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193-056
State of Alaska Oil and Gas Conservation Commission Deficiency Report Location: ��.tp iCo7P MPr- Date: to`34'Z.1 PTD: r� 3d S("o I- S/zi 9z-1i,7-d operator, --- i-e-.�Cy ��{ 4A t.LC- ra7YPe Inspection: I�-r Operator Rep: A_rV►t5 14ej150^j Inspector RlA•i i � Position: CP6ZATd9 Op. Phone: ffd_?_ 4 q _ r 0 18D Correct by (date): /Z.'?(-) Op_ Email: -T-i<C."Lt,50, j a ov cowep. C.0", Follow Up Req'd: a Detailed Description of Deficiencies Date Corrected MI)z i-is XM rWP.r- ! 51 -51 ou.Zo tiE6a N0j &4M W b6 s r�-,.j s �srA�� ❑ / 5 f��. z� � IAK& ac = ORds of ^X ► SM-1.5 f�e-� Attachments:I P"4uZ e5 C7C operator Rep AOGCC inspector •After signing, a copy of this form is to be left with the P tryructions Return tion: Inspection Supervisor] within 7 days of receipt. Include the "[]ate a CM of this Deficiency Report to AOGCC (Atten and attach supporting documentation for each corrective action implemented to address the deficiencies_ If a follow-up ,� P� by AOGCC, include the date and Warne of Inspector. Extensions for corrective actions taking (anger than :the ■pwr� Syr' date must be requested and accompanied by justification [Attention: Inspection Supervisor). Documentation of � t are outside of AOGCC regulatory judsdiction will he forwarded to the appropriate authority for follow-up aet'son. L - r r ' r Oak. e f • J ..� r A s }r • RECEIVE Post Office Box 244027 1I ! tn� +ryy 1 Anchorage,AK 99524-4027 Hilcorp Alaska,LLC JUL 3 V Lo1j 3800 Centerpoint Drive Suite 100 AOGCCAnchorage,AK 99503 Phone: 907/777-8300 July 29, 2015 Fax: 907/777.-8301 Commissioner Cathy Foerster iQSW Alaska Oil & Gas Conservation Commission 1613 �... 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Duck Island Unit Well Renaming Request SCANNED AUG 2 9 2016 Dear Commissioner Foerster, Hilcorp Alaska, LLC (HAK) requests a change to the naming convention of Duck Island Unit wells to remove the unused suffixes at the end of each well name. Well names currently include a forward slash "/" followed by an obsolete bottom hole location designator. HAK would like to retain the well number as well as the "A, B, C...." sidetrack designations but remove the "/suffix". For example, "DUCK IS UNIT SDI 1-09A/L21" would become "DUCK IS UNIT SDI 1-09A". The attached spreadsheet includes original and new names for all Duck Island wells. While performing the review of Duck Island well names, HAK found a single well, "DUCK IS UNIT SDI 4-20/M35" (PTD# 1861730), that should also be modified to include an "A" label to reflect the fact that the well is a sidetrack from the original "DUCK IS UNIT SDI 4-20/T34" (PTD # 1861500). The original wellbore, abandoned 10/13/1986, was sidetracked to a new bottom hole location completed on 9/9/1987. This well appears to be one of the first sidetracks performed at Endicott. While the bottom hole code was changed, no letter was added to reflect the sidetrack. "DUCK IS UNIT SDI 4-20A" is also included on the attached spreadsheet. Sincerely, Wyatt Rivard Well Integrity Engineer Hilcorp Alaska, LLC CC Dave Roby Victoria Loepp Orig New API_WeIINo PermitNumber WellName WellNumber WellNumber 50029218010000 1880370 DUCK IS UNIT MPI 1-01/J19 1-01 50029226010000 1951500 DUCK IS UNIT MPI 1-03/P16 1-03 50029216050000 1861060 DUCK IS UNIT MPI 1-05/020 1-05 50029217430000 1870810 DUCK IS UNIT MPI 1-09/J18 1-09 50029217430100 1970290 DUCK IS UNIT MPI 1-09A/L21 1-09A 50029221070000 1901570 DUCK IS UNIT MPI 1-11/SN4 1-11 50029223610000 1930560 DUCK IS UNIT MPI 1 15/P25 1 15 50029221000000 1901500 DUCK IS UNIT MPI 1-17/SN2 1-17 50029221000100 1961990 DUCK IS UNIT MPI 1 17A/I17 1-17A 50029225690000 1950930 DUCK IS UNIT MPI 1-19/118 1-19 50029220050000 1900020 DUCK IS UNIT MPI 1-21/K25 1-21 50029225100000 1941280 DUCK IS UNIT MPI 1-23/015 1-23 50029217220000 1870420 DUCK IS UNIT MPI 1-25/N22 1-25 50029217220100 1970750 DUCK IS UNIT MPI 1-25A/K22 1-25A 50029216930000 1870090 DUCK IS UNIT MPI 1-27/P20 1-27 50029216690000 1861810 DUCK IS UNIT MPI 1-29/M25 1-29 50029225620000 1950720 DUCK IS UNIT MPI 1-31/M21 1-31 50029225770000 1951070 DUCK IS UNIT MPI 1-33/M23 1-33 50029225770100 1980870 DUCK IS UNIT MPI 1-33A/L24 1-33A 50029225770200 1982550 DUCK IS UNIT MPI 1-33B/L24 1-33B 50029225770300 2050040 DUCK IS UNIT MPI 1-33C/M24XX 1-33CXX 50029216720000 1861840 DUCK IS UNIT MPI 1-35/025 1-35 50029217480000 1870900 DUCK IS UNIT MPI 1-37/P24 1-37 50029218270000 1880630 DUCK IS UNIT MPI 1-39/P17 1-39 50029218270100 2061870 DUCK IS UNIT MPI 1-39A/N-16 1-39A 50029217130000 1870320 DUCK IS UNIT MPI 1-41/023 1-41 50029218640000 1881050 DUCK IS UNIT MPI 1-43/P26 1-43 50029219910000 1891240 DUCK IS UNIT MPI 1-45/Q26 1-45 50029216250000 1861310 DUCK IS UNIT MPI 1-47/Q21 1-47 50029216250100 1972030 DUCK IS UNIT MPI 1-47A/M20 1-47A 50029218410000 1880780 DUCK IS UNIT MPI 1-49/P21 1-49 50029223040000 1921190 DUCK IS UNIT MPI 1-51/V20 1-51 50029225010000 1941120 DUCK IS UNIT MPI 1-53/Q20 1-53 50029217880000 1880210 DUCK IS UNIT MPI 1-55/R25 1-55 50029218730000 1881140 DUCK IS UNIT MPI 1-57/R23 1-57 50029226440000 1960220 DUCK IS UNIT MPI 1-59/024 1-59 50029225200000 1941420 DUCK IS UNIT MPI 1-61/Q20 1-61 50029219050000 1890060 DUCK IS UNIT MPI 1-63/T22 1-63 50029226270000 1951880 DUCK IS UNIT MPI 1-65/N25 1-65 50029226270100 2032120 DUCK IS UNIT MPI 1-65A/N27 1-65A 50029219850000 1891140 DUCK IS UNIT MPI 1-67/T20 1-67 50029220200000 1900290 DUCK IS UNIT MPI 1-69/V19 1-69 50029215680000 1860630 DUCK IS UNIT MPI 2-02/P18 2-02 50029215850000 1860820 DUCK IS UNIT MPI 2-04/M19 2-04 50029216990000 1870180 DUCK IS UNIT MPI 2-06/J22 2-06 50029217710000 1880040 DUCK IS UNIT MPI 2-08/K16 2-08 50029223020000 1921170 DUCK IS UNIT MPI 2-12/Q16 2-12 50029216390000 1861490 DUCK IS UNIT MPI 2-14/016 2-14 50029218850000 1881340 DUCK IS UNIT MPI 2-16/M16 2-16 50029220320000 1900430 DUCK IS UNIT MPI 2-18/L16 2-18 50029220480000 1900600 DUCK IS UNIT MPI 2-20/115 2-20 50029219310000 1890340 DUCK IS UNIT MPI 2-22/L14 2-22 Pages NOT Scanned in this Well History File XHVZE This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. File Number of Well History File PAGES TO DELETE Complete RESCAN Color items - Pages: Grayscale, halftones, pictures, graphs, charts- Pages: Poor Quality Original- Pages: [] Other- Pages: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED -[] Logs-of vadous kinds [] Other COMMENTS: Scanned by: ianna Vincent Nathan Lowell TO RE-SCAN Notes' Re-Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: /si • • bp BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB -20 Post Office Box 196612 Anchorage, Alaska 99519 -6612 May 22, 2012 a ";; y Mr. Jim Regg l 19( 3 — 0 Alaska Oil and Gas Conservation Commission 1 _ 15 Ras- 333 West 7 Avenue 01) 1 Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of Endicott Row 1 Dear Mr. Regg, Enclosed please find multiple copies of a spreadsheet with a list of wells from Endicott Row 1 that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10 -404, Report of Sundry Operations. If you require any additional information, please contact me or my altemate, Gerald Murphy, at 659 -5102. Sincerely, Mehreen Vazir BPXA, Well Integrity Coordinator • • BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) Endicott Row 1 Date: 09/24/2010 . Corrosion Initial top of Vol. of cement Final top of Cement top off Corrosion inhibitor/ Well Name PTD # API # cement pumped cement date inhibitor sealant date ft bbls ft na gal END1 -01 /J -19 1880370 50029218010000 1.5 0.3 0.5 9/2/2010 0.85 9/23/2010 END1 -03 / P -16 1951500 50029226018000 4.0 3.5 0.5 9/2/2010 5.10 9/23/2010 END1 -05 / 0 -20 1861060 50029216050000 0.3 NA 0.3 NA 1.70 9/23/2010 END1 -09 / L -21 1970290 50029217430100 6.0 5.0 0.5 8/28/2010 3.40 9/23/2010 w ___.-?END1 -15 / P -25 1930560 50029223610000 4.0 3.0 0.5 9/2/2010 6.80 9/23/2010 END1- 17/I -17 1961990 50029221000100 8.0 4.3 0.5 9/2/2010 2.55 9/23/2010 END1 -19 /1-18 1950930 50029225690000 7.0 9.3 0.5 9/2/2010 4.25 9/23/2010 END1 -21 / K -25 1900020 50029220050000 2.5 1.5 0.5 9/2/2010 1.70 9/23/2010 END1 -23 / 0 -15 1941280 50029225100000 12.0 12.5 0.5 9/2/2010 1.70 9/23/2010 END1 -25 / K -22 1970750 50029217220100 5.0 1.5 0.5 9/2/2010 5.10 9/23/2010 END1 -27 / P -20 1870090 50029216930000 8.0 4.3 0.5 9/2/2010 2.55 9/23/2010 END1 -29 / M -25 1861810 50029216690000 2.0 1.3 0.5 9/2/2010 1.70 9/23/2010 END1 -31 / M -21 1950720 50029225620000 5.0 1.8 0.5 9/2/2010 13.60 9/23/2010 END1 -33 / L -24 1982550 50029225770200 1.5 0.3 0.5 9/2/2010 3.40 9/23/2010 END1 -35 / 0-25 1861840 50029216720000 8.0 4.8 0.5 9/2/2010 3.40 9/23/2010 END1 -37 / P -24 1870900 50029217480000 0.5 NA 0.5 NA 4.25 9/23/2010 END1 -39A / N -16 2061870 50029218270100 0.5 NA 0.5 NA 6.80 9/23/2010 END1 -41 / 0 -23 1870320 50029217130000 8.0 5.2 0.5 9/2/2010 4.25 9/23/2010 END1 -43 / P -26 1881050 50029218640000 2.0 0.5 0.5 9/2/2010 3.40 9/23/2010 END1 -45 / 0-26 1891240 50029219910000 1.5 0.3 0.5 9/2/2010 1.70 9/24/2010 END1 -47A / M -20 1972030 50029216250100 1.0 0.1 0.5 9/2/2010 3.40 9/24/2010 END1 -49 / P -21 1880780 50029218410000 1.0 0.8 0.5 9/2/2010 3.40 9/24/2010 END1 -51 / V -20 1921190 50029223040000 1.5 0.3 0.5 9/2/2010 1.70 9/24/2010 END1 -53 / 0-20 1941120 50029225010000 9.0 4.2 0.5 9/2/2010 1.70 9/24/2010 END1 -55 / R -25 1880210 50029217880000 1.3 0.1 0.5 9/2/2010 1.70 9/24/2010 END1 -57 / R -23 1881140 50029218730000 3.0 1.3 0.5 9/2/2010 5.10 9/24/2010 END1 -59 / 0 -24 1960220 50029226440000 3.0 1.3 0.5 9/2/2010 0.85 9/24/2010 END1 -61 /0 -20 1941420 50029225200000 8.0 6.8 0.5 9/2/2010 2.55 9/24/2010 END1 -63 / T -22 1890060 50029219050000 8.0 4.1 0.5 9/2/2010 2.55 9/24/2010 END1 -65A / N -27 2032120 50029226270100 8.0 5.8 0.5 9/2/2010 3.40 9/24/2010 END1 -67 / T -20 1891140 50029219850000 0.5 NA 0.5 NA 1.70 9/24/2010 END1 -69 / V -19 1900290 50029220200000 15.0 10.3 0.5 9/2/2010 0.85 9/24/2010 12/10/10 Schhiaberger NO. 5658 Alaska Data & Consulting Services Company: State of Alaska 2525 Gambelt 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 It Log Description Date BL Color CD MPF -13 BDAD -00024 USIT 19,E (') 09129110 1 _ 1 s� Q /�c NK-65A BCRD -00064 INJ PROFILE/RSTMIFL ;15 — lNO3 10/21/10 1 1 .J6.(.�` i) S-41A BCRD-00058 USIT ;)j(� / (a( 09124110 1 1 I ¢ 1- 15/P -25 B3SQ -00096 SCMT 1 - 10/31/10 1 1 ♦ 9 W -219 B0Z7 -00012 USIT _ • — • 11/22110 1 1 •. — 09 -09 BCRD -00062 RST 'f '� 10/14/10 1 1 5 - _ 01 -02 BCRD - 00066 RST /(e ^ -- It • 10/26/10 1 1 1 05 -33B BAUJ -10042 MCNL .. I(1 -('l Sfl 08/28/10 1 1 'Mg 05-31B 10AKA0071 OH MWD /LWD EDIT of in - / 0:ifs' 08/30/10 2 1 • . I PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY EACH TO: BP Exploration (Alaska) Inc. Alaska Data & Consulting Services Petrotechnical Data Center LR2 -1 2525 Gambeit Street, Suite 400 900 E. Benson Blvd. Anchorage, AK 99503 -2838 • ..„,..,.._,.\ . pc ...,\A ,....„,„ „ „..... Agti6tit MAR 14 Z011 `1 c,`) 0,0 vo— • • WELL LOG TRANS /TTAL PROACiivE DiAgwmk SERVICES, INC. I To: AOGCC Christine Mahnken 333 W. 7th Ave Suite 100 Anchorage, Alaska 99501 (907) 793 -1225 RE: Cased Hole /Open Hole /Mechanical Logs and/or Tubing Inspection(Caliper / MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the following BP Exploration (Alaska), Inc. Petrotechnical Data Center Attn: Joe Lastufka LR2 -1 900 Benson Blvd. Anchorage, Alaska 99508 N�A' 2 and ProActive Diagnostic Services, Inc. Attn: Robert A. Richey La !�3 - O 130 West International Airport Road Suite C Anchorage, AK 99518 Fax: (907) 245 -8952 1) Leak Detection - WILD 30 -0ct -10 1 -15 / R-25 BL / EDE 50-029 - 22361 -00 Signed : Date Print Name: PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245 -8951 FAX: (907)245 -88952 E oelsanchoraaeCa memorylog.com WESSITE : www.memorylog.com CADocumena and SemngsTiane Williams \Desktop \Transmit_BP.docx MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: Tuesday, October 19, 2010 P.I. Supervisor ►��1� 11 � 1 � t� SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC 1- 15/P25 FROM: Bob Noble DUCK IS UNIT MPI 1- I5/P25 Petroleum Inspector Sre: Inspector Reviewed By: P.I. Supry -JT., NON Comm Well Name: DUCK IS UNIT MPI 1- 15/P25 API Well Number 50- 029 - 22361 -00 -00 Inspector Name: Bob Noble Insp Num: mitRCN101012140419 Permit Number: 193 -056 -0 Inspection Date: 10/8/2010 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min 60 Min. Well 1 /P25 � Type In). { I N TVD 9481 - IA 960 5650 - 5400 5260 5100 , P.T.D 1930560 • ITypeTest f SPT Test p si 5650 - QA 60 60 60 60 60 Interval 4Y RTST P/F F T ubing J 680 3140 3080 , 3040 3000 Notes: Test was held an extra 15 min because pressure faile to stabi lize. PA. NOV Tuesday, October 19, 2010 Page I of 1 Y I � • ORANDUM State of Alaska 0 Alaska Oil and Gas Conservation Commission Jim Regg DATE: Tuesday, October 19, 2010 ' P.I. Supervisor ' l , 1 110 SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC 1- 151P25 FROM: Bob Noble DUCK IS UNIT MPI 1- 15/P25 Petroleum Inspector Sre: Inspector Reviewed By: P.I. Supry le — NON - CONFIDENTIAL Comm Well Name: DUCK IS UNIT MPI 1- 15/P25 API Well Number: 50- 029 - 22361-00 -00 Inspector Name: Bob Noble Insp Num: mitRCN101012141148 Permit Number: 193 -056 -0 Inspection Date: 10/8/2010 Re] Insp Num: Packer Depth Pretest Initial 15 Min, 30 Min 45 Min. 60 Min. I -IS P25 9481 IA 5100 5650 5460 — 5310 Well Typ InJ. � N TVD _ P.T.D 1930560 (Type Test j SP — T I Test p si 5650 OA 60 60 — I 60 60 in terval F` 4YRTST P� F Tubing 3000 3100 3060 3000 Notes: This is the second test on this well today. Torin wanted to pump it up again and re -test the well. The pressure fail to stabili just like the first test. I Tuesday, October 19, 2010 Page I of I • Jack Lau Petroleum Engineer ~ ;_ a ,~ +.+ BP Exploration (Alaska), Inc. '~ - ' ~' P.O. Box 196612 ©~ ~j Anchorage, AK 99519-6612 I ~~°` Re: Endicott Field, Endicott Oil Pool, 1-15 / P-25 Sundry Number: 310-270 Dear Mr. Lau: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Chair DATED this ~® day of September, 2010. Encl. ' STATE OF ALASKA ALASK~AND GAS CONSERVATION COMMISSI~ ~_/G~IZ ~ ~D-~O • APPLICATION FOR SUNDRY APPROVALS 77~~' q,~b. ~b ~n aac ~~ ~Rn 1. Type of Request: Abandon ^ Plug for Redrill ^ Pertorate New Pool ^ Repair Well ^ Change Approved Program ^ Suspend ^ Plug Pertorations ^ Perforate^ Pull Tubing ^ Time Extension ^ Operation Shutdown ^ Re-enter Susp. Well ^ Stimulate^ Alter Casing ^ Other: PKR SQUEEZE 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: BP Exploration (Alaska), Inc. Development ^ Exploratory ^ 193-0560 - 3. Address: P.O. Box 196612 Stratigraphic ^ Service ^, 6. API Number: Anchorage, AK 99519-6612 50-029-22361-00-00_ 7. If pertorating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property tine where ownership or landownership changes: Spacing Exception Required? Yes ^ No ^ 1-15/P-25' 9. Property Designation (lease Number): 10. Field/Pool(s): ADLO-047502 ENDICOTT Field / ENDICOTT OIL Pool 11 • PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 12972 - 10094.82 • 12952 10078.66 1 2200' NONE Casing Length Size MD TVD Burst Collapse Structural Conductor 80 20' 91.5# H-40 39 119 39 119 1490 470 Surface 2715 13-3/8" 68# L-80 38 2753 38 2740 4930 2270 Intermediate 10634 9-5/8" 47# NT80WS 37 10671 37 8432 6870 4760 Production 1823 9-5/8" 47# NT95HS 10671 12494 8432 9720 8150 5080 Liner 768 7"29# NT-80 12204 12972 9504 10095 8160 7020 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): SEE ATTACHED - - 7" 26# NT-80S 35 12208 Packers and SSSV Tvoe: 5-1/2" Weathertord ArrowPac Packer Packers and SSSV MD and TVD (ftl: 11845 9245 5-1/2" Weatherford ArrowPac Packer 11866 9260 7" Baker SABL-3 Packer 12173 9481 12. Attachments: Description Summary of Proposal Q 13. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development ^ Service ^~ - 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 9/9/2010 Oil ^ Gas ^ WDSPL ^ Suspended ^ 16. Verbal Approval: Date: WINJ ^ GINJ Q - WAG ^ Abandoned ^ Commission Representative: GSTOR ^ SPLUG ^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact JACK LAU Printed Name JA K LA Title PE Signature Phone Date 564-5102 8/26/2010 Prepared by Gary Prebie 564-4944 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~~ ~~O Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ~ Location Clearance ^ ' M l T l R ~ ~4 bl h~ Other: j ~ 1~ E-^~+?,~ 5 ii ~ V 5 ~ -~' I ' ~ ,~~ c'°'~G~t [,~ i ~~ b'L ,~ 1" S r ~ ~ ~G -{"~i ~ ~'c . 2 ~ 7 C~ ` , . , . . ~ f ' k' f . ! ~. ~ ~ , A't I T- f ~}~, ~ . ~~ ~ s^ SSi ~1, ~a~ ~~.~~i ~ y Subsequent Form Required: p - (~~ ~~ . :_. r ` ,,r ~~ !1~6P ?a:~lrl t~~l APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date ~ ' ~ n ,5 sEP ~0-e Zo~ro O R I G I N A 1.~. ~- ~:3~ ,~ ~~~~~~ Form 10-403 Revised 1/2010 Submit in Duplicate 1-15/P-25 193-056 Sw Name Perf Operation Code Operation Date PERF ATTACHME Meas Depth Top NT Meas Depth Base Tvd Depth Top Tvd Depth Base 1-15/P-25 PER 6/5/93 12,667. 12,687. 9,852.15 9,867.71 1-15/P-25 PER 6/5/93 12,702. 12,706. 9,879.41 9,882.53 1-15/P-25 PER 6/5/93 12,718. 12,730. 9,891.92 9,901.32 1-15/P-25 PER 6/5/93 12,742. 12,756. 9,910.74 9,921.76 1-15/P-25 PER 6/5/93 12,770. 12,809. 9,932.8 9,963.7 1-15/P-25 APF 8/5/93 12,498. 12,519. 9,722.86 9,738.76 1-15/P-25 APF 8/5/93 12,566. 12,620. 9,774.45 9,815.82 1-15/P-25 APF 8/5/93 12,650. 12,667. 9,838.98 9,852.15 1-15/P-25 BPS 1/5/02 12,200. 12,809. 9,500.7 9,963.7 1-15/P-25 BPP 6/22/04 12,200. 12,952. 9,500.7 10,078.66 1-15/P-25 BPS 6/9/10 12,166. 12,809. 9,475.79 9,963.7 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 n U ~JD1-15 IA Cement Squeeze by U September 8th, 2010 To: Jerry Bixby /Rob Liddelow - Wireline Operations Team Lead Clark Olsen /Tyler Norene -Wells Services Operations Team Lead From: Jack Lau, Wells Engineer Jennifer McLeod, Endicott PE Subject: END1-15 IA Cement Squeeze REV1 ~~ ~- ~~~ D P ~ q-~ Please perform the attached packer squeeze procedure on END1-15: 1 S ~ Pull XXN. D&T. Set PXN. 2 E Tubing Punch 3 F Circulate Tubing and IA. MITIA to 1500 psi. 4 C Packer Squeeze 5 FP WOC 3 days. MITIA to 3000 psi. MITT to 3000 psi. ~ 6 EP CBL. 7 SP Pull PXN. Install SSSV. Well Info Current Status: Shut In Not-Operable Gas Injector due to failed MITIA - secured with TTP Deviation: 49° at 6850 MD Minimum ID: 3.725 @ 12,200' thru reducing nipple, 4.0" thru patch Last Downhole Op: 06/08/10: Set TTP plug at 12200' MD Latest H2S value: N/A Completion: 7", 26#, NT-80S tubing Surface - 10671' and NT 95HS to 12208' Baker 9-5/8" x 7" SABL-3 packer at 12173' MD Note: 5.93" Weatherford Patch @ 11,843' MD (4.0" ID) Reducer set in lowest R nipple (3.755" ID) Sundry: Needs a Sundry prior to commencing cementing work. Page 1 of 9 ~ID1-15 IA Cement Squeeze Objective: The objective of this program is to reestablish IA integrity by repairing the PC leak in the range of 12,080-12,150' by squeezing a cement donut plug into the IA through tubing punches. Discussion: Well 1-15/P-25 has a history of manageable T x IA communication, which required a bleed approximately every month and a half. As per Administrative Approval 1.006 an MIT-T IA was done on Jan-08 to 5650 and failed. A MITIA subsequently passed using a triplex pump on 06/04/08. The two year AOGCC MITIA failed on 06/17/10. A LLR was established at ~1 bpm @ 3300 psi. No tubing pressure response was indicated during the failed MITIA possibly indicating a leaking packer or a PC leak. To restore the well as a back up injector, communication must be corrected. A LDL was run 077/11/10 to determine the source of MITIA failure. The temperature passes indicate a PC leak in the 9-5/8" casing between 12,080 and 12,150'. The plan forward is to place a cement donut plug in the IA above the leak at 12,080' effectively acting as a second packer. This cement barrier will provide isolation from the PC leak. AnnComm History: > 08/16/01: LDL ID'ed tubing leak @ 11,858' > 01/05/02: Ran nipple reducer, set TTP > 01/29/03: CMIT T x IA PASSED to 3000 psi. > 04/19/04: CMIT TxIA Passed to 2500 psi > 05/31/04: TBG Patch set from 11847' to 11867' > 06/17/04: MITIA Passed to 4000 psi > 06/18/04: MITIA Passed to 4000 psi -state witnessed by Jeff Jones. Sent form to Winton. > 01/20/06: Notified AOGCC of slow IA repressurization, plan to leave on injection for MITIA > 02/11/06: AOGCC MITIA Passed to 4000 psi, witness Jeff Jones. > 02/12/06: Email to Winton & Jim notifying of plans to continue operation with slow IA repressurization > 02/21 /06: AA for TxIA sent to state. > 03/03/06: Received approval A1O 1.006 for continued GI, with IAP pilot installed. Edited A1O with email from Harry Engel and Winton about removal of MIT-OA requirement. > 11 /25/06: MCX SSV set @ 1487' > 02/11/08: Operation repaired leaking swab > 02/13/08: PPPOT-T Passed to 5000 psi, PPPOT-IC Passed to 3000 psi, set TTP @ 12159' > 02/14/08: MIT-T Passed to 3000 psi > 02/15/08: AOGCC MIT-IA Failed > 03/01 /08: Caliper 7": 309 jts < 20%; 9 jts 20-27% > 03/18/08: A1O 1.006 Cancelled > 04/07/08: LDL found small leak @TTP > 04/07/08: MITIA Passed to 3500 psi, MIT-T Failed Page2of9 ~ID1-15 IA Cement Squeeze > 06/04/08: MIT-IA Passed to 5650 psi > 06/22/08: Pulled TTP from 12200' > 09/19/08: AA1.008 for continued operation with Slow IA re-pressurization > 06/03/10: PPPOT-T & IC Passed > 06/06/10: Pulled SSSV > 06/06/10: Caliper 322 jts 0-29% > 06/09/10: TTP set @ 12200', MIT-T- Failed > 06/12/10: MIT-IA Passed to 4000 psi > 06/17/10: AOGCC MIT-IA Failed, LLR 1 bpm @ 3300 psi (no Tbg response) > 07/10/10: Pulled TTP from 12166' > 07/12/10: MIT-IA Failed, LLR 1 bpm @ 3300 psi, LDL indicates PC leak @ 12080'- 12150' > 07/18/10: Set TTP @ 12169', MIT-T Passed to 3000 psi, MIT-IA Passed to 3000 psi > 07/26/10: MIT-T Failed, CMIT-TxIA Failed LLR 1.6 gpm @ 3300 psi & 11.3 gpm @ 3430 psi Contact Jack Lau at 564-5102 (W), 227-2760 (C); or Jennifer McLeod 564-2764 (W) with any questions or comments. CC: Well File END1-15 IA Cement Squeeze Procedure Slickline 1. RIH and retrieve 4'/2" XXN plug from 12,200'. 2. Drift & Tag TD. 3. Set 4'/2" PXN plug in the XN nipple at 12,200'. The PXN plug will be easier to retrieve post cement squeeze. E-line MIRU e-line. RU with GR/CCL and tubing punch. RIH, tie into tubing tally. Punch hales at 12,160' to establish communication path between tubing and IA. Log from just below packer up past tubing patch (11,847-11867) to establish accurate depths for later cementing work. Fullbore 5. Rig up pumping equipment to the tubing to load and circulate the following fluids into the well by pumping down the tubing and taking returns. from the inner annulus to ensure the leak rate can be established and the wellbore is fluid packed with all the gas removed prior to the upcoming cement packer repair. Pump at max rate not exceeding 3000 psi. Do not attempt to load the inner annulus by pumping directly down the IA. It is critical that all gas is removed from both the tubing and IA prior to pumping cement. Jumper the IA to flow line to be able to take returns down the flowline. Freeze protect the flowline after fluid packing the wellbore. Page 3 of 9 ~ID1-15 IA Cement Squeeze - 1100 bbls of inhibited seawater/1 %KCI Tubing volume to XN 453 bbls IA Volume to packer 312 bbls total 765 bbls 1.5 x 1148 bbls 6. After pumping 1100 bbls inhibited seawater/1 % KCI and 30 bbls diesel into the tbg and up the IA, U-tube diesel freeze protect into the IA. . 7. Perform aCMIT-TxIA to 1500 psi to verify that the PXN plug is holding prior to the cement packer repair. If the pressure test fails establish a liquid leak rate (LLR). Do not proceed with the repair until a passing CMIT-TxIA is achieved. Cementing Specifications: - 15.8 ppg Unislurry Cement - 2 - 3 hours thickening time - 6 - 8 hours to reach 500 psi compressive strength - 2,000 psi ultimate compressive strength - Bottom hole circulating temperature: 160 °F - Static bottom hole temperature: 200 °F - Perform a UCA test and a thickening time test on the field blend prior to rigging up. - Cement ramp attached. Post Cement Squeeze Diagram Page 4 of 9 ~ID1-15 IA Cement Squeeze f----- TES 11,900' ~-- Tubing Punches 12,160' Coil Tubing -Packer Repair Page 5 of 9 ,JD1-15 IA Cement Squeeze • 8. RU the CTU with cementing equipment. MU and RIH with a ball drop cementing nozzle and lightly tag PXN plug at 12,200' MD, taking pipe displacement returns out of the coil tubing-by-tubing annulus. Pickup until full string weight is observed and flag pipe. This flag will be used for depth control during cement cleanout. Pull up hole to 12,155' MD (tubing punches at 12,160') while laying in 1.5 bbls of calcium carbonate sluggits 1-for-1 in the 7" tubing, taking returns out of the coil tubing-by-tubing annulus. Utilize a HEC gel slurry to deploy sluggits. 9. PUH 100' and wait for sluggits to settle. Tag top of sluggits. Either cleanout or. pump additional sluggits to attain target depth of 12,160'. An acceptable range is between 12,160 to 12,170'. 10.Once 1.5 bbls of calcium carbonate sluggits have been placed in the wellbore; open up the coil tubing-by-tubing annulus and pump 150 bbls of 140°F KCI water down the coil tubing taking returns to surface to allow for wellbore cooling. 11.After pumping 150 bbls of 140°F KCI water down the coil tubing, keep the coil tubing-by-tubing annulus open, open up the IA and pump 100 bbls of 140°F KCI water into the IA to cool wellbore and ensure infectivity through the tubing punches can be established (with returns up backside). 12. Pump 95 bbls of diesel down the IA. This will leave ~83 bbls (3200') of freeze ~ protect in the well post cement squeeze and leave the well underbalanced on the IA by 150 psi. 13.Open the coil tubing-by-tubing annulus to take returns to surface. Prepare to mix 6.7 pumpable barrels of 15.8 ppg unislurry cement on the fly, which will have a thickening time of 2-3 hours, give 500 psi compressive strength in 6 - 8 hours, and 2,000 psi ultimate compressive strength. The bottom hole circulating temperature at cement depth should be 180 °F. - Ensure that there is no gas in the tubing or IA. Do not proceed with the repair unless the tubing and IA are fully liquid packed. - Base cleanout on field blend UCA. Line out the cementers to the coil. Pump the following fluids down the coil (see steps 12 - 15 for complete pumping details): - 5 bbls spacer water - 4.5 bbls Unislurry cement - Coil Tubing volume of water - 20 bbls of biozan 14. With the coil tubing-by-tubing annulus open and the IA closed, pump 5 bbls of spacer water out the coil while parked at 12,155', taking returns out the coil tubing-by-tubing annulus. 15. Begin pumping cement while continuing to take returns up the coil tubing-by- tubing annulus and maintaining 100-200 psi back pressure on the tubing. Pump 6.7 bbls of cement out the nozzle (120' of cement above the nozzle assuming cement bottom will be at the top of the sluggits at 12,080') and lay in remaining Page 6 of 9 ~ID1-15 IA Cement Squeeze cement while PUH (this will ensure that the cement is not diluted as the coil pulls up). Strap returns in the 40 bbl tank while pumping cement. Time nozzle to be at TOC just as the last of the cement is out the nozzle. SAFETY: If no cement is circulated up the IA, 6.7 bbls of cement will extend up the tubing to 11,980' MD (180' above the top of the sluggits at 12,160'). 16. Park well above the worst case cement top, shut-in the coil tubing-by-tubing annulus and open up the IA. Continue pumping water spacer until 6.7 bbls of cement have been circulated into the IA. Strap returns in the 40 bbl tank. Shut in the inner annulus. FROM THIS POINT ON KEEP THE IA SHUT IN AT ALL TIMES. DO NOT BLEED THE IA IF PRESURE INCREASES. Maintain at least 200 psi WHP at all times. 17. Pump the remaining coil tubing volume of water followed by 20 bbls of biozan to contaminate remaining cement in the tubing. Pump biozan from 11,800' to 12,080', keeping coil tubing-by-tubing annulus pressure constant and the IA shut in (do not open IA in the case pressure increases). Only bleed fluid from the coil tubing-by-tubing annulus to achieve constant pressure. Take coil tubing-by- tubing returns to a calibrated returns tank to confirm 1:1 returns. 18. Pump another 20 bbls of biozan while reciprocating across the patch at 11,847- 11,867'. Keeping coil tubing-by-tubing annulus and IA pressure constant. Only bleed fluid from the coil tubing-by-tubing annulus to achieve constant pressure. Take coil tubing-by-tubing returns to a calibrated returns tank to confirm 1:1 returns. 19. Begin POOH pumping 50/50 methanol/water to freeze protect coil and 1000' of tubing (37 bbls) also replacing coil tubing volume to maintain a balanced wellbore. It is critical that the coil tubing-by-tubing annulus and the IA remain at constant pressure at cement depth while POOH. Based on fluid hydrostatics in the wellbore once the coil is out of the well, 100 psi will need to be applied to the IA to keep the IA and tubing pressure constant at the cement plug to avoid cement "u-tubing". 20.Once at surface, block in everything and ensure that all valves are holding and maintain a constant pressure on the tubing and IA. 21. Do not disturb the well (i.e. do not apply pressure, bleed off pressure, etc.) until these samples have started to set up. 22.Once cement has developed 500 psi compressive strength nased on the UCA then make up BHA with jetting nozzle to clean out calcium carbonate sluggits. RIH to 11,800' and perform a "mini" MIT-IA to a OP of 500 psi (i.e. IA pressure + 500 psi) by pumping diesel down the IA. Page 7 of 9 iJD1-15 IA Cement Squeeze . - Wait until the cement reaches 500 psi compressive strength - based on the UCA. 23.If "mini" MIT-IA passes, clean out calcium carbonate from 12,080 to PXN plug at 12,200. Use caution by reducing to very low speed to avoid damaging the PXN equalizing prong. - If cement stringers are encountered POOH and PU DB underreamer. - Note: Use vendor guidelines while underreaming. . 24.If "mini" MIT-IA does not pass - do not clean out calcium carbonate sluggits, contact either Jack Lau or Brad Gathman to discuss results prior to proceeding with milling. 25. Establish LLR from T~ IA and IA ~ T. 26.Once calcium carbonate sluggits have been cleaned out perform a "mini" MIT-T to a 0P of 500 psi (i.e. WHP pressure + 500 psi) by pumping down the coil. 27. POOH. Ensure that tubing is freeze protected to 1000' with diesel or methanol. 28. RDMO. Fullbore -Post Packer Squeeze (Pending "mini" MIT-IA passing) 29.After 3 days WOC, MIT-IA to 3000 psi. If the MIT-A fails establish LLR.' 30. Perform MITT to 3000 psi, est LLR if Fails. / E-line 31.MIRU a-line. RU with CBL. RIH, tie into tubing tally. Log CBL from 12,195' to 11,800'. POOH. RDMO. o t ~D L• Slickline 32. Pull 4'/2" PXN plug from the XN nipple at 12,200'. Install SSSV. Page 8 of 9 ~JD1-15 IA Cement Squeeze Page 9 of 9 kC1= MC~"Vi7Y ~~w~An= ~ E N C~'I ~'I 5 SAS ~o~s: a,cTUaio~= nxFis~~N ~D1-15 IA Cement Squeeze August 23, 2010 To: Jerry Bixby /Rob Liddelow - Wireline Operations Team Lead Clark Olsen /Tyler Norene -Wells Services Operations Team Lead From: Jack Lau, Wells Engineer Jennifer McLeod, Endicott PE l~. Subject: END1-15 IA Cement Squeeze ~~e~~~ ~ti.~`e~r- Please perform the attached packer squeeze procedure on END1-15: 1 S Pull XXN. D8~T. Set PXN. 2 E Tubing Punch 3 C Packer Squeeze Well Info Current Status: Shut In Not-Operable Gas Injector due to failed MITIA - secured with TTP Deviation: 49° at 6850 MD Minimum ID: 5.962" ID at 1514 and 12152' MD Last Downhole Op: 06/08/10: Set TTP plug at 12200' MD Latest H2S value: N/A Completion: 7", 26#, NT-80S tubing Surface - 10671' and NT 95HS to 12208' Baker 9-5/8" x 7" SABL-3 packer at 12173' MD Note: 5.93" Weatherford Patch @ 11,843' MD (4.0" ID) Reducer set in lowest R nipple (3.755" ID) ~J ~V Sundry: Needs a Sundry prior to commencing cementing work. ~.. ~ ~ - r~ _~: a Objective: The objective of this well intervention is place 125' of cement in the IA to repair a small production casing leak 50-125' above the production packer. Discussion: Page 1 of 7 ~D1-15 IA Cement Squeeze Well 1-15/P-25 has a history of manageable T x IA communication, which required a bleed approximately every month and a half. As per Administrative Approval 1.006 an MIT-T IA was done on Jan-08 to 5650 and failed. A MITIA subsequently passed using a triplex pump on 06/04/08. The two year AOGCC MITIA failed on 06/17/10. A LLR was established at ~1 bpm @ 3300 psi. No tubing pressure response was indicated during the failed MITIA possibly indicating a leaking packer or a PC leak. To restore the well as a back up injector, communication must be corrected. A LDL was run 077/11/10 to determine the source of MITIA failure. The temperature passes indicate a PC leak in the 9-5/8" casing between 12,080 and 12,150'. The plan forward is to place a cement donut plug in the IA above the leak at 12,080' effectively acting as a second packer. This cement barrier will provide isolation from the PC leak. AnnComm History: > 08/16/01: LDL ID'ed tubing leak @ 11,858' > 01/05/02: Ran nipple reducer, set TTP > 01/29/03: CMIT T x IA PASSED to 3000 psi. > 04/19/04: CMIT TxIA Passed to 2500 psi > 05/31 /04: TBG Patch set from 11847' to 11867' > 06/17/04: MITIA Passed to 4000 psi > 06/18/04: MITIA Passed to 4000 psi -state witnessed by Jeff Jones. Sent form to Winton. > 01/20/06: Notified AOGCC of slow IA repressurization, plan to leave on injection for MITIA > 02/11/06: AOGCC MITIA Passed to 4000 psi, witness Jeff Jones. > 02/12/06: Email to Winton & Jim notifying of plans to continue operation with slow IA repressurization > 02/21/06: AA for TxIA sent to state. > 03/03/06: Received approval AIO 1.006 for continued GI, with IAP pilot installed. Edited A1O with email from Harry Engel and Winton about removal of MIT-OA requirement. > 11 /25/06: MCX SSV set @ 1487' > 02/11/08: Operation repaired leaking swab > 02/13/08: PPPOT-T Passed to 5000 psi, PPPOT-IC Passed to 3000 psi, set TTP @ 12159' > 02/14/08: MIT-T Passed to 3000 psi > 02/15/08: AOGCC MIT-IA Failed > 03/01/08: Caliper 7": 309 jts < 20%; 9 jts 20-27% > 03/18/08: A1O 1.006 Cancelled > 04/07/08: LDL found small leak @TTP > 04/07/08: MITIA Passed to 3500 psi, MIT-T Failed > 06/04/08: MIT-IA Passed to 5650 psi > 06/22/08: Pulled TTP from 12200' > 09/19/08: AA1.008 for continued operation with Slow IA re-pressurization > 06/03/10: PPPOT-T & IC Passed > 06/06/10: Pulled SSSV > 06/06/10: Caliper 322 jts 0-29% Page 2 of 7 ~D1-15 IA Cement Squeeze > 06/09/10: TTP set @ 12200', MIT-T- Failed > 06/12/10: MIT-IA Passed to 4000 psi > 06/17/10: AOGCC MIT-IA Failed, LLR 1 bpm @ 3300 psi (no Tbg response) > 07/10/10: Pulled TTP from 12166' > 07/12/10: MIT-IA Failed, LLR 1 bpm @ 3300 psi, LDL indicates PC leak @ 12080'- 12150' > 07/18/10: Set TTP @ 12169', MIT-T Passed to 3000 psi, MIT-IA Passed to 3000 psi > 07/26/10: MIT-T Failed, CMIT-TxIA Failed LLR 1.6 gpm @ 3300 psi & 11.3 gpm @ 3430 psi Contact Jack Lau at 564-5102 (W), 227-2760 (C); or Jennifer McLeod 564-2764 (W) with any questions or comments. CC: Well File END1-15 Packer Repair Slickline 1. RIH and retrieve 4~/z" XXN plug from 12,200'. 2. Drift & Tag TD. 3. Set 4'/z" PXN plug in the XN nipple at 12,200'. The PXN plug will be easier to retrieve post cement squeeze. E-line 4. MIRU e-line. RU with GR/CCL and tubing punch. RIH, tie into tubing tally. Punch holes at 12,075' to establish communication path between tubing and IA. Log from just below packer up past tubing patch (11,847-11867) to establish accurate depths for later cementing work. Fullbore 5. Rig up pumping equipment to the tubing to load and circulate the following fluids into the well by pumping down the tubing and taking returns from the inner annulus to ensure the leak rate can be established and the wellbore is fluid packed with all the gas removed prior to the upcoming cement packer repair. Pump at max rate not exceeding 3000 psi. Do not attempt to load the inner annulus by pumping directly down the IA. It is critical that all gas is removed from both the tubing and IA prior to pumping cement. Jumper the IA to flow line to be able to take returns down the flowline. Freeze protect the flowline after fluid packing the wellbore. - 1100 bbls seawater/1 % KCI - 63 bbls diesel Page 3 of 7 ~D1-15 IA Cement Squeeze 6. After pumping 1100 bbls seawater/1 % KCI and 63 bbls diesel into the well, jumper the IA and tubing together to "u-tube" diesel into the IA and tubing to freeze protect well. Cementing Specifications: - 15.8 ppg Unislurry Cement - 2 - 3 hours thickening time - 4 - 5 hours to reach 500 psi compressive strength - 2,000 psi ultimate compressive strength - Bottom hole circulating temperature: 160 °F - Static bottom hole temperature: 200 °F - Perform a UCA test and a thickening time test on the field blend pnor to nggfng up. - Cement ramp attached. Coil Tubing -Packer Repair 7. RU the CTU with cementing equipment. MU and RIH with a ball drop cementing nozzle and tag PXN plug at 12,200' MD, taking pipe displacement returns out of the coil tubing-by-tubing annulus. Pickup until full string weight is observed. Pull up hole to 12,080' MD (tubing punches at 12,075') while laying in 4.6 bbls of calcium carbonate sluggits 1-for-1 in the 7" tubing, taking returns out of the coil tubing-by-tubing annulus. 8. Once 4.6 bbls of calcium carbonate sluggits have been placed in the wellbore, close in the coil tubing-by-tubing annulus and perform aCMIT-TxIA to 1500 psi to verify that the composite plug is holding prior to the cement packer repair. If the pressure test fails establish a liquid leak rate (LLR). Do not proceed with the repair until a passing CMIT-TxIA is achieved. 9. After a successful CMIT-TxIA, open up the coil tubing-by-tubing annulus and pump 150 bbls of 140°F KCI water down the coil tubing taking returns to surface to allow for wellbore cooling. 10. After pumping 150 bbls of 140°F KCI water down the coil tubing shut in the coil tubing-by-tubing annulus and open up the IA and pump 100 bbls of 140°F KCI water into the IA to cool wellbore and ensure infectivity through the packer can be established. 11. Pump 63 bbls of diesel down the IA. This will leave 26 bbls or 2250' of freeze protect in the well post cement squeeze and leave the well underbalanced on the IA by 100 psi. Page 4 of 7 ~D1-15 IA Cement Squeeze • 12.Open the coil tubing-by-tubing annulus to take returns to surface. Batch mix 4.5 pumpable barrels of 15.8 ppg unislurry cement which will have a thickening time of 2-3 hours, give 500 psi compressive strength in 4 - 5 hours, and 2,000 psi ultimate compressive strength. The bottom hole circulating temperature at cement depth should be 180 °F. - Ensure that there is no gas in the tubing or IA. Do not proceed with the repair unless the tubing and IA are fully liquid packed. - Take two sample bottles of the cement actually mixed onsite. Place these in a water bath at 180 °F. Monitor to see when they start to set up. Line out the cementers to the coil. Pump the following fluids down the coil (see steps 12 - 15 for complete pumping details): - 5 bbls spacer water ~; - 4.5 bbls Unislurry cement - Coil Tubing volume of water - 20 bbls of biozan ~~"~-~=-:~~..~_~~ ~..=-~ ~, 13. With the coil tubing-by-tubing annulus open and the IA closed, pump 5 bbls of spacer water out the coil while parked at 12,075', taking returns out the coil tubing-by-tubing annulus. 14. Begin pumping cement while continuing to take returns up the coil tubing-by- tubing annulus and maintaining 100-200 psi back pressure on the tubing. Pump 4.5 bbls of cement out the nozzle 0120' of cement above the nozzle assuming cement bottom will be at the top of the sluggits at 12,080') and lay in remaining cement while PUH (this will ensure that the cement is not diluted as the coil pulls up). Strap returns in the 40 bbl tank while pumping cement. Time nozzle to be at TOC just as the last of the cement is out the nozzle. SAFETY: If no cement is circulated up the IA, 8.0 bbls of cement will extend up the tubing to 11,960' MD (120' above the top of the sluggits at 12,080'). 15. Park well above the worst case cement top, shut-in the coil tubing-by-tubing annulus and open up the IA. Continue pumping water spacer until 4.5 bbls of cement have been circulated into the IA. Strap returns in the 40 bbl tank. Shut in the inner annulus. 16. Pump the remaining coil tubing volume of water followed by 20 bbls of biozan to contaminate remaining cement in the tubing. Pump biozan from 11,800' to 12,080', keeping coil tubing-by-tubing annulus and IA pressure constant. Only bleed fluid from the coil tubing-by-tubing annulus to achieve constant pressure. Page 5 of 7 ~D1-15 IA Cement Squeeze z Take coil tubing-by-tubing returns to a calibrated returns tank to confirm 1:1 returns. 17. Pump another 20 bbls of biozan while reciprocating across the patch at 11,847- 11,867'. Keeping coil tubing-by-tubing annulus and IA pressure constant. Only bleed fluid from the coil tubing-by-tubing annulus to achieve constant pressure. Take coil tubing-by-tubing returns to a calibrated returns tank to confirm 1:1 returns. 18. Begin POOH pumping 50/50 methanol/water to freeze protect coil and 1000' of tubing (37 bbls) also replacing coil tubing volume to maintain a balanced wellbore. It is critical that the coil tubing-by-tubing annulus and the IA remain at constant pressure at cement depth while POOH. Based on fluid hydrostatics in the wellbore once the coil is out of the well, 100 psi will need to be applied to the IA to keep the IA and tubing pressure constant at the cement plug to avoid cement "u-tubing". 19.Once at surface, block in everything and ensure that a ~ Iding and maintain a constant pressure on the tubing and IA. ~~w,, ~~`~- 20. Confirm that the cement samples are developing some compre strength. Do not disturb the well (i.e. do not apply pressure, bleed off pressure, etc. these samples have started to set up. 21. Make up BHA with jetting nozzle to clean out calcium carbonate sluggits. RIH to 11,800' and perform a "mini" MIT-IA to a DP of 500 psi (i.e. IA pressure + 500 psi) by pumping diesel down the IA. - Wait until the cement reaches 500 psi compressive strength - based on the sample taken during the cementing job. 22.If "mini" MIT-IA passes, clean out calcium carbonate from 12,080 to PXN plug at 12,200. Use caution by reducing to very low speed to avoid damaging the PXN equalizing prong. - If cement stringers are encountered POOH and PU DB underreamer, . - Note: Use vendor guidelines while underreaming. . 23.If "mini" MIT-IA does not pass - do not clean out calcium carbonate sluggits, contact either Jack Lau or Brad Gathman to discuss results prior to proceeding with milling. 24. Establish LLR from T~ IA and IA ~ T. 25. POOH. Ensure that tubing is freeze protected to 1000' with diesel or methanol. Page 6 of 7 ~D1-15 IA Cement Squeeze Y ~ - 26. RDMO. Fullbore -Post Packer Squeeze (Pending "mini" MIT-IA passing) 27. After 3 days WOC, MIT-IA to 3000 psi. If the MIT-A fails establish LLR. 1REE= MCEVflY ovELUiEAO= SIC ACTLJ4TUR= AXEL~}N KH. FiEV = 55.3" E3E. 6.EV - 18.12` KUP= Max An~~+ = 49` ~ 6850" UatumMC1= 12'~2a' Uaturtr 1V d = 1JOt10 SS 13-3i8" CSG, 88k, L-80 BU77, ~1= 12.d15' END 1-15 5~~"-~1ES: 1514' t' 01 IS S SSV LAN©M1G NIP, ID = 5.962" 19-si8'CSG.47k, N1805 XflNT95F$ Minimum ID = 3.725" @ 12200' 4-1I2" REDUCER NIPPLE 2 a ~ S ~ -f'/Oa p w.~ 'bbl ; _ 12152' r° ores •Fr N~. rc~ = 5.~i C er^~*~ IfiflP C7F 7' LtJt 7" 78G, 261s•, L-80 NSCC, .0383 bp1, A7 = 8275-. KB1+22 Atrf:!-fi7R IU = 6.fl0 MILLC1Lff EXt'EN51QN, ~_ X 7' XC3 HN, I[1= 6.27' x r° C5G, 4711, Nt 95HS NS{~, O = 8.681' PERi~?RAtICXd SUAR~4ARY AI~,LEA?TflPPERw:41` ~12a98 Pb4i: RflfEr to Produotxxa UB Iw Mrstorcai ~trr1 data SILE ~ INTERVAL flpn,+5dz p41'E 4" a 12458 - 12519 C 08~'05~'93 4" 4 12566 - 126"20 C 08~'O5~'93 4" 4 12554 - 12887 C t}&'05.93 a" a 12687 - 12687 C 06f05:'93 a° 4 12702 -12706 C 0605+93 4' 4 12718 - 12730 L 06m5193 4' 4 127x2 - 12756 C 0&'05P93 4' a 12770 - 12809 C O6f05+'93 Izy9P~ 7" LP Page 7 of 7 Page 1 of 2 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, September 01, 2010 2:52 PM To: 'Lau, John, Jack' Cc: Maunder, Thomas E (DOA) Subject: RE: Non-rig cement packer 1-15/P-25 (PTD 193-056) Jack, Yes... please send a revised copy. I also did not see a tubing pressure test in the procedure after the FCO of the carbolite (and leaving the PXN plug in place). Could add that in step 27.... Before you guys pull the PXN plug. Thanks, Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Lau, John, Jack [mailto:Jack.Lau@bp.com] Sent: Wednesday, September O1, 2010 2:39 PM To: Schwartz, Guy L (DOA) Cc: AK, D&C Well Integrity Coordinator; Gathman, Brad; McLeod, Jennifer D; Lau, John, Jack Subject: RE: Non-rig cement packer 1-15/P-25 (PTD 193-056) Guy - Thanks for taking a look at this well. The tubing punch depths were originally planned at a shallower depth to ensure coil tubing would be capable of washing out carbolite without damaging the isolating PXN plug. Seeing your concern with this well and to further mitigate potential of gas flow into the IA, we will revise the program to place the cement plug from 12,155' to 11,900'. We will also plan on running a CBL with the aforementioned revision. Would you like a copy of the revised procedure once completed? I will communicate the potential for changes to the current MIT criteria for END1-15 to the Well Integrity Coordinators. Thanks, Jack From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Wednesday, September 01, 2010 2:12 PM To: Gathman, Brad; Lau, John, Jack Cc: Maunder, Thomas E (DOA) Subject: Non-rig cement packer 1-15/P-25 (PTD 193-056) Jack, I talked briefly with Brad about this well. As this is a gas injector I have some concerns with the cement placement 9/8/2010 • Page 2 of 2 in the annulus and want to verify where it ends up after the job is completed. A cement bond log is going to have to be run to verify placement ... whether or not it passes the tubing and IA pressure tests. I was also curious about where the tubing perfs are being located. Why not a little deeper (or just above the packer) so you can circulate past the suspected leaks in the casing . ?? There is the possibly of the IA pressure testing but the tubing failing to the casing leak at some point in the future and not knowing that it had. There may be a change in the MIT criteria for this well after the wellwork is completed (i.e. test both the IA and the tubing on a shortened cycle 2 yr cycle). Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) 9/8/2010 ~J 0 ~ ~ ~ SEAN PARNELL, GOVERNOR AL.ASSA OIL AIQD rirA-S 333 W. 7th AVENUE, SUITE 100 COI~TSI'.RQA7`IOl1T COMMISSIOI~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 CANCELLATION ADMINISTRATIVE APPROVAL AIO 1.008 Steve Rossberg Wells Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 ~` `~ °~(i ~ s ~. , ~ ,- ,u: RE: Cancellation of Administrative Approval AIO 1.008 DIU 1-15/P-25 (PTD 193-056) Endicott Oil Pool Dear Mr. Rossberg: Pursuant to BP Exploration (Alaska) Inc. (BPXA)'s request dated August 11, 2010 the Alaska Oil and Gas Conservation Commission (AOGCC) hereby cancels Administrative Approval AIO 1.008, which allows continued gas injection in Duck Island Unit (DIU) well 1-15/P-25. This well exhibited slow tubing x inner annulus (TxIA) communication and BPXA did not at the time propose repairing the well to eliminate the problem. The Commission determined that gas injection could safely continue in the well, but subject to a number of restrictive conditions set out in the administrative approval. The well recently failed a MITIA. BPXA has determined to shut-in the well and evaluate further repair options. Consequently, Administrative Approval AIO 1.008 no longer applies to operation of this well. Instead, DIU 1-15/P-25 will be governed by provision of the underlying AIO No. 1. DONE at Anchorage, Alaska and dated Daniel T. Seamount, Jr. Commissioner, Chair cc: Torin Roschinger/Gerald Murphy BPXA Well Integrity Coordinator, P.O. Box 196612 Anchorage, AK 99519-6612 AIO 1.008 cancel • • September 2, 2010 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(6), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB-20 Post Office Box 196612 Anchorage, Alaska 99519-6612 August 11, 2010 ~ ~ ~ ~.; ZOla `; ~ F` ~ ~ ~~ ~~ "~ ~2~a r~ ~~ dri~~i~u ~a,L 1~ ~ L~>i 'S„ A J K ~, ~,4 Mr. Daniel Seamount, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Endicott 1-15 / P-25 (PTD#1930560) Application for Cancellation of Administrative Approval 1.008 Dear Mr. Seamount, by BP Exploration (Alaska) Inc. requests cancellation of Administrative Approval number 1.008 dated September 19, 2008. The administrative approval was for continued gas injection into Well END1-15 with slow TxIA communication. This well failed an MITIA for Administrative Approval compliance on June 17, 2010. The well is secured with a downhole mechanical plug and will remain shut-in until repairs can be completed. Therefore it is requested to cancel the Administrative Approval for continued operations. A plot of wellhead pressures has been included for reference. If you require any additional information, please contact me at 564-5637 or Torin Roschinger /Gerald Murphy at 659-5102. Sincerely, R. Steven Rossberg Well Operations Manager, BPXA • i Attachments: TIO Plot Cc: Bixby/Liddelow Murphy/Roschinger Endicott Onshore Site Manager Alecia Wood Harry Engel ~J f Endicott 1-15 / P-25 (PTD#30560) TIO Plot • Well. 1-15 5 000 5,rA~] d OC0 3.690 2,000 10~ ~ Tbq t IA ~ OA OOA OOOA - Or. o7/z7no • Schlumh~rger Alaska Data & Consulting Services 2525 Gambell Street, Suae 400 Anchorage, AK 99503-2839 ATTN: Beth Well Job # N0.5567 Company: State o} Alaska Alaska Oi19 Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 1D0 Anchorage, AK 99501 Log Description Date BL Color CD P2-16 6B6M-00027. LDL - ! 07/2D/10 1 1 F-03A V 225 AVKP-00096 SCMT _. ~ ! - 07/22/10 1 1 - 5-100 2-58/S-09 1-15/P-25 W-19A 01-228 BBKA-00039 BC22-00014 BC22-00016 AYKP-00084 BCRD-00036 AZ2F-00042 USR _ USIT LDL LDL ~ USIT ~ MCNL _ 07/01/10 07/14/10 07/17/10 07/11/10 07/25/10 05/19/10 1 1 1 1 1 1 1 i 1 1 1 1 8-20 04-20 B-/8 AV1M-00042 BCRJ-00020 AVKP-00002 RST - RST RST 05/07/10 05/30/10 06/02/10 1 / 1 1 1 1 05-32A H-25 P2-34 B8K5-00040 BCRD-00017 AVYO-00063 RST RST RST -. 05/19/10 05/10!10 04/17/10 1 1 1 1 1 1 PLEASE ACKNOWLEDGE HFC FlD7 wv srnuw r wun oen rouwn nue nn,,.. ~..... ~... BP Exploration (Alaska)Inc. Petrotechnical Data Center LR2-1 900 E. Renson Blvd. Alaska Data 8 Consulting Services 2525 Gambell Street, Sutle 400 Anchorage, AK 99503-2838 ,~~~_. ti ~~ifi w. €~ , _. e~ttl~ht . ; ~°ti %(~ NOT OPERABLE: Injector END1-15 (PTD# 1930560) Failed AOGCC MITIA Page 1 of 1 Maunder, Thomas E (DOA) From: AK, D&C Well Integrity Coordinator [AKDCWeIIlntegrityCoordinator@bp.com] Sent: Friday, June 18, 2010 1:04 PM To: Maunder, Thomas E (DOA); AK, D&C Wireline Operations Team Lead; AK, D&C Welf Services Operations Team Lead; Regg, James B (DOA); Brooks, Phoebe L (DOA); Schwartz, Guy L (DOA); AK, OPS END AES Drillsite Lead; AK, OPS END Facility & FieldO&M TL; AK, OPS END Operations Lead Tech; AK, RES END Production Optimization Engineer; Cismoski, Doug A; Engel, Harry R Cc: AK, D&C Well Integrity Coordinator; Clingingsmith, Mike J (Ct12Nf Hill); McLeod, Jennifer D; Garing, John D Subject: NOT OPERABLE: Injector END1-15 (PTD# 1930560) Failed AOGCC MITIA Attachments: END1-15 TIO Plot 06-18-10.doc; 1-15.pdf; END1-15 AA A101-008 09-19-08.pdf; MIT ACT END1-15(P-25) 06-17-10.x1s . ~1Q~ All, ~~~~~~ Gas Injector END1-15 (PTD# 1930560) failed a state witnessed MITIA on 06/17/10. The failing test indicates that either the tubing or production casing has lost integrity. After liquid leak rates are established the plan forward is to run an LDL. The well has been secured with a TTP and will be reclassified as Not Operable until repaired. A TIO plot, wellbore schematic, Administrative Approval for TxIA comm and MIT form have been included for your reference. «END1-15 TIO Plot 06-18-10.doc» «1-15.pdf» «END1-15 AA A101-008 09-19-08.pdf» «MIT ACT END1-15(P-25) 06-17-10.x1s» Please call with any questions. Thank you, Torin Roschinger (alt. Jerry Murphy) Well Integrity Coordinator Office (907) 659-5102 Harmony Radio x2376 Cell (406) 570-9630 Pager (907) 659-5100 Ext. 1154 8/7/2010 • • wa >I-ls 4.000 3,000 z,ooa 1000 -a- ic9 t ~ -~- on Don Doan on 03/20/10 03/27/10 04/03/10 04/10!10 04/17!70 04/24/10 05/01/10 0570B/10 05/15/10 0522/10 05/29710 06/05/10 06/12/10 i • o SARAN PALlN, GOVERNOR OI~ ~ G~ 333 W. 7tiiAVENUE, SUITE 40d COI~SERYAZ'IO11T CODLdIISSIOIQ ANCHORAGE, ALASKA 99501-3539 PHONE (907j 279-4433 FAX (907j 276-7542 ADMINISTRATIVE APPROVAL .AIO~ 1.Q08 Mr. Steve Rossberg Wells Manager BP Exploration (Alaska) Inc. ~~~. ~ i~~~ , ~ ~ + ~, cl ~~ ~~~ P.O. Box 19bb l 2 ~~ ~ Anchorage, AK 99519-bb 12 RE: Duck Island Unit 1-15lP25 (PTD 1930560) Req~-est for Administrative Approval Endicott Oil Pool Dear Mr. Rossberg: Pursuant to Rule 9 of Area Injection Order (AIO} 01.000, the Alaska Oit and Gas Conservation Commission (AOGCC or Commission) hereby grants BP Exploration (Alaska) Inc. (BPXA)'s request for administrative approval to continue gas injection in the subject well. The Commission previously granted BPXA's request for administrative approval - AIO 1.006 - allowing the continued gas injection in Duck Island Unit (DILI) 1-15/P25. The well exhibited inner annulus (IA) repressurization that was manageable with periodic pressure bleeds. AIO 1.006 was canceled on March 18, 2008 following a failed mechanical integrity test, and BPXA advised the well would remain shut in for a rig workover. BPXA indicates it does not have specific plans for repairs at this time, but is evaluating DIU 1-15/I'25 as a potential sidetrack candidate far rig work scheduled at Endicott during spring 2009. The Commission finds that BPXA successfully completed three mechanical integrity tests (MITs) in the tubing-casing annulus of DIU 1-1S/P25 on June 4, 2008. Test pressures ranging up to 5,630 psi in these passing MITs demonstrate competent primary and secondary barriers to the release of wellbore fluids. The Commission further finds that outer annulus pressures do not indicate anomalous conditions or loss of pressure integrity. The Commission believes that the well's condition does not compromise overall well integrity so as to threaten the environment or human safety, if the well's operation is subject to the constraints enumerated below. AOGCC's administrative approval to continue gas injection in DIU 1-15/P25 is conditioned upon the following: 1. BPXA shall ~•ecord wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures and injection rates, and shall flag the well's periodic pressure bleeds on the report; 3. BPXA shalt perform an MIT-IA every 2 years to the maximum anticipated injection pressure; AIO I.00$ September 19, 2008 Page 2 of 2 4, BPXA shall maintain and operate existing automatic well shut-in equipment linked to the well's IA pressure. The actuation pressure shall not exceed 2,500 psi. Testing of the shut-in equipment shall be performed in conjunction with production well pilots and safety valves; 5. BPXA shall limit the IA pressures to 2,500 psi; 6. BPXA shall immediately notify the A4GCC and shut in the well if there is any continued deterioration in well integrity, indicated by increased inner or outer annulus pressure, in- creased repressure rate, or increased bleed frequency; 7. Ater well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The MIT anniversary date is June 4, 2008. DANE at Anchorage, Alaska and dated September 19, 2008. p' Daniel T. Seamaunt, Jr. Cathy . Foerster Chair Com issioner cc: BPXA Well Integrity Coordinator, P1Z.B-20 P.O. Box 196612 Anchorage, AK 99519-6612 RECONSIDERATION AND As provided in AS 31.05.080(a), within 20 days after written notice of the entry of This order or decision, or such further time as the Commission grants for good cause shown, a person affected by ii may file with the Commission an application for reconsideration of the matter determined by it. tf the notice was mailed, then the period of time shall be 23 days- An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant ar refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the dea»al of re- consideration are F[NAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Com- mission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideratiar, UNLESS the denial is by in- action, in which case the appeal M11UST be filed within 40 days after the date on which the application for r~ottsideration Ives filed. If the Commission grants an application Por reconsideration, this order or decision does not become final. Rather, the order or decision on re- consideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date an which the Commission mails, OR 34 days if the Commission otherwise distributes, the order or decision on re- consideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the tutor or default after which the designated period begins to run is oat included in the pe- riod; the test day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • MEMORANDUM To: Jim Regg P.I. Supervisor ( ~ ~( 6(2~~ j0 FROM: Chuck Scheve Petroleum Inspector State of Alaska • Alaska Oil and Gas Conservation Commission DATE: Friday, June 18, 2010 SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC 1-15/P25 DUCK IS iINIT MPI 1-15/P25 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv J P Comm Well Name: DUCK IS UNIT MPI 1-t5/P25 API Well Number: 50-029-22361-00-00 Inspector Name: Chuck Scheve Insp Num: mitCS100618083249 Permit Number: 193-056-0 Inspection Date: 6/17/2010 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 1~IS/P25 'I'ypC In]. N ~ TVD 9481 ~ IA 350 5660 3060 ' ~ j P.T.D 1930560 TypeTCSt 1 SPT 'l'est pSl 2370 OA 60 70 70 Interval REQvAR p/F F "~'ubing 480 3060 2640 Notes: A plug had been set in tubing tail and the tubing pressured up to 3000 psi. The IA was then pressured to 5660 psi declining to 3060 in 15 min. Attempt to repressure IA failed with an injection rate of 1 bbl per min at 3300 psi with no pressure response on the tubing or OA. f1oG~cc nv~-,~~ h~ e 6f 1°~~+~~ wt~,l ~~ ~CG.a~i~ u)~ -r-r~ Friday, June 18, 2010 Page 1 of 1 ~RA~~f1AL ~I~ P~A~ o~l~,~ s~~, INC. U To: AOGCC Christine Mahnken 333 W. 7th Ave Suite 100 Anchorage, Alaska 99501 (907J 793-1225 RE : Cased Hole/Open Hole/Mechanical Logs and /or Tubing fnspection(Caliper/ MTTj The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the following BP Exploration (Alaska), Inc. Petrotechnicai Data Center Attn: Joe Lastufka LR2-1 900 Benson Bhrd. Anchorage, Alaska 99508 and ProActive Diagnostic Services, Inc. Attn: Robert A. Richey ~~ ~ (g 3 - ~S~ 130 West International Airport Road ~-_~ Suite C ~ ~ ~ Anchorage, AK 99518 Fax: (907) 245.8952 1 ] Temperature Survey 23-Jan-10 1-15 / P-25 BL / EDE 50-029-22361-00 2) ~ ~~ Signed Print Name: Date PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (9071245-8951 Fax: (807)245-88952 E-MAIL : wEBSITE :: ': Q1Dociunents and SettingsVDiane Williams~DesktoplTransmit._BP.docx UNDER EVALUATION -Endicott 1-15/P-25 (PTD 1930560) Put on Injection to evaluat... Page 1 of,7l~ • • Regg, James B (DOA) From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com] Sent: Saturday, July 19, 2008 10:34 AM ~~ To: Regg, James B (DOA); Maunder, Thomas E (DOA); END/BAD.Area Manager; END, O&M TL; END, Operations Lead Tech; END, Wellhead Tech; NSU, ADW Well Operations Supervisor; Engel, Harry R; Rossberg, R Steven Cc: Lau, John, Jack; Soto, Jose A; Caring, John D; Rockafellow, Joseph D; Hernandez, Rogelio (ASRC ENERGY SERVICES); Houser, John (ASRC); Whitney, William A; NSU, ADW Well Integrity Engineer; Winslow, Jack L. Subject: UNDER EVALUATION -Endicott 1-15/P-25 (PTD 1930560) Put on Injection to evaluate rate of IA repressurization for AOGCC AA All, The block valve with the actuator in need of replacing is now open. The well can now be put on injection in order to obtain an MITIA. The welt has been reclassified as Under Evaluation and the 28-day clock wilt start once the wets is on injection. The plan forward the well is as follows: 1. Slickline: Pull TTP to unsecure well -DONE 2. Endicott Operations: Place well on injection for 7 days. Notify WIE when on injection. Please attempt to keep injection rates as stable as possible so that accurate IA repressurization informa#ion may be obtained. DHD: Monitor WHPs for 7 days while online / Fulibore: MITIA with well online to confirm MITIA results 4. Well Integrity Engineer: Evaluate IA repressurization rate and review far AA request Please call with any questions or concerns. Thank you, Andrea Hughes Well Integrity Coordinator Office: (907) 659-5102 Pager: (907) 659-5100 x1154 ~~~;~~~~~ SSA ~ t~ x008 From: NSU, ADW Well Integrity Engineer Sent: Wednesday, June 25, 2008 1:10 PM To: 'jim.regg@alaska.gov'; 'tom.maunder@alaska.gov'; END/BAD Area Manager; END, O&M TL; END, Operations Lead Tech; END, Wellhead Tech; NSU, ADW Well Operations Supervisor; Engel, Harry R Cc: Roschinger, Torin T.; Holt, Ryan P (ASRC); Lau, John, lack; Soto, Jose A; Caring, John D; Rockafellow, Joseph D; Hernandez, Rogelio (ASRC ENERGY SERVICES); Houser, John (ASRC); Whitney, William A; NSU, ADW Well Integrity Engineer Subject: NOT OPERABLE -Endicott 1-15/P-25 (PTD 1930560) Needs actuator replaced All, We have received word that the actuator needs to be replaced on END1-15 prior to placing the well on injection. 8/29/2008 UNDER EVALUATION -Endicott 1-15/P-25 (PTD 1930560) Put on Injection to evaluat... Page 2 o~i3'~ • • It is estimated to take up to 1 month to perform the repair. Therefore, the well has been reclassified as Not Operable and removed from the 28-day clock until the repair has been made. At that time, the welt will be reclassified to put the well on injection and evaluate for possible IA repressurization. Please call with any questions or concerns. Thank you, Andrea Hughes From: NSU, ADW Well Integrity Engineer Sent: Sunday, June 15, 2008 12:37 PM To: 'jim.regg@alaska.gov'; 'tom.maunder@alaska.gov'; END/BAD Area Manager; END, O&M TL; END, Operations Lead Tech; END, Wellhead Tech; NSU, ADW Well Operations Supervisor; Engel, Harry R Cc: Wellman, Taylor T; NSU, ADW Well Integrity Engineer; Holt, Ryan P (ASRC); Lau, John, Jack; Soto, Jose A; Garing, John D; Rockafellow, Joseph D; Hernandez, Rogelio (ASRC ENERGY SERVICES); Houser, John (ASRC); Whitney, William A Subject: UNDER EVALUATION -Endicott 1-15/P-25 (PTD 1930560) Put on Injection to evaluate rate of IA repressurization for AOGCC AA Hi all, Endicott well 1-15/P-25 (PTD 1930560) has a tubing patch and was operating under AOGCC Administrative Approval for slow IA repressurization. On 02/15/08, a MITIA was attempted to revise the AA and it failed. The AA was cancelled due to the failing MITIA. Eline was then sent to conduct a leak detect log but while attempting to re-establish the liquid leak rate, a MITIA passed to 5650 psi on 06/04/08. Approval has been obtained from the AOGCC to put the well on injection, monitor the IA pressure build up, and repeat a MITIA with the well online. The Well Integrity Engineer will then evaluate the rate of repressurization and review the well for an AA request. The well has been reclassified as Under Evaluation and has been added to the AOGCC Monthly Injection Report. The plan forward includes: 1. Slickline: Pull TTP to unsecure well 2. Endicott Operations: Place well on injection for 7 days. Notify WIE when on injection. Please attempt to keep injection rates as stable as possible so that accurate IA repressurization information may be obtained. 3. DHD: Monitor WHPs for 7 days while online 3. Fullbore: MITIA with well online to confirm MITIA results 4. Well Integrity Engineer: Evaluate IA repressurization rate and review for AA request A wellbore schematic and TIO plot have been included for reference. Please call with any questions. Thank you, Anna ~u6e, P E. Well Integrity Coort#inator GPB Wells Group Phone: {907) 859-5102 Pager: {90?) 859-51 QO x1154 8/29/2008 DIU 1-15 PTD 193-056 4,000 - 3,000 2,000 1 ,000 0 12M Sr1007 1-15 TIC Plot f Tbg -F IA -~- OA -~ OOA I i i -F OOOA i i j _f L r: 1 M 412008 2M 4!2008 3M 5!2008 4M Sf200S SM SC2008 6M Sf200$ TREE= MCEVOY WELLHEAD= FMC ACTUATOR= AXELSON KB. ELEV - 55.3' BF. ELEV = 16.12' KOP= Max Angle = ~~ ~ 49° @ 6850' ~.._..,n Datum MD - 12924' Datum TV D = 10000 SS 13-318" CSG, 68#, L-80 BUTT, ID = 12.415" ~ 9-5/8" CSG, 47#, NT80S XO NT95HS ~ - w ~ S NOTES: ~~ 1514' -~ 7" OTIS SSSV LANDING NIP, ID = 5.962" Minimum ID = 3.725" @ 12200' 7" X 4-1l2" REDUCER NIPPLE TOP OF 7" LNR 12205' 7" TBG, 26#, L-80 NSCC, .0383 bpf, ID = 6.276" 12208` 9-5/8°' CSG, 47#, NT-95HS NSCC, ID = 8.681" f-~ 12494• PERFORATION SUMMARY ANGLE AT TOPPERF:4i° @ 12498' Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 4" 4 12498 - 12519 O 08!05!93 4" 4 12566 - 12620 O 08/05/93 4" 4 12650 - 12687 O 08/05/93 4" 4 12667 - 126$7 O 06/05/93 4" 4 12702 -12706 O 06/05193 4" 4 12718 - 12730 O 06!05/93 4" 4 12742 - 12756 O 06/45/93 4" 4 12770 - 12809 O 06/05/93 7" LNR; 29# NT80 NSCC, .0371 bpf, ID = 6.276" 12972' 11847' -11867' {-~ 5.93" WRD PATCH, ID = 4.0" (05131104) 12152' ~- ~ 7" OTIS "R" NIP, ID = 5.962" 12173' 9-5l8" X 7" BKR S-3 PKR w / 8" KBH-22 ANCHOR: ID = 6.00 12179' 7-5l8" MILLOUT EXTENSION, ID = 6.62" 12184' 7-5/8" X 7" XO PIN, ID = 6.27" 122Q0' - ~-OTIS "R" NIP, ID = 5.962" 12200' 7" X 4-1t2" NIP REDUCER, ID = 3.725" {01105/02) 12205' 6" TNV TIEBACK wlRPOB, CD = ? 12208' - 7" WLEG, ID = 6.27" 12213' 9-518" X 7" TIW LTP w (LNR HGR, ID = ? 12592' PBTD 12905' ELMD PBTD DATE REV BY COMMENTS DATE REV BY COMMENTS 05115/93 E315 INITIAL COI+APLETION 08/06!93 JLH PERF8 & ADPERFS 01 /05!02 MS SET NIP REDUCER 05/31/04 WRR SET TBG PATCH - 02/23t08 DAV/PJC MIN ID CORRECTION NIP RED 04f13f0$ JASIPJC CONVERTTO NEW FORMAT ENDICOTT UNff WELL: 1-15tP-25 PERMIT Na: 1930560 API No: 05-029-22361-01 SEC 36, T12N, R16E, 1987' FNL & 2065' FEL BP Exploration {Alaska) • 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 OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: SP Exploration (Alaska), Inc. Endicott /ACT / END1 06/04/08 Anna Dube Packer De h Pretest Initial 15 Min. 30 Min. WeII 1-15/P-25 T pe Inj. N TVD ~ 9,481' Tubing 3000 2990 2970 2890 Interval O P.T.D. 1930560 Type test P Test psi 2370 Casing 3000 ,;,4600 4560 4540 P/F P Notes: MIT-IA for integrity verification / AA request. OA 80 80 80 80 Well 1-15/P-25 Type Inj. N ND 9,481' Tubing 2890 2940 2900 2860 Interval O P.T.D. 1930560 Type test P Test psi 2370 Casing 4540 5100 5070 5060 P/F P Notes: MIT-IA for integrity verification / AA request. OA 80 80 80 80 Well 1-15/P-25 Type In'. N TVD 9,481' Tubing 2860 2900 2880 2840 Interval O P.T.D. 1930560 Type test P Test psi 2370 Casing 5060 5630 5600 5590 P/F P Notes: MIT-IA for integrity verification / AA request. OA 80 80 80 80 Well T pe Inj. ND Tubing Interval P.T.D. T pe test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D =Drilling Waste M =Annulus Monitoring I =Initial Test G =Gas P =Standard Pressure Test 4 =Four Year Cycle 1=Industrial Wastewater R = Internal Radioactive Tracer Survey V =Required by Variance N =Not Injecting A =Temperature Anomaly Survey T =Test during Workover W =Water D =Differential Temperature Test O =Other (describe in notes) ~~N~~ .iUL ~ ~.~ 2Q08 MIT Report Form BFL 9/1/05 2008-0604_MIT_DIU_1-15_(3tests).xls NOT OPERABLE -Endicott 1-15/P-25 (PTD 1930560) Needs actuator replaced Page 1 of 2 • Maunder, Thomas E (DOA) From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com] Sent: Wednesday, June 25, 2008 1:10 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA); END/BAD Area Manager; END, O&M TL; END, Operations Lead Tech; END, Wellhead Tech; NSU, ADW Well Operations Supervisor; Engel, Harry R Cc: Roschinger, Torin T.; Holt, Ryan P (ASRC); Lau, John, Jack; Soto, Jose A; Garing, John D; Rockafellow, Joseph D; Hernandez, Rogelio (ASRC ENERGY SERVICES); Houser, John (ASRC); Whitney, William A; NSU, ADW Well Integrity Engineer Subject: NOT OPERABLE -Endicott 1-15/P-25 (PTD 1930560) Needs actuator replaced All, We have received word that the actuator needs to be replaced on END1-15 prior to placing the welt on injection. It is estimated to take up to 1 month to perform the repair. Therefore, the well has been reclassified as Not Operable and removed from the 28-day clock until the repair has been made. At that time, the well will be reclassified to put the well on injection and evaluate for possible IA repressurization. Please call with any questions or concerns. Thank you, Andrea Hughes ~1E~ JUG ~ ~ 2008 From: NSU, ADW Well Integrity Engineer Sent: Sunday, June 15, 2008 12:37 PM To: 'jim.regg@alaska.gov'; 'tom.maunder@alaska.gov; END/BAD Area Manager; END, 0&M TL; END, Operations Lead Tech; END, Wellhead Tech; NSU, ADW Well Operations Supervisor; Engel, Harry R Cc: Wellman, Taylor T; NSU, ADW Well Integrity Engineer; Holt, Ryan P (ASRC); Lau, John, Jack; Soto, Jose A; Garing, John D; Rockafellow, Joseph D; Hernandez, Rogelio (ASRC ENERGY SERVICES); Houser, John (ASRC); Whitney, William A Subject: UNDER EVALUATION -Endicott 1-15JP-25 (PTD 1930560) Put on Injection to evaluate rate of IA repressurization for AOGCC AA Hi all, Endicott well 1-15/P-25 (PTD 1930560) has a tubing patch and was operating under AOGCC Administrative Approval for slow IA repressurization. On 02/15/08, a MITIA was attempted to revise the AA and it failed. The AA was cancelled due to the failing MITIA. Eline was then sent to conduct a leak detect log but while attempting to re-establish the liquid leak rate, a MITIA passed to 5650 psi on 06/04/08. Approval has been obtained from the AOGCC to put the well on injection, monitor the IA pressure build up, and repeat a MITIA with the well online. The Well Integrity Engineer will then evaluate the rate of repressurization and review the well for an AA request. The well has been reclassified as Under Evaluation and has been added to the AOGCC Monthly Injection Report. The plan forward includes: 1. Slickline: Pull TTP to unsecure well 2. Endicott Operations: Place well on injection for 7 days. Notify WIE when on injection. Please attempt to keep injection rates as stable as possible so that accurate IA repressurization information may be obtained. 6/25/2008 NOT OPERABLE -Endicott 1-15/P-25 (PTD 1930560) Needs actuator replaced Page 2 of 2 • • 3. DHD: Monitor WHPs for 7 days while online 3. Fullbore: MITIA with well online to confirm MITIA results 4. Well Integrity Engineer: Evaluate IA repressurization rate and review for AA request A wellbore schematic and TIO plot have been included for reference. Please call with any questions. Thank you, Anna 1~u6e, ~I'. E. Well Integrity Coordinator GPB Wells Group Phone: (907) 659-5102 Pager: (907) 659-5100 x1154 6/25/2008 ~ a _ ~~ ~ ~z _.,_ w ____ ProActive Diagnostic Services, Inc. To: AOGCC Christine Mahnken 333 W. 7th Ave Suite 100 Anchorage, Alaska 99501 (907) 793-1225 RE : Cased Hole/Open Hole/Mechanical Logs and /or Tubing Inspection(Caliper / MTT] The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the following BP Exploration (Alaska), Inc. Petrotechnical Data Center Attn: Joe Lastuflca LR2-1 900 E. Benson Bh-d. Anchorage, Alaska 99508 and ProActive Diagnostic Services, Inc. Attn: Robert A. Richey 130 West International Airport Road Suite C Anchorage, AK 99518 U~ ~ ~~3 ~~ ~ ~ ~~v~~ Fax: [907) 245-8952 1 ] Leak Detection - WLD 06-Apr-08 1-15 / R25 2] l/ Signed Print Name: 1 EDE 50-029-22361.00 Date : - _ _ .. PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245-88952 E-MAIL: L3^.~'5~5~!~~iT`~3~1'+~65- i~~l'?>,~~.~~ WEBSITE 'A+N~°5,~~~'.3~Y''./7~C.~i. C:1Documents and SettingslOwneflDesktoplTransmit_BP.doc MEMORANDUM To: Jim Regg P.I. Supervisor ~~ 2'Z~h~ FROM: John Crisp Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, February 25, 2008 SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) IiVC I -t S~P25 DUCK [S UNIT MPI 1-i5/P25 Src: Inspector NON-CONFIDENTIAL Reviewed By: r~ P.I. Suprv ~ ~~- Comm Well Name• DUCK IS UNIT MPI 1-i5~P25 API Well Number: 50-029-22361-00-00 Inspector Name: John Crisp Insp Num: mitJCr0802211d1907 Permit Number: 193-056-0 Inspection Date• 2.!15/2008 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 1-I X25 ;Type Inj. ! N ~I TVD 94x1 ~ IA ~- zao ~ sloo 460o asoo I P T 1930560 TypeTest ~ SPT ; Test psi z3~o.z~ f pA t3o j I4o I too I4o i __ Interval OTHER p~F F Tllbing 800 ~ 3030 3300 ~, 3400 ~, i Notes• The Operators report stated that this MIT-[A was for AA compliance and adherence to a potential change in well integrity policy. Volume to pack tbg. & pressure to 3000 psi was 23 bbl's. The Operator Rep has not gotten back to me with volume that was pumped to attempt test on IA. Talked with WIE PBU Anna Dube & made Her aware that Jim Regg would have to be notified if BP wanted to pull TTP & inject into this well for any reason including diagnostics. ~~~~ FEB 2 9 2Q08 Monday, February 25, 2008 Page 1 of 1 Recent MITIA for Endicott 1-15/P~ (PTD #1930560) Page 1 of 1 • Regg, James B (DOA) From: NSU, ADW Well Integrity Engineer [NSUADWWeIIlntegrityEngineer@BP.com] 1 ~~~ Sent: Sunday, February 17, 2008 8:39 PM ~~( To: Regg, James B (DOA); Maunder, Thomas E (DOA); Fleckenstein, Robert J (DOA) Cc: NSU, ADW Well Integrity Engineer; NSU, ADW WI Tech Subject: Recent MITIA for Endicott 1-15/P25 (PTD #1930560) Attachments: MIT END 1-15(P-25) 02-17-08.x1s Hi Jim, Tom, and Bob, Please find the attached MIT forms for Endicott well 1-15/P25 (PTD #1930560). The well failed AA compliance testing. A ~ request to cancel the AA will be sent to the AOGCC. «MIT END 1-15(P-25) 02-17-08.x1s» u~ FED ~ ~(~(~~. Zi22i2oos • 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 OPERATOR: BP Exploration (Alaska), Inc. ~ '7~ FIELD /UNIT /PAD: Endicott /ACT / END1 \\~~ ~~~ 1~ DATE: 02!15/08 OPERATOR REP: Anna Dube AOGCC REP: John Crisp Packer De h Pretest Initial 15 Min. 30 Min. Well 1-15/P-25 ype Inj. N ND 9,481' Tubing 800 3030 3500 3440 Interval O P.T.D. 1930560 ~ Type test P Test psi 2370 Casing 280 5100 4600 4440 P!F F Notes: MIT-IA for AA 1.006 compliance OA 130 140 140 140 and to align testing to other AA's for similar repressurization. First test failed. Well 1-15/P-25 Type Inj. N ND 9,481' Tubing 3440 3800 Interval O P.T.D. 1930560 Type test P Test psi 2370 Casing 4440 5200 P!F F Notes: Second attempt failed due to OA 140 140 swab stem packing leak. Aborted test and bled pressure. Well Type Inj. ND Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. ND Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. ND Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA l~ TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D =Drilling Waste M =Annulus Monitoring I =Initial Test G =Gas P =Standard Pressure Test 4 =Four Year Cycle I =Industrial Wastewater R =Internal Radioactive Tracer Survey V =Required by Variance N =Not Injecting A =Temperature Anomaly Survey T =Test during Workover W =Water D =Differential Temperature Test O =Other (describe in notes) ~ ~wC~~s 6 ~- 5 ~ ~s.i 4_ ,._ ~~1 ~ ~~~- lt~ ~J i s MIT Report Form BFL 9/1105 MIT END 1-15(P-25) 02-17-OS.xls Re: Endicott 1-15 Administrative Approval daWeb 28, 2006 ''t; -~S~,.,. e SUbject:Re:En~icott l-1~Administrative~pprövalciated Feb28, 2006 Frol11: Winton Aub~lt~""i"ton_aut>er1@admin.state.ak.us> Date: Fri, Q3 Mar 2006 07:56:54...0900 To: "Engel, Harry R" <Harry.Engel@bp.com> CC: Catherine P Foerster <cathy_foerster@admin.state.ak.us> Harry , AOGCC acknowledges the mechanical condition of End 1-15's OA. Accordingly, the Commission hereby withdraws Condition 4 of Administrative Approval AIO 1.006. An MIT - OA every two years is not required for End 1-15. All other AIO 1.006 conditions of approval are unchanged. Thank you for calling our attention to this matter. Winton Aubert AOGCC 793-1231 Engel, Harry R wrote: Winton- This is a follow-up to our telephone conversation earlier today regarding the subject Administrative Approval. Condition of approval number 4 requires an MIT-OA every 2 years. Considering the mechanical condition of Endicott 1-15, an MIT-OA is not necessary to ensure the integrity of the well. BP requests that this requirement be removed from the Administrative Approval. Future requests for Administrative Approval will include historical MIT information. Please give me a call if you have any questions. Harold R. Engel (Harry) GPB Staff Engineer 907-564-4194 office 907-564-5510 fax 1 of 1 3/3/20068:00 AM • • _ __ _ _y __ __ _ _~ __, __, _; J ~ v, ~. _ _ - J FRANK H. MURKOWSKI, GOVERNOR ~~~~ ~~~~++ ~t~ ~t~~~ r' 1aT~+~{ ~7~-7RA ®~7~~~`L~+v~~-a7T i 333 W. T" AVENUE, SUITE 100 CO~-s-7i~Rs~ilOts CO~~ai-1iS-7IO1~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADb1INISTRATIVE APPROVAL AIO 1.006 Mr. Steve Rossberg, We11s i/lanager BP Exploration (Alaska) Inc. ~~~~ ~~~ ~ ZQd 900 East Benson Bivd. P.O. Box 196612 Anchorage, AK 995 1 9-66 1 2 RE: End 1-151P25 (PTD 193-056) Request for Administrative Approval Dear UIr. Rossberg: In accordance with Rule. 9 of Area Injection Order 001.000, the Alaska Oil and Gas Con- servation Commission ("AOGCC" or "Commission'') hereby- approves BP Exploration (Alaska) Inc. ("BPXA")'s request for administrative approval to inject gas in the subject well. End 1-1 ~/P25 exhibits inner annulus ("IA") repressurization. AOGCC finds that BPXA has elected to perform no corrective action at this time on End 1-15/P25. The Commis- sion further finds that, based upon reported results of BPXA's diagnostic procedures, End 1-1 ~/P25 exhibits two competent barriers to release of well pressure. Accordingly, the Commission believes that well operation in gas injection service will not threaten the en- vironment or human safety. AOGCC's administrative approval to inject gas in End 1-15/P25 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures and injec- tion rates; 3. BPXA shall perform an 1v1IT -Tor CMIT - T x IA every two years, the anniver- sary date of which shall be this approval's effective date; • • N~ir. Steve Rossberg February 28, 2006 Page 2 of 2 4. BPXA shall perform an MIT - OA every two years, the anniversary date of which shall be this approval's effective date; ~. BPXA shall limit the well's IA pressure to 200 psi; 6. BPXA shall install and operate automatic well shut-in equipment on the well's I<4; 7. BPXA shall immediately shut in the w-e11 and notify the AOGCC if there is any change in the well's mechanical condition; and 8. after well shut-in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection. As provided in AS 31.0.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is consid- ered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. ~A~ rage, Alaska and dated February 28, 2006. ~~ ~~~ ~ N an, Daniel T. Seamount, Jr. Cathy P. F erster, .n Commissioner Commissioner MEMORANDUM e State of Alaska e Alaska Oil and Gas Conservation Commission TO: Jim Regg P.I. Supervisor 'K¿f1 Z( 1'7/0(; DATE: Thursday, February 16,2006 SUBJECT: Mechanical Integrity Tests BP EXPLORATION (ALASKA) INC 1-15/P25 DUCK IS UNIT MPI 1-15/P25 Src: Inspector S(P \q 3/Ö FROM: Jeff Jones Petroleum Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv -sge-- Comm Well Name: DUCK IS UNIT MPI 1-15/P25 Insp Num: mitJJ060211164012 ReI Insp Num API Well Number 50-029-22361-00-00 Permit Number: 193-056-0 Inspector Name: Jeff Jones Inspection Date: 2/11/2006 -~--¡; Well ' 1-15/P25 !Type Inj. L G P.T. I 1930560 !TypeTest I SPT Interval OTHER P/F Packer Depth TVD I942s i Test psi I 2356.25 P Pretest Initial I IA : , i OA ! Tubing I 1550 4000 15 Min. 30 Min. 45 Min. 4010 4010 I 60 Min. ! I 100 100 ]00 100 - 4750 i ------------------~ 4750 4750 4750 ~ Notes MITIA to evaluate post tubing patch IA re-pressurization. 1 well house inspected; no exceptions noted. t~ (, Thursday, February 16,2006 Page 1 of 1 Re: ENDl-15 (PTD #1930560) Slow IA repressurization e PTb.i1lq3-~ Subject: Re: END I-IS (PTD # 1930560) Slow IA rcpressurizatiotl From: James Regg <jim_regg(t;~;'.admin.statc.ak.us> Date: Mon, 13 Feb 200614:10:58 -0900 To: "NSLJ, ADW Well flltegrity Engineer" <NSUADWWelllntegrityEngincer@.BP.eom> CC: "AOGCC Winton Al1bel1 (E.-mail)" <winton_aubert@.admin.statc.ak.us>, "NSl.!, ADW WI Tcch" <NSUADWWITceh@BP.com>, END/BAD Area Manager <ENDHADArcaManage.r@BP.com>, "McMullen, John C" <McMl1IUC@BP.com>, "END, Operations Lead Tech" <ENDOperationsLcadTech@BP.com>, "NSLJ, ADW Well Operations Supervisor" <NSUADWWellOperationsSupervisor@BP.com>, "Engel, Harry R" <Harry.Engel(z.¡;.BP.com>, "Rossberg, R Steven" <Steven.Rossberg(qjBP.com>, hob_t1eckcnstcin@admin.state.ak.us, "Dubc, Anna T" <Anna.Dube@HP.com>, "Hughes, Andrea (VECO)" <hugha4@BP.com>, "Austin, Paul AI! <Pau1.A.Austin@BP.com>, "Winslow, Jack L." <Lyonsw@BP.com> ~e1 C{ 2,,1 l:7l ù(o >From the no pressure plot you supplied (presumably in response to my emaill/23/06), it appears there was a change in the well's mechanical integrity beginning in August 2005. Since that time, BP has been managing the pressure with periodic bleeds to keep IA from exceeding 2500 psi. There is no administrative approval (Rule 9, AIO 1) or sundry approval that establishes allowable annulus pressures for this gas injector. We do not understand what is meant by "operating within AOGCC prescribed pressures". You should apply for an administrative approval to continue operating this well if no repairs are planned, regardless of the fact that it passes an MIT. There is clearly communication between the tubing and IA. Should BP convince the Commission that Endicott 1-15 is safe to operate with known TxIA communication, you can expect a condition of approval that requires automatic well shut-in or pressure limit equipment on the well's tubing and IA. If you intend to keep this well in service, we should receive that administrative approval request by February 24. Jim Regg AOGCC NSU, ADW Well Integrity Engineer wrote: í: ì' ¡,;..-; Ie Hello Jim and Winton. An MITIA conducted on END1-15 on 2/11/06 passed to 4000 psi. The well exhibits signs of slow IA repressurization as indicated in the attached TIO plot. The well is operating within AOGCC prescribed pressures. Current plans are to continue gas injection operations. Attached is an MIT form, TIO plot and wellbore schematic. Please call with any questions. «MIT END 1-15 02-11-06.xls» «END1-15 TIO Plot.jpg» «1-15.pdf» Joe Anders, P.E. Well Integrity Coordinator, BP Exploration, (Alaska) Inc. Work: 1-907-659-5102 Mobile: 943-1154 10f2 2/13/20062:11 PM Re: END 1-15 (PTD # 1930560) Slow IA repressurization e e Pager: 659-51 DO, x1154 Email: NSUADWWelllnteç:¡rityEnQineer(â2bp.com From: NSU, ADW Well Integrity Engineer Sent: Sunday, January 22,200611:42 PM To: McMullen, John C; END/BAD Area Manager; END, Operations Lead Tech; Rossberg, R Steven; NSU, ADW Well Operations Supervisor; 'AOGCC Jim Regg (E-mail)'; 'AOGCC Winton Aubert (E-mail)' Cc: NSU, ADW Well Integrity Engineer; Winslow, Jack L.; NSU, ADW WI Tech Subject: ENDl-15 (PTD #1930560) Slow IA repressurization All, END1-15 (PTO #1930560) is a gas injector exhibiting slow IA repressurization. The TIO's on 01/21/06 were 4612/500/100. The well remains on injection with plans to conduct a MITIA and evaluate mitigation options The plan forward for this well is as follows: 1. FB: AOGCC MITIA 2. WIE: Eval MITIA results A wellbore schematic has been included for reference. Please call if you have any questions. Thank you, }f..nna c])u6e Well Integrity Coordinator GPB Wells Group Phone: (907) 659-5102 Pager: (907) 659-5100 x1154 20f2 2/13/20062:11 PM 01-151'10 of I 926x286 ~ ::::: -' t/l. i Q: '1 011212005 1211212005 2/13/20062:37 PM ~' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Perlormed: Abandon 0 Alter Casing D Change Approved Program D 2. Operator Repair WellŒ) Pluq PerlorationsD Pull TubingD Perlorate New PoolO Operation Shutdown 0 Perlorate 0 4. Current Well Class: Stimulate 0 OtherD waiverD Time ExtensionD Re-enter Suspended WellD 5. Permit to Drill Number: 193-0560 Name: BP Exploration (Alaska), Inc. Development 0 ExploratoryD Service ŒJ 6. API Number 50-029-22361-00-00 3. Address: P.O. Box 196612 Anchorage, Ak 99519-6612 7. KB Elevation (ft): 56.00 8. Property Designation: ADL-047502 11. Present Well Condition Summary: Total Depth Stratigraphic 0 9. Well Name and Number: 1-15/P-25 10. Field/Pool(s): Endicott Field 1 Endicott Oil Pool, Duck Island Unit measured 12972 feet None Effective Depth true vertical 10094.8 feet None measured 12952 feet Plugs (measured) Junk (measured) true vertical 10078.7 feet Casing Conductor Liner Production Production Surface Length 80 768 10634 1823 2715 Perloration deDth: Size 20" 91.5# H-40 7" 29# NT -80 9-5/8" 47# NT80S 9-5/8" 47# NT95HS 13-3/8" 68# L-80 MD TVD Burst Collapse 39 119 39.0 119.0 1490 470 12204 - 12972 9503.6 - 10094.8 8160 7020 37 - 10671 37.0 - 8431.6 6870 4760 10671 - 12494 8431.6 - 9719.8 8150 5080 38 - 2753 38.0 - 2739.6 4930 2270 Measured depth: 12498 - 12519, 12566 - 12620, 12650 - 12667, 12667 - 12687, 12702 - 12706, 12718 - 12730, 12742 - 12756 12770 - 12809 True vertical depth: 9722.86 -,9774.45 - 9738.76,9838.98 - 9815.82,9852.15 - 9852.15,9879.41 - 9867.71,9891.92 - 9882.53 9910.74 - 9901.32,9932.8 - 9921.76 Tubing ( size. grade, and measured depth): 7" 26# NT80S @ 35 12208 Packers & SSSV (type & measured depth): 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: ReDresentative Dailv Average Production or Injection Data Gas-Mef Water-Bbl Casing Pressure -32.5 0 600 13 Prior to well operation: Subsequent to operation: 14. Attachments: Copies of Logs and Surveys run - Daily Report of Well Operations. ! 5-1/2" Weatherford ArrowPac Packer 5-1/2" Weatherford ArrowPac Packer 7" Baker SABL-3 Packer @ @ @ 11845 11866 12173 , i i ,I, I ,,:~ Oil-Bbl 0 Tubing Pressure 4224 4161 0 -61.5 0 600 15. Well Class after proposed work: ExploratoryD 16. Well Status after proposed work: OilD GasD DevelopmentD Service ŒI WAG D GINJrBJ WINJD WDSPLD Prepared by Garry Catron (907) 564-4657. Sundry Number or N/A if C.O. Exempt: 303-031 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Garry Catron Garry Catron iJc1 C,~ Contact Printed Name Signature Form 10-404 Revised 4/2004 Title Production Technical Assistant Phone 564-4657 ORIGINAL Date 8/11/04 AüG 11 20~~ Rß0tì4S rBf/1.. 1-15/P-25 DESCRIPTION OF WORK COMPLETED NRWO OPERATIONS EVENT SUMMARY 05/31/04 A 7" PATCH WAS SET FROM 11847' TO 11867'. PATCH WAS 20' ELEMENT TO ELEMENT. MAX 00 OF PATCH WAS 5.93" GR-CCL WAS USED FOR CORRELATION. WELL LEFT SHUT IN. PAD OPERATOR NOTIFIED. FLUIDS PUMPED BBLS No Fluids Pumped 0 ITOTAL Page 1 . iii R.T. ELEV = 55.3' B.F ELEV = 16.12' MAX DEV = 48.82':' @ 6850' M.D. TREE: 6"1 10,000 pSI 1 MeEvoy WELLHEAD' 13-5/8" 110,000 pSI/ FMC .. ~ SSSVLANDING NIPPLE 1514' I ., ......----- OTIS (5.962"I.D.) , 13-3/8", 68#JfI, L-80. Blrs Csg I 2,753' >-A . ..-- 7", 26#/ft, NT-80S NSCC Tubing 9-5/8", 47#/ft NT80S XO to NT95HS I 10,671' I > ~ ~93"WEATHERFORD PATCH I 11.843' I ~ 4.0"" I.D. 7" OTIS "R" NIPPLE I 12.152' I ...~ 5.962" 1.0. g ~ 9-5/8" X T' PACKER I 12,173' I BAKER "SABL-3" TOP OF T' LINER ~ 7"OTIS"R"NIPPLE I 12.200' I 112.204' I >- )1 5.962" I D. 7" WLEG I 12,208' I 9-5/8", 47Mt, NT95HS, NSCC 4-1 J2" X 7" REDUCING NIPPLE I 12,494' I A ~ 3.755" ID I 12.159' I » PERFORATING SUMMARY Ref. Log: DLL.GR 15/15/93) CO GUN SPF INTERVAL AWS 4" 4 12498'.12519' AWS 4" ...¡. 12566'-12620' AWS 4" 4 12650'-12687' AWS 4" 4 12702'.12706' AWS 4" ...¡. 12718'-12730' AWS 4" 4 12742'-12756' AWS "¡" 4 12770'-12809' PBTD: Elec Line 12,905' PBTD: Dnller 12,952' )- 7", 29#1Il. NT -80 I 12 ,972' I > NSCC . DATE BY COfvUv1ENTS 5119193 ~lDrvl 8/6/93 JLH Perf and Add Perfs 1/5/02 MS Set Nipple Reducer 5/31/0..¡ WRR Set Tubing P¡:¡tch . ENDICOTT WELL: 1-15/P-25 API NO. 50-029-22361 COMPLETION DIAGRAM .. B.P. EXPLORATION (ALASKA) INC. MEMORA.NDUM TO: ..--. I~''l( (.!Zr¡Io4 Jim Regg P.I. Super\'i50or FROM: JetT Jones Petroleum Inspector \Vell Name: DUCK IS UNIT ~tPII-15/P25 Insp Num: mnJJO-t06210731-t5 Rellnsp Num: State of Alaska Alaska Oil and Gas Conservation Commission DATE: t\.londay. June ~ 1.200-1 SllBJECT: ~1echanlcallntegr (y Tests BP EXPLORATION IALASK.AI TNC 1-15'1'25 DUCK IS UNlT tl.fPll-lS'1'2S Src: In-:.pector NON-CONFIDENTIAL API \Vell Number: 50-029-22361-00-00 Permit Number: 193-056-0 Re\'iewed B~: P.I. Supr\' :I~ Comm Inspector Name: Jeff Jones Inspection Date: 6/18/2004 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 1-15.'P~5 Type loj. N TVD 10093 IA 720 ..1000 3890 3825 P.T. 1930%0 TypeTest SPT Test psi ~356.~5 OA 60 60 65 65 Inten'al .rYRTST PIF P Tubing 2000 2.t60 ~5:!O I 25:!O Notes: 6 BBLS diesel pumped. \-Vell was not on injection & \\as not at operating temperature. ~Ionday. June 2 L :!OO.. Page 1 of 1 BP Exploration (Alaska) Inc. Post Office Box 196612 900 East Benson Blvd Anchorage, Alaska 99519-6612 bp January 30,2003 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W. 7th Ave. Anchorage, Alaska 99501 Subject: Endicott Well 1-15/P-25 Application for Sundry Approval Dear Mr. Aubert: Attached is Application for Sundry Approval form 10-403 for Endicott gas injection well 1-15/P-25 (PTD 193-056). This request is for app~roval of installation of a tubing patch to repair tubing to inner annulus communication.'~ A summary proposal and wellbore schematic are attached. If you require any additional information or clarification, please contact Dan Robertson at 564-5546. Sincerely, Dan Robertson, P.E. Sr. Petroleum Engineer SCANNED FEB ! 0 2003 Attachments Endicott Gas Injection Well 1-15/P-25 Summary Proposal 1/30/03 Problem: Gas injection well with confirmed tubing to inner annulus communication via a tubing leak at 11,858 MD. Well History and Status Endicott gas injection well 1.~15/P-25 developed a tubing leak in mid 2001 and has been shut in since that time. The following operations have been performed: · 7/24/01 Tubing hanger seals passed pressure test after tubing to inner annulus / communication indicated by daily inner annulus pressure monitoring · 7/24-25/01 Installed plug in R nipple to secure well downhole · 7/31/01 Circulate well with seawater/diesel freeze protection. Good CMIT at 2500 psi. Establish leak rate of 4 bpm at 600 psi differential pressure. · 8/16/01 Leak detection log indicated only one tubing leak at 11,858 MD. / · 9/5/01 Tubing caliper survey indicated tubing ID to be in good condition overall / except at point of leak. · 1/29/03 Repeat combined mechanical integrity test of tubing and inner annulus a,~ 3000 psi to reconfirm integrity prior to tubing patch installation. Passed CMIT. This sundry request is to allow installation of a tubing patch with electric line to restore tubing integrity. Proposed Action Plan 1. Pressure test the combined tubing and casing at 2500 psi for 30 minutes. 2. RU slickline and run a 5.875" OD x 20' dummy tubing patch assembly to 12,100 MD. RD slickline. 3. RU eline. Install 20' Eclipse retrievable tubing patch across tubing leak at 11,858 MD. RD eline. Differential pressure rating of the patch is 5000 psi. 4. Perform AOGCC witnessed pressure test of the inner annulus at 2500 psi for 30 minutes. 5. If the inner annulus MIT is successful, Install SSSV. 6. Return well to gas injection service. If the post patch installation MIT of the inner annulus is unsuccessful, diagnostics/repairs will be necessary prior to resuming gas injection. / further STATE OF ALASKA ~ ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS / / 1. Type of request: Abandon_ Suspend_ Operational shutdown _ Re-enter suspended well _ Alter casing _ Repair well _X Plugging _ Time extension _ TUBING PATCH Change approved program _ Pull tubing _ Variance _ Stimulate _ Perforate _ Other_ 2. Name of Operator BP Exploration (Alaska), Inc. 3. Address P. O. Box 196612 Anchora[le, AK 99519-6612 4. Location of well at surface 5. Type of Well: Development __ Exploratory __ Stratigraphic __ Service_._X 6. Datum elevation (DF or KB feet) RKB 56.0 feet 7. Unit or Property name Duck Island Unit/Endicott 1987' FNL, 2065' FEL, Sec. 36, T12N, R16E, UM At top of productive interval 1227' FNL, 1798' FEL, SEC 06, T11N, R17E, UM At effective depth 1471' FNL, 1611' FEL, Sec. 06, T11N, R17E, UM At total depth 1481' FNL, 1603' FEL, Sec 06 T11N, R17E, UM (asp's 259140, 5982425) (asp's 264150, 5977744) (asp's 264330, 5977494) (asp's 264337, 5977484) 8. Well number 1-15/P-25 X~ 9. Permit number / approval number 193-056 f 10. APl number 50-029-22361-00 11. Field / Pool Endicott Field / Endicott Pool 12. Present well condition summary Total depth: measured 12972 feet Plugs (measured) true vertical 10095 feet Effective depth: measured 12952 feet Junk (measured) true vertical 10079 feet Casing Length Size Cemented Conductor 92' 30" Driven Surface 2714' 13-3/8" 1193 cf 'E', 464 cf 'C' Intermediate 12453' 9-5/8" 800 cf Class 'G' Liner 768' 7" 230 cf Class 'G' Measured De~h True ve~icalDepth 131' 131' 2753' 2740' 12494' 9720' 12204'-12972' 9504'-10095' Perforation depth: measured Open Perfs 12498'-12519', 12566'-12620', 12650'-12687', 12702'-12706', 12718'-12730', Open Perfs (continued) 12742'-12756', 12770'-12809' true vertical Open Perfs 9723'-9739', 9775'-9816', 9839'-9868', 9880'-9883', ~9~-~0~1 V ED Open Perle (continued) 9911'-9922', 9933'-9964' Tubing (size, grade, and measured depth 7", 26#, NT-80S NSCC Tubing to 12,208'. JAN 5 1 ?_005 Packers & SSSV (type & measured depth) 9-5/8" X 7" Baker 'SABL-3' Packer @ 12173'. 7" OTIS SSSV Landing Nipple @ 1514'. &l~.~l(a 0il & Gas Cons. Commission 13. Attachments Description summary of proposal __X Detailed operations program __ 14. Estimated date for commencing operatio.~j February 10, 2003 -- 16. If proposal was verbally approved Name of approver Date approved 17. I hereby/Ee[tify that the foregoing is true and correct to the best of my knowledge. Signed~t~J~,.~ //'~rO/c~_~ Title: Endicott Sr. Petroleum Engineer Dan Robertson 15. Status of well classification as: Oil _ G7_ Service GAS Iniector FOR COMMISSION USE ONLY Suspended _ Questions? Call Dan Robe~tson @ 564-5546. Date 01/30/2003 Prepared by DeWayne R, Schnorr 564-5174 Conditions of approval: Notify Commission so representative may witness Approval no. Plug integrity __ Bv.OP Test _ Location clearance Mechanical Integrity Test ~, Subsequent form re~uirad 10- ~"~,/~ Approved by order of the Commission OpdG|NAL SIGN~I~ ~¥ ~. , Comm~klAl~m .. ~ ~ 1~/n ~ Form 10-403 Rev 06/15/88 · TREE: 6" / 10,000 psi / McEvoy R.T. ELEV = 55.3" WELLHEAD: 13-5/8" / 10,000 psi ! FMC B.F. ELEV = 16.12' MAX DEV = 48.82° @ 6850' M.D. SSSV LANDING NIPPLEI OTIS (5.962" 13-3/8", 68#~t, L-80, Btrs Csg ~ ~ 7", 26#/ft, NT-80S NSCC Tubing 9-5/8", 47#/ff NT80S XO to NT95HS I I4 ,/ 5.962"7" OTIS "R" NIPPLEi.D. I 12,152' Z 9-5!8"×7"P^CKER I 12,173' BAKER "SABL-3" TOP OF 7" LINER ! I ~J ~ 7" OTIS "R" NIPPLE I 12,200' -- -- ~ 7"WLEG I 12,208' 9-5/8", 47#/ft, NT95HS, NSCC J 12,494'J ~-- ~ k PERFORATING SUMMARY Ref. Log: DLL-GR (5/15/93) CO. GUN SPF INTERVAL AWS 4" 4 12498'-12519' AWS 4" 4 12566'-12620' AWS 4" 4 12650'-12687' AWS 4" 4 12702'- 12706' AWS 4" 4 12718'-12730' AWS 4" 4 12742'-12756' AWS 4" 4 12770'-12809' PBTD: ElecLine J 12,905' J~ SCANNED FEB ! 0 2003 PBTD: Ddller ~ NSCC~ DATE BY COMMENTS ENDICOTT WELL: 1-151P-25 5/19/93 MDM APl NO. 50-029-22361 8/6/93 JLH Perf and Add Rerfs COMPLETION DIAGRAM B.P. EXPLORATION (ALASKA) INC, 01'40g ggFO c:t,o~~°c ~ STATE OF ALASKA ALAS .)IL AND GAS CONSERVATION COMMIS[ REPORT OF SUNDRY WELL OPERATIONS Operations performed: Operation shutdown__ Stimulate__ Plugging__ Pull tubing Alter casing __ Repair well __ Perforate__ Other X 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P. O. Box 196612, Anchora.c/e, Alaska 99519-6612 4. Location of well at surface 1987' SNL, 2065' WEL, Sec. 36, T12N, R16E At top of productive interval 1227 SNL, 1798' WEL, Sec. 6, TIIN, R17E At effective depth 1470' SNL, 1610' WEL, Sec. 6, TIIN, R17E At total depth 1479' SNL, 1601' WEL, Sec. 6, TIIN, R17E 5. Type of Well: Development __ Exploratory ~ Stratigraphic ~ Service .. 6. Datum elevation (DF or KB) KB£ = 56' feet 7. Unit or Property name Duck Island Unit/Endicott 8. Well number 1 - 15/P-25 9. Permit number/approval number 93-56~Not recluired 10. APl number 50- 029-22361 11. Field/Pool Endic¢~ ~)il/Pqel ! 12. Present well condition summary Total depth: measured Effective depth: Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: true vertical measured true vertical Length 12972' feet Plugs (measured) 10093 feet BKB 12952 feet Junk (measured) 10078 feet BKB i'\Lk. C ] VEL] AU,S' 4, 1998 Oil & Gas Cons, C0mmi~si0n Anchorage Size Cemented Measured depth True vertical depth BKB BKB 92' 30' Driven 131' 131' 2714' 13 3/8" 1193 c.f. "E'Y464 c.f. "C" 2753' 2684' 12453' 9 5/8" 800 c. f. Class G 12494' 9664' 768' 7" 230 c. f. Class G 12204'- 12972' 9448'- 10039' measured 12498'-12519', 12566'-12620', 12650'-12687, 12702'-12706', 12718'-12730', 12742'-12756', 12770'- 12809 true vertical 9705'-9721', 9758'-9800', 9823'-9853', 9864'-9868', 9877'-9887', 9896'-9907', 9918'-9949' Tubing (size, grade, and measured depth) 7"26#/ft. NT-80S NSCC tubing to 12208' Packers and SSSV (type and measured depth) 9 5/8"x 7" Packer set at 12173'; 7" SSSV set at 1514' 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure ORIGINAL 14. Prior to well operation Subsequent to operation Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure 4211 4228 15. Attachments Copies of Logs and Surveys run . Daily Report of Well Operations X 16. Status of well classification as: 0i1__ Gas__ Suspended Service m~.~ Ini. p.m.t~r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Form 10-4~4 Rev 0¢15/88 Date 7/30/98 SUBMIT IN DUPLICATE,~ BPX Endicott Production Engineering Department DATE: 7/9/98 WELL N°: 1-15/P-25 TYPE OF OPERATION: BP EXPLORATION REP: SERVICE COMPANY: Operations Report MIT IA Lovelace/Barba Tri-plex TIME OPERATIONS SUMMARY 15OO 1525 1605 1610 RIG UP Tri-plex AND P-TEST LINE TO 3000 PSIG FWHP = 3950, IA = 450, OA = 0 BEGIN PUMPING METHANOL DOWN IA and pressured up to 2600 ps~g. MONITOR FOR 30 MINUTE, PRESSURE HELD. Witnessed by John Spaulding of the i AOGCC. FWHP = 3950, IA = 2600, OA = 0. GOOD TEST. BLED IA DOWN TO 500 PSIG & RIG DOWN Tri-plex. Summary: Performed a IA MIT. Pumped methanol into the IA and held 2600 psi for 30 min. Bled inner annulus to 500 psi. LARRY GRANT Attn. ALASKA OIL + GAS CONSERVATION 3001 PORCUPINE DRIVE ANCHORAGE AK, 99501. Date: 11 July 1995 RE: Transmittal of Data Sent by: PRIORITY MAIL Dear Sir/Madam, Enclosed, please find the data as described below: WELL # DESCRIPTION 1 PFC/PERF FINAL BL+RF 1 PLS/STP FINAL BL+RF 1 PLS FINAL BL+RF 1 PLS FINAL BL+RF ECC No. Run # 1 2628.07 Run ~ 1 3235.06 Run # 1 5669.05 Run # 1 5959.05 1 PFC/PERF FINAL BL+RF Run # 1 6217.14 1 PLS FINAL BL+RF Run # 1 6412.01 Please sign and return to: Attn. Rodney D. Paulson Atlas Wireline Services 5600 B Street Suite 201 Anchorage, AK 99518 ~ Or FAX/o (907) 563-7803 Received by Date ~'~OGCC Individual Well Geological Materials Inventory " .... Page: 1 Date: 04/11/95 PERMIT DATA T DATA_PLUS 93 -056 93-056 93-056 93-056 93-056 93-056 93-056 93-056 407 MP DATE :06-06-93 DAILY WELL OP. q~ DRILLING HISTORY / SURVEY ~ ANADRILL DIRECTIONAL / CNL/GR ~/L 11700-12897 DLL/MSFL ¢/~ 11950-12960 / DLL/MSFL/GR/STVD~ 11950-12960 PFC/GR t~ 12000-12878 RUN DATE_RECVD 07/12/1993 07/26/1993 07/26/1993 07/26/1993 06/11/1993 06/1 i/199,3 06/11/1993 08/02/1993 93-056 PFC/GR/CCL ~ R1,12430-12800 93-056 PROD ~'/12400-12860 93-056 PROD ~/12400-12850 / 93-056 SBT/GR/CCL ~/L 11700-12897 Are dry ditch samples required? yes ~no )And rec~l~ yes Was the well cored? yes '~ Analysis & descriptl~B-~eceived? Are we~ tests requ~ed~ yes ~ Rece s no Well is in compliance ~ ~ I~iti~ COMMENTS 08/24/1993 09/20/1993 09/01/1994 06/11/1993 no yes no ALASKA OIL & GAS CONSERVATION COMMISSION Attn. LARRY GRANT 3001 PORCUPINE DR. ANCHORAGE AK, 99501. USA Date: 24 August 1994 RE: Transmittal of Data Sent by: ANCHORAGE EXPRS Dear Sir/Madam, Enclosed, please find the data as described below: WELL # DESCRIPTION 1-15/P-25 1 PL/PROFILE FINAL BL 1 PL/PROFILE RF SEPIA 1 PFC/PERF FINAL BL 1 PFC/PERF RF SEPIA ~ ~ ~& 3-17/J-30A SDI Run # 1 Run # 1 ECC No. 5959.04 Run # 1 6185.05 Run # 1 Please sign and ret~o: Atlas Wireline Services ~ 5600 B Street ~ Suite 201 ~ ~ Anchorage, AK 99518 /~ Attn. Rodney D. Pa~LLs6~ Received by: Please s fEn and x'e%-u~ ~o.. BPpetrotechni~al Da~a Cente~ EXploration (Alaska) 900 East Benso~ BOUlevard ~chorage, ~ka ~08 ~eeived by~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown Pull tubing Alter casing Stimulate Plugging 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P. 0. Box 196612, Anchorage, Alaska 99519-6612 Repair well 4. Location of well at surface 1987' SNL, 2065' WEL, Sec. 36, T12N, R16E At top of productive interval 1227 SNL, 1798' WEL, Sec. 6, TIIN, R17E At effective depth 1470'SNL, 1610' WEL, Sec. 6, TIlN, R17E At total depth 1479' SNL, 1601' WEL, Sec. 6, TIIN, R17E 5. Type of Well: 6. Development Exploratory Stratigraphic Service X Gas Cons. Commission Anchorage Perforate Other X Datum elevation (DF or KB) KBE = 56' feet 7. Unit or Property name Duck Island Unit/Endicott 8. Well number 1-15/P-25 9. Permit number/approval number 93-56/Not required 10. APl number 50- 029-22361 11. Field/Pool Endicott Oil Pool 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: 12972' feet Plugs (measured) 10093 feet BKB 12952 feet Junk (measured) 10078 feet BKB Length Size 92' 30' 2714' 133/8" 12453' 9 5/8" Cemented Measured depth True vej-ti.c_~l depth BKB Driven 131' 131' 1193 c.f. "E"/464 c.f. 'C" 2753' 2684' 800 c. f. C/ass G 12494' 9664' measured 768' 7" 230 c. f. Class G 12204'- 12972' 9448'- 10039' 12498'-12519', 12566'-12620', 12650'-12687, 12702'-12706', 12718'-12730', 12742'-12756', 12770'- 12809 true vertical 9705'-9721', 9758'-9800', 9823'-9853', 9864'-9868', 9877,-9887,, 9896'-9907,, 9918'-9949' Tubing (size, grade, and measured depth) 7" 26~/ft. NT-80S NSCC tubing to 12208' Packers and SSSV (type and measured depth) 95/8"x 7" Packer set at 12173'; 7"SSSV setat 1514' 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure 14. Prior to well operation Subsequent to operation 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water~Bbl Casing Pressure Tubing Pressure 16. Status of well classification as: Oil Gas Suspended Service Gas Injector 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~?~/~7..,/-~(~, ~>~". ~ Title Senior Technical A ssistantll Form 10-40~Rev 06/15/88 SUBMIT IN DU'PLI~'A?i5 '" Endicott ' Production Engineering ,,, Depa,r, tment, .... MIT DATE: 7/9/94 WELL N-°: 1-15 / P-25 BP EXPLORATION REP: SERVICE COMPANY: KIMMET LITTLE RED (MURRAY) TIME OPERATIONS' SUMMARY " .' 0730 MIRU LITTLE RED. 0830 lAP '1800 PSi, WHP 4'200 PSI. PUMP DIESEL DOWN INNER ANNUL0'E~'UNTIL PRESSURE IS 2500 PSI. 0850 IA PRESSURE DOWN TO 2350 PSIi BUMP UP TO 2500 PSI. 0939 .... IAP'2495 PSI. PASS'ED MIT. 0940 BLEED I~,1S TO '~800 PSi. RDMO'. ' ' .... PASSED MIT. WITNESSED BY JOHN SPAULDING, AOGCC REPRESENTATIVE. Alaska Oil & Gas Cons. Commission Anchora',J~ · STATE OF ALASKA A ,KA OIL AND GAS CONSERVATION COMMIS.. JN REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown Stimulate Plugging Perforate × Pull tubing Alter casing Repair well Other 6. Datum elevation (DF or KB):'~r--~?'..~ 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P. O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 1987' SNL, 2065' WEL, Sec. 36, T12N, R16E 5. Type of Well: Development Exploratory Stratigraphic Service KBE = 56' 7. Unit or Property name Duck Island Unit/Endicott 8. Well number 1-15/P-25 At top of productive interval 1227 SNL, 1798'WEL, Sec. 6, T/IN, R17E At effective depth 1470' SNL, 1610' WEL, Sec. 6, TIIN, R17E At total depth 1479' SNL, 1601' WEL, Sec. 6, TIIN, R17E 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length 92' 2714' 12453' 768' 9. Permit number/approval number 93-56 10. APl number 50- 029-22361 11. Field/Pool Endicott Oil Pool 12972' feet Plugs (measured) 10093 feet BKB 12952 feet Junk (measured) 10078 feet BKB Size Cemented Measured depth True ve_rti.c,.al depth BKB 30' Driven 131' 131' 13 3/8" 1193 c.f. "E"/464 c.f. "C" 2753' 2684' 9 5/8" 800 c. f. Class G 12494' 9664' measured 7" 230 c. f. Class G 12204'- 12972' 9448'- 10039' 12498'-12519', 12566'-12620', 12650'-12687, 12702'-12706', 12718'-12730', 12742'-12756', 12770'-12809 true vertical 9705'-9721', 9758'-9800', 9823'-9853', 9864'-9868', 9877'-9887', 9896'-9907', 9918'-9949' Tubing (size, grade, and measured depth) 7"26tt/ft. NT-80S NSCC tubing to 12208' Packers and SSSV (type and measured depth) 13. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure 14. 9 5/8"x 7" Packer set at 12173'; 7" SSSV set at 1514' OCT t ~ 1J993 Naska Oil & Gas Cons. (;ummis$~u, Representative Daily Average Production or Injection Data Anchorage Oil-Bbl Gas-Mcr Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 0 Subsequent to operation 25520 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations. X 16. Status of well classification as: Oil Gas .. Suspended Service Gas Injector 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed (~"~/'L~/C2,__~ c'~. /~~? Title Senior Technical A ssistantll Form 10-C,~ Rev 06/15/88 SUBMIT IN DU'PLI~ATE Endicott Production Engineering Department DATE: 8 / 5 / 9 3 WELL N-°: 1-15/P-25 BP EXPLORATION REP: SERVICE COMPANY: Additional Perforations HOBBS ATLAS/HARPER INOTE: INSURE THAT THE WELL SITE AREA, WELL HOUSE AND PRODUC31ON TREI~ ARE KEPT FREE OF CRUDE OIL, EQUIPMENT LEAKS OR TRASH. CLEAN UP AN~ CRUDE/HYDRAULIC OIL LEAKS BEFORE LEAVING THE JOB SITE. DATE/TIME OPERATIONS SUMMARY 0700 RU. Post radio silence signs at the entrance to island and next to well site. Install SSV fusible cap. WHP = 0 psig. lAP = 0 psig. OAP = 0 psig. Well SI. 0 84 4 ESTABLISH RADIO SILENCE AND ARM GUNS (Notify security). 091 5 Pressure test lubricator to wellhead pressure. 0920 RIH with Gun #1 (17 feet). SlWHP = 0 psi~l. 0 95 0 Tie in to CBL dated 5/17/93. All of the depths listed below are from the open ho!e reference Io9. 1 01 0 Hang gun #1 Top Shot at 12650' MDBKB. 1013 Shoot ,(]un #1 from 12650-12667' MDBKB. 1015 WHP-150 psi. 1 01 5 Log collars while POOH. 1105 RIH with Gun #2 (20 feet). SIWHP = 150 psig. 1140 Tie in to CBT logging up. Shoot gun # 2 from 12600'-12620' MDBKB. SlWHP -- 150 psig. 1 14 2 Log collars while POOH. 1230 RIH with Gun #3 (20 feet). SIWHP = 150 psig. 1255 Tie in to CBT logging up. Shoot gun # 3 from 12580-12600' MDBKB. SIWHP = 150 psicj. 13 05 Log collars while POOH. 1350 RIH with Gun #4 (14 feet). SIWHP = 150 psig. 1420 Tie in to CBT logging up. Shoot gun # 4 from 12566'-12580' MDBKB. SlWHP = 150 psig. 14 3 0 Log collars while POOH. 1526 RIH with Gun #5 (21 feet). SlWHP = 250 psi!]. 1600 Tie in to CBT logging up. Shoot gun # 5 from 12498'-12519' MDBKB. SIWHP = 3O0 psig. 1 61 0 Log collars while POOH. Hang up at 12492'. Will not go down or up. Suspect sand. Work wire a bit. No luck. 1700 Wait on Little Red. SIWHP-400 1 830 MIRU Little Red. SIWHP-500 psi. 1 85 5 PT to' 4000 psi. ok. 1 900 Be,(]in Pumping. 7 bpm rate at 800 psi. 2030 555 bbl seawater pumped away. Pressure began to rise at 400 bbl away. At 555 bbl away, WHP was 2200 psi at 5 bpm. At shut-down, pressure was 1850 psi and fell to 350 psi by 2045. 2035 End radio silence. 2045 Binds pulled to 7500#. At limits of crane. Call for cutter bar. SIWHP- 350 psi. 2200 Cutter bar on location. Work to 7500# a few more times. 224 0 No luck with working. Close BOPS to drop cutter bar. 8/6/93 0020 Kinley cutter away. 01 0 0 Kinley cutter cut. Pull wire out of the hole. " C'T Aiaska Oil & Gas Cons. Commissto,".- Anchorage DATE: WELL N°: TYPE OF OPERATION: Additional Perforations 0150 0200 Estimate that there is about 250' of line in the hole. Could be as little as { 150' if the discrepancy is du, e to slippage. $1WHP = 150 psig. RE)MO. I PERFORATION SUMMARY: GUN INTERVAL(DLL) CBL DEPTH FEET ~UBZONE I 12650-12667 12650-12667 17 3C2 2 12600-12620 12600-12620 20 3C3 3 12580-12600 12580-12600 20 3C3 4 12566-12580 12566-12580 14 3C3 5 12498-12519 12498-12519 21 3C5 All intervals were shot using 4" ALPHA-JET guns at 4 spf, 90 degree phasing and random orientation. The tie-in Icg was on depth with the open-hole reference Icg. THERE IS A KINLEY CUTTER AND A 32' 4" GUN AND PCM ASSEMBLY IN THE HOLE. Alaska Oil & Gas Cons, Anchorage BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 September 16, 1993 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear AOGCC Representative, Attached in duplicate is detailed information regarding the enclosed well logs for the Endicott Field. Please contact me at 564-5225 if you have any questions. Sincerely, '-8~'enior Technical Assistant II JLH Enclosures xc: File 06.10 WELL NAME DATE ~?'",~' ! 1-09/J-18 8/22/93 INTERVALS LOG NAME RUN NO COMPANY NAME 11200'-11945' PDK-100 LOG 1 ATLAS WIRELINE ~.-" "~ ~ 3-17/J-30 CfCr~ 2-18/L-16 c-j'0 -,2~ 2-36/O-14 ~-- I,~ ~'.-/' 1-35/0-25 "i!~'-'- ~6 2-28/P- 19 c/5_ ~ 1-15/P-25 %l~----~q 3-47/Q-35 ::t2.._ ~ i,~ 1-51/v-20 7/27/93 9/5/93 8/20/93 8/25/93 8/28/93 9/4/93 9/6/93 8/21/93 13400'- 13950' 10900'- 11200' 10800'- 11250' 12700'- 13261' 9800'- 10320' 12400'- 12860' 100'-10450' 3600'-12700' PRODUCTION LOGGING SERVICES PFC/GR/CCL PRODUCTION LOGGING SERVICES PRODUCTION LOGGING SERVICES PRODUCTION LOGGING SERVICES PRODUCTION LOGGING SERVICES PRODUCTION LOGGING SERVICES PRODUCTION LOGGING SERVICES I ATLAS WIRELINE I ATLAS WIRELINE I ATLAS WIRELINE I ATLAS WlRELINE I ATLAS WlRELINE I ATLAS WlRELINE I ATLAS WlRELINE 1 ATLAS WlRELINE INTERVALS LOG NAME RUN NO COMPANY NAME WELL NAME/~DATE 1-15/P-25 ~¢t,/' (,, 6/5/93 1-27/P-20 q,q ..e' ~_ 6 / 26 / 9 3 2'04/M' 19~'~,'~'~6 / 25/93 2-18/L-16 ~O'"~! 7/17/93 2-50/U-08 ~,(,17/1 8/93 7/18/93 ~,,~,,,~'~ 7 /20/03 3-21/L-34 6/19/93 3-25/M-27 q~1'~"-6/27/93 3-49/J-40~1,,~06/28/937/9/93 12000'-1 10100'-1 10000'-.1 10700'-1 13500'-1 13500'-1 14737'-1 12300'-1 13600'-1 14350'-1 14700'-1 2878' 0709' 0695' 1334' 5452' 5417' 4905' 2830' 3957' 4856' 4870' PFC Gamma Ray CNL/GR PDK-100 Production Logging Services Segmented Bond Log Compensated Neutron/GR/CCL GR/CCL PDB-100/GR/CCL Production Logging (PITS) PFC/GR/CCL PFC/CCL ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS BP EXPLORATION ARCO Alaska, Inc. ~~' To: Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Date' July 21, 1993 Attention' Steve McMains Subject: DS 1-15/P-25 Corrected Completion Notice As per our discussion today, enclosed, in duplicate, is a corrected copy of the Completion Notice for the above referenced well. The BHL township and range had been incorrectly reported. Our apolgies for any inconvenience this may have caused your office. Yours Sincerely, Russell Strickland MS cc. Well file PDC Jeanne Haas STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION CO v, MISSION WELL COMPLETION OR RECOMP LETION REPORT AND LOG 1. Status of Well Classification of Service Well GAS [] SUSPENDED [] ABANDONED [] SERVICE [] Gas Injector OIL [] 2. Name of Operator 7. Permit Number / BP Exploration 93-56 3. Address 8. APl Number P. 0. Box 196612, Anchorage, Alaska 99519-6617 ~ 50- 029-22361 1987,SNL, 2065'WEL, SEC. 36, T,2N, R,6E /;~:i~; !;'¢,~~ DucklslandOnit/Endicott At Top Producing Interval --~:?- 10. Well Number 1113'SNL, 3179' EWL, SEC. 6, Tl l N, R17E :- --~ . 11. Field and Pool At Total Depth -"- ........ Endicott Field/Endicott Pool 1372' SNL, 3385' EWL, SEC. 6, T11N, R17E 5. Elevation in feet (indicate KB, DF, etc.) 16. Lease Designation and Sedal No. BKB 56' I ADL 47502 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. 115. Water Depth, if offshore 116. No. of Completions 4/24/93 5/14/93 6/6/93I 6'-12' MSL feet MSL lOne 17. Tolal Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) 19. Directional Survey ~20. Depth where SSSV set ~21. Thickness of Permalros t 12972' MD/10093' TVD 12952' MD/10078' TVD YES [] N3 []! 1514' feet MD 11465'(Approx.) 22. Type Electric or Otha' Logs Run DLL/MSFL/GR/MWD 23. CASING, LINER AND CEMENTING RECOFID ~ DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BO'I-rOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 30" Struct. Drive 37' 131' Drive 13-3/8" 68# NT80 42' 2753' 16" 1193 cu fl "E"/464 cu fl "C" 9-5/8" 47# NT80/NT95 40' 12494' 12-1/4" 800 cu ft Class "G" 7" 29# NT80 12204' 12972' 8-1/2" 230 cuft Class "G" 24. Pedorations open to Production (MD+TVD of Top and Bottom and 25. TUBING REC, ORD interval, size and number) SIZE DEPTH SET(MDI PACKER SET (MD) Gun Diameter4" 4 spf MD TVD 7", NT80 12208' 12173' 12770'- 12809' 9941'-9971' 12742'- 12756' 9920'-9931' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 12718'-12730' 9902'-9911' DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 12702'- 12706' 9890'-9893' 12667'-12687' 9864'-9879' .~7. PRODUCTION TEST Date First Production IMethod of Operation (Flowing, gas lift, etc.) Not yet injecting I N/A Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE S[7_.E IGAS-OIL RATIO TEST PERIOD ~ I Flow Tubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (corr) Press. 24-HOUR RATE I~ 28. CORE DATA Brier description of lithology, porosity, lractures, apparent dips, and presence of oil, gas or water. Submit core chips. ,~iaska Oil & Gas Cons, Cornlnission Anchorage Form 10-407 Submit in duplicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE 29. 30. GEOLOGIC MARKERS I-._...VlATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Base HRZ 12427' 9684' Top Kekiktuk 12457' 12457' Top zone 3B 12757' 12757' · 41aska Oil & Gas Cons. Cnm,;~ieeir, r: 31. LIST OF ATTACHMENTS Anchorage .............. 32. I hereby certily that the foregoing is true and correct to the best of my knowledge Signed :~~~ Title OrillingEn.qineerSupervisor Date 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 1' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 BP/AAI SHARED SERVICE DAILY OPERATIONS PAGE: 1 WELL: MPI 1-15/P-25 BOROUGH: NORTH SLOPE UNIT: ENDICOTT FIELD: ENDICOTT LEASE: API: 50- PERMIT: APPROVAL: ACCEPT: 04/24/93 07:00 SPUD: 04/24/93 06:30 RELEASE: OPERATION: DRLG RIG: DOYON 15 WO/C RIG: DOYON 15 04~25/93 ( 1) TD: 800' ( 0) 04/26/93 (2) TD: 2442' (1642) 04/27/93 ( 3) TD: 2765' ( 323) · . . _ 04/28/93 (4) TD: 2775' ( 10) -04/29/93 ( 5) TD: 4690' (1915) 04/30/93 (6) TD: 5980' (1290) 05/01/93 ( 7) TD: 6885' ( 905) 05/02/93 ( 8) TD: 8020' (1135) 05/03/93 ( 9) TD: 8750' ( 730) SURVEY. MW: 9.0 VIS:230 RIG ACCEPTED @ 07:00 HRS, 4/24/93. N/U DIVERTER. TEST SAME. RIH W/ BHA. SPUD WELL @ 18:30 HRS, 4/24/93. DRLG F/ 80'-800' POOH. MW: 9.3 VIS: 94 DRLG F/ 800'-1040' SHORT TRIP TO 800' DRLG F/ 1040'-1517' SHORT TRIP TO 1000'_ DRLG F/ 1517'-2089' SHORT TRIP TO 1400' DRLG F/ 2089'-2442' POOH. CMT CSG. MW: 9.5 VIS:107 RIH. DRLG F/ 2442'-2765' CIRC. SHORT TRIP TO 2200' CBU. POOH. L/D BHA. RIH W/ 13-3/8" CSG. CIRC. PUMP 100 BBLS WATER, CMT. DRLG. MW: 9.4 VIS: 56 CMT CSG. BUMP PLUG W/ 2000 PSI. N/D DIVERTER. TOP JOB W/ 20 BBLS CMT. N/U TBG SPOOL, BOPE. TEST BOPE. RIH W/ BHA, BIT. TETST CSG. OK. DRLG FC, CMT, FS, 10' NEW HOLE. DRLG. .... MW: 9.3 VIS: 44 CIRC. FIT (14..4 PPG.~MW). DRLG F/ 2775'-3357' CIRC. SHORT TRIP TO SHOE. DRLG F/ 3357'-4025'. CIRC. SHORT TRIP TO 3071'. DRLG F/ 4025'-4690'. DRLG. MW: 9.6 VIS: 50 DRLG F/ 4690'-5166' CIRC. POOH. CHANGE BHA. RIH. DRLG F/ 5166'-5980' POOH. MW- 9.7 VIS- 44 DRLG F/ 5980'-6026' CIRC. SHORT TRIP. DRLG F/ 6026'-6695' SHORT TRIP. DRLG F/ 6695'-6885' CIRC. POOH. DRLG. MW: 9.7 VIS: 45 POOH. CHANGE BIT. RIH. DRLG F/ 6885'-7425'. CIRC. SHORT TRIP..TO 6400' DRLG F/ 7425'-8020' .. DRLG. MW: 9.7 VIS: 43 DRLG F/ 8020'-8099'. SHORT TRIP TO 7425' DRLG F/ 8099'-8550' POOH. CHANGE BIT. RIH. DRLG F. 8550'-8750' Alaska..Oil .& Gas Coils. Cornrnission An,,norage WELL · MPI 1-15 OPERATION: RIG - DOYON 15 PAGE: 2 05/04/93 (10) TD: 9239' ( 489) 05/05/93 (11) TD: 9606' ( 367) DRLG. DRLG F/ 8750'-9179' F/ 9179'-9239' MW: 9 8 VIS: 52 CIRC. POOH. CHANGE BHA. RIH. DRLG RIH. MW: 9 6 VIS: 42 DRLG TO 9606' CIRC. POOH. TEST BOPE. CHANGE BIT. RIH. 05/06/93 (12) TD:10730' (1124) DRLG. RIH. DRLG TO 10320' MW: 9 9 VIS: 49 SHORT TRIP TO 9365' DRLG TO 10730' 05/07/93 (13) TD:11342' ( 612) TEST MWD. MW: 9 8 VIS: 42 DRLG TO 11342' POOH. CHANGE BHA. RIH. TEST MWD. 05/08/93 (14) TD:l1860' ( 518) DRLG. RIH. DRLG TO 11792' MW:10 0 VIS: 46 SHORT TRIPTO 10742' DRLG TO 11860' 05/09/93 (15) TD:12496' ( 636) 05/10/93 (16) TD:12496' ( 0) 05/11/93 (17) TD:!2496' ( 0) 05/12/93 (18) TD:!2560' ( 64) 05/13/93 (19) TD:12660' ( 100) 05/14/93 (20) TD:!2972' ( 312) SHORT TRIP. DRLG TO 11983' MW:10 3 VIS: 47 SHORT TRIP. DRLG TO 12496' SHORT TRIP. RUN CSG. MW:10 4 VIS: 49 SHORT TRIP F/ 12496'-11196'. CBU. POOH. L/D BHA. TEST BOPE. RIH W/ 9-5/8" CSG. CIRC. CIRC. MW:10 4 VIS: 40 PUMP 20 BBLS WATER,..50 BBLS PREFLUSH, 462 BBLS (800 SX) PREMIUM CMT, 41 BBLS.i200 SX) TAIL CMT. DISP W/ MUD. NO BUMP PLUG. N/D BOPE. SET EMERGENCY SLIPS. INSTALL PACKOFF. TEST SA_ME. N/U BOPE. TEST BOPE. P/U BHA. RIH. · . CIRC. DRLG. MW: 9.3 VIS: 49 DRLG FLOAT EQUIP, 6' NEW HOLE. CIRC. FIT (10 PPG EMW) . DRLG TO 12522' REPAIR TURBINES. DRLG TO 12560' DRLG 8 1/2" HOLE ~W: 9.5 VIS: 53 DRLG TO 12564' TRIP OUT. TRIP BACK TO BTM. CIRC & COND MUD TO 9.5 PPG. TRIP OUT. TRIP IN W/ BIT %11. CUT DRLG LINE. TRIP TO 12500' WASH & REAM TO 12564' DRLG TO 12660' CBU @ TD DRLG TO 12972' ~ = TD. CBU. MW: 9.-6 VIS: 48 WELL ' MPI 1-15 OPERATION: RIG ' DOYON 15 PAGE: 3 05/15/93 (21) TD:12972' ( 0) 05/16/93 (22) TD'12972' ( 0) 05/17/93 (23) TD:12972' ( 0) 05/18/93 (24) TD:12972' ( 0) 05/19/93 (25) TD: 12972 PB: 0 LD BHA MW' 9.6 VIS' 45 SHORT TRIP, CBU. DROP TOTCO SURV, TRIP OUT. RU & LOG. RD, TRIPPING. CIRC & COND MUD. TRIP OUT FOR LINER. LD BHA. TRIPPING W/BIT MW: 9.5 VIS: 42 TRIPPING W/7" LINER. CIRC DP, TRIP. CIRC & PUMP PREFLUSH. TEST SURF LINES. DISPLC W/MUD, BUMP PLUG & SET HGR & PKR. REV CIRC. CUT DRLG LINE. MU BIT & BHA. REV CIRC MW: 9.5 VIS: 40 CIRC & TEST CASG. TAG CMT @ 12783. DRILL OUT CMT, LNG COLLAR & CMT. CBU. RIH W/CASG SCRAPERS. RIG REPAIR. RIH W/ LINER. REV CIRC & CNG OVER TO SW. RIH W/7" TBG MW: 8.6 VIS: 0 REV CIRC CHG TO SW. TEST CSG. LD SCRAPERS, RU W/L. LOGGING. RIH W/7" TBG. MOVE RIG TO 2-5/U-08 MW: 8.5 WBM FINISH RUNNING 7" 26# TBG. SPACE OUT & MAKE UP HANGER, TEST SAME. LAND TBG. NIPPLE DOWN BOPE & INSTALL SBMS METAL TO METAL 7" SEAL ADAPTER FLANGE & MASTER VALVE. NIPPLE UP TREE. TEST TREE TO 5000#. PULL 2 WAY CHECK. DISPLACE 100 BBL-DIESEL & U TUBE SAME. SET PACKER & TEST TO 3500#. TEST ANNULUS TO 3500#. INSTALL BPV, CLEAN CELLAR & PITS, SECURE TREE. RIG RELEASED @ 0130 HOURS 05/19/93. MOVE S~ME TO WELL 2-50/U-08. SIGNATURE: (drilling superintendent) DATE' AZ_I~JTH FRF.~.~ R~AR¥ TAB~ _~ TA~;£T I~ D:'T, ' ( E/-~ ) O, O0 MICit FILMEO ,. .Oil & Gas Cons. Commission Anchorage i-15/P-25 D£F~H DP'TH ft ft ft i00,00 0,0 I~.:~,00 450,0i 380,0 5i,4,65 3-:,6 5i6,65 5'77,04 80,4 5'3'7,04 e_:~.,; ~ 53.7 DEPAE%URE DISPLACEM. EN? at EY-W 0.32 0.47 0:32 0.44- 0,2~, 0,37 0,41 AZIMUTH 137,13 !33,79 121.87 114.54 DL9 deq/ lOOft 0,00 0,04 1.04 0.3~. 0,24 705.10 740 ~52 7~J ,45 878.98 974,02 1041,~ i072,34 !i01,2~ 117i,63 !2~$,56 54.4 705,0? 46,9 767, .~: 95.0 97~.75 67,7 I041,2~ lwl,/o 26,9 1i'X:,63 70,4 1!70,76 ~,,~ .... !259,42 O.AO .... 0,37 1o9,24. -0,2! 0,41.. 0,~4. ~:.,~o '"~ ¢: O, 47 . .~ ~.~ 1¢5,~ ~ -0,31 0,~ l,~; 106,17 1,20 ~ ~ 1, !,95 105.76 1,55 ~,7~ 1,53 t01,97 -0,53 87 ~:.29 3+32 !05,9i -_,~11 ~ 5,62 5,62 105,03 1,97 ~' ,C5,o~ 0.30 10,5~, d,A!. 1(~,57 -~,v,~ ^~ 11,1~_ 1!,56 ~- ~o !5.31 4,97 114,!4 -4.64 15.88. 16..~ 106.95 2.22 17,74 4.34 !22,3t -6.00 16.07 19,04 108.37 2.96 19,92 4,4i 120,52 -7.15 19,'75 21,19 !09,72 0.52 ~,54 4,81 1Zo,04 - 10,34 ..,,.,...~ ~r, 26,zc:,., , . ~,.,~ 1,04 32,S~ 4,02 1~,~ -!4,46 30,07 5~,37 115,~ 0,91 1269,42 13i3,03 136!,~ 1447,70 1453,3% 8,9 12~8,26 43,6 13ii,78 48,4 12~4),(~ 86,3 1446,22 5,7 1451,87 ~,~.'"'" 3,94 128,42 -14,63 [<~.56 2~,97 115,89 2,23 35,82 3,51 132,4i -16,68 32,71 36,71 117.02 1,23 3~.74 3,41 1Z7,~3 -16,5~ ~,92 39,56 1!8.0i 0,76 43,62 3~07 127,71 -21,55 38.79 44.37 119.06 0.40 43,~ 3.09 12~,52 -21,74 [~'.03 44.67 11~,12 0.86 i552.63 i647.79 1740.58 99,5 i55!,~ $5,0 1646,16 91,8 1738.,90 42,~ ~A ~ ' ..... _ ~,~5 ,20,~.; 1.~1 44,30 51,82 121,24 0,11 46,25 S4,63 122,17 0,20 47,46 56,40 172,69 1,0~ 46,57 57,97 123.09 0,57 ~o~n 37 2024,96 244iZi,46 22!5,48 2264,92 2385,54 2413,26 250~.65 260!.50 94,8 192&51 94,6 2022,89 96,5 2i!5,97 94,0 7212 ~ . ,~j 49,4 226!,35 47,2 2~08,07 73,4 2380.59 27,7 2407,94 95,4 ~.0i,72 92.9 2592.56 62,18 3,50 124,i9 -34,49 52,17 62.54 i23,47 1,60 68.72 4.57 !16,12 -37.78 57.95_, 69.17 123,10 1,26 ~,37 5,93 ilg,87. . -4!,95 65,72 77,97 i~_Z,JJ~ == 1,45 ,~ 123,3! -47,A7 74,96 8~,64. 122,46 1.57 ~ .. . 94,66 7,93 124.80 -51,~6 80,41 95,41 122,57 1,24 lOl,o~.qq A,~_ t2~,83. -55,17 i12,71 9,56 124.25 %1,65 117.41 !0.03 123,42 I34,&~ 10,~ 129,03 -74.53 · ~./, 12.86 126.17 85,89 102.¢r~ 122.72 0,89 ~5,31 113.51 122,90 1,65 ~,23 116,2~ 122.~ 1,77 113,16 135.50 ~ ~'~ 1~o,o, 1,40 128.11 154,54, 124.01 2.12 2697,60 2781,23 2676,16 .... 1.30 £7/_ 3570,56 96,1 26~6,03 83.6 2766,85 95,1 2946,94 99,3 ~D35,62 i76,i4 14,(~ i25,79 -100.~6 145,60 176,64 124,% 1,24 197,$4 i5,76 130.0~ -114,0~ 162,20 19~,27 i25,11 2.09 2~5,6& 1~.75 t37,[~6 -i~1:,56 1B2.40 226,07 126.21 =~7,~4 ~1,12 1~.69 -!57,68 ~ . ~/..'~ 1~7,67 ~.54 ~74,8~. 23,35 i37.95 -185,73 229.06 2%.89 127,04 2,2a ~-15/P-25 MEASUF.:~D i~Ff~VAL D~:TH 5~,x ;,~ c~. ~ 3!26,0.7 3--S~ ,83 9!,._. ~' '~-¢~._'¢~,y?' ""' '":'~ A '7' 9.~., 6 379A.TA O0.b., ~ ....... 3453,03 96,6 32~.i,63 ~547,0! 94,0 3462,56 9_$.'.~Y CA~LATICqNS **.~,~.~x~**** CI.E~L~: ARC S~T!~ IN~N, N/-S ft deg d.~ ft ~ !4 24+5! ~ a-~ -214-~. ~ =:~ 26~37 !34,!4 -243+23 416,96 ~ +8! o~ ~o -275 ~2,8~ 29+~ 135+43 -306+13 DEPAi;ff!}2 DISf'LA~.,'~ C at. E/-W ft ft Z54,7~ 333,15 28i,93 ~' ~= 313.59 417,12 [~5,7~ 46~+1~ ~n ~ 510 ~ AZIMU?H I30,12 130,7~ 13i,26 131.70 131,~0 DLS deo/ !0Oft 1,27 1,72 1,55 3,92 3745,23 363~+46 4022~34 4~,65 4213,4~ 4307+56 4ali ,16 ,~TJ+// 94,3 354! ,,.~- 103,9 86,2 92,7 37~8,99 96,2 38.41 94,3 ~"'~ 96,8 94,4 4(~6,82 93,3 41!4,31 5'IJ8 3~,99 l~ :A -37~,x5 62i+3~ 36,05 127+32 -4~5,81 A74,77 ~.'.+53 129,3! -441.97 "a' ^ 39 120,53 -477,41 796,13 42+C~ 130,49 -~=~,J,.~'n ~A 420,79 54,2+06 131,53 2,80 4~.4,17 621,54 131,13 1,%' 510+09 674,93 130,91 3,13 554,82 733,26 1~,,83 1.34 ./-42.75_ 796+2'? 130.~ 2,96 ~,88 44,37 1~,69 -S~,2,¢5 652,?? ~,I,(~ 928,77 44.+67 !29,79 -~5,45 704.~ 928.92 ~4,70 43+~ !~,,07 -647,76 755,05 994.84 i059,i2 43,39 130,41 -~,49+3~ 834,23 1~9,26 ....... · ~+¢~ o~,~, 1124,03 130,75 130,~ 130+~ 130,59 2,21 0,32 0,80 0.64 0.41 459!.27 4~89+45 4784,44 4880,94 49T.//.+00 ~,5 4L;52,~ 95,0 43'~a24 96.5 .4459,&0 96,! 4528.59 1190.t7 44.91 127.62 -773.02 · ~e,.¢..u,~ 44.29 128+82 -815.&6 1325,02 43,72 126,6i -856,02 !391,~3 44+05_.'- 126.72 -895,97 1458+79 44+48 i27+!4 _o~ 9~ 995.12 1190.30 i30.50 959,2~ 1259.!7 1~.37 10ii.47 1325.08 130.2~ 1065,13 139i.86 1~0.07 1118,72 1458,80 1~9,9~ 2,81 1.07 1,72 0.3-4 Jl$o 5~,0~ 5~.8! 5452 ~ 87,0 45~,89 99,3 4661,80 94,8 4727,4i %',7 47~5+06 95,0 4659,82 !519,44 44,03 t27.41 -973,02 1S~j,91 44,85 127.3~ -1015.21 16~.27 47.52 15¢0,.~ -1058,23 /ou,.J 47.07 130.76 -!!06+02 18¢~,,!1 47+04 I~,84 -!15i,4E ll&.02 1519.44 I29.52 1~2.29 1586.92 129.71 1275.41 I657.27 129.~ 133.0,99 1730+55 129,73 i3_~.66 18~).i2 129,77 0,57 0.84 3.79 0,46 0.07 5548.99 5644,7? 5739,65 5434+27 ~r, SG 6025.82 6124.32 6220.30 63!6,89 96,1 ~925,35 95,8 4990,89 94,9 5056,07 94,^ 512i '"~ ~.'.8 51o~,,~ 96.5 53~+q~ 96,0 5385,44 52.2 5420.82 44.4 S450+~: ~a,u.~. np i79,79 -1!96,~ .... ~z .~ ...... to~n qi 4A,M, 131,74 -I~2,Ai ~9,i? "~ 1977,79 46,40 li~,!9 214~,6i 46,40 131,12 -1378.83 2216,67 46,76 1~3+58 -1423,35 ~68.,E4 47.i8 124,27 -1470,66 2359,t9 47.39 130,&3 ~.,.oz 47.34 130.20 24~<~.24 47.35 131.06 -1~2,10 1437.~ 1870.45 129.79 1490.21 1940.32 129.&2 154i.98 2009.20 129,87 1594,13 2077,~1 129,90 1647,87 2148.63 129+92 1699.~. 2216.70 129.95 1.754.18 2286.71 !29.% 1807.76 2359.~ 129.95 1836.98 '239/.6,., 129.'~ 1&61,74 24~),2~ 1DC,,O0 0,80 1,54 0,69 ) ~. 0,68 0,5~. 0,47 0,49 0,89 1+43 6410.04 6505,47 6767,55 93.1 ~13.52 · 2Jlr, 7J+ _~.. 93.2 56~,8i 93,2 57(K~,7g ,~,/ 5764.,27 2499,!6 4~,13 126,07 -1605.99 2570,42 45,54 128.(6 -1649,94 2640+13 48,31 129,73 -!693,7i 2709.77 48,36 i30,44 -17~5,5'5 2781.32 ~.48 129.80 -1784,66 1914.~ 2497,2~; 129/79 i97i,02, o~v,,~, ~+ ~=,~ !27,'73 2025.28 2640,15 ,.o ,-,, . ££/+7£ 2078,57 2709+80 1~',91 21~.28 2781.~ 2,51 0,43 1,37 0,52 ., -15/P-25 ft ft ft 6?64,,.~7 9A.0... 588i, !I 7059,i3 94~4 ~s~,~ .*****:**~**** CtRCb%AR ARC TARGE.? STATION AZI~H LAT!TLE~.o- ft de9 deg ft 2842,3A. 48,9? !27,74 -,ozz,~ "~'" ~'" -,a · ~ , Vi4,J.:, 48.J~ 128.~ -1867.33 2984,~4 47.&! 129.46 -1911.45 2~S,59,~6 47,49 126,19 -1956, O0 · ., ,vo t2S',23 -2000,17 ~/-W ft ft 2!80,68 2~2,38 ~37,77 2914,54 ~92,53 29~4,85 ~!,,=0 oS 3059,07 .2402,98 3126,50 AZIMUTH deg 129,~9 199.',84 i29,82 129,80 129~/-7 DLS 0.e.~/ 10Oft 2,0I 0.6i 1,24 1 ~00 0,97 75~,57 ioof,gU W30.47 8i12,05 820?,55 96,6 '~'~' 94,6 627i,37 95,4 ~37,35 95,5 ~69,97 102,3 654i,43 94,9 A~,07 o~ 88,8 ~.70,07 97,5 672~,1~ 3197,2i CE,,~ 127,07 oooo,o~ 46,24 i2~,93 -~Zy.7! ~05,32 46,28 !28,26 -2i72,7g 3474,i5 46,01 128,82 -2215,67 a~4z./~ %.77 126.3~ -225~.43 3615.97 45.6~ 128.65 ~83,82 45,bS, !2&,2<; -2346,27 3-4,16,9~ ~6.1i 129.~. -2429,5i 2458,6i 3!97,2! i29,74 ~=~ =~ 3267,75 129,69 2565,i8 2536,37 129,67 2622,07 ~g~,3~~. ~ 119,65 2675,92 3474,15 129,62 2729,53 35~2,72 !29,~ 27~,,83 36!5,95 129,58 2840,c~ 3053,83 129,% 28S9,64 3747,1! 125:,54 2943,~6 3616,91 129,53 0,87 0,79 0,51 0,51 0.44 0,24 0,27 0.3i 1.21 82~6,63 840!,72 8470,~6 8591,~' 97.1 6805.51 ,.,1 &571,27 69,i 6918,87 24,0 6935,41 96,2 7(O1,87 2&&6,80 46,0I 13i,¢E~ -2474,75 ~555,% 46..,49 131,55 -2520,06 4uvo,po .o, 49i2~,81 -~.-¢3,73 ~322,9A.. 46,51 ~.~....~ -2565,~2_ ~3,5~,45 46,!0 I32,12 -2612,26 2997,15 ~56,80 129,55 30B5.93 4005,56 129,6! ~98,76 4022,96 129,62 3150,28 4092,45 129,67 1,00 0,66 1,32 i,47 0,45 8782, ~%0,11 8978,~g 9072,53 4i60,61 45,A9.. 131,60 4229,P.A... 45,29 lSd,AA.. 4298,24 44,~) !33,26 -2749,Cr?' 4'--' M /-.A ~,02 1.5~;, 19 -2796,50 ~.n.., ~.., 443! ,37 43.15 135,29 - 2:-2_4 2,22 3201,0~ 4160,6! 12'9,70 39sq.~ 4229,87 129,73 3~5'4,15 4296,24 129,76 3353.72 4366,67 129,82 c~:~.~,,,~,~ 4431,40 129,59 0,59 0,81 2,03 0,89 9!6i ='~ , _,~, 5%1,75 9456.6.3 95~5.fi.i 9552,53 9728.85 9926,87 10029,79 I01~,92 10218,95' !0314,19 !'-0410 ~ ".= I 74~-' 95,1 7552,2~ 95,1 7618,49 ~,0 7664~03 92,2 7746,18 83,9 7802,44 104,1 7872,43 93,9 797~,~4 96,! 8070,99 93,i 81-~ == 95,2 8!99,!9 96,0 82~,95 449i,72 42,76 135,91 -2885,57 4563,59 43,96 133,4! -2936,26 46[<~.3B 45.47 '~' ~ lo~,~,., -2961,78 ~98,60 i ~ ..... 3027,34 4736,44 47.12 129,94 -'~-".,9J~,O~.~n 4768,74 47,D3' i26,58 48~6,74 47,68 126,74 -3!~4,~.: ~7~,~ 47,86 126,29 -315i.01 497S,78 47 ~o 127,65 -3!97,34 5/J45,,~_, 47,4A. t28,21 -~¢¥,94"~"' 5t20,71 47,2! 12~,70 5191,i6 47 ~ ~,-. 5259.i5 ¢5,77 126,75 -3374.i3 5329.02 47.69 !27,38 -3417.22 5399,76 ? n . 4/,4C 128,48 -34.A0,74 34.42,?~ 449!,79 129,97 ..... ,. ~ .... 3542,63 46:<),50 130,09 3593,52 &698,74 130.11 3622,22 4736,58 130,ll '::47.23 47A,'-',, ~. 130.11 3701,10 46:~.~, 86 130,08 3751.09 4895.% 130.03 %!2,63 45'~,~,5 12'5' ~67,30 5045,11 129 3?26,56 5120,77 129',93 ,az 5191,~ i29,72 ~n~°,lE,~, 53~?,05 !29,86 4!45,03 5399,8i 129,86 0,65 2,00 1,77 1,16 2,53 2,30 1 '~ 0,40 0,99 0,47 0,43 0,47 0,5! 1,42 0,90 ....· '-.: ='"'.: ......, "<:_ '.:.-'5 .:: --_,:.:: "-'- ', '-'-~:-= 5478: 7_-'7: s: ....., :c- ':'27 ~57: - -': ........ :-, :'~, ~ ~ 42:::..:~, 5':_5.47: ~ 2': ',, _:';-....:'.: :...-:. z. ~c:=:= ::,:. '.:,"5.~.! 8z57 ,'.2"5' =:.:<0; ;77.' ~'-~.--~-;: ..... ':' ...... ': =' 4~i('.,,'5'2 =...;,C4.77:, i?o, 7: a'-.'.-.-:.-: s _- ....... -.-: .-~ iL: .~ 70 '='207 ,_,5 ......... .__ ~'--"- --'.; ..--v~..: ~::-,"5,~5 S,-:...::c;~:5:~ '~: ~: :---7,:3 -2.5:!'-.-_-',=2 --E;=.?,'_', , 7:: =" ....= i"-::,7~ :2.,7: """:: :.~ ...-_: ... ~:_ .... '.:.5.,::'..',' ............. ~5-: 55 i'-"': ~f-? _3.5 ::~ ~.f.:.? -,/': :.:.__ ~ ..=:'='_ =. r ,<.:_...:.., =~. _ :~-:,.:._ ~-, '~=. _ ,'. ALASKA OIL & GAS CONSERVATION COMMISSION Attn. HOWARD OKLAND 3001 PORCUPINE DR. ANCHORAGE AK, 99501. USA Date: 7 July 1993 RE: Transmittal of Data ECC #: 5959.00 Data: LDWG Dear Sir/Madam, Reference: 1-15/P-25 ~ END I COTT NORTH SLOPE, AK Enclosed, please find the data as described below: Tapes/Diskettes: Sent by COURIER LDWG TAPE & LISTER Run # 1 Received by: Please sign and return to: Atlas Wireline Services Petrophysical Services 5600 B Street Suite 201 Anchorage, AK 99518 Attn. Rodney D. Paulson Date: BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box'196612 Anchorage, Alaska 99519-6612 (907) 561-5111 June 10, 1993 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear AOGCC Representative, Attached in duplicate is detailed information regarding the enclosed well logs for the Endicott Field. Please contact me at 564-5225 if you have any questions. Sincerely, en?ne L. Haas or Technical Assistant !i JLH Enclosures xc: File 06.10 WELL NAME 3-03/J-33 3-41/K-39 3-351L-36 1-29/M-25 3-451M-39 2-14/O-16 ~'" '~ 4-08/P-27 J3--t t"l 2-12/Q-16 ici - oLo 1-63/T-pp I~.-It fl 1-51/v-20 DATE INTERVALS LOG NAME 5/23/9 3 13400'- 13670' PFC/CCL 5/1 5/93 13200'-13655' Pi::IODUCTION ~ING 5/22/93 11900'-12264' PRODUCTION LC)C.-~ING 5/24/93 13100'-14071' PDK- 100 5/20/93 29'-11848' PRODUCTK)N L.CGGING 6/1/93 10350'-10578' PFIODUCTE)N LOGGING 6/4/93 10350'- 10800' PRODUCTK)N ~ING 5/14/93 11950'-12960' DUAL LATEROLOG- MSFL 5/14/93 11950'-12960' · DLL-MSFL-GR SS'I'VD LOG 5/17/93 11700'-12897' CNL/G R 5/17/93 11700'-12897' ~IS~J~G R/CC L 5/19/93 13000'- 13676' PRODUC3X:)N LOGGING 5/27/93 10000'-10300' PFIODUCI'K)N LOGGING 5/27/9 3 9950'- 10318' PFIODI. JCI'K:)N LOGGING 5~26~93 12100'-12700' PI::K:Z)UCTION I_OC..-~ IN G 5~26/93 11400'-12200' GR/CCL 5/1 5~93 11300'-12500' PFC/CCL . 5116~93 12350'-12600' PFC/CCL 5/18~93 12350'-12600' PFC/CCL RUN NO COMPANY NAME ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS SCHtJ~BEFIC.-,ER ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS ATLAS MEMORANDUM ALASKA OIL AND GAS CONSERVATION COMMISSION STATE OF ALASKA to; David Johnstop~ Commissioner ~" date: May 20, 1993 file: 051593.doc thru: Blair E Wondzell ~~' subject: Petr Insp Supervisor from: ~u Gdmaidi Petr Inspector Rig BOPE Inspection Doyon Rig #15 BPX Well 1-15!P25 Duck Island Unit PTD 93-56 Saturday, May 15, 1993: I traveled to Doyon§ Rig #15 drilling well #1-15/P-25 on BPX's Endicott Facility in the Duck Island Unit. ! fou.n.d Rig !5 to be in go_od shape with al! BOP equipment in place and in apparent good working order. The rig and its surrounding area was clean and orderly. There were three hammer unions in between the choke manifold and the pit skid (they were in an obscure location). Mike Droudy (Doyon tool pusher) will order and install unibolts and notify an inspector when completed. Due to the cleanliness of the rig and its surrounding area, I complimented Rig 15's crew. Summary: The rig BOPE inspection of Doyon Rig #15 revealed three hammer unions in the choke system. attachments 2 DOUG AMOS STATE OF ALASKA AI_ASI~ ~.. _AND GAS CONSERVATION COMMISSION RIG [ BPS INSPECTION REPORT OPERATION: Drilling ~ Werkover~Compl. UIC DATE: ,3'--/ " Well Name: / --,' o-""/' f~- ,¢,.d'"" PTD# OdgContr~ctor: "J'b,o~,,2~' Rig# /,.d-- R_ep. C2/--~/~L=-,dc-¢ Operator: ~'/~ Rep.' /*.4 / ¢4"t~ ~b~) ~' V/ Rig Ph.# Loce~tion: Section ~ ~ T. / ~ ,~/ R. /~ r~ M. ii)/.i;i (A.) B.O.P. STACK YES NO N/A :!?~il;i (C.) MUD SYSTEM YES NO ?!;!!!i;~, Wellhead fig wkg press ~ ;i.'.2.:~b:i Pit level floats installed :i;;:2_ ;; Stack wkg p~ess 7( :.ii~i.0..'i. Flow r~te sensor :.3.:! Annular p~eventer ~' . ::,~;~i ' Mud ge,.s sepor~tor i;i~;:; Pipe rems X !;~i;i Uego, sser · ;;;;?,.;.; Blind ,-ams ~' .;i~i~; Separe. tor bypass ,,~ '!;:7...;.i Chke/kill line size~ ;i-".2..5.'.~, Choke line connections !~-8;;, ~:~.~:, All turns targeted ( chke & kill Ln.) '/'~/ ;;~¢i,~.d_ .p_ !~n_k ..................... .~_ ;,;';~; -'"'" 'h' '":'"!'"r'F'"'":'"]:F'£L:' -' ': "2'L F"'"'' · ""'" '' "" ...... i!::~ l.¢i~?alvalves (chke & kill Ln.) X . ?,i? (D.) RIG FLOOR YES NO N/A i,]:,! Connections (Flgd. Whd. Cl~mped ~ ¢-f.-i;~i~: K.elly cocks (upper. ie~'Cer, IBOP) ,,~ ;]i~,; Drilling spool ~ ii~; Floorvo. ives (de. rt, bell. oct.) -;!:~Flowl',lipple ~ i.T.3:§ Kelly& floor vaive wrenches :;! .... i~; Flow monitor ;,( ii:~.Drillers console (flow.monitor, /,~' i,!!:~; iControl lines fire protected ~ flaw rctte indicator, pit level / . ... :;i;~::~ (B.t CLOSING UNIT YES NO N/A .!~:..".4.].~!. Kill sheetup..zto.-date ,,~ !.:6[ 'Working pressure ,X~ ;i;~.~; Gas detedion monitors :1~?FMd level~(; (H2S & methane) / ;!:~;. Operating pressure ~(~ ii~.~i Hydre. ulic choke panel :]:9:Pressure gauges,~' :il;~:~i Choke me~'dfold :;2:24-way valves (actuators)~' ;!~.5.;; Flare/vent line X' . ;!;!; Blind rarrl, handle cover '/~ i!~,~i Ai' turns te.'geted ,,~ :~.:-'] Driller control panel )~ (do~mslream choke lines) Remote control panel .~;~:~ R. eser,/e pit tonkctge 2~! Firewall~ ii~.~: Personnel protedive equip, aval. :2.~; Nitlogen power source (backup) 2~' i~.~ii All Drillsite Supervisors Trained .~I~i Condition (leaks. hoses, ect.) X::~ ....... For Procedures !:~0.; H2S probes X~ .... ,._. /..~. ~i~!i;i Ric. t housekeepinr.,1 '¢ RECORDS: Date of Last Rig / BPS Inspedion ~ Dote of Lest BOP Test ~/¢-~ Resulling Non-Compli~nce ~ems: ~~ ~ Non-Complian~ not corroded & Reason: ~ Date Corrections Will Be ~mpleted: ~ BOPTest & Results Properly Entered On Doily Record? Kill Sheet Current? ~. Distribution: orig - Well File c- Oper./Rig c- D~t~b~se c- Tdp Rpt File c- Inspector FI-B22.×L¥ (~v. 12/~2) MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: David John~,~ Chairma~ THRU: Blair Wondzell, P. I. Supervisor FROM: Jerry Herring, ~{~'~ Petroleum Inspector DATE: FILE NO: SUBJECT: May 13, 1993 jh-rep42.doc BOP Test- Doyon 15 BP Exp., DIU, 1-15/P-25 Endicott Field PTD #93-56 Tuesday, April 27, 1993: I traveled to Endicott and witnessed a BOP test on Doyon 15 drilling MPI 1-15. The 13-3/8" surface casing was installed to 2,753 feet. The BOP Test Report is attached for reference. The BOP test started at 3:00 p.m. and lasted for 2-1/2 hours. All of the BOP equipment functioned well. One minor problem was discovered; the "closed" indicator on the remote control panel for the upper pipe ram did not function although the ram tested and proved closed. The electrician was called out the next day and a wiring problem was corrected. Tool pusher Mike Droddy was good company and kept the test moving smoothly. The rig was clean and in good shape. Access is tight round the rig due to the tight congestion on the Main Production Island. Summary: The BOP test on Doyon 15 lasted 2-1/2 hours and there was 1 failure. Attachment STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report 4/z OPERATION: DrLg: ~, Workover: DATE: Drig Contractor: ~)0~ ~ . ,_Rig No. t ~" PTD # ~- ~1.~ Rig Ph.#., Operator: ,~, ~'~.. ~ o~i ~Ft (A, ~ Rep.: WellName: ~N~)co~ ~ j_ ~57 e~- ~j RigRep.: Casing Size: )%~: Set~ ~'-~ Loca~on:Sec. 3~" T.{J~ R. Test: In,al ~ Weekly '..-: O~er Test MISC. INSPECTIONS: Location Gan.: ~ Housekeeping: (Gan) Reserve Pit Well Sign Drl. Rig BOP STACK: Quan. Annular Preventer I Pipe Rams Pipe Rams Blind Rams Choke Ln. Valves HCR Valves ?.- J 5~.~ Kill Line Valves Check Valve Test Pressure P/F I P i MUD SYSTEM: Visual Ala~'m mdp Tank ~/~ ,, h/,/t~ Pit Level Indicators ~' '~,,/ Flow Indicator Gas Detectors V' '~/ FLOOR SAFETY VALVES: Q.uan. Pressure P/F Upper Kelly / IBOP Lower Kelly /IBOP jJ Ball Type ,~(~,:~ /.,~,~.%~ Inside BOP CHOKE MANIFOLD: No. Valves. 17 No. Flanges Manual Chokes Hydraulic Chokes t Test Pressure P/F ! -t ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure System Pressure Attained Blind Switch Covers: Master: Nitgn. Btrs: -~ minutes~:~ sec. 3 minutes ~ sec. ,/ Remote: ,/' ~/~ ~F~,',~ Psig. ~'m~i~'~f"~ailUres i 'J""' 'Tesi Tim® ~Y2_ ~' "(~m "'N~r~'6'~r of Valves testeC~ .... i~aiie'd''' Equipment will be made within -~ days. Notify the Inspector and follow with Written or Faxed verification to the AOGCC Commission Office at: Fax No. 276-7542 Inspector North Slope Pager No, 659-3607 or 3687' If your call is not returned by the inspector within 12 hours please contact the P. I. Supervisor at 279-1433 REMARKS: Distribution: odg-Well File c - OperJRig c - Database c - Tdp Rpt File c- Inspector STATE .~NESS REQUIRED? YES NO 24 HOJJR NOTICE GIVEN YES,~ NO ! Waived By: FI-021L (Rev. 2/93) Boptst3 ALASKA OIL AND GAS CONSERVATION CO~IMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORA(3E, ALASKA 99§01-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 April 14, 1993 Bill Kirton Drilling Engineer Supervisor BP Exploration (Alaska), Inc. P O Box 196612 Anchorage, AK 99519-6612 Re .' Duck Island Unit/Endicott 1-15/P-25 BP Exploration (Alaska), Inc. Permit No. 93-56 Sur. Loc 1987'SNL, 2065'WEL, Sec. 36, T12N, R16E, UM Btmhole Loc. 1430'SNL, 1260'WEL, Sec. 6, TllN, R17E, UM Dear Mr. Kirton: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. The blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035; and the mechanical integrity (MI) of the injection wells must be demonstrated under 20 AAC 25.412 and 20 25.030(g)(3). Sufficient notice (approximately 24 hours) of the MI test before operation, and of the BOPE test performed before drilling below the surface casing shoe, must be given so that a representative of the Commission may witness the tests. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Sincerely, Original Signed By David W. Johnston David-~; Jonns~on Chairman BY ORDER OF THE COMMISSION dlf/Enclosure cc; Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 2O AAC 25.OO5 la. Type of work Drill [] Redrill Clllb. Type of well. Exploratory r-i Stratigraphic Test [] Development Oil [] Re-Entry [] Deepen1-11 Service [] Development Gas [] Single Zone [] Multiple Zone [] 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exploration BKB=56 feet Endicott Field/Endicott Pool 3. Address 6. Property Designation P. O. Box 196612, Anchorage, Alaska 99519-6612 ADL 47502 4. Location of well at surface 7. Unit or property Name 11. Type Bond(me 20 AAC 25.025) 1987' SNL, 2065' WEL, SEC. 36, T12N, R16E, UM Duck Island Unit/Endicott At top of productive interval 8. Well number Number 1157' SNL, 1588' WEL, SEC. 6, T11N, R17E, UM 1-15/P-25 25100302630-277 At total depth 9. Approximate spud date Amount 1430' SNI~ 1260' WEL, SEC. 6, T11N, R17E, UM 4/15/93 $200,000.00 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property15. Proposed depth (MD and TVD) property line , . ADL 312828-1430' Tee~ 1-11/SN-04-9'@ 499' MDfeet 2560 13278' MD/10326' TVDfeet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2)) Kickott depth 1900 feet Maximum hole unpile 45.50 Maximum surface 3900 psig At total depth (TVD) 10000Y4890 psig 18. Casing program Setting Depth s~ze Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 30" Struct. Drive Pipe 94' 37 37' 131' 131 Drive 16" 13-3/8" 68# NT80C Butt 2735' 36' 36' 2771' 2756' 550 sx "E"/400 sx "G"/250 sx "C" 12-1/4" 9-5/8" 47# NT80S NSCC 10637' 35 35' 10674' 8500' 12-1/4" 9-5/8" 47# NT95H NSCC 1720 10674 8500' 12394' 9706' 1000 sx Class "G" 8-1/2" 7" 29# NT80S NSCC 1134 12144 9531' 13278' 10326' 280 sx Class "G" 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured dep~ True Vertical depth Structural Conductor Surface Intermediate .A.P!~ - ~ Production · Liner ^Jask~. Oil & Gas Cons. Perforation depth: measured Anchorage true vertical 20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling program[] Drilling fluid program [] Time vs depth pict [] Refraction analysis [] Seabed report[] 20 AAC 25.050 requirements[] 21 I hereby certi that~the fo egoing is true and correct to the best of my knowledge Signed ,//.'~ ~/./..~/, Title Drilling En~lineer Supervisor Date ~//~/"~_~ Commission Use Only Permit Number IAPI number IApproval date ISee cover letter ~Z---~'~ 150- o~ ¢- ~-.~ ~ ~ / I ./-/.,-/~f,.. ¢ .~ Ifor other requirements Conditions of approval Samples required [] Yes [] No Mud Icg required []Yes ~ No Hydrogen sulfide measures [] Yes .~ No D~r,ectiona,,_~l survey required ~ Yes [] No Required working pressure for BOPE [] 2M; ,J~3M; /1~5M; []10M; I-]15M; Other: Original Signed By by order of Approved by David W. Johpst~n Commissioner tne commission Date ,...,¢~', Form 10-401 Rev. 12-1-85 Submit in triplicate MUD PROGRAM: MPI 1-15/P-25 MUD SPECIFICATIONS- S'URI.'AC]~ HOLE Mud Properties Mud Wr (ppg) Funnel Viscosity YP (lbs/100 f~2) 10 sec Gel (lbs/100 ft2) 10 rain Gel (lbs/100 ft2) API Fluid Loss (cc/BO rain) Hardness (rog/l) Spud to 2000' TVD At Csg Point 8.5-9.5 ppg 8.5-9.5 ppg +/- 300 sec/qt < 100 sec/qt 40~(} 20-40 30-60 15-20 60-80 20-30 8.$-10.O 8.5-:1.O.0 15-25 15-25 < 200 < 200 MU]D SPEC.~!CATIQNS- 1NT~ ._L~JATE ltOLI:!. Surface casing shoe to top of the Kekiktuk Formation: LSND GeVWater System Mud Properties Mud Wt (ppg) YP (lbs/1 O0 ft2 ) 10 sec Gel (lbs/100 ft.2) 10 mln Gal (lbs/1 O0 ft2) PH APl Fluid Lo~ (cc/30 mtn) TO LCU At Cs$ Point 9.$-9.8 ppg 9.8-10.3 ppg 10-t5 10-15 5-10 5-10 20~30 20-30 8.5-10.0 8.5-10.0 15-tO $-10 MUD SPECIFICATIONS- PRQDUCTION HOLE Watered back LSND GeVWater System from the intermediate hole Mud Properties Mud W t (ppg) YP (lbs/100 ft2) 10 sec Gel (lbs/100 ft2) 10 m_in Gel (lbs/100 ft2) PH API Fluid Loss (cc/30 rain) 9.0-9.8 ppg 8-13 $-10 7-15 8.5-10.0 6-8 I ECEi'VED APR 1 z 19,93 Alaska Oil & Gas Cons. Commission Anchorage DOYON RIG #15 MUD PIT SCHEMATIC RECEIVED APR 1 ~ 1993 Alask~ 011 & Gas Cons. Commission Anchorage CUTTINGS CONVEYOR ' DEGASSER MIX PIT TANK DESANDER PIT MUD CLEANER TANKi SUCTION TANK PILL 235 BBLS 115 BBLS 2".0 BBLS 155 BBLS 235 BBLS PIT 101 BBL~ HOLE FILL TANK 90 BBL$ EQUIPMENT UTILIZED: 2 SETS OF BRANDT TOTAL FLOW SHALE SHAKERS 1 -DEMCO 3- 12" CONE DESANDER 1: TRIFLOW 16 - 4" CONE MUD CLEANER 1- DRILCO DEGASSER 1- PIONEER MARK II CENTRIFUGE 1 - DRECO POOR BOY DEGASSER 2- PIONEER S-BO0 SIDEWINER MUD HOPPERS R'ECEIVED APR 1 31993 Alaska.Oil .& Gas Cons. Commission Anchorage PROPOSED DRILl,lNG AND COMP!,..FrION PROGRAM ~NDICOTT MPI 1-15/P-2S PROCEDURE 1) MIRU Doyon 15 Drilling Rig. N/U diverter and function test same. 2) Drill 16" hole to surface ca~ing point. Run and cement surface casing. Nipple up BOPE and test to 250 psi ,(low test) and 5000 psi (high test). 3) P/U 12-1/4" BHA and RIH. Test casing to 3500 psi for 30 minutes. Drill 10' of new hole and perform leak off test. 4) Drill 12-1/4" hole to casing point. 5) .MU and run 9-5/8" casing and cement as per well plan. 6) RIH w/8.1/2" BHA and drill through reservoir to TD. 7) AU and run E-line logs. 8) MU 7" liner on 5" DP. KIH to TD. Cement same. Set liner hanger and packer. Circulate excess cement from well bore. POII. 9) MU casing scraper and clean out 7" liner. 10) Run 7" L-80 tubing and packer assembly with SSSV. Freeze protect with diesel. Test tubing and casing to 4000 psi. 11) NU and tree and test to 5000 psi, Release drilling rig, Anticipated BHP: Maximum Anticipated gut/ace Pro..~sure: Planned Completion Fluid: 4000-4900 psi & 9660' 'IYD SS 3500-4000 psi ~ 9850' '[VD SS 4900 psi @ 10050' TVD SS 3934 psi 8.6 ppg Filtered Sea water Notes: a. The drilling program and surface system will conform to the regulations sar. for'th, in 2OACC,25.003. b. Maximum surface pressure is based on BHP and a full column of gas to TD (0.10 psifft). c. Based on Endicott previous logs, no potential productive zones are anticipated above the Kekiktuk formation. d. No potential hazardous levels of H2S are anticipated in this well. ENDICO'I-r PRELIMINARY WELL PL Well: 1-15/P-25 Island: Main Production Island RT Elev. AMSL: 56 Rig: Doyon #1 5 BPJ100': 2 Location Surface: X= 259,141 Y= 5,982,425 1987' SNL, 2065' WEL, Sec. 36, T12N, R16E Target: X= 264,361 Y= 5,977,807 1157' SNL, 1588' WEL, Sec. 6, T11 N, R17E Est. Spud Date: February '92 Operation Days: 31 Max. Angle: 45.46 KOP (BKB): 1900 Target Dep.' 6,971 Target Dir.: . ..S 50.3" E Item TVDss -I-VD BKB MD BKB DEPARTURE 30" Drive Pipe 75 131 131 Base Permafrost 1,41 0 1,466 1,466 0 13-3/8" Casing 2,700 2,756: 2,771 184 E O B 3,884 3,940 4,173 908 9-5/8" NT80S Casing 8,444 8,500 10,674 5,542 Top Tuffs 8,840 8,896 11,239 5,944 Top HRZ 9,410 9,466. 12,051 6,523 9-5/8" Packer 9,440 9,496 12,094 6,554 7" Liner Top 9,475 9,531 12,144 6,590 Base HRZ/Top Put River 9,650 9,706 12,394 6,767 9-5/8" NT95HS Casing 9,650 9,706 12,394 6,767 Top Kekiktuk / Top Zone 3C 9,660 9,716 12,408 6,777 GOC 9,850 9,906 12,679 6,971 Target 9,850 9,906 12,679 6,971 Top Zone 3B 9,850 9,906 12,679 6,971 Top Zone 3A . 10,050 10,106 12,964 7,174 O W C 10,185 10,241 13,156 7,311 Top Zone 2B 10,201 10,257 13,179 7,327 Total Depth 7" 29# Liner 10,270 10,326 13,278 7,397 Logging Program' Open Hole: Final: Cased Hole: 7" Liner: RUN 1' DLL/MSFL/GR RUN 2: LDT/CNL/GR RUN 3' RFT 5-10points CET/CBT/GR/CCL Gyro survey from PBTD to surf~k'~-~' ;Jil & t~a.~.~ ,,,u,,.:,. ,~,,,"' '- CBT in 9-5/8" casing Well ......... : 1-15/P-25 (P1) Field ........ : ENDICOTT Computation..: MINIMUM CURVATURE GREAT LAND DIRECTIONAL DRILLING, INC. Corporate Office 1111 East 80th Avenue ~ ~.~? ~ ~ ~ ~ Anchorage, AK 99518 ~ ~ ~ii ~ ~ (907) 349-4511 Fax 349-2487 DIRECTIONAL WELL PLAN for PRUDHOE BAY ~~ ~ ~0i]S~~(;~!~k~ ~n~ Prepared ..... :~' 10/16/92 Section at...: S,50.33,E KB elevation.: 56.00 LEGAL DESCRIPTION X ASP ZONE 3 Y Surface ...... : 3292 FSL 2065 FEL S36 T12N R16E UM 259140.60 5982425.03 Target ....... : 4123 FSL 1588 FEL S06 TllN R17E UM 264361.25 5977807.28 BHL .......... : 3850 FSL 1260 FEL S06 TllN R17E UM 264681.32 5977524.52 PROPOSED WELL PROFILE STATION IDENTIFICATION KB NUDGE KOP 1.5/100BLD END 1.5/100 BUILD NUDGE DROP !/100 BASE PERMAFROST END !/100 DROP KOP BUILD 2.0/100 SURFACE CASING · . '--LDD (c)92 115P25 131.36 12:16 PM 2) PLEAS INCLN VERT-DEPTHS SECT DIRECTION REL-COORDINATES DL/ DEPTH ANGLE BKB SUB-S DIST BEARING FROM-WELLHEAD 100 0 0.00 0 -56 0 N 0.00 E 0 N 0 E 0.0 500 0.00 500 444 0 S 50.33 E 0 N 0 E 0.0 600 1.50 600 544 1 S 50.33 E 1 S 1 E 1.5 700 3.00 700 644 5 S 50.33 E 3 S 4 E 1.5 800 4.50 800 744 12 S 50.33 E 8 S 9 E 1.5 1100 4.50 1099' 1043 35 S 50.33 E 23 S 27 E 0.0 1200 3.50 1199 1143 42 S 50.33 E 27 S 33 E 1.0 1300 2.50 1298 1242 48 S 50.33 E 30 S 37 E 1.0 1400 1.50 1398 1342 51 S 50.33 E 33 S 39 E 1.0 1468 0.82 1466 1410 52 S 50.33 E 33 S 40 E 1.0 1500 0.50 1498 1442 53 S 50.33 E 34 S 41 E 1.0 1550 0.00 1548 1492 53 S 50.33 E 34 S 41 E 1.0 1900 0.00 1898 1842 53 S 50.33 E 34 S 41 E 0.0 2000 2.00 1998 1942 55 S 50.33 E 35 S 42 E 2.0 2100 4.00 2098 2042 60 S 50.33 E 38 S 46 E 2.0 2200 6.00 .2198 2142 2300 8.00 2297 2241 2400 10.00 2396 2340 2500 12.00 2494 2438 2600 14.00 2591 2535 69 S 50.33 E 44 S 81 S 50.33 E 52 S 96 S 50.33 E 62 S 116 S 50.33 E 74 S 138 S 50.33 E. 88 S 53 E 2.0 62 E 2.0 74 E~ 2.0 89 E 2.0 106 E 2.0 2700 16.00 2688 2632 2771 17.42 2756 2700 2800 18.00 2784 2728 2900 20.00 2878 2822 3000 22.00 2971 2915 164 S 50.33 E 105 S 184 S 50.33 E 118 S 193 S 50.33 E 123 S 226 S 50.33 E 144 S 262 S 50.33 E 167 S 126 E 2.0 142 E 2.0 149 E 2.0 174 E 2.0 201 E 2.0 3100 24.00 3064 3008 3200 26.00 3154 3098 3300 28.00 3243 3187 3400 30.00 3331 3275 3500 32.00 3416 3360 301 S 50.33 E 192 S 343 S 50.33 E 219 S 388 S 50.33 E 248 S 437 S 50.33 E 279 S 488 S 50.33 E 312 S 231 E 2.0 264 E 2.0 299 E 2.0 336 E 2.0 376 E 2.0 ~15/P-25 (P1) PROPOSED WELL PROFILE 10/16/92 Page 2 STATION IDENTIFICATION END 2.0/100 BUILD TOP TUFFS TOP HRZ BASE HRZ CASING POINT TOP PUT RIVER TOP ITKILYARIAK TOP KEKIKTUK TOP ZONE 3C EST GOC TARGET TOP ZONE 3B TOP ZONE 3A EST OWC TOP ZONE 2B TD EST TOP T~ MEAS INCLN VERT-DEPTHS SECT DIRECTION REL-COORDINATES DL/ DEPTH ANGLE BKB SUB-S DIST BEARING FROM-WELLHEAD 100 3600 34.00 3500 3444 3700 36.00 3582 3526 3800 38.00 3662 3606 3900 40.00 3740 3684 4000 42.00 3815 3759 543 S 50.33 E 346 S 600 S 50.33 E 383 S 660 S 50.33 E 422 S 723 S 50.33 E 462 S 789 S 50.33 E 504 S 418 E 2.0 462 E 2.0 5O8 E 2.0 557 E 2.0 607 E 2.0 4100 44.00 3888 3832 857 S 50.33 E 547 S 660 E 2.0 4173 45.46 3940 3884 908 S 50.33 E 580 S 699 E 2.0 11238 45.46 8896 8840 5944 S 50.33 E 3795 S 4575 E 0.0 12051 45.46 9466 9410 6523 S 50.33 E 4164 S 5021 E 0.0 12393 45.46 9706 9650 6767 S 50.33 E 4320 S 5209 E 0.0 12393 45.46 9706 9650 6767 S 50.33 E 4320 S 12393 45.46 9706 9650 6767 S 50.33 E 4320 S 12407 45.46 9716 9660 6777 S 50.33 E 4326 S 12407 45.46 9716 9660 6777 S 50.33 E 4326 S 12407 45.46 9716 9660 6777 S '50.33 E 4326 S 5209 E 0.0 5209 E 0.0 5217 E 0.0 5217 E 0.0 5217 E 0.0 '12678 45.46 9906 9850 6970 S 50.33 E 4450 S 5365 E 0.0 12678 45.46 9906 9850 6970 S 50.33 E 4450 S 5365 E 0.0 12678 45.46 9906 9850 6970 S 50.33 E 4450 S 5365 E 0.0 12963 45.46 10106 10050 7174 S 50.33 E 4579 S 5522 E 0.0 13156 45.46 10241 10185 7311 S 50.33 E 4667 S 5627 E 0.0 13179 45.46 10257 10201 7327 S 50.33 E 4677 S 5640 'E 0.0 13277 45.46 10326 10270 7397 S 50.33 E 4722 S 5694 E 0.0 10351 10295 · . ,~GLDD (c)92 115P25 B1.36 12:16 PM 2) PRUDHOE BAY DRILLTNG I i 5/?-25 (Pi) VERTTCAL SECTTON TVD Scale · ~ inch = ~20~*~.~,~ ' !~ Dep Scale.' J inch = :1200 feet Drawn ' 09/24/92 ~'~:'~ '- ~ ~..,,~ ~ ~ '0 A!as~(a 0[i &~,~.,.- ...... Cons. ,,u~,~,, ....... Narker Identification MD BKB SECTN INCLN 0 0.00 0 0.00 ~2 4.50 25 4.50 53 0.00 53 0.00 9O8 45.~6 I I A) KB 0 0 B) NUDGE KOP 1.5/JOOBLD 500 500 C) END ~.5/]00 BUILD 800 800 DJ NUDGE DROP 1/100 1100 1099 E) END 1/100 DROP ~550 ~548 F) KOP BUILD 2.0/100 1900 ~898 G) END 2.0/100 BUILD 4173 3940 I I ! I I I I il I 5°0° t, ',, i I!!!'it 55001!!!~~ 7~00 ,, ~, ; I 5400 !i~i~ ! I I I I I I I, I i i i I t I i i I I I HI CASING POINT I) TARGET J} TO t I I I i I ! I I~,,;1 : i i i I I I ! I I I I I ! I !l!i~li,i. i ! t i : ; I I I I i I 12393 9706 6767 45.46 ~2578 9906 6970 45.46 i3277 ~0326 7397 45.46 I illllllll~lil I I I I II Illllll I lilllll ! : II 1tli111 I : II IIIIII1! !Ii ii iiii IIII i 66OO 72OO i I i i 7800 I ' ~ I I I I i I ~'' '_'_!_'-L!±J .... ' ' ' , r r ? ~,-q-l-r,- f ? -i-i- i- -m-:- -;-i , , : , , , ~?-',~-t-"-Ff -, !-~ : j , , , I- I I i I I i I i I I I t I I I I I I 2400 30oo 35o0 4200 4800 5400 6000 Section DeDaptune PRUDHOE BAY DRTLLZN6 ~1 ~o~ ~o~ ,.~,oo~o ~oo o~ o ~ ~1 ~o ,.~,oo ~o ~oo ~ ~ ~ PLAN VIEN 0) NUDGE DROP ~/~00 ~00 ~3 S 27 E~ '" E} E~O ~/~00 D~OP ~550 3~ S 4~ E CLOSURE ' 7397 ft a~ S 50.33 E F} KOP BUILD 2.0/JO0 J900 34 S 4! E 6) ENO2.0/JOOSUZLD 4~73 580S 699E OEOLZNATZON.' 30.00 E H) CASING POINT ~2393 4380 S 5209 E :SCALE · ! ~nch = ~000 feet I) TARGET ~2578 4450 S 5365 E J) ID 13277 4722~~3~I,~/=~'=% ~ ~F ~ DRAWN '09/24/92 '~'~ *-G!99~ Stoa2 Land ~Jre£tYona] _ ,,, III! i, i, ',.,.i.=.~.i,,. ,,,, ..,, ' ' = i,,,ilI ii,, ,, ,,,,,, = ,,., I "i " "III I1, " II iii, " .. o_~,,,~ ,, II,., . 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" ;LDO (c)92 L1~25 Bi.35 2:47 PH 2} Great Land birectional Drilling, Inc. Collision Avoidance Analysis Planned Well' 115P25 Pad' MPI Field' NSLOPE Existing Well 250U08 159V20 212Q16 266SAGSW 101J19G !05020G !09J18G lllSN4G ll7SN2G !21K25G !25N22G 127P20G !29M25G 135025G !37P24G !39P17G !41023G t43P26G !45Q26G i47Q21G ~9P21G !55R25G !57R23G !63T22G !67T20G =69V!9G 202P18G 204M19G 206J22G 208K16G 214016G 216M16G 2!SL16G 220L!5G 222L14G 226N!4G 228Pi9G 230009G 232SN3G 234P14G 236014G 238SN1G ~g2P13G 244R12G 246Q15G 252S14G 254Q12G 258S09G 262Q17G 264U10G ~68S17G 270U15G =01SG7G 502SG10G 09/24/92 11'34'39 Closest Approach Sep Depth min ft TVD ft MD ft 100ft [MD's] 25ft Warning band Serious band Start End Start End 270 0 0 260 500 500 170 0 0 336 0 0 56 712 712 31 726 727 19 63 63 9 499 499 20 208 208 40 1 1 44 2089 2091 70 119 119 79 454 454 140 0 0 150 1 1 159 820 821 170 0 0 132 5023 5717 188 972 973 200 219 219 206 548 .548 239 963 964 248 395 395 280 ! ! 297 2061 2062 305 1497 1499 180 476 '476 177 496 496 164 1996 1998 170 554 554 170 401 401 170 370 370 170 490 490 171 498 498 175 443 443 180 127 127 183- 491 491 188 471 471 189 496 496 196 491 491 220 496 496 223 493 493 240 481 481 247 408 408 254 401 401 277 489 489 286 61 61 302 1 1 318 164 164 326 484 484 344 493 493 353 314 314 1612 507 507 1614 7146 8740 1 2310 1 2382 1 1772 1 1708 1 1833 1 2423 0 2638 1 2036 ! 2240 1 620 1 952 1 904 503SNgG 1651 483 483 DI01G 17387 1564 1566 DI02G 17393 1545 1547 DI03G 22863 1560 1562 SAGD1G 18802 24 24 SAGD2G 16260 18 18 SAGD2AG 16260 18 18 SAGD3G 8157 30 30 SAGD4G 7103 3756 3902 SAGD5G 30608 3039 3065 SAGDSG 13672 507 507 SAGDllG 28377 9562 12184 SD311016 67253 1641 1642 SD311116 40321 29 29 11'34: 39 ended' 11:54:29 started: 1-15/P-25 (MPi) Casing Design Specifications SURFACE CASING 13-3/8" 68#/FT NT-80CYHE BTC CASING BURST COLLAPSE PBYS (#) TJYS (#) NT-80CYHE 5020 2260 1556000 1585000 Burst Pressure Calculation Burst rating based on shutting in the well on a gas kick equivalent to the LOT (14.0 ppg) at the surface casing shoe. LOT (ppg) TVD (FT) SIPRESSURE 1 4 2756 2006 Burst S.F. 2.50 Collapse Calculation Coliapse rating based on losing returns until the fluid level is below the surface casing shoe Mud weight behind the surface casing is 9.5 ppg Mud Wt. (ppg) TVD (FT) Collapse press 9.5 2756 1361 Collapse S.F. I. 66 Tension Calculation Based on full string weight in mud Casg Wt. (#/ft) MD (FT) 68 2771 PBYS Tension S.F. 9.66 Mud Wt. 9.5 ppg TJYS 9.84 String Wt. (#) 161068 1-15/P-25 (MPI) Casing Design Specifications Production Casing 9-5/8", 47#,NT-80S and NT-95HS,NSCC Casing GRADE BURST COLLAPSE NT-80S 6870 4750 NT-95HS 815 0 508 0 PBYS (#) 1086000 12890O0 TJYS (#) 1161000 1273000 Burst Pressure Calculation Burst rating based on have a tubing leak on top of full column of fluid Worst case will be at the surface, which has no back up gradient. srTP 39OO Burst S.F. Burst S.F. I .76 (NT-80S) 2.09 (NT-95HS) Collapse Calculation Collapse rating based on annulus being evacuated due to gas lift Mud weight behind the casing is 10.2 ppg Gas Grad. Mud Wt. (ppg) TVD (FT) (psi/ft) 10.2 9706 0.1 Collapse S.F. 1.1 4 (NT-80S) Collapse S.F. 1.22 (NT-95HS) Collapse press 4177 Tension Calculation Based on full string weight in mud Casg Wt. (#/ft) MD (FT) Mud Wt. 47 12394 10.2 PBYS TJYS Tension S.F. 2.21 2.36 Tension S.F. 2.62 2.5 9 String Wt. (#) 491703 (NT-80S) (NT-95HS) 1-15/P-25 (MPI) Casing Design Specifications PRODUCTION LINER 7", 29#,NT-80,NSCC Casing GRADE BURST NT-80 8160 COLLAPSE PBYS (#) TJYS (#) 7020 676000 746000 Burst Pressure Calculation Burst rating based on formation pressure on top of 9.7 ppg fluid SITP Fluid wt (ppg) back up (ppg) Burst Pressure 3900 9.5 9.7 3808 Burst S.F. 2.1 4 Collapse Calculation Collapse rating based on annulus being evacuated due to gas lift Mud weight behind the casing is 9.7 ppg Gas Grad. Mud Wt. (ppg) TVD (FT) (psi/ft) Collapse Press 9.7 9645 0.1 3900 Collapse S.F. 1.80 Tension Calculation Based on full string weight in mud Casg Wt. (#/ft) MD (FT) 29 1134 Mud Wt. String Wt. (#) 9.7 27759 Tension S.F. PBYS TJYS 24.35 26.87 DOYON 15 13 5/8" 5,000 psi Stack 9.00 4.65 3.00 2.00 2.00 1.85 "' RKB '~ ! I HYDRIL 5" PIPE RAM BLIND RAM KR TC') RF RIt i FLO~ 11.32 14.32 R 16.32 MUD CROSS 4 1/2" x 7" VARIABLE PIPE RAM 20.17 39.05 13.95 4 FEET ABOVE GROUND LEVEL · SUI--, CE ,-~OLE DfVERTF__,~ SYSTEM ...... Two lines venling 90 deg. apart in directions that ensure safe down wind venling, and ex- tending to a point at least 100' from any potential source of Jgnilion. __ .~~_10' Full Opening Valves 1-~ ...... 35' or as required Dresser Sleeve 10' Diverter Une 1. All pipe connections 150¢. ANSI Flanges or welded connections and secured to prevent mevemenL 2.. Manual 10' full opening valves mechanically c..onnected to ensure that one valve is fail-sale open at. all limes. 3. All tums are 90 deg. and targeted. 10' Full opening bali valve w/Hydraulic Actuator Cellar 20' Dived. er Sl:x:~ol w/10' Side Outlet MF_.M l~/g0 CEMENT PROGRAM -HALLIBURTON 13 3/8" SURFACE CASING CASING SIZE: 13 3/8", 68# CIRC. TEMP: 40°F LEAD CEMENT TYPE. Type 'E' Permafrost ADDITIVES' retarder WEIGHT: 12.0 ppg YIELD:2.17 ft3/sx APPROX #SACKS: 550 MIX WATER: 11.63 gps THICKENING TIME' 5+ hrs TAIL CEMENT TYPE: Premium ADDITIVES: 2% Calcium Chloride WEIGHT: 15.8 ppg YIELD'1.16 ft3/sx APPROX #SACKS: 400 THICKENING TIME: 4 hrs MIX WATER: 5.00 gps TOP JOB CEMENT TYPE' Type 'C' Permafrost ADDITIVES: retarder WEIGHT: 15.6 ppg YIELD'0.94 ft3/sx MIX WATER' 3.5 gps APPROX #SACKS: 250 SPACER_' 100 bbls fresh water ahead of lead slurry. The mixing temperature should be as cold as possible to prevent acceleration-approximately 35-40F. CEMENT VOLUME 1. Lead slurry + 400 sx Tail slurry w/40% excess over gauge hole. 2. Top job volume 250 sx. CASING SIZE' 9 5/8", 47# CIRC. TEMP 135°F LEAD 9 5/8" INTERMEDIATE CASING CEMENT TYPE; Premium ADDITIVES: 0.5% CFR-3 (Dispersant) + 3% Econolite (Extender) + 0.4% Halad-344 (Fluid Loss) WEIGHT: 11.0 ppg YIELD:3.24 ft3/sx MIX WATER: 20.4 gps APPROX #SACKS: 800 PUMP TIME: 5+hrs TAIL CEMENT TYPE: Premium ADDITIVES: 0.2% CFR-3 (Dispersant) + 0.2% Halad-344 (Fluid Loss) + HR-5 (Retarder) WEIGHT: 15.8 ppg YIELD:l.15 ft3/sx MIX WATER: 5.0 gps APPROX #SACKS: 200 PUMP TIME: 4 hrs Retarder (HR-5) concentration will be based on actual lab tests. ,~PACERS.' Pump 20 bbls ARCO Preflush; 50 bbls ARCO spacer @ 11 ppg. OTHER CONSIDERATIONS' Continuously mix lead and tail slurries. ~ E (E~V E D Displace at 12-15 bpm with rig pumps. ~ ~ CEMENT VOLUME 1. Lead Slurry based 90% of hole volume to surface casing shoe. 2. Tail Slurry to 500' above shoe w/30% excess. 7" LINER CASING SIZE; 7", 29# CR-13 CIRC. TEMP: 140° F CEMENT TYPE: Premium ADDITIVES: 0.2% CFR-3 (Dispersant) + 2% KCL (clay control) + 0.9% LAP-1 (Powdered Latex) + 0.3% Econolite (Extender)+ 0.4% Halad-344 (Fluid Loss) + 0.01gps Stabilizer 434B (Surfactant) + 0.01 gps D-AIR 3 (Defoamer) + HR-5 (Retarder) Retarder (HR-5) concentration to be based on actual lab tests. WEIGHT: 15.7 ppg YIELD:1.19 ft3/sx MIX WATER: 5.12 gps APPROX #SACKS: 280 THICKENING TIME: 3 hrs +45 min @surface PREFLUSH'. 20 bb!s ARCO preflush ~PA(~ER.' 50 bbls ARCO spacer, weighted 1ppg above MW. OTHER CONSIDERATIONS: Batch mix the cement slurry. Perform fluid loss test on the batch mixed slurry. Fluid loss should be 40cc or less. Displace @ 8-10 bpm. LINER CEMENT VOLUME 1. Open hole (8 1/2" X 7") annulus + 75% excess. 2. 7" 26# casing capacity below landing collar (80 feet). 3. 250' liner lap (9 5/8" x 7" liner) 4. 200' of cement on top of the liner in the 9 5/8" casing (without DP in hole). J.L. Hupp April 5, 1993 11 _~. -- ENDICO'i-r PROPOSED DIAGh~ WELL 1-15/P-25 (MPI) NON-FREEZING FLUID TVD (BKB) MD (BKB) 30" DRIVE PIPE BASE PERMAFROST -- SSSV KOP ( DIR: S 50.3° E; ANGLE: 45.5°) 13-3/8" 68#/FT NT-80CYHE BTC 131 FT 131 FT 1466 FT 1466 FT 1550 FT 1550 FT 1900 FT 2756 FT 2771FT BOTTOM OF FREEZE PROTECTION (ESTIMATED) 3000 FT TOP OF 9-5/8" CEMENT (ESTIMATED) 3700 FT 7", 26#/FT L-80 TUBING WITH 7" TAILPIPE 9-5/8" 47#/FT NT80S NSCC 8500 FT 10674 FT 9-5/8" PACKER 9496 FT 12094 FT 7" LINER TOP 9531 FT 12144 FT 9-5/8" 47#/FT NT95HS NSCC 9706 FT 12394 FT PLUG BACK TD 7" 29#/FT NT-80S NSCC LINER 10326 FT 13198FT 13278 FT P0/9-25-92 1-15 CivlT.XLS i State: 'v/ell: Field: State Permit 1 - 15/1='-25 Endicott 98.-56 Erlg~rleeE "¢¢ork Sheet: Date: Cement Volume 4/8/93 Casing Type Casing Size -Inches Casing Length - Feet Hole Diarnete~ -Inches Cement-Sack:~ :111 Cement-Yield :1:I1 Cement- Cubic It 111 Cement- Cubb It 111 Cement- Sacks 112 Cement-Yield 112 Cement- Cubic ft 112 Cement-Cubic It 112 Cement-Sacks 113 Cement-Yield 113 Cement- Cubic [t 113 Cement- Cubic It 113 Cement- Cubic tt / Vol Cement- Fill Factor Conductor 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 ~:DIV/O! Su~tace 13.375 2,735.000 16.000 550.000 2.170 1,193.500 1,193.500 400.000 1.160 464.000 464.000 0.000 0.000 0.000 0.000 1,657.500 1.441 Liner 7.000 1,134.000 8.500 280.000 1.190 333.200 333.200 0.000 0.000 0.000 0.000 333.200 2.317 Casing Type Ca~ing Size -Inches Casing Depth - Feet Hole Diamete~-Inct'~ Cement-Sacks 111 Cement-Yield 111 Cement- Cubic It 111 Cement-Cubic It 111 Cement- Sacks112 Cement- Yield112 Cement- Cubic ft Cement- Cubic It 112 Cement- Sacks113 Cement- Yield113 Cement- Cubic it 113 C. ement - Cubic it 113 Cement- Cubic It / Vol Cement-Internal ft Top of Cement- Feet Intermediate 111 0.000 0.000 0.000 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 11DIV/0! 11DIV/0! Intermediate 112 0.000 0.000 0.000 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 11DIV/O!. 11DIV/O! Production 9.625 12,394.000 12250 800.00 3.24 2,592.00 2,592.00 200.00 1.15 230.00 230.00 0.00 0.00 0.00 0.00 2,822.00 9,010.74 3,383.3 14 easured Depth State: Alaska Borough: Well: 1-15 ! P-25 Field: Endicott St. Perm # 93-56 1-15C5 G.XLS Date 4/8/93 Engr: M. Minder Casing Interval Interval Description Description Description Tension Size Bottom Top Length Lbs Grade Thread Lbs 1A 13. $75 2756 96 2735 68 NTSOC BTC 0 ?.A 9.625 9706 35 12357 47 NT80-S NSCC 0 3A 7 10326 9531 1134 29 NTS0-S NSCC 0 4A 0 0 0 0 0 0 0 0 5A 0 0 0 0 0 0 0 0 6A 0 0 0 0 0 0 0 0 7A 0 0 0 0 0 0 0 0 8A 0 0 0 0 0 0 0 0 9A 0 0 0 0 0 0 0 0 10A 0 0 0 0 0 0 0 0 Mud Hydraulic Collapse Maximum Minimum Weight Gradient Gradient Pressure Yield ppg psi/ft psi/ft psi psi BDF 1B 9,5 0.494 0.394 3900 4930 1.3 2B 10.3 0,536 0.436 3900 6870 1.8 3B 9,8 0.510 0,410 8900 8160 2,1 4B 0.0 0.000 -0.100 0 0 #DIV/0! 5B 0.0 0.000 -0.100 0 0 #DIV/O! 6B 0,0 0.000 -0.100 0 0 #DIV/0! 7B 0.0 0.000 -0.100 0 0 #DIV/O! 8B 0.0 0.000 -0.100 0 0 #DIVi0! 9B 0.0 0.000 -0,100 0 0 #DIV/O! 10B 0,0 0.000 -0,100 0 0 #DIV/0! Tension Strength K/Lbs K/Lbs 1C 185.98 1545 ZC 580.779 1086 3C 32,886 4C 0 5C 0 6C 0 7C 0 8C 0 9(3 0 10C 0 Collapse Collapse TDF Pr-Bot-Psi Resist. CDF 8.31 1086 2850 2.625 1,87 4228 4750 1.123 676 20.56 4280 7020 1.660 0 #DIV/O! 0 0 #DIVIO! 0 #DIV/Oi. 0 0 #DIV/0! 0 #DiV/0! 0 0 #DIV/O! 0 #DIV/O! 0 0 #DIV/O! 0 #DIVtO.! 0 0 #DrV'/O! o #DiV/O.I 0 0 #DN/O! 0 #DIV/0! 0 0 #DlV/0! Page 1 CHECK LIST FOR NEW WELL PERMITS ** ITEM APPROVE DATE (1) Fee ?£,,-'_ (2) Loc [2 thru 8] [8] ' (3) Admin ~f~ ~/~//f,~ [9 thru 13] [ 10 & 13] (4) Casg ¢/--¢:~.~¢'t', ~,~5.':'~. [14 thru 22] [23 thru 28] (6) Other AF£~ r~u 31]- [29 th (7) Contact [32] (8) Add l ge~ol ogy: eng i neer ing: MTM,~F~ 'RADS-N$ . BEw JDH ~_~- LG rev 12/92 Company .... Lease $ Well 1. Is permit fee attached ............................................... 2. Is well to be located in a defined pool .............................. 3. Is well located proper distance from property line ................... 4. Is well located proper distance from other wells ..................... 5. Is sufficient undedicated acreage available in this pool ............. 6. Is well to be deviated & is wellbore plat included ................... 7. Is operator the only affected party .................................. 8. Can permit be approved before 15-day wait ............................ 1 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26 27. 28. 29. 30. 31. 32. YES NO ? .. // , /~ ,, Does operator have a bond in force ................................... Is a conservation order needed ....................................... Is administrative approval needed .................................... Is lease nL~nber appropriate .......................................... Does well have a unique name & nLFnber ................................ Is conductor string provided ......................................... Wil 1 surface casing protect al 1 zones reasonably expected to serve as an underground source of drinking water .................. Is enough cement used to circulate on conductor & surface ............ Will cement tie in surface & intermediate or production strings ...... Will cement cover all known productive horizons ..................... Will all casing give adequate safety in collapse, tension, and burst. Is well to be kicked off from an existing wellbore ................... Is old wellbore abandonment procedure included on 10-403 ............. Is adequate wellbore separation proposed ............................. Is a diverter system required ........................................ Is drilling fluid program schematic & list of equipment adequate ..... Are necessary diagrams & descriptions of diverter & BOPE attached .... Does BOPE have sufficient pressure rating-- test to~O~~psig. Does choke manifold comply w/API RP-53 (May 84) ...................... Is presence of H2S gas probable ...................................... REMARKS FOR EXPLORATORY & STRATIGRAPHIC WELLS: Are data presented on potential overpressure zones ................... Are seismic analysis data presented on shallow gas zones ............. If offshore loc, are survey results of seabed conditions presented... Name and phone nLFnber of contact to supply weekly progress data ...... Additional requirements ............................................. ~/~_ INITIAL GEOL UNIT ON/OFF POOL CLASS STATUS AREA ~ SHORE Additional remarks' MERIDIAN' UM ~, SM E.W_ELL, TYPE' E x P X~'~) ~' In j. Red r il 1 Rev 33. Well History File APPENDIX Information of detailed nature that is not . particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information, of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. RECEIVED ,JUL 0 ~Nas~ 0ii & Gas Cons. ~mmission 1- iS/P- 25 ENDICOTT MICROFILM Run 1' 17 - May - 1993 CNIGR Cased Hole 12160 2862 Tape S~bfile 2 is type: LIS TAPE HEADER PRUDHOE BAY UNIT CASED HOLE WIRELINE LOGS WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: ELEVATION (FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: WELL CASING RECORD 1ST STRING 2ND STRING 3RD STRING PRODUCTION STRING OPEN HOLE BIT SIZE CURVE SHIFT DATA - ALL PASSES TO BASELINE CURVE FOR SHIFTS PBU TOOL CODE: DLL PBU CURVE CODE: GR RUN NUMBER: 1 PASS NUMBER: DATE LOGGED: LOGGING COMPANY: (IN) BASELINE DEPTH GRCH 12146.0 12146.0 12162.5 12164.5 12166.5 12169.5 12174.0 12177.0 12187.5 12191.0 12199~5 12203.5 12205.5 12210.5 12234.5 12237.5 12249.5 12252.0 12264.0 12267.0 12272.0 12275.0 12291.5 12294.0 12298.5 12301.5 1 - 15/P - 25 500292236100 BP EXPLORATION (ALASKA), ATLAS WIRELINE SERVICES 07-JUL-93 5959.00 KOEN/BRUNNER M. MARTIN 36 12N 16E 1988 2065 56.00 10.00 CASING DRILLERS CASING SIZE (IN) DEPTH (FT) WEIGHT 13.375 2753.0 68.00 9.625 12487.0 47.00 7.000 12972.0 29.00 STANDARD (MEASURED DEPTH) 14-MAY-93 SCHLUMBERGER WELL SERVICES EQUIVALENT UNSHIFTED DEPTH .... INC. (LB/FT) 123 123 123 123 123 123 123 123 124 124 124 124 125 125 125 125 '03.0 11.0 27.0 34.5 41.0 50.5 63.0 91.0 11.5 20.5 29.5 89.0 06.5 63.5 8'5.5 99.5 12618 12645 12670 12688 12700 12705 12714 12717 12724 12745 12749 12754 12778 12786 12795 12801 12805 12810 12832 12842 12930 $ REMARKS: .5 .0 .0 .5 .5 .0 .0 .0 .0 .5 .0 .0 .5 .0 .0 .5 .0 .5 .5 .5 .0 12306.0 12314.0 12329.5 12338.0 12343.5 12354.0 12366.0 12394.0 12413.5 12423.0 12431.5 12490.5 12508.5 12565.0 12587.0 12601.5 12617.5 12643.5 12670.0 12687.0 12701.5 12705.5 12712.0 12715.5 12724.0 12746.0 12749.5 12754.0 12779.5 12787.0 12795.0 12802.0 12805.5 12811.0 12833.0 12842.0 12930.0 CN/GR Cased Hole. LOG TIED TO SWS DUAL LATEROLOG-MSFL RUN 14-MAY-1993. CN LOGGED IN COMBINATION WITH SBT. OPEN HOLE GAMMA RAY FOR DEPTH MATCHING SUPPLIED BY BP EXPLORATION (07-JUL-93) . SHIFT PROCEDURE AS FOLLOWS: 1) MAIN PASS GAMMA RAY DEPTH MATCHED TO OPEN HOLE GAMMA RAY. 2) MAIN PASS NEUTRON DEPTH MATCHED TO "SHIFTED" MAIN PASS GAMMA RAY. $ FILE HEADER FILE NUMBER: 1 EDITED CURVES Depth shifted and clipped curves for each pass in separate files. PASS NUMBER: 4 DEPTH INCREMENT: 0.5000 FILE SUMMARY PBU TOOL CODE GRCH 2435 $ CURVE SHIFT DATA - PASS TO PASS BASELINE CURVE FOR SHIFTS PBU CURVE CODE: GRCH PASS NUMBER: 1 START DEPTH 12160.0 12206.0 BASELINE DEPTH NPHI 12146.0 12146.0 12162.5 12164.5 12166.5 12169.5 12174.0 12177.0 12187.5 12191.0 12199.5 12203.5 12205.5 12210.5 12234.5 12237.5 12249.5 12252.0 12264.0 12267.0 12272.5 12276.0 12291.5 12294.0 12298.5 12301.5 12303.0 12306.0 12311.0 12315.0 12327.0 12329.5 12334.5 12338.0 12340.5 12345.0 12350.5 12354.0 12362.5 12366.5 12391.0 12394.0 12411.5 12413.5 12420.5 12423.0 12429.5 12431.5 12489.0 12490.5 12493.5 12494.0 12506.5 12508.5 12563.5 12565.0 12585.5 12587.0 12599.5 12601.5 12613.5 12614.0 12618.5 12619.0 12645.0 12643.5 12670.0 12669.0 12688.5 12687.0 12700.5 12701.5 12705.0 12705.5 12714.0 12712.0 12717.0 12715.5 STOP DEPTH 12855.0 12862.0 (MEASURED DEPTH) EQUIVALENT UNSHIFTED DEPTH 127'24.0 12746.0 12754.0 12778.5 12786.0 12795.0 12801.5 12805.0 12810.5 12832.5 12930.0 $ REMARKS: CN WN FN COUN STAT 12724.0 12745.5 12754.0 12779.5 12787.0 12795.0 12802.0 12805.5 12811.0 12833.0 12930.0 MAIN PASS. FUCT & NUCT WERE SHIFTED WITH NPHI. GRCH WAS DEPTH MATCHED TO OPEN HOLE GAMMA RAY. $ : BP EXPLORATION : 1 - 15/P - 25 : ENDICOTT : NORTH SLOPE : ALASKA * FORMAT RECORD (TYPE# 64) ONE DEPTH PER FRAME Tape depth ID: F 4 Curves: Name Tool Code Samples Units API API API API Log Crv Crv Size Length Typ Typ Cls Mod 1 GRCH 2435 68 1 GAPI 4 2 NPHI 2435 68 1 PU-S 4 3 FUCT 2435 68 1 CPS 4 4 NUCT 2435 68 1 CPS 4 4 98 211 23 1 4 98 211 23 1 4 98 211 23 1 4 98 211 23 1 16 * DATA RECORD (TYPE~ 0) 1006 BYTES * Total Data Records: 32 Tape File Start Depth = 12930.000000 Tape File End Depth = 12146.000000 Tape File Level Spacing = 0.500000 Tape File Depth Units = Feet **** FILE TRAILER **** LIS representation code decoding summary: Rep Code: 68 7846 datums Tape Subfile: 2 222 records... Minimum record length: Maximum record length: 62 bytes 1006 bytes Tape Subfile 3 is type: LIS FILE HEADER FILE NUMBER: 2 RAW CURVES Curves and log header data for each pass in separate files; raw background pass in last file. PASS NUMBER: 4 DEPTH INCREMENT: 0.2500 FILE SUMMARY VENDOR TOOL CODE START DEPTH GR 12159.5 2435 12206.0 $ LOG HEADER DATA DATE LOGGED: SOFTWARE VERSION: TIME LOGGER ON BOTTOM: TD DRILLER (FT): TD LOGGER (FT): TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT): LOGGING SPEED (FPHR): DEPTH CONTROL USED (YES/NO): STOP DEPTH 12880.0 12882.0 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE CCL GR CN KNJT KNJT ACC SBT CENT $ CASING COLLAR LOC. GAMMA RAY COMPENSATED NEUTRON KNUCKLE JOINT KNUCKLE JOINT ACOUSTIC COMMON SEGMENTED BOND LOG CENTROLLER WTS BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE(IN): DRILLER'S CASING DEPTH (FT): LOGGER'S CASING DEPTH (FT): BOREHOLE CONDITIONS FLUID TYPE: FLUID DENSITY (LB/G): SURFACE TEMPERATURE (DEGF): BOTTOM HOLE TEMPERATURE (DEGF): FLUID SALINITY (PPM): FLUID LEVEL (FT): FLUID RATE AT WELLHEAD (BPM): WATER CUTS (PCT): GAS/OIL RATIO: CHOKE (DEG): NEUTRON TOOL TOOL TYPE (EPITHERMAL OR THERMAL): MATRIX: 17-MAY-93 FSYS REV. J001 VER. 1.1 2046 17-MAY-93 12952.0 12905.0 11700.0 12897.0 1500.0 YES TOOL NUMBER 2317XA 1309XA 2435XA 1633XA 1424XA 0.000 12972.0 0.0 8.5# WATER 0.00 0.0 0.0 0 0.0 0.000 0.000 0.000 0.0 THERMAL SANDSTONE MATRIX DENSITY: HOLE CORRECTION (IN): 0.00 8.500 BLUELINE COUNT RATE NORMALIZATION IN OIL ZONE TOP NORMALIZING WINDOW (FT): 0.0 BASE NORMALIZING WINDOW (FT): 0.0 BLUELINE COUNT RATE SCALES SET BY FIELD ENGINEER FAR COUNT RATE LOW SCALE (CPS): 0 FAR COUNT RATE HIGH SCALE (CPS): 0 NEAR COUNT RATE LOW SCALE (CPS): 0 NEAR COUNT RATE HIGH SCALE (CPS): 0 TOOL STANDOFF (IN): 0.0 REMARKS: MAIN PASS. CHISM FILTERING ACTIVE. CASING CORRECTIONS ACTIVE: CASING THICKNESS = 0.408" CEMENT THICKNESS = 0.75" $ CN WN FN COUN STAT : BP EXPLORATION : 1 - 15/P - 25 : ENDICOTT : NORTH SLOPE : ALASKA * FORMAT RECORD (TYPE~ 64) ONE DEPTH PER FRAME Tape depth ID: F 8 Curves: Name Tool Code Samples Units API API API API Log Crv Crv Size Length Typ Typ Cls Mod 1 GR 2435 68 1 GAPI 4 2 CNC 2435 68 1 PU-S 4 3 CN 2435 68 1 PU-L 4 4 LSN 2435 68 1 CPS 4 5 SSN 2435 68 1 CPS 4 6 SPD 2435 68 1 F/MN 4 7 CCL 2435 68 1 4 8 TEN 2435 68 1 LB 4 4 08 501 10 0 4 98 211 23 1 4 52 326 75 5 4 84 023 70 1 4 83 368 34 1 4 54 376 29 5 4 90 640 78 6 4 19 912 29 5 32 * DATA RECORD (TYPE# 0) 1014 BYTES * Total Data Records: 113 Tape File Start Depth = 12930.000000 Tape File End Depth = 12146.000000 Tape File Level Spacing = 0.250000 Tape File Depth Units = Feet **** FILE TRAILER **** LIS representation code decoding summary: Rep Code: 68 28234 datums Tape Subfile: 3 196 records... Minimum record length: 42 bytes Maximum record length: 1014 bytes Tape Subfile 4 is type: LIS FILE HEADER FILE NUMBER: 3 RAW CURVES Curves and log header data for each pass in separate files; raw background pass in last file. PASS NUMBER: 3 DEPTH INCREMENT: 0.2500 FILE SUMMARY VENDOR TOOL CODE START DEPTH GR 12602.0 2435 12649.0 $ LOG HEADER DATA DATE LOGGED: SOFTWARE VERSION: TIME LOGGER ON BOTTOM: TD DRILLER (FT): TD LOGGER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): LOGGING SPEED (FPHR): DEPTH CONTROL USED (YES/NO): TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE CCL GR CN KNJT KNJT ACC SBT CENT $ STOP DEPTH 12879.0 12881.0 CASING COLLAR LOC. GAMMA RAY COMPENSATED NEUTRON KNUCKLE JOINT KNUCKLE JOINT ACOUSTIC COMMON SEGMENTED BOND LOG CENTROLLER WTS 17-MAY-93 FSYS REV. J001 VER. 1.1 2028 17-MAY-93 12952.0 12905.0 11700.0 12897.0 1500.0 YES TOOL NUMBER 2317XA 1309XA 2435XA 1633XA 1424XA BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE(IN): DRILLER'S CASING DEPTH (FT): LOGGER'S CASING DEPTH (FT): 0.000 12972.0 0.0 BOREHOLE CONDITIONS FLUID TYPE: FLUID DENSITY (LB/G): SURFACE TEMPERATURE (DEGF): BOTTOM HOLE TEMPERATURE (DEGF): FLUID SALINITY (PPM): FLUID LEVEL (FT): FLUID RATE AT WELLHEAD (BPM): WATER CUTS (PCT): GAS/OIL RATIO: CHOKE (DEG): 8.5# WATER 0.00 0.0 0.0 0 0.0 0.000 0.000 0.000 0.0 NEUTRON TOOL TOOL TYPE (EPITHERMAL OR THERMAL): MATRIX: THERMAL SANDSTONE MATRIX DENSITY: HOLE CORRECTION (IN): 0.00 8.500 BLUELINE COUNT RATE NORMALIZATION IN OIL ZONE TOP NORMALIZING WINDOW (FT): 0.0 BASE NORMALIZING WINDOW (FT): 0.0 BLUELINE COUNT RATE SCALES SET BY FIELD ENGINEER FAR COUNT RATE LOW SCALE (CPS): 0 FAR COUNT RATE HIGH SCALE (CPS): 0 NEAR COUNT RATE LOW SCALE (CPS): 0 NEAR COUNT RATE HIGH SCALE (CPS): 0 TOOL STANDOFF (IN): 0.0 REMARKS: REPEAT PASS. $ CN WN FN COUN STAT : BP EXPLORATION : 1 - 15/P - 25 : ENDICOTT : NORTH SLOPE : ALASKA * FORMAT RECORD (TYPE# 64) ONE DEPTH PER FRAME Tape depth ID: F 8 Curves: Name Tool Code Samples Units API API API API Log Crv Crv Size Length Typ Typ Cls Mod 1 GR 2435 68 1 GAPI 4 2 CNC 2435 68 1 PU-S 4 3 CN 2435 68 1 PU-L 4 4 LSN 2435 68 1 CPS 4 5 SSN 2435 68 1 CPS 4 6 SPD 2435 68 1 F/MN 4 7 CCL 2435 68 1 4 8 TEN 2435 68 1 LB 4 4 08 501 10 0 4 98 211 23 1 4 52 326 75 5 4 84 023 70 1 4 83 368 34 1 4 54 376 29 5 4 90 640 78 6 4 19 912 29 5 32 * DATA RECORD (TYPE~ 0) 1014 BYTES * Total Data Records: 49 Tape File Start Depth = 12929.000000 Tape File End Depth = 12593.000000 Tape File Level Spacing = 0.250000 Tape File Depth Units = Feet **** FILE TRAILER **** LIS representation code decoding summary: Rep Code: 68 19952 datums Tape Subfile: 4 128 records... Minimum record length: 42 bytes Maximum record length: 1014 bytes Tape Subfile 5 is type: LIS 93/ 7/ 7 01 **** REEL TRAILER **** 93/ 7/ 7 01 Tape Subfile: 5 2 records... Minimum record length: 132 bytes Maximum record length: 132 bytes End of execution: Wed 7 JLY 93 3:21p Elapsed execution time = 18.07 seconds. SYSTEM RETURN CODE = 0
