then control drill through siderite stringer to 13,215'. Continue to drill ahead with normal drilling parameters to 13,427'. Max gas observed was connection gas at 3,197 units over a background of 452 units. No losses were observed, calculated annulus correction was 27 bbls. 5/11/2010 Drill ahead from 13,427' to 15,620' and encounter siderite stringer. Control drill to 15,670'to prevent excessive dogleg in well path. No losses to the formation were observed calculated washout was ' estimated at 35 bbls. Max gas observed was connection gas at 3197 units over a background of 452 units. 5/12/2010 Drill from 15,550' to 15,620' and encounter siderite stringer, breach stringer with minimum dogleg severity at 15,670'. Continue to drill ahead to 15,535' and cross Green Fault#3, fault shifted up approx 54' TVD, 1 PIONEER NATURAL RESOURCES ' HALLIBURTON Sperry Drilling landing BHA in base of zone 5. Adjust well plan accordingly with well site geologist and drill ahead to ' 16,225'. Circulate bottoms up and short trip through base of zone 5 to ensure borehole stability and possible swelling fractured shales. RIH on elevators with no issues and continue to drill ahead to 16,850'. Estimated annulus correction was 35 bbls with no observed losses to formation. Max gas was 1,040 ' units. 5/13/2010 Continue to drill ahead to TD - 17,383' MD. Circulate three times bottoms up and begin POOH to 7" ' casing shoe. Slip and cut drill line and RIH to 16,322' and stack out, begin washing and reaming to bottom. Sperry observed a 20 bbl loss while POOH for short trip to casing shoe annulus adjustment remained at 35 bbls. A high viscosity sweep was pumped while circulating after TD and confirmed estimated correction factor of 35 bbls. Max gas recorded was 1,788 units while reaming to bottom after short trip. 5/14/2010 ' Stage pumps up and circ hole clean. W& R in the hole from 17,093 to 17,150'. Pump 20 bbl Hi-Vis Sweep and circulate same out the hole. Spot 220 bbls of new 7.2 ppg MOBM across open hole. POOH from 17,150'to12,050'. Pump 49 bbls 10.2 ppg MOBM to displace open hole from 8.1 ppg MOBM while maintaining 9.8 ppg EMW. POOH from 12,050'to 11,304'. Displace casing volume from 8.1 ppg with 10.2 ' ppg MOBM. Monitor well, remove RCD bearing, and install trip nipple. Circulate and condition mud weight to 10.2 ppg. POOH from 11,304'to 416'. Function test BOPE. 5/15/2010 POOH from 416'to 223'. Remove nuclear sources, and lay down BHA. Rig up testing equipment. Test Annular to 250 psi low/2,500 psi high with 4.5"test joint. Test Upper 2-7/8"x 5"VBR's with 4.5"test joint to 250 psi low/4,500 psi high. All tests held 5 minutes each. All tests charted. Rig up 4 1/2"casing ' equipment. RIH with 4.5" casing from surface to 5,290'. Pick up WFT hydraulic hanger, liner top packer, and tie back sleeve from 5,920'to 5,945'. Make up SLB memory cement bond log tool. TIH with 4.5" liner on 4"drill pipe from 5,945'to 11,285'. Pump lx drill pipe capacity. TIH with 4.5" liner on 4"drill pipe from 11,285'to 14,123'. Trip in hole with 4.5" liner on 4" drill pipe from 14,123'to 17,140'. Drop 1 3/4" ball and pump down same at 1 bpm with 400 psi, seat ball and engage hanger with 1,500 psi, slack off to 50K to set hanger. Pressure up in 500 psi increments to 2,500 psi to engage packer, shear ball seat with 3,400 psi. Pick up to expose packer setting dogs and set packer with 65K down and repeat to ensure packer set. Test annulus to 4,500 psi—good test. Rack back 1 stand to ensure that SLB SCMT tool could not contact liner top. Break circulation and displace 10.2 MOBM with 10.2 brine. 5/16/2010 ' SDL released. PIONEER NATURAL RESOURCES 1 I MINk I Customer: Pioneer Natural Res. Report#: 1 HALLIBURTON Well: ODSN-15i Date: 4/26/2010 I Area: Oooguruk 04:00 Depth 8882' Location: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: RIH Job No.: AK-AM-0007262433 Report For: R. Klepzig/J. Cortez Daily Charges $3,762.72 Total Charges: $51,308.08 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. (ft/hr) 0.0 0.0 0.0 Flow In (gpm) SPP (psi) Gas(units) 0 0 0 Flow In (spm) Gallons/stroke Hole Condition Depth On Bot Hrs Ann Corr Avg Diam PWD Drilling Min Avg Max All Circ Min Avg Max • Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (secgt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I ok I8870' _ 10.00 10.00 _ 40 2.5 8 19 9.4 9.30 21K 9.9 BHA Run # I Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition I . Lithology (%): Sd Sst Silt Siltst _ Cht Clyst Sh Lst Coal Gvl Tuff I (current) Gas Breakdown H2S Data I Sample Line'Max: 'Avg: I Ambient Air Pit Room 'Max: 'Avg: I Gas (units) Chromatograph (ppm) Depth to I to to to to to to to to Gas Type abreviations:BG- Background Gas; GP-Gas Peak; CG-Connection Gas;WTG-Wiper Trip Gas; POG-Pumps Off Gas; PG-Produced Gas; RG-Ream Gas; T---Trip...; F---Formation...; E---Early... I 24 hr Recap: N/U BOPs and N/U MPD rotating head.Test BOPs. RIH with 5"DP and flush same. POOH and rack back DP in derrick.M/U BHA and RIH.Shallow pulse test MWD.Currently RIH at time of report. I I I ILogging Engineer: Mark Lindloff/Dan Sherwood * 10000 units= 100% Gas In Air I Customer: Pioneer Natural Res. Report#: 2 -IALLIBURTON Well: ODSN-15i Date: 4/27/2010 I Area: Oooguruk 04:00 Depth 9381' Location: North Slope Progress 24 hrs: 499' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK-AM-0007262433 Report For: R. Klepzig/J. Cortez IDaily Charges $3,762.72 Total Charges: $55,070.80 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. (ft/hr) 67.2 55.4 150.0 9190' Flow In (gpm) 605 SPP(psi) 2940 Gas(units) 126 75 225 9003' Flow In (spm) 170 Gallons/stroke 3.7030 Hole Condition Depth On Bot Hrs Ann Corr Avg Diam PWD Drilling _Min Avg Max 1 9381' 9.6 All Circ Min Avg Max •Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/gt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I % I9066' 10.00 _ 10.00 43 5.0 10 _ 16 7.0 9.30 22K 9.4 _ BHA Run # I Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition Lithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) Gas Breakdown H2S Data 1 Sample Line Pax: Avg: I Ambient Air Pit Room IMax: Avg: I Gas(units) Chromatograph (ppm) Depth to I to to to to I to to to to IGas Type abreviations:BG-Background Gas; GP-Gas Peak; CG-Connection Gas;WTG-Wiper Trip Gas; POG- Pumps Off Gas; PG-Produced Gas; RG-Ream Gas; T---Trip...; F---Formation...; E---Early... I 24 hr Recap: Test casing to 3,500 psi for 30 minutes. Install RCD an drill out float collar,and 20'of new formation to 8902'. Circulated bottoms up,followed by LOT with 10ppg mud at 5,307 TVD.Pressure broke at 1900psi and bled back to 667 after 10 minutes.Drilled to 8,995'increasing ECD to 13.5ppg and encountered losses,lowered ECD to 12.5 and got returns under I control. Drilling ahead at time of report.Total losses for the past 24 hrs was 370bb1. Max gas was 225 units at a depth of 9003'. I I Logging Engineer: Dan Sherwood/Colby Marks * 10000 units= 100% Gas In Air I Customer: Pioneer Natural Res. Report#: 3 HALLIBURTON Well: ODSN-15i Date: 4/28/2010 I Area: Oooguruk 04:00 Depth 9900' Location: North Slope Progress 24 hrs: 519' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Tripping Job No.: AK-AM-0007262433 Report For: R.Klepzig/A.Vaughn Daily Charges $3,762.72 Total Charges: $58,833.52 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: I R.O.P. (ft/hr) 0.0 _ 43.3 115.0 9668' Flow In (gpm) SPP(psi) Gas(units) 25 150 1159 9668' Flow In (spm) Gallons/stroke 3.7030 Hole Condition Depth On Bot Hrs Ann Corr Avg Diam PWD Drilling Min Avg Max All Circ Min Avg Max Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I % I9900' 10.00 10.00 45 7.5 11 21 7.0 8.00 , 21K 9.5 BHA Run # Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition Lithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff I (current) Gas Breakdown H2S Data I Sample Line Max: Avg: I Ambient Air Pit Room Max: (Avg: I Gas(units) Chromatograph (ppm) Depth 9,300 to 9,668 1159 142 127931 3651 1073 417 143 POG I to to to to I to to to to 1 Gas Type abreviations:BG- Background Gas; GP-Gas Peak; CG-Connection Gas;WTG-Wiper Trip Gas; POG-Pumps Off Gas; PG-Produced Gas; RG-Ream Gas; T---Trip...; F---Formation...; E---Early... I 24 hr Recap: Drilled to 9900'. At 9528'experienced losses of 200bbl/hr,pumped LCM pill and lowered ECD to 12.1,reducing loss rate to 35bbl/hr. Held pre-job for DOBC2 and proceeded with same.Finished with DOBC2 and squeeze job.RIH at report time. Total losses observed to the hole for this period were 577 bbl.Max Gas observed during the past 24 hours was 1159 units. I I I Logging Engineer: Dan Sherwood/Colby Marks * 10000 units= 100% Gas In Air I Customer: Pioneer Natural Res. Report#: 4 HALLIBURTON Well: ODSN-15i Date: 4/29/2010 Area: Oooguruk 04:00 Depth 10712' Location: North Slope Progress 24 hrs: 812' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK-AM-0007262433 _ Report For: R.Klepzig/A.Vaughn Daily Charges $3,762.72 Total Charges: $62,596.24 I ROP & Gas: Current Avg 24 hr Max . Max @ ft Current Pump & Flow Data: R.O.P. (ft/hr) 77.0 43.3 179.0 10620' Flow In (gpm) 629 SPP (psi) 3335 Gas(units) 204 250 846 9900' Flow In (spm) 177 Gallons/stroke 3.7030 I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ftz) ml/30min mg/I % 10380' 10.00 10.00 50 8.0 13 23 7.2 9.20 22K 9.9 IBHA Run # Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition 1 Lithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) IGas Breakdown H2S Data I Sample Line Max: lAvg: 1 Ambient Air Pit Room'Max: !Avg: Gas(units) Chromatograph (ppm) I Depth 9,900 to 9,900 846 200 93864 2707 645 215 43 TG 10,522 to 10,522 628 380 64566 2531 966 451 160 CG I 10,522 to 10,542 751 390 75315 3294 1260 558 177 GP 10,542 to 10,604 741 415 74362 3198 1250 549 165 GP to to Ito to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG-Connection Gas; VVTG-Wiper Trip Gas; POG- Pumps Off Gas; PG- Produced Gas; RG- Ream Gas;T---Trip...; F--- Formation...; E--- Early... I 24 hr Recap: After getting back to bottom after DOBC2 squeeze job,drilled ahead from 9900'-10142'with excessive stick slip. Added tubes to mud,torque fell of and drilling resumed. Drilled to 10174'. Problems with MWD, POOH to 9952'to check survey and troubleshoot MWD.RIH and drill ahead.Drilling ahead at 10712'at report time. Observed losses to the hole for the past 24 hours was 358bb1. Max gas for the past 24 hours was 846 units. I I Logging Engineer: Dan Sherwood/Colby Marks * 10000 units= 100% Gas In Air I 1 Customer: Pioneer Natural Res. Report#: 5 HALLIBURTON Well: ODSN-15i Date: 4/30/2010 I Area: Oooguruk 04:00 Depth 11379' Location: North Slope Progress 24 hrs: 667' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: POOH Job No.: AK-AM-0007262433 Report For: R.Klepzig/A.Vaughn IDaily Charges $3,762.72 Total Charges: $66,358.96 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: IR.O.P. (ft/hr) 66.7 296.0 10815' Flow In (gpm) 497 SPP (psi) 2564 Gas (units) 22 250 711 10712' Flow In (spm) 141 Gallons/stroke 3.7030 • I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I % 11379' 10.00 10.00 50 10.0 15 25 6.1 8.10 22K 11.0 BHA Run # I Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition Lithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) Gas Breakdown H2S Data I Sample Line'Max: IAvg: I Ambient Air Pit Room Max: IAvg: Gas (units) Chromatograph (ppm) I Depth 10,712 to 10,712 711 406 71956 2873 1180 560 204 CG 10,808 to 10,808 565 290 57915 2530 1047 501 186 CG I 10,903 to 10,903 321 192 33932 1402 640 354 135 CG 10,998 to 10,998 328 143 34005 1206 515 291 116 CG to to to to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG-Connection Gas; WTG-Wiper Trip Gas; POG- Pumps Off Gas; PG- Produced Gas; RG- Ream Gas;T---Trip...; F--- Formation...; E--- Early... I 24 hr Recap: Drilled to TD of intermediate section @ 11379'. Pumped 2 hi vis sweeps with an average of 25%increase in returns between the two sweeps. Back reamed to 11,188', hole packed off, RIH 2 stands and circulate two more hi vis sweeps,with minimal increase in cuttings. Began POOH,encountered more pack off at 10,984'.Got through and currently POOH to shoe. Max gas for the past 24 hours was 711 units.Total losses observed to the hole were 277bb1 I I eLogging Engineer: Dan Sherwood/Colby Marks 10000 units= 100% Gas In Air I 1 Customer: Pioneer Natural Res. Report#: 6 HALLIBURTON Well: ODSN-15i Date: 5/1/2010 .................. Area: Oooguruk 04:00 Depth 11379' Location: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Pump 13 ppg mud Job No.: AK-AM-0007262433 Report For: R.Klepzig/A.Vaughn IDaily Charges $3,762.72 Total Charges: $70,121.68 I ROP & Gas: Current R.O.P. (ft/hr) Avg 24 hr Max Max @ ft _ Current Pump & Flow Data: Flow In (gpm) 77 SPP (psi) 1022 Gas(units) 35 275 862 Flow In (spm) 22 Gallons/stroke 3.7030 I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I 11379' 10.00 10.00 50 8.0 16 25 4.4 8.60 22K 6.9 1 BHA Run # Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition Lithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) Gas Breakdown H2S Data I Sample Line'Max: IAvg: 1 Ambient Air Pit Room Max: 'Avg: Gas(units) Chromatograph (ppm) I Depth to to to to to to to to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG-Connection Gas;WTG-Wiper Trip Gas; POG- Pumps Off Gas; PG- Produced Gas; RG- Ream Gas;T---Trip...; F--- Formation...; E---Early... I 24 hr Recap: POOH pumping up to the HRZ. Backed reamed and pumped slowly to avoid pack off. Losses varying between 50-170bbl hr. Reamed through HRZ. Pulled out to shoe on elevators.Pump LCM pill right outside of shoe, losses continued. RU- Washed and reamed all the way to bottom.Circualte B/U two times.POOH to 10998'and experienced heavy losses, 150bbl/hr. I Spotted LCM at 11000', losses slowed to 60bb/hr. Pulled 10 stands than ran back to bottom to pump 13 ppg pill. Pulling 10 stands pumping pill while doing so at report time, then we will displace well with 13ppg fluid. Total losses observed to the hole for the past 24 hours was 1079 bbl. Max gas was 862 units. I I iLogging Engineer: Dan Sherwood/Colby Marks 10000 units= 100% Gas In Air I Customer: Pioneer Natural Res. Report#: 7 HALE-(BURTON Well: ODSN-15i Date: 5/2/2010 I Area: Oooguruk 04:00 Depth 11379' Location: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Test BoPs Job No.: AK-AM-0007262433 Report For: R.Klepzig/A.Vaughn IDaily Charges $3,762.72 Total Charges: $73,884.40 I ROP & Gas: Current R.O.P. (ft/hr) Avg 24 hr Max Max @ ft Flow In (gpm)Current Pump & Flow Data: SPP (psi) Gas(units) _ 135 _ 364 _ Flow In (spm) Gallons/stroke • I Mud Data: Density(ppg) Viscosity MBT PV YP API Flit pH Chlorides Car Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I % 11379' 12.80 12.80 53 7.5 17 39 5.7 9.50 22K 18.5 BHA Run # I Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition Lithology (%): Sd Sst _ Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) IGas Breakdown H2S Data I Sample Line Max: (Avg: I Ambient Air Pit Room (Max: !Avg: Gas (units) Chromatograph (ppm) I Depth to _ to I to to to to to to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG-Connection Gas;WTG-Wiper Trip Gas; POG-Pumps Off Gas; PG - Produced Gas; RG- Ream Gas; T---Trip...; F--- Formation...; E--- Early... I24 hr Recap: Displaced well with 12.8ppg mud, pulled to shoe and rigged down RCD. Spotted 50ppb LCM at shoe. POOH to surface and lay down BHA.Test BOP's at report time. Losses observed to the hole for the past 24 hours was 181 bbl. Max gas was 364 units. I I I Logging Engineer: Dan Sherwood/Colby Marks 10000 units= 100%Gas In Air I ICustomer: Pioneer Natural Res. Report#: 8 HALLIBU ',TON Well: ODSN-15i Date: 5/3/2010 I Area: Oooguruk 04:00 Depth 11379' Location: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Running Casing Job No.: AK-AM-0007262433 Report For: R.Klepzig/A.Vaughn IDaily Charges $3,762.72 Total Charges: $77,647.12 I ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: R.O.P. (ft/hr) Flow In (gpm) SPP (psi) Gas (units) Flow In (spm) Gallons/stroke • I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I % 11379' 12.80 12.80 55 7.5 14 38 5.8 9.50 22K 18.5 IBHA Run # Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition Lithology (%): Sd Sst _ Silt _ Siltst Cht Clyst Sh _ Lst Coal _ Gvl Tuff (current) IGas Breakdown H2S Data I Sample Line Max: Avg: I Ambient Air Pit Room Max: Avg: Gas(units) Chromatograph (ppm) I Depth to to I to to to to I to to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG-Connection Gas;WTG-Wiper Trip Gas; POG- Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T---Trip...; F--- Formation...; E---Early... I 24 hr Recap: Rigged up and ran casing to 9976'. Replacing parts on Frank's Casing tool. Losses observed to hole during the past 24 hours was negligible as was the gas. I I I Logging Engineer: Dan Sherwood/Colby Marks 10000 units= 100% Gas In Air I 1 1 Customer: Pioneer Natural Res. Report#: 9 HALLIBURTON Well: ODSN-15i Date: 5/4/2010 Area: Oooguruk 04:00 Depth 11379' Location: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Rig down cementing Job No.: AK-AM-0007262433 Report For: R.Klepzig/A.Vaughn Daily Charges $4,462.18 Total Charges: $83,508.22 I ROP & Gas: Current R.O.P. (ft/hr) Avg 24 hr Max Max @ ft Flow In (gpm)Current Pump & Flow Data: SPP (psi) Gas(units) 275 528 Flow In (spm) Gallons/stroke • I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) m1/30min mg/I 11379' 12.80 12.80 55 7.5 14 38 5.8 9.50 22K 18.5 IBHA Run # I Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition ILithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) IGas Breakdown H2S Data I Sample Line'Max: 'Avg: I Ambient Air Pit Room'Max: 'Avg: Gas (units) Chromatograph (ppm) I Depth to to Ito to to to Ito to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG -Connection Gas;WTG-Wiper Trip Gas; POG- Pumps Off Gas; PG- Produced Gas; RG- Ream Gas;T---Trip...; F--- Formation...; E--- Early... ' I r 24 hr Recap: While running casing to bottom, casing became stuck. Began circulating with hole taking fluid. R/U for cement job Pumped lube pill,while pumping got H2S in flow line setting off alarms. Rig was evacutaed and gas vented.Observed well was flowing,shut in well and bled off pressure.Pumped LCM. Pumped cement job. Preparing to rig down cement jobs at report time. I Losses observed to the hole for the previous 24 hours was 476 bbl, and the max gas was 528 units. Max H2S seen in sample line coming from the pits was 60 PPM. I I ILogging Engineer: Dan Sherwood/Colby Marks * 10000 units= 100% Gas In Air I I ICustomer: Pioneer Natural Res. Report#: 10 HALLIBURTON Well: ODSN-15i Date: 5/5/2010 I ._ . Area: Oooguruk 04:00 Depth 11379' Location: North Slope Progress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Lay down 5"DP Job No.: AK-AM-0007262433 Report For: R.Klepzig/A.Vaughn IDaily Charges $4,462.18 Total Charges: $87,970.40 I ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: R.O.P. (ft/hr) Flow In (gpm) SPP (psi) Gas (units) Flow In (spm) Gallons/stroke • I Mud Data: Density(ppg) Viscosity MBT PV YP API Flit pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I 11379' IBHA Run # I Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition I Lithology (%): Sd _ Sst _ Silt Siltst Cht Clyst Sh _ Lst Coal _ Gvl Tuff (current) IGas Breakdown H2S Data I Sample Line jMax: 'Avg: I Ambient Air Pit Room IMax: Avg: Gas (units) Chromatograph (ppm) I Depth to to I to _ to to to I to to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG -Connection Gas;VVTG-Wiper Trip Gas; POG- Pumps Off Gas; PG - Produced Gas; RG - Ream Gas;T---Trip...; F--- Formation...; E--- Early... I 24 hr Recap: Bumped cement plug. N/D stack and install emergency slips. Cut casing. Rig up MPD. Laying down 5"DP at time of report. I I I Logging Engineer: Dan Sherwood/Colby Marks 10000 units= 100% Gas In Air I ICustomer: Pioneer Natural Res. Report#: 11 HALLIBUATON Well: ODSN-15i Date: 5/6/2010 I Area: Oooguruk 04:00 Depth Progress 11379' Location: North Slope ress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Pick up DP Job No.: AK-AM-0007262433 Report For: R.Klepzig/A.Vaughn 1 Daily Charges $4,462.18 Total Charges: $92,432.58 I ROP & Gas: Current Avg R.O.P. (ft/hr) 24 hr Max Max @ it Flow In (gpm)Current Pump & Flow Data: SPP (psi) Gas(units) Flow In (spm) Gallons/stroke I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I % 11379' 7.80 7.80 40 10 10 3.8 'BHA Run # I Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition ILithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst _ Coal Gvl Tuff (current) IGas Breakdown H2S Data l Sample Line'Max: !Avg: l Ambient Air Pit Room Max: 'Avg: Gas (units) Chromatograph (ppm) I Depth to to to to _ _ to to I to to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG-Connection Gas;WTG-Wiper Trip Gas; POG- Pumps Off Gas; PG- Produced Gas; RG- Ream Gas;T---Trip...; F--- Formation...; E--- Early... 24 hr Recap: Finished laying down 5"DP. Began picking up 4"DP,still picking up 4"DP at report time. I I I Logging Engineer: Dan Sherwood/Colby Marks 10000 units= 100%Gas In Air I I ICustomer: Pioneer Natural Res. Report#: 12 HALLIBURTON Well: ODSN-15i Date: 5/7/2010 I Area: Oooguruk 04:00 Depth Progress 11379' Location: North Slope ress 24 hrs: 0' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Test BOP Job No.: AK-AM-0007262433 Report For: R.Klepzig/J.Cortez IDaily Charges $4,462.18 Total Charges: $96,894.76 I ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: R.O.P. (ft/hr) Flow In (gpm) SPP (psi) Gas(units) Flow In (spm) Gallons/stroke I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I % 11379' 10.80 10.80 45 7.5 11 24 8.6 9.50 22,000 10.4 BHA Run # Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition ILithoiogy (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) IGas Breakdown H2S Data I Sample Line'Max: 'Avg: l Ambient Air Pit Room Max: 'Avg: Gas(units) Chromatograph (ppm) I Depth to to I to to to to I to to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG-Connection Gas;WTG-Wiper Trip Gas; POG- Pumps Off Gas; PG- Produced Gas; RG- Ream Gas;T---Trip...; F--- Formation...; E--- Early... 24 hr Recap: Finished RIH with 4"DP. Pumped slug and POOH.Testing BOPs at report time. I I I Logging Engineer: Dan Sherwood/Colby Marks * 10000 units= 100% Gas In Air I I ICustomer: Pioneer Natural Res. Report#: 13 HALLIBURTON Well: ODSN-15i Date: 5/8/2010 I Area: Oooguruk 04:00 Depth 11399' Location: North Slope Progress 24 hrs: 20' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Displace w/OBM Job No.: _AK-AM-0007262433 Report For: R.Klepzig/J.Cortez IDaily Charges $4,462.18 Total Charges: $101,356.94 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: R.O.P. (ft/hr) 0.0 40.0 53.0 11389' Flow In (gpm) SPP (psi) Gas (units) 0 20 39 _ 11381' _ Flow In (spm) Gallons/stroke 3.7030 • I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH ChloridesrCor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/1 ok 11379' 10.80 10.80 45 7.5 11 24 8.6 9.50 22,000 10.4 IBHA Run # Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition 4 Hycalog 6.125 0.416 0.50 11379' 20' 1 Lithoiogy (%): Sd Sst _ Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) IGas Breakdown H2S Data I Sample Line Pax: Avg: I Ambient Air Pit Room Max: 'Avg: Gas (units) Chromatograph (ppm) I Depth to to I to to to to I to to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG-Connection Gas;WTG-Wiper Trip Gas; POG- Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T---Trip...; F--- Formation...; E--- Early... I24 hr Recap: RIH and tag cement. Drill out shoe track, rathole and 20'of new formation. Perform FIT to 12.5 ppg. Install RCD element.At report time,cleaning out pits in preparation for displacement to OBM. I I I Logging Engineer: Dan Sherwood/Colby Marks 10000 units= 100% Gas In Air I I Customer: Pioneer Natural Res. Report#: 14 U A LLIBURTON Well: ODSN-15i Date: 5/9/2010 ' Area: Oooguruk 04:00 Depth 12366' Location: North Slope Progress 24 hrs: 967' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK-AM-0007262433 Report For: R.Klepzig/J.Cortez IDaily Charges $4,462.18 Total Charges: $105,819.12 I ROP & Gas: Current Avg 24 hr Max . Max @ ft _ Current Pump & Flow Data: R.O.P. (ft/hr) 0.0 67.2 53.0 11389' Flow In (gpm) 247 SPP (psi) 2391 Gas(units) 239 220 1258 _ 11787' Flow In (spm) 70 Gallons/stroke 3.7030 I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt cP pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) (Ib/100ft2) ml/30min mg/I % 11960' 7.90 7.90 50 10 11 5.8 4.4 1 BHA Run # Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition 4 Hycalog 6.125 0.416 14.80 . 11379' 20 Lithology (%): Sd Sst Silt _ Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 90 10 IGas Breakdown H2S Data I Sample Line IMax: _lAvg: I Ambient Air Pit Room'Max: 'Avg: Gas(units) Chromatograph (ppm) I Depth 11,787 to 11,787 1258 295 138306 2731 771 192 37 CG 12,077 to 12,077 438 200 52019 1065 365 141 16 CG Ito to to to Ito to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG-Connection Gas;VVTG-Wiper Trip Gas; POG - Pumps Off Gas; PG- Produced Gas; RG - Ream Gas; T---Trip...; F--- Formation...; E--- Early... I24 hr Recap: Displaced well with OBM. Drilling ahead at report time No losses to the hole observed for the past 24 hrs.Max gas seen in the past 24hrs was 1258u I I I Logging Engineer: Dan Sherwood/Colby Marks 10000 units= 100%Gas In Air I I 1 Customer: Pioneer Natural Res. Report#: 15 HALLIBURTON Well: ODSN-15i Date: 5/10/2010 I Area: Oooguruk 04:00 Depth 12857 Location: North Slope Progress 24 hrs: 491' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK-AM-0007262433 Report For: R.Klepzig/J.Cortez Daily Charges $4,462.18 Total Charges: $105,819.12 I ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: R.O.P. (ft/hr) 1.2 22.3 80.0 12664' Flow In (gpm) 231 SPP (psi) 2247 Gas(units) 31 120 550 12640' Flow In (spm) 65 Gallons/stroke 3.7030 • I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I % 11960' 7.90 7.90 50 10 11 5.8 4.4 IBHA Run # Bit Type Size TFA Hours Depth in/out Footage . WOB RPM Condition 4 Hycalog 6.125 0.416 36.90 11379' ILithology (%): Sd Sst _ Silt Siltst Cht Clyst Sh Lst Coal _ Gvl Tuff (current) 90 10 , IGas Breakdown H2S Data I Sample Line IMax: JAvg: I Ambient Air Pit Room iMax: Avg: Gas(units) Chromatograph (ppm) I Depth to to I to to to to I to to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG -Connection Gas;WTG-Wiper Trip Gas; POG- Pumps Off Gas; PG- Produced Gas; RG- Ream Gas;T---Trip...; F--- Formation...; E---Early... I24 hr Recap: Drilling. Currently time drilling on siderite stringer. I I I Logging Engineer: Dan Sherwood/Colby Marks 10000 units= 100% Gas In Air I Customer: Pioneer Natural Res. Report#: 16 HALLIBURTON r Well: ODSN-15i Date: 5/11/2010 Area: Oooguruk 04:00 Depth 12857' Location: North Slope Progress 24 hrs: 826' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK-AM-0007262433 Report For: J.Polya/J.Cortez IDaily Charges $4,462.18 Total Charges: $110,281.30 I ROP & Gas: Current . Avg 24 hr Max Max @ ft Current Pump & Flow Data: R.O.P. (ft/hr) 117.0 42.0 249.0 12946' Flow In (gpm) 251 SPP (psi) 2240 Gas(units) 317 240 615 13522' Flow In (spm) 65 Gallons/stroke 3.7030 I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) m1/30min mg/I % 13254' 7.80 7.80 50 11 9 5.6 4.1 IBHA Run # I Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition 4 Hycalog 6.125 0.416 56.20 11379' 1 Lithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 95 5 IGas Breakdown H2S Data l Sample Line'Max: Avg: l Ambient Air Pit Room Max: iAvg: Gas(units) Chromatograph (ppm) I Depth 13,583 to 13,583 615 437 70959 1574 486 171 51 BG to Ito to to to I to to to I Gas Type abreviations: BG - Background Gas; GP-Gas Peak; CG-Connection Gas;WfG-Wiper Trip Gas; POG- Pumps Off Gas; PG - Produced Gas; RG - Ream Gas;T---Trip...; F--- Formation...; E--- Early... 24 hr Recap: Timed drilled through siderite. Drilling ahead at report time. No losses observed to hole. Max gas was 615 units, I I I ' Logging Engineer: Dan Sherwood/Colby Marks 10000 units= 100% Gas In Air I I Customer: Pioneer Natural Res. Report#: 17 HALLIBURTON Well: ODSN-15i Date: 5/12/2010 I Area: Oooguruk 04:00 Depth Progress 15672' Location: North Slope ress 24 hrs: 1955' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK-AM-0007262433 Report For: J.Polya/J.Cortez IDaily Charges $4,462.18 Total Charges: $114,743.48 I ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: R.O.P. (ft/hr) 74.0 119.0 279.0 15367' Flow In (gpm) 251 SPP (psi) 2240 Gas(units) 142 650 3197 14199' Flow In (spm) 65 Gallons/stroke 3.7030 • I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Car Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I 15261' 7.90 7.90 49 9 9 5.6 5.2 IBHA Run # I Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition 4 Hycalog 6.125 0.416 56.20 11379' Lithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 95 _ 5 IGas Breakdown H2S Data I Sample Line IMax: 'Avg: I Ambient Air Pit Room'Max: Avg: Gas(units) Chromatograph (ppm) I Depth 14,199 to 14,199 3197 452 327007 7848 2383 723 139 CG 14,296 to 14,296 464 392 54233 1166 417 181 60 CG I 14,296 to 14,672 1310 700 142059 2974 947 344 99 GP 14,672 to 15,500 1386 850 149259 4106 1330 470 127 GP to to to to to IGas Type abreviations: BG - Background Gas; GP-Gas Peak; CG -Connection Gas; WTG -Wiper Trip Gas; POG- Pumps Off Gas; PG- Produced Gas; RG- Ream Gas;T---Trip...; F--- Formation...; E--- Early... 24 hr Recap: Drilling for past 24 hours. No losses observed to the hole. Max gas for the past 24 hours was 3197 units I I I Logging Engineer: Dan Sherwood/Colby Marks * 10000 units= 100% Gas In Air I I 1 Customer: Pioneer Natural Res. Report#: 18 HALLIBURTON Well: ODSN-15i Date: 5/13/2010 Area: Oooguruk 04:00 Depth 17165' Location: North Slope Progress 24 hrs: 1493' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Drilling Job No.: AK-AM-0007262433 Report For: J.Polya/J.Cortez IDaily Charges $4,462.18 Total Charges: $119,205.18 I ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: R.O.P. (ft/hr) 98.5 119.0 235.0 17004' Flow In (gpm) 248 SPP (psi) 2808 Gas(units) 663 600 1040 17066' Flow In (spm) 70 Gallons/stroke 3.7030 I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I % 16661' 8.00 8.00 49 10 10 6.0 6.3 BHA Run # I Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition 4 Hycalog 6.125 0.416 87.91 11379 Lithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 100 IGas Breakdown H2S Data I Sample Line!Max: IAvg: j Ambient Air Pit Room IMax: 'Avg: Gas(units) Chromatograph (ppm) I Depth 15,936 to 15,936 668 155 77963 1540 467 150 17 CG 16,225 to 16,255 727 263 77122 1658 481 144 22 TG I 16,225 to 16,862 1038 730 106194 2397 722 260 82 GP to to to I to to to I Gas Type abreviations: BG - Background Gas; GP-Gas Peak; CG - Connection Gas;WTG-Wiper Trip Gas; POG- Pumps Off Gas; PG- Produced Gas; RG- Ream Gas;T---Trip...; F--- Formation...; E--- Early... I 24 hr Recap: Drilled to 16225'and decided to do a check trip after realizing the base of the Nuiqsut. Trip went fine, RIH and drill ahead.Currently drilling ahead at report time. No losses to the hole at time of report. Max gas for the past hole section was 1040 units. I I I Logging Engineer: Dan Sherwood/Colby Marks ` 10000 units= 100%Gas In Air I Customer: Pioneer Natural Res. Report#: 19 HALLIBURTON Well: ODSN-15i Date: 5/14/2010 I Area: Oooguruk 04:00 Depth 17383' Location: North Slope Progress 24 hrs: 218' Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Washing Job No.: AK-AM-0007262433 Report For: J.Polya/J.Cortez IDaily Charges $4,462.18 Total Charges: $123,667.36 I ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: R.O.P. ft/hr 109.0 152.0 17312' Flow In •pm) 70 SPP (psi) 1779 Gas (units) 411 365 1788 17113' Flow In (spm) 20 Gallons/stroke 3.7030 I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Car Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I % 17383' 8.10 8.10 48 10 9 6.0 7.5 IBHA Run # Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition 4 Hycalog 6.125 0.416 87.91 11379' 17383' 6004' IILithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 100 IGas Breakdown H2S Data I Sample Line'Max: lAvg: I Ambient Air Pit Room Max: Avg: Gas (units) Chromatograph (ppm) I Depth 17,113 to circ 1788 574 WTG to to to to to I to to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG-Connection Gas;WTG-Wiper Trip Gas; POG- Pumps Off Gas; PG- Produced Gas; RG- Ream Gas;T---Trip...; F--- Formation...; E---Early... I 24 hr Recap: TD well at 17,383'. Pump sweep and trip out to shoe. Slip and cut drill line. RIH. Currently attempting to wash to bottom at 17112,after experiencing pack off and it pulling tight. No losses observed to the hole for the past 24 hours. Max gas seen was 1788 units I I I 1 Logging Engineer: Dan Sherwood/Colby Marks * 10000 units= 100%Gas In Air I I Customer: Pioneer Natural Res. Report#: 20 HALLIBURTON Well: ODSN-15i Date: 5/15/2010 I Area: Oooguruk 04:00 Depth 17383' Location: North Slope Progress 24 hrs: Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Flush stack Job No.: AK-AM-0007262433 Report For: J.Polya/J.Cortez IDaily Charges $3,762.72 Total Charges: $127,430.08 I ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: R.O.P. (ft/hr) Flow In (gpm) SPP (psi) Gas(units) 150 1219 17144' Flow In (spm) Gallons/stroke 3.7030 • I Mud Data: Depth ft Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids in out (sec/qt) (ppb Eq) cP (Ib/100ft2) ml/30min mg/I % 17383' 10.40 10.40 80 19 15 5.4 19.0 1 BHA Run # I Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition 4 Hycalog 6.125 0.416 87.91 11379' 17383 6004' Lithology (%): Sd Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) 100 IGas Breakdown H2S Data I Sample Line!Max: 'Avg: I Ambient Air Pit Room IMax: 'Avg: Gas (units) Chromatograph (ppm) I Depth to to to to to to to to to I Gas Type abreviations: BG- Background Gas; GP-Gas Peak; CG-Connection Gas;WTG-Wiper Trip Gas; POG- Pumps Off Gas; PG- Produced Gas; RG- Ream Gas;T---Trip...; F--- Formation...; E---Early... I 24 hr Recap: Diplaced lateral section of hole with 7.2ppg OBM. POOH to sump at 12050 and circulated kill weight fluid,10.2 ppg, to surface while pulling to shoe. Once at shoe finished displacement. Remove RCD.Conitnue POOH and lay down MWD Getting ready to run liner at time.Flushing stack at report time. I I I Logging Engineer: Dan Sherwood/Colby Marks * 10000 units= 100%Gas In Air I / . Customer: Pioneer Natural Res. Report#: 21 HALLIBURTON Well: ODSN-15i Date: 5/16/2010 I Area: Oooguruk 04:00 Depth 17383' Location: North Slope Progress 24 hrs: Sperry Drilling Services Rig: Nabors 19AC Rig Activity: Set Packer Job No.: AK-AM-0007262433 Report For: J.Polya/J.Cortez IDaily Charges $3,762.72 Total Charges: $131,192.80 ROP & Gas: Current Avg 24 hr Max Max @ ft Current Pump & Flow Data: R.O.P. (ft/hr) Flow In (gpm) SPP (psi) Gas (units) Flow In (spm) Gallons/stroke 3.7030 I Mud Data: Density(ppg) Viscosity MBT PV YP API Filt pH Chlorides Cor Solids Depth ft in out (sec/qt) (ppb Eq) cP (Ib/100ft2) m1/30min mg/I % 17383' 10.20 10.20 55 22 15 5.6 19.1 IBHA Run # I Bit Type Size TFA Hours Depth in/out Footage WOB RPM Condition 4 Hycalog 6.125 0.416 87.91 11379' 17383' 6004' ILithology (%): Sd _ Sst Silt Siltst Cht Clyst Sh Lst Coal Gvl Tuff (current) IGas Breakdown H2S Data I Sample Line IMax: IAvg: I Ambient Air Pit Room IMax: 'Avg: Gas(units) Chromatograph (ppm) I Depth to to I to to to to I to to to I Gas Type abreviations: BG - Background Gas; GP-Gas Peak; CG- Connection Gas;WTG-Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG- Ream Gas; T---Trip...; F--- Formation...; E---Early... I 24 hr Recap: Test BOP's. Rig up to run liner, RIH to shoe and circulate 750 stks. Continue RIH with liner on drill pipe. Setting packer at report time. No losses or gas to report for this time period. I I I ' Logging Engineer: Dan Sherwood/Colby Marks * 10000 units= 100% Gas In Air I E. I I E N CC I � L o000 0 T O7 L . O. C T O7 O O N a a 2 I OZ < ' Cal OD a- Z a o O Q a m cu Q a N p O z W D O K X p r2 O w 2 m U a Z U 2 m a C1 x I O E ° 28 J N LL y V 7 O a X Nel a m co m re el Tr N E M U n 1 ii, Z, 4 � E N Y C 0 0 0 m j( 0 O R co Y O m v - O a co z a E w Q O O om • a O U E O j 0 v Z Q p } a 0 c"o W K a o oo J O a FW CO �o 1 N i o 00 m o 0 0 I v m 3 w O o `VV COO LL •t I 11 _ Fri' c-' p O t Z �n c m I m — � N 0 Ille m � N co co . I CC 3 m U 0 a Ce C rn O i W m N V O O T T I S S _ M W m = to p Z O m rt a x m I 1 1 Y m Q D_ C Q c Q d Q. 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O2 N m N M M R R R Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q• Q d .1 N A 4 6 6 r co' OS N N N N N 6 s- C� 2l 2 d 2 N ,J2 42 a2 N N N N N N NW � W CO U 0 p)r n IC I I HALLIBURTON Sperry Drilling I ODSN_-15i Formation Tops Marker MD INC AZ TVD I Top Permafrost 841.0 8.2 316.3 838.1 Base Permafrost 1742.0 37.3 283.0 1667.6 Top West Sak 2512.0 36.0 241.3 2287.5 I Tuffaceous Shale 3503.0 62.7 243.1 2943.8 SCP 3589.0 63.7 242.9 2982.3 Brook 2B 6512.0 63.6 244.2 4267.3 I Torok Top 8149.0 64.5 246.2 4991.1 Torok Base 8732.0 64.5 250.1 5241.6 ICP1 8870.0 64.5 248.6 5301.3 I Top HRZ 9984.0 69.7 273.3 5743.3 Base HRZ 10386.0 72.2 291.8 5873.5 Kalubik Marker 10666.0 72.9 299.7 5956.5 I Kup C 10859.0 73.3 305.5 6013.2 LCU 10867.0 73.2 305.5 6015.5 BCU 11201.0 71.3 306.0 6118.6 BCU::Top Nuigsut_D1 11325.0 71.6 305.5 6158.1 Top Nuiqsut::Nuiq_1_D1 11347.0 71.6 305.5 6165.1 ICP2 11348.0 71.6 305.5 6165.4 I Nuiq_1::Nuiq_2_D1 11494.0 78.2 304.8 6204.1 Nuiq_2::Nuiq_3_D1 11500.0 78.5 304.8 6205.4 Nuiq_3::Nuiq_4_D1 11588.0 82.7 305.6 6219.7 I Nuiq_4::Nuiq_5_D1 11611.0 83.8 306.1 6222.4 Wert#1 (1-41 12044.7 90.0 312.6 6248.2 Nuiq_5::Nuiq_4_U2 13275.0 95.0 312.8 6227.6 I Nuiq_4::Nuiq_3_U2 13305.0 94.9 313.3 6224.9 Nuiq_3::Nuiq_2_U2 13487.0 94.4 317.2 6211.9 Nuiq_2::Nuiq_1_U2 13505.0 94.2 317.3 6210.5 I Revert#1 (T7) 14222.3 90.0 323.1 6181.4 Green 3 Fault(Nuiq_1::Nuiq_5) D3 15535.0 88.9 325.9 6205.0 Nuiq_5::Base Nuiqsut 15608.0 86.8 324.0 6207.8 Invert#2(T10) 15827.0 90.0 319.4 6218.2 Base Nuiqsut:: Nuiq_5_U4 15985.0 95.1 319.1 6208.3 Nuiq_5::Nuiq_4_U4 16370.0 94.9 318.1 6174.9 I Nuiq_4::Nuiq_3_U4 16395.0 94.9 318.0 6172.8 Nuiq_3::Nuiq_2_U4 16615.0 94.1 315.9 6155.6 Nuiq_2::Nuiq_1_U4 16631.0 94.0 316.0 6154.4 I Nuiq 1::Top_Nuiq_U4 17162.0 94.9 314.3 6115.3 Top Nuiq::BCU_U4 17240.0 95.1 313.7 6108.6 TD(T13) 17382.6 _ 95.0 313.7 6096.1 I PIONEER I NATURAL RESOURCES I SCHLUMBERGER ISurvey report 13-May-2010 15:08:34 Page 1 of 8 Client • I Field • Well Spud date API number • Last survey date • 13-May-10 Engineer - Total accepted surveys...: 207 I COUNTY. MD of first survey 0.00 ft MD of last survey - 17345.62 ft STATE- - I Survey calculation methods Geomagnetic data Method for positions • Minimum curvature Magnetic model • BGGM version 2009 Method for DLS Mason & Taylor Magnetic date • 15-Apr-2010 Magnetic field strength..: 57656.70 GAMA Depth reference Magnetic dec (+E/W-) 21.56 degrees I Permanent datum GROUND LEVEL Magnetic dip - 80.90 degrees Depth reference - GL above permanent -50000.00 ft MWD survey Reference Criteria KB above permanent • -50000.00 ft Reference G - 1002.69 mGal DF above permanent • -50000.00 ft Reference H • 57656.50 GAMA I Reference Dip 80.90 degrees Vertical section origin Tolerance of G • (+/-) 2.50 mGal Latitude (+N/S-) - 0.00 ft Tolerance of H - (+/-)300.00 GAMA Departure (+E/W-) • 0.00 ft Tolerance of Dip • (+/-) 0.45 degrees I Platform reference point Corrections Magnet Latitude (+N/S-) 0.00 ft Magnetic dec (+E/W-) • 21.56 degrees Departure (+E/W-) • 0.00 ft Grid convergence (+E/W-).: 0.00 degrees Total az corr (+87W-) 21.56 degrees I Azimuth from Vsect Origin to target: 283.37 degrees (Total az corr = magnetic dec - grid cony) Survey Correction Type . I=Sag Corrected Inclination M=Schlumberger Magnetic Correction I S=Shell Magnetic Correction F=Failed Axis Correction R=Magnetic Resonance Tool Correction D=Dmag Magnetic Correction I [(c)2010 IDEAL ID15_OC_05]❑ SCHLUMBERGER Survey Report 13-May-2010 15:08:34 Page 2 of 8 Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) 1 0.00 0.00 0.00 0.00 81.59 0.30 272.24 81.59 0.00 0.00 0.00 0.00 0.00 0.00 0.00 TIP None 2 81.59 0.21 0.01 -0.21 0.21 272.24 0.37 GYR None 3 140.59 0.69 272.71 59.00 140.59 0.71 0.03 -0.72 0.72 272.47 0.66 GYR None 4 180.59 0.97 279.09 40.00 180.58 1.28 0.10 -1.30 1.30 274.23 0.74 GYR None I S 211.59 1.36 286.55 31.00 211.58 1.91 0.24 -1.91 1.92 277.23 1.35 GYR None 6 241.59 1.73 298.23 30.00 241.57 2.71 0.56 -2.65 2.71 281.89 1.61 GYR None 7 272.59 2.29 304.92 31.00 272.55 3.74 1.13 -3.57 3.75 287.62 1.96 GYR None 8 302.59 2.60 308.45 30.00 302.52 4.91 1.90 -4.59 4.97 292.47 1.15 GYR None I 9 333.59 2.94 313.30 31.00 333.48 6.23 2.88 -5.72 6.41 296.73 1.33 GYR None 10 363.59 3.36 312.68 30.00 363.44 7.67 4.01 -6.93 8.00 300.03 1.40 GYR None 11 454.61 5.40 310.42 91.02 454.19 13.81 8.59 -12.15 14.88 305.26 2.25 GYR None I 12 544.91 6.16 307.55 90.30 544.03 22.01 14.30 -19.23 23.96 306.64 0.90 GYR None 13 636.31 6.99 298.90 91.40 634.83 31.85 19.98 -27.98 34.38 305.52 1.41 GYR None 14 730.59 6.46 281.23 94.28 728.47 42.67 23.78 -38.21 45.01 301.90 2.26 GYR None 15 764.05 6.26 286.95 33.46 761.72 46.38 24.68 -41.80 48.54 300.56 1.98 MWD M None I 16 825.59 7.90 312.76 61.54 822.81 53.41 28.53 -48.12 55.94 300.67 5.75 GYR None 17 861.68 8.57 320.96 36.09 858.53 57.70 32.30 -51.63 60.91 302.03 3.74 GYR None 18 890.59 9.53 327.38 28.91 887.08 61.13 35.99 -54.28 65.13 303.55 4.81 GYR None 19 921.59 9.82 330.60 31.00 917.64 64.77 40.46 -56.96 69.87 305.38 1.98 GYR None I 20 952.64 10.31 333.12 31.05 948.21 68.37 45.24 -59.52 74.76 307.24 2.12 MWD-M None 21 986.50 10.58 328.12 33.86 981.51 72.53 50.58 -62.53 80.43 308.97 2.79 MWD_M None 22 1016.59 10.75 330.45 30.09 1011.08 76.40 55.37 -65.37 85.67 310.27 1.54 GYR None I I 23 1112.49 15.10 326.81 95.90 1104.53 91.57 73.61 -76.63 106.26 313.85 4.61 GYR None I 24 1142.92 15.77 329.85 30.43 1133.86 25 1177.36 15.71 321.49 34.44 1167.01 97.30 80.51 -80.87 114.11 314.87 3.45 MWD_M None 104.19 88.20 -86.13 123.28 315.68 6.58 MWD_M None 26 1206.44 16.26 318.63 29.08 1194.97 110.61 94.34 -91.27 131.26 315.95 3.30 MWD M None I 27 1237.50 17.29 314.73 31.06 1224.71 118.10 100.85 -97.42 140.22 315.99 4.91 MWD_M None 28 1270.30 18.53 314.00 32.80 1255.92 126.75 107.90 -104.64 150.31 315.88 3.84 GYR None 29 1302.59 20.18 312.31 32.29 1286.38 136.04 115.22 -112.45 160.99 315.70 5.40 GYR None 30 1396.93 25.11 304.06 94.34 1373.44 169.04 137.40 -141.09 196.94 314.24 6.20 MWD_M None I [(c)2010 IDEAL ID15_0C_05]❑ ISCHLUMBERGER Survey Report 13-May-2010 15:08:34 Page 3 of 8 Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr 1 -_- (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) 31 1427.47 26.49 300.20 30.54 1400.94 181.62 144.46 -152.34 209.94 313.48 7.12 MWD_M None 32 1492.59 27.28 300.62 65.12 1459.02 209.77 159.36 -177.74 238.72 311.88 1.25 GYR None 33 1587.59 32.24 295.99 95.00 1541.48 255.33 181.57 -219.28 284.70 309.63 5.75 GYR None I 34 1619.00 33.79 293.73 31.41 1567.82 35 1715.85 37.03 284.59 96.85 1646.80 272.10 188.76 -234.81 301.27 308.80 6.30 GYR None 327.80 206.96 -287.74 354.44 305.73 6.40 MWD_M None 36 1811.89 38.14 278.80 96.04 1722.93 386.29 218.79 -345.05 408.57 302.38 3.85 MWD_M None I 37 1905.42 35.96 274.67 93.53 1797.58 442.24 225.44 -400.98 460.01 299.35 3.54 MWD_M None 38 2000.03 36.01 270.73 94.61 1874.15 496.85 228.06 -456.48 510.28 296.55 2.45 MWD_M None 39 2095.76 36.79 265.02 95.73 1951.22 551.53 225.93 -513.20 560.73 293.76 3.63 MWD_M None 40 2191.12 36.82 259.75 95.36 2027.59 604.83 218.36 -569.78 610.19 290.97 3.31 MWD_M None I 41 2286.79 36.06 254.97 95.67 2104.57 655.88 205.96 -625.19 658.25 288.23 3.07 MWD M None 42 2381.45 35.54 248.87 94.66 2181.37 703.07 188.81 -677.78 703.59 285.57 3.81 MWD_M None 43 2473.98 35.60 242.21 92.53 2256.67 745.53 166.55 -726.71 745.55 282.91 4.19 MWD_M None 44 2568.44 36.65 239.98 94.46 2332.97 786.72 139.63 -775.45 787.92 280.21 1.78 MWD_M None I 45 2665.83 38.50 239.85 97.39 2410.15 829.82 109.86 -826.83 834.10 277.57 1.90 MWD-M None 46 2761.14 41.28 241.24 95.31 2483.28 874.66 79.82 -880.06 883.67 275.18 3.06 MWD M None 47 2855.79 46.23 242.09 94.65 2551.62 923.53 48.78 -937.66 938.93 272.98 5.27 MWD_M None 48 2950.94 50.59 243.62 95.15 2614.77 977.64 16.35 -1000.98 1001.12 270.94 4.74 MWD_M None I 49 3046.61 51.06 243.80 95.67 2675.20 1034.73 -16.49 -1067.48 1067.61 269.11 0.51 MWD_M None 50 3141.98 49.06 243.74 95.37 2736.42 1091.07 -48.81 -1133.07 1134.12 267.53 2.10 MWD_M None 51 3236.96 50.49 243.78 94.98 2797.76 1146.94 -80.87 -1198.11 1200.84 266.14 1.51 MWD_M None 52 3332.23 54.75 242.80 95.27 2855.59 1204.84 -114.91 -1265.71 1270.92 264.81 4.55 MWD_M None I 53 3427.14 59.44 242.74 94.91 2907.13 1265.32 -151.36 -1336.54 1345.09 263.54 4.94 MWD_M None 54 3522.33 63.49 243.23 95.19 2952.59 1329.01 -189.33 -1411.03 1423.68 262.36 4.28 MWD_M None 55 3534.14 63.51 242.85 11.81 2957.86 1337.07 -194.12 -1420.45 1433.66 262.22 2.88 MWD_M None I 56 3559.22 63.54 242.65 25.08 2969.04 1354.11 -204.40 -1440.41 1454.84 261.92 0.72 MWD_M None 57 3652.90 64.00 243.34 93.68 3010.45 1418.13 -242.56 -1515.28 1534.57 260.91 0.82 MWD_M None 58 3747.33 64.35 243.12 94.43 3051.58 1483.11 -280.84 -1591.17 1615.77 259.99 0.43 MWD_M None 59 3842.86 64.00 243.63 95.53 3093.20 1548.98 -319.38 -1668.04 1698.34 259.16 0.60 MWD_M None 60 3938.20 64.19 243.17 95.34 3134.85 1614.71 -357.78 -1744.72 1781.03 258.41 0.48 MWD_M None 1 [(c)2010 IDEAL ID15_0C_05]0 ISCHLUMBERGER Survey Report 13-May-2010 15:08:34 Page 4 of 8 Seq Measured Intl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool I -#- depth angle angle length depth section +N/S- (ft) +E/W- displ Azim (deg/ tool Corr (ft) (deg (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) 61 4033.76 64.38 243.26 95.56 3176.32 1680.51 -396.58 -1821.58 1864.25 257.72 0.22 MWD_M None 62 4128.80 63.77 243.10 95.04 3217.87 1745.81 -435.14 -1897.86 1947.11 257.09 0.66 MWD_M None I 63 4224.29 63.65 243.34 95.49 3260.16 1811.24 -473.71 -1974.29 2030.33 256.51 0.26 MWD_M None 64 4319.93 63.59 242.63 95.64 3302.66 1876.51 -512.63 -2050.63 2113.73 255.96 0.67 MWD_M None 65 4414.15 63.62 242.58 94.22 3344.54 1940.43 -551.47 -2125.56 2195.93 255.46 0.06 MWD_M None 66 4509.51 63.74 242.09 95.36 3386.82 2004.90 -591.15 -2201.26 2279.26 254.97 0.48 MWD_M None I 67 4605.37 63.85 241.36 95.86 3429.15 2069.17 -631.89 -2277.00 2363.06 254.49 0.69 MWD_M None 68 4700.01 63.92 241.44 94.64 3470.81 2132.35 -672.57 -2351.61 2445.90 254.04 0.11 MWD_M None 69 4795.45 63.78 243.17 95.44 3512.88 2196.94 -712.39 -2427.47 2529.84 253.64 1.63 MWD_M None NM ' 70 4891.19 63.93 243.70 95.74 3555.06 2262.84 -750.82 -2504.34 2614.47 253.31 0.52 MWD_M None 71 4985.81 63.96 243.47 94.62 3596.62 2328.17 -788.64 -2580.47 2698.29 253.01 0.22 MWD_M None 72 5081.71 64.03 243.33 95.90 3638.67 2394.22 -827.23 -2657.53 2783.31 252.71 0.15 MWD_M None 73 5175.26 64.04 244.27 93.55 3679.63 2459.05 -864.36 -2733.00 2866.43 252.45 0.90 MWD_M None ' 74 5271.40 64.17 244.65 96.14 3721.62 2526.35 -901.65 -2811.03 2952.10 252.22 0.38 MWD_M None 75 5365.96 63.79 244.94 94.56 3763.10 2592.78 -937.84 -2887.92 3036.38 252.01 0.49 MWD_M None 76 5461.21 63.62 244.25 95.25 3805.30 2659.36 -974.47 -2965.05 3121.08 251.81 0.67 MWD_M None 77 5557.12 63.73 244.37 95.91 3847.83 2726.11 -1011.74 -3042.52 3206.33 251.61 0.16 MWD_M None ' 78 5651.31 63.87 244.47 94.19 3889.41 2791.83 -1048.23 -3118.75 3290.19 251.42 0.18 MWD_M None 79 5746.85 64.07 244.28 95.54 3931.34 2858.55 -1085.36 -3196.15 3375.41 251.24 0.28 MWD_M None 80 5842.79 64.13 244.16 95.94 3973.25 2925.48 -1122.89 -3273.87 3461.08 251.07 0.13 MWD_M None ' 81 5936.46 63.97 244.37 93.67 4014.24 2990.84 -1159.46 -3349.74 3544.73 250.91 0.26 MWD_M None 82 6031.84 63.94 244.67 95.38 4056.12 3057.58 -1196.33 -3427.10 3629.90 250.76 0.28 MWD_M None 83 6127.47 64.30 244.65 95.63 4097.86 3124.72 -1233.15 -3504.86 3715.47 250.62 0.38 MWD_M None 84 6222.91 63.91 244.58 95.44 4139.54 3191.67 -1269.96 -3582.43 3800.87 250.48 0.41 MWD_M None 85 6318.56 64.00 244.59 95.65 4181.53 3258.66 -1306.84 -3660.05 3886.36 250.35 0.09 MWD_M None ' 86 6413.64 63.56 244.59 95.08 4223.54 3325.15 -1343.44 -3737.09 3971.23 250.23 0.46 MWD_M None 87 6509.01 63.58 244.19 95.37 4265.99 3391.54 -1380.36 -3814.10 4056.20 250.10 0.38 MWD_M None 88 6604.03 63.43 243.81 95.02 4308.38 3457.28 -1417.63 -3890.54 4140.77 249.98 0.39 MWD_M None 89 6699.30 63.59 243.32 95.27 4350.88 3522.79 -1455.59 -3966.89 4225.51 249.85 0.49 MWD_M None 90 6794.06 63.56 242.70 94.76 4393.05 3587.45 -1494.11 -4042.50 4309.78 249.72 0.59 MWD_M None ' ((c)2010 IDEAL ID15_0C_05)0 SCHLUMBERGER Survey Report 13-May-2010 15:08:34 Page 5 of 8 ' S-eq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -91 6889.39 63.57 242.27 95.33 4435.49 3651.98 -1533.54 -4118.21 4394.48 249.58 0.40 MWD_M None 92 6983.73 63.56 241.98 94.34 4477.49 3715.50 -1573.04 -4192.89 4478.25 249.44 0.28 MWD_M None 93 7077.89 63.52 241.35 94.16 4519.44 3778.43 -1613.05 -4267.08 4561.79 249.29 0.60 MWD_M None 94 7174.22 63.28 241.53 96.33 4562.58 3842.51 -1654.23 -4342.73 4647.13 249.15 0.30 MWD_M None 95 7269.06 63.53 242.26 94.84 4605.03 3906.05 -1694.18 -4417.54 4731.27 249.02 0.74 MWD_M None 96 7365.07 63.50 242.69 96.01 4647.85 3971.01 -1733.89 -4493.75 4816.65 248.90 0.40 MWD_M None 97 7459.87 63.50 243.97 94.80 4690.15 4035.96 -1771.97 -4569.56 4901.09 248.80 1.21 MWD_M None 98 7554.64 63.49 244.50 94.77 4732.45 4101.75 -1808.83 -4645.93 4985.64 248.73 0.50 MWD_M None 99 7649.98 63.46 244.05 95.34 4775.02 4167.95 -1845.86 -4722.78 5070.69 248.65 0.42 MWD_M None ' 100 7745.94 64.00 243.87 95.96 4817.50 4234.43 -1883.63 -4800.10 5156.45 248.57 0.59 MWD_M None 101 7841.47 64.68 243.80 95.53 4858.86 4300.84 -1921.60 -4877.38 5242.27 248.50 0.71 MWD_M None 102 7936.69 64.54 244.22 95.22 4899.69 4367.35 -1959.30 -4954.71 5328.04 248.42 0.42 MWD_M None 103 8031.58 64.51 244.58 94.89 4940.50 4433.96 -1996.32 -5031.96 5413.49 248.36 0.34 MWD_M None 104 8126.84 64.48 246.10 95.26 4981.52 4501.68 -2032.19 -5110.09 5499.35 248.31 1.44 MWD_M None 105 8222.76 64.51 246.58 95.92 5022.83 4570.79 -2066.93 -5189.39 5585.87 248.28 0.45 MWD_M None 106 8317.58 64.54 247.44 94.82 5063.61 4639.72 -2100.36 -5268.19 5671.45 248.26 0.82 MWD_M None 107 8412.51 64.52 248.29 94.93 5104.44 4709.49 -2132.65 -5347.57 5757.15 248.26 0.81 MWD_M None 108 8507.70 64.58 249.19 95.19 5145.34 4780.21 -2163.82 -5427.68 5843.10 248.26 0.86 MWD_M None 109 8602.09 64.64 249.89 94.39 5185.81 4851.05 -2193.63 -5507.57 5928.35 248.28 0.67 MWD_M None 110 8696.46 64.54 250.31 94.37 5226.31 4922.32 -2222.64 -5587.72 6013.55 248.31 0.42 MWD_M None ' 111 8791.30 64.41 249.83 94.84 5267.18 4993.85 -2251.81 -5668.18 6099.09 248.33 0.48 MWD_M None 112 8850.64 64.24 249.45 59.34 5292.89 5038.33 -2270.42 -5718.32 6152.56 248.34 0.64 MWD_M None 113 8943.80 65.51 245.25 93.16 5332.45 5106.52 -2302.91 -5796.13 6236.86 248.33 4.30 MWD_M None 114 9039.33 66.02 249.55 95.53 5371.68 5177.00 -2336.36 -5876.52 6323.93 248.32 4.14 MWD_M None 115 9133.80 66.05 254.12 94.47 5410.07 5250.55 -2363.27 -5958.52 6410.07 248.37 4.42 MWD_M None 116 9227.14 65.83 256.96 93.34 5448.13 5325.91 -2384.55 -6041.04 6494.63 248.46 2.79 MWD_M None 117 9323.83 65.66 259.30 96.69 5487.86 5405.64 -2402.68 -6127.30 6581.54 248.59 2.21 MWD_M None 118 9418.92 65.69 261.60 95.09 5527.03 5485.44 -2417.06 -6212.74 6666.35 248.74 2.20 MWD_M None 119 9514.46 66.14 264.56 95.54 5566.03 5567.24 -2427.56 -6299.31 6750.88 248.92 2.87 MWD_M None 120 9609.44 66.86 267.89 94.98 5603.91 5650.46 -2433.29 -6386.21 6834.07 249.14 3.30 MWD_M None ' [(c)2010 IDEAL ID15_0C_05]❑ SCHLUMBERGER Survey Report 13-May-2010 15:08:34 Page 6 of 8 I Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) I 121 9705.28 67.63 271.01 95.84 5640.99 5736.23 -2434.13 -6474.57 6917.01 249.40 3.11 MWD_M None 122 9800.75 67.92 272.43 95.47 5677.10 5822.79 -2431.47 -6562.91 6998.84 249.67 1.41 MWD_M None 123 9895.37 68.88 275.54 94.62 5711.94 5909.57 -2425.35 -6650.65 7079.09 249.96 3.22 MWD_M None 124 9989.69 69.74 273.16 94.32 5745.26 5996.71 -2418.67 -6738.63 7159.54 250.26 2.53 MWD_M None I125 10087.36 70.50 275.75 97.67 5778.48 6087.44 -2411.53 -6830.19 7243.41 250.55 2.61 MWD_M None 126 10182.14 71.03 284.78 94.78 5809.76 6176.68 -2395.59 -6918.13 7321.16 250.90 9.01 MWD_M None 127 10276.53 71.90 288.85 94.39 5839.78 6265.99 -2369.70 -7003.78 7393.80 251.31 4.19 MWD_M None I 128 10371.36 72.16 291.55 94.83 5869.04 6355.54 -2338.55 -7088.42 7464.22 251.74 2.72 MWD_M None 129 10466.14 72.68 293.45 94.78 5897.67 6444.75 -2303.98 -7171.89 7532.88 252.19 1.99 MWD_M None 130 10560.65 72.95 295.88 94.51 5925.60 6533.28 -2266.30 -7253.94 7599.72 252.65 2.47 MWD_M None 131 10656.32 72.90 299.33 95.67 5953.70 6621.91 -2223.93 -7334.96 7664.70 253.13 3.45 MWD_M None I 132 10750.52 72.70 302.56 94.20 5981.56 6707.68 -2177.67 -7412.13 7725.41 253.63 3.28 MWD_M None 133 10846.16 73.30 305.43 95.64 6009.53 6793.27 -2126.53 -7487.95 7784.05 254.15 2.94 MWD_M None 134 10942.00 72.93 305.71 95.84 6037.36 6878.18 -2073.19 -7562.54 7841.57 254.67 0.48 MWD_M None 135 11036.75 71.46 305.95 94.75 6066.34 6961.55 -2020.38 -7635.68 7898.45 255.18 1.57 MWD_M None I 136 11132.76 71.52 305.66 96.01 6096.82 7045.70 -1967.12 -7709.52 7956.52 255.69 0.29 MWD_M None 137 11227.48 71.23 306.07 94.72 6127.07 7128.63 -1914.53 -7782.26 8014.30 256.18 0.51 MWD_M None 138 11322.84 71.61 305.49 95.36 6157.45 7212.19 -1861.68 -7855.59 8073.17 256.67 0.70 MWD_M None 139 11363.89 71.59 305.52 41.05 6170.41 7248.27 -1839.06 -7887.30 8098.87 256.88 0.08 MWD_M None I 140 11459.35 76.57 304.82 95.46 6196.59 7333.48 -1786.21 -7962.32 8160.21 257.36 5.26 MWD_M None 141 11555.95 81.19 304.84 96.60 6215.21 7421.67 -1732.08 -8040.10 8224.56 257.84 4.78 MWD_M None 142 11652.07 85.74 307.07 96.12 6226.15 7509.81 -1676.02 -8117.38 8288.60 258.33 5.26 MWD_M None 143 11748.99 87.02 310.33 96.92 6232.27 7597.22 -1615.56 -8192.85 8350.62 258.84 3.61 MWD_M None I 144 11845.90 84.72 312.55 96.91 6239.25 7682.50 -1551.59 -8265.30 8409.68 259.37 3.29 MWD_M None 145 11942.28 87.36 311.79 96.38 6245.91 7766.75 -1487.05 -8336.56 8468.15 259.89 2.85 MWD_M None 146 12039.18 89.93 312.48 96.90 6248.20 7851.66 -1422.07 -8408.39 8527.79 260.40 2.75 MWD_M None I 147 12135.71 91.17 313.80 96.53 6247.27 7935.45 -1356.07 -8478.82 8586.58 260.91 1.88 MWD_M None 148 12232.33 90.86 316.64 96.62 6245.56 8017.50 -1287.50 -8546.86 8643.29 261.43 2.96 MWD_M None 149 12328.53 91.55 317.65 96.20 6243.54 8097.44 -1217.00 -8612.27 8697.83 261.96 1.27 MWD_M None 150 12425.35 91.07 317.07 96.82 6241.32 8177.70 -1145.79 -8677.84 8753.16 262.48 0.78 MWD_M None I [(c)2010 IDEAL ID15_0C_05]0 SCHLUMBERGER Survey Report 13-May-2010 15:08:34 Page 7 of 8 ISeq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool # depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr I -_- (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) 151 12521.55 92.03 317.21 96.20 6238.72 8257.63 -1075.30 -8743.25 8809.13 262.99 1.01 MWD_M None 152 12618.03 91.58 318.75 96.48 6235.68 8337.00 -1003.67 -8807.80 8864.80 263.50 1.66 MWD_M None 153 12661.38 91.99 319.24 43.35 6234.33 8372.22 -970.97 -8836.23 8889.42 263.73 1.47 MWD_M None I 154 12713.87 89.56 317.60 52.49 6233.62 8415.18 -931.71 -8871.06 8919.85 264.00 5.58 MWD_M None 155 12810.83 90.31 316.26 96.96 6233.73 8495.98 -860.88 -8937.27 8978.63 264.50 1.58 MWD_M None 156 12907.35 90.96 314.62 96.52 6232.66 8577.76 -792.12 -9004.99 9039.76 264.97 1.83 MWD_M None 157 12928.34 89.86 313.82 20.99 6232.51 8595.78 -777.48 -9020.03 9053.47 265.07 6.48 MWD_M None I 158 13003.40 86.19 312.21 75.06 6235.10 8660.96 -726.31 -9074.87 9103.88 265.42 5.34 MWD_M None 159 13099.81 89.97 312.05 96.41 6238.33 8745.41 -661.69 -9146.31 9170.21 265.86 3.92 MWD_M None 160 13196.74 94.84 311.91 96.93 6234.26 8830.41 -596.93 -9218.28 9237.59 266.30 5.03 MWD_M None I 161 13293.25 95.02 312.97 96.51 6225.97 8914.45 -532.05 -9289.24 9304.46 266.72 1.11 MWD_M None 162 13389.56 94.19 315.34 96.31 6218.23 8996.91 -465.18 -9358.11 9369.66 267.15 2.60 MWD_M None 163 13415.72 93.75 316.04 26.16 6216.42 9018.96 -446.51 -9376.34 9386.96 267.27 3.16 MWD_M None 164 13440.36 93.13 316.03 24.64 6214.94 9039.67 -428.80 -9393.41 9403.20 267.39 2.52 MWD_M None 165 13485.94 94.43 317.22 45.58 6211.94 9077.70 -395.74 -9424.65 9432.95 267.60 3.86 MWD_M None I166 13583.07 93.06 317.53 97.13 6205.59 9158.05 -324.43 -9490.28 9495.83 268.04 1.45 MWD_M None 167 13679.63 93.50 318.75 96.56 6200.07 9237.24 -252.63 -9554.61 9557.95 268.49 1.34 MWD_M None 168 13776.29 92.47 320.91 96.66 6195.04 9314.87 -178.88 -9616.87 9618.54 268.93 2.47 MWD_M None I 169 13872.63 92.20 321.37 96.34 6191.11 9390.96 -103.92 -9677.27 9677.83 269.38 0.55 MWD_M None 170 13968.92 91.82 322.52 96.29 6187.73 9466.19 -28.15 -9736.58 9736.63 269.83 1.26 MWD_M None 171 14065.71 92.71 323.67 96.79 6183.91 9540.57 49.18 -9794.66 9794.78 270.29 1.50 MWD_M None ■ 172 14162.25 90.17 323.50 96.54 6181.48 9614.26 126.84 -9851.95 9852.76 270.74 2.64 MWD_M None 173 14257.53 89.90 322.87 95.28 6181.42 9687.45 203.12 -9909.04 9911.12 271.17 0.72 MWD_M None 174 14353.69 89.66 323.02 96.16 6181.79 9761.57 279.86 -9966.98 9970.91 271.61 0.29 MWD_M None 175 14449.84 89.76 323.08 96.15 6182.28 9835.56 356.70 -10024.78 10031.12 272.04 0.12 MWD_M None ' 176 14546.10 89.52 321.27 96.26 6182.88 9910.57 432.73 -10083.81 10093.09 272.46 1.90 MWD_M None 177 14643.63 90.28 321.06 97.53 6183.06 9987.64 508.70 -10144.97 10157.71 272.87 0.81 MWD_M None 178 14739.13 89.66 323.95 95.50 6183.10 10061.71 584.46 -10203.09 10219.82 273.28 3.10 MWD_M None 179 14835.86 88.94 323.21 96.73 6184.29 10135.57 662.29 -10260.51 10281.87 273.69 1.07 MWD_M None 180 14930.94 88.08 323.93 95.08 6186.76 10208.17 738.77 -10316.96 10343.37 274.10 1.18 MWD_M None ' ((c)2010 IDEAL ID15_0C_05]❑ SCHLUMBERGER Survey Report 13-May-2010 15:08:34 Page 8 of 8 Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool ' # depth angle angle length depth section (ft) (deg) (deg) (ft) (ft) (ft) +N/S- +E/W- displ Azim (deg/ tool Corr (ft) (ft) (ft) (deg) 100f) type (deg) 181 15028.41 88.19 323.22 97.47 6189.93 10282.57 817.15 -10374.80 10406.93 274.50 0.74 MWD_M None ' 182 15125.21 87.22 321.35 96.80 6193.81 10357.82 893.66 -10433.96 10472.17 274.90 2.17 MWD_M None 183 15220.77 88.77 320.33 95.56 6197.15 10433.62 967.71 -10494.27 10538.79 275.27 1.94 MWD_M None 184 15317.32 87.67 319.42 96.55 6200.15 10511.19 1041.50 -10556.46 10607.71 275.63 1.48 MWD_M None 185 15413.76 88.12 320.49 96.44 6203.69 10588.57 1115.27 -10618.47 10676.88 276.00 1.20 MWD_M None ' 186 15451.05 88.78 322.38 37.29 6204.70 10617.92 1144.42 -10641.70 10703.06 276.14 5.37 MWD_M None 187 15485.78 90.76 324.41 34.73 6204.84 10644.51 1172.30 -10662.41 10726.66 276.27 8.16 MWD_M None 188 15512.20 89.62 326.44 26.42 6204.75 10664.12 1194.05 -10677.40 10743.96 276.38 8.81 MWD M None 189 15608.88 86.74 323.96 96.68 6207.82 10736.11 1273.38 -10732.54 10807.82 276.77 3.93 MWD_M None 190 15705.22 86.47 321.12 96.34 6213.53 10810.66 1349.71 -10791.02 10875.11 277.13 2.96 MWD_M None ' 191 15802.39 88.46 319.45 97.17 6217.83 10888.27 1424.38 -10853.05 10946.12 277.48 2.67 MWD_M None 192 15899.04 94.43 319.37 96.65 6215.39 10966.36 1497.72 -10915.88 11018.15 277.81 6.18 MWD_M None 193 15995.26 95.15 319.02 96.22 6207.36 11044.11 1570.30 -10978.54 11090.28 278.14 0.83 MWD_M None 194 16090.32 95.26 318.61 95.06 6198.73 11121.23 1641.54 -11040.88 11162.24 278.46 0.44 MWD_M None 195 16186.40 94.81 318.36 96.08 6190.30 11199.52 1713.21 -11104.32 11235.70 278.77 0.54 MWD_M None 196 16283.73 94.78 318.75 97.33 6182.17 11278.79 1785.91 -11168.51 11310.40 279.09 0.40 MWD_M None 197 16379.67 94.91 318.07 95.94 6174.06 11357.06 1857.41 -11231.97 11384.51 279.39 0.72 MWD_M None ' 198 16476.23 94.57 317.50 96.56 6166.08 11436.44 1928.68 -11296.63 11460.09 279.69 0.69 MWD_M None 199 16571.40 94.26 315.85 95.17 6158.76 11515.74 1997.70 -11361.73 11536.02 279.97 1.76 MWD_M None 200 16667.59 93.88 316.04 96.19 6151.93 11596.60 2066.66 -11428.45 11613.81 280.25 0.44 MWD_M None 201 16765.33 93.88 315.69 97.74 6145.32 11678.84 2136.64 -11496.35 11693.22 280.53 0.36 MWD_M None ' 202 16863.41 93.98 315.15 98.08 6138.59 11761.78 2206.34 -11565.04 11773.61 280.80 0.56 MWD_M None 203 16958.80 94.50 314.24 95.39 6131.54 11843.04 2273.25 -11632.66 11852.70 281.06 1.10 MWD_M None 204 17055.42 94.43 314.16 96.62 6124.02 11925.76 2340.40 -11701.71 11933.47 281.31 0.11 MWD_M None 205 17152.94 94.88 314.35 97.52 6116.10 12009.17 2408.23 -11771.33 12015.15 281.56 0.50 MWD M None ' 206 17248.18 95.09 313.68 95.24 6107.83 12090.80 2474.16 -11839.57 12095.32 281.80 0.73 MWD_M None 207 17345.62 94.95 313.68 97.44 6099.30 12174.60 2541.19 -11909.76 12177.85 282.04 0.14 MWD_M None ((c)2010 IDEAL ID15_0C_05] 1 -IALLIBURTON ' Sperry Drilling Oooguruk 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