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Home My WebLink About206-053Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 07/19/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230719 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# PBU 07-20C 50029209020300 218036 6/8/2023 HALLIBURTON RBT PBU 13-19 50029206900000 181180 6/8/232 HALLIBURTON WFL-RMT3D PBU 18-29C 50029223160300 209055 6/13/2023 HALLIBURTON CAST-CBL PBU L-213 50029233080000 206053 6/12/2023 HALLIBURTON IPROF PBU M-205 50029237330000 222127 6/6/2023 HALLIBURTON IPROF PBU S-17c 50029211480300 202007 5/29/2023 HALLIBURTON RBT Please include current contact information if different from above. T37859 T37860 T37861 T37862 T37863 T37864 PBU L-213 50029233080000 206053 6/12/2023 HALLIBURTON IPROF Kayla Junke Digitally signed by Kayla Junke Date: 2023.07.19 13:22:09 -08'00' MEMORANDUM TO: Jim Regg P.I. Supervisor FROM: Brian Bixby Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, February 14, 2022 SUBJECT: Mechanical Integrity Tests Hilcorp North Slope, LLC L-213 PRUDHOE BAY UN ORIN L-213 Src: Inspector Reviewed By P.I. Suprv.�— Comm Well Name PRUDHOE BAY UN ORIN L-213 API Well Number 50-029-23308-00-00 Inspector Name: Brian Bixby Permit Number: 206-053-0 Inspection Date: 2/5/2022 Insp Num: mitBDB220205155052 Rel Insp Num: Monday, February 14, 2022 Page I of I Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well L -z13 w � Type Inj TVD T azss � Tubing, 2012 - 2007 I 2062 2073 - - PTD 2060530 i '] a Test I SPT Type I�Test psi: 1500 IA I — 15 I 2734 -II 62 26 2604 - r BBL Pumped: I P 2.6 BBI. 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Exploratory Development Service 5 Permit to Drill Number:206-053 6.API Number:50-029-23308-00-00 Prudhoe Bay Field, Orion Schrader Bluff Hilcorp North Slope, LLC 5. Field/Pools:9. Well Name and Number: ADL 028238 Property Designation (Lease Number):10. 8. PBU L-213 7.If perforating: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Stratigraphic Current Well Class:4. Type of Request:1.Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Polymer Injectivity Trial Op Shutdown GAS GSTOR5WAG SPLUG Abandoned Oil WINJ Exploratory Development Stratigraphic 5Service WDSPL 12. Attachments: PRESENT WELL CONDITION SUMMARY 6725 Effective Depth MD: L-80 11. 8/15/2020 Commission Representative: 15. Suspended Contact Name: Brodie Wages Contact Email: david.wages@hilcorp.com Authorized Name: Stan Golis Authorized Title:Operations Manager Authorized Signature: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Yes No Spacing Exception Required?Subsequent Form Required: Approved by:COMMISSIONER APPROVED BYTHE COMMISSION Date: 5OtherAlter Casing Pull Tubing Conditions of approval: Notify Commission so that a representative may witness Sundry Number: COMMISSION USE ONLY 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Detailed Operations Program Packers and SSSV Type: No SSSV Installed Packers and SSSV MD (ft) and TVD (ft): Perforation Depth MD (ft):Tubing Size: Size Total Depth MD (ft):Total Depth TVD(ft): 4811 Effective Depth TVD:Plugs (MD):Junk (MD): Other Stimulate Re-enter Susp Well Suspend Plug for Redrill Perforate Perforate New Pool 6143 / 4255 6237 / 4344 6321 / 4424 6390 / 4490 Date: Liner Well Status after proposed work: 16. Verbal Approval: Change Approved Program 29 - 3897 29 - 2806 14. Estimated Date for Commencing Operations: BOP Sketch 29 - 109 Structural Proposal Summary 13. Well Class after proposed work: 3-1/2" Baker Premium Packers (4) 6186 - 6450 4296 - 4547 3-1/2" 9.2#6468 Production 6461 4558 6461 none 29 - 109 770 9-5/8" Contact Phone:907-564-5006 Date: 80 228020" X 34" Conductor 3090 GINJ 5 Post Initial Injection MIT Req'd? Yes No 5 Comm. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Surface 3868 5750 Intermediate 6688 7" 26 - 6714 26 - 4801 7240 5410 Address:3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 3. No 5Yes Casing Length MD TVD Burst Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Collapse MPSP (psi): Wellbore Schematic Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 03/2020 Approved application is valid for 12 months from the date of approval. No SSSV Installed By Jody Colombie at 9:18 am, Jul 29, 2020 320-314 Digitally signed by Stan Golis DN: cn=Stan Golis, ou=Users Date: 2020.07.29 07:41:39 - 08'00' Stan Golis ; ADL0028239 DLB MGR06AUG20 10-404 DLB 07/29/20 DSR-7/29/2020 X Polymer injection not allowed until an administrative approval is granted that authorizes the pilot project. Yes equired? Comm. 8/6/2020 dts 8/6/2020 JLC 8/6/2020 RBDMS HEW 8/7/2020 Well: L-213i Date: 7/28/20 Well Name: L-213i API Number: 50-029-23306 Current Status: Online - Injecting Pad: L-Pad Estimated Start Date: 8/15/2020 Rig: Reg. Approval Req’d? NA Date Reg. Approval Rec’vd: Regulatory Contact: NA Permit to Drill Number: NA First Call Engineer: David Wages 907.564.5006 713.380.9836 Brief Well Summary: Hilcorp has had good success with polymer floods over in Milne, we want to test the concept in PBU Shrader. In 2015, open pocket injection tests were performed in each interval using diesel as the injected fluid (screenshot of findings below). Objective: Execute polymer injection into each individual zone then open all zones and obtain final injection profile. Procedure: 1. Slickline Prep Work: a. Set up OA only for injection 2. Special Projects Fullbore (~1 week pumping time, OA, plant water only): a. RU, PT to 1500 psi high, pump step rate test with plant water, 5cp and 10 cp polymer, shut in overnight for PFO between tests 3. Slickline Intermediate Work1: a. Set up OBa/OBb only for injection 4. Special Projects Fullbore (~3-4 days pumping time, Oba/OBb, Plant Water Only): a. RU, PT to 1500 psi high, pump step rate test with plant water, 5cp and 10 cp polymer, shut in overnight for PFO between tests 5. Slickline Intermediate Work2: a. Set up OBc only for injection 6. Special Projects Fullbore (~1 week pumping time, OBc, Plant Water Only): a. RU, PT to 1500 psi high, pump step rate test with plant water, 5cp and 10 cp polymer, shut in overnight for PFO between tests 7. Slickline Intermediate Work3: a. Set up OBd only for injection 8. Special Projects Fullbore (~1 week pumping time, OBd): a. RU, PT to 1500 psi high, pump step rate test with plant water, 5cp and 10 cp polymer, shut in overnight for PFO between tests 9. Slickline Intermediate Work4: a. Open all intervals for injection 10. Special Projects Fullbore (~1 week pumping time, all zones open, Plant Water Only): a. Pump 10 cp plant water and polymer solution at ~1000 psi till all polymer is used up b. Flush wellbore with plant water, shut in for PFO c. It may be necessary to call in a cement van this week. 11. Slickline Work: a. Re-install QFRV/s for water injection -00-00 DLB -23308- Schrader DLB Formation Compatibility: BP conducted two field low salinity injection tests on W-210 (10/2013) and L-210 (3/2005) in the SB at PBU. W-210 injected Prince Creek water (4900 ppm – 3900 ppm) into the OBA, OBC, and OBD sands. L- 210 injected Prince Creek water (2000 ppm) into the OBd sand. Prince Creek water increased injectivity in W-210 by 29%-47% and decreased injectivity in L-210 by 20%-25% during the low salinity injection tests. Injection rates for both wells were the same before and after the low salinity tests, indicating the tests did not impact injectivity long term. Low salinity water does not impact Schrader injector injectivity significantly. Similar low salinity water will be used in the 2020 PBU polymer pilot; Hilcorp does not anticipate the polymer pilot to decrease injectivity of the L213i. Well: L-213i Date: 7/28/20 WBD: S • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday,February 20,2018 TO: Jim Regg 4 P.I.Supervisor IVlj 27(13 SUBJECT: Mechanical Integrity Tests ( BP EXPLORATION(ALASKA)INC. L-213 FROM: Brian Bixby PRUDHOE BAY UN ORIN L-213 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name PRUDHOE BAY UN ORIN L-213 API Well Number 50-029-23308-00-00 Inspector Name: Brian Bixby Permit Number: 206-053-0 Inspection Date: 2/19/2018 Insp Num: mitBDB180219112744 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well I- -- �- T --1- ---- - - ---- - -_- — - L-213 Type Inj TVD 4255 Tubing 1718 1739 • 1882 1865 PTD 2060530 [Type Test SPT 1Test psi' 1500 - IA 216 2299 ' 2243 ' 2234 BBL Pumped: 2.2 - BBL Returned: 1.4 - OA 299 311 • 313 - 313 Interval 4YRTST - P/F P . Notes: SCANNED 5 t, 9 2, Tuesday,February 20,2018 Page 1 of 1 • 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. (a ~ - QJ~ ~ Well History File Identifier Organizing (done> ^ Two-sided III (III II II III II III ^ Rescan Needed III (IIIII II II III III RESCAN Color Items: DIGITAL DATA Diskettes No ` OVERSIZED (Scannable) M , . ^ aps: ^ 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: g /s/ Project Proofing I II ( III II III II II II I BY: Maria Date: D ~ lsl Scanning Preparation ~_ x 30 = ~ + =TOTAL PAGES BY: Maria Q Date: ~/ ~ ~V (Count does not include cover sheet) /s/ Production Scanning ~~ ~ ~ IIIIIIIIIIIIII IIIII Stage 1 Page Count from Scanned File: (Count does incl~ude~c/ov'er sheet) Page Count Matches Number in Scanning Preparation: 1/ YES NO BY: Maria Date: ~ ~ ~ 8 /s/ ~, 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. II I II II II I II II I I III ReScanned III IIIIIIIIIII IIIII BY: Maria Date: /s/ Comments about this file: Quality Checked III II (III III (III II P P 10/6/2005 Well History File Cover Page.doc • ~M ,.. ~- ~ ~ '~ ~,4 `~'. ~€ , ~....<. .~ .y.,.. MICROFILMED 6/30/2010 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE C:\temp\Temporary Internet Files\OLK9\Microfilm_Marker.doc MEMORANDUM TO: Jim Regg ~C~ !.~ ~~ 1~;7 P.I. Supervisor 1 \ FROM: Chuck Scheve Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, March 10, 2010 SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC L-213 PRUDHOE BAY UN ORIIJ L-213 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv~ Comm Well Name: PRUDHOE BAY UN GRIN L-213 Insp Num: mitCS100305144014 Rel Insp Num: API Well Number: 50-029-23308-00-00 Permit Number: 206-053-0 Inspector Name: Chuck Scheve Inspection Date: 3/4/2010 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well L-213 ~ Type Inj. W TVD 4255 ~ IA 580 4000 3870 3860 ~ P.T.D 2060530 TypeTest SPT Test psi 1500 ~ QA 20 i 30 30 30 Interval OTHER P~ P Tubing 775 775 775 775 Notes: Test performed pre-MI swap. ~ Wednesday, March 10, 2010 Page 1 of 1 17 /( Schlumberger t . p� oi .4e . tN N0.5436 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambell Street, Suite 400 Alaska Oil & Gas Cons Comm Anchorage, AK 99503 - 2838 Attn: Christine Mahnken ATTN: Beth 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Well Job # Log Description Date BL Color CD MPC -04 AXBD -00061 MEMORY:GLS - 11/17/09 1 1 NK -38A AWJI -00057 MEW - PROD PROFILE L - 11/04/09 1 1 14.12 B3SO -00033 PRODUCTION PROFILE 11/13109 1 1 13.35 B14B -00084 INJECTION PROFILE V 11/10/09 1 1 06 -08A B1413-00082 PLUGBACK SET W /X -FLO C ECK - 11/08/09 1 1 H -30 AV1H -00031 PRODUCTION PROFILE 11/14/09 1 1 18-11A B2NJ -00038 MEM CNL & SCMT G 111/06/09 1 1 Y -23B AYKP -00055 GLS -4( L a 11/22/09 1 1 N -24 AYS4 -00109 PRODUCTION PROFILE - 11/08/09 1 1 02 -31A AYKP -00053 PRODUCTION PROFILE 11/15/09 1 1 03 -01 B81(5 -00014 PRODUCTION PROFILE 11124/09 1 1 L -213 B581 -00017 INJ PROFILE W/WFL 11119/09 1 1 W -209 AYKP -00054 INJ PROFILE W/WFL - 11/17/09 1 1 X -05 AP30 -00072 PRODUCTION PROFILE - 11/29/09 1 1 X -07 AYS4 -00111 PRODUCTION PROFILE It - 11/27109 1 1 • PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Alaska Data & Consulting Services Petiotechnical Data Center LR2 -1 2525 Gambol] Street, Suite 400 900 E. Benson Blvd. Anchorage, AK 99503 -2638 I ~ BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 ~`~s~r~v~`i~`+~~ .'~' ~ _ ~ J~Iv~t August 14, 2009 ~ ~ bp ~~~~~~~~ Mr. Tom Maunder Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of GPB L-Pad Dear Mr. Maunder, 0 C T 0 5 2009 ~iask~ ~il ~ Gas Cons. Cammi~~ion Anchorag~ aa6 - ~~ ~~~ ~ Enclosed please find multiple copies of a spreadsheet with a list of wells from GPB L- Pad that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10-404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Anna Dube, at 659-5102. Sincerely, Torin Roschinger BPXA, Well Integrity Coordinator ~ BP Exploration (Alaska ) Inc. ~ Surface Casing by Conductor Mnulus Certrent, Corrosion inhibRor, Sealant Top-off Report of Sundry Operetions (70~04) flMn L pad R/t:i/2009 Well Name PTD # API # IniGal to of cement Vol. of cement um ed Final top of cement Cement top off date Corrosion inhibitor Corrosion inhibftoN sealant date ft bbis ft na al L-Ot 2010720 50029230110000 NA 6 NA 61.2 6/25/2009 L-02A 2041490 50029230480100 NA 1.4 NA 14.5 6/27/2009 L-03 2051030 50029232690000 NA 2.8 NA 24.7 6/25/2009 L-04 2061200 50029233190000 NA 1.7 NA 15.3 6/25/2009 L-100 1980550 50029228580100 NA 62 NA 57.8 6/29/2009 L-101 1980320 50029228650000 NA 3.3 NA 30.6 6/29/2009 L-102 2020360 50029230710000 37' NA Need To Job? NA L-103 2021390 50029231010000 NA 1.6 NA 10.2 6/26/2009 ~-104 2012380 50029230600000 NA 3.5 NA 47.6 5/6/2009 L-105 2020580 50029230750000 NA 1.75 NA 24.65 5/6/2009 L-106 2012230 50029230550000 NA 2.75 NA 28.05 5/6/2009 L-107 2011510 50029230360000 NA 4.8 NA 57.8 5/6/2009 L-108 2021090 50029230900000 NA 12 NA 13.8 6/25/2009 L-109 2012010 50029230460000 NA 2.9 NA 32.3 6/27/2009 L-110 2011230 50029230280000 NA 27 NA 3162 6/29/2009 L-111 2020300 50029230690000 NA 4.7 NA 54.4 6/29/2009 L-112 2022290 50029231290000 NA 5.5 NA 51 6/27/2009 L-114A 2051120 50029230320100 NA 2.5 NA 25.5 6/29/2009 L-115 2011400 50029230350000 NA 0.5 NA 3.4 6/27/2009 L-116 2011160 50029230250000 NA 5 NA 54.4 6/28/2009 L-117 2011670 50029230390100 NA 2.9 NA 28.9 6/27/2009 L-118 2011870 50029230430000 NA 1.4 NA 15.3 6/27/2009 L-119 2020640 50029230770000 NA 2.25 NA 28.9 5/6/2009 L-120 2020060 50029230640000 NA 0.75 NA 6.8 5/5/2009 L-121 A 2030390 50029231380100 NA 2.2 NA 25.5 6/27/2009 L-122 2030510 50029231470000 NA 2 NA 20.4 6/27/2009 L-123 2051940 50029232900000 NA 2 NA 18.7 6/27/2009 L-124 2050430 50029232550000 NA 1.8 NA 17 6/27/2009 L-200 2040010 50029231910000 NA 1.8 NA 13.5 6/26/2009 L-201 2040460 50029232020000 NA 1.75 NA 15.3 5/6/2009 L-202 2041960 50029232290000 NA 2 NA 17 6/26/2009 L-204 2060920 50029233140000 NA 1.5 NA 5.95 5/6/2009 L-205 2080530 50029233880000 NA 1 NA 12.75 1/10/2009 L-210 2031990 50029231870000 NA 325 NA 31.4 5/5/2009 L-211 2040290 50029231970000 NA 1.8 NA 17 6/27/2009 L-212 2050300 50029232520000 NA 1.8 NA 17 6/26/2009 L-213 2060530 50029233080000 NA 2 NA 17 6/25/2009 L-214A 2060270 50029232580100 NA 025 NA 102 5/6/2009 L-215 2051270 50029232740000 NA 1.5 NA 30.6 5/6/2009 L416 2040650 50029232060000 NA 1.3 NA 11.9 6/26/2009 L-217 2060750 50029233120000 late bbckin conductor NA NA L-218 2051190 50029232720000 NA 1.7 NA 15.3 6/27/2009 L-219 2071480 50029233760000 surtace NA NA L-220 2080470 50029233870000 NA 2 NA 20.4 6/28/2009 L-221 2080310 50029233850000 NA 1.7 NA 16.2 6/25/2009 L-250 2051520 50029232810000 NA 3.4 NA 34 6/26/2009 L-50 2051360 50029232770000 NA 1.8 NA 20.4 6/27/2009 L-51 2060590 50029233090000 NA 1.8 NA 17 6/27/2009 Schlumberger Alaska Da1a & Consulting Services 2525 Gampall Slroel, Suila q00 Mchorage, AK 99503~2B7B ATTN: Balh Well Job M ~~ ~/ b`~3 ~3 ~~ ~ Log Description Date ui N0. 5353 Company; State ol Alaska Alaska Oil !~ Gas Cons Comm Altn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 895D1 • • ~ ~~~ c=~J `_ Pelrotechnlcal Data Center Lf~2-1 Alaska Data & Consulling Services 900 E. Cienson 81vd. 2525 Gambell Sireel, Sude 400 Anchorage, AK 99503-2838 ~ ~ ~~ DATA SUBMITTAL COMPLIANCE REPORT 5/20/2008 Permit to Drill 2060530 Well Name/No. PRUDHOE BAY UN ORIN L-213 Operator BP EXPLORATION (ALASKA) INC MD 6725 TVD 4811 Completion Date 4/28/2006 Completion Status WAGIN Current Status WAGIN API No. 50-029-23308-00-00 REQUIRED INFORMATION Mud Log No Samples No Directional Survey DATA INFORMATION Types Electric or Other Logs Run: MWD / GR, MWD / GR / RES /DEN / NEU / PWD, USIT Well Log Information: Log/ Electr Da Digital Dataset Log Log Run Tye Med/Frmt Number Name Scale Media No ED D Asc Directiona! Survey ~t Directional Survey Cement Evaluation 5 Co '-~ED C Li 14549 i ll l t s ng co ar oca or s ~ig Injection Profile 5 Blu /ED C Lis 15173 "Gamma Ra ~ y ~,og 15173 Induction/Resistivity 25 Blu ~g 15173 Induction/Resistivity 25 Blu 1 (data taken from Logs Portion of Master Well Data Maint Interval OH / Start Stop CH Received Comments 0 6725 Open 5/19/2006 ~ 0 6725 Open 5/19/2006 0 6600 Case 5/24/2006 USIT/6" Gauge Ring/GR/CCL 27-Apr-2006 0 6546 Case 3/22/2007 LIS Veri, GRCH, Tens, CCL DEPT 5960 6450 Case 4/30/2007 Mem MI IPROF, GR, CCL, CCL, STP, Gradio 17-Mar- 2007 98 6717 Open 5/31/2007 LIS Veri, GR, ROP, FET w/Graphics 108 6725 Open 5/31/2007 TVD Vision Service 24-Apr- 2006 108 6725 Open 5/31/2007 MD Vision Service 24-Apr- 2006 j Well Cores/Samples Information: Interval Name Start Stop ADDITIONAL INFORMATION Well Cored? Y MIS Chips Received? Y / N Analysis ~ / ~ N Received? Sample Set Sent Received Number Comments Daily History Received? V/ N Formation Tops ~ N DATA SUBMITTAL COMPLIANCE REPORT 5/20/2008 Permit to Drill 2060530 Well Name/No. PRUDHOE BAY UN GRIN L-213 Operator BP EXPLORATION (ALASKA) INC API No. 50-029-23308-00-00 MD 6725 TVD 4811 Completion Date 4/28/2006 Completion Status WAGIN Current Status WAGIN UIC Y Comments: Compliance Reviewed By: Date: 05/17/07 Schlumberger Schlumberger-DCS 2525 Gambell St, Suite 400 ~ }-~ Anchorage, AK 995D3-2638 V J- ~ _ ~j. _ ATTN: Beth ~ e~~ ,_. ~ C ? t" /G Well Job # Log Description NO. 4262 Company: Alaska Oil B Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Borealis Orion Date BL Color CD L-123 40012830 OH EDIT MWD/LWD 01/01106 2 1 L-123PB7 40012830 OH EDIT MWDA_WD 12I25/OS 2 1 L-213 40013428 OH EDIT MWD/LWD 04/25/06 2 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPV EACH TO: BP Exploration (Alaska) Inc ~ ~;'~"'""' - Petrotechnical Data Center LR 4 ~ ,, J ~~~'~~-r^+ 900 E Benson Bivd. 1 Anchorage AK 99508-4254 (~~~ ly ^~ d i N~ uJ A ~ ®®~ Date Delivered: g~ h~~"~" Schlumberger-DCS 2525 Gambefl St, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth a~ ,~.._-_... _.. Received by:~ 04!25/0! Schlumberger Schlumberger-DCS 2525 Gambell St, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Well Job # Log Description NO.4223 Company: Alaska Oil 8 Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Aurora Orion Date BL Color CD L-213 ~ W-210 S-104 11648950 11626075 10563057 MEMORY IPROF USIT INJECTION PROFILE 03117107 03/06107 05!03103 1 1 1 L-218 L-218 S-111PB1 10913045 10913045 40011960 CEMENT/PERF EVALUATION MDT OHED17MWO/LWD 09104105 09/04/05 05/24/05 2 1 1 1 S-111P82 L-202 L-202L7 40011960 40012011 40012011 OH EDIT MWD/LWD OH EDIT MWD/LWD OH EDIT MWD/LWD O6I06/05 06117/05 06124/05 2 2 2 1 1 1 L-202L2 40012011 OHEDI7MWD/LWD 06/29/05 2 1 L-202L3 40012011 OH EDIT MWD/LWD 07/05/05 2 1 S-122 S-122PB1 5-122P82 40012137 40012137 40012137 OH EDIT MWDILWD OH EDIT MWD/LWD OH EDIT MWDILWD 08/17/05 08109/05 08/14/05 2 2 2 1 1 1 5-122P83 40012137 OH EDIT MWDILWD 08/15/05 2 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska)Inc. Petrotechnical Data Center LR2-1 ' 900 E Benson Blvd. Anchorage AK 99508-4254 A~ ~ o zoo? Date Delivered: r r-~ .-•-.' r1' ° C.~f : ~~ea arrui rrccr~°~ Schlumberger-DCS 2525 Gambell St, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Received -. 1 5cbfamberger Schlumberger-DCS 2525 Gambell St, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Well ~~ ~ ~ ~~~ i Job # Log Description Da e l`«~ NO. 4179 Company: Alaska Oil 8 Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Polaris Borealis Orion BL Color CD L-213 11212849 CH EDIT USIT PDC-GR 04127/06 1 W-204 11630451 _ CEMENT BOND 8 IMAGE LOG 02/02107 1 W-205L2 11626070 RSTANFL 02105/07 1 S-213A 11628755 _ MEMORY GLS 02/14107 1 V-105 11626370 IPROFILEANFL 01129107 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TG: BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2 1 . ~ ! FS "- 900 EBenson Blvd. ~'~~ 6' ~~ 1 ~~ ~) Anchorage AK 99508-4254 ~:1 -~"--,-- - "----'~ '~~ "--''- Date Delivered. n4 ,1 { '~ K~ )ftfl-3~ ~l~ A T <_, ... Schlumberger-DCS 2525 Gambell St, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth ,~ i r Received by: '~ 03/13/07 ~~ s-y ~J~,~., MEMORANDUM ' To: Jim Regg -- P.I. Supervisor ~1, ,-' • ; ~~~~ ~ ~1 FROM: John Crisp Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, July 25, 2006 SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC L-213 PRUDHOE BAY UN ORIN L-213 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv.~ Comm Well Name• PRUDHOE BAY UN GRIN L-213 Insp Num: mitJCr060717151236 Rel Insp Num API Well Number Permit Number: 50-029-23308-00-00 206-053-0 Inspector Name: John Crisp Inspection Date: 7!4!2006 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well L-z13 ITYpe Inj. ~ w TTVD azss IA ~ s7o ~ 1760 17 0 ~ 171o i P.T. 2060530 iTypeTest SPT ~ Test psi lsao ~ pA ~ 350 ' 420 ~ 415 410 Interval ~IT~' P/F P Tubing 940 940 i 940 940 I Notes .5 bbl pumped for test. Tuesday, July 25, 2006 Page 1 of I STATE OF ALASKA ALAS IL AND GAS CONSERVATION COSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG .;{. ~~ 1a. Well Status: ^ Oil ^ Gas ^ Plugged ^ Abandoned ^ Suspended ®WAG zoAAC2s.,os zoAAC~s.,,o ^ GINJ ^ WINJ ^ WDSPL No. of Completions One Other 1b. Well Class:, ^ Development ^ Exploratory ^ Stratigraphic ®Service 2. Operator Name: BP Exploration (Alaska) Inc. 5. Date Comp., Susp., or Aband. 4/28/2006 12. Permit to Drill Number 206-053 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 6. Date Spudded 4/19/2006 13. API Number 50-029-23308-00-00 4a. Location of Well (Governmental Section): /1„t,~i ~ Surface: 1~'' ~~ 'ti ' ' 7. Date T.D. Reached 4/24/2006 14. Well Name and Number: PBU L-2131 1 FEL, SEC. 34, T12N, R11 ~ U I 2409 FSL,. 3602 Top of Productive Horizon: 951' FSL, 5213' FEL, SEC. 35, T12N, R11 E v tM ~ g KB Elevation (ft): 78.1 15. Field /Pool(s): Prudhoe Bay Field / Orion Schrader Bluff Total Depth: 908' FSL, 5066' FEL, SEC. 35, T12N, R11 E U ~'-'l 9. Plug Back Depth (MD+TVD) 6629 + 4719 Ft 4b. Location of Well (State Base Plane Coordinates): Surface: x- 583314 y- 5978132 Zone- ASP4 10. Total Depth (MD+TVD) 6725 + 4811 Ft 16. Property Designation: ADL 028238 TPI: x- 587001 y- 5976715 Zone- ASP4 Total Depth: x- 587149 Y- 5976675 Zone- ASP4 11. Depth where SSSV set None MD 17. Land Use Permit: ff th if h 19 W t d Thickness of Permafrost 20 18. Directional Surve Y ®Yes ^ No er , o s ore . a ep N/A MSL . 1900' (Approx.) 21. Logs Run: MWD / GR, MWD / GR / RES /DEN / NEU / PWD, USIT ASING, INER AND EMENTING ECORD CASING EYEING' Ep7H MD ETTING EPTH TVD HOLE OUNT SIZE WT. PER FT. GRADE OP 7TOM OP OTEOM SIZE CEMENTING RECORD PULLED 20" 215.5# A-53 Surface 109' Surface 109' 42" 260 sx Arctic Set Approx. 9-5/8" 40# L-80 29' 3896' 29' 2806' 12-1/4" 609 sx AS Lite, 400 sx Class 'G' 7" 26# L-80 26' 6714' 26' 4801' 8-3/4" 29 sx LiteCrete, 252 sx Class 'G' 23. Perforations open to Production (MD +TVD of Top and " " 24. TUBING RECORD Bottom Interval, Size and Number; if none, state none ): SIZE DEPTH SET (MD) PACKER SET (MD) 4-1 /2" Gun Diameter, 5 spf 3-1/2", 9.2#, L-80 6468' 6143', 6237', 6321', 6390' MD TVD MD TVD 6192' - 6226' 4301' - 4334' 6255' - 6286' 4361' - 4391' 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 6298' - 6313' 4402' - 4416' 6368' 44 6356' 8' 69' DEPTH INTERVAL MD AMOUNT & KIND OF MATERIAL USED - 5 - 44 6408' - 6456' 4507' - 4553' Freeze Protected w/ 116 Bbls of Diesel 26. PRODUCTION TEST Date First Production: Not on Injection Yet Method of Operation (Flowing, Gas Lift, etc.): N/A Date of Test Hours Tested PRODUCTION FOR TEST PERIOD OIL-BBL GAS-MCF WATER-BBL CHOKE $IZE GAS-OIL RATIO Flow Tubing PreSS. Casing Pressure CALCULATeD 24-HOUR RATE OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-API (CORK) 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". ~ BF~ ~1~N Q ~' 20(16 ca~,rQ~~rro~~.' None s~~~ ~: Form 10-407 Revised 12/2003 CONTINUED ON REVERSE SIDE 28' T GEOLOGIC MARKS 29' ORMATION TESTS Include and briefly summarize test results. List intervals tested, NAME MD TVD and attach detailed supporting data as necessary. If no tests were conducted, state "None". Ugnu 4051' 2886' None Ugnu MA 5784' 3926' Ugnu MB1 5827' 3964' Ugnu M62 5883' 4014' Ugnu MC 5962' 4086' Schrader Bluff NA 6030' 4149' Schrader Bluff NB 6056' 4173' Schrader Bluff NC 6066' 4183' Schrader Bluff OA 6194' 4303' Schrader Bluff OBa 6257' 4363' Schrader Bluff OBb 6300' 4404' Schrader Bluff OBc 6356' 4458' Schrader Bluff OBd 6410' 4509' Schrader Bluff OBe 6472' 4568' Schrader Bluff OBf 6522' 4616' Base Schrader Bluff 6571' 4663' 30. List of Attachments: Summary of Daily Drilling Reports, Well Schematic Diagram, Surveys 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. ~~// Signed Terrie Hubbl Title Technical Assistant Date vl0 Q ~ ~ PBU L-2131 206-053 Prepared By Name/Number: Terrie Hubble, 564-4628 Well Number Permit No. /Approval No. orining Engineer: Ron Phillips, 564-5913 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. IreM 1a: Classification of Service Wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. IreM 4b: TPI (Top of Producing Interval). IreM 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. IreM 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). IreM 20: True vertical thickness. IreM 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. IreM 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). IreM 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). IreM 27: If no cores taken, indicate "None". IreM 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 Submit Original Only BP EXPLORATION Page 1 of 1 Leak-Off Test Summary Legal Name: L-213 Common Name: L-2131 Test Date Test Type Test Depth (TMD) Test Depth (TVD) AINW Surface Pressure. Leak Off Pressure (BHP) EMW 4/24/2006 LOT 3,896.0 (ft) 2,805.0 (ft) 8.80 (ppg) 740 (psi) 2,022 (psi) 13.88 (ppg) • Printed: 5/1/2006 1:31:06 PM • • BP EXPLORATION Page 1 of 7 Operations SumrnaryReport Legal Well Name: L-213 Common Well Name: L-2131 Spud Date: 4/19/2006 Event Name: DRILL+COMPLETE Start: 4/18/2006 End: 4/28/2006 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 4/28/2006 Rig Name: NABORS 9ES Rig Number: Date From - To Hours Task Code NPT Phase Description of Operations 4/18/2006 00:00 - 03:30 3.50 MOB P PRE Move shops and satellite camp from I-Pad to L-Pad. 03:30 - 07:00 3.50 MOB P PRE Move mud pit complex from I-Pad to L-Pad. 07:00 - 08:30 1.50 MOB P PRE PJSM. Lower cattle chute, lower derrick. 08:30 - 09:30 1.00 MOB P PRE Raise cellar doors and prep cellar for move. 09:30 - 17:00 7.50 MOB P PRE Move main rig complex from I-Pad to L-Pad. 17:00 - 21:00 4.00 BOPSU P PRE Nipple up surface Diverter BOP, and diverter line prior to spotting rig due to spacing of adjacent wells and flowlines. 21:00 - 00:00 3.00 RIGU P PRE Position rig on L-213i. Set matting boards and herculite. Spot rig over conductor. Spot mud pits. Accept rig for operations on L-213i @ 21:00 hr. 4/1812006. Backed up acceptance time 4 hrs due to nipple up of diverter. 4/19/2006 00:00 - 01:00 1.00 RIGU P PRE Raise derrick and cattle chute. 01:00 - 02:30 1.50 RIGU P PRE Rig up rig floor. 02:30 - 08:00 5.50 BOPSU P PRE Nipple up diverter riser and remaining diverter lines with crane. 08:00 - 13:30 5.50 RIGU P PRE Pick up 111 joints 4" HT-40 drill pipe, 24 joints 4" HWDP and stand back in derrick. 13:30 - 14:30 1.00 DRILL P SURF Pick up, make up, and stand back jar and collar stands. 14:30 - 17:00 2.50 DRILL P SURF Hold Pre Spud and PJSM. Make up BHA #1 per directional driller. 17:00 - 17:30 0.50 BOPSU P SURF Function test Diverter and accumulator. Witnessing of test waived by AOGCC rep Jeff Jones. Test witnessed by BP WSL Alan Madsen and NAD TP Kelly Cozby. 17:30 - 19:00 1.50 DRILL P SURF Fill hole, check and fix leaks. 19:00 - 20:30 1.50 DRILL P SURF Drill from 108' to 300'. 600 gpm, 900 psi, 60 rpm, 1 k TO off bottom, 6k TO on bottom, PU-SO-RT - 57k 20:30 - 21:30 1.00 DRILL P SURF POH to pick up NM STAB & jar stand. RIH to 300' and Gyro survey. 21:30 - 00:00 2.50 DRILL P SURF Directionally drill and gyro from 300' to 452'. 600 gpm, PSI ON - 1,160 psi, PSI OFF - 1,100 psi, RPM - 60, TO - 1k on and off bottom. AST - .36 hrs., ART - .87 hrs. Gyro survey every 100'. Lost 173 bbls 8.2 ppg spud mud from 140' to present. 4/20/2006 00:00 - 10:00 10.00 DRILL P SURF Directionally drill and gyro from 452' to 1,672'. 700 gpm, PSI ON - 2,430 psi, PSI OFF - 2,310 psi, RPM - 60, TQ ON - 5k, TO OFF - 4k, PU - 81 k, SO - 75k, RT - 70k, WOB -15-30k. Gyro survey every 100' to 1,004'. No mud losses after 500'. AST - 4.31 hrs, ART - 2.67 hrs. * Held Pre Spud Meeting with Midnight to Noon crew during Pre Tour Safety Meeting. 10:00 - 10:30 0.50 DRILL P SURF Circulate bottoms up @ 715 gpm, 2,320 psi, 100 rpm, 3.2k TO, 9.1 ppg mud weight. Monitor well - OK. 10:30 - 12:30 2.00 DRILL P SURF POH from 1,672' to 268'. Hole started swabbing @ 1,076'. RIH to 1,118', pump out from 1,118' to 1,022'. Continue to POH dry from 1,022' to 268'. 12:30 - 13:00 0.50 DRILL P SURF Stand back jar and collar stands. 13:00 - 13:30 0.50 DRILL P SURF Change out bit. Adjust motor housing from 1.83 deg. to 1.5 deg. 13:30 - 14:30 1.00 DRILL P SURF Run in hole with BHA #2 to 1,575' without problem. Wash from 1,575'to 1,672'. 14:30 - 00:00 9.50 DRILL P SURF Directionally drill from 1,672' to 3,295'. 700 gpm, PSI ON - 3,425 psi, PSI OFF - 3,220 psi, RPM - 80, TO ON - 8k, TO OFF - 6k, PU - 98k, SO - 76k, RT - 86k, WOB -20-40k. AST - Printed: 5/1/2006 1:31:12 PM BP EXPLORATION Page 2 of 7 Operations Summary Report Legal Well Name: L-213 Common Well Name: L-2131 Spud Date: 4/19/2006 Event Name: DRILL+COMPLETE Start: 4/18/2006 End: 4/28/2006 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 4/28/2006 Rig Name: NABORS 9ES Rig Number: Date From = To Hours Task Code NPT Phase. Description of Operations 4/20/2006 14:30 - 00:00 9.50 DRILL P SURF 2.8 hrs, ART - 2.5 hrs. Encountered hydrates from 2,187 on intermittently. 4/21/2006 00:00 - 02:00 2.00 DRILL P SURF Directionally drill from 3,295' to 3,909'. 700 gpm, PSI ON - 3,330 psi, PSI OFF - 3,280 psi, RPM - 80, TQ ON - 8.1 k, TQ OFF - 4k, PU - 120k, SO - 80k, RT - 90k, WOB -30-40k. AST - 2.8 hrs, ART - 2.5 hrs. 02:00 - 04:00 2.00 DRILL P SURF Circulate 3 1/2 times bottoms up at 660 gpm, 3,260 psi, 80 rpm, 4.6k TO, MW - 9.6 ppg. Monitor well - OK. 04:00 - 09:00 5.00 DRILL P SURF POH from 3,909' to 1,002'. Backream as needed @ 650 gpm, 3,090 psi, 80 rpm, 6k TO. 09:00 - 11:00 2.00 DRILL P SURF RIH from 1,002' to 3,909' with no adverse hole conditions or fill on bottom. Had to work pipe in through build, no pumping or reaming. 11:00 - 12:30 1.50 DRILL P SURF Circulate 3 1/2 times bottoms up while pumping at 700 gpm, 3,400 psi, 80 rpm, 4.5k TO. Shakers cleaned up good. No indication of hydrates after short trip. MW 9.7 ppg. Monitor well - OK. 12:30 - 17:00 4.50 DRILL P SURF POH from 3,909' to 1,920'. Started overpulling and swabbing. Backream from 1,920' to 932' at 670 gpm, 2,100 psi, 75 rpm, 3k TQ. POH without pump from 932' to 266'. 17:00 - 18:00 1.00 DRILL P SURF Laydown BHA #2. 18:00 - 19:00 1.00 DRILL P SURF Clear and clean rig floor. 19:00 - 22:00 3.00 CASE P SURF Rig up to run 9 5/8" casing. Make dummy run with casing hanger. 22:00 - 00:00 2.00 CASE P SURF PJSM. Pick up and Baker Lok 9 5/8" 80' shoe track. Fill pipe and check floats - OK. Continue running in hole with 9 5/8" 40# L-80 BTC casing to 456'. Make up torque - 8,600 fUlbs using BOL 2000. Fill each joint with casing fill-up tool. 4/22/2006 00:00 - 01:30 1.50 CASE P SURF Change out damaged joint of casing from coming in contact with elevator inserts. Change out elevators. 01:30 - 04:30 3.00 CASE P SURF Continue running in hole with 9 5/8" 40# L-80 BTC casing from 456' to 2,090'. Installed bowspring centralizers on 1st 25 jts Pump down as needed. Started taking weight at 2,000'. Worked pipe down without pumps to 2,090'. 04:30 - 14:00 9.50 CASE P SURF Continue running in hole with 9 5/8" 40# L-80 BTC casing by washing down each joint from 2,090' to 3,581'. 275 gpm, 375 psi. PU - 160k, SO - 93k. 14:00 - 15:00 1.00 CASE N RREP SURF Change out casing Tongs. Circulate @ 282 gpm, 490 psi. Repair skate alignment counterweight. 15:00 - 16:00 1.00 CASE P SURF Continue running in hole with 9 5/8" 40# L-80 BTC casing by washing down each joint from 3,581' to planned casing depth of 3,896'. Ran total of 95 joints, 1-10ft pup jt of 9 5/8" 40# L-80 BTC casing. Float Shoe @ 3,896' Float Collar @ 3,810' 16:00 - 19:00 3.00 CEMT P SURF Circulate and condition mud for cement job at 335 gpm, 540 psi. Reciprocating pipe 10 ft strokes. PU - 170k, SO - 110k. Dropped YP from 54 to 16. Held PJSM while circulating. 19:00 - 22:30 3.50 CEMT P SURF Switch over to Dowell. Pump 5 bbls H2O @ 2 bpm, 150 psi, pressure test lines to 3,500 psi - OK. Pump 20 bbls CW-100 preflush @ 6.6 bpm, 230 psi. Pump 80 bbls 10.5 ppg Punted: 5/1/2006 1:31:12 PM • • BP EXPLORATION Page 3 of 7 Operations Summary Report Legal Well Name: L-213 Common Well Name: L-2131 Event Name: DRILL+COMPLETE Contractor Name: NABORS ALASKA DRILLING I Rig Name: NABORS 9ES Date from - To I Hours ~ Task I Code ~ NPT Start: 4/18/2006 Rig Release: 4/28/2006 Rig Number: Spud Date: 4/19/2006 End: 4/28/2006 Phase ~ Description of Operations 14/22/2006 119:00 - 22:30 I 3.501 CEMT I P I I SURF 22:30 - 00:00 I 1.501 CEMT I P SURF 14/23/2006 100:00 - 04:00 I 4.001 BOPSUR P I I SURF 04:00 - 09:30 I 5.501 BOPSUF~ P I I SURF 00:00 - 15:00 I 5.00 BOPSU~P SURF 15:00 - 15:30 0.50 BOPSUE~P SURF 15:30 - 18:00 2.50 DRILL P PROD1 18:00 - 20:30 2.50 DRILL P PROD1 20:30 - 21:30 1.00 DRILL P PROD1 21:30 - 22:00 0.50 DRILL P PROD1 22:00 - 23:00 1.00 DRILL P PROD1 23:00 - 23:30 I 0.501 DRILL I P I I PROD1 23:30 - 00:00 0.50 DRILL N RREP PROD1 4/24/2006 00:00 - 01:00 1.00 DRILL P PROD1 01:00 - 01:45 0.75 DRILL P PROD1 02:00 - 02:30 I 0.501 DRILL ~ P I I PROD1 MudPush @ 5.1 bpm, 150 psi. Drop bottom plug. Batch mix and pump 487 bbls, 600 sx, 10.7 ppg ArcticSet Lite lead cement @ 6.2 bpm, 290 psi ICP, 380 psi FCP. Batch mix and pump 84 bbls, 415 sx, 15.8 ppg Class "G" cement @ 5.1 bpm, 400 psi ICP, 280 psi FCP. Slow down to 3.8 bpm, 160 psi for last 15 bbls of slurry to add DuraStone. Shut down and drop top plug and kick out with 10 bbls of H2O @ 9.5 bpm, 275 psi. Switch over to rig pumps and displace cement with 9.4 ppg mud @ 8 bpm avg for first 260 bbls, 400 psi ICP, 850 psi FCP, slow pump to 3 bpm for final 20 bbls for 280 bbls total with 680 psi ICP, 720 psi FCP. Bump plug with 1,500 psi @ calculated displacement of 96%. CIP @ 22:15 hr. Bleed off pressure, check floats - OK. Reciprocated casing throughout cement job until) casing was set on landing ring with tail cement going around shoe. PU - 175k, SO - 55k. Had full returns throughout cementing and displacement. Returned 123 bbls of sidewalk cement to surface. Flush surface equipment. Rig down cement line and head. Back out landing joint. Rig down casing tools. Flush out surface stack. Rig down diverter riser. Rig down knife valve. ND surface stack. ND diverter. Change out bell nipple. Secure surface stack in cellar Move base flange and tubing spool in from behind cellar, prep and install same. Test metal to metal seal to 1,000 psi - 10 min - OK. Position and nipple up BOPE. Tighten turn buckles, install riser and annulus valves. Install mouse hole. Rig up to test BOPE Test BOPE to 250 psi low pressure, 4,000 psi high pressure. Test annular preventer to 250 psi low pressure, 3,500 psi high pressure. Perform Accumulator test (D4). Witnessing of test waived by AOGCC rep. Chuck Scheve. Test witnessed by BP WSL Alan Madsen, NAD TP Kelly Cozby. Rig down BOPE test equipment. PJSM on nuclear source. Pick up, make up 8 3/4" (BHA #3). RIH on 4" HWDP to 997'. Shallow hole test MWD - OK. Run in hole with BHA #3 on 4" drill pipe from 997' to 3,663' Cut and slip drilling line 65'. Inspect brake linkage. Circulate air out of drill pipe and casing. Pressure test 9 5/8" 40# surface casing to 3,500 psi - 30 minutes - OK. Lost 25 psi. Wash down from 3,683' to top of float collar at 3,810'. Cleanout cement to top of float collar on depth @ 3,810'. 550 gpm, 2,350 psi, 60 rpm, 6k TO. PU - 118k, SO - 68k, RT - 90k. Leak discovered under flowline at complex interconnect. Repair flowline boot seal. Drill float equipment and cement from float collar @ 3,810' to shoe @ 3,896'. Clean out rathole to 3,909'. 500 gpm, 2,125 psi on, 2,000 psi off. 50 rpm, 5.6k TQ on, 5.4k TO off. Pump 50 bbl spacer and displace well from 9.4 ppg spud mud to 8.8 ppg LSND mud. 500 gpm, 2,000 psi, 50 rpm, 5.4k TO. Drill new 8 3/4" hole from 3,909' to 3,929'. Perform LOT. Hole depth - 3,929' Printed: 5/1/2006 1:31:12 PM • • BP EXPLORATION Page 4 of 7 Opera#ions Summary Report Legal Well Name: L-213 Common Well Name: L-2131 Spud Date: 4/19/2006 Event Name: DRILL+COMPLETE Start: 4/18/2006 End: 4/28/2006 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 4/28/2006 Rig Name: NABORS 9ES Rig Number: Date From - To Hours Task Code NPT Phase - Description of Operations 4/24/2006 02:00 - 02:30 0.50 DRILL P PROD1 TMD - 3,826' TVD - 2,805' LOP - 740 psi MW-8.8PP9 EMW - 13.87 ppg 02:30 - 03:00 0.50 DRILL P PROD1 Obtain benchmark ECD's and slow pump rates. CECD - 9.39 PP9• 03:00 - 12:00 9.00 DRILL P PROD1 Directionally drill 8 3/4" hole from 3,929' to 5,499'. 585 gpm, 2,180 psi on, 2,100 psi off, 100 rpm, 6.8k TO on, 6.4k TO off, PU - 122k, SO - 81 k, RT - 101 k, WOB - 10k. CECD - 9.54 ppg, AECD - 10.07 ppg. AST - 2.07 hrs, ART - 2.25 hr. Backream and survey each stand. 12:00 - 19:00 7.00 DRILL P PROD1 Directionally drill 8 3/4" hole from 5,499' to TD @ 6,725' TMD, 4,812' TVD. 585 gpm, 2,480 psi on, 2,100 psi off, 100 rpm, 8k TO on, 6.6k TO off, PU - 122k, SO - 81 k, RT - 101 k, WOB - 10-20k. CECD - 9.63 ppg, AECD - 10.20 ppg. AST - 2.47 hrs, ART - 2.12 hr. Backream and survey each stand. 19:00 - 19:30 0.50 DRILL P PROD1 Circulate @ 585 gpm 2,520 psi, 100 rpm, 8.6k TO, CECD - 9.63 ppg, AECD - 10.2 ppg. 19:30 - 00:00 4.50 DRILL P PROD1 Backream from 6,725' to 5,594' @ 1,000 fph when possible. Slow down as needed through coal sections and ECD spikes to 1 ppg over. 580 gpm, 2,410 psi, 100 rpm, 8.4k TO. 4/25/2006 00:00 - 01:00 1.00 DRILL P PROD1 Backream from 5,594' to 5,312' with ghost reamer in casing. 580 gpm, 2,410 psi, 100 rpm, 8.4k TO. Circulate bottoms up while pumping out 2 stands. Attempt to pull dry with hole swabbing. Backream from 5,100' to 4,830'. POH without pumping from 4,830' to 3,690' - OK. 01:00 - 02:30 1.50 DRILL P PROD1 Monitor well - OK. Pump dry job. POH from 3,690' to 997'. 9.2 PP9 MW. 02:30 - 03:00 0.50 DRILL P PROD1 Stand back HWDP to 261'. 03:00 - 05:00 2.00 DRILL P PROD1 PJSM on nuclear source. Laydown BHA #3. 05:00 - 08:00 3.00 BOPSU P RUNPRD Clean and clear the floor. Pull wear ring. Flush the stack and install the test plug. Change upper pipe rams from 3.5" x 6" VBR's to 7" and test the door seals. RD testing equipment. Make dummy run with casing hanger. 08:00 - 10:00 2.00 CASE P RUNPRD RU 7" casing handling equipment and the rig floor to run 7" longstring. 10:00 - 19:00 9.00 CASE P RUNPRD Hold PJSM. PU and RIH with 7" float shoe, 2 joints of 7" 26# L-80 BTC-m casing, and 7" float collar. All connections below the float collar were Bakerloc'd and torqued to the mark with 8,200 ft-Ibs. Continue to RIH with 29 additional joints of 7" 26# L-80 BTC-m casing, 2 x 20' pups with RA tags in the collars, and 1 x 10' spaceout pup utilizing BOL 2000NM thread lubricant and 8,200 ftlbs of torque. Crossover and run 63 joints of 7" 26# L-80 TCII casing utilizing Jet Lube Seal Guard lubricant and 10,100 ftlbs of torque. 19:00 - 19:30 0.50 CASE P RUNPRD Circulate a bottoms up prior to going into the open hole - 250 gpm, 438 psi, PU - 115K, SO - 92K. 19:30 - 00:00 4.50 CASE P RUNPRD Continue RIH with 40 additional joints of 7" 26# L-80 TCII casing utilizing Jet Lube Seal Guard lubricant and 10,100 ftlbs of torque. 4/26/2006 00:00 - 02:00 2.00 CASE P RUNPRD Continue RIH with 29 additional joints of 7" 26# L-80 TCII casing utilizing Jet Lube Seal Guard lubricant and torque Printed: 5/1/2006 1:31:12 PM • ~ BP EXPLORATION Page 5 of 7> 4peratioins Summary Report Legal Well Name: L-213 Common Well Name: L-213i Event Name: DRILL+COMPLETE Contractor Name: NABORS ALASKA DRILLING Rig Name: NABORS 9ES Date From - To I Hours I Task Code NPT 4/26/2006 100:00 - 02:00 I 2.00 I CASE I P Start: 4/18/2006 Rig Release: 4/28/2006 Rig Number: Spud Date: 4/19/2006 End: 4/28/2006 Phase- Description of Operations RUNPRD turned with 10,100 ftlbs of torque. PU landing joint and hanger and RIH. Land hanger with the casing shoe at 6,714'. Circulate with the Franks tool while reciprocating the pipe. Ran a total of 31 joints of 7" 26# L-80 BTC-m, 2 x 20' BTC-m pumps w/RA tags in the collars, 10' BTC-m spaceout pup, 4' TCI I box xBTC-m pin XO, 132 joints of 7" 26# L-80 TCI I, and 75 x 7-1/8" x 8-1/4" x 8" centralizers. 02:00 - 02:30 0.50 CASE P 02:30 - 05:00 2.50 CEMT P 05:00 - 07:00 I 2.001 CEMT I P BTC-m Float shoe - 6714' BTC-m Float collar - 6629' RA tag - 6160' RA tag - 5775' TCII box to BTC-m pin xo - 5394' RUNPRD RD the Franks Fillup tool and RU the cement head. RUNPRD Circulate and condition the mud through the cement head, while reciprocating, staging the pumps up to 6 bpm. Hold PJSM for the cement job while circulating. Batch up the cement following the PJSM. RUNPRD Switch over to Dowell. Pump 5 bbls fresh water. Shut in and pressure test lines to 4,000 psi - OK. Pump 30 bbls CW-100 preflush @ 5 bpm, 500 psi. Pump 30 bbls 10.3 ppg MudPush @ 4.7 bpm, 450 psi. Drop bottom plug. Pump 14 bbls of 11.5 ppg LiteCRETE w/GASBLOK lead cement @ 5 bpm, 500 psi ICP, 500 psi FCP. Swap over to 15.8 ppg Class G GASBLOK Tail slurry and pump 52 bbls @ 5.6 bpm, 500 psi ICP, 200 psi FCP. Shut down and drop top plug. Line up and wash cementing lines through "T" on the rig floor. Line up to the rig to displace. Kick out the plug and displace with seawater @ 6 bpm, 238 psi ICP, 500 psi FCP. Slow pump to 4 bpm with 30 bpm remaining and then 2 bpm for final 15 bbls for a displacement of 254 bbls with 94% efficiency. Bump plug with 860 psi and then increase the pressure to 4000 psi, chart and hold for 30 minute casing test -good. Bleed off pressure, check floats - OK. Reciprocated casing throughout cement job until) casing was set on landing ring with just prior to bumping the plug. PU - 195k, SO - 113k. Had full returns throughout cementing and displacement. CIP @ 0630 hours. 07:00 - 09:00 2.00 CEMT P RUNPRD RD the cement head and casing handling equipment. Changeout the bails from long to short. 09:00 - 10:30 1.50 WHSUR P RUNPRD Install packoff. RILDS and torque to 450 ftlbs. Test to 5,000 psi -good. 10:30 - 12:00 1.50 BOPSU P RUNPRD Install the test plug and changeout the upper 7" rams back to the 3-1/2" x 6" variables. Test door seals -good. 12:00 - 14:30 2.50 PERFO P OTHCMP Hold PJSM. RU the rig floor to run DPC perforating guns. MU the 4.5", 5 spf, 4505 PowerJET perforating guns with E-fire and RIH to 312'. 14:30 - 18:30 4.00 PERFO P OTHCMP RIH with perforating guns w/SlimPulse MWD tool on 4" DP from 312' to 2,095'. Flow test the string - 290 gpm, 642 psi. Continue RIH to 6,165'. 18:30 - 21:00 2.50 PERFO P OTHCMP Correlate the pert guns on depth by logging the RA tags in the 7" longstring located at 5,774' and 6,160' -found on depth. Printed: 5/1/2006 1:31:12 PM BP EXPLORATION Page 6`of 7 Operations Summary :Report Legal Well Name: L-213 Common Well Name: L-2131 Spud Date: 4/19/2006 Event Name: DRILL+COMPLETE Start: 4/18/2006 End: 4/28/2006 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 4/28/2006 Rig Name: NABORS 9ES Rig Number: Date From - To Hours Task Code. NPT Phase Description of Operations 4/26/2006 18:30 - 21:00 2.50 PERFO P OTHCMP RIH and tag the landing collar at 6,629'. POH and spot the bottom shot on depth at 6,456'. Simops: Inject 140 bbls of 9.2 ppg LSND down the OA to ensure the annulus is clear - 2 bpm, 550 psi ICP, 900 psi FCP. 21:00 - 21:30 0.50 PERFO P OTHCMP Displace the well over to 9.0 ppg brine through the firing head/debris sub at 6,145' - 6 bpm, 680 psi. 21:30 - 22:00 0.50 PERFO P OTHCMP Activate the E-fire firing head through a sequence of pressure signals and fire the perforating guns. Monitor the well. Fluid level dropped -20' (5 bbls) following the fire and then stabilized. 4.5", 5 spf, 4505 PowerJET intervals 6192' - 6226' 6255' - 6286' 6298' - 6313' 6356' - 6368' 6408' - 6456' 22:00 - 22:30 0.50 PERFO P OTHCMP POH standing back the 4" DP from 6,457' to 6,100' -above the top shot. 22:30 - 23:00 0.50 PERFO P OTHCMP Circulate a bottoms up - 7 bpm, 928 psi -lost 10 bbs of fluid while circulating bottoms up. 23:00 - 00:00 1.00 PERFO P OTHCMP LD 4" HT40 DP from 6,100' to 5,645'. 4/27/2006 00:00 - 04:30 4.50 PERFO P OTHCMP Continue to LD 4" HT40 DP from 5,645' to 312'. Simops: Freeze protect the OA with 94 bbls of dead crude with LRHOS 04:30 - 08:00 3.50 PERFO P OTHCMP PJSM. LD perforating guns and tools -all guns fired. Clear and clean the rig floor. 08:00 - 09:30 1.50 PERFO P OTHCMP RIH with 11 stands of 4" DP from the derrick. LD 33 joints of 4" DP. 09:30 - 10:00 0.50 PERFO P OTHCMP Service the top drive and the crown. 10:00 - 13:30 3.50 CONDH P OTHCMP PJSM. RU SLB E-line. RIH with 6" GR/JB to 6,600' to clean out the well prior to running USIT. Made 2 runs. Run #1 recovered -0.5 cups of debris. Run #2 recovered -0.25 cups of debris. 13:30 - 16:30 3.00 EVAL P OTHCMP MU USIT and RIH to log the cement behind the 7" casing. Log up with the USIT. POH and LD tool. RD SLB E-line. USI log shows good quality cement behind the 7" casing from the 6,550' (bottom of log) to -4,550'. 16:30 - 18:30 2.00 RUNCO RUNCMP Pull the wear ring. Make a dummy run with the 3-1/2" hanger. RU 3-1/2" tubing handling equipment. 18:30 - 00:00 5.50 RUNCO RUNCMP PJSM. PU and RIH with the 3-1/2" 9.2# L-80 TCII completion to 2,000'. All connections below the lowest packer have been Bakerloc'd. All connections "torque turned" to 2,300 ftlbs utilizing Jet Lube Seal Guard thread lubricant. 4/28/2006 00:00 - 08:30 8.50 RUNCO RUNCMP Continue to PU and RIH with 3.5" 9.2# L-80 TCII completion from 2,000' to 6,468' utilizing Jet Lube Seal Guard thread lubricant and torque turining the connections to 2,300 ftlbs. MU tubing hanger and land tubing, PU - 90k, SO - 60k. Printed: 5/1!2006 1:31:12 PM , BP EXPLORATION: Page 7 of 7 Operations Summary Report Legal Well Name: L-213 Common Well Name: L-2131 Spud Date: 4/19/2006 Event Name: DRILL+COMPLETE Start: 4/18/2006 End: 4/28/2006 Contractor Name: NABORS ALASKA DRILLING I Rig Release: 4/28/2006 Rig Name: NABORS 9ES Rig Number: Date From - To Hours Task Code NPT Phase Description of Operations 4/28/2006 00:00 - 08:30 8.50 RUNCO RUNCMP 3.5" WLEG, 3.5" TC-II - 6468.18' 3.5" HES 'X' Nipple: 2.813" ID - 6461.00' 3.5" HES 'X' Nipple: 2.813" ID RHC-M Plug - 6440.39' GLM #1-3.5" x 1.5" MMG-W w/Dum-RK latch - 6411.57' 7" x 3.5" Baker 'Premier' Packer #1 - 6390.22' GLM #2-3.5" x 1.5" MMG-W w/Dum-RK latch - 6366.41' GLM #3-3.5" x 1.5" MMG-W w/Dum-RK latch - 6337.80' 7" x 3.5" Baker'Premier' Packer #2 - 6321.44' GLM #4-3.5" x 1.5" MMG-W w/Dum-RK latch - 6297.63' GLM #5-3.5" x 1.5" MMG-W w/Dum-RK latch - 6258.97' 3.5" HES 'X' Nipple: 2.813" ID - 6248.13' 7" x 3.5" Baker 'Premier' Packer #3 - 6236.54' 3.5", 9.2#, L-80 TC-I I Pup Jt with RA collar below collar - 6222.00' GLM #6-3.5" x 1.5" MMG-W w/Dum-RK latch - 6212.76' GLM #7-3.5" x 1.5" MMG-W w/Dum-RK latch - 6164.29' 7" x 3.5" Baker'Premier' Packer #4 -.6142.93' 3.5" HES 'X' Nipple: 2.813" ID - 6127.31' 08:30 - 09:30 1.00 RUNCO RUNCMP Reverse circulate 180 bbls of 9.0 ppg NaCI brine - 3 bpm, 225 psi 09:30 - 11:30 2.00 RUNCO RUNCMP Drop 1-5/16" ball and rod and allow to seat in the RHC-m plug @ 6,440'. Pressure up on the tubing to 4,200 psi to set the packers. Hold pressure and chart for 30 minutes for tubing test - good. Bleed off pressure on the tubing to 2,500 psi. Pressure up on the IA to 4,000 psi. Hold pressure and chart for 30 minutes for IA test -good. Bleed the annulus to 0 psi and then the tubing to 0 psi. Pressure up on the annulus and observe the DCR-1 Shear Valve shear at 2,500 psi. Pump both ways to ensure shear -good. 11:30 - 12:00 0.50 RUNCO RUNCMP Install TWC and test from below to 1,000 psi -good. 12:00 - 14:00 2.00 BOPSU P RUNCMP Remove the mouse hole, pull the riser and ND and secure the BOPE. 14:00 - 17:00 3.00 WHSUR P RUNCMP Prepare and MU the tubing hanger and tubing adapter flange. Test to 5,000 psi and hold for 10 minutes -good. Retrieve the tree from behind the cellar and NU. Test the tree to 5,000 psi - good. 17:00 - 17:30 0.50 WHSUR P RUNCMP Pull the TWC with DSM lubricator. 17:30 - 18:30 1.00 RUNCO RUNCMP Reverse circulate 75 bbls of 9.0 ppg NaCI brine with corrosion inhibitor down the IA - 3 bpm, 415 psi. 18:30 - 21:30 3.00 RUNCO RUNCMP PJSM. RU LRHOS and reverse circulate 116 bbls of freeze protection diesel down the IA - 3 bpm, 500 psi. Shut down and allow the diesel to u-tube into the tubing. RD LRHOS. 21:30 - 22:30 1.00 RUNCO RUNCMP Install BPV and test from below to 1,000 psi -good. LD DSM lubricator. 22:30 - 00:00 1.50 RUNCO RUNCMP Secure the well and clear the cellar area for the rig move. Rig released at 0000 hours to L-122 RWO. Printed: 5/1/2006 1:31:12 PM ,~, L-213 Su Report Date: 25-Apr-O6 Client: BP Exploration Alaska Field: Prudhoe Bay Unit - WOA Structure /Slot: L-PAD / L-213 Well: L-213 Borehole: L-213 UWI/API#: 500292330800 Survey Name /Date: L-213 /April 25, 2006 Tort /AHD / DDI / ERD ratio: 132.143° / 4106.99 ft / 5.880 / 0.854 Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feet location LaULong: N 70.35022064, W 149.32358380 Location Grid NIE Y/X: N 5978131.650 ftUS, E 583314.080 itUS Grid Convergence Angle: +0.63702889° Report Schlumberger Survey / DLS Computation Method: Minimum Curvature / Lubinski Vertiral Section Azimuth: 111.250° Vertical Section Origin: N 0.000 ft, E 0.000 ft TVD Reference Datum: Rotary Table TVD Reference Elevation: 78.10 ft relative to MSL Sea Bed /Ground Level Elevation: 49.60 ft relative to MSL Magnetic Declination: 24.256° Total Field Strength: 57579.012 nT Magnetic Dip: 80.855° Declination Date: April 20, 2006 . Magnetic Declination Model: BGGM 2005 North Reference: True North Total Corr Mag North -> True North: +24.256° Comments Measured Inclination Azimuth Sub-Sea TVD TVD Vertical Along Hole Closure NS EW DLS Northing Easting Latitude Longitude Depth Section Departure ft de de ft ft ft ft ft ft ft de 100 ft ftUS ftUS H 1 t U. UU U.UU U .UU -/kS.l U V.UU U.VU U.UU U.UU U.UU U .UU U.UU by/til:il.bb bt53J14.U23 N /U. 35UZZUb4 VV 14`J.JL3btlJtSU GYD GC MS 68. 00 0.06 346 .15 -10.10 68.00 -0.02 0.04 0.04 0.03 -0 .01 0.09 5978131.68 583314.07 N 70. 35022074 W 149.32358387 168. 00 0.02 359 .12 89.90 168.00 -0.06 0.11 0.11 0.10 -0 .02 0.04 5978131.75 583314.06 N 70. 35022093 W 149.32358398 263 .00 0.39 240 .42 184.90 263.00 -0.27 0.42 0.31 -0.04 -0 .30 0.42 5978131.61 583313.78 N 70. 35022053 W 149.32358626 355 .00 1.45 155 .52 276.89 354.99 0.37 1.72 1.26 -1.25 -0 .09 1.60 5978130.39 583314.00 N 70. 35021722 W 149.32358456 441. 00 3.40 143 .38 362.81 440.91 3.31 5.35 4.69 -4.29 1 .88 2.33 5978127.38 583316.01 N 70. 35020892 W 149.32356855 539. 00 6.87 135 .59 460.40 538.50 11.11 14.11 13.28 -10.81 7 .72 3.60 5978120.92 583321.92 N 70. 35019110 W 149.32352116 630. 00 10.40 131 .29 550.36 628.46 23.79 27.76 26.80 -20.12 17 .70 3.94 5978111.73 583332.00 N 70. 35016567 W 149.32344012 722. 00 14.17 126 .70 640.24 718.34 42.45 47.32 46.18 -32.34 32 .97 4.23 5978099.68 583347.41 N 70. 35013230 W 149.32331613 815 .00 16.42 121 .80 729.94 808.04 66.35 71.84 70.43 -46.07 53 .28 2.79 5978086.18 583367.86 N 70. 35009479 W 149.32315132 Last GYD GC MS 907 .00 19.08 114 .83 817.56 895.66 94.15 99.85 97.93 -59.24 77 .98 3.70 5978073.29 583392.71 N 70. 35005881 W 149.3 First MWD+IFR+MS 945 .10 20.04 112 .46 853.46 931.56 106.89 112.61 110.37 -64.35 89 .67 3.27 5978068.31 583404.45 N 70. 2 35004485 W 149.32 1040 .22 22.93 114 .68 941.97 1020.07 141.69 147.44 144.61 -78.32 121 .57 3.16 5978054.70 583436.50 N 70. 35000669 W 149.322 1 1136 .37 25.68 113 .04 1029.59 1107.69 181.22 187.01 183.80 -94.29 157 .77 2.94 5978039.13 583472.87 N 70. 34996304 W 149.32230307 1231. 28 27.63 113 .30 1114.41 1192.51 223.77 229.58 226.06 -111.05 196 .91 2.06 5978022.81 583512.19 N 70. 34991726 W 149.32198533 1326 .72 30.01 112 .04 1198.02 1276.12 269.76 275.59 271.80 -128.76 239 .37 2.57 5978005.57 583554.84 N 70. 34986887 W 149.32164070 1423 .20 31.99 111 .45 1280.71 1358.81 319.44 325.28 321.21 -147.16 285 .52 2.08 5977987.68 583601.19 N 70. 34981860 W 149.32126603 1517 .82 34.71 113 .20 1359.75 1437.85 371.44 377.29 373.06 -166.94 333 .62 3.05 5977968.44 583649.50 N 70. 34976455 W 149.32087558 1613 .20 38.02 113 .28 1436.54 1514.64 427.95 433.83 429.52 -189.26 385 .58 3.47 5977946.71 583701.70 N 70. 34970358 W 149.32045382 1707 .37 39.19 112 .38 1510.13 1588.23 486.69 492.59 488.19 -212.05 439 .73 1.38 5977924.52 583756.10 N 70. 34964131 W 149.32001422 1802 .64 42.01 113 .62 1582.46 1660.56 548.65 554.58 550.12 -236.29 496 .78 3.08 5977900.92 583813.41 N 70. 34957508 W 149.31955108 1897 .47 43.34 112 .35 1652.18 1730.28 612.89 618.85 614.34 -261.38 555 .96 1.67 5977876.49 583872.86 N 70. 34950653 W 149.31907073 1993 .13 46.74 111 .43 1719.77 i 797.87 680.57 686.53 681.91 -286.60 618 .76 3.62 5977851.98 583935.93 N 70. 34943762 W 149.31856093 SurveyEditor Ver SP 1.0 Bld( doc40x_56) L-213\L-213\L-213\L-213 Generated 5/17/2006 3:06 PM Page 1 of 3 Comments Measured Inclination Azimuth Sub-Sea ND ND Vertical Along Hole Closure NS EW DLS Northing Easting Latitude Longitude Depth Section Departure tt de de ft tt ft ft tt ft ft de 100 tt ftUS ttUS 'LUiitS.tfl 5V .45 11G.L5 1/tf:i.V4 1C1i1.14 /5'L.:il /515.'125 /5:i.52f -:ilJ.;iU bif5.:ib :i.y:i 5`J//tf"Lb. U'L 5t54UVL.iSG N /V.:i4y:ib4b5 W 14`J.:S1t5ULU:iS 2183.96 52 .90 113.01 1842.04 1920.14 826.93 832.92 828.18 -342.03 754.25 2.65 5977798. 06 584072.01 N 70.34928615 W 149.31746116 2279.46 56 .26 110.78 1897.38 1975.48 904.73 910.74 905.91 -371.01 826.46 4.00 5977769. 88 584144.53 N 70.34920694 W 149.31687506 2374.84 56 .62 109.99 1950.11 2028.21 984.20 990.22 985.23 -398.70 900.96 0.79 5977743. 03 584219.33 N 70.34913129 W 149.31627031 2470.43 57 .80 110.09 2001.88 2079.98 1064.54 1070.57 1065.43 -426.24 976.45 1.24 5977716. 34 584295.12 N 70.34905604 W 149.31565753 2567.22 57 .96 110.11 2053.34 2131.44 1146.50 1152.55 1147.26 -454.41 1053.43 0.17 5977689. 02 584372.40 N 70.34897904 W 149.31503267 2662.67 58 .31 112.13 2103.73 2181.83 1227.56 1233.61 1228.26 -483.62 1129.05 1.83 5977660. 66 584448.33 N 70.34889922 W 149.31441893 2757.62 60 .52 111.35 2152.04 2230.14 1309.29 1315.35 1309.97 -513.88 1204.97 2.43 5977631. 24 584524.57 N 70.34881649 W 149.31380267 2852.97 60 .33 111.41 2199.10 2277.20 1392.22 1398.27 1392.86 -544.12 1282.19 0.21 5977601. 87 584602.12 N 70.34873387 W 149.31317589 2948.15 59 .58 111.66 2246.76 2324.86 1474.61 1480.66 1475.23 -574.36 1358.83 0.82 5977572. 49 584679.08 N 70.34865122 W 149.31255383 3044.08 60 .10 111.03 2294.96 2373.06 1557.55 1563.61 1558.14 -604.55 1436.08 0.79 5977543. 16 584756.66 N 70.34856870 W 149.31 3139.92 59 .80 110.97 2342.95 2421.05 1640.51 1646.56 1641.06 -634.28 1513.53 0.32 5977514. 30 584834.42 N 70.34848744 W 149.31 3235.80 59 .14 111.01 2391.65 2469.75 1723.09 1729.15 1723.61 -663.86 1590.64 0.69 5977485. 58 584911.85 N 70.34840658 W 149.31067234 3331.33 59 .17 110.58 2440.63 2518.73 1805.11 1811.17 1805.59 -692.98 1667.31 0.39 5977457. 32 584988.83 N 70.34832699 W 149.31005001 3426.90 59 .33 110.06 2489.50 2567.60 1887.23 1893.30 1887.66 -721.50 1744.33 0.50 5977429. 66 585066.16 N 70.34824902 W 149.30942486 3522.69 59 .86 111.02 2537.98 2616.08 1969.84 1975.92 1970.23 -750.49 1821.69 1.03 5977401. 53 585143.83 N 70.34816978 W 149.30879697 3619.10 59 .41 111.05 2586.72 2664.82 2053.02 2059.10 2053.39 -780.34 1899.34 0.47 5977372. 54 585221.79 N 70.34808816 W 149.30816681 3714.79 59 .37 110.89 2635.44 2713.54 2135.38 2141.46 2135.72 -809.82 1976.24 0.15 5977343. 93 585299.01 N 70.34800758 W 149.30754266 3809.89 59 .51 111.22 2683.79 2761.89 2217.27 2223.35 2217.60 -839.24 2052.66 0.33 5977315. 36 585375.75 N 70.34792715 W 149.30692240 3849.71 59 .63 111.02 2703.96 2782.06 2251.60 2257.68 2251.92 -851.61 2084.69 0.53 5977303. 35 585407.91 N 70.34789333 W 149.30666245 3991.85 58 .41 113.91 2777.14 2855.24 2373.42 2379.54 2373.76 -898.15 2197.29 1.94 5977258. 07 585521.01 N 70.34776610 W 149.30574857 4087.19 58 .83 113.63 2826.78 2904.88 2454.73 2460.93 2455.13 -930.96 2271.78 0.51 5977226. 09 585595.86 N 70.34767642 W 149.30514402 4183.06 58 .31 113.14 2876.77 2954.87 2536.48 2542.73 2536.92 -963.43 2346.86 0.70 5977194. 46 585671.29 N 70.34758765 W 149.30453466 4278.69 57. 51 112.43 2927.58 3005.68 2617.47 2623.75 2617.93 -994.80 2421.56 1.05 5977163. 92 585746.32 N 70.34750186 W 149.30392846 4374.68 58 .51 110.18 2978.43 3056.53 2698.87 2705.16 2699.32 -1024.37 2497.40 2.24 5977135. 20 585822.48 N 70.34742102 W 149.30331293 4470.53 58 .29 108.75 3028.66 3106.76 2780.46 2786.80 2780.86 -1051.58 2574.37 1.29 5977108. 86 585899.74 N 70.34734663 W 149.30268827 4565.60 57 .40 109.14 3079.26 3157.36 2860.89 2867.29 2861.22 -1077.71 2650.50 1.00 5977083. 58 585976.14 N 70.34727517 W 149.30207044 4661.89 55 .41 109.48 3132.53 3210.63 2941.04 2947.49 2941.33 -1104.23 2726.19 2.09 5977057. 90 586052.12 N 70.34720265 W 149.30145616 4757.14 55 .74 110.20 3186.38 3264.48 3019.59 3026.06 3019.84 -1130.89 2800.09 0.71 5977032. 06 586126.31 N 70.34712973 VV 149.3 8 4852.71 57 .67 110.94 3238.84 3316.94 3099.46 3105.93 3099.69 -1158.96 2874.88 2.12 5977004. 83 586201.39 0 N 70.34705296 W 149.30 8 4948.53 59 .08 110.75 3289.08 3367.18 3181.05 3187.52 3181.27 -1187.99 2951.12 1.48 5976976. 65 586277.95 N 70.34697357 W 149.29963069 5043.93 58 .06 109.39 3338.83 3416.93 3262.43 3268.92 3262.62 -1215.93 3027.58 1.62 5976949. 57 586354.70 N 70.34689716 W 149.29901024 5140.03 56 .22 108.42 3390.97 3469.07 3343.08 3349.64 3343.24 -1242.09 3103.94 2.09 5976924. 26 586431.34 N 70.34682561 W 149.29839052 5235.57 53 .97 108.20 3445.64 3523.74 3421.32 3427.99 3421.44 -1266.71 3178.32 2.36 5976900. 47 586505.99 N 70.34675828 W 149.29778690 5330.46 51 .08 109.74 3503.37 3581.47 3496.56 3503.29 3496.65 -1291.16 3249.53 3.31 5976876. 81 586577.46 N 70.34669138 W 149.29720899 5426.82 46 .32 112.20 3566.95 3645.05 3568.92 3575.65 3569.01 -1317.01 3317.12 5.30 5976851. 72 586645.32 N 70.34662070 W 14929666051 5521.93 41 .79 112.48 3635.29 3713.39 3635.02 3641.77 3635.12 -1342.13 337828 4.77 5976827. 28 586706.75 N 70.34655198 W 14929616422 5617.68 37 .18 112.82 3709.17 3787.27 3695.87 3702.64 3695.98 -1365.57 3434.46 4.82 5976804. 48 586763.18 N 70.34648790 W 149.29570834 5713.18 32 .67 111.76 3787.45 3865.55 3750.52 3757.30 3750.63 -1386.32 3485.02 4.76 5976784. 29 586813.97 N 70.34643112 W 149.29529803 5808.60 28 .43 109.78 3869.61 3947.71 3799.00 3805.78 3799.11 -1403.57 3530.33 4.57 5976767. 55 586859.47 N 70.34638396 W 14929493031 5904.34 25 .01 109.27 3955.11 4033.21 3842.03 3848.83 3842.12 -1417.96 3570.89 3.58 5976753. 61 586900.18 N 70.34634458 W 149.29460115 SurveyEditor Ver SP 1.0 Bld( doc40x_56) L-213\L-213\L-213\L-213 Generated 5/17/2006 3:06 PM Page 2 of 3 Comments Measured Inclination Azimuth SulrSea ND ND Vertical Along Hole Closure NS EW DLS Northing Easting Latitude Longitude Depth Section Departure ft de de ft ft ft ft ft ft ft de 00 ft ftUS ftUS 6000.13 21.80 107.30 4043.01 4121.11 3880.02 3886.87 3880.10 -1429.94 360/.00 3.45 597674Z.U3 6096.17 20.22 107.39 4132.66 4210.76 3914.37 3921.30 3914.44 -1440.20 3639.87 1.65 5976732.14 6192.23 18.12 107.59 4223.39 4301.49 3945.84 3952.84 3945.90 -1449.68 3669.95 2,19 5976723.00 6287.40 17.58 106.76 4313.98 4392.08 3974.94 3982.01 3974.99 -1458.29 3697.82 0.63 5976714.69 6383.04 17.14 105.98 4405.26 4483.36 4003.37 4010.55 4003.41 -1466.34 3725.20 0.52 5976706.95 6478.64 16.65 105.40 4496.73 4574.83 4031.03 4038.33 4031.05 -1473.85 3751.95 0.54 5976699.74 6574.26 16.21 105.77 4588.45 4666.55 4057.94 4065.38 4057.95 -1481.12 3778.00 0.47 5976692.76 Last MWD+IFR+MS 6651.40 15.96 105.05 4662.57 4740.67 4079.20 4086.75 4079.21 -1486.80 3798.60 0.41 5976687.31 TD (Projected) 6725.00 15.96 105.05 4733.33 4811.43 4099.32 4106.99 4099.32 -1492.06 3818.15 0.00 5976682.27 Survey Type: Definitive Survey NOTES: GYD-GC-SS - (Gyrodata -gyro compassing m/s -- Older Gyrodata gyro multishots-plus all battery/memory tool surveys (RGS-BT). Replaces ex-BP "Gyrodata multishot into open hole" model. Not to be run above 70 degrees inclination. ) MWD +IFR + MS - (In-field referenced MWD with mull-station analysis and correction applied in post-processing. Assumes a BHA sag correction is applied to enhance inclination accuracy. ) Legal Description: Northing (Y) [ftUS] Easting (X) [ftUS] Surface : 2408 FSL 3602 FEL S34 T12N R11 E UM 5978131.65 583314.08 BHL : 915 FSL 5067 FEL S35 T12N R11 E UM 5976682.27 587148.22 58(i93(i.4L N /U.34ti3118L W 149."19430814 586969.39 N 70.34628374 W 149.29404142 586999.58 N 70.34625781 W 149.29379729 587027.54 N 70.34623423 W 149.29357112 587055.00 N 70.34621221 W 149.29334894 587081.83 N 70.34619165 W 149.29313189 587107.95 N 70.34617176 W 149.29292048 587128.62 N 70.34615622 W 149.29275328 587148.22 N 70.34614183 W 149.29259468 • • SurveyEditor Ver SP 1.0 Bld( doc40x_56) L-213\L-213\L-213\L-213 Generated 5/17/2006 3:06 PM Page 3 of 3 TREE = 41/8" WELLHEAD = FMC ACTUATOR = NA KB. ELEV = BF. ELEV = 78.1' 49.6' KOP = 400' Max Angle = 61° @ 2757 Datum MD = xxxx' Datum ND = xxxx' SS DRLG DRAFT L-213i ETY NOTES: GLM'S @ STA#1- #7 ARE 1/2" X 1-112" MMG-W WHICH ARE WATERFLOOD MANDRELS. 3299' 3-1 /2" HES X NIP, ID = 2.813" WATERFLOOD/GAS LIFT MANDRELS 9-5/8" CSG, 40#, L-80, ID = 8.835" ( 3896' . Minimum ID = 2.813" 3-112" HES X NIPPLE 7" MARKER JOINT W/ RA TAG 5775' 7" MARKER JOINT W/ RA TAG ~-~ 6160' 3-1/2" TBG W/ RA Tag in Centralizer ~~ 6222' 3-112" TBG, 9.2#, L-80, .0087 bpf, ID = 2.992" ~~ 646$' PERFORATION SUMMARY REF LOG: Anadrill LWD 04/25/2006 ANGLE AT TOP PERF: 18° @ 6192' Note: Refer to Production DB for historical pert data SIZE SPF INTERVAL Opn/Sqz DATE 4.5" 5 6192-6226 Open 04/26/06 4.5" 5 6255-6286 Open 04/26/06 4.5" 5 6298-6313 Open 04/26/06 4.5" 5 6356-6368 Open 04/26!06 4.5" 5 6408-6456 Open 04/26/06 ST MD ND DEV TYPE VLV LATCH PORT DRTE 8 6036 4154 21 MMG DCR-1 RKP 1.5" 04/28/06 7 6164 4275 19 MMG-W DUM RK 1.5" 04/28/06 6 6213 4322 18 MMG-W DUM RK 1.5" 04(28/06 5 6259 4365 18 MMG-W DUM RK 1.5" 04128!06 4 6298 4402 18 MMG-W DUM RK 1.5" 04/28/06 3 6338 4440 18 MMG-W DUM RK 1.5" 04/28/06 2 6366 4467 17 MMG-W DUM RK 1.5" 04/28!06 1 6412 4512 17 MMG-W DUM RK 1.5" 04/28/06 6127' 3-1l2" HES X NIP, ID = 2.813" 6143' 7" X 3-1/2" BKR PREMIER PKR, ID = 2.87" 6236' ( 7" X 3-1 /2" BKR PREMIER PKR, ID = 2.87" 6248' 3-1/2" HES X NIP, ID = 2.813" 6321' 7" X 3-1/2" BKR PREMIER PKR, ID = 2.87" 6390' 7" X 3-1 /2" BKR PREMIER PKR, ID = 2.87" PI BTD I~ bbLJ 7" CSG, 26#, L-8q ID = 6.276" 6714' 644~~3-112" HES XNIP, ID = 2.813" w/RHC-m 6461' 3-1 /2" HES X NIP, ID = 2.813" 646$' 3-1 /2" WLEG, ID = 3.00" DATE REV BY COMMENTS DATE REV BY COMMENTS ORION UNIT 04/28/06 9ES ORIGINAL COMPLETION WELL: L-2131 PERMIT No: 206-053 API No: 50-029-23308-00 SEC 34, T12N, R11E, 2408' NSL & 3602' WEL BP Exploration (Alaska) SCHLUMBERGER Survey report Client ...................: BP Exploration (Alaska) Inc. Field ..................... Orion Well ...................... ~ _ ~ 13 API number ...............: 50-029-23308-00 Engineer .................: St. Amour RIG :.....................: Nabors 9ES STATE :.................... Alaska ----- Survey calculation methods------------- Method for positions.....: Minimum curvature Method for DLS...........: Mason & Taylor ----- Depth reference ---- Permanent datum..........: Depth reference..........: GL above permanent.......: KB above permanent.......: DF above permanent.......: ------------------ Mean Sea Level Driller's Pipe Tally 49.60 ft N/A (Topdrive) 78.10 ft ----- Vertical section origin---------------- Latitude (+N/S-).........: 0.00 ft Departure (+E/W-)........: 0.00 ft ----- Platform reference point--------------- Latitude (+N/S-).........: -999.25 ft Departure (+E/W-)........: -999.25 ft Azimuth from Vsect Origin to target: 111.25 degrees 25-Apr-2006 11:26:50 Page 1 of 4 Spud date ................: 19-Apr-6 Last survey date.........: 25-Apr-06 Total accepted surveys...: 73 MD of first survey.......: 0.00 ft MD of last survey........: 6725.00 ft ----- Geomagnetic data ---------------------- Magnetic model...........: BGGM version 2005 Magnetic date ............: 19-Apr-2006 Magnetic field strength..: 57579.16 LAMA Magnetic dec (+E/W-).....: 24.26 degrees Magnetic dip .............: 80.86 degrees ----- MWD survey Reference Reference G ..............: Reference H ............... Reference Dip ............: Tolerance of G...........: Tolerance of H............ Tolerance of Dip.........: Criteria --------- 1002.68 meal 57579.00 GAMA 80.86 degrees (+/-) 2.50 meal (+/-)300.00 LAMA (+/-) 0.45 degrees ----- Corrections --------------------------- Magnetic dec (+E/W-).....: 24.26 degrees Grid convergence (+E/W-).: 0.00 degrees Total az corr (+E/W-)....: 24.26 degrees (Total az corr = magnetic dec - grid conv) Survey Correction Type .... I=Sag Corrected Inclination M=Schlumberger Magnetic Correction S=Shell Magnetic Correction F=Failed Axis Correction R=Magnetic Resonance Tool Correction D=Dmag Magnetic Correction • • !_ ._ ® S SE:.'HLUMBERGER Survey Report 25-Apr-2006 11:26:50 Page 2 of 4 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 0.00 0.00 0.00 0.00 0.00 0.00 0.00 TIP None 2 68.00 0.06 346.15 68.00 68.00 -0.02 0.03 -0.01 0.04 346.15 0.09 BP _GYD CT DMS 3 168.00 0.02 359.12 100.00 168.00 -0.06 0.10 -0.02 0.11 348.29 0.04 BP _GYD CT DMS 4 263.00 0.39 240.42 95.00 263.00 -0.27 -0.04 -0.30 0.31 262.44 0.42 BP _GYD CT DMS 5 355.00 1.45 155.52 92.00 354.99 0.37 -1.25 -0.09 1.26 184.23 1.60 BP GYD CT DMS 6 441.00 3.40 143.38 86.00 440.91 3.31 -4.29 1.88 4.69 156.35 2.33 BP _GYD CT DMS 7 539.00 6.87 135.59 98.00 538.50 11.11 -10.81 7.72 13.28 144.49 3.60 BP - • GYD CT DMS 8 630.00 10.40 131.29 91.00 628.46 23.79 -20.12 17.70 26.80 138.67 3.94 BP GYD CT DMS 9 722.00 14.17 126.70 92.00 718.34 42.45 -32.34 32.97 46.18 134.44 4.23 BP _ _GYD CT DMS 10 815.00 16.42 121.80 93.00 808.04 66.35 -46.07 53.28 70.43 130.85 2.79 BP GYD CT DMS 11 907.00 19.08 114.83 92.00 895.66 94.15 -59.24 77.98 97.93 127.22 3.70 BP _GYD CT DMS 12 945.10 20.04 112.46 38.10 931.56 106.89 -64.35 89.67 110.37 125.67 3.27 BP _MWD+IFR+MS 13 1040.22 22.93 114.68 95.12 1020.07 141.69 -78.32 121.57 144.61 122.79 3.16 BP _MWD+IFR+MS 14 1136.37 25.68 113.04 96.15 1107.69 181.22 -94.29 157.77 183.80 120.87 2.94 BP MWD+IFR+MS 15 1231.28 27.63 113.30 94.91 1192.51 223.77 -111.05 196.91 226.06 119.42 2.06 BP _ MWD+IFR+MS 16 1326.72 30.01 112.04 95.44 1276.12 269.76 -128.76 239.37 271.80 118.28 2.57 BP _MWD+IFR+MS 17 1423.20 31.99 111.45 96.48 1358.81 319.44 -147.16 285.52 321.21 117.27 2.08 BP _MWD+IFR+MS 18 1517.82 34.71 113.20 94.62 1437.85 371.44 -166.94 333.62 373.06 116.58 3.05 BP _MWD+IFR+MS 19 1613.20 38.02 113.28 95.38 1514.64 427.95 -189.26 385.58 429.52 116.14 3.47 BP MWD+IFR+MS 20 1707.37 39.19 112.38 94.17 1588.23 486.69 -212.05 439.73 488.19 115.74 1.38 BP _ MWD+IFR+MS 21 1802.64 42.01 113.62 95.27 1660.56 548.65 -236.29 496.78 550.12 115.44 3.08 BP MWD+IFR+MS • 22 1897.47 43.34 112.35 94.83 1730.28 612.89 -261.38 555.96 614.34 115.18 1.67 BP _ _MWD+IFR+MS 23 1993.13 46.74 111.43 95.66 1797.87 680.57 -286.60 618.76 681.91 114.85 3.62 BP MWD+IFR+MS 24 2088.81 50.45 112.25 95.68 1861.14 752.31 -313.30 685.36 753.58 114.57 3.93 BP _ _MWD+IFR+MS 25 2183.96 52.90 113.01 95.15 1920.14 826.93 -342.03 754.25 828.18 114.39 2.65 BP MWD+IFR+MS 26 2279.46 56.26 110.78 95.50 1975.48 904.73 -371.01 826.46 905.91 114.18 4.00 BP _MWD+IFR+MS 27 2374.84 56.62 109.99 95.38 2028.21 984.20 -398.70 900.96 985.23 113.87 0.79 BP _MWD+IFR+MS 28 2470.43 57.80 110.09 95.59 2079.98 1064.54 -426.24 976.45 1065.43 113.58 1.24 BP _MWD+IFR+MS 29 2567.22 57.96 110.11 96.79 2131.44 1146.50 -454.41 1053.43 1147.26 113.33 0.17 BP _MWD+IFR+MS 30 2662.67 58.31 112.13 95.45 2181.83 1227.56 -483.62 1129.04 1228.26 113.19 1.83 BP MWD+IFR+MS SCHLUMBERGER Survey Report 25-Apr-2006 11:26:50 Page 3 of 4 --- 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) ------ (f t) -------- (ft) -------- (ft) ------- (ft) --------- (ft) ------- (deg) -------- 100f) ----- - type (deg) ---- ------ 31 -------- 2757.62 ------ 60.52 ------- 111.35 ------ 94.95 -------- 2230.14 -------- 1309.29 ------- -513.88 --------- 1204.97 ------- 1309.97 -------- 113.10 ----- 2.43 - BP ---- ------ _MWD+IFR+MS 32 2852.97 60.33 111.4 1 95.35 2277.20 1392.22 -544.12 1282.19 1392.86 112.99 0.21 BP _MWD+IFR+MS 33 2948.15 59.58 111.66 95.18 2324.86 1474.61 -574.36 1358.83 1475.23 112.91 0.82 BP _MWD+IFR+MS 34 3044.08 60.10 111.03 95.93 2373.06 1557.55 -604.55 1436.08 1558.14 112.83 0.79 BP _MWD+IFR+MS 35 3139.92 59.80 110.97 95.84 2421.05 1640.51 -634.28 1513.53 1641.06 112.74 0.32 BP MWD+IFR+MS 36 3235.80 59.14 111.01 95.88 2469.75 1723.09 -663.86 1590.64 1723.61 112.65 0.69 BP MWD+IFR+MS 37 3331.33 59.17 110.58 95.53 2518.73 1805.11 -692.98 1667.31 1805.59 112.57 0.39 BP - • MWD+IFR+MS 38 3426.90 59.33 110.06 95.57 2567.60 1887.23 -721.50 1744.33 1887.66 112.47 0.50 BP _MWD+IFR+MS 39 3522.69 59.86 111.02 95.79 2616.08 1969.84 -750.49 1821.69 1970.23 112.39 1.03 BP _MWD+IFR+MS 40 3619.10 59.41 111.05 96.41 2664.81 2053.02 -780.35 1899.33 2053.39 112.34 0.47 BP MWD+IFR+MS 41 3714.79 59.37 110.89 95.69 2713.54 2135.38 -809.82 1976.24 2135.72 112.28 0.15 BP _MWD+IFR+MS 42 3809.89 59.51 111.22 95.10 2761.89 2217.27 -839.24 2052.66 2217.60 112.24 0.33 BP _MWD+IFR+MS 43 3849.71 59.63 111.02 39.82 2782.06 2251.60 -851.61 2084.69 2251.92 112.22 0.53 BP _MWD+IFR+MS 44 3991.85 58.41 113.91 142.14 2855.24 2373.41 -898.15 2197.29 2373.76 112.23 1.94 BP _MWD+IFR+MS 45 4087.19 58.83 113.63 95.34 2904.88 2454.73 -930.96 2271.78 2455.13 112.28 0.51 BP MWD+IFR+MS 46 4183.06 58.31 113.14 95.87 2954.87 2536.48 -963.43 2346.86 2536.92 112.32 0.70 BP _MWD+IFR+MS 47 4278.69 57.51 112.43 95.63 3005.68 2617.47 -994.80 2421.56 2617.93 112.33 1.05 BP _MWD+IFR+MS 48 4374.68 58.51 110.18 95.99 3056.53 2698.87 -1024.37 2497.40 2699.32 112.30 2.24 BP _MWD+IFR+MS 49 4470.53 58.29 108.75 95.85 3106.76 2780.46 -1051.58 2574.37 2780.86 112.22 1.29 BP _MWD+IFR+MS 50 4565.60 57.40 109.14 95.07 3157.36 2860.89 -1077.71 2650.50 2861.22 112.13 1.00 BP MWD+IFR+MS 51 4661.89 55.41 109.48 96.29 3210.63 2941.04 -1104.23 2726.19 2941.33 112.05 2.09 BP _MWD+IFR+MS • 52 4757.14 55.74 110.20 95.25 3264.48 3019.59 -1130.89 2800.09 3019.84 111.99 0.71 BP _MWD+IFR+MS 53 4852.71 57.67 110.94 95.57 3316.94 3099.46 -1158.96 2874.88 3099.69 111.96 2.12 BP _MWD+IFR+MS 54 4948.53 59.08 110.75 95.82 3367.18 3181.04 -1187.99 2951.12 3181.27 111.93 1.48 BP MWD+IFR+MS 55 5043.93 58.06 109.39 95.40 3416.93 3262.43 -1215.93 3027.58 3262.62 111.88 1.62 BP MWD+IFR+MS 56 5140.03 56.22 108.42 96.10 3469.07 3343.08 -1242.09 3103.94 3343.24 111.81 2.09 BP _MWD+IFR+MS 57 5235.57 53.97 108.20 95.54 3523.74 3421.32 -1266.71 3178.32 3421.44 111.73 2.36 BP _MWD+IFR+MS 58 5330.46 51.08 109.74 94.89 3581.47 3496.56 -1291.16 3249.53 3496.65 111.67 3.31 BP _MWD+IFR+MS 59 5426.82 46.32 112.20 96.36 3645.05 3568.92 -1317.01 3317.12 3569.00 111.65 5.30 BP _MWD+IFR+MS 60 5521.93 41.79 112.48 95.11 3713.39 3635.02 -1342.13 3378.28 3635.12 111.67 4.77 BP MWD+IFR+MS 5';HLUMBERGER Survey Report 25-Apr-2006 11:26:50 Page 4 of 4 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) (f t) (f t) (ft) (ft) (deg) 100f) type (deg) 61 5617.68 37.18 112.82 95.75 3787.27 3695.87 -1365.57 3434.45 3695.98 111.68 4.82 BP _MWD+IFR+MS 62 5713.18 32.67 111.76 95.50 3865.55 3750.52 -1386.32 3485.02 3750.63 111.69 4.76 BP _MWD+IFR+MS 63 5808.60 28.43 109.78 95.42 3947.71 3799.00 -1403.57 3530.33 3799.11 111.68 4.57 BP _MWD+IFR+MS 64 5904.34 25.01 109.27 95.74 4033.21 3842.02 -1417.96 3570.89 3842.12 111.66 3.58 BP _MWD+IFR+MS 65 6000.13 21.80 107.30 95.79 4121.11 3880.02 -1429.94 3607.00 3880.10 111.63 3.45 BP MWD+IFR+MS 66 6096.17 20.22 107.39 96.04 4210.76 3914.37 -1440.20 3639.87 3914.44 111.59 1.65 BP _MWD+IFR+MS 67 6192.23 18.12 107.59 96.06 4301.49 3945.84 -1449.68 3669.95 3945.90 111.55 2.19 BP - • MWD+IFR+MS 68 6287.40 17.58 106.76 95.17 4392.08 3974.94 -1458.30 3697.82 3974.98 111.52 0.63 BP _MWD+IFR+MS 69 6383.04 17.14 105.98 95.64 4483.36 4003.37 -1466.34 3725.20 4003.41 111.49 0.52 BP _MWD+IFR+MS 70 6478.64 16.65 105.40 95.60 4574.84 4031.02 -1473.86 3751.95 4031.05 111.45 0.54 BP MWD+IFR+MS 71 6574.26 16.21 105.77 95.62 4666.55 4057.94 -1481.12 3778.00 4057.95 111.41 0.47 BP _MWD+IFR+MS 72 6651.40 15.96 105.05 77.14 4740.67 4079.20 -1486.80 3798.60 4079.21 111.38 0.41 BP _MWD+IFR+MS 73 6725.00 15.96 105.05 73.60 4811.43 4099.32 -1492.06 3818.14 4099.32 111.34 0.00 Projected To TD [(c)2006 IDEAL ID10 2C O1] • RECEIVED MAY 2 4 2006 s~ _,_~I_ ~~ p TaA~ (~,~~.'t"`nmrtti~`~'~ NO. 3820 Schlumberger-DCS ! ~i A~W Www~ne~Mr~ VV~~~~" Company: Alaska Oil & Gas Cons Comm 2525 Gambell St, Suite 400 A,MM°,y" Attn: Helen Warman Anchorage, AK 99503-2838 333 West 7th Ave, Suite 100 ATTN: Beth Anchorage, AK 99501 Field: Orion Borealis Well Job N Log Description Date BL Color CD 05/23/06 • PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Petrotechnical Data Center LR2-1 900 E Benson Blvd. Anchorage AK 99508-4254 n h Date Delivered: ~~~.,~ Schlumberger-DCS 2525 Gambell St, Suite 400 Anchorage, AK 99503-2638 ATTN: Beth ~{- /, Received by: .J /~ ~/bl, • • Schlumberger Drilling & Measurements MWD/LWD Log Product Delivery Customer BP Exploration (Alaska) Inc. Dispatched To: AOGCC -Librarian Well No L-213 Installation/Rig Nabors 9ES Date Dispatched Dispatched By: 2-May-O6 Mauricio Perdomo Data No Of Prints No of Floppies Surveys 2 1 r Received By: ~ ~ ~`.p7 ~.- !~ Please sign and return to: Drilling & Measurements LWD Division y ~ ~ 9 , ~,~ ~ ~~ ~a ~ 2525 Gambell Street, Suite 400 Anchorage, Alaska 99501 nrosetC~slb.com Fax: 907-561-8317 LWD Log Delivery V1.1,10-02-03 ~ ~ ~m~ ~J ~~ ~~ ~' I~ ~~~ ~ ~' ~ 3 ALASSA OIL A1~TD GAS COI~TSERQATI011T CO1rIl-IISSIOIQ Robert Tirpack Senior Drilling Engineer BP Exploration (Alaska) Inc. PO Box 196612 Anchorage, AK 99519-6612 ' r' FRANK H. MURKOWSKI, GOVERNOR 333 W. 7T" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Prudhoe Bay Field, Orion Oil Pool, PBU L-213i BP Exploration (Alaska) Inc. Permit No: 206-053 SurIat:~ T ~~?t~~n: 2409' FSL, 3602' FEL, SEC. 34, T12N, R11E Bottomhole Location: 964' FSL, 5171' FEL, SEC. 35, T 12N, R 11 E Dear Mr. Tirpack: 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 i.he right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). DATED this? day of April, 2006 cc: Department of Fish 8s Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. ~~i~~ STATE OF ALASKA ALA.~OIL AND GAS CONSERVATION COMIV~ON PERMIT TO DRILL 20 AAC 25.005 ~'c~~~~ APR 0 4 2006 Alaska Qi1 ~ Gas Cons. Ci~mmissar 1 a. Type of work ® Drill ^Redrill ^ Re-Entry 1 b. Current Well Class O Exploratory ^ Development Gas ®Service ^ Multiple Zone ^ Stratigraphic Test Q Development Oil ^ Single Zone 1 c. Specify if well is pro~lf~~ ^ Coalbed Methane ^ Gas Hydrates ^ Shale Gas 2. Operator Name: BP Exploration (Alaska) Inc. - 5. Bond: ®Blanket ^ Single Well Bond No. 6194193 11. Well Name and Number: PBU L-213i 3. Address: P.O. Sox 196612, Anchorage, Alaska 99519-6612 6. Proposed Depth: MD 6671 TVD 4805 12. Field /Pool(s): Prudhoe Bay Field / Orion 4a. Location of Well (Governmental Section): Surface: 2409' FSL 3602' FEL, SEC 34 R11 E (As Staked) T12N 7. Property Designation: ADL 028238 Schrader Bluff ~ , . , , Top of Productive Horizon: 1012' FSL, 19' FEL, SEC. 34, T12N, R11 E 8. Land Use Permit: 13. Approximate S Date: Apr' 15 006 Total Depth: 964' FSL, 5171' FEL, SEC. 35, T12N, R11 E 9. Acres in Property: 2560 14. Distance to N crest Property: 9480' 4b. Location of Well (State Base Plane Coordinates): Surface: x-583314 y- 5978123 Zone-ASP4 10. KB Elevation (Height above GL): 78.1 feet 15. Distance to Nearest well Within Pool: 820' away from L-104 16. Deviated Wells: Kickoff Depth: 300 feet Maximum Hole Angle: 58.11 de rees 17. Maximum Anticipated Pressures in psig (see 20 .035) Downhole: 2138 Surface: 178 18. Casin Pro. ram: S ecifiCations Top - Settin De th -Bottom Quanti of ent, c.f. or sacks Hole Casin Wei ht Grade Cou lin Len th MD TVD MD TVD includin sta a data 42" 20" 215.5# A-53 Welded 80' 29' 29' 109' 109' 260 sx Arctic Set A rox. 12-1/4" 9-5/8" 40# L-80 BTC 3647' 29' 29' 3676' 2678' 552 sx Class 'G', 294 sx Class 'G' 8-3/4" 7" 26# L-80 BTC-M / TC II 6642' 29' 29' 6671' 4805' 35 sx Crete, 251 sx Class 'G' 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effective Depth MD (ft): Effective Depth TVD (ft) Junk (measured): Easing Length Size Cement Volume MD ND Conductor /Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments ®Filing Fee, $100 ^ BOP Sketch ®Drilling Program ^ Time vs Depth Plot ^ Shallow Hazard Analysis ® Property Plat ^ Diverter Sketch ^ Seabed Report ®Drilling Fluid Program ®20 AAC 25.050 Requirements 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact Ron Phillips, 564-5913 Printed Name Robert Tirpack Title Senior Drilling Engineer Prepared ey NamelNumber: Si nature ~s.°z~ ~ Phone ~ ~ `/ ~ ~~~ ~ Date 3~3~ ~ Sondra Stewman, 564-4750 Commission Use Onl y Permit To Drill Number: „Zd6~-b API Number: 50- OZ - 2.3 3 O $' Permit A prova( Date: ~ See cover letter for other requirements Conditions of Approval: If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas rates, or gas contained shales Samples Req'd: ^ Yes ~No Mud Log Req'd: ^ Yes ~No 2 ~ ~ ~~ ~ ~~ , _ HZS Mgasur s: Yes ^ N Dir ctional Survey Req'd: Yes ^ No Other: ~ 'e-'-r n tti- ~ °'vt-~ ~ ~- . APPROVED BY THE COMMISSIO Date ~ ~~ ,COMMISSIONER Form 10-401 Revised 12/2005 ~ ~ ~ ~ u ~/ / ~ Submit In Duplicate ORIG v • • Well Name: L-2131 Well Plan Summary T e of Well roducer or in'ector : USH Injector Surface Location: As Staked 2408' FSL, 3602' FEL, Sec. 34, T12N, R11 E X = 583,314 Y = 5,978,132 Shallow Target Coordinates To SV1 : 1688' FSL, 1811' FEL, Sec. 34, T12N, R11 E X = 585,115 Y = 5,977,431 Z = -2500' TVDss Target Start ASP Coordinats To OA : 1011' FSL, 19' FEL, Sec. 34, T12N, R11 E X = 586,915 Y = 5,976,775 Z = -4220' TVDss BHL ASP Coordinates: 963' FSL, 5172' FEL, Sec. 35, T12N, R11 E r X = 587,043 Y = 5,976,729 Z = -4727' TVDss AFE Number: XXXXXXXXX Ri Nabors ES GL: 49.6' KB: 28.5' Estimated Start Date: April 15, 2006 O eratin da s to com lete: 14.5 TD: 6,671' MD TVD: 4,805' Max Inc: 58.38° KBE: 78.1' Well Design: USH Grassroots Schrader Injector 3-'h" TCII 4-Packer Com letion. Current Well Information General Distance to Nearest Property: 9,480' to PBU boundary Distance to Nearest Well in Pool: 820' to L-104 at Top OA ~ API Number: 50-029-XXXXX Well Type: Development -Orion Schrader Injector Current Status: New well, 20" X 34" insulated conductor Conductor: 20" X 34", 215.5 Ib/ft, A53 ERW set at 109' RKB BHP: 2,050 psi -Top of OBf Sand (8.6 ppg ~ 4,585' TVDss) BHT: 95°F C~ 4,727' TVDss estimated '/a Mile Weltbore Near Wellbore Mechanical Integrity Summary: 2a4ivR `o"' ~ti,B L~, ~ ~ Three wellbores lie within a'/a mile radius of proposed injection well L-213i as measured from the L-213i O- sand Schrader Bluff injection interval: V-203, L-03, and L-104. For the offset production wells V-203 and L-03, successful cement programs were pumped to provide cement well above the top of the Orion Schrader Bluff l Pool. Both jobs successfully bumped the plug at the calculated displacement, and got full returns. In addition, V-203, had a USIT log run, which showed good quality cement across the Schrader Bluff N and O sand intervals. L-2131 will provide injection support to the V-203 O sand producing laterals which lie 1280' away at the OBd sand. L-03 is an Ivishak production well which lies i 000' away from L-213i at the OBf sand level. The third well, Borealis Kuparuk producer L-104, lies 808' to the north of L-2131 at the OA sand level. During cementing of L-104 in January 2002, fluid losses occurred, and there were no returns during cement displacement. Assuming a 30% excess hole volume, the 115 BBLs of cement pumped would cover the L-104 5-1/2"x3-1/2" (701' of 3-1/2") string in 6-3/4" annulus for an expected Top of Cement at 5337' MD (286' MD above the top Ugnu Ma sand, or 835' MD above the top of the Orion Pool) if no losses were noted (top of the Ma in L-104 is 5623' MD). A SCMT bond log was run after completion over the short Kuparuk production interval from TD to the tubing tail, which showed good cement, so the lost circulation zone is assumed to be uphole of this point (9658' MD). Additionally, an analysis of the cementing pressure and detail log suggests L-213i Drilling Permit Page • ~ ~ that cement was being displaced up the annulus, but the final top of cement can not be calculated. Based on ~' all available data, cement integrity in L-104 across the Schrader Bluff interval is unknown. L-213i is proposed as a WAG injector supporting the Orion penta-lateral producer V-203. (See attached target map) L-2131 will be located deep in the corner of afault-bounded O sand reservoir polygon, and is positioned to sweep the bulk of that corner's reserves toward the V-203 producer. The bounding fault to the north of the L-213 O sand injection point is 80-90' in throw and to the west is 160-170'. Both faults are believed to be ~ sealing. In particular across the northern fault, geochemical analysis of Schrader Bluff oils obtained on either side of the fault are very different in composition. This observation along with the regional observation of both fluid level and compositional differences across faults displacing the Schrader Bluff O sands support the interpretation of sealing faults in the L-213i area. Reservoir modeling suggests that the differential path of all injected fluids into L-2131 will be toward the pressure sink caused by the V-203 producer to the southeast, and not to the north toward L-104 across the fault. As Orion Field Operator, BP believes that while mechanical integrity can not be proven in all wells within a ~/a ~ mile radius of the proposed L-213i injection point due to top of cement uncertainty in L-104, the geologic and fluid migration detail provided above suggest the risk of L-213i injected fluids migrating out of the Pool or to surface via the L-104 wellbore is minimal. Regular daily annulus pressure monitoring on L-104, as well as on all L and V Pad wells, will provide additional ongoing assurance of Schrader Bluff injection conformance once injection begins in L-2131. Anti-Collision Issues: On a Global Scan, all wells pass BP's major risk assessment. L-213i Drilling Permit Page 2 Formation Markers L-2131 (Based on SOR) • Est. Form. Top Commercial H drocarbon Bearin Est. Pore Press. Est. Pore Press. Formation (MD) (TVD-kb) (TVDss) (Yes/No) (Psi) (PPS EMW) G1 333 333 255 No 115 8.7 SV6 962 953 875 No 394 8.7 Fault 1 L Pad Fault 1176 1153 1075 SV5 1650 1548 1470 No 662 8.7 SV4 1840 1683 1605 Poss. Gas H drates 722 8.7 Base Permafrost 1964 1763 1685 No 758 8.7 SV3 2503 2063 1985 Poss. Gas H drates 893 8.7 SV2 2827 2233 2155 Poss. Gas H drates 970 8.7 SV1 3485 2578 2500 Gas Hydrates or free as 1125 8.7 UG4 4095 2898 2820 Thin coal 1269 8.7 UG4A 4152 2928 2850 Heavy Oil betty 2855 and 2950' SS 1283 8.7 UG3 4887 3313 3235 Thin coals 1456 8.7 UG1 5574 3773 3695 Heavy oil betty 3625' and 3770' SS. 1663 8.7 Ma Faulted to 5708 3888 3810 Heavy oil betty 3810' and 3825' SS 1715 8.7 Mb1 5725 3903 3825 Heavy oil betty 3825' and 3865' SS 1721 8.7 Mb2 5803 3973 3895 Heavy oil betty 3895' and 3910' SS 1753 8.7 Mc 5896 4058 3980 Heavy oil betty 3985' and 4015' SS 1791 8.7 Na 5970 4128 4050 No 1915 8.8 Nb 6001 4158 4080 Yes 1850 8.7 Nc 6033 4188 4110 Yes 1870 8.7 Ne 6043 4198 4120 Yes 1870 8.7 OA 6146 4298 4220 Oil w/ oss. Free as 1800-1885 8.2 - 8.6 OBa 6209 4358 4280 Oil w/ poss. Free gas 1830-1910 8.2 - 8.6 OBb 6250 4398 4320 Oil w/ poss. Free gas 1930 8.6 OBc 6307 4453 4375 Oil w/ poss. Free gas 1955 8.6 OBd 6359 4503 4425 Oil w/ poss. Free gas 1885-1970 8.2-8.6 OBe 6421 4563 4485 Yes 2010 8.6 OBf 6473 4613 4535 Yes 2030 8.6 OBf_Base 6524 4663 4585 No 2050 8.6 T.D. 6671 4805 4726 L-213i Drilling Permit Page ~ • C~sing/Tubing Program: Hole Size Csg / Tb O.D. WUFt Grade Conn Burst si Collapse si Length Top MD /TVDrkb Bottom MD /TVDrkb 42" 20" 215.5# A-53 Welded 80' 29' / 29' 109' / 109' 12-'/a" 9-s/s" 40# L-80 BTC 5,750 3,090 3,647' 29' / 29' 3,676' / 2,678' 8-3/a" 7" 26# L-80 BTC-M 7,240 5,410 5,147' 29' / 29' 5,176' / 3,486' 8-3/a" 7" 26# L-80 TC II 7,240 5,410 1,495' 5,176' / 3,486' 6,671' 14,805' Tubin 4 ~h" 12.6# L-80 TC II 8,430 7,500 3' 29' / 29' 32' / 32' Tubin 3'/z" 9.30# L-80 TC II 10,160 10,530 6,394 32' / 32' 6,426' MD Mud Pro ram: 12'/a" Surface Hole Mud Properties: Spud -Freshwater Mud Interval Density Funnel Vis PV YP FL Chlorides PH 0-1,965' (Base Perm) 8.8 - 250-300+ 30-55 50-70 NC-8.0 <1000 9.0-9.5 1,965-3,675 (TD) 9. 9 225-250 30-55 45-60 8.0 <1000 9.0-9.5 8 3/a" Production Hole Mud Pr'6perties: ~ Freshwater LSND System Interval ~ Density ~ PV ~ YP ~ FL ~ pH ~ LGS % ~ MBT Surface shoe to TD 8.8 - 9.2 8-16 18-24 N/C 9-10 < 6.0 < 20 Survey and Logging Program: 12-'/a" Hole Section: Surface Gyro will be needed (run to 800' or as conditions dictate) O en Hole: MWD / GR Cased hole: None 8-3/a" Hole Section: O en Hole: MWD/ GR/ Res/ Den/ Neu/ PWD (real-time except for Den-Neu Recorded) Cased Hole: USIT (Follow Primary Depth Control Procedures) Surface and Anti-Collision Issues: Surface Shut-in Wells: Nearb Well L-03 L-1081 L-1051 L-106 L-107 Distance to L-213i 30.40 14.58 29.82 44.83 46.23 L-03, L-1081, & L-105i will require surface shut-in and wellhouse removal in order to move over well L-213i. L-106 & 107 may require surface shut-in and wellhouse removal in order to move over well L-213i. Close Approach Shut-in Wells: There are NO close approach wells requiring subsurface isolation for this profile. Hydrogen Sulfide: L Pad is not esignated as an H2S site, however Standard Operating Procedures for H2S precautions should be followed at all times. No measurable H2S is being produced from the formation at this time. However 5 to 30 ppm is measured regularly at both L and V pads as a result of the use of Ivishak gas lift gas. All L and V pad gas lift wells will likely have H2S in this concentration. Recent H2S data from the pad is as follows: Well Name H2S Level #1 Closest SHL Well H2S Level #2 Closest SHL Well H2S Level #1 Closest BHL Well H2S Level #2 Closest BHL Well H2S Level Max. Recorded H2S on Pad/Facility Faults: L-107 30 m 8/15/2005 L-106 5 m 10/16/2003 L-201 5 m 11 /14/2004 V-201 110 m 6/22/2004 L-107 30 m 8/15/2005 Fault #1 has been penetrated by nearly all previous L-Pad wells, with no drilling incidents. Fault #2 has been penetrated by more than 20 L-Pad wells, also with no drilling incidents. Lost circulation is considered a low to moderate risk; therefore loss circulation material should be on location as a precaution. Details are listed below for reference: Fault #1: 1176' MD 1153' TVD Fault #2: 5708' MD 3888' TVD -1075' TVDss Throw: -50' W -3810' TVDss Throw: -155' W L-213i Drilling Permit Page 4 Cement Calculations: Casin Size: 9 5/8-in 40-Ib/ft L-80 BTC - • Basis: Lead: 250% excess over gauge hole in permafrost, 30% excess over gauge hole below permafrost Lead TOC: Surface Tail: 500' TVD (963' MD) of open hole with 30% excess, plus 80' shoe track Tail TOC: 2,665' MD Total Cement Volume: Wash 20 bbls CW100 S acer 80 bbls of Viscosified er wei hted to 10.5 d Push II Lead 442 bbls, 2478 cult s 10.7 Class G C«3 .4 cuf k Tail 61 bbls, 341 cuff, sks 15.8 Class G + ad @ .1 cufUsk Durastone 15 bbls, 84 cuff, 7 s 16.3 Class G + adds + Durasto 1.18 cut Temp BHST = 60° F. BHCT 70° F estimated by Schlumberoer 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. Casin Size: 7" 26 Ib/ft L-80 BTC-M / TCII -Single Stage Basis: Lead: 599' of open hole with 30% excess. Lead TOC: 4,676' MD 1000' MD below Surface Casin Shoe Tail: 500' MD of open hole with 30% excess, plus 80' shoe track Tail TOC: 5,275' MD 500' above tanned Mato Total Cement Volume: Wash 30 bbls CW100 3 acer 30 bbls of Viscosifie acer Mud ush II Desi 10.3 Lead 22.5 bbls, 126 cuff sks 11.0 Ib/ al Crete cuft/sk Tail 52 bbls, 291 cuff, ks 15.8 Ib/ al G @ .1 cuft/sk Temp BHST = 95° F. B T 88° F estimated by lumberoer Centralizer Recommendations: 9 5/e" Casing Centralizer Placement a) Run (25) 9 5/8" Bow-spring centralizers attached over the collar of each joint of casing from the casing shoe up to 2,676' MD (1,000' MD above the shoe). b) Run 2 bow-spring centralizers on either side of the TAM Port Collar (if run). 7" String Centralizer Placement a) Place 2 rigid straight blade centralizers back to back at the very bottom of the shoe joint. Do not run any centralizers on the next two full joints. b) With the exception stated above, run two centralizers per joint, one floating across the bottom half of joint and one floating across the upper half of joint with locking collar in the middle of joint, up to 5,208' MD (500' MD above Ma sand). Zonal isolation with cement is required across the Ma, OA and OB sands. The centralizer program is subject to change pending modeling and hole conditions. Well Control: Well control equipment consisting of 5,000 psi working pressure pipe rams (2), blind/shear rams, and annular preventer will be installed and are capable of handling the maximum potential surface pressures. Based upon calculations below, BOP equipment will be tested to 4,000 psi. Due to Max Anticipated WHP not exceeding 3,000 psi it will not be necessary to have two sets of pipe rams installed at all times. BOP regular test frequency will be 14 days. Function test every 7 days. Below is an excerpt from the permit application requesting a variance to the requirements of 20 AAC 25.035 (e)(10)C PRIMARY DRILLING AND COMPLETION; 20 AAC 25.036 (d)(4) THROUGH TUBING DRILLING AND COMPLETION; 20 AAC 25.285 (f)(2) TUBING WORKOVERS: or, 20 AAC 25.286(e)(1) WORKSTRING SERVICE OPERATIONS "BPXA requests a variance to the provisions of 20 AAC 25.035 (e)(10)C regarding the function pressure test requirement after the use of BOP ram type equipment for other than well control or equivalent purposes, except when the routine use of BOP ram type equipment may have compromised their effectiveness. (Example would be when pipe rams are inadvertently closed on a tool joint during routine operations.) The activities associated with this request will not compromise the integrity of the BOP equipment." Diverter, BOPE and drilling fluid system schematics on file with the AOGCC. L-213i Drilling Permit Page • Production Section • Maximum anticipated BHP: • Maximum surface pressure: • Planned BOP test pressure: • 7" Casing Test: • Integrity Test - 8-3/4" hole: • Kick Tolerance: • Planned completion fluid: Disposal: • 2,138 psi - TD (8.7 ppg @ 4726' TVDss) 1,788 psi -Based on a full column of gas C«~ 0.10 psi/ft 4,000 psi/250 psi Rams 2,500 psi/250 psi Annular 4,000 psi /` 11.2 ppg minimum EMW LOT 20' from 9-5/8" shoe 52.6 bbls with an 11.2 ppg EMW LOT Estimated 9.0 ppg Brine (w/6.8 ppg Diesel freeze protect) • No annular injection in this well. • Cuttings Handling: Cuttings generated from drilling operations will be hauled to grind and inject at DS- 04. Any metal cuttings will be sent to the North Slope Borough. • Fluid Handling: Haul all drilling and completion fluids and other Class II wastes to DS-04 for injection. Haul all Class I waste to Pad 3 for disposal. L-213i Drilling Permit Page 6 • Drilling Hazards and Contingencies POST THIS NOTICE IN THE DOGHOUSE Well Control A. The Schrader in the Polygon 2 fault block is expected to be normal to sub-normally pressured at 8.2-8.7 ppg EMW. II. Hydrates and Shallow gas A. Gas Hydrates are present at L-pad and have been encountered in wells throughout the SV4, SV3, SV2, and SV1. Setting casing through the SV1 should keep hydrate exposure from extending past the surface hole. Recommended practices and precautions for drilling hydrates should be followed in the surface hole. Occasionally hydrates are encountered below the SVi . III. Lost Circulation/Breathing A. Lost circulation is not expected due to the benign nature of L Pad fault. • Note: Massive losses were encountered on L pad at L-118 due to high penetration rates (1100-1300 fph) and inadequate hole cleaning strategy. • While running production casing L-104 had losses with no returns. B. We do not expect breathing on this well. IV. Kick Tolerance/Integrity Testing A. The 9 5/8" casing will be cemented to surface. B. The 7" casing will be cemented with 15.8 Ib/g it cement to 500' MD above the Ma sand 5,275' MD. C. The Kick Tolerance for the surface casing i 52. bbls with 9.2ppg mud, 11.2 ppg LOT, and an 8.7 ppg pore pressure. - D. Integrity Testing Test Point Test De th Testa a EMW Ib/ al 9 5/8-in shoe 20-ft minimum from 9 5/8--in shoe LOT 11.2 minimum V. Stuck Pipe A. We do not expect stuck pipe if the hole is kept adequately clean. VI. Hydrogen Sulfide L Pad is no esignated as an H2S site, however Standard Operating Procedures for H2S precautions should be followed at all times. No measurable H2S is being produced from the formation at this time. However 5- 30 ppm is measured regularly at both L and V pads as a result of the use of Ivishak gas lift gas. All V and L pad gas lift wells will likely have H2S in this concentration. Note that all injection has been with produced water not seawater. H2S levels are expected to remain low until the waterflood matures. Recent H2S data from the pad is as follows: o Adjacent producers at Surface: o Adjacent producers at TD: L-107 30 ppm L-107 30 ppm L-106 5 ppm L-50 5 ppm VII. Faults A. Two faults are expected to be crossed. No losses are expected to be associated with these faults. Details are listed below for reference: Fault #1: 1176' MD 1153' TVD -1075' TVDss Throw: -50' W Fault #2: 5708' MD 3888' TVD -3810' TVDss Throw: -155' W VIII. Anti-Collision Issues All wells pass Major Risk criteria. Gyro will need to be run within 800' of surface or as conditions dictate for clean directional measurements due to the surface proximity to neighboring wellbores. CONSULT THE L-PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION L-2131 Drilling Permit Page 7 • • L-2131-Drill and Complete Procedure Summary Pre-Rig Work: 1. Weld an FMC landing ring for the FMC Gen 5 Wellhead on the conductor. 2. If necessary, level the pad and prepare location for rig move. 3. Prepare neighboring wells for the rig move and simops production. Shut in L-03, L-105i, L-1081 and remove well houses as necessary. The L-106 and L-107 may also need to be shut in and have their well houses removed. Rig Operations: / 1. MIRU Nabors 9ES. i 2. Nipple up diverter spool and function test diverter. PU 4" DP as required and stand back in derrick. 3. MU 12-~/a" drilling assembly with MW D/GR and directionally drill surface hole to base of permafrost and trip for a new bit. 4. RIH and drill the remainder of the surface hole to approximately 3,676' MD. The actual surface hole TD will be -100' ~ TVD below the top of the SVi sands. POOH and laydown BHA. 5. Run and cement the 9-5/d', 40.0-Ib/ft. surface casing back to surface. A TAM Port Collar may be run as a contingency. i 6. ND diverter spool and NU casing /tubing head. NU BOPE and test to 4,000 psi. 7. MU 8-3/a" drilling assembly with MWD/GR/Res/Den(recorded)/Neu(recorded)/PWD and RIH to float collar. Test the 9-5/8" casing to 3,500 psi for 30 minutes. r 8. Drill shoe track and displace over to new 8.8 ppg LSND mud. 9. Drill new formation to 20' below 9 5/e" shoe and perform LOT (Notify ODE if 11.2 ppg LOT is not obtained). 10. Drill ahead to Polygon 2 Target TD at 6,671 MD, (250' MD below Top OBe marker). 11. Circulate and condition hole, POOH to run casing. Perform wiper trip if hole conditions dictate. 12. Run and cement the 7" production casing. Note: Torque turn all 7" TC-II threaded casing. Displace the casing with i seawater during cementing operations. Pressure test casing to 4,000 psi for 30 minutes at plug bump. Freeze protect the 7" x 9 5/d' annulus. 13. PU DPC guns and RIH w/ --155' of 4.5" Power Jet 5 spf, pert guns (total assembly length to be -263') with Anadrill LWD GR for gun correlation. Tag PBTD. Circ hole over to 9.0 brine while correlating. 14. Space out utilizing GR and RA tags in 7" casing. Once correlated correctly, Gently tag TD and w/ guns on bottom, circ in pert pill. Pull back to shooting depth & confirm cement compressive strength is at least 2,000 psi. Perforate OA, OBa, OBb, OBc, and OBd. POOH standing DP back. 15. RU Schlumberger E-line. RIH with gauge ring and junk basket to recover any pert debris. Repeat until clean to at least 50' below the bottom perforation (OBd pert predicted 6,363'-6,408'). 16. Run USIT/GR log following Primary Depth Control procedures as USIT log will be primary depth control for future well f work. 17. Run the 3-'/z", L-80 TCI I completion with a 7" x 3-'/z" straddle packer assembly and injection mandrels. Torque turn TC-II threaded tubing. Note: Do not circulate inhibited brine down the backside yet. 18. Run in the lockdown screws and set the packers. Test the production casing/tubing annulus and tubing to 4,000 psi each. Shear the DCR shear valve and pump both ways to confirm circulation ability. 19. Install FMC TWC. Nipple down the BOPE. Nipple up and test the tree to 5,000 psi. 20. Freeze protect the well to 3,272 MD /2,500' TVD by first pumping corrosion inhibited brine down the IA with rig pumps followed by 115 bbls diesel down IA w/ Hot Oiler, taking clean brine returns to surface. Allow diesel to u-tube into tubing. 21. Install BPV in tubing hanger. Install a VR plug in the 7"x 3-'/z" annulus valve and secure the well. Assure that IA/OA are both protected with two barriers. 22. Rig down and move off. Post-Rig Work: 1. R/U Slickline and pull ball and rod / RHC from the tailpipe. 2. Replace the DCR shear valve with a dummy GLV. 3. Pull dummy valves in injection mandrels and replace with injection valves. 4. Pull VR plug. 5. Install wellhouse and flowlines. L-213i Drilling Permit Page 8 • • L-2131 Detailed Drilling Procedure Job 1: MIRU Critical Issues: - Ensure the starting head has been welded on the conductor at the right height and there is adequate space to NU the diverter and subsequently the BOP once the rig is spotted (Slot S-Q on L-Pad). Confirm this requirement prior to the rig moving over the well. Verify that the Diverter does not require any additional spacer spools as well. - Ensure the AOGCC receives 24-hour advance notification of the diverter test and all subsequent BOP tests. - L-03, L-108i, & L-105i will require surface shut-in and wellhouse removal before rig can be moved over the well. L-106 & 107 may also require surface shut-in and wellhouse removal. All surface flowlines and gas lift lines will need to be depressurized to header pressure. Discuss the move at a pre-job safety meeting and designate a spotter to ensure there is no danger of a collision. Nearb Well L-03 L-108i L-105i L-106 L-107 Distance to L-2131 30.40 14.58 29.82 44.83 46.23 Hydrogen Sulfide L Pad is not designated as an H2S site, however Standard Operating Procedures for H2S precautions should be followed at all times. No measurable H2S is being produced from the formation at this time. However 5 to 30 ppm is measured regularly at both L and V pads as a result of the use of Ivishak gas lift gas. All L and V pad gas lift wells will likely have H2S in this concentration. Recent H2S data from the pad is as follows: Well Name H2S Level #1 Closest SHL Well H2S Level #2 Closest SHL Well H2S Level #1 Closest BHL Well H2S Level #2 Closest BHL Well H2S Level Max. Recorded H2S on Pad/Facility Reference SOP: L-107 30 m 8/15/2005 L-106 5 m 10/16/2003 L-201 5 m 11 /14/2004 V-201 110 m 6/22/2004 L-107 30 m 8/15/2005 • "Drilling/ Work over Close Proximity Surface and Subsurface Wells Procedure Job 2: Drill 12'/a" Surface Hole Critical Issues: - At L-Pad, no significant surface hole drilling problems are present. Tight hole, bridging, and obstructions have been encountered while drilling the Permafrost and particularly at ± 900-1000'. In several wells reaming and tight hole have been present with a few examples of lost circulation while cementing. - Mud Temperature: Maintain the fluid temperature as low as possible (<60°F if possible). Use cold lake water whenever possible for additions or dilutions to keep the fluid temperature at a minimum. - Close Approach: L-03, L-1081 and L-105i will require shut in and have their wellhouses removed due to surface location proximity to the L-213i. L-106 & 107 may also require surface shut-in and wellhouse removal, but as long as cellar doors are able to close w/ these wells outside of the cellar, they can be brought back online after the rig moves on. There are NO close approach wells requiring subsurface isolation for this profile. A gyro should be run to 800' if conditions dictate. - Faults: One fault is expected to be crossed in the L-2131 surface section. No losses are expected to be associated with this fault. Details are listed below for reference: Fault 1 ("L" Pad Fault): 1176' MD 1153' TVD -1075' TVDss Throw: -50' W L-2131 Drilling Permit Page 9 r • - Directional: Every effort should be made to ensure a `smooth' well profile that will benefit torque / drag in the later hole sections and allow for easier 9 5/8" casing running. A graduated build profile is planned. It is preferred that DLS are not pushed ahead of plan on the surface hole, so as to minimize the chance for hole irregularity or obstructions that could cause problems while running casing. - Hole Cleaning: Good hole cleaning practices will be critical to the success of the well. Surface rotary speeds should be maximized wherever possible. The BHA is limited to 60 to 80-rpm while drilling because of the 1.83° motor bend. Vary flowrates 400-650 GPM to achieve the required directional response. However it will be possible at TD to raise the rotary speed to +100-rpm prior to POOH to run casing. At this time flowrates should be increased to 650 - 700 GPM to increase hole cleaning. Before pulling out of the hole for the final time, make sure that the hole is clean, full returns are observed, and that the pipe pulls without significant overpull. Lost circulation is possible while cementing if these conditions are not satisfied. - Premium Drill Pipe specs: Adjusted weight: 15.12 #/ft 4", 14#, HT-38, 'S-135' ID Colla se Burst Torsional Tensile 100% 3.34 13,800 psi 17,800 psi 32,800 Ibs 403,500 Ibs 80% 2.4375(tool joint) 11,040 psi 14,240 psi 26,240 Ibs 322,800 Ibs *""Max Recommended MU Torque: 19,800 ft-Ibs Fluid Capacity: 0.455 gal/ft *""Min Recommended MU Torque: 18,000 ft-Ibs Fluid Displacement: 0.210 gal/ft - Tight spots: During short trips, work out any tight spots as they are seen while pulling out of the hole instead of waiting and reaming them out after running back in the hole as this could lead to accidental sidetracking. Consider back-reaming across initial tight spots only if washing does not alleviate the problem. If tight spot is thought to be cuttings, run back in the hole at least the length of the BHA and circulate and condition the hole for a minimum of 30 minutes at max RPM's and GPM's. - Critical LWD Tools: It is critical for the landing of this hole section to have the GR to pick the base of the SVi sand. If this tool fails, it will require an immediate trip out of the hole to replace. It is imperative that the surface casing isolates all of the SVi sands. Reference RPs: • "Prudhoe Bay Directional Guidelines" • "Well Control Operations Station Bill" • Follow Schlumberger logging practices and recommendations Job 3: Run 9 5/8" Surface Casing Critical Issues: - Casing to bottom: It is imperative the casing is set in the shale below the SV1 sands to ensure wellbore integrity for the intermediate interval. Hydrates are prevalent on L-pad all the way into the SV1. It may be desirable to stop and roll the mud over half way in the hole to break the gels and reduce surging intensity on the SV sands. This will also help to ensure circulation is attained at TD at the desired cementing rates without losses. Make sure that the hole is clean and obstructions are minimized before running casing as higher doglegs and aggressive directional work could make casing running more difficult. - Casing drift: 9 5/e', 40# special drift casing is being used (8.835" ID, 8.75" drift). Ensure that casing equipment is properly drifted to ensure adequate ID for the 8-3/a" bit (float equipment, casing hanger, etc). - Franks Casing Fill-up tool: Make sure that a casing fill up tool is on location prior to PU 9-5/8" casing. - Cement to surface: A single-stage job will be done on this well using 250% excess in the permafrost and 30% excess below the permafrost. A TAM Port collar should be placed at 1,000-ft MD as a contingency, only if hole conditions warrant. - Losses during cement job: Lost circulation has been experienced on offset wells/pads while running and cementing surface casing on past wells. The expected frac gradient for the shale below the SV1 sands is at least 12.7-Ib/gal EMW. Follow the Schlumberger recommended pumping rates as they have modeled the expected ECD's during the entire cement job to help mitigate the potential for breaking down the formations. L-2131 Drilling Permit Page 10 • Reference RPs: • "Casing and Liner Running Procedure" • "Surface Casing and Cementing Guidelines" • "Surface Casing Port Collar Procedure" Job 4: Drill 8-3/a" Production Hole Critical Issues: - Differential Sticking could be a problem if lost circulation is occurring or if the drill string is left stationary for an extended period of time across the somewhat depleted/permeable Schrader Sands. - LOT: Perform an LOT after drilling 20' of new hole below the surface casing (minimum 11.2 ppg EMW to satisfy kick tolerance). KICK TOLERANCE: Based upon the max expected Ugnu/Schrader reservoir pressures of 8.7 ppg and 9.2 ppg mud, an 11.2 ppg leak-off will provide 52.6bbls of kick tolerance. Contact Anchorage personnel if LOT is less than 11.2 ppg. Based upon off-set drilling data, a minimum leak-off of 12.7 ppg is expected at the 9 5/8' shoe. - Penetration Rate: Penetration rates should not exceed 600 fph instantaneous. This should allow for ECDs not to exceed 0.6ppg above calculated. If ECDs are sustained above this threshold, it is advised that drilling should be stopped and the hole circulated before continuing. This should allow for ECDs not to exceed 0.8ppg above calculated. - Torque: Use lubricants as per the MI program as necessary. If weight transfer problems are encountered during sliding, attempt to circulate and rotate for a minimum of 2 BU to test if lubricants are truly needed or if the hole is loading up with cuttings. - Faults: We expect to cross only one fault with no losses in the 8-3/4" Production Hole section of L- 213i. As always, unexpected faults may be encountered. Follow LCM Decision Tree if losses persist. Details are listed below for reference: Fault 2: 5708' MD 3888' TVD -3810' TVDss Throw: -155' W - Screen Blinding: The Ugnu has been successfully drilled with minimal screen blinding by adding 1.0% ScreenKleen to the new fluid mixed at the mud plant to start drilling this section. It can also be added at the possum belly prior to drilling the Ugnu if additional concentrations are needed. It may be necessary to temporarily screen down on the shakers from 140 / 175 mesh to 84 / 110 mesh to control whole mud losses across the shakers while drilling the Ugnu. - Critical LWD Tools: It is critical to have the GR tool in order to pick the landing points for the production hole section. As mentioned above in the landing point discussion, the landing of this well depends on picking the base of the OBf and OBd sands using the Gamma Ray. Therefore if the GR tool is lost, a trip will have to be made to change it out. - Directional Constraints: It is important to keep the wellbore smooth and the tangent angle close to plan to facilitate casing running and slickline access. It is important to design a BHA to minimize inclination walking tendencies thus minimizing wellbore tortuousity. DLS should be kept as close as possible to <_1 ° over planned. Dogleg will take priority over angle as long as main bore tangent angle does not approach 68 degrees. - 7" casing landing point: The 7" casing setting point will be determined by depth based on changes in GR/Res curves associated with the top OBe marker. After seeing the top OBe, TD will be picked based on drilling 250' MD past this marker. This footage is critical for future well work. If tops are coming in 100' or more out from proposed, then conduct a short trip and notify town. A Rigsite Geologist will be required on site to pick casing point. - Premium Drill Pipe specs: Adjusted weight: 15.12 #/ft 4", 14#, HT-38, 'S-135' ID Colla se Burst Torsional Tensile 100% 3.34 13,800 psi 17,800 psi 32,800 Ibs 403,500 Ibs 80% 2.4375(tool joint) 11,040 psi 14,240 psi 26,240 Ibs 322,800 Ibs ***Max Recommended MU Torque: 19,800 ft-Ibs Fluid Capacity: 0.455 gaUft ***Min Recommended MU Torque: 18,000 ft-Ibs Fluid Displacement: 0.210 gal/ft L-2131 Drilling Permit Page 11 - Survey program per JORPS: Do le Severit Surve Fre uenc <1 °/100' 90' Eve stand, not exceedin 100' 1 ° - 5°/100' 90' Eve stand, not exceedin 100' >5°/100' 30' Eve 'oint Reference RPs: • Standard Operating Procedure for Leak-off and Formation Integrity Tests • Prudhoe Bay Directional Guidelines • Lubricants for Torque and Drag Management. • "ERD Operating Practices" Job 5: Run and Cement 7" Production Casing Critical Issues: - Tight hole, packing off and lost circulation have been experienced while running casing though this interval. Good hole cleaning, mud conditioning, and casing running practices are required for trouble free operations. - Cement Job: It is imperative to achieve a good cement job on this well to achieve zonal isolation and effective injection control. Therefore reciprocate pipe as long as possible while cementing. A USIT log will be run to confirm the quality of the cement job from above the Ma sand through the O sand perforations. Keep cementing ECD's below 12.7 ppg EMW during the displacement. - Freeze Protection: Ensure the lower production cement has reached at least a 500 psi compressive strength prior to freeze protecting. Freeze protect the 7" x 9 5/s" casing outer annulus with 83 bbls of deisel (2,936' MD, 2,500'TVD). Ensure adouble-barrier at the surface on the annulus exists until the cement has set up for at least 12 hours. Trapped annulus pressure may be present after pumping the deisel as the hydrostatic pressure of the mud and deisel could be underbalance by 254 psi to the open hole. - Centralization/Differential Sticking: See centralizer strategy in the Well Plan Summary. Differential Sticking could be a problem if lost circulation is occurring or if the casing is left stationary for an extended period or time across the permeable sands. Ensure the casing is centralized across any permeable zones if the casing is left stationary while running in the hole. - RA Tags: There will need to be 2 RA tags (2 pips each) placed in the 7" casing for depth control. Placement strategy is: o Pip #1: Top Ma Sand at 3,895' TVDss (5,803' MD) o Pip #2: 40-60' above top OA sand at 4,290' TVDss (6,213' MD) - Mud Requirements: Thin the mud as per MI's Mud Program. The thinner the mud the better displacement is achieved and the better the cement job will be. Extra time spent circulating is warranted to ensure optimum mud properties and hole cleaning prior to the cement job. - Franks Casing Fill-up tool: Make sure that a casing fill up tool is on location prior to PU 7" casing. - TIW Valve: Ensure that a TIW valve with a cross over to 7" BTC-M casing is on the rig floor before running casing. Reference RPs: • "Intermediate Casing and Cementing Guidelines" • "Freeze Protecting an Outer Annulus" L-213i Drilling Permit Page 12 Job 6: DPC Perforate Well • Critical Issues: - Barriers: While running DPC guns the well will contain kill weight fluid and BOPs will be in place. After perforating, up to freeze protecting this will be adequate to provide two barriers. - The well will be perforated ±95 psi over-balanced using the 9.0 ppg brine as currently planned. Ensure all personnel are well briefed on Schlumberger's perforating procedures and that all responsibilities are understood. - It should be stressed that while picking up and running the perforating string, only essential personnel should be on the rig floor. Normally "essential personnel" will consist of the driller, floor hands, Schlumberger perforating crew. All other personnel will stay off the rig floor and out of the cellar until the perforating string is at least 200-ft below the rotary table. - Contact Schlumberger to prepare for approximately 155' of 4-1/2" Power Jet guns at 5 spf to be run on DP. Exact perforation depths will be provided after reviewing all log data. - Be prepared for fluid losses to the formation after perforating. Have ample seawater and brine on location and be prepared with LCM if necessary. Losses are not expected to be severe based on past perforation jobs. It is expected that the formation will take some fluid after the initial perforating due to the extra pressure induced by the detonation of the perf guns. Major brine loss is not expected to be a problem. - It is planned to utilize LWD GR to correlate to the formation and casing RA tags to position the perforation assembly. The GR tool will be placed above the perforating assembly, the assembly is then RIH past the pert depth, the well will be logged up to correlate DP depth, and then the guns can be brought on depth and fired. (NOTE: The 4-3/4" LWD GR tool requires a 175-350 gpm flowrate to establish a signal.) Reference RPs: • "Alaska Wells Group Standard Operating Procedure: Perforating" • Follow Schlumberger perforating practices and recommendations Job 7: Run 3-'h" Completion Critical Issues: - Barriers: o The well will have OA, OBa, OBb, OBc and OBd intervals open with an 8.2-8.7 ppg EMW formation pressure during completion operations. o Completion will be run with BOPs in place and kill weight fluid (9.0 ppg brine) for annulus side barriers. Tubing side barriers will be provided via TIW and kill weight fluid. o Once packers are set the annulus above the packer will be tested to 4,000 psi to verify packer/annulus integrity. Kill weight fluid and the tubing hanger provide additional annulus side barriers. At this point the ball and rod with kill weight fluid and a TIW valve comprise the tubing side barriers. o Since it is not feasible to test the lower packer/annulus integrity, when the DCR valve is sheared a casing annulus valve must be in place along with kill weight fluid to provide sufficient annular barriers. Tubing side barriers are still kill weight fluid on ball and rod and a TIW. o A TWC will be installed and tested from above to 1,000 psi for 30 minutes prior to nippling down the BOP's. With the DCR valve sheared the TWC in addition to kill weight fluid provide the tubing side barrier. The annular side barrier is the casing annulus valve and the kill weight fluid. With the TWC in place BOPs can be nippled down and the tree nippled up. o With the tree nippled up freeze protecting removes the kill weight fluid as a barrier. We then count on the tree for tubing side barriers, and two casing annulus valves for annulus side protection. o Before rigging down, a BPV tested from below to 1,000 psi will be left in the tubing hanger to provide an additional tubing side barrier once the rig is off. Since the DCR valve is still open it will be necessary to leave one casing annulus valve and a VR plug for annular barriers. Make sure that a lubricator is used to install the VR plug while both casing annulus valves are still in place. L-2131 Drilling Permit Page 13 r~ I~ - Thread Dope: Jet Lube is the BP approved thread compound for Premium Carbon API connections. All TCII pipe should arrive on location with Jet Lube thread compound. It would still be good practice to look over each connection in the pipe shed prior to incorporating them into the tally. - Torque Turn: Injectors will be used for MI injection and therefore must have all premium connections torque turned and charted to help reduce risk of leaks. - Shear Valve: We will be using a DCR shear valve due to the RP shear valve failure on numerous wells. The DCR shear valve has had good success due to the locking mechanism that keeps the sleeve from migrating back down over the ports after the tool is sheared open. This valve does require a higher differential pressure to open. - Injection Mandrels: Remove the check valves from the MMG-W waterflood mandrels. This will allow us the flexibility to circulate between mandrels and clean up the tubing/casing annulus later in the well life. This should be done before the mandrels are sent to .the wellsite and is a fairly standard practice. It would certainly be good to verify prior to RIH w/the completion. Reference RPs: • "Completion Design and Running" RP • "Tubing Connections" RP • Follow Schlumberger perforating practices and recommendations Job 8: ND/NU/Release Rig Critical Issues: - See Job 1 for adjacent well spacing. Identify hazards in a pre-move meeting, and take every precaution to ensure good communication prior to beginning the rig move. Use spotters when moving the rig. - Diesel: Diesel will be used to freeze protect the well. The diesel flash point is 100° F. Diesel vapor pressure is ~ 0.1 psia at 100° F. - Leo Valve: Be sure the tree is equipped with a Leo Surface Safety Valve before accepting it and hanging it in the cellar. Reference RPs: • "Freeze Protecting an Inner Annulus" RP L-213i Drilling Permit Page 14 ~L-213i Target Ar Top OA Structure Pa `~"-: L-108i -~ Wool- o~ _ . . ~L-103 ~-. ~- 0'-90' Displ. -- ~~ { ~ Fault j -.~~. L-214Ai L_~ .1 .. ., ~ .. :. ... ._. .J ~J ..rC_.. • ~ ~ ~ ~~ -G~ I ~ ^ • L-2131 ..~ _, ~_ 4 ~. !.. 3 - ~ ~- ~._ -210 4 I ~~~ ~~ ~ c ~ 160'-170' Displ. p~ Fault N ., ~, 0 -214i ~ o Prop.) WKU ~T-0 ~ ~'~~ ' ~ ... ~„ - -211 i ,~,~P~ Structure Contours on top Schrader Bluff OA Sand ~,~ Faults which offset top Schrader Bluff OA Sand ~~~ Existing Multilateral Production Wells 1/4 Mile Radius Circle ~ L-2131 Target Location ~ Existing Stand alone Orion Injection Well 0 Existing Commingled Orion/Borealis Injection Well Variance Request Issue • Compliance with AOGCC testing requirements for BOP rams after they have been used in the normal coarse of operations. Request The AOGCC is in the process of developing a guideline document clarifing the intent of the regulations pertaining to function pressure testing ram type BOP's. BPXA requests a variance to the provisions of 20 AAC 25.035 (e)(10)C regarding the function pressure test requirement after the use of BOP ram type equipment for other than well control or equivalent purposes, except when the routine use of BOP ram type equipment may have compromised their effectiveness. (Example would be when pipe rams are inadvertently closed on a tool joint during routine operations.) The activities associated with this request will not compromise the integrity of the BOP equipment. Background AOGCC regulations require rams that have been used in the course of primary drilling & completion, workover and through tubing drilling operations be function pressure tested before the next wellbore entry. This is not a new regulation. The intent of this regulation is to ensure that ram type equipment has integrity after it has been utilized in a wellbore..~.for example; to ensure integrity if a ram was closed on a tool joint. The exact regulation language is: "if BOP sealing ram type equipment has been used, it must be function pressure-tested, before the next wellbore entry, to the required working pressure specifiied in the approved Permit to Drill, using anon-compressible fluid, except that an annular type preventer need not be tested to more than 50 percent of its rated working pressure;" The pertinent sections are: 20 AAC 25.035 (e)(10)C PRIMARY DRILLING- AND COMPLETION; 20 AAC 25.036 (d)(4) THROUGH TUBING DRILLING AND COMPLETION; 20 AAC 25.285 (f)(2) TUBING WORKOVERS: 20 AAC 25.286(e)(1) WORKSTRING SERVICE OPERATIONS This issue has been discussed with Winton Aubert at the AOGCC. The test requirement in the regulation is intended to apply to ram type equipment only. The AOGCC understands that ram type BOP's are utilized for purposes other than well control in the normal coarse of operations. The regulations allowing a variance are at 20 AAC 25.035(h) PRIMARY DRILLING AND COMPLETION; 20 AAC 25.036(f) THROUGH TUBING DRILLING AND COMPLETION; 20 AAC 25.285(h) TUBING WORKOVERS; 20 AAC 25.286(g) WORKSTRING SERVICE OPERATIONS...which says generally: 20 AAC 25.035(h)... Upon request of the operator, the commission will, in its discretion, approve a variance (i) from the BOPS requirements in (e) of this section if the variance provides at least an equally effiec#ive means of well control; Cellar Elevation = 49.4' Nabors 9ES RKB =T7.9 4-112", 12.6 Ib/ft, L-80, 1 Drift / ID : 3.833"/3.958" 4-12" X 3-12° TCII XO 3-1/2", 9.3 Ib/ft, L-80, T( Drift / ID : 2.867"/2.992" 7' Short Joint 8 RA Tag Top Ma sand (5,775') 7' Short Joint 8 RA Tag Above Top OA (6,100') RA Tag in 3-1 /2" (6157`) TREE~FMC 41/16' SM WELLHEAD: FMC Gen 5 Sysaem 11 ", 5M csg.head w/ 7" mandrel hanger ~ packoff 11' x 11', SM, m9 spool w/ 11' x 41 /2' tubing hanger 11' X 4-1 /1 S` Adaptor Flange 20" X 34' 215.5 Ib/ft, 109' A53 ERW Insulated 270` 3-12" 'X' Landing Nipple with 2.813" seal bore. 676' 9-5/8", 40 #/ft, L-80, BTC 676` Proposed Top of Cement 176` TCII above and IBT-mod bek~nr D23` Camco 3-1/2" x 1-1/2" MMG GLM D96` 3-112" 'X' Landing Nipple with 2.813" seal bore. 112' 7" x 3-1/2" Baker `PRM' Production Packer 131` Camco 3-1/2" x 1-1/2" MMG-W GLM OA sand Perfs: 6,190`-6,145' and 180` Camco 3-1/2" x 1-112" MMG-W GLM 203` 7" x 3-1/2" Baker `PRM' Production Packer 223` Camco 3-1/2" x 1-1/2" MMG-W GLM OBa & OBb sand Perfs: 6,247`-6,212' 8 6,269`-6,254' 261' Camco 3-1/2" x 1-1/2" MMG-W GLM 285` 7" x 3-1/2" Baker `PRM' Production Packer 299` Camco 3-1/2" x 1-1/2" MMG-W GLM OBc sand Perfs: 6,326`-6,311' and 328` Camco 3-1/2" x 1-1/2" MMG-W GLM 351` 7" x 3-1/2" Baker `PRM' Production Packer 370` 399` 420` 426` 571` _, 571 ` Date Rev By Comments 3/14/06 RLP Proposed Completion wp1 Camco 3-1/2" x 1-1/2" MMG-W GLM 3-1/2" `X' Landing Nipple with 2.813" seal bore. 3-112" 'X' Landing Nipple with 2.813" seal gore. 3-1/2" WireLine Entry Guide OBd sand Perfs: 6,408`-6,363' and T', PBTD 7", 26 #fft, L80, ~2~ t'dtPl~~`t1r11~Icr' ~d WELL: L-2131 API NO: 50-029-xxxxx Z-213i Proposed by Schlurnberger L-213 (P3) Pro posal Report Date: February 7, 2006 Survey 1 DLS Computation Method: Minimum Curvature / Lubinski Client: BP Exploration Alaska Vertical Section Azimuth: 111.250° Field: Structure 1 Slot: Prudhoe Bay Unit - WOA L-PAD / L-213 ~® Vertical Section Origin: N 0.000 ft, W 0.000 ft 'O TVD Reference Datum: Rotary Table Well: ~ ® Plan L-213 (S-CZ) TVD Reference Elevation: 78.10 ft relative to MSL Borehole: ~ Plan L-213 ~ ~r®~ Sea Bed I Ground Level Elevation: 49.60 ft relative to MSL UWIIAPI#: ~ 50029 Magnetic Declination: 24.251 ° Survey Name 1 Date: L-213 (P3) I February 7, 2006 Total Field Strength: 57579.041 nT Tort 1 AHD I DDI 1 ERD ratio: 102.173° 13986.86 ft / 5.752 10.830 Magnetic Dip: 80.855° Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feel Declination Date: April 25, 2006 Location LaULong: N 70.35022064, W 149.32358380 Magnetic Declination Model: BGGM 2005 Location Grid NIE YIX: N 5978131.650 ftUS, E 583314.080 ftUS North Reference: True North Grid Convergence Angle: +0.63702889° Total Corr Mag North •> True North: +24.251 ° Grid Scale Factor. 0.99990789 Local Coordinates Referenced To: Well Head • Measured Vertical Comments Inclination Azimuth Sub•Sea TVD TVD NS EW DLS Tool Face Build Rate Walk Rate Northing Easting Latitude Longitude Depth Section ft de de ft ft ft ft ft de 1100 ft de de 100 ft de 1100 ft ftUS ftUS RIC ~.vU U.UU IwU.UU -i o.iU U.UU U.UU U.UU U.UU U.UU IwU.UUIVI U.UU U.UU D`J/BI JI AO D83314.U0 N/U.3bUZZUb4 VV "14y.3Z30253iSV KOP Bld 1.5/100 300.00 0.00 140.00 221.90 300.00 0.00 0.00 0.00 0.00 140.OOM 0.00 0.00 5978131.65 583314.08 N 70.35022064 W 149.32358380 G1 333.10 0.50 140.00 255.00 333.10 0.13 -0.11 0.09 1.50 140.OOM 1.50 0.00 5978131.54 583314.17 N 70.35022034 W 149.32358306 Crv 2.5/100 400.00 1.50 140.00 321.89 399.99 1.15 -1.00 0.84 1.50 128.99M 1.50 0.00 5978130.66 583314.93 N 70.35021791 W 149.32357697 500.00 3.96 128.99 421.77 499.87 5.58 -4.18 4.36 2.50 126.44M 2.46 -11.01 5978127.52 583318.49 N 70.35020924 W 149.32354838 600.00 6.45 126.44 521.35 599.45 14.29 -9.68 11.56 2.50 -4.04G 2.49 -2.55 5978122.10 583325.75 N 70.35019419 W 149.32348995 700.00 8.94 125.31 620.44 698.54 27.24 -17.51 22.42 2.50 -2.92G 2.50 -1.13 5978114.39 583336.69 N 70.35017281 W 149.32340180 Crv 3.5/100 742.39 10.00 125.00 662.26 740.36 34.01 -21.53 28.12 2.50 -16.40G 2.50 -0.73 5978110.44 583342.44 N 70.35016184 W 149.32335549 800.00 11.95 122.25 718.81 796.91 44.73 -27.58 37.27 3.50 -13.70G 3.38 -4.77 5978104.49 583351.65 N 70.35014531 W 149.32328129 900.00 15.37 119.12 815.97 894.07 68.02 -39.55 57.60 3.50 -10.66G 3.42 -3.13 5978092.74 583372.11 N 70.35011259 W 149.32311619 SV6 961.55 17.49 117.80 875.00 953.10 85.29 -47.84 72.91 3.50 -9.39G 3.45 -2.15 5978084.63 583387.51 N 70.35008995 W 149.32 1000.00 18.82 117.12 911.53 989.63 97.20 -53.36 83.55 3.50 -8.74G 3.46 -1.77 5978079.23 583398.21 2 N 70.35007487 W 149.322 1100.00 22.29 115.71 1005.15 1083.25 132.17 -68.94 115.00 3.50 -7.43G 3.47 -1.40 5978064.00 583429.82 N 70.35003229 W 149.32265029 Fault Crossing 1176.23 24.93 114.90 1075.00 1153.10 162.62 -81.98 142.60 3.50 -6.68G 3.47 -1.07 5978051.26 583457.57 N 70.34999667 W 149.32242620 1200.00 25.76 114.67 1096.48 1174.58 172.77 -86.25 151.84 3.50 -6.48G 3.48 -0.94 5978047.10 583466.85 N 70.34998502 W 149.32235122 1300.00 29.24 113.87 1185.17 1263.27 218.88 -105.21 193.93 3.50 -5.76G 3.48 -0.81 5978028.61 583509.15 N 70.34993322 W 149.32200950 1400.00 32.72 113.22 1270.89 1348.99 270.31 -125.75 241.12 3.50 -5.20G 3.48 -0.65 5978008.60 583556.56 N 70.34987709 W 149.32162642 1500.00 36.21 112.68 1353.32 1431.42 326.87 -147.80 293.24 3.50 -4.76G 3.49 -0.54 5977987.13 583608.91 N 70.34981684 W 149.32120340 1600.00 39.70 112.23 1432.15 1510.25 388.35 -171.28 350.07 3.50 -4.40G 3.49 -0.45 5977964.29 583666.00 N 70.34975270 W 149.32074201 SV5 1649.82 41.44 112.02 1470.00 1548.10 420.75 -183.48 380.09 3.50 -4.25G 3.49 -0.41 5977952.42 583696.15 N 70.34971935 W 149.32049834 1700.00 43.19 111.83 1507.10 1585.20 454.52 -196.10 411.42 3.50 -4.11 G 3.49 -0.38 5977940.16 583727.62 N 70.34968489 W 149.32024399 1800.00 46.68 111.49 1577.88 1655.98 525.14 -222.16 477.06 3.50 -3.86G 3.49 -0.34 5977914.83 583793.54 N 70.34961368 W 149.31971119 SV4 1840.05 48.08 111.36 1605.00 1683.10 554.62 -232.93 504.50 3.50 -3.78G 3.49 -0.32 5977904.37 583821.09 N 70.34958427 W 149.31948847 WeIlDesign Ver SP 1.0 Bld( doc40x_56) L-213\Plan L-213 (S-O)\Plan L-213\L-213 (P3) Generated 2/7/2006 3:04 PM Page 1 of 3 Measured Vertical Comments Inclination Azimuth Sub-Sea TVD Typ NS EW DLS Tool Face Build Rate Walk Rate Northing Easting Latitude Longitude Depth Section ft de de ft ft ft k ft de 1100 ft de de 1100 ft de 100 ft ftUS ftUS IyUU .UV OU . I / I I I . 10 1044.GG I /GG .3G byy.y4 -G4y .3/ b40 .l4 3.bV -3.bOb 3.4y -U.3U by/ /88b.4U 083803.bU IV lU.34yb3y34 VV -14y.31y~14bOV End Crv 1913 .77 50 .66 111 .14 1653.00 1731 .10 610.56 -253 .20 556 .63 3.50 O.OOG 3.49 -0.29 5977884.68 583873.44 N 70.34952887 W 149.31906525 Base Perm 1964. 25 50. 66 111. 14 1685.00 1763. 10 649.59 -267. 28 593. 04 0.00 O.OOG 0.00 0.00 5977871.00 583910.00 N 70.34949040 W 149.31876972 Crv 3.5/100 2013 .77 50 .66 111 .14 1716.40 1794 .50 687.89 -281 .09 628 .76 0.00 -3.07G 0.00 0.00 5977857.59 583945.87 N 70.34945265 W 149.31847975 2100 .00 53 .67 110 .94 1769.29 1847 .39 755.98 -305 .54 692 .32 3.50 -2.95G 3.50 -0.23 5977833.85 584009.68 N 70.34938585 W 149.31796388 2200 .00 57 .17 110 .73 1826.04 1904 .14 838.30 -334 .82 769 .25 3.50 -2.83G 3.50 -0.21 5977805.44 584086.93 N 70.34930585 W 149.31733937 End Crv 2234 .76 58 .38 110 .66 1844.57 1922 .67 867.70 -345 .20 796 .76 3.50 O.OOG 3.50 -0.20 5977795.36 584114.55 N 70.34927746 W 149.31711610 SV3 2502. 61 58. 38 110. 66 1985.00 2063. 10 1095.77 -425. 67 1010. 18 0.00 O.OOG 0.00 0.00 5977717.28 584328.83 N 70.34905758 W 149.31538374 SV2 2826. 86 58. 38 110. 66 2155.00 2233. 10 1371.87 -523. 07 1268. 54 0.00 O.OOG 0.00 0.00 5977622.76 584588.24 N 70.34879137 W 149.31328661 SV1 3484. 90 58. 38 110. 66 2500.00 2578. 10 1932.20 -720. 75 1792. 87 0.00 O.OOG 0.00 0.00 5977430.95 585114.69 N 70.34825104 W 149.309 5 9-5/8" Csg Pt 3675. 64 58. 38 110. 66 2600.00 2678. 10 2094.61 -778. 05 1944. 85 0.00 O.OOG 0.00 0.00 5977375.35 585267.28 N 70.34809441 W 149.30 UG4 4095. 26 58. 38 110. 66 2820.00 2898. 10 2451.92 -904. 10 2279. 21 0.00 O.OOG 0.00 0.00 5977253.03 585602.98 N 70.34774978 W 149.30 7 UG4A 4152. 48 58. 38 110. 66 2850.00 2928. 10 2500.64 -921. 29 2324. 80 0.00 O.OOG 0.00 0.00 5977236.35 585648.76 N 70.34770278 W 149.30471364 UG3 4886. 82 58. 38 110. 66 3235.00 3313. 10 3125.93 -1141. 88 2909. 92 0.00 O.OOG 0.00 0.00 5977022.29 586236.24 N 70.34709958 W 149.29996497 Drp 4/100 4961 .95 58 .38 110 .66 3274.39 3352 .49 3189.91 -1164 .45 2969 .79 0.00 -180.OOG 0.00 0.00 5977000.39 586296.35 N 70.34703786 W 149.29947914 5000 .00 56 .86 110 .66 3294.76 3372 .86 3222.03 -1175 .79 2999 .85 4.00 -180.OOG -4.00 0.00 5976989.39 586326.53 N 70.34700686 W 149.29923516 5100 .00 52 .86 110 .66 3352.31 3430 .41 3303.79 -1204 .63 3076 .35 4.00 -180.OOG -4.00 0.00 5976961.41 586403.34 N 70.34692799 W 149.29861433 5200 .00 48 .86 110 .66 3415.42 3493 .52 3381.32 -1231 .98 3148 .91 4.00 -180.OOG -4.00 0.00 5976934.87 586476.19 N 70.34685318 W 149.29802550 5300. 00 44 .86 110 .66 3483.79 3561 .89 3454.27 -1257 .72 3217 .17 4.00 -180.OOG -4.00 0.00 5976909.89 586544.73 N 70.34678279 W 149.29747154 5400 .00 40 .86 110 .66 3557.08 3635 .18 3522.27 -1281 .71 3280 .80 4.00 -180.OOG -4.00 0.00 5976886.62 586608.62 N 70.34671718 W 149.29695515 5500 .00 36 .86 110 .66 3634.93 3713 .03 3585.00 -1303 .83 3339 .50 4.00 -180.OOG -4.00 0.00 5976865.15 586667.55 N 70.34665666 W 149.29647883 UG1 5573. 68 33. 91 110. 65 3695.00 3773. 10 3627.66 -1318. 88 3379. 42 4.00 -180.OOG -4.00 0.00 5976850.54 586707.63 N 70.34661550 W 149.29615488 5600 .00 32 .86 110 .65 3716.97 3795 .07 3642.14 -1323 .99 3392 .97 4.00 -180.OOG -4.00 0.00 5976845.59 586721.24 N 70.34660153 W 149.29604492 5700. 00 28 .86 110 .65 3802.80 3880 .90 3693.42 -1342 .08 3440 .95 4.00 -180.OOG -4.00 0.00 5976828.03 586769.42 N 70.34655205 W 149.29565551 Fault Crossing 5708. 21 28. 53 110. 65 3810.00 3888. 10 3697.36 -1343. 47 3444. 64 4.00 O.OOG -4.00 0.00 5976826.69 586773.12 N 70.34654825 W 149.29562559 Ma 5708. 22 28. 53 110. 65 3810.01 3888. 11 3697.36 -1343. 47 3444. 65 4.00 -180.OOG -4.00 0.00 5976826.68 586773.12 N 70.34654825 W 149.29562555 Mb1 5725. 23 27. 85 110. 65 3825.00 3903. 10 3705.40 -1346. 30 3452. 16 4.00 -180.OOG -4.00 0.00 5976823.93 586780.67 N 70.34654050 W 149.29556455 5800. 00 24 .86 110 .65 3892.00 3970 .10 3738.58 -1358. 01 3483 .22 4.00 -180.OOG -4.00 0.00 5976812.57 586811.85 N 70.34650848 W 149.2953 Mb2 5803. 31 24. 73 110. 65 3895.00 3973. 10 3739.97 -1358. 50 3484. 52 4.00 -180.OOG -4.00 0.00 5976812.10 586813.16 N 70.34650714 W 149.295 Mc 5895. 58 21. 03 110. 65 3980.00 4058. 10 3775.84 -1371. 15 3518. 08 4.00 -180.OOG -4.00 0.00 5976799.82 586846.86 N 70.34647253 W 149.295 5900 .00 20 .86 110 .65 3984.12 4062 .22 3777.42 -1371. 71 3519 .56 4.00 -180.OOG -4.00 0.00 5976799.28 586848.34 N 70.34647101 W 149.29501761 Na 5969. 87 18. 06 110. 65 4050.00 4128. 10 3800.69 -1379. 92 3541. 34 4.00 -180.OOG -4.00 0.00 5976791.32 586870.21 N 70.34644855 W 149.29484086 6000 .00 16 .86 110 .65 4078.74 4156 .84 3809.73 -1383. 11 3549 .80 4.00 -180.OOG -4.00 0.00 5976788.22 586878.70 N 70.34643983 \N 149.29477222 Nb 6001. 32 16. 81 110. 65 4080.00 4158. 10 3810.11 -1383. 24 3550. 16 4.00 -180.OOG -4.00 0.00 5976788.09 586879.06 N 70.34643946 W 149.29476932 Nc 6032. 56 15. 56 110. 65 4110.00 4188. 10 3818.82 -1386. 31 3558. 30 4.00 -180.OOG -4.00 0.00 5976785.11 586887.24 N 70.34643107 W 149.29470322 Ne 6042. 93 15. 14 110. 65 4120.00 4198. 10 3821.56 -1387. 28 3560. 87 4.00 -180.OOG -4.00 0.00 5976784.17 586889.82 N 70.34642842 W 149.29468237 End Drp 6046. 46 15 .00 110 .65 4123.41 4201 .51 3822.48 -1387. 60 3561 .73 4.00 O.OOG -4.00 0.00 5976783.86 586890.68 N 70.34642753 W 149.29467541 L-213 Tgt 1 6146. 46 15 .00 110 .65 4220.00 4298 .10 3848.36 -1396. 73 3585 .95 0.00 O.OOG 0.00 0.00 5976775.00 586915.00 N 70.34640257 W 149.29447887 OA 6146. 47 15. 00 110. 65 4220.01 4298. 11 3848.36 -1396. 73 3585. 95 0.00 O.OOG 0.00 0.00 5976775.00 586915.00 N 70.34640256 W 149.29447885 OBa 6208. 57 15. 00 110. 65 4280.00 4358. 10 3864.44 -1402. 40 3600. 99 0.00 O.OOG 0.00 0.00 5976769.50 586930.10 N 70.34638706 W 149.29435679 OBb 6249. 98 15. 00 110. 65 4320.00 4398. 10 3875.16 -1406. 18 3611. 02 0.00 O.OOG 0.00 0.00 5976765.83 586940.17 N 70.34637672 W 149.29427540 WeIlDesign Ver SP 1.0 Bld( doc40x_56) L-213\Plan L-213 (S-Q)\Plan L-213\L-213 (P3) Generated 2/7/2006 3:04 PM Page 2 of 3 Measured Vertical Comments inclination Azimuth SulrSea TVD TVD NS EW DLS Tool Face Build Rate Walk Rate Northing Easting Latitude Longitude Depth Section ft de de ft ft ft ft ft de 1100 ft d de 100 ft de 1100 ft ftUS ftUS VOG OJVO..YC IO.VU 7IU.OJ 4J/.7.VU 44U3.IV 36O`J.UJ -7477. JiS JOZ4.S7 U.UU U.UUh V.VU V.UV D`J/O/bV./J btlb!lD4.UL IV /V.J4bJtlZbU W 14`J.Zy47bJ4'J OBd 6358.69 15.00 110.65 4425.00 4503.10 3903.29 -1416.10 3637.35 0.00 O.OOG 0.00 0.00 5976756.21 586966.61 N 70.34634958 W 149.29406176 6420.80 15.00 110.65 4485.00 4563.10 3919.36 -1421.77 3652.39 0.00 O.OOG 0.00 0.00 5976750.70 586981.71 N 70.34633407 W 149.29393968 OBe 6420.82 15.00 110.65 4485.01 4563.11 3919.37 -1421.77 3652.40 0.00 O.OOG 0.00 0.00 5976750.70 586981.71 N 70.34633407 W 149.29393966 Oef 6472.57 15.00 110.65 4535.00 4613.10 3932.76 -1426.50 3664.93 0.00 O.OOG 0.00 0.00 5976746.12 586994.30 N 70.34632114 W 149.29383795 OBf Base 6524.33 15.00 110.65 4585.00 4663.10 3946.16 -1431.22 3677.47 0.00 O.OOG 0.00 0.00 5976741.53 587006.89 N 70.34630822 W 149.29373621 6670.72 15.00 110.65 4726.40 4804.50 3984.04 -1444.58 3712.92 0.00 O.OOG 0.00 0.00 5976728.57 587042.48 N 70.34627167 W 149.29344851 TD / 7" Csg 6670.80 15.00 110.65 4726.48 4804.58 3984.07 -1444.59 3712.94 0.00 O.OOG 0.00 0.00 5976728.56 587042.50 N 70.34627165 W 149.29344835 Legal Descriotion: Northi ng (Y) [ftUS] Easting (X) [ftUS] Surface : 2408 FSL 3602 FEL S34 T12N R11E UM 5978131.65 583314.08 L-213 Tgt 1 : 1011 FSL 19 FEL S34 T12N R11 E UM 5976775.00 586915.00 BHL : 963 FSL 5172 FEL S35 T12N R11 E UM 5976728.56 587042.50 • WeIlDesign Ver SP 1.0 Bld( doc40x_56) L-213\Plan L-213 (S-Q)\Plan L-213\L-213 (P3) Generated 2/7/2006 3:04 PM Page 3 of 3 • by • Schlum6erger WELL L-213 (P3) FIELD Prudhoe Bay Unit - WOA STRDCTDRE L-PAD MagmlK Parameters Su9ace Loulron NAD2] Ma Siaie Planes. Zone G US Feel p hlisrellmeous Model BGGM 2Ml5 Dip 90855' Date Aynl 2'v 2006 N102~019d NmNng 59 ]9'l fiS RllS Gnd GOnv -0 e3102999' Slot L~211 NO ReI. Rotary TaUle x]0101 aDOVe MSL) Mag Dec'. rZd.251' FS 525I90nT Lon. Wtd9192d.902 EasUrg S919'd C91US Scala Fact 099990]8951 flan. L~2t3lP9l Srvy Date. Feduary 0]. 2009 0 800 1600 2400 3200 4000 0 800 1600 x 0 0 a0 2400 c a~ m U 3200 4000 4800 ro ~ r• csg 0 800 1600 2400 3200 4000 4800 0 800 1600 2400 3200 4000 Vertical Section (ft) Azim = 111.25°, Scale = 1(in):800(ft) Origin = 1.25344e-005 N/-S, -1.64599e-005 E/-V by Schlumberger WELL L-213 (P3) FIELD Prudhoe Bay Unit - WOA STRUCTURE L-PAD Maynetx: Parameters En~a~.u L~>ivliun NA01/Alaska Stale Panns. Zonn OJ. US Feel M1I151:tlINlleulle Motlel BGGM 2005 Dip. 80.855° Dde: Apn12S.2W6 .~ /021 (1 /9a NM6my. 19]613161 M1US Grq Conv ~06J 102889' Slur ~21J ND Rar. Mary Ta0k (]B.tOfl a0eve MSLI Mag Dec. ~I<111• FS'. 1]5 ]9.0 nT Wt~5153a.902 Eas6riy 5flJJ la O6 lIU5 Srale Fxt 099950]8851 Plan L-21J (PJI Srry Dale Febuary 0],2W6 0 500 1000 1500 2000 2500 3000 3500 0 n n n Z -500 0 0 c m m U N -1000 v v v -1500 0 -500 -1000 -1500 0 500 1000 1500 2000 2500 3000 3500 c« W Scale = 1(in):500(ft) E »> . Plan L-213 (S-Q)/Plan L-213 ap BP Alaska Anticollision Report ~ Company: BP Amoco Date: 217/2006 Time: 15:22:12 Page: 1 Field: Prudhoe Bay Reference Site: PB L Pad Co-ordinate(NE) Keference: Well: Plan L-213 (S-Q), True North Reference WeII: Plan L-213 (S-Q) Vertical (I'VD) Refere nce: L-213 Pla n S-O 78.1 Reference Wellpath: Plan L-213 Db: Oracle __ ENO GLOBAL SCAN: Using user defined selection & scan criteria _ _ Reference: _ _ Principal Plan 8~ PLANNED PROGRAM ~ Interpolation Method : MD In terval: 20,00 ft Error Model: ISCWSA Ellipse Depth Range: 28.50 to 6670 .80 ft Scan Method: Trav Cylinder No rth ~!, Maximum Radius:10000.00 ft Error Surface: Ellipse + Casing Survey Program for Definitive Wellpath Date: 3/2/2005 Validated: No Version: 6 !; Planned From To Survey Toolcode Tool Name I ft ft - i 28.50 800.00 Planned: Plan #3 V1 -- - CB-GYRO-SS - - -_ - Camera based gyro single s - ---_---_ - --- hots 800.00 2200.00 Planned: Plan #3 V1 MWD MWD - Standard ~ 800.00 6670.80 Planned: Plan #3 V1 MWD+IFR+MS MWD +IFR + Mu lti Station i Casing Points - ~IU 1'~'U Diameter H ole Size Name - - -- - ft ft in in 3675.64 2678.10 9.625 12.250 9 5/8" 6670.80 .4804.58 7.000 8.750 7" I 1 Summary - - - ---- <------- Offset Wellpath ---- -------> Reference Offset Ctr-Ctr No-Go Allowable Site Well Wellpath MD MD Distance Area Deviation Warning i - ft ft ft ft ft ~ I PB L Pad L-01 - - L-01 V14 - 440.03 440.00 60.52 - - 8.71 51.82 Pass: Major Risk ~' PB L Pad L-02 L-02 V1 408.12 420.00 282.29 8.60 273.69 Pass: Major Risk ', PB L Pad L-02 L-02A V5 413.29 420.00 282.38 8.79 273.59 Pass: Major Risk PB L Pad L-02 L-02APB1 V2 413.29 420.00 282.38 8.79 273.59 Pass: Major Risk PB L Pad L-02 L-02P61 V21 408.12 420.00 282.29 8.71 273.58 Pass: Major Risk PB L Pad L-03 L-03 V5 339.72 340.00 31.32 7.60 23.72 Pass: Major Risk ~~ PB L Pad ~ L-101 L-101 V4 411.79 420.00 332.70 8.67 324.03 Pass: Major Risk PB L Pad L-102 L-102 V2 955.17 940.00 107.08 16.73 90.36 Pass: Major Risk PB L Pad L-102 L-102P61 V10 279.10 280.00 105.34 5.70 99.64 Pass: Major Risk ~~ PB L Pad L-102 L-102P62 V2 279.10 280.00 105.34 5.70 99.64 Pass: Major Risk , P8 L Pad L-103 L-103 V23 395.98 400.00 181.47 7.92 173.55 Pass: Major Risk j PB L Pad L-104 L-104 V7 1025.14 1020.00 34.04 18.40 15.64 Pass: Major Risk PB L Pad L-105 L-105 V4 700.92 700.00 28.73 14.46 14.27 Pass: Major Risk ', PB L Pad L-106 L-106 V14 539.57 540.00 42.96 10.41 32.54 Pass: Major Risk ; PB L Pad L-107 L-107 V14 697.31 700.00 30.67 14.46 16.21 Pass: Major Risk ~, PB L Pad L-108 L-108 V18 419.61 420.00 13.18 9.08 4.11 Pass: Major Risk ~ PB L Pad L-109 L-109 V12 438.71 440.00 131.14 10.24 120.90 Pass: Major Risk ', i PB L Pad L-110 L-110 V11 399.06 400.00 176.05 8.63 167.43 Pass: Major Risk ', PB L Pad L-111 L-111 V24 301.83 300.00 282.01 6.55 275.46 Pass: Major Risk ~ PB L Pad L-112 L-112 V8 352.41 360.00 297.97 8.63 289.34 Pass: Major Risk PB L Pad L-114 L-114 V15 417.49 420.00 251.74 7.97 243.78 i Pass: Major Risk PB L Pad L-114 L-114A V4 417.49 420.00 251.74 7.97 243.78 Pass: Major Risk PB L Pad L-115 L-115 V7 486.10 500.00 238.43 9.68 228.75 Pass: Major Risk ~ PB L Pad L-116 L-116 V10 400.23 400.00 145.75 7.44 138.31 Pass: Major Risk ~ PB L Pad L-117 L-117 V11 338.71 340.00 232.29 6.66 225.63 Pass: Major Risk i PB L Pad L-118 L-118 V9 338.88 340.00 223.47 7.52 215.95 Pass: Major Risk I ~ PB L Pad L-119 L-119 V9 337.90 340.00 196.58 6.91 189.67 Pass: Major Risk ~ i PB L Pad L-120 L-120 V8 298.98 300.00 210.40 6.31 204.09 Pass: Major Risk PB L Pad L-121 L-121 V14 379.77 380.00 206.83 8.16 198.67 Pass: Major Risk PB L Pad L-121 L-121A V1 379.77 380.00 206.83 8.16 198.67 Pass: Major Risk ~ PB L Pad L-122 L-122 V5 338.62 340.00 262.60 6.83 255.76 Pass: Major Risk I PB L Pad L-123 L-123 V5 222.08 220.00 274.14 5.12 269.02 Pass: Major Risk 'I PB L Pad L-123 L-123P61 V3 222.08 220.00 274.14 5.12 269.02 Pass: Major Risk i PB L Pad L-124 L-124 V13 357.16 360.00 308.88 7.35 301.54 Pass: Major Risk PB L Pad L-124 L-124P61 V5 357.16 360.00 308.88 7.35 301.54 Pass: Major Risk ', PB L Pad L-124 L-124PB2 V4 357.16 360.00 308.88 7.35 301.54 Pass: Major Risk PB L Pad L-200 L-200 V7 220.49 220.00 190.91 4.88 186.03 Pass: Major Risk ~ '~ PB L Pad L-200 L-200L1 V3 220.49 220.00 190.91 4.88 186.03 Pass: Major Risk PB L Pad L-200 L-200L2 V6 220.49 220.00 190.91 4.88 186.03 Pass: Major Risk PB L Pad L-201 L-201 V6 259.39 260.00 190.21 5.61 184.60 Pass: Major Risk j PB L Pad L-201 L-201 L1 V9 259.39 260.00 190.21 5.61 184.60 Pass: Major Risk j 'i PB L Pad L-201 L-201 L1 PB1 V10 259.39 260.00 190.21 5.61 184.60 Pass: Major Risk !, by BP Alaska Anticollision Report Company: BP Amoco - -- Date: 2/7!2006 - - Time: 15:22:12 Page: 2 Field: Prudhoe Bay Reference Site: PB L Pad Co-ordinate(NF,) Reference: Well: Pla n L-213 (S-Q), True North Reference Well: Plan L-213 (S-Q) Vertical ('I'VD) Refere nce: L-213 Plan S-Q 78.1 Reference Wellpath: Plan L-213 Db: Oracte Summan <------ --- O ffset Wellpath ---- ------> Reference Offset Ctr-Ctr No-Go Allowable Site Well ~Ycllpath MD MD Distance Area Deviation Warning ft ft ft ft ft PB L Pad L-201 L-201 L2 V5 259.39 260.00 190.21 5.61 184.60 Pass: Major Risk ~ 'i PB L Pad L-201 L-201 L3 V2 259.39 260.00 190.21 5.61 184.60 Pass: Major Risk ~~ PB L Pad L-201 L-201 L3PB1 V6 259.39 260.00 190.21 5.61 184.60 Pass: Major Risk ' PB L Pad L-201 L-201PB1 V12 259.39 260.00 190.21 5.61 184.60 Pass: Major Risk ~' PB L Pad L-201 L-201 P62 V3 259.39 260.00 190.21 5.61 184.60 Pass: Major Risk PB L Pad L-202 L-202 V5 358.03 360.00 186.29 7.33 178.96 Pass: Major Risk PB L Pad L-202 L-202L1 V7 358.03 360.00 186.29 7.33 178.96 Pass: Major Risk PB L Pad L-202 L-202L2 V6 358.03 360.00 186.29 7.33 178.96 Pass: Major Risk '~, PB L Pad L-202 L-202L3 V6 358.03 360.00 186.29 7.33 178.96 Pass: Major Risk PB L Pad L-210 L-210 V6 453.85 460.00 200.04 9.13 190.91 Pass: Major Risk PB L Pad L-210 L-210P61 V8 453.85 460.00 200.04 9.13 190.91 Pass: Major Risk PB L Pad L-211 L-211 V6 413.32 420.00 248.83 9.06 239.77 Pass: Major Risk ~~ PB L Pad L-211 L-211 P61 V6 413.32 420.00 248.83 9.06 239.77 Pass: Major Risk PB L Pad L-212 L-212 V11 319.41 320.00 182.90 6.60 176.30 Pass: Major Risk i PB L Pad L-212 L-212P61 V9 319.41 320.00 182.90 6.60 176.30 Pass: Major Risk i~ ~ PB L Pad L-212 L-212P62 V2 319.41 320.00 182.90 6.60 176.30 Pass: Major Risk PB L Pad L-214 L-214 V9 359.71 360.00 89.46 7.90 81.56 Pass: Major Risk ~, PB L Pad L-214 Plan L-214A V2 Plan: L 342.57 340.00 89.13 7.69 81.44 Pass: Major Risk PB L Pad ~ L-215 L-215 V7 319.06 320.00 186.53 7.09 179.44 Pass: Major Risk I PB L Pad L-215 L-215P61 V4 319.06 320.00 186.53 7.09 179.44 Pass: Major Risk PB L Pad L-215 L-215P62 V2 319.06 320.00 186.53 7.09 179.44 Pass: Major Risk PB L Pad L-216 L-216 V6 239.70 240.00 180.35 5.25 175.10 Pass: Major Risk PB L Pad L-218 L-218 V4 483.11 500.00 320.95 9.67 311.28 Pass: Major Risk ~, PB L Pad L-250 L-250 V4 376.86 380.00 195.91 8.24 187.67 Pass: Major Risk ~ PB L Pad L-250 L-250L1 V14 376.86 380.00 195.91 8.24 187.67 Pass: Major Risk PB L Pad L-250 L-250L2 V10 376.86 380.00 195.91 8.24 187.67 Pass: Major Risk PB L Pad L-250 L-250P61 V3 376.86 380.00 195.91 8.30 187.61 Pass: Major Risk ~I PB L Pad L-250 L-250P61_005 V4 Plan: 579.28 600.00 218.72 47.07 171.65 Pass: Major Risk PB L Pad L-50 L-50 V1 399.08 400.00 237.55 8.42 229.14 Pass: Major Risk PB L Pad L-50 L-50PB1 V4 399.08 400.00 237.55 8.42 229.14 Pass: Major Risk PB L Pad L-50 L-50PB1 003 V6 Plan: P 510.99 520.00 239.36 23.94 215.42 Pass: Major Risk PB L Pad NWE1-01 L-100 V2 301.01 300.00 403.87 6.42 397.44 Pass: Major Risk ~ PB L Pad NWE1-01 NWE1-01 V5 301.01 300.00 403.87 6.42 397.44 Pass: Major Risk , PB L Pad Plan L-203 (N-Q) Plan L-203 V6 Plan: PI 603.55 620.00 181.06 13.03 168.03 Pass: Major Risk ~, PB L Pad Plan L-51 (S-B) Plan L-51 V1 Plan: Pla 417.29 420.00 266.17 9.17 257.00 Pass: Major Risk PB L Pad ~-- Plan L-52 (S-E) Plan L-52 V1 Plan: Pla 455.30 460.00 221.26 10.04 211.23 Pass: Major Risk • • ', Field: Prudhoe Bay II ', Site: PB L Pad '~ Well: Plan L-213 (S-Q) ~~ Wellpath: Plan L-213 loo i o0 se Inu Travelling Cylinder Azimuth (TFO+AZq [deg] vs Cen[re [o Centre Separation [IOOft/irt] Target: L-213 Tgt 1 Site: PB L Pad Well: Plan L-213 (S-Q) ^ Drilling Target Conf.: 95% Based on: Planned Program Description: Vertical Depth: 4220.00 ft below Mean Sea Level Map Northing: 5976775.00 ft Local +N/-S: -1396.73 ft Map Easting : 586915.00 ft Local +E/-W: 3585.94 ft Latitude: 70°20'47.049N Longitude:149°1T40.124W Shape: Circle _ Radius: 150 ft f i p0 ~ ~ } D~} ,} f ~00 O O O O O O 0 0 0 0 0 0 ~ ~ o ~ ~ ~ m c~ m m m m 4 ~ PLANT -N~,S'DD'DD" L-PAD I GRID N-L (NWE-1) L-111i ~ N-A (NWE-2) i L-113 L-114 ~ L-124 L-SD ~ ~ L-1121 L-02 L-121 ~ ~ L-122 L-110 ~ ~ L-2111 L-SI ~ ~ L-115i L-116 ~ ~ L-117 L-109 ~ ~ L-118 L-SL ~ 34 f§ _ L-PAD ~.~ ~ PROJECT ` AREA ~~~ _ -N ; , l T12N T11N g - - w ~ ._ .,~ I ~ 3 2 _.. _ _ _. VICINITY MAP N.T.S. LEGEND -~ AS-BUILT CONDUCTOR ~ EXISTING CONDUCTOR L-01 ~ (i L-200 L-107 L-03 ~- ~o ~: ~~ ° 0 F q ~ ~ ° L-213i ~ L-1081 ~ ~ L-216i ~P°° °S,r ° ~ ~ °° 9 ` L-106 ~ oF .7 (i L-201 ° ° ° ° ° ° ° L-104 ~ ~ L-119i S-W ~ ~ L-210i L-102 ~ a'& ~ L-120 °°C °°°°°°°°°°°°°°°°°°°°°°°°°°° ' a ~ °, Richard F. Allison , ° 10608 °°° ° ,~,,~oo °°°~ ~ '"'~' grPa ESSI - ~~ ~ SURVEYOR'S CERTIFICATE - ~ --- °- ---~- ---- - ---- - --- --- -- ~ -~ -- -- ~ ~ ~ ~ ~ I HEREBY CERTIFY THAT I AM ," - ` PROPERLY REGISTERED AND LICENSED %" TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT NOTES THIS PLAT REPRESENTS A SURVEY MADE BY ME OR UNDER MY DIRECT 1. DATE OF SURVEY: JULY 16, 2004. SUPERVISION AND THAT ALL 2. REFERENCE FIELD BOOK: W004-11 PAGES 11-13. DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF JULY 16, 2004. 3. ALASKA STATE PLANE COORDINATES ARE ZONE 4, NAD 27. GEODETIC POSITIONS ARE NAD 27. 4. BASIS OF HORIZONTAL LOCATION IS L-PAD OPERATOR MONUMENTATION. 5. BASIS OF ELEVATION IS L-PAD OPERATOR MONUMENTS. ELEVATIONS ARE BP MSL DATUM. 6. MEAN PAO SCALE FACTOR IS 0.999907827. LOCATED WITHIN PROTRACTED SEC. 34, T. 12 N., R. 11 E., UMIAT MERIDIAN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC CELLAR SECTION N0. COORDINATES COORDINATES POSITION(DMS POSITION(D.DD BOX ELEV. OFFSETS L Y= 5,978,123.44 N= 9,819.89 70'21'00.717" 70.3501992' 49 6 2,401' FSL -03 X= 583,284.81 E= 5,249.90 -149'19'25.760" -149.3238222' ' 3,631' FEL L Y= 5,978,131.65 N= 9,820.24 70'21'00.794" 70.3502206' 49 6 2,409' FSL -213i X= 583,314.08 E= 5,280.30 -149'19'24.902" -149.3235839' ' 3,602' FEL r. lcooerr. °"""'° dACOes cHEDKED:HACKLEMAN by DATE: 7/19/04 DRAWING: GPB WOA L-PAD SHEET: ((~~((~~ FR804 WOL 06-00 ®~ 1U 1U~LiDa ~De ND: AS-BUILT CONDUCTORS 0 7 19 O ISSUED FOR INFORMATION ~ KYA~ n~o,eus wo uwo an~cmns SCALE: 1 OF 1 N0. DATE REVISION BY CHK ~~ ra,au~ 1"= 150 WELLS L-03 & L-2131 • • Conditions of Approval BP Exploration (Alaska) tnc. PBU L-2131 (PTD 206-053) 1. BPXA shall test BOPE to 4000 psi. 2. Per 20 AAC 25.035 (h) (1), alternate BOPE test procedure is approved. 3. BPXA shall perform mechanical integrity testing. 4. BPXA shall obtain a cement quality log. 5. BPXA shall submit to the Commission monthly TIO plots of daily recorded pressures in AOR wells PBU V-203 (PTD 205-168), PBU L-03 (PTD 205-103) and PBU L-104 (PTD 201-238). 6. An approved amended Orion Area Injection Order is required prior to com- mencing injection. .7 SONDRA D STEWMAN BP EXPLORATION AK INC "Mastercard Check" PO BOX 196612 MB 7-5 ANCHORAGE', AK 99519-6612 ss-sii25z 1.46 DATE ~D ORDER OF E V G ~ ~ L ~~/dt Jl~ lr" ~ DOLLARS. First Nations Bank Alaska Anchors e, A -99501 l~ ~,1~1 MEMO ~: i 2 5 2 0 0 0 6 0:9 9 ~4~~~6 2 2 7~~~ L 564~~' O L46 • • TRANSMITTAL LETTER CHECKLIST WELL NAME ~ `!1-~L~ ~~ ~ ` ~ ~ Development ~ Service Exploratory Stratigraphic Test Non-Conventional Well Circle Appropriate Letter /Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS TEXT FOR APPROVAL LETTER WHAT (OPTIONS) APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in permit No. API No. 50- - - API number are , between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - -_) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce /inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Non-Conventional production or production testing of coal bed methane is not allowed Well for (name of welly until after (Com~any NameZhas designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company NameZmust contact the Commission to obtain advance approval of such water well testing rogram. 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