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Home My WebLink About203-198MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, July 21, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Matt Herrera P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC S-120 PRUDHOE BAY UN AURO S-120 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/21/2022 S-120 50-029-23186-00-00 203-198-0 W SPT 6386 2031980 1596 2258 2260 2263 2265 414 550 546 543 4YRTST P Matt Herrera 6/25/2022 MIT-IA Performed to 2500 PSI Per Operations 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UN AURO S-120 Inspection Date: Tubing OA Packer Depth 713 2496 2480 2474IA 45 Min 60 Min Rel Insp Num: Insp Num:mitMFH220629125557 BBL Pumped:1.3 BBL Returned:1.3 Thursday, July 21, 2022 Page 1 of 1          e e 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. ~ Q 3 - J c;¡ ß Well History File Identifier Organizing (done) D Two-sided 11111111111" 111111 D Rescan Needed III" 1I1I11 II 111111 RESCAN DIGITAL DATA tØÓiskettes, No. I D Other, No/Type: OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Color Items: D Greyscale Items: D Poor Quality Originals: D Other: OVERSIZED (Non-Scannable) D Logs of various kinds: NOTES: Date (() 'g / () 0 D Other:: BY: ~ 151 V\1f III" 111111111 11111 Project Proofing BY: ~ . - Date ~/f{/Ob j x 30 = In 0 Date: /R /9t 106 151 VV1f Scanning Preparation + I d- = TOTAL PAGES 18- (Count does not include cover sh et) IMP 151 V I I' BY: ~ Production Scanning Stage 1 Page Count from Scanned File: 7 3 (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES Date: ~ Ie¿; lOb 11111111111111 1111I BY: (M~i~ 151 NO MP Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: 151 111"111111111 1111/ Scanning is complete at this point unless rescanning is required. ReScanned III "111111I11 "III BY: Maria Date: 151 Comments about this file: Quality Checked 1111111111111111111 10/6/2005 Well History File Cover Page.doc STATE OF ALASKA ALASKA OAND GAS CONSERVATION COMMISS104 REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Stimulate ❑ Other El CONVERT TO WAG Performed: Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver❑ Time Extension ❑ 6/9/2006 Change Approved Program ❑ Operat. Shutdown ❑ Perforate ❑ Re -enter Suspended Well ❑ 2. Operator BP Exploration (Alaska), Inc. 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ❑ Exploratory ❑ •• 203 -1980 3. Address: P.O. Box 196612 Stratigraphic❑ Service 0 6. API Number: Anchorage, AK 99519 -6612 • 50- 029 - 23186 -00 -00 8. Property Designation (Lease Number) : 9. Well Name and Number: ADLO- 028258 r S -120 10. Field /Pool(s): _ PRUDHOE BAY FIELD / AURORA POOL 11. Present Well Condition Summary: Total Depth measured 8440 feet Plugs (measured) None feet true vertical 6963.12 feet Junk (measured) None feet Effective Depth measured 8339 feet Packer (measured) 7853 feet true vertical 6863.39 feet (true vertical) 6386 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 20 "91.5# H -40 33 - 113 33 - 113 1490 470 Surface 3534' 9 -5/8" 40# L -80 32 - 3566 32 - 2914 5750 390 Production 8394' 7" 26# L -80 31 - 8425 31 - 6948 7240 5410 Production Liner t� Liner ° "t JUL 2 9 Z0I1 Perforation depth: Measured depth: SEE ATTACHED - _ - - True Vertical depth: _ _ - Tubing: (size, grade, measured and true vertical depth) 4 -1/2" 12.6# L -80 29 - 7914 29 - 6445 Packers and SSSV (type, measured and true vertical depth) 4 -1/2" Baker PRM Packer 7853 6386 12. Stimulation or cement squeeze summary: t � rk t Intervals treated (measured): Treatment descriptions including volumes used and final pressure: pp�� F4 3.i•.i .ali 5,a ?n?sr `.;ffltt. , *, iimillSSlOf1 13. Representative Daily Average Productior pr Injection Data Oil-Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing pressure Prior to well operation: 3352 1822 Subsequent to operation: 2214 160 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory Development ❑ Service IO Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil ❑ Gas ❑ WDSPL ❑ GSTOR ❑ WINJ p WAG El GINJ ❑ SUSP❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: NA Contact Joe Lastufka Printed Na e Lastup Title Petrotechnical Data Technologist Signatu r C� Phone 564 -4091 Date 7/19/2011 RBD S ``' M .rU�L 20 1i Form 10-404 Revised 10/2010 Z 8 ' 1 ( Submit Original Only S -120 203 -198 PERF ATTACHMENT Sw Name Operation Date Perf Operation Code Meas Depth Top Meas Depth Base Tvd Depth Top Tvd Depth Base S -120 4/30/04 PER 8,052. 8,077. 6,580.8 6,605.37 S -120 4/30/04 PER 8,084. 8,114. 6,612.25 6,641.74 S -120 4/30/04 PER 8,166. 8,178. 6,692.88 6,704.69 S -120 4/30/04 PER 8,252. 8,264. 6,777.55 6,789.38 AB ABANDONED PER PERF APF ADD PERF RPF REPERF BPP BRIDGE PLUG PULLED SL SLOTTED LINER BPS BRIDGE PLUG SET SPR SAND PLUG REMOVED FCO FILL CLEAN OUT SPS SAND PLUG SET FIL FILL SQF SQUEEZE FAILED MIR MECHANICAL ISOLATED REMOVED SQZ SQUEEZE • MIS MECHANICAL ISOLATED STC STRADDLE PACK, CLOSED MLK MECHANICAL LEAK STO STRADDLE PACK, OPEN OH OPEN HOLE • • • • S -120 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY . . E • 673/26/3 /2006: ** *WELL INJECTING UPON ARRIVAL * ** (Post SBG) RIG UP, INSTALL HYDROLIC ACCUATOR OVERRIDE ** *CONTINUE ON 06 -04 -2006 WSR * ** i t 6/4/2006= ** *CONTINUED FROM 06 -03 -2006 WSR * ** DRIFT W/ 3.83" CENT. TO 2196' SLM SET 4.5" MCX (sn= m- 002...vly 'type= 22mcx38100) @ 2196' SLM GOOD CLOSURE TEST ** *GAVE WELL BACK TO PAD -OP TO BRING BACK ON INJ. * ** 6/9/2006; MI SWAP TREE= 4- 1/16" CM/ WELLHEAD•= FMC • SAFETY KIPS: WELL REQUIRES A SSSV WHEN ON ACTUATOR = LEO S-120 ML KB. ELEV = 64.3' BF. ELEV = 35.8' - KOP = 260' _Max Angle = 49 @ 4670' — ---I 1013' H9-5/8" TAM PORT COLLAR I Datum MD = 8137' , Datum 'ND = 6600' SS ' ' I 2208' H 4 -1/2" HES X NIP, ID = 3.813" I 9 -5/8" CSG, 40 #, L -80 BTC, ID = 8.835" H 3566' I--- SOT MC X e h — �{— GAS LIFT MANDRELS 'I ST MD - ND DEV TYPE VLV LATCH PORT DATE Minimum ID = 3.725" 7901' f� 2 4858 3797 46 KBG -2 DMY BK 0 06/27/04 1 7723 6258 12 KBG -2 DMY BK 0 01/01/04 4 -1/2" HES XN NIPPLE 1 I 7790' I- I4 -1/2" HES X NIP, ID = 3.813" I Z I` I 7853' H 7" X 4 -1/2" BKR PREM PKR, ID = 3.875" I ' , I 7880' H 4 -1/2" HES X NIP, ID = 3.813" 1 ' ' 7901' I — I4 - 1/2" HES XN NIP, ID = 3.725" I 4 -1/2" TBG, 12.6 #, L -80 TCII, --I 7914' I-- / • 1 7914' 1 — I 4-1/2" WLEG, ID = 3.958" .0152 bpf, ID = 3.958" I 7906' I — ) ELMD TT LOGGED ON 04/16/09 1 7" CSG, 26 #, L -80 BTC-M, — 8041' I — X ( 8041' H r MA RKER JOINT W/ RA TAG I .0383 bpf, ID = 6.276" PERFORATION SUMMARY I REF LOG: PEX 12/28/03 ANGLE AT TOP PERF: 11° @ 8052' I Note: Refer to R DB for historical perf data SIZE SPF INTERVAL Opn /Sqz DATE 3 -3/8" r 6 8052 - 8077 0 04/30/04 3 -3/8" 6 8084 - 8114 0 04/30/04 3 -3/8" r^ 6 8166 - 8178 0 04/30/04 3 -3/8" IF 6 8252 - 8264 0 04/30/04 I 7" CSG, 29 #, L -80 BTC-M, -I 8278' I — X :---i 8278' H T MARKER JOINT W/ RA TAG I .0371 bpf, ID = 6.184" PBTD 1 8339' �.�.�.�.�.�.�.�.�.� + 4.,,x . , . , 1 , 4. ,,,.. 4 7" CSG, 26 #, L -80 BTC-M, — 8425' 1 ��1 .0383 bpf, ID = 6.276" DATE REV BY COMMENTS DATE REV BY COMMENTS AURORA UNIT 01/02/04 TMN/KK ORIGINAL COMPLETION 04/29/11 TA/ PJC ELMD LOGGED 04/16/09 WELL: S -120 04/11/04 JLJ /KAK GLV C/0 04/29/11 PJC DRAWING CORRECTIONS PERMIT No: 2031980 04/30/04 MJA /KAK IPERFS API No: 50- 029 - 23186 -00 06/27/04 RMHJKAK GLV C/0 SEC 35, T12N, R12E, 4360' NSL & 4500' WEL 10/22/05 RCC /PJC - ACTUATOR CORRECTION 02/15/11 MB /JMD ADDED SSSV SAFETY NOTE BP Exploration (Alaska) 05/06/11 Sddumberger NO. 5738 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambell Street, Suite 400 Alaska Oil & Gas Cons Comm Anchorage, AK 99503 -2838 Attn: Christine Shartzer ATTN: Beth 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Well Job 4 Log Description Date BL Color CD P2 -16 BBSK -00061 USIT - — 04/04/11 1- 35/0 -25 _ BBKA -00101 PRODUCTION PROFILE 1 1 P2 -52 BJGT -00027 CROSS FLOW CHECK 'le Wier I, 04/14/11 1 G 1 03 -37 BJGT -00028 INJECTION PROFILE li - _f At: � r ( 1 2-42/P-13 BAUJ -00076 MEM LDL 1fflr r •W rA . j 1 N -11C BH4H -00048 PRODUCTION PROFILE _ 1 02 -12C BD88 -00098 MEM CBL :Mg 41 'r r J'f. ' 1 1 - 0 c.,:: -r00. I,. TIO, -- *Ft - _ .TI<. ar 27)ff[ 1 P1 -09 BJOH -00024 PRODUCTION PROFILE - r r 2D,WE 1 P1 -09 BJOH -00024 SCMT ♦ 05/02/11 - g 1 1 • P2-43 BG4H -00049 SCMT • 'mot " 04/28/11 4 r , - 1 1 16-21 - BJGT -00030 PRODUCTION PROFILE / -- - / 04/28/11 1 Co / 09 -26 _ BD88 -00104 MEM LDL / 1—/)� 04/30/11 1 j �z / C 1 - -' 1 04 -33A BLPO -00095 MEM PRODUCTION PROFILT . n 9- n 1 5 - 0 04/30/11 1 iq j "- 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Alaska Data & Consulting Services 1 Petrotechnrcal Data Center LR2 -1 2525 Gambell Street, Suite 400 900 E. Benson Blvd. Anchorage, AK 99503 -2838 • MEMORANDUM To: Jim Regg ~„ _ l 5 ~ ~~'iJ P.I. Supervisor ~~ FROM: Bob Noble Petroleum Inspector • State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, April 28, 2010 SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC 5-120 PRUDHOE BAY iJN AURO 5-120 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv ~~ Comm Well Name: PRUDHOE BAY UN AURO 5-120 API Well Number: 50-029-23186-00-00 Inspector Name: Bob Noble Insp Num: mitRCN100423171529 Permit Number: 203-198-0 Inspection Date: 4/23/2010 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well T s-lzo ~ Type Inj. W~ TVD 6386 / IA I 580 4000 3965 3960 ~ P.T. ~ 2031980 TypeTest APT Test psi 4000 ~ QA 200 500 510 500 ~ IriteCVal4YRTST P~F P ~ TUblrig 2740 - 2740 2740- 2740 Notes: ~ i Jl ~ 4~~ ~ C~ ~3~- ~''t'-sS ~~,le_ = t ~~~~P~ Wednesday, April 28, 2010 Page 1 of 1 . ~ June 25, 2009 ~ ~~} ~~ iss ~~~ ~:-~ ~~ ; Mr. Tom Maunder ~1~L ~ ~. 2009 Alaska Oil and Gas Conservation Commission ~;4~~~~ ~,! ~ r~~ ~a~c~ ~a~mis~FA~ 333 West 7th Avenue ~n~€~~~~c~ Anchorage, Alaska 99501 ~ aa3 - ~ ~ Subject: Corrosion Inhibitor Treatments of S-Pad `~O S~ Dear Mr. Maunder, Enclosed please find a spreadsheet with a list of wells from S-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, 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, ;~~ w~~~~~.% ~'v" ,_ ~=, 2~~~ ~ ~~ Torin Roschinger BPXA, Well Integrity Coordinator ~ • BP Exploration (Alaska ) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report ot Sundry Operetions (10-404) S-pad r \ Data 6/25/2009 W ell Name PTD N Initial top of cement Vol. of cement um ed Final top of cement Cement top otf date Corrosion inhibitor Corrosion inhibitor/ sealant data fl bbls ft na al S-O1B 1952020 025 NA 025 NA 2.6 5/30/2009 S-02A 1941090 025 NA 025 NA 1.7 5/25/2009 S-03 1811900 7325 NA 13.25 NA 92.65 5/20I2009 S-oa 7830790 0 NA 0 MA 0.9 5/25/2009 S-05A 1951890 0 NA 0 NA 0.9 5/26/2009 S-O6 1821650 0 NA 0 NA 0.9 5/26/2009 S•07A 1920980 0 NA 0 NA 0.9 5/26/2009 S•088 2010520 0 NA 0 NA 0.85 5/27/2009 S•09 1621040 1.5 NA i.5 NA 9.4 5/37/2009 S-10A 1911230 0.5 NA 0.5 NA 3.4 5/31/2009 S-118 1990530 0.25 NA 025 NA 1.7 5/27/2009 S•12A 1851930 0.25 NA 025 NA 1.7 6/1/2009 S-~3 1827350 8 NA 8 NA 55.3 6/1l2009 S-15 1640170 0.25 NA 025 NA 3 6/2I2009 5-nC 2020070 0.25 NA 0.25 NA 2.8 6/1l2009 S•18A 2021630 0.5 NA 0.5 NA 3 6/2l2009 S-19 1861160 075 NA 0.75 NA 22 5/19/2009 S-20A 2010450 025 NA 025 NA 1.3 5/79/2009 S•21 1900470 0.5 NA 0.5 NA 3.4 5/25/2009 5-228 1970510 0.75 NA 0.75 NA 3 5/19/2009 5-23 1901270 0.25 NA 025 NA 1.7 5/25/2009 S-248 2031630 0.5 NA ~ 0.5 NA 2.6 5/25/2009 S-25A 1982140 0.5 NA 0.5 NA 2.6 5/25/2009 S-26 1900580 0.75 NA 0.75 NA 3.4 5/26/2009 S-278 2031680 0.5 NA 0.5 NA 2.6 5/31/2009 S-28B 2030020 0.5 NA 0.5 MA 2.6 5/31/2009 S-29A~7 1960120 0 NA 0 NA 0.85 5/27/2009 S30 1900660 0.5 NA 0.5 NA 5.1 5/37/2009 S-31A 1982200 0.5 NA 0.5 NA 3.4 5/26/2009 S-32 1901490 0.5 NA 0.5 NA 3.4 5/31/2009 S33 1921020 0.5 NA 0.5 NA 4.3 5/26/2009 S-3a 1921360 0.5 NA 0.5 NA 3.a 5/31/2009 S-35 1921480 0 NA 0 NA .85 in 5/31/2009 S36 1921160 0.75 NA 0.75 NA 425 5/27/2009 S-37 7920990 125 NA 125 NA 17.9 5/27/2009 S-38 1921270 0.25 NA 025 NA 102 5/27l2009 S-at 1960240 1.5 NA 1.5 NA Y1.1 5/30/2009 S-42 1960540 0 NA 0 NA 0.9 5/30/2009 S-43 1970530 0.5 NA 0.5 NA 1.7 5/28/2009 S-44 1970070 025 NA 0.25 NA 1.7 5/28/2009 5-100 2000780 2 NA 2 NA 21.3 5/29l2~9 5-101 2001150 1.25 NA 125 NA 77.s 5/29/2009 S402L1 2031560 1.25 NA 125 NA 11.7 5/31Y2009 5-103 2001680 1.5 NA 1.5 NA 11.9 5/18/2009 5-104 2001960 175 NA 1J5 NA 15.3 5/20/2009 5-105 2001520 4 NA 4 NA 32.7 5/20/2009 S-to6 2010120 16.25 NA 1625 NA 174.3 6/2/2009 S-t07 2011130 2.25 NA 225 NA 28.8 5/78/2009 S-70e 2011000 3.5 NA 3.5 NA 40 5/30/2009 S-709 2022450 2 NA 2 NA 21.3 5/30/2009 5-110 2071290 11.75 NA 11.75 NA 98.6 5/30/2009 S-~ 7 t 2050510 2 NA 2 NA 19.6 5/30/2009 5-172 2021350 0 NA 0 NA 0.5 5/30/2009 S-tt3 2021430 175 NA 775 NA 22.1 5/18/2009 S-11aA 2021980 125 NA 125 NA tOZ 5/30l2009 5-~15 2022300 2.5 NA 2.5 NA 27.2 5/29/2009 5-~76 2031810 1.5 NA 7.5 NA 13.6 5/28/2009 5-117 2030120 1.5 NA 1.5 NA 15.3 5/29/2009 5-1~8 2032000 5 NA 5 NA 76.5 5/28/2009 S-119 2041620 1 NA 1 NA 52 5/30/2009 5-120 2031980 5.5 NA 5.5 NA 672 5/29/2009 S-121 2060410 4.5 NA 4.5 NA 53.fi 5/28/2009 S-~22 2050810 3 NA 3 NA 21.3 5/29/2009 S-t23 2041370 1.5 NA 1.5 NA 20A ~ 5/26/2009 5-124 2061360 1.75 NA 175 NA 11.9 5/26/2009 5-125 2070830 225 NA 225 NA 20.4 5/28/2009 S-t26 20770970 125 NA 1.25 NA t5.3 6/1/2009 S•2ao 1972390 1.25 NA 125 NA ta.5 5/28I2009 5-207 2001840 0 NA 0 NA 0.85 6/19/2009 S-2t3A 2042130 2 NA 2 NA t3.e 5/29/2009 5-215 2021540 2 NA 2 NA /8.7 6l1/2009 5-216 2001970 4.75 NA 4.75 NA 51 5/29/2009 5-217 2070950 025 NA 025 NA t.7 6/1/2009 5-400 2070740 2 NA 2 NA 9.4 5/28/2009 S-a01 2060780 16 NA 16 NA 99.5 6/2/2009 S-SM 0 NA 0 NA 0.85 5/28/2009 • • >-~.~. °~- MICROFILMED 03/01/2008 DO NOT PLACE .. ~'" -.: :~. ANY NEW MATERIAL UNDER THIS PAGE F: ~L.aserFiche\C`vrPgs_Inserts~Microfilm_Marker. doc 08/07/00 Schlumberger NO. 3903 SchlumÞerger-DCS 2525 GamÞeIl St, Su~e 400 Anchorage, AK 99503-2838 A TTN: Beth UJ: ê..- () 03 . ¡C)"'6 Company: Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Su~e 100 Anchorage, AK 99501 :tt H O()-ì Field: Aurora Well Job # Log Description Date BL Color CD S-118 10687665 OH EDIT OF WIRELINE LOGS 01/09/04 3 1 S-120 10621756 OH EDIT OF WIRELlNE lOGS 12/28/03 4 1 S-123 10877787 OH EDIT OF WIREllNE LOGS 09/20/04 4 1 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) inc. Petrotechnical Data Center LR2-' 900 E Benson Blvd, Anchorage AK 99508-4254 Schlumberger-DCS 2525 Gambel! St. Suite 400 Anchorage, AK 99503-2838 A TTN: Beth Date Delivered: Received by: RECE1VED \' '1 t~ ,>,p,r..'ft.í,h· ~,:¡;;n f\\¡ci .- Ö\¡Jrv~ii"~"" AUG 0 ð 2006 A.Jéiska Oil & Gas Cons. Commis$ÏOO Anchorage e e 'k¿1cl b( s(De STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:Winton_Aubert@admin.state.ak.us;Bob_Fleckenstein@admin.state.ak.us;Jim_Regg@admin.state.ak.us;Tom_Maunder@admin.state.ak.us OPERA TOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: BP Exploration (Alaska), Inc. Prudhoe Bay / PBU / S Pad 05/09/06 Joe Anders abY ¡q15 Packer Depth Pretest Initial 15Min. 30 Min. WellS-120 I Type Inj. I W TVD I 6,386' Tubing 1,340 1,340 1,280 1,240 Interval 0 P.T.D.12031980 Type test' P Test psi' 4000 Casing 800 4,000 3,880 3,820 P/FI P Notes: MITIA to 4000 psi pre-Mllnjection OA 400 650 600 600 Weill I Type Inj. , TVD , Tubing I I Intervall P.T.D.I I Type test I I Test psil Casing , I P/FI Notes: OA I Weill Type Inj.1 I TVD I Tubing I Interval I P.T.D.I I Type test I Test pSi Casing I P/FI Notes: OA I Weill I Type Inj. I TVD Tubing I Intervall p.T.D.1 I Type test I Test psi Casing I I P/F Notes: OA I I Weill I Type Inj. TVD I Tubing Interval P.T.D.I I Type test I Test psil Casing P/FI Notes: OA TYPE INJ Codes D = Drilling Waste G = Gas I = Industrial Wastewater N = Not Injecting W = Water MIT Report Form BFL 911105 TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaiy Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover 0= Other (describe in notes) St;~~tl~E~J JUN ç\ ?nnF' d c..w.....; MIT PBU S·120 05-09-06-1.xls 3~ ~ ~~ DATA SUBMITTAL COMPLIANCE REPORT 4/24/2006 Permit to Drill 2031980 Well Name/No. PRUDHOE BAY UN AURO S-120 Operator BP EXPLORATION (ALASKA) INC sp~d.. J.^k~ ~ API No. 50-029-23186-00-00 MD 8440""'--- TVD 6963 ..- Completion Date 4/30/2004 Completion Status 1WINJ Current Status 1WINJ ~ REQUIRED INFORMATION Mud Log No Samples No Directional ~ ~ DATA INFORMATION Types Electric or Other Logs Run: MWD 1 GR, MWD 1 GR 1 PWD, PEX 1 SHCS, USIT Well Log Information: Logl Electr Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No < V (data taken from Logs Portion of Master Well Data Maint Interval OH / Start Stop CH Received Comments . USIT/GRlCCL-JEWELRY LOG FINAL COMPOS IT GAMMA RAY MD & TVD PDS MEASURED DEPTH LOG FINAL PRINT COMPOSITE GAMMA RAY MD 1/9/2006 TRUE VERTICAL DEPTH LOG FINAL PRINT COMPOSITE GAMMA RAYTVD Directional Survey 0 8440 1/22/2004 0 8440 1/22/2004 7600 8280 2/11/2005 110 8381 1/9/2006 110 8381 1/9/2006 Directional Survey Cement Evaluation 5 Col ~C Pds 'tõQ ~ 13456 1~ Gamma Ray 25 Slu f32t56 Gamma Ray 25 Slu 110 8381 Well Cores/Samples Information: Name Interval Start Stop Sample Set Number Comments Sent Received ADDITIONAL INFORM~ON Well Cored? Y~ Chips Received? ~ ~ Daily History Received? Formation Tops Analysis Received? ~ . DATA SUBMITTAL COMPLIANCE REPORT 4/24/2006 Permit to Drill 2031980 Well Name/No. PRUDHOE BAY UN AURO S-120 Operator BP EXPLORATION (ALASKA) INC MD 8440 Completion Date 4/30/2004 TVD 6963 Completion Status 1WINJ Current Status 1WINJ Comments: Compliance Reviewed By: )Jd Date: API No. 50-029-23186-00-00 UIC Y ~'ft1J ~~ ~ . . RECEIVED 12/28/05 Schlumbergel' JAN 0 9 2006 AJætaCfl & Gas coos. ~ Anchorage NO. 3634 schlumborgor-DCs 2525 Gamboll st, suito 400 Anchorago, AK 99503-2838 ATTN: Both Company: Alaska 011 & Gas Cons Comm Attn: Helen Warman 333 Wo.t 7th Avo, suito 100 Anchorago. AK 99501 Fiold: Borealis Aurora WolI Job# Log Description Date Color BL CD Z-100 40009858 OH LDWG EDIT OF MWDILWD 12/02103 Z-100 40009858 MD CDR·GR 12102/03 Z-100 40009858 TVO CDR-GR 12/02/03 5-116 40009909 OH LDWG EDIT OF MWDILWD 12/14/03 5-116 40009909 MD CDR-GR 12/14/03 5-116 40009909 TVD CDR·GR 12/14/03 . .~:~;~ }d68.. Jq~ 40009967 OH LOWG EOiT OF MWD/LWD 12/28/03 40009987 MD CDR-GR 12/28/03 5-120 40009967 TVD COR-GR 12/28103 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, Alaska 99508 Date Delivered: schlumberger·DCS 2525 Gambell St. Suite 400 Anchorage, AK 99503-2838 :~:~(fJ . o . . SGblumbepgep Schlumberger-DCS 2525 Gambell SI, Suite 400 Anchorage, AK 99503·2838 ATTN: Beth Well ZO"'!r tC(<8'-S.120 "l d 1~1_-S-123 C1\O'T-:. 7. ./_ S-116 ?-o.i> - S-118 ~J - J-- Job# Log Description 10674426 US IT 10900127 USIT 10674425 USIT 10703986 SCMT 4116104 12122/04 04115104 04112104 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 Date Delivered: ;¿f (o~- /) ... ""1 C?<O:;? -/9 f1 02/11/05 NO. 3335 Company: Alaska 011 & Gas Cons Comm AUn: Helen Warman 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Aurora Date BL CD Color Schlumberger DeS 3940 Arctic Blvd Suite 300 Anchorage AK 99503-5789 :~/~a,^-, MEMORANDUM . State of Alaska - Alaska Oil and Gas Conservation Commission TO: Jim Regg P.I. Supervisor ~1 9>1-zA-I04 DATE: Wednesday, August 11,2004 SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC S-120 PRUDHOE BAY UN AURO S-120 a.D6-ICft FROM: John Crisp Petroleum Inspector Src: Inspector Reviewed By: ..--:: P.I. Suprv ,-I ßI!- Comm NON-CONFIDENTIAL Well Name: PRUDHOE BAY UN AURO $-120 Insp Num: miUCr040810185119 Rei Insp Num: API Well Number: 50-029-23186-00-00 Permit Number: 203-198-0 Inspector Name: John Crisp Inspection Date: 8/9/2004 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well S-120 Type Inj. S I TVD 6963 I IA 340 3010 2980 3000 P.T. 2031980 TypeTest SPT Test psi 1643.5 OA 240 300 300 260 Interval INITAL PIF P Tubing 1350 1350 1350 1350 Notes: Wednesday, August 11,2004 Page 1 ofl '" e STATE OF ALASKA e ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: 0 Oil 0 Gas 0 Plugged 0 Abandoned 0 Suspended 0 WAG 20MC 25.105 20MC 25.110 21. Logs Run: MWD / GR, MWD I GR / PWD, PEX I BHCS, USIT CASING, LINER AND CEMENTING RECORD $I$T'rING[)1;I?tH MD SETTING[)EptH TVD Top BoTT'OM rop BOTT'OM Surface 99' Surface 99' 29' 3566' 29' 2914' 26' 8425' 26' 6948' o GINJ a WINJ 0 WDSPL No. of Completions 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 4360' NSL, 4500' WEL, SEC. 35, T12N, R12E, UM Top of Productive Horizon: 58' NSL, 3182' WEL, SEC. 27, T12N, R12E, UM Total Depth: 108' NSL, 3225' WEL, SEC. 27, T12N, R12E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 618930 y- 5980564 Zone- ASP4 TPI: x- 614952 y- 5981479 Zone- ASP4 Total Depth: x- 614908 y- 5981528 Zone- ASP4 18. Directional Survey a Yes 0 No 22. WT. PER 91.5# 40# 26# H-40 L-80 L-80 20" 9-5/8" 7" 23. Perforations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): 3-3/8" Gun Diameter, 6 spf MD TVD MD TVD 8052' - 8077' 6581' - 6605' 8084' - 8114' 6612' - 6642' 8166' - 8178' 6693' - 6705' 1252' - 8264' 6778' - 6789' 26. Date First Production: August6,2004 Date of Test Hours Tested PRODUCTION FOR 5/18/2004 4 TEST PERIOD .. Flow Tubing Casing Pressure CALCULATED .. Press. 55 590 24-HoUR RATE One Other Pre-Produced Injector 5. Date Comp., Susp., or Aband. 04/30/2004 6. Date Spudded 12/22/2003 7. Date T.D. Reached 12/27/2003 8. KB Elevation (ft): 64.35' 9. Plug Back Depth (MD+ TVD) 8339 + 6863 Ft 10. Total Depth (MD+TVD) 8440 + 6963 Ft 11. Depth where SSSV set (Nipple) 2208' MD 19. Water depth, if offshore NIA MSL Revised: 08/10/04, Put on Injection 1b. Well Class: o Development 0 Exploratory o Stratigraphic a Service 12. Permit to Drill Number 203-198 13. API Number 50- 029-23186-00-00 14. Well Name and Number: PBU 5-120 15. Field / Pool(s): Prudhoe Bay Field I Aurora Pool 16. Property Designation: ADL 028258 17. Land Use Permit: 20. Thickness of Permafrost 1900' (Approx.) 42" 260 sx Arctic Set (Approx.) 12-1/4" 550 sx Arctic Set Lite PF, 293 sx 'G' 8-3/4" 151 sx Litecrete, 159 sx Class 'G' 24. SIZE 4-1/2", 12,6#, L-80 DEPTH SET (MD) 7914' PACKER SET (MD) 7853' AMOUNT & KIND OF MATERIAL USED Freeze Protected with 85 Bbls of Diesel DEPTH INTERVAL (MD) 2200' PRODUCTION TEST Method of Operation (Flowing, Gas Lift, etc.): Water Injection OIL-BeL GAs-McF WATER-BeL 143 256 -0- OIL-BeL GAs-McF WATER-BeL 856 1,533 -0- CHOKE SIZE I GAS-OIL RATIO 1760 1,791 OIL GRAVITY-API (CORR) 27. CORE DATA I Brief description of lithology, porosity, fractures, apparent dips and presence O~\ oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". None ~a~. ........$ '~""ft Form 1 0-407 Revised 12/2003 AUG' 1 ~. ~,,", "" C9\V CONTINUED ON REVERSE SIDE nq\G\NAL .... 28. e- GEOLOGIC MARKERS 29. - FORMATION TESTS , NAME MD TVD Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". Ugnu 4598' Ugnu M Sands 6160' Schrader Bluff N 6326' Schrader Bluff 0 6446' Base Schrader I Top Colville 6761' HRZ 8022' Kalubik 8049' Kuparuk C 8051' Kuparuk B 8150' Kuparuk A 8242' Miluveach 8303' 3621' None 4783' 4929' 5040' 5336' 6551' 6578' 6580' 6677' 6768' 6828' 30. List of Attachments: Summary of Daily Drilling Reports and Post Rig work, Well Schematic Diagram, Surveys 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Terrie Hubble '1ÔAlllR . ~ Title Technical Assistant PBU S-120 203-198 Well Number Permit No. I Approval No. INSTRUCTIONS Date 09 -[ O-Dc.¡ Prepared By Name/Number: Terrie Hubble, 564-4628 Drilling Engineer: Jim Smith, 564-5773 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. ITEM 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. ITEM 4b: TPI (Top of Producing Interval). ITEM 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. ITEM 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). ITEM 20: True vertical thickness. ITEM 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). ITEM 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). ITEM 27: If no cores taken, indicate "None". ITEM 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 Submit Original Only e -- STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:Winton_Aubert@admin.state.ak.us;Bob_Fleckenstein@admin.state.ak.us;Jim_Regg@admin.state.ak.us OPERATOR: FIELD I UNIT I PAD: DATE: OPERATOR REP: AOGCC REP: BP Exploration (Alaska) Inc. Prudhoe Bay I PBU I S Pad 06/27/04 Donald Reeves Packer Depth Pretest wellls-120 I Type Inj. F TVD I 6,386' TUbingl 5001 P.T.D. 2031980 Type test P Test psi 3,000 Casing 1,600 Notes: MITIA pre injection weill I Type Inj. I TVD I I TUb~ngl P.T.D. Type test Test psi Casing Notes: weill Type Inj'l I TVD I I TUb~ngl P.T.D. Type test Test psi Casing Notes: weill Type Inj'l I TVD I I TUb~ngl P.T.D. Type test Test psi Casing Notes: weill Type In¡'1 I TVD I I TUb~ngl P.T.D. Type test Test psi Casing Notes: Test Details: 'K~q 6/zJðfc4 Initial 15 Min. 30 Min. 5001 5001 5oollnterval 3,000 2,920 2,920 P/F TYPE INJ Codes F = Fresh Water Inj G = Gas Inj S = Salt Water Inj N = Not Injecting TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test Notes: If the test was not AOGCC witnessed. leave the "AOGCC REP:" box blank. MIT Report Form Revised: 06/19/02 2004-0627 _MIT_PBU_S-120.xls o P I Interval 1 P/F II nterval P/F I Interval I P/F II nterval P/F INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover 0= other (describe in notes) · STATE OF ALASKA e ALASKA~IL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG , 1a. Well Status: 0 Oil 0 Gas 0 Plugged 0 Abandoned 0 Suspended 0 WAG 20AAC 25.105 20AAC 25.110 o GINJ IS! WINJ 0 WDSPL No. of Completions 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 4360' NSL, 4500' WEL, SEC. 35, T12N, R12E, UM Top of Productive Horizon: 58' NSL, 3182' WEL, SEC. 27, T12N, R12E, UM Total Depth: 108' NSL, 3225' WEL, SEC. 27, T12N, R12E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: x- 618930 y- 5980564 Zone- ASP4 TPI: x- 614952 y- 5981479 Zone- ASP4 Total Depth: x- 614908 y- 5981528 Zone- ASP4 18. Directional Survey IS! Yes 0 No 21. Logs Run: MWD I GR, MWD I GR I PWD, One Other Pre-Produced Injector 5. Date Comp., Susp., or Aband. 04/30/2004 6. Date Spudded 12/22/2003 7. Date T.D. Reached 12/27/2003 8. KB Elevation (ft): 64.35' 9. Plug Back Depth (MD+ TVD) 8339 + 6863 Ft 10. Total Depth (MD+TVD) 8440 + 6963 Ft 11. Depth where SSSV set (Nipple) 2208' MD 19. Water depth, if offshore N/A MSL CASING SIZE 20" 9-5/8" 7" PEX I BHCS, US IT CASING, liNER AND CEMENTING RECORD SEITING DEPTHMD SeITINGDEPTH TIID BOTTOM 'lOP BOTTOM 99' Surface 99' 3566' 29' 2914' 8425' 26' 6948' 22. WT. PER FT. 91.5# 40# 26# GRADE H-40 L-80 L-80 Surface 29' 26' 23. Perforations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): 3-3/8" Gun Diameter, 6 spf MD TVD MD TVD 8052' - 8077' 6581' - 6605' 8084' - 8114' 6612' - 6642' 8166' - 8178' 6693' - 6705' 1252' - 8264' 6778' - 6789' 26. Date First Production: 1b. Well Class: o Development 0 Exploratory o Stratigraphic Test IS! Service 12. Permit to Drill Number 203-198 13. API Number 50- 029-23186-00-00 14. Well Name and Number: PBU 5-120 15. Field I Pool(s): Prudhoe Bay Field I Aurora Pool 16. Property Designation: ADL 028258 17. Land Use Permit: 20. Thickness of Permafrost 1900' (Approx.) 42" 260 sx Arctic Set (Approx.) 12-1/4" 550 sx Arctic Set Lite PF, 293 sx 'G' 8-314" 151 sx Litecrete, 159 sx Class 'G' 24. SIZE 4-1/2", 12.6#, L-80 TUBING RECORD DEPTH SET (MD) 7914' PACKER SET (MD) 7853' DEPTH INTERVAL (MD) 2200' AMOUNT & KIND OF MATERIAL USED Freeze Protected with 85 Bbls of Diesel Not on Production I Injection Yet PRODUCTION TEST Method of Operation (Flowing, Gas Lift, etc.): NIA Oll-BBl GAs-McF WATER-BBl Date of Test Hours Tested PRODUCTION FOR TEST PERIOD ... Flow Tubing Casing Pressure CALCULATED ........ Press. 24-HoUR RATE"'" Oll-Bsl GAs-McF W A TER-Bsl CHOKE SIZE I GAS-Oil RATIO Oil GRAVITY-API (CORR) 27. CORE DATA n r f"'" r ~ \ p-' r',,\ Brief description of lithology, porosity, fractures, apparent dips and presence of oil, ~~~~,.J:tM:J·~Þaf.ate sheet, if necessary). Submit core chips; if none, state "none". rC(^::'r7¡;¡~,¡~~f~iGi¡& 1 None ~¡1: \ -~r Form 10-407 Revised 12/2003 -=- eft. 1U~ () 8 lGß~ Ala:;ka O¡I JUN 022004 CONTINUED ON REVERSE SIDE ORtG1NAL t, P 28. e GEOLOGIC MARKERS - 29. FORMATION TESTS NAME MD TVD Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". Ugnu 4598' Ugnu M Sands 6160' Schrader Bluff N 6326' Schrader Bluff 0 6446' Base Schrader I Top Colville 6761' HRZ 8022' Kalubik 8049' Kuparuk C 8051' Kuparuk B 8150' Kuparuk A 8242' Miluveach 8303' 3621' None 4783' 4929' 5040' 5336' 6551' 6578' 6580' 6677' 6768' 6828' J\JN 0 ~~ '2004 30. List of Attachments: Summary of Daily Drilling Reports and Post Rig work, Well Schematic Diagram, Surveys 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed TerrieHubble/fP'MLP ~ Title Technical Assistant Date {J...o"'O~ "'O<{ PBU S-120 203-198 Prepared By Name/Number: Terrie Hubb/e, 564-4628 Well Number Drilling Engineer: Jim Smith, 564-5773 Permit No. I Approval No. 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. ITEM 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. ITEM 4b: TPI (Top of Producing Interval). ITEM 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. ITEM 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). ITEM 20: True vertical thickness. ITEM 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). ITEM 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). ITEM 27: If no cores taken, indicate "None". ITEM 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 5-120 S-120 Legal Name: Common Name 4.00 (ppg) 2,118 (psi 650 (psi 9.70 (ppg) 2,913.0 (ft) 3,565.0 (ft) LOT e - 9:13:33 AM /5/2004 Printed: e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-120 S-120 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 7ES Start: Rig Release: Rig Number: 12/20/2003 1/2/2004 Spud Date: 12/21/2003 End: 1/2/2004 12120/2003 02:30 - 12:00 9.50 MOB N WAIT PRE Held PJSM. Changed Out Saver Sub, Gripper Blocks and Guide on Top Drive. Serviced Top Drive and Blocks. R I U Kelly and Blower Hose. Changed Out Bails and R I U 5" Pipe Elevators. Changed Pump Liners from 5" to 5.5", Replaced Clipper Seals on Pony Rods. Pressure Tested Spare Saver Sub and Safety Valves. Installed New Cable on Both Tuggers. 12:00 - 14:00 2.00 MOB N WAIT PRE Held PJSM. Removed Snow from Under Pit Module and Camp For Truck and Cable Access. Wind Speed Diminished and Allowed for Crane Pick. Held GPB Reflection and Focus on Safety Meeting wI Both Crews and Service Companies. Note: Waited on Wind Speed to Diminish Over Last 9 days for Removal of S-213 Well house Prior to Move onto S-120. 14:00 - 15:00 1.00 MOB N WAIT PRE Held PJSM. Crane Removed Wellhouse from S-213. 15:00 - 00:00 9.00 MOB P PRE RID Pit Module Connections from Sub Base. Set Mats Over S-120 Cellar. Removed Snow and Leveled Location. Set Mats on Location for Sub Base. Broke Apart Rig Modules. Moved Pits Ahead 5' to Clear Sub. Prepared to Move Rig. 12/21/2003 00:00 - 00:30 0.50 MOB P PRE Held Pre-Spud Meeting w/ Drilling Crew, Service Companies, Toolpusher and Drilling Supervisor. 00:30 - 06:30 6.00 MOB P PRE Held PJSM. Backed Sub Base Off of S-116. Matted Location Around S-120. Laid Herculite Over Mats. Loaded Cellar wI Tree, Wellheads, DSA, 7" Rams. Moved and Spotted Sub Over S-120. Spotted Pit Module and Began Rigging Up Connections. 06:30 - 09:00 2.50 RIGU N SFAL PRE Dug Out Conductor, Attempted to N / U Starter Head and 20" Riser. Landing Ring on 20" Conductor Out of Round. PI U 9-5/8" Hanger, Attempted to Stab Hanger into Landing Ring without Success. Heated Landing Ring w/ a Torch and Re-Shaped Landing Ring. Rig Accept 0630 hrs 12 I 21 I 2003 09:00 - 12:00 3.00 RIGU P PRE N I U Starter Head and 20" Riser. 12:00 - 12:30 0.50 RIGU P PRE Held Pre-Spud Meeting wI Drilling Crew, Service Companies, Toolpusher and Drilling Supervisor. 12:30 - 14:00 1.50 RIGU P PRE Finished N I U Riser and Air Boot. Measured RKB's. Connected Cement Valves on Conductor. 14:00 - 18:00 4.00 DRILL P SURF Conditioned Spud Mud in Pits. Loaded BHA Components in Pipe Shed. Brought Smaller BHA Components to Rig Floor. 18:00 - 20:00 2.00 EVAL P SURF Held PJSM. R I U Sheaves and Wireline f/ Gyro Tools. M I U Gyro Tools. 20:00 - 21 :00 1.00 DRILL P SURF P / U 1 Stand of 5" HWDP and RIH, Tagged Up at 30'. POOH. M I U HTC 12-1/4" MXC-1, Bit Sub and XO onto 1 Stand of 5" HWDP. 21 :00 - 21 :30 0.50 DRILL P SURF RIH to 30', Drilled Ice Plug, Junk and Cement Out of Conductor from 30' to 99'. WOB 5,000#, RPM 40, Torque 1,000 ft Ilbs, Pump Rate 350 gpm, 200 psi. Circulated Out, Ice, Wood, Plastic and Cement. 21 :30 - 22:00 0.50 DRILL P SURF POOH, Broke Off and L / D 12-1/4" Bit and Subs. 22:00 - 00:00 2.00 DRILL P SURF Held PJSM. M / U BHA #1: 12-114" HTC MXC-1 Bit, Ser# 5040964, dressed wI 1 x14, 3x18 jets - 9-5/8" Motor wI 1.83 deg Printed: 1/5/2004 9: 13:43 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-120 S-120 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 7ES Start: Rig Release: Rig Number: 12/20/2003 1/2/2004 Spud Date: 12/21/2003 End: 1/2/2004 12121/2003 22:00 - 00:00 2.00 DRILL P SURF Bent Housing - Float Sub - 2 x 10' Non Mag Pony Collars - 12.25" Near Bit Stabilizer - MWD - Orienting Sub - Non Mag XO. Total BHA Length - 92.14'. Oriented MWD and Motor, Checked Orientation wI Gyro. 12/22/2003 00:00 - 01 :30 1.50 DRILL P SURF Held PJSM. Drilled 12-1/4" Hole from 99' to 271'. WOB 2,000# - 10,000#, RPM 80, Motor RPM 121, No Torque, Pump Rate 550 gpm, SPP 450 psi. Circulated Bottoms Up, Pump Rate 550 gpm, SPP 450 psi. Took Survey. POOH to UBHO Sub for Additional BHA Components. 01 :30 - 03:00 1.50 DRILL P SURF Held PJSM. M I U Additional Drill Collars, Stabilizer and Jars. BHA #1 now consists of: 12-1/4" HTC MX-C1 Bit, Ser# 5040162, dressed w/1x14, 3x18 jets - 9-5/8" Motor wI 1.83 deg Bent Housing - Float Sub - 2 x 10' Non Mag Pony Collars - 12.25" Non Mag Stabilizer - MWD - Orienting Sub - 12.25" Non Mag Stabilizer - Non Mag Drill Collar - Non Mag XO - Non Mag Drill Collar - 8.75" Non Mag Stabilizer - Non Mag Drill Collar - Saver Sub - Hyd Jars. Total BHA Length - 230.68'. RIH wlBHA #1 to 271'. 03:00 - 03:30 0.50 DRILL P SURF Drilled 12-1/4" Hole from 271' to 290'. WOB 2,000# -10,000#, RPM 80, Motor RPM 121, No Torque, Pump Rate 550 gpm, SPP 450 psi. 03:30 - 04:00 0.50 DRILL P SURF Ran Gyro Survey. 04:00 - 06:00 2.00 DRILL P SURF Directionally Drilled 12-1/4" by Rotating and Sliding from 290' to 468'. WOB Sliding 15,000# - 20,000#, WOB Rotating 5,000#- 15,000#, RPM 80, Motor RPM 121, Torque On Bottom 1,000 ft Ilbs, Torque Off Bottom 1,000 ft Ilbs, Pump Rate 550 gpm, SPP On Bottom 900 psi, SPP Off Bottom 900 psi. String Weight Up 50,000#, String Weight Down 50,000#, String Weight Rotating 50,000#. Slide Sheet Depth Tool Face 290' - 340' 274.0 - M 379' - 430' 280.0 - M 06:00 - 06:30 0.50 DRILL P SURF Ran Gyro Survey. 06:30 - 11 :00 4.50 DRILL P SURF Directionally Drilled 12-1/4" by Rotating and Sliding from 468' to 919'. WOB Sliding 20,000# - 25,000#, WOB Rotating 10,000#- 12,000#, RPM 80, Motor RPM 121, Torque On Bottom 2,500 ft Ilbs, Torque Off Bottom 1,500 ft Ilbs, Pump Rate 550 gpm, SPP On Bottom 1,000 psi, SPP Off Bottom 900 psi. String Weight Up 75,000#, String Weight Down 75,000#, String Weight Rotating 75,000#. AST = 3.36 hrs, ART = 1.74 hrs. Slide Sheet Depth Tool Face 468' - 520' 280.0 - M 557' - 630' 290.0 - M 643' - 723' 15.0 R 737' - 807' 30.0 R 828' - 895' 15.0 L 11 :00 - 11 :30 0.50 DRILL P SURF Circulated 3 x Bottoms Up, Pump Rate 550 gpm, SPP 1,000 psi. 11:30 - 12:00 0.50 DRILL P SURF Ran Gyro Survey. 12:00 - 13:30 1.50 DRILL P SURF Held PJSM. POOH to Bit. 13:30 - 14:30 1.00 EVAL P SURF Held PJSM. R / D Gyro Equipment. Printed: 1/5/2004 9:13:43 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-120 S-120 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 7ES Start: Rig Release: Rig Number: 12/20/2003 1/2/2004 Spud Date: 12/21/2003 End: 1/2/2004 12122/2003 14:30 - 15:00 0.50 DRILL P SURF Flushed and Drained Motor. M I U New HTC 12-1/4" MXC-1 Bit Ser# 5040162 w/1 x 14 - 3 x 18 Jets. Removed Orienting Sub from BHA. 15:00 - 16:00 1.00 DRILL P SURF Changed Out Saver Sub wI 4-1/2" IF Threads fl Saver Sub wI 4" HT -40 Threads. 16:00 - 17:30 1.50 DRILL P SURF RIH wlBHA to 919', No Fill. 17:30 - 18:00 0.50 DRILL P SURF Changed Out 5" Elevators f/ 4" Elevators. 18:00 - 00:00 6.00 DRILL P SURF Directionally Drilled 12-1/4" by Rotating and Sliding from 919' to 1,562'. WOB Sliding 30,000# - 40,000#, WOB Rotating 25,000# - 30,000#, RPM 85, Motor RPM 121, Torque On Bottom 4,000 ft /Ibs, Torque Off Bottom 2,000 ft /Ibs, Pump Rate 550 gpm, SPP On Bottom 1,400 psi, SPP Off Bottom 1,200 psi. String Weight Up 75,000#, String Weight Down 70,000#, String Weight Rotating 75,000#. AST = 3.07 hrs, ART = 1.17 hrs. Slide Sheet Depth Tool Face 919' - 978' 25.0 L 1,013' - 1,063' 10.0 R 1,109 -1,144' HS 1,205' - 1,245' 30.0 L 1,300 - 1,360' 30.0 L 1,396' - 1,456' 30.0 L 1,492 - 1,562' 20.0 L 12/23/2003 00:00 - 14:30 14.50 DRILL P SURF Directionally Drilled 12-1/4" by Rotating and Sliding from 2250' to 3580'. WOB Sliding 35,000# - 40,000#, WOB Rotating 20,000# - 30,000#, RPM 80, Motor RPM 121, Torque On Bottom 6,500 ft /Ibs, Torque Off Bottom 4,500 ft Ilbs, Pump Rate 608 gpm, SPP On Bottom 2,500 psi, SPP Off Bottom 2,300 psi. String Weight Up 100,000#, String Weight Down 65,000#, String Weight Rotating 90,000#. AST = 2.85 Hrs. ART = 6.65 Hrs. 14:30 - 16:00 1.50 DRILL P SURF Circulate and condition mud. CBU. 16:00 - 18:30 2.50 DRILL P SURF POH for wiper trip to 919' Last bit trip. Tight hole at 2352'. Tight & Swabbing @ 1815', Pump out to 1684'. Ok from there to HWDP. 18:30 - 22:00 3.50 DRILL P SURF Run back in Hole. Stopped @ 1755'. Screwed in TD and reamed to 1815'. RIH - Tight @ 1964' & 2450'. Worked through without TD. precautionary wash last 80' to bottom @ 3580'. 22:00 - 00:00 2.00 DRILL P SURF Circulate Hole Clean & Condition Mud @ 620 GPM & 100 RPM. 12/24/2003 00:00 - 01 :30 1.50 DRILL P SURF Circulate 3X bottoms up @ 620 GPM & 100 RPM while Conditioning Mud. 01 :30 - 05:00 3.50 DRILL P SURF POH to Drill Collars with no problems. 05:00 - 06:00 1.00 DRILL N RREP SURF Repair Skate - Sprocket was mis-alligned. Straightened Same. 06:00 - 09:00 3.00 DRILL P SURF Stand back DC's. LID remaining BHA. Clear & Clean Floor. 09:00 -11:15 2.25 CASE P SURF Rlu to run 9 5/8" Surface Casing. Make Dummy run w/ Landing Jt & Hanger. 11:15 -11:45 0.50 CASE P SURF PJSM for Running Casing. 11:45 - 18:00 6.25 CASE P SURF Run 86 Jts, 9 5/8", 40#, L-80, BTC Casing as per program. Shoe @ 3566', Float collar@ 3479'. 18:00 - 20:30 2.50 CEMT P SURF Circulate & Condition Mud for cement Job. Stage up to 10 BPM @ 560 psi. Reciprocate Csg 10'. Printed: 1/5/2004 9:13:43 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-120 S-120 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 7ES Start: Rig Release: Rig Number: 12/20/2003 1/2/2004 Spud Date: 12/21/2003 End: 1/2/2004 12124/2003 20:30 - 21 :00 0.50 CEMT P SURF RID Franks Tool & RlU Cement Head. 21 :00 - 22:30 1.50 CEMT P SURF Continue C & C Mud to a 64 Viscosity & a YP of 20. Held PJSM's wI Dowell, Rig Crew & Veco Vac Truck Drivers. 22:30 - 00:00 1.50 CEMT P SURF Switch Manifold over to Dowell: Pump 5 Bbls Water & Test lines to 3500 psi. Pum 25 bbls CW-100 @ 8.37 ppg. & 6.5 BPM. Pump 75 bbls. MUDPUSH Spacer @ 10.5 ppg. & 5 BPM. Drop Bottom Plug. Mix & Pump 435 bbls, 550 sks, 4.44 yield, 10.7 ppg, ARCTICSET Lite III Lead Slurry @ 7.5 BPM. 12/25/2003 00:00 - 01 :30 1.50 CEMT P SURF Continue Cement Job. Mix & Pump 61 bbls, 293 sks, 1.17 yield, 15.8 ppg, Class "G" Tail Slurry @ 5 BPM. Drop Top Plug. Chase plug w/1 0 Bbls Water from Dowell to clear lines. Switch back over to Rig & pump 255 bbls Mud to Bump Plug. Final displacement pressure = 604 psi. Reciprocated casing 10ft. 100 % Returns throughout Job Approximately 117 bbls good 10.7 ppg Lead Cement to Surface. 01 :30 - 02:00 0.50 CASE P SURF Pressure Casing up to 3500 psi and hold for 30 minute Casing Test while monitoring for flow. Good test. Bleed off & check Floats - OK. 02:00 - 03:30 1.50 CEMT P SURF RID Cement Head, back out & UD Landing Jt. 03:30 - 04:00 0.50 CEMT P SURF Wash & Clean Cement from cellar & lines. 04:00 - 05:15 1.25 CASE P SURF NID Riser and surface equipment. 05: 15 - 07:00 1.75 WHSUR P PROD1 N/U FMC Big Bore lower Split UniHead. Test Metal to Metal Seal to 1000 psi. 07:00 - 09:00 2.00 BOPSURN SFAL PROD1 Landing Ring 3" Higher than S-116. Had to remove studs from DSA in order to clear Well Head with BOPE. 09:00 - 14:00 5.00 BOPSUR P PROD1 NIU BOP, Install turnbuckles. Hang Tree in corner of cellar. 14:00 - 15:00 1.00 BOPSURN SFAL PROD1 Had to cut Bell Nipple to Fit. 15:00 - 21 :00 6.00 BOPSURP PROD1 Test BOPE to 250 psi. Low & 4000 psi High. Annular to 3500 psi. High. Witness waived by AOGCC. 21 :00 - 21 :30 0.50 BOPSURP PROD1 Pull Test Plug & Install Wear Bushing. 21 :30 - 22:30 1.00 DRILL P PROD1 PIU 15 Jts 4", HT -40 DP & Stand back in Derrick. 22:30 - 00:00 1.50 DRILL P PROD1 CIO Elevators to 5" & PIU BHA # 3. 12/26/2003 00:00 - 01 :30 1.50 DRILL P PROD1 Continue M/U BHA #3. RIH wi HWDP 01 :30 - 04:00 2.50 DRILL P PROD1 PIU 4" DP from Shed & RIH to 2750'. 04:00 - 04:30 0.50 DRILL P PROD1 Service Top Drive. 04:30 - 05:00 0.50 DRILL P PROD1 Test MWD - OK 05:00 - 06:00 1.00 DRILL P PROD1 PIU 4" DP from Shed & RIH to 3381'. 06:00 - 08:30 2.50 DRILL P PROD1 Wash down to Plugs @ 3480'. Drill Plugs & Cemented Shoe Track. Clean out Rat Hole to 3580". Drill new Hole to 3600'. 08:30 - 09:30 1.00 DRILL P PROD1 Displace Hole with 9.7 ppg New LSND Mud @ 565 GPM & 1575 psi. 09:30 - 10:30 1.00 DRILL P PROD1 Perform LOT. TVD = 2913'. Mud Wt. = 9.7 ppg. Leak - Off Pressure = 650 psi. LOT = 14.0 ppg. EMW. Perform ECD Baseline Test & take SPR's. 10:30 - 00:00 13.50 DRILL P PROD1 Drilled 8 3/4" Directional Hole from 3600' to 5933'. Pumping @ Printed: 1/5/2004 9: 13:43 AM - e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-120 S-120 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 7ES Start: Rig Release: Rig Number: 12/20/2003 1/2/2004 Spud Date: 12/21/2003 End: 1/2/2004 12/26/2003 10:30 - 00:00 13.50 DRILL P PROD1 535 to 580 GPM. Drilling @ 5933', the following parameters apply: On bottom circ pressure = 2450 psi. Off bottom circ pressure = 2150 psi. Torque on bottom = 9500 ftIlbs. Torque off bottom = 8000 ftIlbs. Pick Up Wt. = 145K, Down Wt. = 95K, Rotating Wt. = 11 OK RPM = 80, WOB = 1 OK to 20K ECD = 10.83 ppg. wI Calculated ECD = 10.38 ppg. Hi Vis Sweeps every 300' to 400'. ART = 5.79 Hrs. AST = 1.85 Hrs. 12/27/2003 00:00 - 21 :00 21.00 DRILL P PROD1 Drilled 8 3/4" Directional Hole from 5933' to 8360', TD. Pumping @ 580 GPM. Drilling @ 8360', the following parameters apply: On bottom circ pressure = 3800 psi. Off bottom circ pressure = 3500 psi. Torque on bottom = 11,500 ftIlbs. Torque off bottom = 10,400 ftIlbs. Pick Up Wt. = 190K, Down Wt. = 125K, Rotating Wt. = 145K RPM = 100, WOB = 20K ECD = 11.03 ppg. w/ Calculated ECD = 10.63 ppg. Hi Vis Sweeps every 300' to 400'. 21 :00 - 22:00 1.00 DRILL P PROD1 Circulate & Conditon Hole for Wiper Trip. After confering with ANC. Geoloogical Team: It was decided to make additional footage. 22:00 - 23:00 1.00 DRILL P PROD1 Drilled Ahead 80' to 8440' with same drilling parameters. Daily ART = 10.5 Hrs. AST = 2.69 Hrs. 23:00 - 00:00 1.00 DRILL P PROD1 Circuate Hi - Vis Sweep around. Calculated ECD = 10.64 ppg. Actual ECD = 10.90 ppg. 12/28/2003 00:00 - 00:30 0.50 DRILL P PROD1 Complete C&C in preparation for Wiper Trip. 00:30 - 03:30 3.00 DRILL P PROD1 POH on Wiper to 5039'. Hole attempting to Swab. Work pipe up to 4656'. Unable to POH further without swabbing. 03:30 - 05:00 1.50 DRILL P PROD1 Pump out of Hole to Shoe @ 3565'. No overpull. 05:00 - 06:00 1.00 DRILL P PROD1 CBU @ Casing Shoe. 06:00 - 07:30 1.50 DRILL P PROD1 Slip & Cut 111' of Drilling Line. High winds complicated job. 07:30 - 10:00 2.50 DRILL P PROD1 RIH to 8386' with no problems. 10:00 - 12:00 2.00 DRILL P PROD1 Precautionary Wash to TD @ 8440' - No Fill. Circulate Hole clean & Condition mud. - 580 GPM @ 3600 psi. Rotate @ 100 RPM while Reciprocating. 12:00 - 16:30 4.50 DRILL P PROD1 POH to BHA. Hole in great shape - No Drag, Hole taking proper displacement. 16:30 - 18:30 2.00 DRILL P PROD1 UD BHA # 3. Monitor Well - Static. Clear & Clean rig Floor. 18:30 - 20:00 1.50 EVAL P PROD1 Load Pipe shed wI SWS Tools, PJSM wI rig Crew & SWS, RlU SWS E-Line. 20:00 - 00:00 4.00 EVAL P PROD1 LOG PEX / BHC Sonic from TD @ 8440 to 9 5/8" Casing Shoe @ 3565'. 12/29/2003 00:00 - 01 :00 1.00 EVAL P PROD1 Lay Down Logging Tools and rig down Schlumberger Eline. 01 :00 - 03:30 2.50 BOPSURP COMP Change out Top Rams to T. Test Door Seals to 300/3500 psi. 03:30 - 05:30 2.00 CASE P COMP Rig up to run 7" Production Casing. Make Dummy Run with Landing Joint and Hanger. PJSM with Rig Crew and casing crew. Printed: 1/5/2004 9:13:43AM e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-120 S-120 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 7ES Start: Rig Release: Rig Number: 12/20/2003 1/2/2004 Spud Date: 12/21/2003 End: 1/2/2004 12129/2003 05:30 - 06:00 0.50 CASE P COMP Make up Float Shoe Joint, 1 Jt of 7" Casing and Float Collar Joint. Filled Casing and Checked Float Equipment, OK. Thread lock all connections on shoe track. 06:00 - 11 :30 5.50 CASE P COMP Run 7" 26.0#, L-80, BTC Casing to 3516' just above 9 5/8" casing shoe. Filled every joint. String weight 98K up, 78K down. 11:30-15:00 3.50 CASE N WAIT COMP Stop casing running operation. Circulate at 3516'. Circulate at 3 BPM with 375 psi. Weather condition deteriorating as the wind speed increases. The loader operator having difficulty maneuvering around the snow drifts on the pad with very poor visibility. Also having difficulty finding the casing on the outside racks as pipe becomes buried in the drifts. Load all 7" casing from outside racks into pipe shed. 15:00 - 00:00 9.00 CASE N WAIT COMP Wait on weather. Weather conditions down graded to Phase 3. Reduce pumping to 5 bbl every 20 minutes to reduce wear on fill up tool valve and to prevent mud lines from freezing. 12/30/2003 00:00 - 05:00 5.00 CASE N WAIT COMP Phase 3 Driving Conditions field wide. 05:00 - 07:30 2.50 CASE N WAIT COMP Phase 2 on Spine. Phase 3 on all access roads & Pads. Called immediately and got High Priority wI Roads & Pads. Sent Blower out right away to clear Pad & Access Road. Ready to proceed with Casing @ 07:30. 07:30 - 16:00 8.50 CASE P COMP Run Total of 185 Joints -7",26#, L-80, BTC-M Casing. Shoe @ 8425', Float collar @ 8338', 20' Marker Jts. wI RA Pip Tags @ 8277' & 8041'. Circulated down 3 Jts every 20 Run. No losses to Hole. 16:00 - 19:30 3.50 CEMT P COMP Circulate & Condition Mud for Cement Job. Vis = 57, PV = 17 YP - 18, Gels = 5 /11. Stage pumps up to 7 BPM @ 604 psi. 19:30 - 22:30 3.00 CEMT P COMP Switch to Dowell & Cement as Follows: Pump 5 bbls water & pressure test to 4000 psi. Leak in Rig Cement Line. Fix leak & re-test to 4000 psi. - OK. Pump 20 Bbls CW-100 @ 8.5 ppg. Batch Mix & Pump 35 bbls, 11.1 ppg, MudPush Spacer. Drop Bottom Plug Mix & Pump 66 Bbls (150 sX), 12.0 ppg, 2.46 ft3/sk, Lite Crete Slurry @ 6 BPM. Batch Mix & Pump 34 Bbls ( 158 sX), 15.8 ppg, 1.2 ft3/sk yield, 'G' Slurry @ 6 BPM. Flush Dowell lines to Floor. Drop Top Plug. Displace with 320 Bbls Filtered Seawater ww/ Rig pumps. Pumped @ 6 to 7 BPM. - Last 10 Bbls @ 3 BPM. Final circ pressure = 1010 psi. Bumped plug w/1600 psi. Pumped up to 4000 psi to test Casing - dripping leak @ XO to Cement head. Bleed pressure - Floats holding. Recirocated casing 15 ft. throughout Job. 100 % Returns. Up Wt = 265K, Dn. Wt = 115K 22:30 - 23:30 1.00 CEMT P COMP RID Cement manifold & Landing Jt. 23:30 - 00:00 0.50 WHSUR P COMP P/U Jt of HWDP, Make up Running Tool & Pack-off. Run in & install Same. Printed: 1/5/2004 9: 13:43 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-120 S-120 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 7ES Start: Rig Release: Rig Number: 12/20/2003 1/2/2004 Spud Date: 12/21/2003 End: 1/2/2004 12131/2003 00:00 - 00:30 0.50 WHSUR P COMP R.I.L.D.S. On 7" Pack-off & Test to 5000 psi. - OK. 00:30 - 01 :30 1.00 CASE P COMP Test 7" Casing under Blind Rams for 30 Minutes - Good Test. 01 :30 - 03:00 1.50 RUNCOMP COMP Change out Top Rams to 3.5" X 6" Variables. Test Door Seals to 3500 psi. 03:00 - 04:30 1.50 RUNCOMP COMP LID 7" Elevators. Rig up to Run 4.5 " Completion String. 04:30 - 04:45 0.25 RUNCOMP COMP PJSM wI Rig Crew, Casers & Baker hand. 04:45 - 15:00 10.25 RUNCOMP COMP Run 4.5" Completion String as per Program. Problem with make up - not getting proper seal per Torque -Turn Computer graph. Inspected threads. Noticed that pin ends appear to have some over spray of the exterior Jt. protective coating. Hooked up hand grinder with steel wire brush wheel and cleaned pins. Did not work on all joints and replaced if 2nd. MIU attempt failed. 15:00 - 00:00 9.00 RUNCOMN SFAL COMP Continue to Run 4.5" Completion string. NPT - Would have run string in 9 to 10 Hrs without the over spray problem. 18 jts laid down & 6 collars replaced at Report Time. 1/1/2004 00:00 - 04:30 4.50 RUNCOMN SFAL COMP Continue to run 4.5" TC-II Completion. Problems with connections the same. Total 28 Jts out. 6 collars replaced. Total 185 Jts Ran. 04:30 - 06:00 1.50 RUNCOMP COMP M/U Hanger & landing Jt. Reverse Circulate 56 Bbls corrosion inhibited Seawater, followed by 90 Bbls. Filtered Seawater - spotting the corrosion inhibited brine from the upper GLM @ 4857 to the Packer @ 7853. 06:00 - 07:00 1.00 RUNCOMP COMP Land Hanger in Tubing Head. Drop BallI Rod Assy. R.I.L.D.S. 07:00 - 09:00 2.00 RUNCOMP COMP Test Secondary Kill Line to 4000 psi. Pressure down Tubing to 4200 psi to set Premier Packer. Hold & Chart for 30 minute Test. Bleed Tubing to 2800 psi. then pressure 4.5" X 7" Annulus to 4000 psi.; Hold & Chart for 30 minute Test. Bleed off Annulus to '0' then Tubing to '0'. Pressure Annuls to 2800 psi to shear DCK Valve. Pump through both ways to confirm shear. Packer set @ 7853', WLEG @ 7913', GLM #1 @ 7722', GLM #2 @ 4857', SV'X' Nipple @ 2207'. 09:00 - 09:30 0.50 WHSUR P COMP Set TWC wI Dry Rod. Test from below to 1000 psi 09:30 - 10:30 1.00 WHSUR P COMP Clear & Clean Rig Floor. 10:30 - 14:00 3.50 WHSUR P COMP NID BOPE. Remove Stack & set back. Remove Spool & DSA. 14:00 - 17:00 3.00 WHSUR P COMP NIU Adapter Flange & Tree. Test both to 5000 psi. 17:00 - 17:30 0.50 WHSUR P COMP RlU DSM Lubricator. Pull TWC. NID DSM Lubricator. 17:30 - 20:00 2.50 WHSUR P COMP RlU Little Red. Test Lines to 3000 psi. Reverse circulate 85 bbls Diesel down 4.5" X 7" Annulus. Shut in and allow to U-Tube into Tubing - Freeze protecting to 2200' TVD (2560' MD). 20:00 - 21 :00 1.00 WHSUR P COMP RlU DSM Lubricator. Set BPV. Test from below to 1000 psi. RID DSM & U-Tube Equipment. 21 :00 - 22:30 1.50 WHSUR P COMP Remove Secondary valve from 7" X 9 5/8" Annulus. Install guages on Upper & Lower Annulus Valves. Secure Cellar for Rig Move. 22:30 - 23:00 0.50 RIGD P COMP Rid Long Bails & RlU Short Bails. 23:00 - 00:00 1.00 RIGD P COMP Move HWDP & 7 Stands of 4" DP to DS. LID 4" DP in Mouse Hole. 1/2/2004 00:00 - 04:00 4.00 RIGD P COMP Lay down all excess DP. Will leave max. allowed racked back for move. Secure cellar and tree. Printed: 1/5/2004 9:13:43 AM e e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: S-120 S-120 DRILL +COMPLETE NABORS ALASKA DRILLING I NABORS 7ES Start: 12/20/2003 Rig Release: 1/2/2004 Rig Number: Spud Date: 12/21/2003 End: 1/2/2004 1/2/2004 00:00 - 04:00 4.00 RIGD P COMP RIG RELEASED @ 04:00 HRS, 01/02/2004 Printed: 1/5/2004 9:13:43 AM e e S-120 Prudhoe Bay Unit 50-029-23186-00-00 203-198 Accept: Spud: Release: POST RIG WORK 12/21/03 12/22/03 01 /02/04 Nabors 7ES 04/10/04 MOVE IN SPOT EQUIPMENT, INSPECT LOCATION. TGSM, WORK ON MAKING JSA AND RIU PROCEDURE WHILE R/U. REDRESS STUFFING BOX, FINSH RIU, RIH WI 3.6" BIG & 2" JDC. 04/11/04 RUN BAILERS. PULL BPV. PULLED B&R FROM RHC-M @ 7872' SLM. PULLED 1" DCK FROM STA #2 @ 4843' SLM. SET 1" OGLV (24/64" PORTS) IN STA #2 @ 4843' SLM. PULLED RHC FROM X NIPPLE @ 7869' SLM. DRIFT W/3 3/8" DUMMY GUN. TAG DEPTH 8296'SLM - NOT CORRECTED. TURN WELL OVER TO DSO - WELL LEFT SHUT IN. 04/16/04 US IT CEMENT BOND LOG RAN FROM 8280' TO TBG TAIL AT 7907'. GOOD CEMENT THROUGHOUT WITH EXCEPTION OF GAS CUT CEMENT FROM 8050'-8150'. TAG TAD AT 8316'. PAD OPERATOR NOTIFIED TO LEAVE WELL SHUT IN. 04/30/04 PERFORATED 8052'-8077',8084'-8114',8166'-8178' AND 8252'-8264' WITH 3 3/8" 3406 POWER JET 6 SPF, 38.6" PENE, 0.45" EH, 22.7 GMS. REFERENCED TO SWS PEX 28-DEC-03. WELL SHUT IN. e e 5-120 Survey Report umberger Report Date: 28-Dec-04 Survey / OlS Computation Method: Minimum Curvature / Lubinski Client: BP Exploration Alaska Vertical Section Azimuth: 283.690' Field: Prudhoe Bay Unn . WOA Vertical Section Origin: N 0.000 h, E 0.000 h Structure / Slot: S-PAD / Slot 4 rVD Reference Datum: KB Well: S-120 TVD Reference Elevation: 64.35 h relative to MSL Borehole: S-120 Sea 8ed I Ground level Elevation: 35.80 h relative to MSL UWYAPI#: 500292318600 Magnetic Declination: 25.282' Survey Name I Date: S·120 / December 28, 2003 Total Field Strength: 57566.816 nT Tort I AHD / 0011 ERO ratio: 119.452" /4157.74 h /5.780 / 0.597 Ma9netic Dip: 80.856" Grid Coordinate System: NAD27 Alaska State Planes. Zone 04, US Feet Declination Date: December 25, 2003 Location latILong: N 70 21 19.991, W 14922.945 Magnetic Declination Model: BGGM 2003 Location Grid NIE YIX: N 5980564.330 hUS. E 618930.210 hUS North Reference: True North Grid Convergence Angle: +0.90964295' Total Corr Ma9 North -> True North: +25.282" Grid Scale Factor: 0.99991607 Local Coordinates Referenced To: Well Head Measured I Inclination I Azimuth I TVD I Sub-Sea TVO I Vertical I Along Hole I NS EW I DlS I Build Rate I Walk Rate I Northing Easting lat~ude long~ude Depth Section Departure (ft) (<leg) (de9) (ft) (ft) (ft) (ft) (ft) (ft) (deg/1ooft) (deg/1ooft) (deg/1OOh) (hUS) (hUS) 0.00 0.00 0.00 0.00 -64.35 0.00 0.00 0.00 0.00 0.00 0.00 0.00 5980564.33 618930.21 N 7021 19.991 W 14922.945 100.00 0.44 260.37 100.00 35.65 0.35 0.38 -0.06 -0.38 0.44 0.44 0.00 5980564.26 618929.83 N 70 21 19.991 W 14922.956 200.00 0.64 262.56 199.99 135.64 1.23 1.33 -0.20 -1.31 0.20 0.20 2.19 5980564.11 618928.90 N 7021 19.989 W 14922.984 300.00 0.98 264.48 299.98 235.63 2.55 2.74 -0.36 -2.72 0.34 0.34 1.92 5980563.93 618927.50 N 7021 19.988 W 14923.025 400.00 1.99 260.80 399.95 335.60 4.96 5.33 -0.72 -5.28 1.01 1.01 -3.68 5980563.53 618924.94 N 7021 19.984 W 14923.100 500.00 3.13 266.98 499.85 435.50 9.18 9.79 -1.14 -9.72 1.17 1.14 6.18 5980563.04 618920.51 N 7021 19.980 W 14923.229 600.00 4.79 278.91 599.61 535.26 15.95 16.67 -0.63 -16.57 1.84 1.66 11.93 5980563.43 618913.65 N 7021 19.985 W 14923.430 700.00 8.03 288.20 698.97 634.62 27.08 27.81 2.20 -27.34 3.39 3.24 9.29 5980566.09 618902.84 N 7021 20.013 W 14923.744 753.00 10.31 286.74 751.29 686.94 35.51 36.26 4.72 -35.40 4.32 4.30 -2.75 5980568.48 618894.75 N 7021 20.038 W 14923.980 842.50 13.18 290.56 838.91 774.56 53.64 54.47 10.61 ·52.62 3.32 3.21 4.27 5980574.10 618877.43 N 7021 20.096 W 14924.484 937.68 16.58 283.79 930.89 866.54 78.00 78.88 17.66 -75.98 4.01 3.57 -7.11 5980580.78 618853.97 N 7021 20.165 W 14925.166 1032.63 19.46 289.54 1021.18 956.83 107.29 108.23 26.18 -104.05 3.56 3.03 6.06 5980588.85 618825.77 N 7021 20.249 W 14925.987 1128.32 20.72 287.74 1111.05 1046.70 140.03 141.10 36.67 -135.20 1.47 1.32 -1.88 5980598.85 618794.46 N 7021 20.352 W 14926.897 1224.95 21.86 286.04 1201.08 1136.73 175.06 176.18 46.85 -168.77 1.34 1.18 ·1.76 5980608.49 618760.73 N 7021 20.452 W 14927.879 1320.30 23.77 285.69 1288.97 1224.62 212.01 213.15 56.95 -204.33 2.01 2.00 -0.37 5980618.03 618725.02 N 70 21 20.551 W 14928.918 1416.30 25.97 284.62 1376.06 1311.71 252.36 253.52 67.49 -243.30 2.34 2.29 -1.11 5980627.95 618685.89 N 7021 20.655 W 149210.058 1512.13 29.38 282.18 1460.92 1396.57 296.86 298.02 77.75 -286.60 3.75 3.56 -2.55 5980637.51 618642.44 N 70 21 20.756 W149211.323 1609.09 32.25 281.92 1544.18 1479.83 346.50 347.68 88.11 -335.17 2.96 2.96 -0.27 5980647.11 618593.72 N 70 21 20.858 W 149212.743 1699.21 34.91 282.95 1619.26 1554.91 396.33 397.52 98.86 -383.83 3.02 2.95 1.14 5980657.08 618544.89 N 70 21 20.964 W 149214.166 1795.65 38.20 283.81 1696.71 1632.36 453.76 454.95 112.17 -439.70 3.45 3.41 0.89 5980669.49 618488.82 N 70 21 21.094 W 149215.799 1892.89 39.97 283.33 1772.19 1707.84 515.06 516.26 126.55 -499.30 1.85 1.82 -0.49 5980682.92 618429.01 N 70 21 21.236 W 149217.541 1989.66 42.40 282.69 1845.01 1780.66 578.77 579.97 140.88 -561.38 2.55 2.51 -0.66 5980696.27 618366.71 N 70 21 21.377 W 149219.356 2085.38 43.49 283.43 1915.08 1850.73 643.98 645.18 155.62 -624.90 1.25 1.14 0.77 5980710.00 618302.97 N 7021 21.522 W 149221.213 2181.40 44.98 283.79 1983.88 1919.53 710.96 712.17 171.39 -690.00 1.57 1.55 0.37 5980724.73 618237.63 N 7021 21.677 W 149223.116 2277.08 48.60 284.17 2049.37 1985.02 780.69 781.89 188.24 -757.66 3.79 3.78 0.40 5980740.50 618169.72 N 7021 21.842 W 149225.094 2372.69 48.45 285.11 2112.70 2048.35 852.31 853.53 206.34 -826.97 0.75 -0.16 0.98 5980757.50 618100.14 N 7021 22.020 W 149227.120 2467.91 48.18 285.67 2176.02 2111.67 923.39 924.64 225.21 -895.53 0.52 -0.28 0.59 5980775.28 618031.30 N 7021 22.206 W 149229.124 2563.64 47.41 285.61 2240.33 2175.98 994.26 995.55 244.33 -963.81 0.81 -0.80 -0.06 5980793.31 617962.72 N 7021 22.394 W 149231.120 2659.39 46.39 284.70 2305.75 2241.40 1064.15 1065.46 262.61 -1031.29 1.27 -1.07 -0.95 5980810.52 617894.97 N 7021 22.573 W 149233.093 2754.18 48.07 282.08 2370.13 2305.78 1133.72 1135.03 278.70 -1098.98 2.69 1.77 -2.76 5980825.53 617827.04 N 7021 22.732 W 149 2 35.072 2850.41 48.35 281.79 2434.25 2369.90 1205.43 1206.78 293.54 -1169.17 0.37 0.29 -0.30 5980839.25 617756.62 N 7021 22.877 W 149237.124 2945.88 47.71 281.97 2498.10 2433.75 1276.38 1277.76 308.15 -1238.63 0.68 ·0.67 0.19 5980852.75 617686.95 N 7021 23.021 W 149239.155 3042.24 47.61 281.53 2563.00 2498.65 1347.56 1348.99 322.66 -1308.37 0.35 -0.10 -0.46 5980866.15 617617.00 N 70 21 23.163 W 149241.193 3137.41 47.62 281.34 2627.15 2562.80 1417.80 1419.29 336.59 -1377.27 0.15 0.01 -0.20 5980878.99 617547.89 N 7021 23.300 W 149243.207 3232.58 46.89 281.25 2691.75 2627.40 1487.63 1489.18 350.28 -1445.80 0.77 -0.77 -0.09 5980891.59 617479.15 N 70 21 23.435 W 149245.211 3327.51 48.90 281.79 2755.40 2691.05 1558.01 1559.60 364.35 -1514.81 2.16 2.12 0.57 5980904.56 617409.94 N 70 21 23.573 W 149247.228 3423.61 48.21 281.83 2819.00 2754.65 1630.00 1631.64 379.09 -1585.32 0.72 -0.72 0.04 5980918.18 617339.21 N 70 21 23.718 W 149249.290 3505.84 48.07 281.43 2873.88 2809.53 1691.21 1692.88 391 .44 -1645.31 0.40 -0.17 -0.49 5980929.57 617279.04 N 70 21 23.839 W149251.043 3618.13 46.39 281.43 2950.13 2885.78 1773.57 1775.31 407.78 -1726.10 1.50 -1.50 0.00 5980944.62 617198.00 N 7021 24.000 W 149253.405 3714.31 46.36 280.13 3016.49 2952.14 1843.10 1844.93 420.80 -1794.49 0.98 -0.03 -1.35 5980956.55 617129.42 N702124.128 W 149255.405 3810.58 46.53 279.60 3082.82 3018.47 1912.71 1914.70 432.75 -1863.23 0.44 0.18 -0.55 5980967.41 617060.51 N 7021 24.245 W 149257.414 3905.53 46.02 279.30 3148.45 3064.10 1981.14 1983.31 444.02 -1930.91 0.58 -0.54 -0.32 5980977.60 616992.66 N 7021 24.356 W 149259.393 4001.08 46.28 279.70 3214.64 3150.29 2049.86 2052.22 455.39 -1998.87 0.41 0.27 0.42 5980987.89 616924.53 N 7021 24.467 W 14931.380 4094.89 46.69 281.72 3279.24 3214.89 2117.79 2120.25 468.03 -2065.71 1.62 0.44 2.15 5980999.47 616857.51 N 7021 24.592 W 14933.334 4190.60 46.84 281.85 3344.80 3280.45 2187.48 2189.98 482.28 -2133.97 0.19 0.16 0.14 5981012.63 616789.04 N 7021 24.731 W 14935.330 4286.70 47.00 283.14 3410.44 3346.09 2257.66 2260.17 497.46 ·2202.50 0.99 0.17 1.34 5981026.72 616720.28 N 7021 24.881 W 14937.333 4382.42 47.04 283.59 3475.70 3411.35 2327.68 2330.19 513.65 -2270.63 0.35 0.04 0.47 5981041.83 616651.91 N 7021 25.040 W 14939.325 4478.42 47.58 28507 3540.79 3476.44 2398.24 2400.75 531.12 -2338.99 1.27 0.56 1.54 5981058.21 616583.29 N 7021 25.211 W149311.324 4574.34 47.66 285.29 3605.44 3541.09 2469.07 2471.61 549.67 -2407.37 0.19 0.08 0.23 5981075.67 616514.62 N 7021 25.393 W 149313.323 4670.22 48.65 285.19 3669.41 3605.06 2540.47 2543.04 568.45 ·2476.29 1.04 1.03 -0.10 5981093.35 616445.43 N 7021 25.578 W 149315.338 8urveyEditor Ver 3.1 RT-8P3.03-HF2.03 Bld( d031 rt-546 ) 8 lot 4\8-120\8-120\8' 120 Generated 1/21/2004 9:54 AM Page 1 of 2 e e r Measured I Inclination I Azimuth I TVD I Sub-Sea TVO I Vertical I Along Hole I NS EW I OLS I 8uild Rate I Walk Rate I Northing Easting Lat~ude Long~ude Oepth Section Departure (It) (deg) (deg) (It) (It) (It) (It) (ft) (It) ( deq/loo It ) ( deg/1 00 ft) ( deg/1oo It ) (flUS) (ltUS) 4765.52 47.11 286.18 3733.32 3668.97 2611.11 2613.72 587.55 -2544.34 1.79 -1.62 1.04 5981111.36 616377.08 N 7021 25.766 W 149317.327 4861.17 46.43 284.81 3798.84 3734.49 2680.76 2683.41 606.17 -2611.49 1.26 -0.71 -1.43 5981128.92 616309.65 N 70 21 25.948 W 149319.291 4957.41 46.74 284.44 3864.98 3800.63 2750.66 2753.32 623.82 -2679.14 0.43 0.32 -0.38 5981145.49 616241.74 N 7021 26.122 W 149321.268 5052.56 45.75 284.61 3930.78 3866.43 2819.38 2822.04 641.06 -2745.67 1.05 -1.04 0.18 5981161.67 616174.95 N 7021 26.291 W 149323.214 5148.10 44.74 284.55 3998.05 3933.70 2887.22 2889.89 658.14 -2811.33 1.06 -1.06 -0.06 5981177.70 616109.03 N 70 21 26.459 W 149325.133 5243.41 43.89 284.63 4066.24 4001.89 2953.79 2956.47 674.91 -2875.76 0.89 -0.89 0.08 5981193.44 616044.34 N 70 21 26.624 W 149327.017 5339.39 43.38 284.68 4135.71 4071.36 3020.02 3022.70 691.66 -2939.84 0.53 -0.53 0.05 5981209.18 615980.01 N 70 21 26.788 W 149328.891 5434.11 42.42 284.58 4205.10 4140.75 3084.48 3087.18 707.95 -3002.23 1.02 -1.01 -0.11 5981224.47 615917.38 N 70 21 26.948 W 149330.715 552996 41.84 284.82 4276.18 4211.83 3148.77 3151.48 724.27 -3064.42 0.63 -0.61 0.25 5981239.80 615854.94 N702127.108 W 149332.533 5625.03 40.75 283.80 4347.61 4283.26 3211.50 3214.22 739.78 -3125.21 1.35 -1.15 -1.07 5981254.34 615793.92 N 70 21 27.261 W 149334.311 5720.15 39.02 283.32 4420.59 4356.24 3272.50 3275.21 754.08 -3184.50 1.85 -1.82 -0.50 5981267.70 615734.41 N 7021 27.401 W 149336.044 5816.12 37.27 282.26 4496.07 4431.72 3331.76 3334 .48 767.21 -3242.30 1.95 -1.82 -1.10 5981279.91 615676.42 N 70 21 27.530 W 149337.734 5910.78 35.23 281.37 4572.40 4508.05 3387 70 3390.45 778.68 -3297.08 2.23 -2.16 -0.94 5981290.51 615621.47 N 7021 27.642 W 149339.336 6008.48 32.90 281 .46 4653.33 4588.98 3442.38 3445.17 789.51 -3350.72 2.39 -2.38 0.09 5981300.49 615587.67 N 7021 27.749 W 149340.904 6104.75 31.12 281.23 4734.96 4670.61 3493.36 3496.20 799.55 -3400.75 1.85 -1.85 -0.24 5981309.73 615517.49 N 7021 27.847 W 149342.367 6199.94 29.20 281.92 4817.26 4752.91 3541.15 3544.02 809.14 -3447.60 2.05 -2.02 0.72 5981318.57 615470.50 N 7021 27.941 W 149343.737 6295.39 26.06 281.75 4901.82 4837.47 3585.39 3588.28 818.22 -3490.92 3.29 -3.29 -0.18 5981326.96 615427.04 N 70 21 28.030 W 149345.003 6391.34 22.75 283.11 4989.18 4924.83 3625.02 3627.92 826.72 -3529.63 3.50 -3.45 1.42 5981334.85 615388.20 N 702128.114 W 149346.135 6486.66 20.32 287.92 5077 .85 5013.50 3659.96 3662.89 836.00 -3563.34 3.15 -2.55 5.05 5981343.59 615354.36 N 70 21 28.205 W 149347.121 6583.06 20.05 289.54 5168.33 5103.98 3693.09 3696.15 846.68 -3594.84 0.64 -0.28 1.68 5981353.76 615322.69 N 7021 28.310 W 149348.042 6677.95 20.10 289.20 5257.45 5193.10 3725.50 3728.72 857.48 -3625.57 0.13 0.05 -0.36 5981364.07 615291.80 N 702128.416 W 149348.940 6774.65 19.10 288.25 5348.55 5284.20 3757.81 3761.16 867.90 -3656.28 1.09 -1.03 -0.98 5981374.00 615260.92 N 7021 28.518 W 149349.838 6870.31 18.83 287.98 5439.02 5374.67 3788.81 3792.25 877.57 -3685.83 0.30 -0.28 -0.28 5981383.20 615231.23 N 7021 28.613 W 149350.702 6965.84 18.35 286.65 5529.56 5465.21 3819.20 3822.70 886.63 -3714.90 0.67 -0.50 -1.39 5981391.80 615202.02 N 70 21 28.702 W 149351.552 7061 .46 17.79 285.25 5620.46 5556.11 384884 3852.36 894.79 -3743.42 0.74 -0.59 -1.46 5981399.50 615173.38 N 70 21 28.782 W 149352.386 7157.82 17.31 284.70 5712.34 5647.99 3877.88 3881.41 902.30 -3771.48 0.53 -0.50 -0.57 5981406.57 615145.20 N 70 21 28.856 W 149353.207 7253.41 16.66 283.72 5803.76 5739.41 3905.81 3909.34 909.16 -3798.55 0.74 -0.68 -1.03 5981412.99 615118.03 N 70 21 28.923 W 149353.998 7349.48 15.87 283.79 5895.98 5831.63 3932.71 3936.24 915.55 -3824.69 0.82 -0.82 0.07 5981418.98 615091.80 N 70 21 28.986 W 149354.762 7444.58 14.83 283.19 5987.69 5923.34 3957.89 3961 .42 921.43 -3849.17 1.11 -1.09 -0.63 5981424.46 615067.23 N 70 21 29.044 W 149355.478 7539.74 14.30 283.33 6079.79 6015.44 3981.82 3985.35 926.92 -3872.46 0.56 -0.56 0.15 5981429.58 615043.86 N 7021 29.098 W 149356.159 7633.44 13.31 285.93 6170.78 6106.43 4004.17 4007.70 932.55 -3894.09 1.25 -1.06 2.77 5981434.86 615022.14 N 702129.153 W 149356.792 7731.21 12.07 292.02 6266.17 6201.82 4025.53 4029.16 939.47 -3914.39 1.86 -1.27 6.23 5981441.46 615001.74 N 7021 29.221 W 149357.385 7826.72 11.13 303.62 6359.74 6295.39 4044.08 4048.30 948.32 -3931.33 2.63 -0.98 12.15 5981450.04 614984.66 N 7021 29.308 W 149357.881 7922.39 11.43 310.72 6453.57 6389.22 4061.20 4066.99 959.62 -3946.20 1.48 0.31 7.42 5981461.10 614969.61 N 702129.419 W 149358.316 8017.87 10.75 318.53 6547.27 6482.92 4076.94 4085.33 972.46 -3959.27 1.73 -0.71 8.18 5981473.73 614956.34 N 7021 29.545 W 149358.698 8113.29 10.55 319.59 6641.04 6576.69 4091.32 4102.97 985.78 -3970.83 0.29 -0.21 1.11 5981486.87 614944.58 N 7021 29.676 W 149359.036 8210.10 10.15 319.83 6736.28 6671.93 4105.39 4120.36 999.05 -3982.07 0.42 -0.41 0.25 5981499.95 614933.12 N 7021 29.806 W 149359.365 8303.77 9.23 318.42 6828.61 6764.26 4118.23 4136.12 1010.97 -3992.38 1.01 -0.98 -1.51 5981511.71 614922.62 N 7021 29.924 W 149359.667 8362.30 9.10 318.09 6886.39 6822.04 4125.90 4145.45 1017.93 -3998.59 0.24 -0.22 -0.56 5981518.57 614916.31 N 70 21 29.992 W 149359.848 8440.00 9.10 318.09 6963.12 6898.77 4136.04 4157.74 1027.07 -4006.80 0.00 0.00 0.00 5981527.58 614907.96 N 70 21 30.082 W 14940.088 LeQal Description: NorthinQ IV) [ftUS] EastinQ IX) [ftUS] Surface: 4360 F8L 4500 FEL 835 T12N R12E UM 5980564.33 618930.21 BHL: 106 FSL 3225 FEL 827 T12N R12E UM 5981527.58 614907.96 8urveyEditor Ver 3.1 RT-8P3.03-HF2.03 Bld( d031 rt-546) 810t 4\8-120\8-120\8-120 Generated 1/21/20049:54 AM Page 2 of 2 TREE = 4-1/16" OW WB...LI-EAD= FtvC Ä Ci1JATOïf = NA KB. ELEV = 64.3' BF.ËLËíF= 35.8' kòp = '260' MaxA-ngle = ---49-@-4670' Diitu¡:n'Mb-;-'--'---ão65' ~__ '_~~~~~'_____~_~~~'_~"m~~_ Datum TV D = 6600' SS e I 9-5/8" CSG, 40#, L-80, ID = 8.835" H 3566' ra IMinimum ID =3.725" @ 7901'1 4-112" HES XN NIPPLE 14-1/2" TBG, 12.6#, L-80, .0152 bpf, ID=3.958"H 7912' ÆRFORA TON SUIV1Iv1ARY REF LOG: PEX 12/28/03 ANGLEA TTOP ÆRF: 11 @ 8052' Note: Refer to Production DB for historical Jerf data SIZE SfT INTERVAL Opn/Sqz DA TE 3-318" 6 8052 - 8077 0 04/30104 3-318" 6 8084 - 8114 0 04/30104 3-318" 6 8166 - 8178 0 04/30104 3-318" 6 8252 - 8264 0 04/30104 I R3TD H 8338' 17" CSG, 26#, L-80, ID = 6.276" H 8425' DATE REV BY COMrvENTS 01/02/04 TM WKK ORIGINAL COMPLETION 04/11104 JlJ/KAK GlV C/O 04/30/04 MJAIKAK IÆRFS 8-120 . I SAFETY NOTES: ~ 1013' H9-5/8"TAM FORf COLLAR I 1 2208' H4-1/2" HES X NIP, ID = 3.813" I GAS LIFT MANDRELS ST MD TVD DEV TYÆ VLV LA TCH PORT DATE ---! 2 4858 3797 46 KBG-2 SO BK 24 04/11/04 1 7723 6258 12 KBG-2 DIv1Y BK 01/01/04 7790' H 4-1 f2" rES X NIP, D = 3.813" I >< :8: --t 7853' H7" X4-1/2" BKRPREM PKR, ID = 3.875" 7880' H4-1f2" rES X NIP, D = 3.813" I 7901' H 4-1 f2" rES XN NIP, ID = 3.725" I , . 7914' H4-1f2" WLffi, D =3.958" I H B...rvD IT NOT LOGGED 1 ~ DA TE REV BY COfllMfNTS 8041' H7" MARKER JOINT WI RA TAG I 8278' H7" MARKER JOINT WI RA TAG I AURORA UNIT WB...L: S-120 ÆR!v1rT No: 2031980 A PI No: 50-029-23186-00 SEe 35, T12N, R12E, 4360' NSL & 4500' WEL BP Exploration (Alaska) . . ~03-98' Schlumberger Drilling & Measurements MWD/LWD Log Product Delivery Customer BP Exploration (Alaska) Inc. Dispatched To: Lisa Weepie Well No S-120 Date Dispatched: 19-Dec-03 Installation/Rig Nabors 7ES Dispatched By: F. Alabi Data No Of Prints No of Floppies Surveys 2 Received By: ~~l~x 'y~t.c' CXÌ)(~Yy'\. Please sign and return to: James H. Johnson BP Exploration (Alaska) Inc. Petrotechnical Data Center (LR2-1) 900 E. Benson Blvd. Anchorage, Alaska 99508 Fax: 907-564-4005 e-mail address:johnsojh@bp.com LWD Log DeliveryV1.1, 10-02-03 Schlumberger Private RECEIVED JAN 2 ;.: 2004 AtasksOiI & Gas Cons.Commilion Anchorage ~~f\¡'\6::, SCHLUMBERGER Survey report Client............ .......: BP Exploration (Alaska) Inc. Field....................: Prudhoe Bay Unit - Aurora Well. . . . . . . . . . . . . . . . . . . . .: S-120 API number...... .........: 50-029-23186-00 Engineer.................: Leafstedt Rig: . . . . . . . . . . . . . . . . . . . . .: Nabors 7ES STATE: . . . . . . . . . . . . . . . . . . .: Alaska ----- Survey calculation methods------------- Method for positions.....: Minimum curvature Method for DLS.... .... ...: Mason & Taylor ----- Depth reference ----------------------- Permanent datum..........: Mean Sea Level Depth reference.... ......: Driller's Pipe Tally GL above permanent.......: 35.80 ft KB above permanent.... ...: N/A DF above permanent.... ...: 64.35 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 rotary table to target: 283.69 degrees RECEIVED I.A r·¡ 2(', '100' ~ ,-, \ .." 'f. AJaska Oil & Gas Cons. CornmIiort AndtonJge . [(c)2003 IDEAL ID8_1C_01J ...... K~~\\\ ~ 28-Dec-2003 06:31:28 Spud date.. ..............: Last survey date.........: Total accepted surveys...: MD of first survey.......: MD of last survey........: ;5103 -)qg Page 1 of 4 Dec-21-2003 28-Dec-03 90 0.00 ft 8440.00 ft . ----- Geomagnetic data ---------------------- Magnetic model...........: BGGM version 2003 Magnetic date... .........: 18-Dec-2003 Magnetic field strength..: 1151.35 HCNT Magnetic dec (+E/W-).....: 25.29 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 mGal 1151.35 HCNT 80.86 degrees (+/-) 2.50 mGal (+/-) 6.00 HCNT (+/-) 0.45 degrees . ----- Corrections --------------------------- Magnetic dec (+E/W-).....: 25.29 degrees Grid convergence (+E/W-).: 0.00 degrees Total az corr (+E/W-). ...: 25.29 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 SCHLUMBERGER Survey Report 28-Dec-2003 06:31:28 Page 2 of 4 -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ Seg 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 2 100.00 0.44 260.37 100.00 100.00 0.35 -0.06 -0.38 0.38 260.37 0.44 GYR None 3 200.00 0.64 262.56 100.00 199.99 1. 23 -0.20 -1.31 1. 33 261.29 0.20 GYR None 4 300.00 0.98 264.48 100.00 299.98 2.55 -0.36 -2.72 2.74 262.55 0.34 GYR None 5 400.00 1. 99 260.80 100.00 399.95 4.96 -0.72 -5.28 5.33 262.29 1. 01 GYR None 6 500.00 3.13 266.98 100.00 499.85 9.18 -1.14 -9.72 9.79 263.33 1.17 GYR None . 7 600.00 4.79 278.91 100.00 599.61 15.95 -0.63 -16.57 16.59 267.81 1. 84 GYR None 8 700.00 8.03 288.20 100.00 698.97 27.08 2.20 -27.34 27.42 274.59 3.39 GYR None 9 753.00 10.31 286.74 53.00 751.29 35.51 4.72 -35.40 35.71 277.59 4.32 G-MAG None 10 842.50 13.18 290.56 89.50 838.91 53.64 10.61 -52.62 53.68 281.40 3.32 G-MAG None 11 937.68 16.58 283.79 95.18 930.89 78.00 17.66 -75.98 78.01 283.08 4.01 G-MAG None 12 1032.63 19.46 289.54 94.95 1021.18 107.29 26.18 -104.05 107.29 284.12 3.56 G-MAG None 13 1128.32 20.72 287.74 95.69 1111.05 140.03 36.67 -135.20 140.08 285.18 1.47 G-MAG None 14 1224.95 21. 86 286.04 96.63 1201.08 175.06 46.85 -168.77 175.15 285.51 1.34 G-MAG None 15 1320.30 23.77 285.69 95.35 1288.97 212.01 56.95 -204.33 212.12 285.57 2.01 G-MAG None 16 1416.30 25.97 284.62 96.00 1376.06 252.36 67.49 -243.30 252.49 285.50 2.34 G-MAG None 17 1512.13 29.38 282.18 95.83 1460.92 296.86 77.75 -286.60 296.96 285.18 3.75 G-MAG None 18 1609.09 32.25 281.92 96.96 1544.18 346.50 88.11 -335.17 346.56 284.73 2.96 G-MAG None 19 1699.21 34.91 282.95 90.12 1619.26 396.33 98.86 -383.83 396.36 284.44 3.02 G-MAG None 20 1795.65 38.20 283.81 96 .44 1696.71 453.76 112 . 17 -439.70 453.78 284.31 3.45 G-MAG None 21 1892.89 39.97 283.33 97.24 1772.19 515.06 126.55 -499.30 515.08 284.22 1. 85 G-MAG None . 22 1989.66 42.40 282.69 96.77 1845.01 578.77 140.88 -561.38 578.79 284.09 2.55 G-MAG None 23 2085.38 43.49 283.43 95.72 1915.08 643.98 155.62 -624.90 643.99 283.98 1. 25 G-MAG None 24 2181.40 44.98 283.79 96.02 1983.88 710.96 171.39 -690.00 710.97 283.95 1.57 G-MAG None 25 2277.08 48.60 284.17 95.68 2049.37 780.69 188.24 -757.66 780.69 283.95 3.79 G-MAG None 26 2372.69 48.45 285.11 95.61 2112.70 852.31 206.34 -826.97 852.32 284.01 0.75 G-MAG None 27 2467.91 48.18 285.67 95.22 2176.02 923.39 225.21 -895.53 923.41 284.12 0.52 G-MAG None 28 2563.64 47.41 285.61 95.73 2240.33 994.26 244.33 -963.81 994.30 284.23 0.81 G-MAG None 29 2659.39 46.39 284.70 95.75 2305.75 1064.15 262.61 -1031. 29 1064.20 284.29 1.27 G-MAG None 30 2754.18 48.07 282.08 94.79 2370.13 1133.72 278.70 -1098.98 1133.77 284.23 2.69 G-MAG None [(c)2003 IDEAL ID8_1C_01] SCHLUMBERGER Survey Report 28-Dec-2003 06:31:28 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) (ft) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- ---------.------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 31 2850.41 48.35 281.79 96.23 2434.25 1205.43 293.54 -1169.17 1205.46 284.09 0.37 G-MAG None 32 2945.88 47.71 281. 97 95.47 2498.10 1276.38 308.15 -1238.63 1276.39 283.97 0.68 G-MAG None 33 3042.24 47.61 281.53 96.36 2563.00 1347.56 322.66 -1308.37 1347.57 283.85 0.35 G-MAG None 34 3137.41 47.62 281.34 95.17 2627.15 1417.80 336.59 -1377.27 1417.80 283.73 0.15 G-MAG None 35 3232.58 46.89 281.25 95.17 2691.75 1487.63 350.28 -1445.80 1487.63 283.62 0.77 G-MAG None 36 3327.51 48.90 281.79 94.93 2755.40 1558.01 364.35 -1514.81 1558.01 283.52 2.16 G-MAG None . 37 3423.61 48.21 281.83 96.10 2819.00 1630.00 379.09 -1585.32 1630.02 283.45 0.72 G-MAG None 38 3505.84 48.07 281. 43 82.23 2873.88 1691.21 391. 44 -1645.31 1691.23 283.38 0.40 G-MAG None 39 3618.13 46.39 281.43 112.29 2950.13 1773.57 407.78 -1726.10 1773.61 283.29 1. 50 G-MAG None 40 3714.31 46.36 280.13 96 .18 3016.49 1843.10 420.80 -1794.49 1843.17 283.20 0.98 G-MAG None 41 3810.58 46.53 279.60 96.27 3082.82 1912.71 432.75 -1863.23 1912.82 283.08 0.44 G-MAG None 42 3905.53 46.02 279.30 94.95 3148.45 1981.14 444.02 -1930.91 1981.31 282.95 0.58 G-MAG None 43 4001.08 46.28 279.70 95.55 3214.64 2049.86 455.39 -1998.87 2050.09 282.83 0.41 G-MAG None 44 4094.89 46.69 281.72 93.81 3279.24 2117.79 468.03 -2065.71 2118..07 282.77 1. 62 G-MAG None 45 4190.60 46.84 281. 85 95.71 3344.80 2187.48 482.28 -2133.97 2187.79 282.73 0.19 G-MAG None 46 4286.70 47.00 283.14 96 .10 3410.44 2257.66 497.46 -2202.50 2257.98 282.73 0.99 G-MAG None 47 4382.42 47.04 283.59 95.72 3475.70 2327.68 513.65 -2270.63 2328.00 282.75 0.35 G-MAG None 48 4478.42 47.58 285.07 96.00 3540.79 2398.24 531.12 -2338.99 2398.53 282.79 1. 27 G-MAG None 49 4574.34 47.66 285.29 95.92 3605.44 2469.07 549.67 -2407.37 2469.33 282.86 0.19 G-MAG None 50 4670.22 48.65 285.19 95.88 3669.41 2540.47 568.45 -2476.29 2540.69 282.93 1. 04 G-MAG None 51 4765.52 47.11 286.18 95.30 3733.32 2611.11 587.55 -2544.34 2611.30 283.00 1. 79 G-MAG None . 52 4861.17 46.43 284.81 95.65 3798.84 2680.76 606.17 -2611.49 2680.92 283.07 1. 26 G-MAG None 53 4957.41 46.74 284.44 96.24 3864.98 2750.66 623.82 -2679.14 2750.81 283.11 0.43 G-MAG None 54 5052.56 45.75 284.61 95.15 3930.78 2819.38 641.06 -2745.67 2819.51 283.14 1. 05 G-MAG None 55 5148.10 44.74 284.55 95.54 3998.05 2887.22 658.14 -2811.33 2887.33 283.18 1. 06 G-MAG None 56 5243.41 43.89 284.63 95.31 4066.24 2953.79 674.91 -2875.76 2953.90 283.21 0.89 G-MAG None 57 5339.39 43.38 284.68 95.98 4135.71 3020.02 691. 66 -2939.84 3020.11 283.24 0.53 G-MAG None 58 5434.11 42.42 284.58 94.72 4205.09 3084.48 707.95 -3002.23 3084.57 283.27 1. 02 G-MAG None 59 5529.96 41. 84 284.82 95.85 4276.18 3148.77 724.27 -3064.42 3148.84 283.30 0.63 G-MAG None 60 5625.03 40.75 283.80 95.07 4347.61 3211.50 739.78 -3125.21 3211.57 283.32 1.35 G-MAG None [(c)2003 IDEAL ID8_1C_01] .. . SCHLUMBERGER Survey Report 28-Dec-2003 06:31:28 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) (ft) (ft) (ft) (ft) (deg) 100f) type (deg) -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ -------- ------ ------- ------ -------- -------- ---------------- --------------- ------ 61 5720.15 39.02 283.32 95.12 4420.59 3272.50 754.08 -3184.50 3272.56 283.32 1. 85 G-MAG None 62 5816.12 37.27 282.26 95.97 4496.07 3331.76 767.21 -3242.30 3331.83 283.31 1. 95 G-MAG None 63 5910.78 35.23 281.37 94.66 4572.40 3387.70 778.68 -3297.08 3387.78 283.29 2.23 G-MAG None 64 6008.48 32.90 281.46 97.70 4653.33 3442.38 789.51 -3350.72 3442.48 283.26 2.39 G-MAG None 65 6104.75 31.12 281.23 96.27 4734.96 3493.36 799.55 -3400.75 3493.48 283.23 1. 85 G-MAG None 66 6199.94 29.20 281.92 95.19 4817.26 3541. 15 809.14 -3447.60 3541.28 283.21 2.05 G-MAG None . 67 6295.39 26.06 281.75 95.45 4901.82 3585.39 818.22 -3490.92 3585.53 283.19 3.29 G-MAG None 68 6391.34 22.75 283.11 95.95 4989.18 3625.02 826.73 -3529.63 3625.16 283.18 3.50 G-MAG None 69 6486.66 20.32 287.92 95.32 5077.85 3659.96 836.00 -3563.34 3660.09 283.20 3.15 G-MAG None 70 6583.06 20.05 289.54 96.40 5168.33 3693.09 846.68 -3594.84 3693.20 283.25 0.64 G-MAG None 71 6677.95 20.10 289.20 94.89 5257.45 3725.50 857.48 -3625.57 3725.59 283.31 0.13 G-MAG None 72 6774.65 19.10 288.25 96.70 5348.55 3757.81 867.90 -3656.28 3757.88 283.35 1. 09 G-MAG None 73 6870.31 18.83 287.98 95.66 5439.01 3788.81 877.57 -3685.83 3788.86 283.39 0.30 G-MAG None 74 6965.84 18.35 286.65 95.53 5529.56 3819.20 886.63 -3714.90 3819.24 283.42 0.67 G-MAG None 75 7061.46 17.79 285.25 95.62 5620.46 3848.84 894.79 -3743.42 3848.87 283.44 0.74 G-MAG None 76 7157.82 17.31 284.70 96.36 5712.34 3877.88 902.30 ~3771.48 3877.92 283.45 0.53 G-MAG None 77 7253.41 16.66 283.72 95.59 5803.76 3905.81 909.16 -3798.55 3905.84 283.46 0.74 G-MAG None 78 7349.48 15.87 283.79 96.07 5895.98 3932.71 915.55 -3824.69 3932.74 283.46 0.82 G-MAG None 79 7444.58 14.83 283.19 95.10 5987.69 3957.89 921. 43 -3849.17 3957.92 283.46 1.11 G-MAG None 80 7539.74 14.30 283.33 95.16 6079.79 3981.82 926.92 -3872.46 3981. 85 283.46 0.56 G-MAG None 81 7633.44 13.31 285.93 93.70 6170.78 4004.17 932.55 -3894.09 4004.20 283.47 1. 25 G-MAG None . 82 7731.21 12.07 292.02 97.77 6266.17 4025.53 939.47 -3914.39 4025.55 283.50 1. 86 G-MAG None 83 7826.72 11.13 303.62 95.51 6359.74 4044.08 948.32 -3931.33 4044.09 283.56 2.63 G-MAG None 84 7922.39 11.43 310.72 95.67 6453.57 4061.20 959.62 -3946.20 4061.20 283.67 1. 48 G-MAG None 85 8017.87 10.75 318.53 95.48 6547.27 4076.94 972.46 -3959.27 4076.95 283.80 1. 73 G-MAG None 86 8113.29 10.55 319.59 95.42 6641. 04 4091.32 985.78 -3970.83 4091.36 283.94 0.29 G-MAG None 87 8210.10 10.15 319.83 96.81 6736.28 4105.39 999.05 -3982.07 4105.48 284.08 0.42 G-MAG None 88 8303.77 9.23 318.42 93.67 6828.61 4118.23 1010.97 -3992.38 4118.40 284.21 1. 01 G-MAG None 89 8362.30 9.10 318.09 58.53 6886.39 4125.90 1017.93 -3998.59 4126.13 284.28 0.24 G-MAG None Projected to TD 90 8440.00 9.10 318.09 77.70 6963.12 4136.04 1027.08 -4006.80 4136.34 284.38 0.00 PROJ None [(c)2003 IDEAL ID8 1C 01] - - . . FRANK H. MURKOWSKI, GOVERNOR AI,ASIiA. OIL AND GAS CONSERVATION COMMISSION Lowell Crane Senior Drilling Engineer BP Exploration (Alaska), Inc. PO Box 196612 Anchorage AK 99519 333 W."7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Prudhoe Bay Unit S-120 BP Exploration (Alaska), Inc. Permit No: 203-198 Surface Location: 4360' NSL, 4500' WEL, Sec. 35, TI2N, RI2E, UM Bottomhole Location: 96' NSL, 3392' WEL, Sec. 27, Tl2N, Rl2E, UM Dear Mr. Crane: 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 approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). Sincerely, ~ QL Sarah Palin Chair BY ORDER OF THE COMMISSION DATED thisL day of December, 2003 cc: Department ofFish & Game, Habitat Section w/o encI. Department of Environmental Conservation w/o encl. Exploration, Production and Refineries Section , WGA lZ-IZ-Iz.003 . STATE OF ALASKA . ALASKA O~\ND GAS CONSERVATION COM_SION PERMIT TO DRILL 20 MC 25.005 1b. Current Well Class 0 Exploratory o Stratigraphic Test III Service 5. Bond: a Blanket 0 Single Well Bond No. 2S100302630-277 6. Proposed Depth: MD 8522 TVD 7010 7. Property Designation: ADL 028258 II Drill 0 Redrill 1a. Type of work 0 Re-Entry 2. Operator Name: BP Exploration (Alaska) Inc. 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 4a. Location of Well (Governmental Section): Surface: 4360' NSL, 4500' WEL, SEC. 35, T12N, R12E, UM Top of Productive Horizon: 54' NSL, 3259' WEL, SEC. 27, T12N, R12E, UM Total Depth: 96' NSL, 3392' WEL, SEC. 27, T12N, R12E, UM 4b. Location of Well (State Base Plane Coordinates): Surface: X-618930 y- 5980564 Zone-ASP4 16. Deviated Wells: Kickoff Depth 1&. ..Casing Program SiZe Casing 20" 9-5/8" Hole 42" .12-1/4" 8-3/4" 300 ft Maximum Hole Angle SpElcifications Grade Coupling H-40 Weld L-80 BTC L-80 BTC-M 7" Weight 91.5# 40# 26# o Development Oil 0 Multiple Zone o Development Gas 0 Single Zone 11. Well Name and Number: PBU 5-120 ,/ 12. Field I Pool(s): Prudhoe Bay Field I Aurora Pool 8. Land Use Permit: 13. Approximate Spud Date: December 31, 2003 / 14. Distance to Nearest Property: 7800' MD 9. Acres in Property: 2560 48° 10. KB Elevation Plan RKB 15. Distance to Nearest Well Within Pool (Height above GL): = 64.3' feet S-117 is 1700' away at 8124' MD 17. Anticipated pressure (see 20 AAC 25.035) / Max. Downhole Pressure: 3350 psig. Max. Surface Pressure: 2680 psig Setting Deptþ.. .... ... ... . Ql,1éJntitY ofyement Top .... ... ..' . .. ........... . Bottom (c.f. or sacks) MD TVD MD TVD (including stage data) Surface Surface 110' 110' 260 sx Arctic Set (Approx.) Surface Surface 3574' 2929' 521 sx Arctic Set Lite PF, 278 sX 'G' Surface Surface 8522' 6980' 174 sx Litecrete, 161 sx Class 'G' ,/ Length 80' 3574' 8522' 19. PRE$ENTWElLCONDITIONSUMMARY (To be complEltedfor RedrillANDRe~entry Operatiops) 'Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effective Depth MD (ft): Depth TVD Junk (measured): Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): 20. Attachments a Filing Fee 0 BOP Sketch a Property Plat 0 Diverter Sketch 21. Verbal Approval: 22. I hereby Printed IperfOration Depth TVD (ft): a Drilling Program 0 Time vs Depth Plot o Seabed Report a Drilling Fluid Program o Shallow Hazard Analysis a20 AAC 25.050 Requirements Date: Contact Jim Smith, 564-5773 Commission Representative: foregoing is true and correct to the best of my knowledge. Crane /-:'/ Title Senior Drilling Engineer /tt: Phone Permit To API Number: Permit APprov111. See cover letter for Number?""'-š'-I?B 50- 0.2. 'f'- .2 jÞ / ~.& Date: I/i other requirements Conditions of Approval: Samples Required 0 Yes ~ No Mud Log Required 0 Yes ~ No Hydrogen Sulfide Measures 0 Yes ~ No Directional Survey Required ~ Yes 0 No Other:T¿ç.+ f:>op£ tifJ i./c;oo p~. /. ML T, ~M~t f,UAtil:¡ lo~ Y'lDt-~rtJ ' Pu '2Æ AAC 2S. ~~S lh)(-¿)/ dt\l~t.r ('eÓLÆ-l~W\.~+;S wA1.vecl. Original Signed By Approved By: Sarah Palin Form 10-401 Revised 3/2003 BY ORDER OF o ~1b1W'A L:HE COMMISSION Date I ~ I ~ I D '1; Sui~it(~ D6plicate e e ",. bp ~~. ~ ~...... ·'I~~li\~ ". To: Winton Aubert, AOGCC Date: Nov. 24, 2003 From: Jim Smith Subject: Dispensation for 20 AAC 25.035 (c) on 8-120 - permit submitted BP Alaska Drilling and Wells requests your consideration of a waiver of the diverter /' system identified in 20 AAC 25.035 (c) "Secondary Well Control for Primary Drilling and Completion: Blowout Prevention Equipment and Diverter Requirements". Experience and data gathered, summarized herein, support the rationale for the request. To date, none of the 40-plus Ivishak wells at S-pad, nor the recent AuroraIPolaris wells have experienced pressure control or shallow gas problems above the surface casing depth, apart from minor and inconsequential hydrate shows. The first ten surface holes for the AuroraIPolaris development were drilled no deeper than the shale underlying the SV-I sands; S-120 is planned to TD in the shallower SV-3 shale, as did the most recent wells. The shale underlying the SVl is the deepest planned surface casing setting depth for future pad development wells. This casing point is ±745' TVD above the Ugnu horizon. The shallowest and most recent RFT points recorded in the area are from S-201, recording a pore pressure of 1,423psi at 3,175' TVDss (8.6 ppg EMW) and not exceeding 8.7 ppg EMW above 3700' TVDss. S-120 is planned to reach 9.5ppg mud weight before TD at 2929' TVD. Supporting surface hole gas detection information is on file with the AOGCC from the recently drilled S-105 as requested by AOGCC. / Your consideration of the waiver is appreciated. ~r~ !!.im Smith GPB Rotary Drilling Engineer 564-5773 e e I Well Name: 18-120 Drill and Complete Plan Summary I Type of Well (service I producer I injector): Injector / Surface Location: As-Built Target Location: Top Kuparuk Bottom Hole Location: x = 618,930.' Y = 5,980,564' 4360' FSL, 4500' FEL, Sec. 35, T12N, R12E X = 614,875' Y = 5,981,475' 54' FSL, 3259' FEL, Sec. 27, T12N, R12E 6550'TVDss X = 614,741' Y = 5,981,514' 96'FSL,3393'FEL,Sec.27,T12N,R12E ;/ 1 AFE Number: 1 AUD5M0071 I 1 Rig: I Nabors 7ES I Estimated Start Date: 112/31/2003 1 / I Operating days to complete: 112.9 / I MD: 18522 I TVD: 17010' I RT/GL: 128.5' I I RKB/MSL: 164.3' I 1 Well Design (conventional, slim hole, etc.): 1 Ultra Slim hole (Iongstring) I Objective: 1 Single zone injector into the Kuparuk formation Mud Program: 12 %" Surface Hole (0-3474'): Densitv (ppg) Initial 8.5 - 9.2 Base PF to top SV 9.0 - 9.5 SV toTD 9.5 max Viscosity (seconds) 250-300 200 150-200 Fresh Water Surface Hole Mud Yield Point API FL PH (lb/1 OOft~) (mls/30min) 45 - 70 NC 35-45 25 -- 35 <8 <8 9.0-9.5 9.0- 9.5 9.0- 9.5 83,4" Production Hole (3574' - 8522'): LSND Interval Density YP PV pH API 10' Gel (ppg).---, Filtrate Upper 9.7~' 25-30 10-15 9.0--9.5 6-8 10 Interval if r Top of HRZ 9.9 - 10.1 22-28 1 0-15 9.0-9.5 4-6 10 to TD S-120 Drilling Program-Draft Page 2 e e Hydraulics: Suñace Hole: 12-1/4" Interval Pump Drill AV Pump PSI ECD Motor Jet Nozzles TFA GPM Pipe (fpm) ppg-emw ("/32) (in2) 0-2095' 550 4" 15.7# 10.0 N/A 18,18,18,16 .942 2095' -3574' 650 4" 15.7# 10.2 N/A 18,18,18,16 .942 Production Hole: 8 3,1.." Interval Pump Drill Pipe AV Pump PSI ECD Motor Jet Nozzles TFA GPM (fpm) ppg-emw ("/32) (in2) 3574' - 8522' 600 4" 15.7# 10.8 N/A 3x14,3x15 .969 Hole Cleaning Criteria: Interval Interval ROP Drill Pump Mud Hole Cleaning Condition Pipe GPM Weight Rotation 110'-3574' Suñace 9.5 Superior hole cleaning practices at to SV-3 connections will greatly enhance cuttings transport in the sliding mode 3574'-8522' 9-5/8" to 9.7 Sweeps and fully reamed connections TD to maintain minimum hole cleaning requirements Casing Criteria: Casing Description Burst Rating {psi} Collapse Rating {psi} 20" insulated conductor 9-5/8" , 40#, L-80, BTC 7", 26#, L-80, BTCM 5750 7240 3090 5410 8-120 Drilling Program-Draft Page 3 e e Directional: Ver. I Anadrill P3 KOP: 300' Maximum Hole Angle: Close Approach Wells: None 48 deg at 2280' MD All wells pass major risk criteria. The nearest wells are: /' S-117 at 550'MD on S-120, 15' away center to center and S-213 at 398'MD on the S-120, 15' away center to center. These are the two adjacent wells at surface. Gyro confirmation of the S-120 wellbore location may be required in the surface hole if magnetic interference is a problem. IFR-MS corrected surveys will be used for survey validation. ,/ No i ~Il(.. Logging Program: Surface Drilling: MWD 1 GR Open Hole: None Cased Hole: None Intermediate/Production Hole Drilling: MW DIG R/PWD Open Hole: PEXlBHCS Cased Hole: USIT Formation Markers: Formation Tops MD TVDss Estimated pore pressure, PPG KOP 300 236 KOP in Permafrost SV6 1705 1565 Base Permafrost 2095 1870 SV5 2551 2180 SV4 2842 2375 SV3 3425 2765 9-5/8" sfc casing 3574 2865 9-5/8" casing SV2 3634 2905 SV1 4105 3220 8.6 ppg EMW UG4A 4688 3610 Minor Hydrocatrbons, possible 10.1 ppg EMW ~.7 UG3 5135 3910 Hydrocarbon bearing, 9.0 ppg EMW UG1 5787 4405 Hydrocarbon bearing, 9.0 ppg EMW Ugnu Ma 6096 4670 Hydrocarbon bearing, 9.2 ppg EMW Top Schrader NA 6318 4870 Hydrofarbon bearing, 8.8ppg EMW Schrader OA 6452 4995 Hydrocarbon bearing, 8.8 ppg EMW Base OBf 6792 5315 CM1(Colville) 7858 6320 shale THRZ 8039 6490 Target 8102 6550 9.~ BHRZ (Kalubik) 8118 6565 Top Kuparuk 8124 6570 Hydrocarbon Bearing, 9.5 ppg EMW Kuparuk C2B 8133 6579 . Hydrocarbon Bearing, 9.5 ppg EMW Kuparuk C1 C 8194 6636 Hydrocarbon Bearing, 9.5 ppg EMW LCU Kuparuk B 8214 6655 Hydrocarbon Bearing, 9.5 ppg EMW Kuparuk A5 8299 6735 Hydrocarbon Bearing, 9.5 ppg EMW TMLV (Miluveach) 8372 6804 shale TDn" casing Criteria 8522 6945 150' MD below Base A5 1 Miluveach top S-120 Drilling Program-Draft Page 4 e e CasinglTubing Program: Hole Csg/ WtlFt Grade Conn Length Top Btm Size Tbg O.D. / / MDITVD MD/TVD bkb 42" Insulated 20" 91.5# H-40 WLD 80' GL 110'/110' 1214" 9 5/8" 40# L-80 BTC 3574' GL 3574'/2929' 8%" 7" 26# L-80 BTC-M 8522' GL 8522'/6980' Tubing 4 }2" 12.6# L-80 TC-II 7874' GL 7874'/6399' Integrity Testing: Test Point Depth Surface Casing Shoe 20' min from surface shoe Test Type LOT EMW 11.8 ppg EMW Target Cement Calculations: The following surface cement calculations are based upon a single stage job using a port collar as a / contingency if cement is not circulated to surface. Casing Size 19-518" Surface I Basis: Lead: Based on conductor set at 110', 1985' of annulus in the permafrost @ 225% excess and 732' of open hole from top of tail slurry to base permafrost @ 30% excess. Lead TOC: To surface Tail: Based on 747' MD(>500'TVD) open hole volume + 30% excess + 80' shoe track volume. Tail TOC: At -2827' MD,2429'TVD I Total Cement Volume: Lead 412 bbl I 2315fe I ~~s. 0 ~rctic Set Lite Permafrost cement at 10.7 Pfg ~d . 4,4/cf/sk. _ Tail 57.3 bbl I 322 ft' ~J.ßÆ 5 of 'G' at 15.8 ppg and~Y disk. ~..... ' Casing Size 17" Production Longstring I Basis: Stage 1: Based on TOC 500' above top of Kuparuk formation + 30% excess + 80' shoe Cement Placement: Tail from shoe to 7624' MD, lead from 7624' to 5596' which is 500' above the UGNU MA sand Total Cement Volume: Lead 70.6 bbls I 7 ft;j I@SkS of Litecrete slurry at 12.0 ppg and. disk. ...--., Tail 34.4 b '93 fe ~sks of gasBLOK 'G' at 15.8 ppg an disk. $-120 Drilling Program-Draft Page 5 e e Well Control: Surface hole will be drilled without diverter pending AOGCC approval. The production hole well control equipment consisting of 5000 psi working pressure pipe rams(2), blind/shear rams, and annular preventer will be installed and is capable of handling maximum potential surface pressures. Based upon the planned casing test fQr future fracture stimulation treatment, the BOP equipment will be tested to 4000 psi. / Oiverter, BOPE and drilling fluid system schematics on file with the AOGCC. An nearby well (5-215) has been injecting water into the Schrader for enhanced recovery. This well will be shut in and the pressure decline reported to drilling at least a week prior to rig arrival to ensure there is no overpressure in the Schrader above the expected 8.5 to 9.0 ppg range. Production Interval- · Maximum anticipated BHP: · Maximum surface pressure: 3350 psi @ 6700' TVOss - Kuparuk AS Sands 2680 psi @ surface (based on BHP and a full column of gas from TO @ 0.10 psi/ft) · Planned BOP test pressure: required for fracture stimulation.) · Planned completion fluid: 4000 psi (The casing and tubing will be tested to 4000 psi as / 8.6 ppg filtered seawater / 6.8 ppg diesel Disposal: · No annular disposal in this well. · Cuttings Handling: Cuttings generated from drilling operations will be hauled to grind and inject at OS-04. · Fluid Handling: Haul all drilling and completion fluids and other Class" wastes to OS- 04 for disposal. Haul all Class I wastes to Pad 3 for disposal. 8-120 Drilling Program-Draft Page 6 e e DRILL AND COMPLETE PROCEDURE SUMMARY Pre-Rig Work: The 20" conductor is in place. 1. Weld an FMC landing ring for the FMC Ultra slimhole wellhead on the conductor. 2. If necessary, level the pad and prepare location for rig move. Rig Operations: 1. MIRU Nabors 7ES. / 2. Nipple up spool (diverter waiver has been submitted). PU 4" DP as required and stand back in derrick. 3. MU 12 %" drilling assembly with MWD/GR to kick off at 300' and directionally drill surface hole to ./' approximately 100' TVD below the SV3 Sands. An intermediate wiper/bit trip to surface will be performed after exiting the Permafrost. 4. Run and cement the 9-5/8", 40# surface casing. Cement to surface. /' 5. ND riser spool and NU casing / tubing head. NU BOPE and test to 4000 psi. /' 6. MU 8-3/4" drilling assembly with MWD/GR & PWD, RIH to float collar. Test the 9-5/8" casing to 3500 psi for 30 minutes. 7. Drill out shoe joints and displace well to 9.7 ppg drilling fluid. Drill new formation to 20' below 9-5/8" shoe and perform Leak Off Test. 8. Drill to +/-100' above the HRZ, ensure mud can be conditioned for 10.0 ppg and perform short trips as / needed. Ensure Pre-Reservoir meeting is held highlighting kick tolerance and detection prior to entering HRZ. 9. Drill ahead to TD at -150' MD below Top Miluveach. 10. Condition hole for PEX/BHCS e-Iogging. 11. Run PEX/BHCS, if hole remains in good condition prepare to run 7" casing, otherwise, perform wiper /' trip and condition hole for running 7" 26# long-string casing. 12. POOH and lay down excess drillpipe above what can me left in the derrick for rig move. 13. Run and cement the 7" production casing in a single stage. (To be reviewed based on log/operational results.) Displace the cement with 8.5 ppg filtered seawater if single stage. 14. Freeze protect the 7" x 9-5/8" annulus as required with heated dead crude. Record formation breakdown pressure on the Morning Report. ,/ 15. Test casing to 4000 psi for 30 minutes. ,/ 16. Run the 4-1/2", 12.6#, L-80 TC-II completion assembly. Set packer at 200'MD above the top of ./ Kuparuk. Test the tubing to 4000 psi and annulus to 4000 psi for 30 minutes. Shear DCK shear valve and install TWC. Test below TWC to 1000 psi. 17. Nipple down the BOPE. Nipple up and test the tree to 5000 psi. Remove TWC. / 18. RU hot oil truck and freeze protect well by pumping diesel to lowermost GLM. Allow to equalize. 19. Rig down and move off. / USIT logging will be performed post-rig as will perforating. The USIT will need to be run prior to tubing only if the 7" cementing job goes poorly. S-120 Drilling Program-Draft Page 7 e e 5-120 Drilling Program Job 1: MIRU Hazards and Contingencies ~ S-Pad is not designated as an H2S site. Recent well tests indicate near 8ppm H2S concentrations as typical but S-40 had 70 ppm on 1/00. Standard Operating Procedures for H2S precautions should be followed at all times. ~ The closest well locations are: S-117, 15' to the north; S-213, 15' to the south. ~ / Two wells (S-213 and S-117, both producers at 15' away on either side) will require removal of the well house and a surface shut in during move in and move out. ~ Check the landing ring height on S-120 prior to rig mobilization. The BOP nipple up may need review for proper space out prior to spud. Reference RPs .:. "Drilling! Work over Close Proximity Surface and Subsurface Wells Procedure" Job 2: DrillinQ Surface Hole ~ There are two critical nearby wells in the surface hole. Those are the S-117 and the S-213 which are still 15 feet away from the planned wellpath in the interval of 398'MD to 550'MD ~ An electronic gyro survey is required per the directional plan to 1000' MD or until the magnetic interference at the surface has dissipated. ~ Gas hydrates have been observed in wells drilled on S-Pad. These were encountered near the base of permafrost to as deep as the SV1 sand. Hydrates will be treated at surface with appropriate mud products and adjustment of drilling parameters. Refer to MI mud recommendation ~ S-120is not expected to cross any faults in the surface hole. Reference RPs .:. "Prudhoe Bay Directional Guidelines" .:. "Well Control Operations Station Bill" .:. Follow Schlumberger logging practices and recommendations Operational Detail · 12-1/4" Bit Recommendation: Bit #1, MX-C1 new, Bit #2, MX-C1 new. The second bit can be picked up on a wiper trip just below the base of permafrost. . BHA: See attached Anadrill recommendations. · MWD: Directional MWD and GR will be used in this interval. · Surveys: Need to be IFR-MSA corrected. A gyro should be on standby for the surface interval until below close approach interval in the event of magnetic interference. · 5-1/2" liners will be used in the 12-1/4" hole section. · A wiper trip to surface will be performed shortly after breaking out of the Permafrost (about 1870'TVDss on the S-120). The second new bit should be picked up on this trip. S-120 Drilling Program-Draft Page 8 e e · Maintain mud viscosity near 300 sec/qt until below the Permafrost. The mud flow rate should be maintained at a reduced level until below the Permafrost, after exiting Permafrost the rate should be increased to about 600 gpm for improved hole cleaning. Adjust flow as needed to allow the breakout of hydrates without overflowing the pitcher nipple. · Once below the Permafrost the mud viscosity can be reduced to near 200 sec/qt while maintaining low-end rheology. The yield point should be held above 40. Hi-vis sweeps should be pumped to ensure the hole is being swept clean and to confirm that the thinned mud is functioning to provide hole cleaning. ./ · Optimize Connection Practices: Utilize the "Blow & Go" strategy for the surface interval, (these practices only apply to the surface interval, existing drilling practices will be followed for production interval.) o 30' wipes on connections, (unless hole conditions dictate pulling a full stand.) o Circulate to clear the BHA o No Trend Sheets. o Don't rotate while wiping. · String in Mix II (fiberous material) while drilling the high permeability SV sands to help minimize seepage losses and reduce the risk of differential sticking. · If operationally feasible, 3 stands prior to surface hole TD increase the flow rate to 650 gpm and pipe rotation to 85 rpm. At TD, maintain flow rate and pipe rotation for approximately 10 minutes. · When TD is reached, let drilling assembly sit no more than 10' off bottom with high flow rates and high rpm. Then work pipe no more than 40' off bottom while pumping sweeps and cleaning hole. · If significant tight hole conditions are encountered on the final trip out of the hole make a full wiper trip run with the directional assembly. · The on-site geologist will be needed throughout the surface hole section for correlation of formation markers and selection of an interval TD. The casing will be set to cover the SV3 sands, and the TD is expected at -100' TVD below the top of the SV3 sand in the first good competent shale (as required to fit casing strap and allow appropriate rat hole). S-120 Drilling Program-Draft Page 9 e e ~~ 0 ,,~~~~_-.~~-,-,TI.T~- Job 3: Install Surface CasinQ Hazards and Contingencies > It is critical that cement is circulated to surface for well integrity. Planned cement amount is: 225% excess cement through the permafrost zone and 30% excess below the permafrost. A 9-5/8" port collar will be positioned at ±1000'MD (if hole conditions indicate excessive washout) to allow remedial cementing should cement not reach the surface on the primary cementing job. It will be necessary to make a judgement call on wheter the hole is washed out more than normal. Reference RPs .:. "Casing and Liner Running Procedure" .:. "Surface Casing and Cementing Guidelines" .:. "Surface Casing Port Collar Procedure" Operational Details: · Review 'Surface Casing & Port Collar' RP as a contingency for not getting cement to surface on the single stage cement job. · Prepare a 9-5/8" 40# split landing joint to accommodate cementing via the port collar. (Review TAM Port Collar Procedure for details). · If a port collar is utilized, have the TAM port collar shifting tool available prior to cement job. · FMC Gen 5 Wellhead for casing & tubing Head. · Verify that Schlumberger have on-hand ±300 sacks of ArticSet Lite 3 cement in case the port / collar contingency is required. · Ensure all casing joints, shoe joints and TAM port collar are drifted for the upcoming 8 %" hole. . Make up casing as follows: o Halliburton float shoe. Verify ID is sufficient for 8 %" bit. o 2 joints of 9 5/8" 40# L-80 BTC csg. Ensure Baker has drifted to 8 %" prior to make-up. o Halliburton float collar. Verify ID is sufficient for 8 %" bit. o 9 5/8" 40# L-80 BTC casing to surface o FMC fluted mandrel hanger (drift pup joint to 8-3/4") o 95/8" split joint (see TAM collar RP) 9-58", 40#, L-80, BTC 100% 80% Collapse 3090 psi 2472 psi Burst 5750 psi 4600 psi Tensile 916,000 Ib 732,800 Ib ID 8.835" 8.679" drift Make-up Torque To Position · Centralizers: one bow-spring type per joint first 15 joints, plus one each side of the port collar if it is utilized. · With higher viscosity mud left in the hole for gravel suspension, be prepared to circulate for a longer period of time to condition the mud prior to pumping cement. Circulate to bring the mud viscosity to <100 sec/qt (15-25 yield point) · Reciprocate casing -10' while displacing cement. Report pipe reciprocation on Morning Report. S-120 Drilling Program-Draft Page 10 e e Note: Cement should be pumped according to the following pump schedule to optimize placement and to stay within the expected frac gradient of 13.0 ppg at the surface hole TO. Description Density Rate Volume CW 100 8.3 ppg 5.0 20 bbls Mud Push II 10.2 ppg 5.0 70.0 bbls Lead Slurry 10.7 ppg 5.0 412.0 bbls Tail Slurry 15.8 ppg 5.0 58 bbls Spud Mud 9.5 ppg 2-8.0 265 bbls Note: Check surface cement level prior to leaving well to establish if cement has slumped. Record depth tagged on Morning Report. If TOC greater than 20' below top of conductor, notify AOGCC and perform top job at an opportune time. Note: 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. Review the "Surface Casing and Port Collar RP" Job 7: Drillinq Production Hole Hazards and Contingencies þ> S-120 will cross one fault - in the lower Colville/HRZ at - 5900'TVDss, 7412' MD (+/- 250'). Lost circulation is considered to be a moderate risk. Consult the Lost Circulation Decision Tree regarding LCM treatments and procedures. ~ KICK TOLERANCE: In the scenario of 9.6 ppg pore pressure at the Kuparuk target depth, gauge hole, a fracture gradient of 11.6 ppg at the surface casing shoe, 10.0 ppg mud in the hole the kick /' tolerance is 26 bbls. An accurate LOT will be required as well as heightened awareness for kick detection. Contact Drilling Manager if LOT is less than 11.6 ppg. ~ Previous wells S-200 and S-201 encountered overpressure (10.0 ppg EMW) while drilling the UG4A. Mud weights of 10.1-10.3 were required to contain the pressure. Several S-Pad wells drilled in 2000 used 10.5 ppg to drill this interval as a precaution. Since that time nineteen wells have been drilled on S Pad without encountering the overpressure. Gas cut mud, mud flow and oil in the returns may indicate that the overpressure is still present at which point the mud should be weighted up. þ> Caution should be exercised when crossing the Schrader interval. Nearby water injection on the S-215 Schrader well will be halted at least a week prior to arrival of 7ES to allow pressure falloff in the Schrader. Expected pressure is 8.5-9.0 ppg but the potential exists for pressure to a maximum of 12.0 ppg. Pressure falloff following shutin of the S-215 will be monitored and reported to the drilling crew. Reference RPs .:. Standard Operating Procedure for Leak-off and Formation Integrity Tests .:. Prudhoe Bay Directional Guidelines .:. Lubricants for Torque and Drag Management. .:. "Shale Drilling- Kingak & HRZ" S-120 Drilling Program-Draft Page 11 e e Operational Details: · Bit Recommendations: Bit #1, 8-3/4" Hycalog DS70FNPV (new) will be used on this well. If a subsequent bit is needed to reach TD, a RR 8-3/4" DS70FNPV should be utilized. · BHA: See attached Anadrill BHA recommendation. · MWD: Directional MWD with GR will be used in this interval to TD. Set up tools for low flow rate 300-600 gpm. · Maximum surface pressure expected is 3000-3500 psi. 5.0" liners with a 4,330 psi. pressure rating will be utilized in the intermediate hole section. · Displace the hole to new 9.7 ppg LSND drilling fluid after drilling the shoe track, displace and then drill 20 ft new hole. Perform LOT- Se~ note in Hazards and Contingencies. A 575 gpm pump rate and 100 rpm (when feasible)~fecommended based on hole cleaning models and recent successes. Refer to attached mud program for additional operational specifics and contingencies. · Obtain initial ECD benchmark readings with PWD tool prior to drilling production hole after completing the LOT. · Suggested Drilling Parameters Initial Drill out 500-1000' of new hole Exercise care when drilling the first 500-1000' below the surface casing shoe. Excessive ECD's have been encountered when drilling ROP's have been allowed to exceed BOO'/hr. Monitor ECD's as outlined in the Forward Plan and only exceed these limits with the acknowledgment of the BP Drilling Supervisor. SV1, UGNU, W. Sak and top 100' TVD into CM3 Drill pipe 80-100 RPM to maintain adequate hole cleaning and directional control. 5-15K WOB or >150 psi motor differential (enough WOB to keep the bit drilling smoothly in it's bottom hole pattern.) Maximum flow rate possible (575 gpm) Clean up well if ECD starts approaching 1.0 ppg over baseline CM3 to Top of KUPARUK 5-15K WOB to maximize Rap through this interval. Drill pipe RPM of 80 - 100 rpm to optimize hole cleaning and directional control Optimum Flow Rate 575 gpm. Clean up well if ECD starts approaching 1.0 ppg over baseline Note: Review Hole Cleaning Minimums earlier in this Drilling Program. MI engineer should run additional modeling as required "real time" to ensure minimum hole cleaning objectives are being met. S-120 Drilling Program-Draft Page 12 It e Connection Practices Backream the full stand at drilling rate (this may be reduced as we get deeper in the well). Ream down with 100 rpm and 75% drilling flow rate. Watch PWD for ECD spikes. If PWD readings indicate hole cleaning is effective, backreaming may be reduced to speed up connection time as long as ECD's do not exceed 1.0 ppg over baseline ECD. Tripping Practices Rotary and flow rate at maximum rate during bottoms up prior to tripping. Utilize sweep strategy outlined in MI Mud recommendation. Watch PWD for ECD spikes. Prior to tripping, use PWD to determine when hole is sufficiently clean based on ECD of .3 ppg over clean mud ECD. · Prior to entering HRZ the mud weight should be increased to 10.0 ppg by stringing in a weighted slurry. · Hold a Pre-Reservoir meeting prior to entering the HRZ, (during conditioning mud system prior to drilling the HRZ or other opportune time), emphasizing the need for a heightened awareness of kick detection and low kick tolerance while drilling the 9.5 to 9.7 ppg EMW reservoir. · During drilling of tangent section, increase rpm to maximum allowable to assist in hole cleaning. With a 1.5 motor approximately 120 rpm should be feasible. Discuss Plan Forward with Drilling Manager/ODE to determine maximum acceptable rate. TO criteria: Production hole section will penetrate 150'MD below the Kuparuk A5 sand. This will allow e-line 10QS over the entire Kuparuk formation and provide adequate rathole for future operations (Need to have 50' of useable casinQ below the A5 and above the float collar. Job 8: Loq Production Hole Hazards and Contingencies )0- Ensure the hole is in optimal condition prior to logging to ensure a successful logging program. Review the use of lubricant pill across logging interval. The log run will be PEX with sonic. )0- If logging time is excessive or hole conditions dictate, perform a clean out run prior to running the 7"longstring casing. Reference RPs .:. Follow Schlumberger logging practices and recommendations. Job 9: Case & Cement Production Hole Hazards and Contingencies )0- The interval is planned to be cemented in a single stage with a 12.0 ppg lead ( to 500'MD above the UGNU MA) and a 15.8 ppg tail (top at 500' above the Kuparuk). If a single stage cement job is deemed too risky while drilling, then a 2 stage cement job may be performed. ~ Ensure the upper production cement has reached at least a 70BC thickening value prior to freeze protecting. Ensure a double-barrier at the surface on the annulus exists until the cement has set up for at least 12 hours. 8-120 Drilling Program-Draft Page 13 e e ~ Pump approximately Y2 the volume of the casing by casing annulus prior to its freezing. After freeze protecting the 7" x 9-5/8" casing outer annulus with dead crude (estimated at 7.5 ppg) to 2485' MD, 2200'TVD, the hydrostatic pressure will be less than the formation pressure immediately below the shoe. To prevent pressure on the annulus pump 31 bbl of 11.6 ppg mud ahead of the dead crude, this should balance formation pressure at the shoe. ~ Cement is being placed from TD to 500' above the UGNU MA (top at 6096'MD/4734'TVD). Planned TOC is 5596'MD which is less than 2000' below the 9-5/8" casing shoe. It may be prudent to insure the 9-5/8" x 7" annulus is clear if there is a delay in cement reaching adequate thickening/compressive strength development. Þ- Ensure a minimum hydrostatic equivalent of 10.2 ppg on the Kuparuk formation during pumping of cement pre flushes/chemical washes. Losses of hole integrity and packing off has resulted from a reduction in hydrostatic pressure while pumping spacers and flushes. Þ- Instability of the Miluveach and Kalubik has been observed on some previous wells. Should there be indication of hole slough into the wellbore from the Miluveach the casing shoe depth may be pulled upwards and a cleanout of shoe joints required to regain rathole. Þ- Considerable losses during running and cementing the 7" longstring has been experienced on offset wells. A casing running program will be jointly issued by the ODE and Drilling Supervisor detailing circulating points and running speed. In addition, a LCM pill composed of "G Seal" may be placed across the Schrader and Ugnu to help arrest mud dehydration. Reference RPs .:. "Intermediate Casing and Cementing Guidelines" .:. "Freeze Protecting an Outer Annulus" Operational Detail: . Make up casing as follows: o 7" Halliburton Float Shoe o 2 joints 7" 26# L-80 BTC-mod casing o 7" Halliburton Float Collar o 7" 26# L-80 BTC-mod casing to surface. 7", 26#, L-80, BTC-mod 100% 80% Collapse 5410 psi 4328 psi Burst 7240 psi 5792 psi Tensile 604,000 Ib 483,200 Ib ID 6.276" 6.151" drift Make-up Torque To Position Note: Long bails may be required to accommodate the cement head. · Centralization: For planning purposes, 1 per joint 7" x 8-1/4" solid centralizers (floating) from the shoe to 200' above the top of Kuparuk, none to 200' below the Schrader and thereafter 1 per joint to 200' above the Schrader Ma. This program will be modified dependant on hole conditions and log evaluation of Schrader. · Two short joints are required. One near the top of Kuparuk and another near the base of Kuparuk A5. S-120 Drilling Program-Draft Page 14 - It . 7" Cementing: 1) If possible reciprocate pipe while circulating and cementing. At any indication of sticking and or deteriorating hole conditions, land the hanger. 2) Pump 5 bbls Mud Push and test the cement lines to 4000 psig. 3) Bleed off the test pressure and load bottom plug. 4) Pump remaining Mud Push spacer. Drop bottom plug. 5) Pump cement as per Dowell program attached. Drop top plug. 6) Switch to the rig pumps and displace the cement with filtered seawater. Ensure that the rate and pressures are being recorded during rig displacement. Note Dowell pump schedule in regards to slowing displacement to avoid exceeding the fracture pressure. 7) Continue displacing the cement until the plug is bumped. Bump plug with 1000 psi over final circulating pressure. Continue pressure up to 4000 psi for casing pressure test. If the plug does not bump, displace half of the shoe track (1.5 bbls) and check floats. Note: Cement should be pumped according to the following pump schedule to optimize placement and stay within the expected frac gradient of 13.5 ppg at the well TD. Description Density Rate Volume Mud Push II 11.0 ppg 5.0 50.0 bbls LiteCrete 12.0 ppg 5.0 71bbls Tail Slurry 15.8 ppg 5.0 35 bbls Filtered Seawater 8.4 ppg 8.0 300 bbls Filtered Seawater 8.4 ppg 2.0 23.1 bbls · Plan casing test for after cement has reached a minimum 1000 psi compressive strength. Ensure the upper lead cement has reached at least a 70BC thickening value prior to freeze protecting. · Pressure test casing to 4000 psi on chart recorder for 30 minutes if not pressure tested during plug bump above. Ensure DIMS morning report details test pressure and duration. Ensure a double-barrier at the surface on the annulus exists until the cement has set up for at least 12 hours. After freeze protecting the 7" x 9-5/8" casing outer annulus with heated dead crude to 2485' MD, 2200'TVD), the hydrostatic pressure will be underbalanced to formation pressure by about 115 psi unless a higher density mud is pumped ahead. Pump 31 bbl of 11.6 ppg mud ahead of the 70 bbl of dead crude (@ 7.5 ppg for dead crude). This should balance the formation pressure below the shoe which is estimated at 8.5 ppg. Record the formation break-down pressure as an equivalent mud weight (LOT) and report on the morning report. Job 12: Run Completion Hazards and Contingencies ).- Watch hole fill closely and verify proper safety valves are on the rig floor while running this completion. The well will be underbalanced if there is a casing integrity problem. ).- When testing annulus maintain no more than a 1500 psi differential: 2500 psi tubing pressure, 4000 psi annulus pressure to avoid premature shear of the DCK valve. Avoid cycling pressure (pumping up and bleeding off) prior to activating shear valve as this is thought to cause shearing at lower pressures. S-120 Drilling Program-Draft Page 15 e e Reference RPs .:. Completion Design and Running .:. Freeze Protection of Inner Annulus Operational Details: · The following requirements have been captured in the "proposed" diagram with relative spacing between jewelry: a 4-1/2" 12.6 Iblft L-80, TC-II tbg- below tubing hanger a 3.813" X nipple for 4-1/2" tbg at 2200' MD a 4-1/2" 12.6 Ibltt L-80 tbg a GLMs (4 W' X 1" KG B-2) - No.2 at 3800' TVD with dummy valve, a The NO.1 valve at two joints above the packer (with DCK shear valve) a 3.813" X nipple for 4-1/2" tbg at one joint above the packer. a 7" X 4-1/2" PREMIER packer at approximately 200' above the Kuparuk top. a Tailpipe below packer: (X/O, 10' pup, 10' pup, 3.813" X nipple, 10' pup, 10' pup, 3.750" XN nipple, 10' pup, WLEG a RHC plug in the bottom nipple (XN) of the tailpipe assembly Note: Use JetLube Sealguard thread compound on the TC-II connections. Note: Pull wear bushing! · With the tubing spaced out and landed in the wellhead, spot filtered seawater with Corexit corrosion inhibitor above the packer. · Drop ball and rod and set packer with 4000 psi on tubing side, hold for 30 minute tubing test on a chart, atter packer is set and test completed, slowly bleed tubing down to 2500 psi. Pressure up annulus to 4000 psi and hold 4000 psi for 30 minutes for casing test on chart recorder. Bleed off pressure from tubing side slowly until DCK valve shears, bleed off all pressure. Install a TWC with T-bar. Test from below to 1000 psi. Nipple down the BOPE. Nipple up production tree and test to 5000 psi. Remove TWC with lubricator 5-120 Drilling Program-Draft Page 16 e e Job 13: ND/NUlRelease Riq Hazards and Contingencies ~ No hazards specific to this well have been identified for this phase of the well construction. Reference RPs .:. Freeze Protection of Inner Annulus Operational Specifics · ND stack. NU tree and test to 250 and 5000 psi with diesel. Test packott to 5000 psi. Pull TWC. · R/U hot oil truck and freeze protect well by reverse circulating diesel to provide diesel to 2200'TVD after allowing to U-tube. Allow diesel to U-tube from annulus to tubing and equalize. Refer to RP: Freeze Protection of Inner Annulus. · Install BPV & test to 1000 psi from below. . Rig down and release the rig. $-120 Drilling Program-Draft Page 17 e e S-120 Well Summary of Drillina Hazards POST THIS NOTICE IN THE DOGHOUSE Surface Hole Section: · Gas hydrates may be encountered near the base of the Permafrost at 2095'MD and near the hole section TD as well. · S-30 and S-25 located on the Southern portion of the pad, reported outer annulus pressures in the past. In December 2002 S-25 was shut in. S-30 is on production however and is being monitored. The pressure does not appear to have charged up any shallow sands in the wells drilled since that time. · Gravel beds below the Permafrost will tend to slough in when aerated (hydrate cut) mud is being circulated out. Ensure adequate mud viscosity is maintained to avoid stuck pipe situations. Production Hole Section: · The production section will be drilled with a recommended mud weight of 10.0 ppg to ensure shale stability in the HRZ shale and to cover the Kuparuk's 9.5 ppg pore pressure. · Previous wells S-200 and S-201 encountered overpressure (10.0 ppg EMW) while drilling the UG4A. Mud weights of 10.1-10.3 were required to contain the pressure. Several S-Pad wells drilled in 2000 used 10.5 ppg to drill this interval as a precaution. Since that time nineteen wells have been drilled on S Pad without encountering the overpressure. Gas cut mud, mud flow and oil in the returns may indicate that the overpressure is still present at which point the mud should be weighted up. · Maintain caution for potential inflow while drilling the Schrader which could retain some overpressure for water injection. · S-120 will cross a fault at -5900' TVDss, 7412' MD (+/-250') in the Lower Colville/HRZ. Lost circulation is considered to be a moderate risk. Consult the Lost Circulation Decision Tree regarding LCM treatments and procedures. HYDROGEN SULFIDE - H2S / · This drill-site is not designated as an H2S drill site. Recent wells tests indicate 8 ppm H2S concentration in Kuparuk wells. Standard Operating Procedures for H2S precautions should be followed at all times. CONSULT THE S-PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION 8-120 Drilling Program-Draft Page 18 TREE = WELLHEAO = ACTUA TOR = KB. ELEV = ..~~ .......~, BF. ELEV = KOP= Max Angle = . MW _..._______ . Datum MD = DatumlVD= 4-1/16" CrN FMC NA 64.7 36.2 500 .' '"'' u________··m. 4:8@2280 ".-:---'.:::------....",..«..........'::::::.] e XXX' SS 9-518" CSG, 40#, L-80, ID = 8.835" H 3474' ~ Minimum ID = 3.750" 4-1/2" HES XN NIPPLE 14-1/2" TBG, 12.6#, L-80, TC-II PERFORA TION SUMMARY REF LOG: TCP ÆRF ANGLEATTOPPERF: xx @ xxxx' Note: Refer to Production DB for historical perf data SIZE SPF INTERV AL Opn/Sqz DA TE L PBTD Ii 17" CSG, 26#, L-80, .0383 bpf, 10 = 6.276" Ii 8440' 8522' OA TE REV BY COMMENTS 10/16/03 JES PROPOSED COMPLETION 8-120 / - - =1 ST MD 1 4970 2 7844 ---L z .~. I \ . ~ DA TE REV BY COMMENTS . 1000' 2200' contingent 9-5/8" TAM I PORT COLLAR 4-1/2"HESXNIP,ID=3.813" I GAS LIFT MANDRELS lVD DEV TYÆ VLV LATCH PORT 3800 6371 DATE 7844' H 7" X 4-1/2" BKR Prerrier PKR within 200' of Kuparuk top 4-112' X riij:fe 4-1I2')tJ riWe Short Joints 1jt above top KUP and 1 at base A5 GPB AURORA WELL: S-120 ÆRMrT No: API No: BP Exploration (Alaska) S-120 (P4) Proposal Schlumberger Report Date: October 17, 2003 Survey / DLS Computation Method: Minimum Curvature 1 Lubinski Client: 8P Exploration Alaska Vertical Section Azimuth: 283.690° Field: Prudhoe 8ay Unit - WOA studY Vertical Section Origin: N 0.000 ft, E 0.000 It Structure / Slot: S-PAD 1 Slot 4 1111II ty TVD Reference Datum: K8 Well: Plan S-120 ø I TVD Reference Elevation: 64.3 ft relative to MSL Borehole: S-120 Feasl b Sea Bed / Ground Level Elevation: 0.000 It relative to MSL UWI/API#: 50029 Magnetic Declination: 25.292° Survey Name 1 Date: S-120 (P4) 1 October 16, 2003 Total Field Strength: 57566.161 nT Tort I AHD I DDII ERD ratio: 76.567" 14298.34 It 15.6021 0.613 Magnetic Dip: 80.855° Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feel Declination Date: December 17, 2003 Location LatlLong: N 70.35555315, W 149.03415147 Magnetic Declination Model: 8GGM 2003 e Location Grid N/E YIX: N 5980564.330 ftUS, E 618930.210 ItUS North Reference: True North Grid Convergence Angle: ..0.90964295° Total Corr Mag North -) True North: +25.292° Grid Scale Factor: 0.99991607 Local Coordinates Referenced To: Well Head I Comments Measured I Inclination I Azimuth I TVD I Sub-Sea TVD I Vertical I NS EW I DLS I Build Rate I Walk Rate I Tool Face I Northing Easting Latitude Longitude Depth Section (It) (deg) (deg ) (It) (It) (It) (It) (It) (deg/100 It) (deg/100 It) (deg/100 It) (deg ) (ltUS) (ltUS) KBE 0.00 0.00 282.71 0.00 -64.30 0.00 0.00 0.00 0.00 0.00 0.00 -77.29M 5980564.33 618930.21 N 70.35555315 W 149.03415147 KOP Bid 11100 300.00 0.00 282.71 300.00 235.70 0.00 0.00 0.00 0.00 0.00 0.00 -77.29M 5980564.33 618930.21 N 70.35555315 W 149.03415147 Bid 2.5/100 400.00 1.00 282.71 399.99 335.69 0.87 0.19 -0.85 1.00 1.00 0.00 -77.29M 5980564.51 618929.36 N 70.35555368 W 149.03415838 G1 401.31 1.03 282.71 401.30 337.00 0.90 0.20 -0.87 2.50 2.50 0.00 -77.29M 5980564.51 618929.33 N 70.35555369 W 149.03415857 500.00 3.50 282.71 499.91 435.61 4.80 1.06 -4.68 2.50 2.50 0.00 -77.29M 5980565.31 618925.51 N 70.35555604 W 149.03418948 600.00 6.00 282.71 599.56 535.26 13.08 2.88 -12.76 2.50 2.50 0.00 O.OOG 5980567.00 618917.41 N 70.35556101 W 149.03425507 700.00 8.50 282.71 698.75 634.45 25.69 5.65 -25.07 2.50 2.50 0.00 O.OOG 5980569.59 618905.06 N 70.35556860 W 149.03435502 800.00 11.00 282.71 797.30 733.00 42.62 9.38 -41.59 2.50 2.50 0.00 O.OOG 5980573.05 618888.48 N 70.35557878 W 149.03448915 900.00 13.50 282.71 895.01 830.71 63.84 14.05 -62.28 2.50 2.50 0.00 O.OOG 5980577.39 618867.72 N 70.35559153 W 149.03465721 1000.00 16.00 282.71 991.71 927.41 89.29 19.65 -87.12 2.50 2.50 0.00 O.OOG 5980582.59 618842.80 N 70.35560683 W 149.03485886 1100.00 18.50 282.71 1087.21 1022.91 118.94 26.18 -116.04 2.50 2.50 0.00 O.OOG 5980588.66 618813.78 N 70.35562466 W 149.03509373 1200.00 21.00 282.71 1181.32 1117.02 152.72 33.61 -149.00 2.50 2.50 0.00 O.OOG 5980595.57 618780.71 N 70.35564497 W 149..138 1300.00 23.50 282.71 1273.86 1209.56 190.58 41.94 -185.94 2.50 2.50 0.00 O.OOG 5980603.31 618743.65 N 70.35566773 W 149. ~28 1400.00 26.00 282.71 1364.67 1300.37 232.44 51.15 -226.77 2.50 2.50 0.00 O.OOG 5980611.87 618702.67 N 70.35569289 W 149. 288 1500.00 28.50 282.71 1453.56 1389.26 278.21 61.23 -271.43 2.50 2.50 0.00 O.OOG 5980621.24 618657.86 N 70.35572041 W 149.03635554 1600.00 31.00 282.71 1540.38 1476.08 327.82 72.15 -319.84 2.50 2.50 0.00 O.OOG 5980631.38 618609.30 N 70.35575023 W 149.03674857 1700.00 33.50 282.71 1624.94 1560.64 381.17 83.89 -371.89 2.50 2.50 0.00 O.OOG 5980642.30 618557.07 N 70.35578230 W 149.03717122 SV6 1705.23 33.63 282.71 1629.30 1565.00 384.06 84.52 -374.71 2.50 2.50 0.00 O.OOG 5980642.89 618554.24 N 70.35578403 W 149.03719412 1800.00 36.00 282.71 1707.10 1642.80 438.16 96.43 -427.48 2.50 2.50 0.00 O.OOG 5980653.95 618501.29 N 70.35581655 W 149.03762269 1900.00 38.50 282.71 1786.70 1722.40 498.68 109.75 -486.52 2.50 2.50 0.00 O.OOG 5980666.33 618442.05 N 70.35585292 W 149.03810212 2000.00 41.00 282.71 1863.57 1799.27 562.61 123.82 -548.90 2.50 2.50 0.00 O.OOG 5980679.41 618379.46 N 70.35589135 W 149.03860859 Base Perm 2095.47 43.39 282.71 1934.30 1870.00 626.71 137.92 -611.44 2.50 2.50 0.00 O.OOG 5980692.52 618316.71 N 70.35592988 W 149.03911647 2100.00 43.50 282.71 1937.59 1873.29 629.83 138.61 -614.48 2.50 2.50 0.00 O.OOG 5980693.16 618313.66 N 70.35593175 W 149.03914115 Well Design Ver 3.1RT-8P3.03-HF1.2 Bld( d031rt-546) 810t 41Plan 8-12018-120\8-120 (P4) Generated 10/17/20038:33 AM Page 1 of 3 Comments Measured I Inclination I Azimuth I TVD I Sub-Sea TVD I Vertical I NS EW I DLS I Build Rate I Walk Rate I Tool Face I Northing Easting Latitude Longitude Depth Section (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) (deg/100 ft) (deg/100 ft) (deg/100 ft) (deg ) (ftUS) (ftUS) 2200.00 46.00 282.71 2008.60 1944.30 700.21 154.10 -683.15 2.50 2.50 0.00 O.OOG 5980707.55 618244.76 N 70.35597405 W 149.03969878 End Bid 2279.76 47.99 282.71 2063.00 1998.70 758.53 166.93 -740.04 2.50 2.50 0.00 O.OOG 5980719.48 618187.67 N 70.35600910 W 149.04016078 EOGU 2393.78 47.99 282.71 2139.30 2075.00 843.24 185.58 -822.69 0.00 0.00 0.00 O.OOG 5980736.81 618104.74 N 70.35606001 W 149.04083192 SV5 2550.68 47.99 282.71 2244.30 2180.00 959.81 211.23 -936.43 0.00 0.00 0.00 O.OOG 5980760.65 617990.63 N 70.35613006 W 149.04175548 SV4 2842.07 47.99 282.71 2439.30 2375.00 1176.31 258.88 -1147.64 0.00 0.00 0.00 O.OOG 5980804.93 617778.70 N 70.35626014 W 149.04347066 SV3 3424.84 47.99 282.71 2829.30 2765.00 1609.29 354.16 -1570.07 0.00 0.00 0.00 O.OOG 5980893.50 617354.85 N 70.35652025 W 149.04690109 9-518" Gsg Pt 3574.27 47.99 282.71 2929.30 2865.00 1720.31 378.60 -1678.39 0.00 0.00 0.00 O.OOG 5980916.20 617246.17 N 70.35658693 W 149.04778071 SV2 3634.05 47.99 282.71 2969.30 2905.00 1764.72 388.37 -1721.72 0.00 0.00 0.00 O.OOG 5980925.29 617202.69 N 70.35661360 W 149.04813255 SV1 4104.75 47.99 282.71 3284.30 3220.00 2114.44 465.34 -2062.91 0.00 0.00 0.00 O.OOG 5980996.82 616860.35 N 70.35682363 W 149.05090338 UG4 4612.81 47.99 282.71 3624.30 3560.00 2491.91 548.41 -2431.19 0.00 0.00 0.00 O.OOG 5981074.03 616490.83 N 70.35705027 W 149.05389417 UG4A 4687.53 47.99 282.71 3674.30 3610.00 2547.42 560.62 -2485.34 0.00 0.00 0.00 O.OOG 5981085.38 616436.49 N 70.35708360 W 149.0.00 Drp 2/100 5082.31 47.99 282.71 3938.49 3874.19 2840.73 625.17 -2771.51 0.00 0.00 0.00 176.80G 5981145.38 616149.37 N 70.35725967 W 149.0 03 5100.00 47.64 282.74 3950.37 3886.07 2853.83 628.06 -2784.29 2.00 -2.00 0.15 176.78G 5981148.06 616136.54 N 70.35726754 W 149.05676186 UG3 5135.28 46.94 282.79 3974.30 3910.00 2879.75 633.79 -2809.57 2.00 -2.00 0.15 176.74G 5981153.39 616111.17 N 70.35728317 W 149.05696717 5200.00 45.64 282.90 4019.02 3954.72 2926.53 644.19 -2855.19 2.00 -2.00 0.16 176.67G 5981163.06 616065.40 N 70.35731153 W 149.05733762 5300.00 43.65 283.06 4090.17 4025.87 2996.79 659.97 -2923.66 2.00 -2.00 0.17 176.55G 5981177.75 615996.69 N 70.35735457 W 149.05789372 5400.00 41.65 283.24 4163.71 4099.41 3064.54 675.38 -2989.63 2.00 -2.00 0.18 176.42G 5981192.11 615930.49 N 70.35739661 W 149.05842950 5500.00 39.66 283.44 4239.58 4175.28 3129.68 69Q.42 -3053.02 2.00 -2.00 0.20 176.27G 5981206.14 615866.88 N 70.35743761 W 149.05894429 5600.00 37.66 283.65 4317.66 4253.36 3192.14 705.05 -3113.74 2.00 -2.00 0.21 176.10G 5981219.80 615805.94 N 70.35747750 W 149.05943748 5700.00 35.66 283.89 4397.88 4333.58 3251.85 719.25 -3171.73 2.00 -2.00 0.23 175.92G 5981233.08 615747.73 N 70.35751625 W 149.05990847 UG1 5786.98 33.93 284.11 4469.30 4405.00 3301.49 731.26 -3219.90 2.00 -1.99 0.26 175.73G 5981244.32 615699.39 N 70.35754899 W 149.06029962 5800.00 33.67 284.14 4480.12 4415.82 3308.73 733.02 -3226.92 2.00 -1.99 0.27 175.71G 5981245.97 615692.34 N 70.35755381 W 149.06035667 5900.00 31.68 284.43 4564.29 4499.99 3362.71 746.34 -3279.23 2.00 -1.99 0.29 175.47G 5981258.46 615639.83 N 70.35759013 W 149.06078154 6000.00 29.68 284.75 4650.29 4585.99 3413.72 759.19 -3328.61 2.00 -1.99 0.32 175.19G 5981270.52 615590.26 N 70.35762516 W 149.06118256 Ma 6095.81 27.77 285.09 4734.30 4670.00 3459.76 771.04 -3373.10 2.00 -1.99 0.36 174.89G 5981281.66 615545.58 N 70.35765748 W 149.06154395 6100.00 27.69 285.11 4738.01 4673.71 3461.71 771.55 -3374.99 2.00 -1.99 0.38 174.87G 5981282.14 615543.69 N 70.35765887 W 149.06155925 6200.00 25.70 285.52 4827.35 4763.05 3506.61 783.41 -3418.32 2.00 -1.99 0.41 174.51G 5981293.31 615500.18 N 70.35769121 W 149.06191114 6300.00 23.71 286.00 4918.19 4853.89 3548.37 794.75 -3458.54 2.00 -1.99 0.48 174.07G 5981304.01 615459.79 N 70.35772215 W 149.06223782 Na 6317.57 23.36 286.09 4934.30 4870.00 3555.38 796.69 -3465.28 2.00 -1.99 0.52 173.99G 5981305.84 615453.02 N 70.35772744 W 149.06229257 6400.00 21.72 286.55 5010.43 4946.13 3586.95 805.56 -3495.60 2.00 -1.99 0.57 173.56G 5981314.23 615422.56 N 70.35775164 W 149..87 OA 6452.41 20.68 286.89 5059.30 4995.00 3605.87 811.01 -3513.75 2.00 -1.99 0.64 173.25G 5981319.39 615404.33 N 70.35776651 W 149. 30 6500.00 19.73 287.22 5103.96 5039.66 3622.28 815.83 -3529.47 2.00 -1.99 0.70 172.94G 5981323.96 615388.54 N 70.35777966 W 149.06281393 8-120 Fit Tgt 6510.98 19.52 287.30 5114.30 5050.00 3625.96 816.93 -3532.99 2.00 -1.98 0.74 O.OOG 5981325.00 615385.00 N 70.35778264 W 149.06284254 OBd 6648.91 19.52 287.30 5244.30 5180.00 3671.95 830.63 -3576.98 0.00 0.00 0.00 O.OOG 5981338.00 615340.80 N 70.35782002 W 149.06319984 OBf Base 6792.13 19.52 287.30 5379.30 5315.00 3719.70 844.86 -3622.67 0.00 0.00 0.00 O.OOG 5981351.50 615294.90 N 70.35785883 W 149.06357089 GM1 7858.39 19.52 287.30 6384.30 6320.00 4075.20 950.78 -3962.76 0.00 0.00 0.00 O.OOG 5981452.00 614953.20 N 70.35814772 W 149.06633320 Top HRZ 8038.75 19.52 287.30 6554.30 6490.00 4135.33 968.69 -4020.28 0.00 0.00 0.00 O.OOG 5981469.00 614895.40 N 70.35819659 W 149.06680046 8-120 Tgt 8102.41 19.52 287.30 6614.30 6550.00 4156.55 975.02 -4040.59 0.00 0.00 0.00 O.OOG 5981475.00 614875.00 N 70.35821383 W 149.06696538 Kalubik 8118.33 19.52 287.30 6629.30 6565.00 4161.86 976.60 -4045.66 0.00 0.00 0.00 O.OOG 5981476.50 614869.90 N 70.35821815 W 149.06700661 Top Kup I G4 8123.63 19.52 287.30 6634.30 6570.00 4163.63 977.13 -4047.36 0.00 0.00 0.00 O.OOG 5981477.00 614868.20 N 70.35821958 W 149.06702035 Kup G2B 8133.18 19.52 287.30 6643.30 6579.00 4166.81 978.07 -4050.40 0.00 0.00 0.00 O.OOG 5981477.90 614865.14 N 70.35822217 W 149.06704509 WellDesign Ver 3.1 RT-8P3.03-HF1.2 Bld( d031 rt-546 ) 810t 41Plan 8-12018-120\8-120 (P4) Generated 10/17/20038:33 AM Page 2 of 3 Comments Measured I Inclination I Azimuth I TVD I Sub-Sea TVD I Vertical I NS EW I DLS I Build Rate I Walk Rate I Tool Face I Northing Easting Latitude Longitude Depth Section (It) (deg) (deg) (It) (It) (II) (It) (II) (deg/100 It) (deg/100 II) (deg/100 II) (deg ) (IIUS) (IIUS) Kup G1G 8193.65 19.52 287.30 6700.30 6636.00 4186.97 984.08 -4069.69 0.00 0.00 0.00 O.OOG 5981483.60 614845.76 N 70.35823855 W 149.06720176 LGU / Kup B 8213.81 19.52 287.30 6719.30 6655.00 4193.69 986.08 -4076.12 0.00 0.00 0.00 O.OOG 5981485.50 614839.30 N 70.35824401 W 149.06725399 Kup A5 8298.69 19.52 287.30 6799.30 6735.00 4221.99 994.52 -4103.19 0.00 0.00 0.00 O.OOG 5981493.50 614812.10 N 70.35826701 W 149.06747388 TMLV 8371.89 ./' 19.52 287.30 6868.30 6804.00 4246.40 1001.79 -4126.54 0.00 0.00 0.00 O.OOG 5981500.40 614788.64 N 70.35828684 W 149.06766353 TD / 7" Csg 8521.89 19.52 287.30 7009.68 6945.38 4296.41 1016.69 -4174.38 0.00 0.00 0.00 O.OOG 5981514.54 614740.57 N 70.35832747 W 149.06805214 LeQal Description: 8urface: 4360 F8L 4500 FEL 835 T12N R12E UM Fault Target: 5176 F8L 2752 FEL 834 T12N R12E UM 8-120 Kup Target: 54 F8L 3259 FEL 827 T12N R12E UM BHL: 96 F8L 3393 FEL 827 T12N R12E UM NorthinQ (Y) [ftUSl 5980564.33 5981325.00 5981475.00 5981514.54 EastinQ ¡X} [ftUSl 618930.21 615385.00 614875.00 614740.57 e e WellDesign Ver 3.1 RT-8P3.03-HF1.2 Bld( d031 rt-546 ) 810t 41Plan 8-12018-12018-120 (P4) Generated 10/17/20038:33 AM Page 3 of 3 e e Schlumberger WELL S-120 (P4) FIelD Prudhoe Bay Unit - WOA STRUCTURE S-PAD Magnetic Parameters Model" BGGM2003 Dip: 80.855' MagDec +25.292" I Surface Location Date: December 17,2003 Lat N702119.991 FS: 57566.2 nT W1492 2.945 NAD27 Alaska stale Planes, Zone 04, US Feat Northing" 5980564.33 ftUS Grid Caw: +0.90964295" Easting: 618930.21 ftUS Scale Fact: 0.9999160677 Miscellaneous Slot Slot 4 Plan" $-120 (P4) TVDRef: KB(64.30naboveMSl) StvyDate: October 16. 2003 o 1000 2000 3000 4000 5000 o o _KOP Bid 11100 1000 1000 2000 2000 3000 3000 e- O 0 0 ~ §: ~ II Q) ëñ 4000 4000 () en 0 > f- 5000 5000 6000 6000 &-120 Tgt 7000 7000 TO /7" Csg o 1000 2000 3000 4000 Vertical Section (ft) Azim = 283.69°, Scale = 1(in):1000(ft) Origin = 0 N/-S, 0 E/-W 5000 ^ ^ ^ z g o o ~ ê ;;:;- ..... II Q) ëij () C/) C/) V V V WELL S-120 9P4) Magnetic Parameters Model: BGGM 2003 Dip 80.855' MagDec +25.292' -4000 -3500 1500 1000 500 .."'''..{......'''''''.... "H.",O"""" ........'1 o -500 ""....{.. .,.,....~.. -4000 -3500 Schlumberger FIELD STRUCTURE S-PAD . . . . . . . . . . 4ç.'·'· . ~ ~~S'120FltTgt /D~ 2/1001 +'''~\;Tmi:=\;mmmlm ""~5{ ~I Prudhoe Bay Unit - WOA SuriaceLocation Dale: December 17, 2003 Lat N702119.991 F$ 57566.2nT Lon W14922.945 NA027 Alaska Stale Planes. Zooo 04. US Fool Northing 5980564.33 ftUS Grid Conv: +0.00964295' Easting 618930.21 ftUS Scale Fact: 0.9999160677 Misoollaneous $101 Slot 4 Plan: S-120{P4} -3000 -2500 -2000 -1500 ·H.'..."·..."""... .".................".......".... ..".".~........."..."..... 'H.""...,,,.......... ..,..;···..·..·..·..,·..·..·....··..···..·r··..··.......·· ,."........0...'...... ,......"..........«. ......r.. ....'1".. ................,»...... ....1'..... ,."..~......o ,...,........,.......... -3000 -2500 -2000 -1500 <<< W Scale = 1 (in):500(ft) E >>> -1000 -1000 TVD Ref: KB (64.30 ft above MSl) SrvyDate: Octobef16,2003 -500 "T..·.. mm..mm. .¡mm........... -500 o 1500 e 1000 500 o e "'~»........ -500 o e BPX AK Anticollision Report e Date: NO GLOBAL SCAN: Using user defined selection & scan criteria Reference: Principal Plan & PLANNED PROGRAM Interpolation Method: MD Interval: 50.00 ft Error Model: 18CW8A Ellipse Depth Range: 28.50 to 8521.89 ft Scan Method: Trav Cylinder North Maximum Radius: 10000.00 ft Error Surface: Ellipse + Casing Survey Program for Definitive Wellpath Date: 8/28/2003 Validated: No Version: 2 Planned From To Survey Toolcode Tool Name ft ft 28.50 8521.89 Planned: Plan #4 V2 MWD+IFR+M8 MWD + IFR + Multi Station Casing Points TVD Diameter Hole Size ft in in 3574.27 2929.30 9.625 12.250 95/8" 8521.89 7009.68 7.000 8.750 7" Summary < Reference Offset Ctr-Ctr No-Go Allowable Site MD MD Distance Area Deviation Warning ft ft ft ft ft PB 8 Pad Plan 8-111 Plan 8-111 V3 Plan: PI 502.13 500.00 166.18 9.19 156.99 Pass: Major Risk PB 8 Pad Plan 8-116 Plan 8-116 V3 Plan: PI 498.31 500.00 90.42 8.55 81.86 Pass: Major Risk PB 8 Pad Plan 8-118 Plan 8-118 V2 Plan: PI 399.33 400.00 75.19 6.88 68.31 Pass: Major Risk PB 8 Pad Plan 8-119 Plan 8-119 V2 Plan: PI 501.36 500.00 136.93 8.52 128.41 Pass: Major Risk PB 8 Pad 8-01A 8-01A V1 346.78 350.00 715.37 8.95 706.42 Pass: Major Risk PB 8 Pad 8-01 B 8-01 B V1 342.99 350.00 715.36 8.90 706.47 Pass: Major Risk PB 8 Pad 8-01 8-01 V1 584.07 600.00 713.43 13.60 699.83 Pass: Major Risk PB 8 Pad 8-02APB1 8-02APB1 V1 393.75 400.00 719.46 7.54 711.93 Pass: Major Risk PB 8 Pad 8-02A 8-02A V1 393.75 400.00 719.46 7.54 711.93 Pass: Major Risk PB 8 Pad 8-02 8-02 V1 392.55 400.00 719.44 7.52 711.92 Pass: Major Risk PB 8 Pad 8-03 S-03 V1 391.57 400.00 742.95 6.76 736.19 Pass: Major Risk PB 8 Pad 8-04 S-04 V1 468.65 500.00 776.54 8.72 767.82 Pass: Major Risk PB 8 Pad 8-05APB 1 8-05APB1 V1 387.54 400.00 829.72 9.61 820.11 Pass: Major Risk PB 8 Pad 8-05A S-05A V1 387.54 400.00 829.72 9.61 820.11 Pass: Major Risk PB 8 Pad 8-05 8-05 V1 381.75 400.00 829.66 9.54 820.12 Pass: Major Risk PB 8 Pad 8-06 8-06 V1 386.23 400.00 892.15 6.83 885.31 Pass: Major Risk PB 8 Pad 8-07A 8-07A V1 385.41 400.00 959.71 7.17 952.55 Pass: Major Risk PB 8 Pad 8-07 8-07 V1 385.41 400.00 959.71 7.17 952.55 Pass: Major Risk PB 8 Pad 8-08 8-08 V1 383.72 400.03 1039.82 9.83 1029.99 Pass: Major Risk PB 8 Pad 8-08 8-0BA V1 383.72 400.03 1039.82 9.84 1029.98 Pass: Major Risk PB 8 Pad 8-08 8-08B V3 383.72 400.03 1039.82 9.84 1029.98 Pass: Major Risk PB 8 Pad S-09 8-09 V1 382.90 400.00 1123.63 8.10 1115.53 Pass: Major Risk PB 8 Pad 8-100 8-100 V10 349.79 350.00 77.38 5.84 71.53 Pass: Major Risk PB 8 Pad 8-101 8-101 V2 949.49 950.00 27.87 16.66 11.21 Pass: Major Risk PB 8 Pad 8-101 8-101 PB1 V9 899.36 900.00 31.06 15.90 15.16 Pass: Major Risk PB 8 Pad 8-102 Plan#4 8-102A V1 Plan: 250.09 250.00 92.58 4.64 87.95 Pass: Major Risk PB 8 Pad 8-102 8-102V11 250.09 250.00 92.58 4.64 87.95 Pass: Major Risk PB 8 Pad S-102 8-102PB1 V14 250.09 250.00 92.58 4.64 87.95 Pass: Major Risk PB S Pad 8-103 8-103 V6 752.64 750.00 210.59 11.45 199.14 Pass: Major Risk PB 8 Pad S-104 8-104 VO 350.31 350.00 286.40 6.58 279.82 Pass: Major Risk PB 8 Pad 8-105 S-105 V5 852.21 850.00 273.47 13.88 259.59 Pass: Major Risk PB 8 Pad 8-106 8-106 V2 294.09 300.00 242.58 6.31 236.28 Pass: Major Risk PB 8 Pad 8-106 8-106PB1 V12 294.09 300.00 242.58 6.31 236.28 Pass: Major Risk PB 8 Pad 8-107 S-107 V35 496.92 500.00 197.84 9.74 188.10 Pass: Major Risk PB 8 Pad 8-108 S-108 V6 443.45 450.00 148.33 7.45 140.88 Pass: Major Risk PB S Pad 8-109 8-109 V8 548.64 550.00 104.78 9.38 95.41 Pass: Major Risk PB S Pad 8-109 8-109PB1 V2 548.64 550.00 104.78 9.38 95.41 Pass: Major Risk PB 8 Pad S-10APB1 8-10APB1 V1 418.57 450.00 1208.80 8.36 1200.43 Pass: Major Risk PB 8 Pad 8-10A 8-10A V1 418.57 450.00 1208.80 8.18 1200.62 Pass: Major Risk PB 8 Pad S-10 8-10 V1 418.57 450.00 1208.80 8.36 1200.43 Pass: Major Risk PB 8 Pad 8-110 8-110V18 494.32 500.00 117.10 9.76 107.34 Pass: Major Risk PB 8 Pad 8-112 8-112V19 394.48 400.00 32.74 7.45 25.29 Pass: Major Risk PB S Pad 8-113 8-113 V13 902.77 900.00 171.34 17.72 153.62 Pass: Major Risk PB S Pad S-113 8-113A V2 902.77 900.00 171.34 17.56 153.78 Pass: Major Risk e BPX AK Anticollision Report e Company: Field: Reference Site: Reference Well: Reference Well path: Summary BP Amoco Prudhoe Bay PB 8 Pad Plan 8-120 Plan S-120 Date: 10/17/2003 Co-ordinate(NE) Reference: Vertical (TVD) Reference: PB 8 Pad 8-113 8-113B V5 902.77 900.00 171.34 17.56 153.78 Pass: Major Risk PB 8 Pad S-114 8-114 V13 651.51 650.00 259.88 12.87 247.01 Pass: Major Risk PB 8 Pad 8-114 8-114A V6 651.51 650.00 259.88 12.71 247.17 Pass: Major Risk PB S Pad 8-115 8-115 ST V1 Plan: Plan 648.63 650.00 39.72 10.62 29.10 Pass: Major Risk PB 8 Pad 8-115 8-115 V7 648.63 650.00 39.72 10.53 29.19 Pass: Major Risk PB 8 Pad 8-117 8-117V4 549.78 550.00 14.39 9.44 4.95 Pass: Major Risk PB 8 Pad 8-11A S-11A V7 297.39 300.00 1299.53 5.45 1294.08 Pass: Major Risk PB 8 Pad 8-11 B 8-11BV5 365.07 350.00 1296.21 7.49 1288.72 Pass: Major Risk PB 8 Pad 8-11 8-11 V1 379.72 400.00 1296.41 7.90 1288.51 Pass: Major Risk PB 8 Pad 8-12A 8-12A V1 333.65 350.00 1384.40 7.83 1376.57 Pass: Major Risk PB 8 Pad 8-12 8-12 V1 97.17 100.00 1392.19 2.17 1390.01 Pass: Major Risk PB 8 Pad 8-13 8-13 V1 337.40 350.00 1487.95 6.28 1481.68 Pass: Major Risk PB 8 Pad 8-14 8-14 V1 441.78 500.00 1587.43 14.41 1573.03 Pass: Major Risk PB 8 Pad S-15 8-15 V2 439.46 450.00 1068.59 10.13 1 058.46 Pass: Major Risk PB 8 Pad 8-16 8-16 V1 393.96 400.02 1175.54 7.10 1168.44 Pass: Major Risk PB 8 Pad S-17 8-17 V1 484.78 499.98 1288.63 10.23 1278.40 Pass: Major Risk PB 8 Pad 8-17 8-17A V1 484.78 499.98 1288.63 10.23 1278.40 Pass: Major Risk PB 8 Pad 8-17 8-17AL 1 V1 484.78 499.98 1288.63 10.23 1278.40 Pass: Major Risk PB 8 Pad 8-17 8-17APB1 V1 484.78 499.98 1288.63 10.23 1278.40 Pass: Major Risk PB 8 Pad 8-17 8-17B V1 484.78 499.98 1288.63 10.23 1278.40 Pass: Major Risk PB 8 Pad 8-17 S-17C V1 484.78 499.98 1288.63 10.07 1278.55 Pass: Major Risk PB 8 Pad 8-17 8-17CPB1 V2 484.78 499.98 1288.63 10.07 1278.55 Pass: Major Risk PB 8 Pad 8-17 8-17CPB2 V1 484.78 499.98 1288.63 10.07 1278.55 Pass: Major Risk PB 8 Pad 8-18 8-18 V1 521.69 550.00 1398.42 9.35 1389.08 Pass: Major Risk PB 8 Pad 8-18 8-18A V15 524.39 550.00 1398.49 9.32 1389.17 Pass: Major Risk PB 8 Pad 8-19 8-19 V1 482.34 500.01 711 .75 9.47 702.29 Pass: Major Risk PB 8 Pad 8-200PB 1 8-200PB1 V4 497.82 500.00 60.74 7.61 53.13 Pass: Major Risk PB 8 Pad 8-200 8-200 V2 497.82 500.00 60.74 7.72 53.02 Pass: Major Risk PB 8 Pad 8-201 8-201 V2 249.88 250.00 226.02 4.34 221.68 Pass: Major Risk PB 8 Pad 8-201 S-201 PB1 V11 249.88 250.00 226.02 4.34 221.68 Pass: Major Risk PB S Pad 8-20 8-20 V4 434.57 450.00 723.65 7.70 715.94 Pass: Major Risk PB 8 Pad 8-20 8-20A V2 434.57 450.00 723.65 7.71 715.94 Pass: Major Risk PB 8 Pad 8-213 S-213 V6 398.35 400.00 15.44 6.20 9.25 Pass: Major Risk PB 8 Pad 8-215 8-215 V7 618.37 650.00 1090.62 11.04 1079.59 Pass: Major Risk PB 8 Pad 8-216 8-216 V1 299.71 300.00 44.60 6.10 38.50 Pass: Major Risk PB 8 Pad 8-21 8-21 V1 393.40 400.00 750.71 7.07 743.64 Pass: Major Risk PB 8 Pad 8-22A 8-22A V1 489.91 500.00 711.21 8.16 703.05 Pass: Major Risk PB 8 Pad 8-22B 8-22B V2 489.91 500.00 711.21 8.32 702.89 Pass: Major Risk PB 8 Pad 8-22 8-22 V1 489.91 500.00 711.21 8.18 703.02 Pass: Major Risk PB 8 Pad 8-23 8-23 V1 439.63 450.00 732.81 7.55 725.26 Pass: Major Risk PB 8 Pad S-24 Plan#4 8-24B VO Plan: 436.40 450.00 765.27 8.18 757.09 Pass: Major Risk PB 8 Pad 8-24 8-24 V5 434.31 450.00 765.22 7.97 757.25 Pass: Major Risk PB 8 Pad 8-24 8-24A V1 436.40 450.00 765.27 8.01 757.26 Pass: Major Risk PB 8 Pad 8-25APB1 S-25APB1 V1 636.61 700.00 788.74 18.96 769.77 Pass: Major Risk PB 8 Pad 8-25A S-25A V1 390.76 400.00 793.08 6.72 786.36 Pass: Major Risk PB 8 Pad 8-25 S-25 V1 390.76 400.00 793.08 6.72 786.36 Pass: Major Risk PB S Pad 8-26 8-26 V1 432.43 450.00 812.21 6.72 805.49 Pass: Major Risk PB 8 Pad S-27 Plan 8-27B V4 Plan: PI 431.56 450.00 849.03 7.69 841.34 Pass: Major Risk PB 8 Pad 8-27 S-27 V1 431.18 450.00 849.02 7.89 841.13 Pass: Major Risk PB 8 Pad 8-27 8-27A V2 431.18 450.00 849.02 7.64 841.38 Pass: Major Risk PB 8 Pad 8-28 8-28 V4 344.49 350.00 869.27 6.63 862.64 Pass: Major Risk PB 8 Pad 8-28 8-28A V1 344.49 350.00 869.27 6.63 862.64 Pass: Major Risk PB 8 Pad 8-28 S-28B V2 345.57 350.00 869.28 6.64 862.64 Pass: Major Risk PB S Pad 8-28 8-28BPB1 V7 345.57 350.00 869.28 6.64 862.64 Pass: Major Risk PB 8 Pad 8-29AL 1 8-29AL 1 V1 339.74 350.00 1064.36 6.52 1057.83 Pass: Major Risk PB S Pad 8-29A Plan 8-29AL2 VO Plan: 343.14 350.00 1064.40 6.38 1058.02 Pass: Major Risk PB 8 Pad 8-29A 8-29A V1 339.74 350.00 1064.36 6.52 1057.83 Pass: Major Risk PB 8 Pad S-29 Plan 8-29B V1 Plan: 8- 343.14 350.00 1 064.40 6.55 1057.85 Pass: Major Risk PB 8 Pad 8-29 8-29 V1 339.74 350.00 1064.36 6.52 1057.83 Pass: Major Risk PB 8 Pad 8-30 S-30 V1 388.86 400.00 938.39 6.66 931.73 Pass: Major Risk PB 8 Pad 8-31A S-31A V3 385.65 400.00 984.69 6.62 978.06 Pass: Major Risk PB S Pad 8-31 S-31 V1 385.65 400.00 984.69 6.62 978.06 Pass: Major Risk PB 8 Pad 8-32 S-32 V1 341.96 350.00 1176.96 8.12 1168.84 Pass: Major Risk e BPX AK Anticollision Report e Summary Reference Offset CtrcCtr . · . No-Go Allowable MD MD Distance·· Area Deviation Warning ft ft ft ft ft PB S Pad 8-33 8-33 V1 382.98 400.00 1011.35 6.39 1004.96 Pass: Major Risk PB 8 Pad 8-34 8-34 V1 336.62 350.00 1238.86 5.60 1233.25 Pass: Major Risk PB 8 Pad 8-35 8-35 V1 338.64 350.00 1268.14 5.47 1262.66 Pass: Major Risk PB 8 Pad 8-36 8-36 V1 336.97 350.00 1327.79 5.51 1322.28 Pass: Major Risk PB 8 Pad 8-37 8-37 V1 377.70 400.00 1356.11 6.02 1350.09 Pass: Major Risk PB 8 Pad 8-38 8-38 V1 380.96 400.00 1148.67 6.04 1142.63 Pass: Major Risk PB 8 Pad 8-40A 8-40A V1 484.45 500.00 1321.36 7.45 1313.91 Pass: Major Risk PB 8 Pad 8-40 8-40 V1 484.45 500.00 1321.36 7.45 1313.91 Pass: Major Risk PB 8 Pad 8-41L1 8-41L1 V1 585.98 600.00 210.52 9.15 201.36 Pass: Major Risk PB S Pad 8-41PB1 8-41PB1 V1 585.98 600.00 210.52 9.15 201.36 Pass: Major Risk PB 8 Pad 8-41 8-41 V1 585.98 600.00 210.52 9.15 201.36 Pass: Major Risk PB 8 Pad 8-42PB1 8-42PB1 V1 538.30 550.00 181.65 9.14 172.52 Pass: Major Risk PB 8 Pad 8-42 8-42 V2 538.30 550.00 181.65 9.14 172.52 Pass: Major Risk PB 8 Pad 8-43L 1 S-43L 1 V2 592.49 600.00 147.14 9.51 137.63 Pass: Major Risk PB 8 Pad 8-43 8-43 V3 592.49 600.00 147.14 9.51 137.63 Pass: Major Risk PB 8 Pad 8-44L 1PB1 8-44L1PB1 V3 545.72 550.00 119.56 8.33 111.23 Pass: Major Risk PB 8 Pad 8-44L 1 8-44L 1 V5 545.72 550.00 119.56 8.33 111.23 Pass: Major Risk PB 8 Pad 8-44 S-44 V10 545.72 550.00 119.56 8.33 111.23 Pass: Major Risk -294 200 100 -0 100 200 -294 Field: Prudhoe Bay Site: PB S Pad Well: Plan S-120 Wellpath: Plan S-120 ./ 27(} It e S-102 (BklOOfB~02A) S-109 (S-I 09fB I) 10 Æ1N/Æ1!f}JT) S-200~8-I2~00PBI) 180 2~. Plan S-II8 (Plan S-II8) Travelling Cylinder Azimuth (TFO+AZI) [deg] vs Centre to Centre Separation [100ft/in] ,. s- 'AD N 1100-' N 1010 _ Ø) ~ í í í (f) (f) (f) .... : : =: : ===.... - ~2~~~ª~2 ~ ~~~g5~ ~ ~~~~ I I I I I I I I I IIIIII I I I I I ø~~ø~~~~ ~ ~oo~~~oo 00 00000000 ---: : ~ ~ ~ :;;: I I I I (/) en en (/) N840- I y~ '" to ~ LEGEND -+- AS-BUILT CONDUCTOR . EXISTING CONDUCTOR ,- I- Z :S CI.. -~- I WELLS S-111. S-119 & S-120 RENAME NOTE THIS AS-BUILT DRAWING IS A REISSUE OF PREVIOUS AS-BUILT DRAWINGS FOR WELLS S-111, S-119 AND S-120. S-111 WAS PREVIOUSLY ISSUED AS SLOT 15 ON JUNE 17, 2002. S-119 WAS PREVIOUSLY ISSUED AS SLOT 13 ON DECEMBER 31, 2001. S-120 WAS PREVIOUSLY SHOWN AS S-116, REISSUED AS SLOT 4 AND ORIGINALLY ISSUED AS WELL S-103 ON JULY 4, 2000. NOTES: 1. DATE OF SURVEYS: (S-120 JULY 2, 2000) (S-119 JANUARY 31, 2001) (S-111 JUNE 15, 2002) 2. REFERENCE FIELD BOOKS: (S-120 WoOO-06 PGS. 1-4) (S-119 Wo01-05 PGS. 33-37) (S-111 Wo02-08 Pg. 7) 3. COORDINATES ARE ALASKA STATE PLANE, ZONE-4 NAD 27. 4. GEODETIC COORDINATES ARE NAD-27. 5. MPU S-PAD AVERAGE SCALE FACTOR IS: 0.9999165. 6. HORIZONTAL CONTROL IS BASED ON MONUMENTS S-3 & S-4. (HELD S-4) 7. BASIS OF VERTICAL CONTROL IS OPERATOR MONUMENTATION. ELEVATIONS ARE BP EXPLORATION MEAN SEA LEVEL DATUM. e 27 26 25 S PAD j) ~ 34 36 3 T.12N. T.11N. 2 ...... I- ë: C) z ¡::: (f) x w VICINITY MAP N.T.S. ~AN~ Ow -1-1 o:::¡ ~o zo «::¡; ::¡; SURVEYOR'S CERTIFICATE I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY MADE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF JULY 2, 2000. LOCATED WITHIN PROTRACTED SEC. 35, T. 12 N., R. 12 E., UMIAT MERIDIAN, ALASKA WELL A.s.P. PLANT GEODETIC GEODETIC CELLAR SECTION NO. COORDINATES COORDINATES POSITION(DMS) POSITION(D.DD) BOX ELEV. OFFSETS Y= 5,980,730.34 N. 1010.61 70'21'21.624" 70.3560067" ,4,527' FSL S-111 X= 618,930.49 E. 124.60 149'02'02.860" 149.0341278' 35.6 4,497' FEL S-119 Y=5,980,699.94 N. 1,010.12 70'21'21.325" 70.3559236' 36.2' 4,497' FSL X= 618,930.01 E. 155.00 149'02'02.888" 149.0341356' 4,498' FEL > S-120 Y=5,980,564.33 N. 1,010.27 70'21'19.991" 70.3555531' 35.8' 4,361' FSL X= 618,930.21 E. 290.63 149'02'02.945" 149.0341515' 4,500' FEL ~~il DRAINN: Obp JJC CHECKED: Lot-! DATE: DRA'MNG: SHEET: FR803 WOA-S 02-00 WOA S-PAD ~ ¡[]~~rnœO JOB NO: SCALE: RENAMED AS-BUILT CONDUCTORS JJC LOH £NGIN£ERSNIDLAND SUR'ÆYDRS WELL S-111, S-119 & S-120 1 OF 1 801 \lEST FIAEWEED lANE ,'= 150' BY CHK """"""" ""'" ""'" o 11/02/03 ISSUED FOR INFORMAllON NO. DA 1E RE\1S1ON Area Injection Order 22b - http://www.state.ak.us/local! akpages/ AD MIN/ ogc/ orders... e STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP EXPLORATION (ALASKA) INC. for an order allowing underground injection of fluids for enhanced oil recovery in Aurora Oil Pool, Prudhoe Bay Field, North Slope, Alaska IT APPEARING THAT: ) Prudhoe Bay Field ) ) Aurora Oil Pool ¡ Area Injection Order No. 22B ¡ May 6, 2003 1. By letter and application dated December 9, 2002, BP Exploration (Alaska) Inc. ("BPXA") requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") modifying Area Injection Order No. 22 ("AIO 22") authorizing underground injection of miscible injectant ("M I") for enhanced oil recovery in the Aurora Oil Pool ("AOP"), Prudhoe Bay Field, on the North Slope of Alaska. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on January 28, 2003. 3. The Commission did not receive any protests or comments concerning this application. 4. A hearing concerning BPXA's request was convened in conformance with 20 MC 25.540 at the Commission's offices, 333 W. 7th Avenue, Suite 100, Anchorage, Alaska 99501 on March 4, 2003. 5. BPXA provided additional information on February 28, 2003 and on March 7, 2003. 6. On April 3, 2003 the Commission issued Area Injection Order No. 22A ("AIO 22A") denying BPXA's application to inject enriched gas in the AOP. 1 of 10 12/1/2003 2:36 PM Area Injection Order 22b http://www.state.ak.us/local/akpages/ AD MINI ogcl orders... It e 7. On April 28, 2003 BPXA applied for rehearing of AIO 22A and supplied additional information in support of their application. FINDINGS: 1. Operators/Surface Owners (20 MC 25.402(c)(2) and 20 MC 25.403(c)(3)) BP Exploration (Alaska) Inc., ExxonMobil Alaska Production Inc., ConocoPhillips Alaska, Inc., Chevron U.S.A. Production, and Forest Oil Corporation are working interest owners. The State of Alaska is the landowner. 2. Project Area Requested for Enhanced Recovery The AOP is defined as an accumulation of oil that is common to, and correlates with, the interval between 6765'- 7765' measured depth ("MD") in the Mobil Oil Corporation Mobil-Phillips North Kuparuk State No. 26-12-12 well. The geology of the AOP is described in Conservation Order 457 ("CO 457") and AIO 22. 3. Description of Operation (20 MC 25.402(c)(4)) The AOP is developed from the Prudhoe Bay S-Pad. Tract operations within the pool began in November 2000. The Commission approved water injection with the issuance of AIO 22 on September 7, 2001. The proposed project involves the cyclical injection of water alternating with enriched hydrocarbon gas into the oil column of the Kuparuk River Formation of the AOP. The injectant will be comprised of hydrocarbon gas, enriched with intermediate hydrocarbons, principally ethane and propane, which is designed to be miscible with the reservoir oil. The proposed source of this enriched gas is from pools within the Prudhoe Bay Unit and processed within the Prudhoe Bay Central Gas Facility. Requested timing for injection of enriched gas into the AOP is second quarter of 2003. Miscible gas injection is planned within the blocks having established water injection, North of Crest and West Blocks. Expansion to the remaining blocks is dependent upon performance of primary production and waterflood operations. Additional recovery as a result of miscible gas injection is projected at 3-50/0 of the original oil in place. 2 of 10 12/1/20032:36 PM Area Injection Order 22b http://www.state.ak.us/local/akpages/ADMIN/ogc/orders... e e 4. Well Loqs (20 MC 25.402(c)(7)) Well logs for the proposed injection wells are on file with the Commission. 5. Mechanicallnteqrity (20 MC 25.402(c)(8)) All newly drilled and converted injection wells have been completed in accordance with 20 MC 25.412, thus satisfying mechanical integrity requirements. The casing programs for S-101i, S-104i, S-107i, S-110i, S-112i, and S-114Ai were permitted and completed in accordance with 20 MC 25.030. Injection well tubulars have premium threads to prevent tubing leaks and maintain integrity during injection of enriched gas. Cement bond logs (ultra sonic imaging tool) run in Wells S-104i and S-112i indicate good cement bond across and above the Kuparuk River Formation. The Commission has approved water-flow logs completed in Wells S-IOli, S-107i and S-114Ai to confirm injection containment into the target zone. BPXA has applied for conversion of S-11 0 from production to injection status. Evidence of sufficient cement integrity is required prior to approval. 6. Injection Fluid and Rates (20 MC 25.402(c)(9)) a. Produced Water: The Aurora waterflood project uses produced water from GC-2. The composition of GC-2 produced water and compatibility issues were addressed in the original AIO 22 application. Maximum water injection capacity at AOP is estimated at 40,000 BPD. b. Miscible Hydrocarbon Gas: The proposed project requests approval for injection of enriched hydrocarbon gas from the Prudhoe Bay Central Gas Facility. No compatibility issues are anticipated in the formation or confining zones. Planned maximum enriched gas injection at AOP is estimated at 20 million SCF per day. c. Source Water: Source water from the Prince Creek Formation may be used to supplement water injection if compatibility between Prince Creek Formation water and AOP formation fluids can be demonstrated. d. Lean Gas: Approval was requested to inject lean produced gas for reservoir pressure maintenance. Compatibility with the formation is not an issue as the gas is of similar composition to AOP produced gas. 3 of 10 12/1/2003 2:36 PM Area Injection Order 22b http://www.state.ak.us/local/ akpages/ AD MIN/ ogc/ orders... e e e. Other Fluids: Other fluids proposed for injection from time to time include: 1. Non-hazardous water collected from PBU reserve pits, well house cellars and standing ponds, and 2. Tracer fluids to monitor reservoir performance. 7. Injection Pressures (20 AAC 25.402(c)(10)) Enriched gas and water injection operations at the AOP are expected to be above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. Maximum proposed surface injection pressure is 2800 psi for water and 3800 psi for gas. 8. Fracture Information (20 AAC 25.402(c)(11)) With a maximum surface water injection pressure of 2800 psi, the injection gradient will be 0.85 psi/ft, assuming no friction losses, which will not propagate fractures through the confining layers. The overlying Kalubik and HRZ shales, which have a combined thickness of approximately 110 feet, have a fracture gradient 0.8 to 0.9 psi/ft. The underlying Miluveach/Kingak shale sequence has a fracture gradient of approximately 0.85 psi/ft. 9. Water Analysis (20 AAC 25.402(c)(12)) The compositions of injection water and AOP connate water were provided in Exhibit IV-4 of the original AIO application. Water analysis from the nearby Milne Point Prince Creek Formation was provided in the April 28, 2003 application for rehearing. 10. Aquifer Exemption (20 AAC 25.402(c)(13)) On July 11, 1986, the Commission approved Aquifer Exemption Order 1 ("AEO 1 ") for Class II injection activities within the Western Operating Area of the Prudhoe Bay Unit. The AOP is entirely within the area covered by AEO-1. 11. Hydrocarbon Recovery and Reservoir Impact (20 AAC 25.402(c)(14)) The Commission denied BPXA's original application because insufficient technical information was supplied to support that the injectant would remain miscible throughout the planned flood area. BPXA fully addressed 4 of 10 12/1/2003 2:36 PM Area Injection Order 22b http://www.state.ak.us/local/akpages/ ADMIN/ogc/orders... tit e the concerns within the April 28, 2003 application for re-hearing. Reservoir Depletion Plan and Field Development: Due to high structural complexity, phased development of the AOP was pursued. Reservoir surveillance from a period of primary production helped define reservoir compartments and appropriate placement of water injectors. Miscible gas injection will begin in the West and North of Crest Blocks where water injection has been established. Water injection in the South East of Crest Block is planned with conversion to injection of S-110 and S-112. Production within the Crest Block began in mid March 2003 with startup of wells S-115 and S-117. An injector will be considered for the Crest Block dependent upon primary production results. A local water injection booster pump is being evaluated to increase water injection support within the AOP. Reservoir Pressure and Minimum Miscibility ("MMP"): Slim tube experiments with Prudhoe Bay enriched gas injectant and Aurora oil yielded a MMP of 2700 psi. BPXA provided an update of the well shut-in pressure measurements and evaluated the information for validity. All shut-in reservoir pressure measurements were above 2700 psi. Reservoir simulation indicates the average field pressure is above 3100 psi, with about 90% of the field above the MMP. Areas below the MMP are limited to local producing well areas. Effect of Delayed Depletion: Reservoir mechanistic studies performed by BPXA show insignificant reserve loss from delayed waterflood if the average reservoir pressure is maintained above 2400 psi. MI injection was simulated for two separate average reservoir pressure cases. The runs at 3400 psi and 2700 psi show comparable incremental recoveries. Reservoir VoidaÇJe: Water injection has recently increased and is equal to or slightly exceeds reservoir withdrawal in both the North of Crest and West Blocks. GOR's within the waterflood area have continued to decline, suggesting good waterflood support. Injection line repair has resulted in increased water injection rates and associated increased wellhead injection pressures. Planned water injector and M I conversions and the potential water injection booster pump will provide further voidage replacement. Reservoir Surveillance: BPXA supplied a plan to acquire reservoir 5 of 10 12/1/2003 2:36 PM Area Injection Order 22b http://www.state.ak.us/local/akpages/ AD MINI ogcl orders... tit e pressure measurements in 2003. The number of reservoir pressures planned exceeds that required by C0457, and adequately addresses the issues raised by the Commission within AIO 22B. Lean Gas Injection: Approval of lean gas injection is premature at this time. Insufficient information was provided regarding impact upon ultimate recovery. Administrative approval allowing lean gas injection may be sought at a later date when plans and recovery benefits are better defined. 12. Mechanical Condition of Adjacent Wells (20 MC 25.402(c)(15)) Mechanical integrity has been established for the wells within % mile radius of proposed injectors. Mechanical integrity is based upon calculated cement tops being at an adequate height above the injection zone to prevent fluid that is injected into the AOP from flowing into other zones or to the surface. CONCLUSIONS: 1. The application requirements of 20 MC 25.402 have been met. 2. There are no freshwater strata in the AOP area. 3. The proposed water and miscible gas injection operations will be conducted in permeable strata and will involve injection above the parting pressure of the Kuparuk Formation in the AOP. 4. Injection pressures up to 2800 psi for water and 3800 psi for gas will not propagate fractures through the confining interval. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 5. Enriched gas injection from the Prudhoe Bay Unit will preserve reservoir energy and enhance ultimate recovery within the North of Crest and West Blocks. Expansion will be dependent upon the production performance under primary recovery and waterflood and the success of the miscible injection within the North of Crest and West Blocks. 6. Reservoir surveillance, operating parameter surveillance and mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project or disclose possible abnormalities. 6 of 10 12/1/20032:36 PM Area Injection Order 22b http://www.state.ak.us/local/ akpages/ AD MIN/ ogc/ orders... e e 7. Fluids approved for injection must be compatible with the AOP Formation. 8. Depletion plan update and approval are needed prior to beginning injection of immiscible hydrocarbon gas. 9. The current average reservoir pressure is above the minimum miscibility pressure of 2700 psi. Though some producers are below this pressure, the enriched gas will remain miscible within the flood front provided the average reservoir pressure remains above this pressure. 10. BPXA's depletion strategy and development plan for the coming year will provide improved reservoir understanding and are designed to result in greater ultimate recovery. NOW, THEREFORE, IT IS ORDERED THAT: 1. AIO 22A is withdrawn. 2. This order supersedes AIO 22 issued September 7,2001 (as corrected September 17, 2002). 3. Rules 2, 3, and 8 of AIO 22 are revised and Rule 9 of AIO 22 is added. 4. Underground injection of fluids pursuant to the projects described in BPXA's application for AIO 22, application of December 9, 2002 for MI injection, and rehearing request of April 28, 2003 is permitted in the following area, subject to the conditions, limitations, and requirements established in the rules set out below and statewide requirements under 20 AAC 25 (to the extent not superseded by these rules, Conservation Order 457, or subsequent amendments). Umiat Meridian Township ange Sections T11N R12E N % Sec. 3 T12N R12E S % Sec 17; SE X Sec 18; E % Sec 19; All Sec 20; All Sec 21;W 1/2NW 1/4,S % Sec 22; SW X Sec 23; SW X Sec 25; All Sec 26; All Sec 27; All Sec 28; N %, Se X Sec 29; E % Sec 32; All Sec 33; All Sec 34; All Sec 35; N %, SW X Sec 36 7 of 10 12/1/20032:36 PM Area Injection Order 22b http://www.state.ak.us/local/ akpages/ AD MIN/ ogc/ orders... e e Rule 1 Authorized Injection Strata for Enhanced Recovery (Source AIO 22) Injection is permitted into the accumulation of hydrocarbons that is common to, and correlates with, the interval between 6765'- 7765' measured depth ("MD") in the Mobil Oil Corporation Mobil-Phillips North Kuparuk State No. 26-12-12 well. Rule 2 Iniection Pressures (Amended this Order AID 228) The injection operations shall not allow fractures to propagate into the confining intervals. Surface wellhead injection pressures shall be limited to 2800 psi for water and 3800 psi for gas. Rule 3 Fluid Iniection Wells (Amended this Order AID 228) The underground injection of fluids must be through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. The application to drill or convert a well for injection must be accompanied by sufficient information to verify the mechanical condition of wells within one-quarter mile radius. The information must include cementing records, cement quality log or formation integrity test records. Rule 4 Monitoring the Tubing-Casing Annulus Pressure Variations (Source AIO 22) The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to confirm continued mechanical integrity. Rule 5 Demonstration of Tubing-Casing Annulus Mechanicallntegritv (Source AID 22) A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. Rule 6 Notification of Improper Class IIlniection (Source AID 22) 8 of 10 12/1/20032:36 PM Area Injection Order 22b http://www.state.ak.us/locallakpages/ AD MINI ogcl orders... e e The operator must notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Rule 7 Other conditions (Source AlO 22) a. It is a condition of this authorization that the operator complies with all applicable Commission regulations. b. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 8 Administrative Action (Amended this Order AlO 228) Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule herein or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Rule 9 Authorized Fluids for Enhanced Recovery (New rule this Order AIO 228) The fluids authorized for injection and conditions of the authorization are as follows: a. produced water from the AOP or Prudhoe Bay Unit processing facilities; b. source water from the Prince Creek formation provided that the water is shown to be compatible with the AOP formation and administrative approval to inject is obtained from the Commission; c. enriched hydrocarbon gas processed within the Prudhoe Bay Unit processing facilities, with the following conditions: 1. reservoir pressure must be maintained to ensure miscibility of the injectant, and 2. expansion of injection outside of the North of Crest and West Blocks must be administratively approved prior to long-term injection; 9 of 10 12/112003 2:36 PM Area Injection Order 22b http://www.state.ak.us/local! akpagesl AD MINI ogcl orders... e e d. immiscible hydrocarbon gas from the AOP or Prudhoe Bay Unit processing facilities provided that Commission approval of the associated depletion strategy and surveillance plans is obtained prior to start of injection; e. tracer survey fluid to monitor reservoir performance; and f. non-hazardous filtered water collected from AOP well house cellars and well pads. DONE at Anchorage, Alaska and dated May 6, 2003. Is/Sarah Palin, Chair Alaska Oil and Gas Conservation Commission /s/Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission Is/Randy Ruedrich, Commissioner Alaska Oil and Gas Conservation Commission Area Injection Order Index 10 of 10 12/1/20032:36 PM P055165 DATE 10/6/2003 INV# PR100103E INVOICE / CREDIT MEMO THE ATTACHED CHECK IS IN PAYMENT FOR ITEMS DESCRIBED ABOVE. BP EXPLORATION, (ALASKA) INC. PRUDHOE BAY UNIT PO BOX 196612 ANCHORAG~. AK99519-6612 PAY: TO THE ORDER OF: DESCRIPTION GROSS PERMIT TO DRILL =EE 3"'00 TOTAL ~ NATIONAL CITY BANK Ashland, Ohio - 8' P·· .... r:. "r.... ,.11") ¡dUl'f'''·!'.·· .··..'·I·!·.·., ..... .. -.. ~' I' "".. 1...·· 't' .:.... . _ .:).J.. "11I" 'IIT" """'.. ....'" ?'" DATE I CHECK NO. 10/6/2003 055165 VENDOR DISCOUNT NET 56-389 412 No. P 0 5516 5 CONSOLIDATED COMMERCIAL ACCOUNT AMOUNT October6, 2003 I.,il ***;7**$100.00*******/ No.r VALID AFTE:R 120 DAYS \:~\::\.:;:?:;::::~~~:~~::;r/.~;~.~;;'~~:~::;~.~\i~;:.:~~:~. :".,:..:\. '>~ ~::,:~:::'!;,::-¡;:::-:.;':":::;::' ,.~./_\<:.::.: ".\.. .:....:........\~::;:..~:. '>:"~ :":::":'~::'!!:~::\~' " .. ....... ,...... ............ ......"....................- \...... ':.' ...... .:.... :...:'..,::." :\. :~,' ::'," :\'-~) ALASKA QIL & GAS CONSERVATION COMMISSION 333 W 7TH AVENUE SUITE 100 ANCHORA<3E. AK 99501-3539 II' 0 5 5 ¡. b 5 II' I: 0... ¡. 2 0 :1 a q 5 I: 0 ¡. 2 ? a q ¡; IIa H It e · e TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERIP ARA GRAPH S TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME PTD# CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API num ber last two (2) digits are between 60-69) PILOT (PH) "CLUE" The permit is for a new wellbore segment of existing weD ~ Permit No, API No. Production should continue to be reported as a function· of the original API number. stated above. HOLE In accordance with 20 AAC 25.005(t), aU records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API Dumber (50 70/80) from records, data and logs acquired for well (name on permit). SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07/10/02 C\jody\templates The permit is approved subject to fuD compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. {Company Name) assumes the liability of any protest to tbe spacing exception that may occur. All dry ditcb sample sets submitted to the Commission must be in no greater tban 30' sample intervals from below tbe permafrost or from wbere samples are first caugbt and 10' sample intervals througb target zones. Field & Pool PRUDHOE BAY, AURORA OIL - 640120 Well Name: PRUDHOE BAY UN AURO S-1~ _Program SER _ Well bore seg D PTD#: 2031980 Company BP EXPLORATION (ALASKA) INC nitial ClassfType SER 11WINJ GeoArea Unit - On/Off Shore On _ Annular Disposal D Administration 11 Pecmit fee attached Y_es _ 2 _Leas~numb~rapRropriale _ _ _ _Y_es 3 _U_nlque well_n_am~_and OUlTJb_er _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - Y~s__ - - - - - - - - - - - - - - - - - - - - - - -- - - - - - -- - - - - - 4 W~II Jocat~d lna_ defined _ppol_ Y~s - - - - - 5 W~llJocated prop~rdlstance from drilling unitb9und_alY_ _ _ _ Yes 6 WeUJocated pr_op~r _dlstance from otlJer welJs_ _ Yes 7 _SJJtfiçientaçreageayailable in_drilliog unjt _ _ Yes 8 Jtdeviated, js weJlbore plaUncJuded _ Yes 9 ø~er_ator only affeçted party _ _ Yes 10 _O~ecator lJas_apprpprlateJ~ond lnJQr~ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ p__q___Y_e$ _ _ _ w _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - -- - - - - - -- - - - - - 11 PeclTJil can be i_ssued witlJout co_ns~rvation order _ _ _Y~s - - -- Appr Date 112 P~rlTJil can be lS$ued witlJout adlTJinistcatille_apprpvaJ _ _ _ _ Ye$ - - -- RPC 12/1/2003 13 Can permit be approved before 15-day wait Yes '14 W~IIJocaled within area and strata _authorized bY_'njectipo Ordec # (pullO# in_ c_omments) (For _ Yes I:\I022BC_OPYATJACHED _ e 15 _AJI welJsJlvithin Jl4_roile_af~a_of reyieW id~otified (FpC servjc_ewell pnly) _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes I'I/Ol'l/E_ _ _ _ _ _ _ _ _ _ _ _ _ _ __ - - - - - - - - - -- - - - - - 16 Pf~-produçed injector; duration_of pre-~roductionle$s than 3 mOnths_ (For_service well QnJy) _ _ No - - - - 17 ACMP Finding _of CQn$i$lency h_a$ been issued_ for_ tbi$ proiecl _ NA - - - Engineering 18 _Cooductor stcing_prQvidecl _ _ _ Yes 19 _Surfacecasing_prQtecis_ alLknown USQWs _ Yes 20 CMT v_ol adeQu_ate_ to circulate_ onconductpr_ 8. surfc¡¡g _ - Y~$ Adequate excesS, 21 CMT v_ol adeQu_ateJo tie-lnJong _string to_surf csg_ _ _ No_ 22 _CMTwill coyeraJl knOwn-Pfo_ductiye borizons_ _ Yes 23 _C_asing d~signs adequate foc C,_T~ B_&_perroafro$t _ Yes 24 _MequaleJan_kage_or reserve pit _ - - - - Ye$ I'I/ab_ors 7ES, 25 Jta_re-:dÖII, bas_a_ lOA03 for abandonlTJe_nt beeo apprQved _ _ __NA I'I/ew weU, 26 Adequale)',,-ellbor~separatio_n_pro~osesL _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s - - - - - - - - - - - - - - - - - - - - - - - - - 27 Jfdiver:t~rr~quir~d, does ]t meel reguJations _ _ __NA Diyerter waiver On $-Pac:l. Appr Date 28 _Drilliog fluid_ progralTJ $Ghematic_& e(!uip Ji$ladequate_ _ Ye$ MaxMWJOJ_ppg._ _ WGA l~1 z./t>"!, 29 _BØPi:s,_dothey meelreguJatipn _ _ _ Yes 30 B_OPE-Pf~ss raiiog ap~ropriate; Jest lo(put psig incomment$)_ _ _ _ Yes Test tp 40QO :!si. _MS~ 26_80 psi. e 31 _Choke manifold cOlTJplies_ w/API RF'-53 (May 64) Yes 32 Work will pcc_ur withputoperation _sbutdown_ _ - - -- Yes 33 JSI:m~sence of HZS gas prOQable _ _ _ - - - - - - - -- No_ 34 MechanlcaLcondjtion pf w~lIs within 1:\08. yerifiecl (fots_ervice welJ only) _ _ . Yes 1'1/0 wells witbio AOR._ ~ Geology 35 Pe(lTJit can be iS$l!ed wlo_ hydr_ogen_ sulfide measures _ _ _ Yes 36 _D_ata pr~sented on_ :!ote_ntial pverRre6-s\.lre _ZOnes _ _ .NA Appr Date 37 SeÎsmicanalysjs_ of shallow gas_zooes_ . NA RPC 38 _Seabedconditipo survey (if off-shore) _ _ NA - - - - - - ~ - 139 CQntact namelp/1QneJorJ,,,eelsly prpgressreRort$ [e¡cploratplY 9nlYl - - - - . _NA Geologic Engineering Public ~ Commissioner: Date: Commissioner: Date Commissioner Dl;; ¿f2-\3 0