The URL can be used to link to this page

Home My WebLink About202-158 Image ¡:.. ¿ject Well History File C()er Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ó( 0 ~ - L Q <6 Well History File Identifier Organizing (done) 0 Two-sided III 1111111111111111 ~escan Needed I R,SCAN 'Ø Color Items: 0 Greyscale Items: 0 Poor Quality Originals: DIGITAL DATA OVERSIZED (Scannable) 0 Maps: D Diskettes, No. D Other, NolType: 0 Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) 0 Other: 0 Logs of various kinds: NOTES: BY: Helen ~ 0 Other::, I DateÂ g () s- /5/ rn f I I t Date:6<.. '6 0.5 151 VYlfJ Project Proofing BY: Helen ~ ------- Scanning Preparation I x 30 = L -.2¡j +~:;J = TØTA~ PAGES 3:J- (Count doe~ not i cJude cover sheet) )11 A P. Date:& <if 0$ 151 r V~ BY: Helen ~ , I Production Scanning Stage 1 Page Count from Scanned File: (~::s (Count does include cover sheet) Stage 1 BY: If NO in stage 1, page(s) discrepancies were found: VVES, Date:~ t¿ OS . YES NO NO ..!) Isl 111 BY: Page Count Matches Number in Scanning Preparation: Helen ~ Helen Maria Date: 151 I Scanning is complete at this point unless rescanning is required. ReScanned I BY: Helen Maria Date: 151 Comments about this file: Quality Checked 1111111111111111111 e e MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFicbe\CvrPgs _ Inserts\Microfilm _ Marker.doc ') -3 Memorandum State of Alaska Oil and Gas Conservation Commission To: Well File: Northstar Unit NS-28 Cancelled Permit Action Northstar Unit NS-28XX Permit # 202-158 August 5, 2002 API # 029-23109-00 This memo will remain at the front of the subject well file. Our adopted conventions for assigning API numbers, permit numbers and well names did not specifically address expired or cancelled permits. This omission has caused some inconsistencies in the treatment of these kinds of applications for permit to drill. Operators have asked us to adopt formal procedures for this class of permit application in order to prevent future database disparities. If a permit expires or is cancelled by an operator, the permit number of the subject permit will remain unchanged. The API number and in some instances the well name reflect the number of preexisting red rills and or multi laterals in a well. In order to prevent confusing a cancelled or expired permit with an active well or multilateral these case sensitive well identifiers will be changed for expired and cancelled applications for permits to drill. The well name for a cancelled or expired permit is modified with an appended xx. These procedures are an addendum to the API numbering methods described in AOGCC staff memorandum "Multi-lateral (wellbore segment) Drilling Permit Procedures, revised December 29, 1995. AOGCC database has been changed to reflect these changes to this permit. CANCELED PERMITS ARE RELEASABLE 2 years from the date on the letter or email received from the operator requesting the permit canceled. (Memorandum January 23, 1997 by Dave Johnston, subject: Canceled and Expired Permits) Su~~ Steve McMains Statistical Technician NS28 slot change to NS24 ~ Subject: NS28 slot change to NS24 Date: Mon, 5 Aug 200221:01:56 -0500 From: "Holt, Barbara M" <HoltBM@BP.com> To: "'Winton Aubert'" <Winton_Aubert@admin.state.ak.us> CC: "Stewman, Sondra D" <StewmaSD@BP.com>, "Goodwin, David W" <GoodwinD@BP.com>, "Lemley, Kenneth R" <LemleyKR@BP.com>, "Schultz, Mikel" <Mikel.Schultz@BP.com>, "Hernandez, Floyd" <HernanF1@BP.com>, "Shenitt, Allen" <SheniJA@BP.com>, "Kyle Monkelien (E-mail)..<kyle.monkelien@mms.gov>...Matson.RickG..<MatsonRG@BP.com>. "Bob Nohejl (E-mail)" <bnohejl@smith.com>, "Eric Mickelson (E-mail)" <emickelson@smith.com>, "Pat Sauvageau (E-mail)..<PSauvageau@anchorage.oilfield.slb.com>. "Hubble, Tenie L" <HubbleTL@BP.com>, Bob Sawyer <Bob_Sawyer@murphyoi1corp.com>, Buford Bates <Buford_Bates@murphyoilcorp.com>, David Hanis <david_hanis@murphyoilcorp.com>, Dennis Watermann <dennis - watermann@murphyoilcorp.com>, Gasper Bivalacqua <gasper_bivalacqua@murphyoilcorp.com>, Randy Bright <randy - bright@murphyoilcorp.com>, Sandra Gracia <Sandra- Gracia@murphyoilcorp.com>, "Anderson, Lowell F (BOT)" <AndersLF@BP.com>, Bernie Leas <bleas@sperry-sun.com>, "Carl Thomesen (E-mail)..<Carl.Thomesen@Halliburton.com> , "Dave Hebert (E-mail)..<dhebert@nabors.com>. "Elmore, Gary 0 (Schlumberger)" <ElmoreGO@BP.com>, "Eric Dompeling (E-mail)..<eric.dompeling@Halliburton.com>. "Francis, Michael J" <Michael.Francis@BP.com>, "John Burton (E-mail)..<burton4@slb.com>. "John Rose (E-mail)..<john.rose2@Halliburton.com>. "Kasecky, Michael (Phillips)" <MKASECKY@ppco.com>, "Kidd, Gavin N" <KiddG1@BP.com>, "Larry Wilger (E-mail)..<larry.wilger@Halliburton.com>. "Lemley, Kenneth R" <LemleyKR@BP.com>, "Miller, Nick J (Baker Hughes)" <Nick.Miller@BP.com>, "Nate Rose (E-mail)..<NRose1@anchorage.oilfield.slb.com>. "Pete Jackson (E-mail)..<pete.jackson@Halliburton.com>...Polya.JosephD..<PolyaJD@BP.com>. "Randy Hicks (E-mail)" <rhicks@quadcoinc.com>, "Ves Cash (E-mail)" <ves.cash@us.abb.com> All, Please note the well name change from NS28 to NS24. This will cancel the NS28 permit (#202-158 API 50-029-23109-00) and will be replaced by NS24 permit (#202-164 API 50-029-23111-00). The bottom hole location will stay the same with only minor changes to cement volumes and directional survey. If you have any questions, please give me a call. Thanks. Barbara M. Holt Northstar Drilling Engineer Office: (907) 564-5791 Cell: (907) 240-8044 NS28 Pennit -J Subject: NS28 Permit Date: Tue, 30 Ju12002 17:23:30 -0500 From: "Holt, Barbara M" <HoltBM@BP.com> To: "Winton Aubert (E-mail)..<winton_aubert@admin.state.ak.us> CC: "Lemley, Kenneth R" <LemleyKR@BP.com>, "Shenitt, Allen" <SheniJA@BP.com>, "Hernandez, Floyd" <HemanF1@BP.com> Winton, I do apologize for the rush on the NS28 permit. This northern well slot was bumped up in the drilling schedule due to required subsidence work to the souths ide of the island. Additionally, we were not anticipating the great drilling performance on this well. We had planned for NS18 to reach Top Sag River shut down on approximately August 8th (thinking that best case scenario we would be TO'd by August 5th). We are now on track to be moving by August 2nd. Well NS18 is the longest step out to date at Northstar (11,882' departure) and time was built in to reflect this well difficulty; however, due to some time saving circumstances (i.e. running a porcupine reamer, eliminating wiper trips, not requiring an additional bit trip, smooth casing run for 14,700' of 95/8" casing, etc) the well timing has been pushed back 7 days from actual planned time (this is 2 days faster than our "best in class" model even predicted). Long story short, the combination of schedule changes and improved performance has pushed NS28 forward. Well NS17, the well following NS28, is already well into the planning phase and a permit will be sent over early next week so as to prevent another rush permit. Again, I apologize for the rush on NS28. Barbara M. Holt Northstar Drilling Engineer Office: (907) 564-5791 Cell: (907) 240-8044 r--"""-""'-- .......-----........ ... -.L. -- ---"- --~ --- -............ ~_..__.._-"'-~---"'."--' -_.~_. ~_...._._----~.."'._, , Name: Blank Bkgrd.gif : I ~Bl~k Bkgrd.gifli .. T~pe: GIF Image (image!. glf)1 !~,.."",,,..,",.,.,..<>,,,,,,,,,...........,.^,.,,,,,.,...'..~,!~~,~~~.~.~.....~,~.~~.?~~^,,,,,,,,....................,......,"~"...."w.r ~ ~~/Æ::E ~!F /ÆL!Æ~æ!Æ A.I~A.SIiA OIL AND GAS CONSERVATION COMMISSION TONY KNOWLES, GOVERNOR 333 W. "'fTH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)276-7542 Floyd Hernandez Senior Drilling Engineer BP Exploration (Alaska), Inc. PO Box 196612 Anchorage AK 99519-6612 Re: Northstar Unit NS 28 BP Exploration (Alaska), Inc. Permit No: 202-158 Surface Location: 1319' NSL, 648' WEL, Sec. 11, TI3N, RI3E, OM Bottomhole Location: 356' NSL, 2036' WEL, Sec. 02, TI3N, RI3E, OM Dear Mr. Hernandez: Enclosed is the approved application for permit to drill the above development well. The permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sufficient notice (approximately 24 hours) 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 test. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Sincerely, ~ DuLL ~ cam~chsli Taylor Chair BY ORDER OF THE COMMISSION DATED this~day of July, 2002 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. '\ STATE OF ALASKAJ. ALASKk. JIL AND GAS CONSERVATION COMh...é)SION PERMIT TO DRILL 20 AAC 25.005 1 a. Type of work II Drill 0 Redrill 1 b. Type of well 0 Exploratory 0 Stratigraphic Test II Development Oil 0 Re-Entry 0 Deepen 0 Service 0 Development Gas 0 Single Zone 0 Multiple Zone 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exploration (Alaska) Inc. Plan RKB = 56' Northstar Unit 3. Address 6. Property Designation P.O. Box 196612, Anchorage, Alaska 99519-6612 ADL 312799 4. Location of well at surface 7. Unit or Property Name 1319' NSL, 648' WEL, SEC. 11, T13N, R13E, UM Northstar Unit At top of productive interval 8. Well Number / 356' NSL, 2036' WEL, SEC. 02, T13N, R13E, UM NS28 At total depth 9. Approximate spud date 356' NSL, 2036' WEL, SEC. 02, T13N, R13E, UM 08/02102/ Amount $200,000.00 12. Distance to nearest property line 13. Distance to nearest well / 14. Number of acres in property 15. Proposed depth (MD and TVD) ADL Y0179, Approx. 2600' MD NS27is9'awayat300'MD 4472 12610' MD /11216' TVD 16. To be completed for deviated wells 0 17. Anticipated pressure {s~ 20 AAC 25.035 (e) (2)} Kick Off Depth 1500' MD Maximum Hole Angle 37 Maximum surface 3934 psig, At total depth (TVD) 11160' I 5280 psig 18. Casin~ Program Specifications Setting Depth Size TaD Bottom Quantitv of Cement Casina Weiaht Grade CouDlina Lenath MD TVD MD TVD (include staae data) 20" 169# X-56 Weld 201' Surface Surface 201' 201' Driven 13-3/8" 68# L-80 BTC 3376' Surface Surface 3376' 3206' 584 sx PF'L', 471 sx Class 'G' 9-5/8" 47# L-80 BTC-M 10778' Surface Surface 10778' 9384' 600 sx Econolite, 581 sx 'G' 7" 26# L-80 Hydril521 1471' 10628' 9234' 12099' 10706' 235 sx Class 'G' 4-1/2" 12.6# 13Cr Vam Ace 661' 11949' 10555' 12610' 11216' 96 sx Class 'G' VJ~ 7/~OIf)L -J¡Þ 7(?øl~ 11. Type Bond (See 20 AAC 25.025) Number 2S100302630-277 Hole 20" 16" 12-1/4" 8-112" 6-1/8" 19. To be completed for Red rill , Re-entry, and Deepen Operations. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical feet feet feet feet Junk (measured) Plugs (measured) Casing Structural Conductor Surface Intermediate Production Liner Length Size Cemented MD TVD Perforation depth: measured RECEIVED JUL 2 9 2002 true vertical Alaska Oil & Gas Cons. Commission Anchorage II Filing Fee 0 Property Plat 0 BOP Sketch 0 Diverter Sketch II Drilling Program II Drilling Fluid Program 0 Time vs Depth Plot 0 Refraction Analysis 0 Seabed Report 0 20 AAC 25.050 Requirements Contact Engineer NameINumber: Barbara Holt, 564-5791 AlIen Sherritt, 564-5204 Prepared By NarneINumber: Terrie Hubble, 564-4628 21. I hereby certify that the foregoing is true and correct to the best of my knowledge S~~~~~~.~~/2'~~ Permit Number API Number Approval D)¥e1.A i See cover letter .2- 0.2 - I ç ~ 50- <3.2.. ~ - 2- 3/0 '7 -/ ;p cq for other reQuirements Conditions of Approval: Samples Required 0 Yes 9 No Mud Log Required' 181 Yes 0 No Hydrogen Sulfide Measures 0 Yes J8I No Directional Survey Required BI Yes 0 No Required Working Pressure for BOPE 0 2K 0 3K 0 4K 0 5K 0 10K 0 15K 0 3.5K psi for CTU Other: p~ 20 AÅ'- l...S. ,,~'S (Á){2.)t ~Y4-P-v rl-l~~þv1..~ v.JA.{V~ J, .. I T~ '=> t- ¡So P tØn~ I <J.~ Y . by order of 1/'1.. '0° Approved By C .I~a~ em"'Xa. i T~li~. ~ifn1{ L the commission Date' vO' ~ Form 10-401 Rev. 12-01-85 ð,y\r , 'LJ \ ! \j J-\ Submit In Triplicate 20. Attachments ) ~ Oilfield Services, Alaska Schlumberger Drilling & Measurements Schlumberger 3940 Arctic Blvd, Site 300 Anchorage, AK 99503 Tel (907) 273-1766 Fax (907) 561-8357 Friday, July 26, 2002 Barbara Holt Northstar NS28 (P4) BP Exploration Alaska Close Approach Analysis We have examined the potential intersections of subject well with all other potentially conflicting wells, according to the BPA Directional Survey handbook (BPA-D-004) dated 09/99. Nabors 33E Method of analvsis: 1. A list of wells to be analyzed is created in Compass by performing a global scan with an initial search radius of two thousand feet with an increment of one hundred feet for every one thousand feet of measured depth in the subject well. 2. Wells are analyzed using the Compass Anti-collision module (BP Company setup) with major risk safety factors applied. For problem wells that are plugged and abandoned or that can be shut in, risk-based safety factor may be used, with client notification. 3. All depths are relative to the planned well profile. Survey Program: Instrument Type GYD-GC-SS MWD - Standard (declination corrected) Start Depth 40.20' md 1,500' md End Depth 1,500' md 12,609.54' md Close Approach Analysis results: Under method (2), all wells except those noted below, pass major risk close approach rules: NS26 - Closest point at 1650'md, center to center distance 13.6 ft. Allowable deviation of -13.9ft. Risk based 1 :200 allows drill by with closest point at 1600'md, center to center distance 13.2 ft. and the allowable deviation would become 4.0 ft. NS27 - Closest point at 600'md, center to center distance 8.8 ft. Allowable deviation of -4. 1ft. Risk based 1 :200 allows drill by at same point, allowable deviation would become 2.9 ft. NS29 Passes the major risk at 400'md, with 2.5' allowable deviation, however it is recommended to use the 1 :200 risk assessment for better drillability around it. This would become 6.2 ft. All data documenting these procedures is available for inspection at the Drilling and Measurements Directional Planning Center. Close Approach Drillinç¡ Aids to be provided: A drilling map, with offset wells on the plan view, and traveling cylinder will be provided. Checked by: Scott Delapp 07/26/02 , ) ) .----.,; bp .,. ,\I,.,,,. .-...,~ ~*..- ~~- ~...-- **~ r" .I'.~I\~ ". BP Exploration Alaska Inc. To: Winton Aubert - AOGCC Date: July 25, 2002 From: Allen Sherritt Northstar Operations Drilling Engineer Subject: NS28 Application for Drilling Permit / NS28 is currently scheduled for Nabors 33E on August 5th, 2002. The rig will be finishing 8 Y2 interval on NS18 approximately August 3rd. / j A Diverter waiver is also requested on NS28. To date, BP has drilled fourteen development wells through the Northstar upper strata-graphic intervals and has not experienced any difficulty with shallow gas. Thirteen surface holes have been drilled and cemented to a common depth of approximately 3,170' TVDss depth, (-150' TVD below the top of the SV6), with one well extending into the SV5 -3280' TVDss. Well mud logs and seismic data do not indicate the presence of a shallow gas hazard. NS28 will perform an "Operatio~hutdown" during the 2002 Seasonal Drilling Restriction period. A Sundry '" 0 4<J ~ J:; for the Operation Shutdown will not be submitted, as the operations are covered in the ADP pr9cedure. of <;.. C~~IÞ Please find attached the NS28 Well Plan Summary, directional plan and proposed completion diagram. If you should have any questions or concerns, please contact me @ 564-5204. SinCerelY,. ~ Allen Sherritt BP Northstar Operations Drilling Engineer 564-5204 Mr. Aubert, ') ~) NS28 SUMMARY DRilLING OPERATIONS Pre-RiQ Work: 1. Set 20" conductor and weld an ABB Vetco landing ring for the ABB Vetco Multibowl Wellhead on the conductor. (Already performed.) 2. Install 7' x 7' cellar and polyshield same. (Already performed.) RiQ Operations: I 1. MIRU Nabors 33E. / 2. Nipple up and function test 21-1/4" diverter system, if required. NOTE: A diverter dispensation has been requested. Confirm dispensation decision with the Drilling Engineer. A D7 Diverter Drill will be conducted prior to spud. 3. MU 16" drilling assembly with MWD/GR and directionally drill surface hole to +/-150' TVD below the top of the SV6 marker at approximately 3194' MD. Surface casing point has been picked at 3376' MD. POOH. 4. Run 13-3/8", 68# surface casing. Cement the casing to surface in 1 stage. A TAM port collar will be run at +/- 1600' MD. In the event the cement does not circulate to surface, this port collar will be utilized to ensure a successful cement job is performed. / 5. ND diverter / riser system and NU casing / multi-bowl wellhead. NU BOPE and test to 750/4800 psi. 6. MU 12-1/4" directional assembly. RIH to float collar. Test the 13-3/8" casing to 3500 psi with 9.3-ppg mud for 30 min. This test pressure may change based on actual mud weight in the hole. / 7. Drill out remaining cement. Drill 20' of new formation below 13-3/8" shoe and perform FIT to a 12.5 ppg EMW. (FIT/LOT procedure on file with AOGCC). 8. Drill 12-1/4" intermediate hole to casing point (approximately 10,777' MD) at the top of the Miluveach. Minimum mud weight of 9.6 ppg at the top of HRZ and 10.1 ppg at the top of Kuparuk. POOH. (No logs will be ?In, unless the Kuparuk is oil bearing.) 9. Run 9-5/8", 47# intermediate casing. Cement the casing to the top of the SV2 sand in a single stage. Set the 9 5/8" pack off. Perform a down-squeeze on the 9-5/8" x 13-3/8" annulus with 1 annular /' volume of mud upon installing and testing the packoff. Down-squeeze diesel to 2000' TVD for freeze protection after WOC. /' 10. MU 8-1/2" directional assembly and RIH to float collar. Pressure-test the 9-5/8" casing to 4100 psi with 10.1 ppg mud for 30 min. This test pressure may change based on the actual mud weight in the hole. 11. Drill out remaining cement. Drill 20' of new formation below 9-5/8" shoe and perform a FIT to a 13.5 ppg EMW, (FIT/LOT procedure on file with AOGCC). 12. Weight up to 11.5 ppg prior to drilling ahead. Drill the drilling liner hole to the top of the Sag at approximately 12,065' MD. Interrpediate casing point has been picked/at 12,099' MD. POOH. 13. Run and cement a 7" 26# drilling liner. Displace cement with 11.5 ppg mud. Set the liner hanger and liner top packer. Circulate excess cement from well bore. 14. Circulate to clean 8.65 ppg seawater using spacers as per Baroid recommendation. 15. Shut down and monitor the well for a minimum of 30 minutes (negative Jst on liner top). 16. POOH and lay down liner running tools. Test 9 5/8" x 7" liner to 4800 psi for 30 mins, (MMS - 700/0 of burst), will need to wait 8 hrs for cement to build 500 psi compressive strength. RIH to 100' below the base of permafrost and circulate 6.8 ppg diesel to freeze protect the well to surface. POOH. 17. Prepare for "Operations Shutdown. (June 1st Seasonal Drilling Restrictionr' 18. Install 4 Y2" tubing hanger and test to 4200 psi. 19. Set the TWC. NO BOP's. NU Tree. Test the tubing head adapter and tree to 5000 psi. 20. Install (dry rod in) BPV and test. Ensure all valves are closed. RD and move off well. 21. Prepare to re-enter well post leasonal Drilling Restriction." 22. MIRU Nabors 33E. NS28 Permit to Drill ) ~) / 23. Pull BPV. Install TWC. ND dry hole tree. NU BOPE and test to 250/4800 psi. 24. RIH w/ 6-1/8" directional assembly to 2000' MD. Displace diesel with seawater, (see diesel handling procedure). Test 9 5/8" x 7" liner to 4800 psi for 30 mins. RIH to 7" liner top. Displace seawater to 9.3 ppg mud. Clean out 7' liner to the landing collar. 25. Drill out remaining cement. Drill 2o/:°f new formation below 7" shoe with 9.1 ppg mud. Perform a Formation Integrity test to 11.5 ppg. (FIT/LOT procedure on file with AOGCC). 26. Drill 6-1/8" production interval to the proposed TD at 12,610' MD. Increase mud weight to 9.3 ppg prior to POOH. 27. RU Schlumberger E-line unit. Run open hole RFT's (pressures only). POOH and RD Schlumberger. 28. Make a clean out run, if required, and condition the hole for a lin~POOH. 29. Run and cement the 4-1/2" 12.6# 13Cr liner with an inner string. Set the liner hanger and liner top packer. Circulate min. 1 bottoms up to remove excess cement 9.3 ppg viscosified brine. 30. Circulate to clean seawater (less than 80 NTU's) using spacers as per Baroid recommendation. 31. Shut down and monitor the well for a minimum of 30 minutes (negative test on liner top). 32. POOH. Close the blind rams and pressure-test the liner lap to 3400 psi with 9.3-ppg fluid in the well for 30 minutes. Prepare to runJhe 4 Y2" completion. No slick line work will be done. 33. Run the 4 Y2", 13Cr Vam Ace completion assembly with CIDRA fiber optics. The fiber optic cable will be run from packer setting depth to surface. 34. RIH to packer setting depth. Dual SSSV control lines will be run from the SVLN at +/- 2000' TVD (2106' MD) to surface. 35. Run space out pups and terminate the 2 - 0.25" control lines and 0.25" fiber optic line. All lines will be secured using collar cable clamps. Pressure test the control lines and tubing hanger seals. Function test the fiber optic line. 36. Pump corrosion inhibitor and heated diesel down the 4 Y2" x 9 5/8" annulus equivalent to the annulus capacity plus tubing capacity to a depth of 4056' TVD (4439' MD). RU the U-tubing manifold and allow the Freeze Protection fluid to u-tube through the GLM lower, -6500 MD. /' 37. Drop ball and rod to set packer. Increase the tubing pressure to 4200 psi (maximum anticipated surface pressure) with 8.65-ppg completion fluid and hold for 30 minutes. Monitor tubing pressure for leaks. Record on chart. J 38. Bleed tubing to 3000 psi and maintain during MIT. Pressure test annulus to 4200 psi (maximum anticipated surface pressure) with 8.65-ppg-completion fluid for mechanical integrity test (MIT). Monitor tubing pressure for leaks. Maintain pressure for 30 minutes and record as annulus test on chart. Email or fax chart to Drilling Engineer. 39. Bleed down the annulus to 3500 psi. Bleed down the tubing to 0 psi. This will shear the RP valve in the lower most GLM. 40. Bleed off annulus to 0 psi. Allow fluids to U-tube from the annulus into the tubing. 41. Set the TWC. ND BOP's. NU Tree. Test the tubing head adapter and tree to 5000 psi. 42. Install and test (dry rod in) BPV. Ensure all valves are closed. RD and move off well. Estimated Spud Date: Estimated Operations Shutdown Date: August 2nd, 2002 August 18th, 2002 Allen Sherritt Operations Drilling Engineer 564-5204 2 NS28 Permit to Drill ") ~) NS28 WELL PLAN SUMMARY I Type of Well (producer or injector): Northstar Slot: Surface Location: Target (top of SAG): 400' Radius Bottom Hole Location: I AFE Number: 1831321 I Estimated Start Date: 18/2/02 I Rig: I Nabors 33E I Operating days to complete: I 33.3 I Producer NS28 1318' FSL,648' FEL,Sec. 11,T13N,R13E,UM X = 659823 Y = 6031091 356'FSL,2036'FEL,Sec.2,T13N,R13E,UM X = 658340 Y = 6035378 10,671' TVDrkb 356' FSL,2036' FEL, Sec. 2,T13N, R13E, UM X = 658340 Y = 6035378 11,216' TVDrkb I MD: 112,610 I I TVDrkb: 111,216 I I RKB/Surface Elevation: (a.m.sJ.) I Well Design (conventional, slimhole, etc.): I Modified Big Bore l Objective: I Ivishak Producer with fiber optic surveillance control line Well Name: API Number: Well Type (proposed): BHP: EMW: BHT: MECHANICAL CONDITION: Cellar box: RKB to Cellar box: Rig Elevation: Conductor: // NS28 Producer 5175 psi @ 11,100' TVDss 8.96 ppg 254 of @ 11,100' TVDss Elevation above MSL = 15.9' 40.1' (Estimated) RKB + MSL = 56.0' 2011 MDrkb of 20",169#, X-56 (pre-driven) / 3 I I I 56.0' / 15.9' I I I NS28 Permit to Drill ~) -~ MUD PROGRAM: Surface Hole Mud Properties: Seawater Spud Mud 16" Hole Section From Surface to -3376' MD /3206' TVD (-150' TVD below top SV6). Interval Density Viscosity YP Tauo Gel APIFL pH (ppg) (seconds) 10 sec Initial 8.8-9.0 100 - 200 50 - 70 >8 25 - 40 15 - 20 8.5 - 9.5 from -1555' *9.0 - 9.y 100 - 200 30 - 45 >6 15 - 25 4-10 8.5 - 9.5 SV6 @ Interval TD *9.5 75 - 100 20 - 35 >6 10 - 25 4-10 8.5 - 9.5 / * Should gas hydrates be encountered, mud densities up to 10.2 ppg may prove necessary. Intermediate Hole Mud Properties: Seawater Polymer From Surface Casing Shoe to 10,778' MD / 9384' TVD. Interval Density (ppg) PV Initial 8.7 - 9.3 10 -16 Top HRZ 9.6- 10 - 16 Top Kuparuk to Miluveach 10.0 / 10 - 18 12-1/4" Hole Section YP 20 - 30 20 - 25 20 - 28 Tauo API/ HTTP FL 4-7 6-10 4 - 7 4-6 / <12 4 - 7 4-6 / <12 pH 8.5 - 9.5 8.5-9.5 8.5-9.5 Drilling Liner Hole Mud Properties: Inhibited KCL 8-1/2" Hole Section From Intermediate Casing Shoe to 12,099' MD / 10,706' TVD (top of Sag) Interval Density (p~) PV YP Miluveach & Kingak to top of Sag 11.5 10 - 25 20 - 25 Tauo 4-7 API FL pH 4-6/<10 8.5 - 9.5 I Production Hole Mud Properties: Seawater/CaC03 Drill-In Fluid From Intermediate Casing Shoe to 12,610' MD / 11,216' TVD Interval Density (ppg)/ PV YP Initial/Final 9.1 - 9.3 7 8 - 12 20 - 25 6-1/8" Hole Section Tauo 4-7 APIFL 3-5 pH 8.5 - 9.5 DIRECTIONAL:(P4) KOP: Maximum Hole Angle: Close Approach Wells: Survey Program: :i:1500' MD Cantenary curve 1.25°/100' to 2.50°/100' build :i:36.9° Surface- 10' well spacing to well NS29 and NS27 NS26 - closest point at 1600' MD center-to-center distance is 13.15 ft. NS27 - closest point at 300' MD center-to-center distance is 8.76 ft. NS29 - closest point at 600' MD center-to-center distance is 9.89 ft. Gyro will be used for initial surveys and kickoff Gyros as required from surface to +/-2000'. Standard MWD surveys from +/-2000' to TD. SURFACE AND ANTI-COLLISION ISSUES: All wells pass the major risk rule expect for NS29, NS27 and NS26. These three well pass the minor risk rules at 1/200. Gyros will be run from surface to -2000' MD or until reliable MWD surveys can be taken. See Anti-collision Report in directional (P4) attachment for summary of allowable deviations. Surface Shut-in Wells: See Northstar Anti-Collision and Well Shut-In checklist. 4 NS28 Permit to Drill LOGGING PROGRAM: 16" Section: Drilling: Open Hole: Cased Hole: 12-1/4" Section: Drilling: Open Hole: Cased Hole: 8-1/2" Section: Drilling: Open Hole: Cased Hole: 6-1/8" Section: Drilling: Open Hole: Cased Hole: Intearitv Testina: Test Point 12 %" Surface 9 5/8" Intermediate 7" Drilling Liner 4 V2" Production Liner CASINGfTUBING PROGRAM: ) ~ GRlDirectional - Gyro as needed to ....2000' MD Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (100' intervals) None None GRlDirectional, Resistivity (real-time), PWD Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (40' intervals - 20' intervals at shows), Geochem samples from 9750' MDrkb (40' intervals - 20' intervals at shows), CFM (connection flow monitoring) PEX and RFT's - Contingent on oil being present in the Kuparuk. None GRlDirectional, PWD Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (40' intervals - 20' intervals at shows), Geochem samples (40' intervals - 20' intervals at shows), CFM (connection flow monitoring) None None G RIDirectional, Resistivity/Density/Neutron (recorded) Mud Logging - Gas analysis/detection, show kit with indexed sample bottles, lithology samples (40' intervals - 20' intervals at shows), Geochem samples (40' intervals - 20' intervals at shows), CFM (connection flow monitoring) RFT's - 20 Pressures None Depth Shoe Test Type FIT FIT FIT EMW Estimated Casing/Liner Test 3500 psi w/ 9.3 ppg 4100 psi w/ 10.0 ppg 4800 psi w/ 11.5/8.65 / 3400 psi w/ 9.3 ppg 20' min from 12 1/4" shoe 20' min from 9 5/8" shoe 20' min from 7" shoe 12.5 ppg EMW Target 13.5 ppg EMW Target 11.5 ppg EMW Target Hole Size Casing/ WtlFt Grade Conn. Casing Casing Top Hole 8tm Tbg O.D. Length MDITVDrkb MDITVDrkb 20" 20" 169# X-56 / WELD 201' Su rface 201 '/201 ' 16" 13 3/8" 68# L-80 BTC 3376' Surface 3376'/3206' 12 %" 9 5/8" 47# L -80 / BTC-Mod 10778' Surface 10778'/9384' 8 }2" 7" 26# L-80 Hydril 521 1471' 10628'/9234' 12099'/10706' 6-1/8" 4-1/2" 12.6# 13Cr / Vam Ace 661' 11949'/10555' 12610'/11216' Tubing 4-1/2" 12.6# 13Cr Vam Ace 11949' Surface 11949'/10555' 5 NS28 Permit to Drill -) ~ FORMATION MARKERS: TVDss MDrkb Pore Press. Comment Formation Top estimated (Psi) I (ppg EMW) Top Permafrost 1,149 1204 542 8.65 Base Permafrost 1,519 1574 708 8.65 Set surface casing -150. tvd SV6 - top confining zone 3,005 3194 1376 8.65 below top SV6 Surface casing point 3,150 3375 0 0.00 SV5 - base confining zone 3,288 3547 1504 8.65 SV4 3,595 3931 1642 8.65 SV2 - top upper injection zone 4,000 4438 1824 8.65 SV1 - top major shale barrier 4,445 4994 2024 8.65 - top lower injection zone - T o~ 4,790 5426 2179 8.65 1 - top Schrader Bluff - Base L 6,385 7420 2897 8.65 3ase lower injection zone (top ( 6,956 8135 3154 8.65 THRl - Top HRl 8,649 10093 3915 8.65 BHRl - Base HRl 8,740 10186 3956 8.65 Top Kuparuk 8,770 10216 4265 9.35 Kuparuk C 9,004 10452 4428 9.46 / Top Miluveach 9,278 10727 4333 8.98 Set intermedate casing into the Intermediate casing point 9,328 10778 0 0.00 top of the Miluveach Intermediate logging point 9,328 10778 0 0.00 Top Kingak 9,767 11216 4690 9.23 Fault 48.1 throw = 50. 10,105 11554 Expected in upper Kingak Top Sag River 10,615 12064 4966 8.95 Set drilling liner into top Sag River to cover Kingak. ./ I ntermediate casing point 10,650 12099 0 0.00 Hydrocarbon bearing. Geol target #1 10,615 12064 4992 9.04 Top Shublik - 90 10,725 12174 5017 8.95 Top Ivishak 10,815 12264 5059 8.95 TD - - 80' above OWC. Oil - Water contact 11 ,1 00 12549 5192 8.95 Top Kavik 11140 12589 5210 8.95 Total Depth 11160 12610 5280 9.05 6 NS28 Permit to Drill REQUIRED MATERIALS: L-80 Surface: L-80 Intermediate: L-80 Drlg Liner: 13Cr Liner: 13Cr Completion: -) 3376' 1 - 13 3/8" 1 - 13 3/8" 1 - 13 3/8" 17 -133/8" x 153/4" 1 - 20" x 13 3/8" 1 - 13 5/8" 10778' 1 - 9 5/8" 1 - 9 5/8" 1 - set 1 - 13 5/8" x 9 5/8" 155 - 9 5/8" x 12" 1471' 1 - 8 Y2" 1-7" 1 -7" 6 - 7" x 8 1/4" 1 - 7" x 9 5/8" 1 - 7" x 9 5/8" 1-7" 1-7" 661' 1 - 4-1/2" 1 -4-1/2" 24 - 4-1/2" x 5-3/4" 12- 4-1/2" x 5-3/4" 1 - 4-1/2" x 7" 1 - 4-1/2" x 7" 1 -4-1/2" 11949' 1 1 1 1 1 1 1 1 1 2 1 ~) 133/8",68# L-80 BTC HES Super Seal II Float Shoe (4.25" valve) HES Super Seal II Float Collar (4.25" valve) TAM Port Collar SV Rigid Centralizers ABB-VGI Fluted hanger - BTC down, 11 %" external ACME landing thread ABB-VGI Casing Headrrbg head 95/8", 47# L-80 BTC-MOD HES Super Seal II Float Shoe HES Super Seal II Float Collar HES Cement Plug Set ABB-VGI Casing Hanger SV Rigid Centralizers 7",26# L-80 Hydril 521 BBL reamer shoe HES Super Seal II Float Shoe HES Super Seal II Float Collar SV Rigid Centralizers Baker Flex Lock Hydraulic Set Liner Hanger - Rotating hanger. Baker ZXP Liner Top Packer Baker HRD running tool Baker Landing Collar and plug set 4-1/2",12.6# 13Cr-80 Vam Ace HES Super Seal II Float Shoe HES Super Seal II Float Collar RH Turbulators Stop bands Baker Flex Lock Hydraulic Set Liner Hanger Baker ZXP Liner Top Packer Baker Landing Collar and plug set 4-1/2",12.6# 13Cr-80 Vam Ace 4 Y2" ABB-VGI tubing hanger 4 Y2" ABB- VG I adapter flange 4 Y2" ABB-VGI 5-1/8" 5K Swab Valve w/ tree cap CIDRA mandrel and 0.25" fiber optic cable (w/4 Y2" cable clamps). 4 Y2" SVLN and 2 - 0.25" control lines 4 Y2" x 1 Y2" GLM with dummy valve installed 4 Y2" x 1 Y2" GLM with RP Shear valve installed 7" x 4 Y2" Baker 13 Cr packer S-3. 4 Y2" WLEG (w/o holes) 4 Y2" 13 Cr X nipples 4 Y2" 13 Cr XN nipple 7 NS28 Permit to Drill ~) ~) PERMAFROST: The 13-3/8" surface casing will be run approximately 1600' TVD below the permafrost to -3376' MD I 3206' TVD. The casing will be cemented to surface with a Premium 'G' with 2% calcium chloride tail slurry and a Permafrost 'L' lead slurry. The tail slurry allows sufficient compressive strength to prevent the shoe from breaking down as well as an accelerator to decrease thickening time. The lead slurry is light slurry that contains a freezing point depressant which enables the cement to set up rather than freeze. CEMENT CALCULATIONS: The following cement calculations are based upon a single stage job. Casing 113-3/8" Surface I Basis: Stage 1 : Lead: Based on 200' cased hole capacity from surface to 200' MD, 1574' of Open Hole + 175% excess from the permafrost ~surface + 50% excess to 750'MD above the shoe. Lead TOC: Surface Tail: Based on 750' of 16" open hole x 13 3/8" casing with 500/0 excess + 80' shoe joint. Tail TOC: -2625' MD I Total Cement / Spacer Preflush Spacer Lead 20 bbl sea water 75 bbl Alpha ~acer weighted to 1.0 ppg over mud weight 432 bbl 1584 sk I 2424 ft of 10.7 ppg Permafrost 'L' Cement. 4.15 cf/sk, BHST 50° I BHCT 50°, TT = 6.0 hrs 97 bbl I 471'Sk I 542 ft~ of 15.8 ppg Premium 'G' wI 2% CaCI2. 1.16 cf/sk, BHST 50° I BHCT 50°, TT = 4.0 hrs Tail Casing 19-5/8" Intermediate Basis: Stage 1: Lead: Based on 6022' of 1.1'1/4" open hole x 9 518" csg with 30% excess Lead TOC: At -4438' MD (4055' TVD) Tail: Based on 1561' of 12 %" open hole x 9 5/8" csg with 30% excess + 80' shoe joint. Tail TOC: At -9216' MD (7901' TVD) Stage 1: Total Cement / Spacer Preflush Spacer Lead 20 bbls sea water 50 bbl Alpha Spacer wei~hted to 1.0 ppg over mud MW 347 bbl I 600 sk/I 1945 ft of 11.2 ppg Econolite. 3.24 cf/sk, B~T 210° I. BHCT 130°, TT = 4.0 hrs 119 bbl I 581 sk I 653 fe of 15.9 ppg Premium 'G'. 1.15 cf/sk, BHST 210° I BHCT 130°, TT = 4.0 hrs Tail Casing t7" Drilling Liner Basis: Stage 1: Slurry: Based on 1322' of 8 Y2" open hole x 7" csg with 50% excess + 150' 95/8" csg x 7" csg liner lap + 200' 9-5/8" csg x 5" drillpipe ,above TaL + 80' shoe joint. Slurry TOC: At -10627' MD (9233' TV D) Stage 1: Total Cement / Spacer Spacer 50 bbl Alpha SP9cer ,^:eighted to 1.0 ppg over mud MW Slurry 63 bbl I 235 sk 1353 fe of 15.9 ppg Premium 'G'. 1.50 cf/sk, BHST 250° I BHCT 150°, TT = 4.0 hrs Casing \4-1/2" Prod Liner Basis: Stage 1 : Slurry: Based on 510' of 6 1/8" open hole x 41/2" csg with 500/0 excess + 150' 7" csg x 4 1/2" csg liner lap + 200' 7" csg x 4" drillpipe a9óve TaL + 80' shoe joint. Slurry TOC: At -11949' MD (10555' TVD) Stage 1: Total Cement / Spacer Spacer 35 bbl Alpha $Pacer ~eighted to 1.0 ppg over mud MW Slurry 26 bbl I 96 sltl 144 ft~ of 15.9 ppg Premium 'G'. 1.50 cf/sk, BHST 250° I BHCT 150°, TT = 4.0 hrs 8 NS28 Permit to Drill ) ~) WEll CONTROL: ~ A Diverter waiver has been requested on well NS28. To date, BP has drilled 14 development wells through the Northstar upper stratagraphic intervals and has not experienced any difficulty with shallow gas. All 14 surface holes have been drilled and cemented to a common depth of approximately 3,170' tvdss depth. Each surface shoe has been set in the competent shale horizon approximately 150' TVD below the top of the SV6 formation marker. Well mud logs and seismic data do not indicate the presence of a shallow gas hazard. ~ Equipment to be Installed and capable of handling maximum potential surface pressures. (Schematics are on file with the AOGCC and MMS.) ~ 5000 psi working pressure pipe rams (2) ~ Blind/shear rams ~ Annular preventer ~ Based upon the calculations below, BOP equipment will be tested to 4800 psi. Surface Section: . Maximum anticipated BHP: 1376 psi @ 3005' TVDss - SV6 . Maximum surface pressure: 1015 psi @ surface (Based on BHP and a full column of gas from TD @ 0.12 psi/ft) Intermediate Section: . Maximum anticipated BHP: 4428 psi @ 9004' TVDss - Kuparuk 'C' . Maximum surface pressure: 3348 psi @ surface (Based on BHP and a full column of gas from TD @ 0.12 psi/ft) Drilling Liner Section: . Maximum anticipated BHP: 4966 psi @ 10615' TVDss - Sag River . Maximum surface pressure: 3692 psi @ surface (Based on BHP and a full column of gas from TD @ 0.12 psi/ft) Production Section: . Maximum anticipated BHP: 5280 psi @ 11160' TVDss - Total Depth . Maximum surface pressure: 3934 psi @ surface / (Based on BHP and a full column of gas from TD @ 0.12 psi/ft) . Planned BOP test pressure: 4800 psi (annular to 3500 psi) /' . Planned completion fluid: 8.5 ppg Seawater /6.8 ppg Diesel DRilLING HAZARDS/CONTINGENCIES: HYDROGEN SULFIDE - H2S: ./ Northstar is not designated as an H2S drill site, however Standard Operating Procedures for H2S precautions should be followed at all times. ./ No H2S was detected at Northstar while drilling or testing the Seal Island A-01, A-02, or A- 03 exploration/appraisal wells. ./ No H2S was detected while drilling the NS10 waste disposal well, or any subsequent Northstar wells. Reference information below on file with AOGCC: ~ Northstar/Nabors 33E H2S contingency plan. ~ Well test hydrocarbon analyses for Seal Island A-01, A-02, and A-03. DISPOSAL: Annular Injection: There will be no annular injection in this well. Cuttings Handling: Cuttings generated from drilling operations will be processed in the Grind and Inject Facility on Nabors 33E and will be disposed of in the NS10 Class I Waste Disposal Well. Fluid Handling: All Class I and Class II fluids will be processed by the Grind and Inject Facility on Nabors 33E and will be disposed of in the Northstar NS10 Class I Waste Disposal Well. 9 NS28 Perm it to Drill ) ~ . SURFACE HOLE SECTION: /' Mudloggers will be rigged up throughout the entire section. ,/ No significant drilling problems have been identified in the surface hole interval based on offset data. Good hole cleaning and management of required mud properties are key to a successful interval. Minor tight hole conditions have been noted in the shale intervals immediately below the permafrost during short trips. Differential sticking could be problematic in this hole section adjacent to the permeable SV Sands. Avoid leaving drill string stationary for extended periods, tighten fluid loss properties of mud. Lost circulation has only been noted while drilling during hole opening runs and was most likely induced by poor hole cleaning. Losses have occurred while running and cementing surface casing. The NS27 experienced losses on the surface cement job at a rate of 12 BPM. The displacement rate was lowered to 10 BPM and full returns were re-established. Be sure to condition and thin mud appropriately prior to pulling out of the hole to run casing, and once on bottom with casing, bring circulation up slowly and reduce mud viscosities before pumping cement. Minor losses were seen on NS29 while running the 13 3/8" surface casing. Reduced running speed eliminated losses and the casing was cemented at 10 BPM displacement rate. Gas hydrates may be present near the base of the permafrost. Wells drilled in the 2000-2002 drilling season have not experienced hydrates. Mudloggers will be used continuously on NS18 to help identify and trend any increase in background gas readings. If gas hydrates are encountered, mud weight may be increased to 10.2 ppg and treated with 2 ppb Driltreat (Lecithin). Additional measures include reducing flow rates to -450 to 500 gpm and keeping the mud temperature cool. . . . . . . INTERMEDIATE SECTION: Mudloggers will be rigged up throughout the entire section. '/ Minor gas shows have been reported in the four (4) Seal Island wells and have been identified as coal associated methane. No indications of shallow gas were seen while drilling during the 2000-2002 drilling season. Mudloggers will be used continuously on this well to help identify and /. trend any increase in background gas readings. Surface casing will be set prior to any intervals r with previously noted gas shows to facilitate nippling up the BOP's. A minimum of 9.0 ppg is recommended. The shallow intervals beneath Northstar are, by interpretation, not faulted. To be prepared for any potential lost circulation, a copy of the 'Non-Payzone Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the rig. Pressure While Drilling (PWD) will be used to monitor the annular pressure. The pressure data will be used to minimize the equivalent circulating density (ECD), minimize lost circulation due to packing off due to loading up the wellbore with solids and provide for an additional well control tool to make sure the well does not become under-balanced. Differential sticking can be a problem if lost circulation is occurring or if the drill string is left stationary for an extended period or time across the permeable SV Sands. Gas in the Kuparuk is likely (5000 unit mud log show in NS13). Circulate as required. High mud weight should minimize the gas entry from the Kuparuk. Oil is not expected in the Kuparuk, however, if oil is found be prepared to run wireline logs to evaluate. The kick tolerance for the 12 1/4" open hole section would be 57.1 bbls assuming an influx from the Kuparuk interval at -9059 TVD. This is the worst-case scenario based on a 9.96 ppg (0.5 ppg over the known pore pressure) pore pressure gradient, a fracture gradient (FIT) of 12.5 ppg at the 13-3/8" shoe, and 10.0 ppg mud in the hole. . . . . . . . 10 NS28 Permit to Drill -) ~ DRilliNG LINER SECTION: . Mudloggers will be rigged up throughout the entire section. / Pressure While Drilling (PWD) will be used to monitor the annular pressure. The pressure data will be used to minimize the equivalent circulating density (ECD), minimize lost circulation due to packing off due to loading up the wellbore with solids and provide for an additional well control tool to make sure the well does not become under-balanced. Gas in the Sag is possible. Circulate as required. According to Geology, the top of the Sag is poor, not porous/permeable rock. This, along with the higher mud weight should minimize the gas in the top of the SAG. One (1) seismic-scale fault is likely (50% probability) to be encountered in this wellbore, Fault 48.1. Penetration is expected at - 10105 TVDss +/- 4001 TVDss; within the upper portion of the Kingak Formation. Be prepared for any potential lost circulation, a copy of the 'Non-Payzone Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the Rig. The kick tolerance for the 8-1/2" open hole section is infinite (due to limited amount of open hole) assuming an influx from the Sag River interval. This is the worst-case scenario based on a 9.45 ppg (0.5 ppg over the anticipated pore pressure) pore pressure gradient, a fracture gradient of 13.5 ppg at the 9-5/8" shoe, and 11.5 ppg mud in the hole. . . . . PRODUCTION SECTION: . Mudloggers will be rigged up throughout the entire section. Gas in the Sag River or Ivishak will be circulated out as required. The drilling liner shoe will be drilled out with the 11.5 ppg mud. The mud will then be displaced with a 9.1 ppg drill-in fluid. The mud weight will be increased to 9.3 ppg prior to tripping out of the hole. Differential sticking is not anticipated but the drill string should not be left stationary for any length of time. Though not visible seismically, there are possible faults in the Sag river, Shublik and and Ivishak. The narrow structural horst that is being targeted is part of the the large-displacement fault system that defines the northern boundary of the Northstar overall closure. Prudhoe experience suggests that the deformation zone around large-displacement faults can be as much as 400' from the mapped fault plane. The center of the target circle is 400 feet away from fault 48.1, which has 150-200' of displacement. Therefore there is some risk of loss circulation in the Sag through Ivishak interval associated with close proximity to a large displacement fault. Potential losses will be treated with the "Pay-zone" loss circulation decision tree. The well is planned to stop short of the OWC. The Kavik will not be penetrated. The project Geologist will be in charge of picking TD above the OWC and sufficient rathole will be drilled. The kick tolerance for the 6 1/8" open hole section is infinite (due to limited amount of open hole) assuming an influx from the proposed TD. This scenario is based on a 9.45 ppg (0.5 ppg over the anticipated pore pressure) pore pressure gradient, a fracture gradient of 11.5 ppg (based on FIT) at the 7" shoe, and 9.1 ppg mud in the hole. . . . . . . 11 NS28 Permit to Drill ) ~ NS28 Ria-site Summary of Drillina Hazards POST THIS NOTICE IN THE DOGHOUSE ~ Gas hydrates may be present near the base of the permafrost. Mudloggers will be used continuously on NS28 to help identify and trend any increase in background gas readings. If gas hydrates are encountered, mud weight may be increased to 10.2 ppg and treated with 2 ppb Driltreat (Lecithin). Additional measures include reducing flow rates to -450 to 500 gpm and keeping the mud temperature cool. ~ Differential sticking could be problematic in both the surface and intermediate hole sections adjacent to the permeable SV Sands. Avoid leaving drill string stationary for extended periods; tighten fluid loss properties of mud. ~ Minor gas shows have been reported in the four (4) Seal Island wells and have been identified as coal associated methane. No indication of shallow gas was seen in any previously drilled Northstar wells. Mudloggers will be used continuously on NS28 to help identify and trend any increase in background gas readings. Surface casing will be set prior to any intervals with previously noted gas shows to facilitate nippling up the BOP's. ~ Severe losses have been seen in the intermediate section with a higher mud weight (11.6 ppg). The well design has been changed to alleviate this problem. The new casing design sets the 9 5/8" casing in the Miluveach and drills out with an 8 Y2" assembly to the Top Sag to allow an appropriate cushion for mud weight increases in the Jurassic shale interval. To be prepared for any potential lost circulation, the 'Lost Circulation Decision Tree' can be found in the last section of the Master Well Plan, which can be found on the Rig. ~ Packing off due to improper hole cleaning can lead to stuck pipe. The PWD data, pick- up/slack-off weights and other drilling parameters must be monitored at all times. If in doubt, stop and condition the hole prior to drilling ahead or tripping. ~ Bit balling has been experienced in the Miluveach. The mud properties and PDC bit selection will be closely monitored to minimize potential balling. ~ The Kingak shale, in the offset Seal Island wells drilled by Shell, experienced severe hole instability. The casing shoe at the base of the Kuparuk, higher mud weight and lower angles will help with hole conditions. ~ Conglomerate drilling in the Ivishak can lead to lost circulation, packing off due to unconsolidated formation and directional problems due to deflection of the drill string off of large rocks. Key drilling parameters must be monitored at all times. Do not drill ahead if a potential problem is detected. Severe lost returns were experienced on the NS29 in the Shublik and Ivishak. The LCM decision tree will be maintained on the rig as well as in the Master Well Plan. ~ Northstar is not a designated H2S pad. ~ CONSULT THE NORTHSTAR PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION 12 TREE: ABB-VGI 5 1/8" 5ksi ' WELLHEAD: ABB-VGI 13-5/8" --) NS28 - Proposed Multibowl 5ksi qRIGINAL KB. ELEV = 56' ---þ-BF. ELEV = 40.1' CB. ELEV = 15.9' 13 3/8" TAM Port Collar at +1-1600'MD 13 3/8", 68#/ft, L-80, BTC @ 3376' MD 4 1/2", 12.6#/ft, 13-Cr, Yam-Ace TUBING 10: 3.958" CAPACITY: 0.01522 BBL/FT 9-5/8" 47# L-80 BTM-C @ 10776' MD 4.5" X NIPPLE, @ 11899' MD 3.813" 10 4.5" X NIPPLE, @ 11919' MD 3.813" 10 4.5" XN NIPPLE, @ 11929' MD 3.725" 10 4.5" WLEG, @ 11939' MD 3.958" 10 - 7", 26#/ft L-80, Hydril 521 @ 12099' MD PBTD @ 12570' MD TO @ 12610' MD ~ ~ 6- B , E J. J DATE 7/19/02 REV. BY JAS COMMENTS )-.JS28 tJroposed ~ ~ I / 1/2" SSSV @ 2000' TVD wI HXO SVLN nipple - 4.562" 10 6.8PPG DIESEL FREEZE PROTECTION AT +1- 4056' TVD (4439'MD) .. 41/2" GLM @ 4500' TVD (4995' MD) wI 4.62" ID 4 1/2" GLM @ 5702' TVD (6500' MD) wI 4.62" ID !\. - 7" LINER TOP @ 10626' MD 4.5" Fiber Optic Transducer 3.958" ID -;7 - 7" PACKER, 13 Cr @ 11909' MD ~E ~ ~ 4.5" LINER TOP @ 11949' MD 4.5",12.6#, 13Cr Yam Ace Northstar WF. . : NS?8 API NO: BP Exploration (Alaska) TREE: ABB-VGI 5 1/8" 5ksi WELLHEAD: ABB-VGI 13-5/8" Multibowl 5ksi -) ~ NS28 - Operation Shutdown ORIGINAL KB. ELEV = 56' KB-BF. ELEV = 40.1' CB. ELEV = 15.9' 13 3/8" TAM Port Collar at +/-1600'MD . 6.8PPG DIESEL FREEZE PROTECTION AT +/- 1600' TVD (1600'MD) 13 3/8", 68#/ft, L-80, BTC @ 3376' MD ~ ~ ~ 8.65 ppg Seawater from 1600' MD / 1600' TVD to 10626' MD / 9232' TVD EMW = 9.04ppg 9-5/8" 47# L-80 BTM-C @ 10776' MD ~ 6" l\. - 7" LINER TOP @ 10626' MD . 11.5 ppg drilling mud from 10626' MD / 9232' TVD to 12099' MD /10706' TVD 7", 26#/ft L-80, Hydril 521 @ 12099' MD J. .... DATE 7/25/02 REV. BY JAS COMMENTS ~S28 Operation Shutdown Northstar WFI I : NS28 API NO: BP Exploration (Alaska) õ NS28 Schlumberger Report Date: Client: Field: Structure 1 Slot: Well: Borehole: UWI/API#: Survey Name 1 Date: Tort 1 AHD 1 DDII ERD ratio: Grid Coordinate System: Location Lat/Long: Location Grid NfE Y/X: Grid Convergence Angle: Grid Scale Factor: Proposed Well Profile 26-Jul-02 BP Exploration Alaska Northstar Northstar PF / NS28 d NS28 ..e ~;~~~ Aapro., NS28 (P4b) S22/ July {" 2002 73.812° /4536.54 ft /5.576/0.404 NAD27 Alaska State Planes, Zone 4, US Feel N 70.49148680, W 148.69332934 N 6031091.250 ftUS, E 659823.570 ftUS +1.23168102° 0.99992902 - Geodetic Report Survey 1 DLS Computation Method: Vertical Section Azimuth: 2 Vertical Section Origin: TVD Reference Datum: 7/26/0 TVD Re~renc. Elevation: Sea Bed 1 Ground Level Elevation: Magnetic Declination: Total Field Strength: Magnetic Dip: Declination Date: Magnetic Declination Model: North Reference: Total Corr Mag North.> True North: Local Coordinates Referenced To: Minimum Curvature / Lubinski 342.140° N 0.000 ft, E 0.000 ft KB 55.8 ft relative to MSL 15.670 ft relative to MSL 26.257° 57543.281 nT 80.945° August05,2002 BGGM 2002 True North +26.257° Well Head I : ~ Grid Coordinates Geographic Coordinates I Station ID MD I Incl I Azim I TVD I VSec I N/-S I E/.W I DLS Northing I Easting Latitude I Longitude (ft) (°) (°) (ft) (ft) (ft) (ft) (°/1 OOft) (ftUS) (ftUS) KBE 0.00 0.00 342.00 0.00 0.00 0.00 0.00 0.00 6031091.25 659823.57 N 70.49148680 W 148.69332934 Top Perm 1204.77 0.00 342.00 1204.77 0.00 0.00 0.00 0.00 6031091.25 659823.57 N 70.49148680 W 148.69332934 KOP Bid 1.25/100 1500.00 0.00 342.00 1500.00 0.00 0.00 0.00 0.00 6031091.25 659823.57 N 70.49148680 W 148.69332934 Base Perm 1574.77 0.93 342.00 1574.77 0.61 0.58 -0.19 1.25 6031091.83 659823.37 N 70.49148838 W 148.69333090 Bid 2.5/100 1600.00 1.25 342.00 1599.99 1.09 1.04 -0.34 1.25 6031092.28 659823.21 N 70.49148964 W 148.69333212 1700.00 3.75 342.10 1699.89 5.45 5.19 -1.68 2.50 6031096.40 659821.78 N 70.49150098 W 148.69334308 1800.00 6.25 342.12 1799.50 14.17 13.48 -4.36 2.50 6031104.63 659818.92 N 70.49152363 W 148.69336498 1900.00 8.75 342.13 1898.64 27.22 25.90 -8.36 2.50 6031116.96 659814.66 N 70.49155755 W 148.69339768 2000.00 11.25 342.13 1997.11 44.58 42.43 -13.69 2.50 6031133.37 659808.97 N 70.49160271 W 148.69344125 LJ 2100.00 13.75 342.13 2094.73 66.22 63.03 -20.33 2.50 6031153.82 659801.89 N 70.49165899 W 148.69349553 ../ 2200.00 16.25 342.14 2191.32 92.10 87.66 -28.27 2.50 6031178.28 659793.42 N 70.49172627 W 148.69356043 2300.00 18.75 342.14 2286.68 122.17 116.28 -37.50 2.50 6031206.69 659783.58 N 70.49180446 W 148.69363588 2400.00 21.25 342.14 2380.64 156.37 148.83 -47.98 2.50 6031239.00 659772.41 N 70.49189338 W 148.69372155 2500.00 23.75 342.14 2473.02 194.64 185.25 -59.72 2.50 6031275.16 659759.89 N 70.49199288 W 148.69381753 2600.00 26.25 342.14 2563.65 236.90 225.47 -72.68 2.50 6031315.09 659746.07 N 70.49210275 W 148.69392347 2700.00 28.75 342.14 2652.34 283.07 269.42 -86.84 2.50 6031358.72 659730.97 N 70.49222282 W 148.69403923 2800.00 31.25 342.14 2738.94 333.06 317.00 -102.17 2.50 6031405.96 659714.62 N 70.49235280 W 148.69416455 2900.00 33.75 342.14 2823.27 386.79 368.14 -118.65 2.50 6031456.73 659697.04 N 70.49249251 W 148.69429927 NS28 (P4b) report.xls Page 1 of 3 7/26/2002-9:41 AM Grid Coordinates Geographic Coordinates Station ID MD I Incl Azim TVD VSec N/.S E/-W I DLS Northing Easting Latitude I Longitude (It) (°) (°) (ft) (ft) (ft) (ft) r/100ft) (ftUS) (ftUS) 3000.00 36.25 342.14 2905.18 444.14 422.73 -136.24 2.50 6031510.92 659678.29 N 70.49264164 W 148.69444308 End Bid 3026.23 36.91 342.14 2926.24 459.77 437.61 -141.03 2.50 6031525.70 659673.18 N 70.49268229 W 148.69448223 SV6 3194.47 36.91 342.14 3060.77 560.80 533.77 -172.01 0.00 6031621.16 659640.14 N 70.49294498 W 148.69473551 13-3/8" Csg pt 3375.80 36.91 342.14 3205.77 669.69 637.41 -205.40 0.00 6031724.05 659604.53 N 70.49322811 W148.69500849 SV5 3548.39 36.91 342.14 3343.77 773.33 736.06 -237.18 0.00 6031821.99 659570.64 N 70.49349761 W 148.69526832 SV4 3932.32 36.91 342.14 3650.77 1003.88 955.50 -307.88 0.00 6032039.84 659495.25 N 70.49409708 W 148.69584638 SV2 4438.80 36.91 342.14 4055.77 1308.03 1244.99 -401.15 0.00 6032327.24 659395.78 N 70.49488791 W 148.69660902 SV1 4995.32 36.91 342.14 4500.77 1642.21 1563.08 -503.63 0.00 6032643.03 659286.50 N 70.49575688 W 148.69744704 TMBK 5426.77 36.91 342.14 4845.77 1901.30 1809.68 -583.08 0.00 6032887.85 659201.77 N 70.49643054 W 148.69809678 I > WS1 7421.46 36.91 342.14 6440.77 3099.11 2949.79 -950.39 0.00 6034019.72 658810.07 N 70.49954506 W 148.70110121 "-' CM3 8135.54 36.91 342.14 7011.77 3527.92 3357.94 -1081.89 0.00 6034424.92 658669.83 N 70.50066002 W 148.70217704 Drp 2/100 8859.25 36.91 342.14 7590.46 3962.51 3771.58 -1215.15 0.00 6034835.57 658527.72 N 70.50178997 W 148.70326739 8900.00 36.09 342.14 7623.22 3986.75 3794.66 -1222.59 2.00 6034858.48 658519.79 N 70.50185302 W 148.70332827 9000.00 34.09 342.14 7705.04 4044.23 3849.37 -1240.22 2.00 6034912.79 658500.99 N 70.50200247 W 148.70347253 9100.00 32.09 342.14 7788.82 4098.82 3901.34 -1256.96 2.00 6034964.39 658483.14 N 70.50214444 W 148.70360951 9200.00 30.09 342.14 7874.45 4150.46 3950.48 -1272.79 2.00 6035013.17 658466.26 N 70.50227868 W 148.70373905 9300.00 28.09 342.14 7961.83 4199.08 3996.76 -1287.70 2.00 6035059.12 658450.36 N 70.50240510 W 148.70386106 9400.00 26.09 342.14 8050.85 4244.62 4040.10 -1301.66 2.00 6035102.14 658435.47 N 70.50252349 W 148.70397529 9500.00 24.09 342.14 8141.41 4287.02 4080.46 -1314.67 2.00 6035142.21 658421.60 N 70.50263374 W 148.70408176 9600.00 22.09 342.14 8233.40 4326.24 4117.79 -1326.69 2.00 6035179.27 658408.78 N 70.50273572 W 148.70418012 9700.00 20.09 342.14 8326.69 4362.22 4152.04 -1337.73 2.00 6035213.27 658397.00 N 70.50282928 W 148.70427047 9800.00 18.09 342.14 8421.19 4394.92 4183.17 -1347.76 2.00 6035244.18 658386.31 N 70.50291432 W 148.70435255 9900.00 16.09 342.14 8516.77 4424.31 4211.14 -1356.77 2.00 6035271.95 658376.70 N 70.50299072 W 148.70442628 10000.00 14.09 342.14 8613.31 4450.34 4235.92 -1364.75 2.00 6035296.55 658368.19 N 70.50305841 W 148.70449158 Top HRZ 10093.92 12.21 342.14 8704.77 4471.71 4256.26 -1371.30 2.00 6035316.74 658361.20 N 70.50311398 W 148.70454519 10100.00 12.09 342.14 8710.71 4472.99 4257.48 -1371.70 2.00 6035317.95 658360.78 N 70.50311731 W 148.70454846 U Base HRZ 10186.72 10.36 342.14 8795.77 4489.87 4273.54 -1376.87 2.00 6035333.90 658355.26 N 70.50316118 W 148.70459077 10200.00 10.09 342.14 8808.84 4492.23 4275.79 -1377.60 2.00 6035336.13 658354.49 N 70.50316733 W 148.70459674 Top Kuparuk 10217.19 9.75 342.14 8825.77 4495.19 4278.60 -1378.50 2.00 6035338.92 658353.53 N 70.50317500 W 148.70460411 10300.00 8.09 342.14 8907.58 4508.03 4290.82 -1382.44 2.00 6035351.05 658349.32 N 70.50320838 W 148.70463635 10400.00 6.09 342.14 9006.81 4520.37 4302.57 -1386.23 2.00 6035362.72 658345.28 N 70.50324048 W 148.70466737 KupC 10453.21 5.03 342.14 9059.77 4525.52 4307.48 -1387.81 2.00 6035367.59 658343.60 N 70.50325390 W 148.70468030 10500.00 4.09 342.14 9106.41 4529.24 4311.02 -1388.95 2.00 6035371.11 658342.38 N 70.50326357 W 148.70468963 10600.00 2.09 342.14 9206.26 4534.63 4316.15 -1390.60 2.00 6035376.20 658340.62 N 70.50327758 W 148.70470313 10700.00 0.09 342.14 9306.23 4536.54 4317.96 -1391.18 2.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 NS28 (P4b) report. xis Page 2 of 3 7/26/2002-9:41 AM Grid Coordinates Geographic Coordinates Station ID MD Inel Azim TVD VSee N/-S E/-W I DLS Northing I Easting Latitude I Longitude (ft) (°) (°) (ft) (ft) (ft) (ft) (0/100ft) (ftUS) (ftUS) End Drp 10704.54 0.00 342.00 9310.77 4536.54 4317.96 -1391.18 2.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 TMLV 10727.54 0.00 342.00 9333.77 4536.54 4317.96 -1391.18 0.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 9-5/8" Csg pt 10777.54 0.00 342.00 9383.77 4536.54 4317.96 -1391.18 0.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 Top Kingak 11216.54 0.00 342.00 9822.77 4536.54 4317.96 -1391.18 0.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 Fault 48 Crossing 11554.54 0.00 342.00 10160.77 4536.54 4317.96 -1391.18 0.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 Target S22 12064.54 0.00 342.00 10670.77 4536.54 4317.96 -1391.18 0.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 Top Sag 12064.55 0.00 342.00 10670.78 4536.54 4317.96 -1391.18 0.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 7" Csg pt 12099.54 0.00 342.00 10705.77 4536.54 4317.96 -1391.18 0.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 Top Shublik 12174.54 0.00 342.00 10780.77 4536.54 4317.96 -1391.18 0.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 Top Ivishak 12264.54 0.00 342.00 10870.77 4536.54 4317.96 -1391.18 0.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 ~ owe 12549.54 0.00 342.00 11155.77 4536.54 4317.96 -1391.18 0.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 Top Kavik 12589.54 0.00 342.00 11195.77 4536.54 4317.96 -1391.18 0.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 TD /4-1/2" Csg pt 12609.54 0.00 342.00 11215.77 4536.54 4317.96 -1391.18 0.00 6035378.00 658340.00 N 70.50328252 W 148.70470788 Leaal Description: Surface: 1318 FSL 648 FEL S11 T13N R13E UM Target S22: 356 FSL 2036 FEL S2 T13N R13E UM BHL: 356 FSL 2036 FEL S2 T13N R13E UM Northina eV) rftUSl Eastina eX) rftUSl 6031091.25 659823.57 6035378.00 658340.00 6035378.00 658340.00 ~ NS28 (P4b) report. xis Page 3 of 3 7/26/2002-9:41 AM ) ~ VERTICAL SECTION VIEW Client: BP Exploration Alaska Well: NS28 (P4b) Field: Northstar Structure: Northstar PF Section At: 342.14 deg Date: July 26, 2002 Schlumberg8r 0 ----- KOP Bid 1;251100 k1500MD 1500TVD . 0.00' 342:....'00' az 0 departure Bid 2.51100 - - - - ~6~MO 1OO0TVD - 1.25' :fi2.0Õ"az- - - - _. - _1 d~~e - - - Top perm 120fMD1205TVD - - - BãsePerm157sMD157sTVD - - - - - -- ----- - - -- - 'ß1LV-10728 MD 9334 TVD - - - - - End Bid 3026 MD 2926 TVD 36.~1' 342.14' az 400 departure 13-318" Csg pt '3376 MD 3206 TVD ~~~~;:£.az"SV6""3194MthOEffì\lI) - - -- - - -- 2000 ------ ------ - "SV5"""3548"M~344r\I1J - - "SV4"""393:<M~ - - - - - - -- ::¡:;- 0)- O)...J "'""c/) g~ 0 Q) N > II .8 c: CU ;:~ _r--.- ..c:1': ..... L{) O-L{) 0)- oeo m~ o.¡...: -- Q) ffiD:: > ã> 0)- :JW ~ I- ------ - - -- 4000 ""lIe' ------ SVn439 MIP056 TVD - ------ SV14005MQ45Õ'fTVD - TMBK 5427 ME> 4846 TVD - - - -- ------ - - -- Hold Angle 36.910 6000 ------ "Ws17421MD6441TVD - CM3 8136 MD 7012 TVD 36-:91'342:14'ãž - 3528 departure - - -- ---'-- - - -- Drp 21100 8859 MD 7590 TVD 36.91' 342.14' az 3963 departure End Dip 10705 MD 9311 TVD ~ 0.00' ,342.00' az 4537 departure 9-S18" Csg Pt 10778 MD 9384 TVD 0.00' 342.00' az 4537 departure :M~i.~c~~,~.o '''''~ O.pO' 342.00' az 4537 departure 8000 ==~~~~~~~~~~mw1~~~~1~1~D~26~== -- -------~~~MD~~-- . ---,-- - - -- - Top Kiñgak11217ME> 9ã23ïVD- - - -- 10000 Hold Angle 0.000 200' Radius T,,'QPf 1':"" 1?11f¡~~.m 111f¡71 TVD 0.00': 342.00' az 4537 departure = = = = = = = = = = :¡~. pp~.:DO§¡~.o;:;,t06]J~m:: = = = = - - - - - - - - - - ~~~~1~~~~ r Csg Pt 12100 MD 10706 TVD - - 1loo~342bo'::ãz 4537 :¡jãparture - - -- ----- ----- -==~~,;¡¡:;~= ------ ------ 12000 TDI4-1I2"CsgPt12610MD 11216TVD 0.00' 34200' az 4537 departure ---.----- I 0 Vertical Section Departure at 342.14 deg from (0.0, 0.0). (1 in = 2000 feet) I -2000 I 2000 I 4000 I 6000 -3000 5000 4000 ^ ^ ^ I l- e::: 0 z 3000 _... 2000 I I- ::> 0 C/) V V V ') Client: Well: Field: Structure: Scale: Date: PLAN VIEW BP Exploration Alaska NS28 (P4b) Northstar Northstar PF 1 in = 1000 ft 26-Jul-2002 -2000 7" <:$g Pt 12100 MD 10706 TVD 0.00" 342.00' az 4318 N 1391 W Fault 48 Crossing 11555 MD 10161 TVD 0.00' 342.00' az 4318 N 1391 W 1 000 ----.-.----.--------------------- 0- I --------------- -1000 -----1---'---- i I -3000 -2000 «< WEST -1000 0 r 1000 r True North Mag Dee ( E 26.26° ) Target 522 12065 MD 10671 TVD O.OJ' 342.00' az 43'8N 1391 W 9-518" Csg Pt 10778 MD 9384 TVD 0.00' 342.00' az 4318 N 1391 W End Drp 10705 MD 9311 TVD 0.00' 342.00' az 4318 N 1391 W Drp 2/100 8859 MD 7590 TVD 36.91' 342.1..' az 3772 N 1215 W t;> ~ 0- ~. % ~ ~ 'Q °0 13-318" Csg Pt \3376 M. D 3206 TVD 36.91' 342.14' az 637N 205W End Bid 3026 MD 2926 TVD 36.91' 342.14' az 438 N 141 W / ~ Bid 2.5/100 KOP Bid 1.25/100 1600 MD 1600 TVD 1500 MD 1500 lYD 1.25' 342.00' az 0.00' 342.00' az 1 NOW 0 N OE -1000 0 EAST »> ~ i I 1000 Schlumbøruør 5000 4000 3000 2000 1000 0 --1000 ) Schlumberger Anticollision Report ~ Comp;tny: BPAm~o Field: . Northståf' . Referenc~S,ite: Northstar PF RefereticeWeU: NS28 Refèr~tice:Wellpatb: PlanNS~8 NO GLOBAL SCAN: Using user defined selection & scan criteria Interpolation Method: MD Interval: 50.00 ft Depth Range: 40.20 to 12609.54 ft Maximum Radius: 3000.00 ft Ðated'7126120Ó2 . Tbne:""'.".O$:44:.15 Ç~rélJtçlte(NE}l~Ø"~en~:' W~I.;'N~28,TrLJt}'N9rth Yerti~:aV1)lJtefer~n,ee: N33E55;8 . . . D~: 'Sybå$19 Principal Plan & PLANNED PROGRAM ISCWSA Ellipse Trav Cylinder North Ellipse + Casing Reference: Error Model: Scan Method: Error Surface: Survey Program for Definitive Wellpath Date: 11/1/2000 Validated: No Planned From To Survey ft ft 40.20 1500.00 1500.00 12609.54 Version: Toolcode 4 Tool Name Planned: Plan #4 V1 Planned: Plan #4 V1 CB-GYRO-SS MWD+IFR+MS Camera based gyro single shots MWD + IFR + Multi Station Casing Points MD TVD Diameter Holt~Size Name ft ft in in 3375.80 3205.77 13.375 16.000 13 3/8" 10749.54 9355.77 9.625 12.250 95/8" 12094.54 10700.77 7.000 8.500 7" 12609.54 11215.77 4.500 6.125 41/2" Summary Rêferenee Offset Ctr-Ctr '..N~ Allowable MD MD. Di~ce'.Area Deviation ft ft ft ft ft Northstar PF NS05 Plan NS05 V10 Plan: PI 1547.70 1550.00 230.01 30.40 199.61 Pass: Major Risk Northstar PF NS06 NS06 V32 749.63 750.00 223.40 14.91 208.49 Pass: Major Risk Northstar PF NS07 NS07 V33 199.59 200.00 212.32 4.94 207.39 Pass: Major Risk Northstar PF NS08 NS08 V18 1595.43 1600.00 201.47 28.82 172.66 Pass: Major Risk Northstar PF NS09 NS09 V14 1199.04 1200.00 193.33 21.93 171.39 Pass: Major Risk Northstar PF NS10 NS10 V17 799.79 800.00 166.38 13.97 152.44 Pass: Major Risk Northstar PF NS11 Plan NS 11 V7 Plan: Pia 699.37 700.00 171.86 15.91 155.95 Pass: Major Risk Northstar PF NS12 NS12 V23 996.12 1000.00 153.25 20.84 132.41 Pass: Major Risk Northstar PF NS13 NS13 V12 1596.51 1600.00 149.37 26.20 123.18 Pass: Major Risk Northstar PF NS14 NS14 V11 1596.69 1600.00 134.40 29.31 105.10 Pass: Major Risk Northstar PF NS15 NS15 V19 1249.09 1250.00 136.05 24.28 111.77 Pass: Major Risk Northstar PF NS16 NS16 V34 699.02 700.00 120.03 15.92 104.12 Pass: Major Risk Northstar PF NS17 Plan NS 17 V7 Plan: Pia 1643.86 1650.00 100.65 33.26 67.41 Pass: Major Risk Northstar PF NS18 NS18 V8 1094.57 1100.00 86.53 24.41 62.18 Pass: Major Risk Northstar PF NS19 Plan NS19 V1 Plan: Pia 900.13 900.00 91.19 17.77 73.43 Pass: Major Risk Northstar PF NS20 Plan NS20 V6 Plan: Pia 746.31 750.00 59.25 17.56 41.69 Pass: Major Risk Northstar PF NS22 Plan NS22 V2 Plan: Pia 1047.11 1050.00 40.47 23.28 17.19 Pass: Major Risk Northstar PF NS24 Plan NS24 V6 Plan: Pia 849.78 850.00 41.54 18.57 22.98 Pass: Major Risk Northstar PF NS26 NS26 V22 1600.00 1600.00 13.15 9.15 4.01 Pass: Minor 1/200 Northstar PF NS27 NS27 V29 599.89 600.00 8.76 5.82 2.94 Pass: Minor 1/200 Northstar PF NS29 NS29 V22 299.60 300.00 9.89 3.75 6.15 Pass: Minor 1/200 Northstar PF NS31 NS31 V14 849.55 850.00 32.43 16.89 15.54 Pass: Major Risk Seal Island SEAL-A-01 SEAL-A-01 V4 2530.19 2500.00 94.91 42.36 52.55 Pass: Major Risk Seal Island SEAL-A-02 SEAL-A-02 VO 2531.47 2500.00 75.62 41.72 33.91 Pass: Major Risk Seal Island SEAL-A-02 SEAL-A-02A V4 2531.22 2500.00 75.61 39.34 36.29 Pass: Major Risk Seal Island SEAL-A-03 SEAL-A-03 V4 2316.91 2300.00 109.46 39.63 69.87 Pass: Major Risk Seal Island SEAL-A-04 SEAL-A-04 V4 2737.99 2650.00 206.50 59.03 149.98 Pass: Major Risk N520(Plan NS20) - ---_._-------~----~-----~- Field: Site: Well: Wellpath: Northstar Northstar PF NS28 Plan NS28 0 I1r ¡ '--' NS31 (N83l) L, Tra"elling Cyll:nder Azia¡ut~ (IFO+AZI) {deg] ,,'5 Centre to Ct'ntre Separation {3Oftlin] Site: Northstar PF . ) Drilling Target Conf.: 99%- Description: Sag Tgt Map Northing: 6035378.00 ft Map Easting : 658340.00 ft Latitude: 70030'l1.817N Shape: Circle Target: S22 ~ll: NS28 ddSed on: Planned Program Vertical Depth: 10615.00 ft below Mean Sea Level Local +N/-S: 4317.96 ft Local +E/-W: -1391.18 ft Longitude: 148°42'16.948W Radius: 200 ft lOO 4-500 4-500 4-4-00 4-300 4-200 4-100 4-000 0 0 0 0 0 0 0 CJ 0 0 0 0 0 0 0 0 CJ 0 r ~ LD Ln 3- (I) N CJ ~ 0 0 / ~ / ~ I H 207003 DATE 7/12/02 CHECK NO. H207003 DATE INVOICE I CREDIT MEMO GROSS VENDOR DISCOUNT NET DESCRIPTION 7/12/02 INV# CK071002D PERMIT TO DRILL FEE /?[' ~'S~<3 JU¡ ? 0, A I .... F 0J) rJ/8Ska /1;1 .... .... ~,j1ì2 1./1, & Ii A CiS :;:OOS. ' I1ClJorage Cblllll11SSl0n THE ATTACHED CHECK IS IN PAYMENT FOR ITEMS DESCRIBED ABOVE. TOTAL .... PAY BPEXPLORATION, (AlBASKA)IN6. P.O.. SOX 196612 . ANCHORAGE, ALASKA99519.6612 TO THE ORDER OF U8 20 700 31,,8 .:0 ~ ~ 2038., 51: 008 ~ ~ ~ ""8 H '-1 I ~ L -J -J TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER /u'4~ C/-~'f- WELL NAME /~ç ;? f PTD# .2ð2-- /~ ~ CHECK WHAT APPLIES ADD-ONS (OPTIONS) MUL TI LATERAL (If API number last two (2) digits are between 60-69) PILOT (PH) HOLE SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07/10/02 C\jody\templates "CLUE" The permit is for a new wellbore segment of existing well Permit No, API No. Production should continue to be reported as a function' of the original API number stated above. In accordance with 20 AAC 25.005(t), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 70/80) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Company Name) assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. /U/-4¿r ?lA//! YiELL PERMIT CHECKLIST COMPANY /1/ X WELL NAME /f/S -./. ¡¡ PROGRAM: Exp - Dev 2{.Redrll - Re-Enter - Serv - Wellbore seg - ~ FIELD & POOL .LJ;7Q/..Q¿;) INITCLASS (J'Pß /-o"ï GEOLAREA ~7/') UNIT# //J'S':on ON/OFFSHOREA ADMINISTRATION 1. Permit fee attached. . . . . . . . . . . . . . . . . . . . . . . 9. N 2. Lease number appropriate. . . . . . . . . . . . . . . . . . . Y N 3. Unique well name and number. . . . . . . . . . . . . . . . . Y I N 4. Well located in a defined pool.. . . . . . . . . . . . . . . . . Y N 5. Well located proper distance from drilling unit boundary. . . . Y N 6. Well located proper distance from other wells.. . . . . . . . . Y N APPR DATE 7. Sufficient acreage available in drilling unit.. . . . . . . . . . . Y N P/Þ ~. ..., pd-:; 8. If deviated, is wellbore plat included.. . . . . . . . . . . . .. ä N 4/I=::r- .LL ¿ C/¿., 9. Operator only affected party.. . . . . . . . . . . . . . . . . . Y N 10. Operator has appropriate bond in force. . . . . . . . . . . . . y. N 11. Permit can be issued without conservation order. . . . . . . . Y N 12. Permit can be issued without administrative approval.. . . . . N (Service Well Only) 13. Well located wlin area & strata authorized by injection order #- Y / /L/.. ,. A" (Service Well Only) 14. All wells w/in X mile area of review identified. . . . . . . . .. /". N ENGINEERING 15. Conductor string provided. . . . . . . . . . . . . . . . . . . f:j) N 1,..v il ~ z.o ( , . 16. Surface casing protects all known USDWs. . . . . . . . . . . ?1J N 17. CMT vol adequate to circulate on conductor & surf csg. . . . . &. N 18. CMT vol adequate to tie-in long string to surf csg. . . . . . . . Y ~ . 19. CMT will cover all known productive horizons. . . . . . . . . . <1j N 20. Casing designs adequate for C, T, B & permafrost. . . . . . . $tN ... i 1 "77 Þ 21. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . N f4tt(¡orS ;) J '- 22. If a re-drill, has a 10-403 fo~ abandonment been approved. . . A.t/A- 23. Adequate wellbore separation proposed.. . . . . . . . . . . . - N . I 24. If diverter required, does it meet regulations. . . . . . . . .."* .Wcvè \I.(J-ý ~õlA.2~t~. 25. Drilling fluid program schematic & equip list adequate. . . . . N d. $' PP1 j1/ú'f..( MW. 26. BOPEs, do they meet regulation. . . . . . . . . . . . . . . . N .. ¿. L +- i'if : 27. BOPE press rating appropriate; testto 4100 psig. NMç,e '5'7~c.t fSt,. t'{qc~'fØ;L ~ DO ps.'o .^- 28. Choke manifold complies w/API RP-53 (May 84). . . . . . . . N tJC,~ 1l3::( 0 L 29. Work will occur without operation shutdown. . . . . . . . . . . . JIl,. 30. Is presence of H2S gas probable.. . . . . . . . . . . . . . . . (þy 31. Mechanical condition of wells within AOR verified. . . . . . . . -¥-N- Ail A- 32. Permit can be issued wlo hydrogen sulfide measures. . . . . éf) N 33. Data presented on potential overpressure zones. . . . . . . . ;r A } /) 34. Seismic analysis of shallow gas zones. . . . . . . . . . . . . N / {/ (/ ~/ v 35. Seabed condition survey (if off-shore). . . . . . . . . . . . " . Y N 36. Contact namelphone for weekly progress reports. . . . . . . . Y N GEOLOGY: PETROLEUM ENGINEERING: RESERVOIR ENGINEERING UIC ENGINEER RP~ APPR DATE (Service Well Only) GEOLOGY APPR DATE ~Þ'<.' ~øf.¿ . (E'¿ploratory Only) COMMISSIONER: TEM JDH JBR COT , J .l DTS 0 7¡'JO/O ~ SFD WGA itJ4V MJW Rev: 07112/02 G:\geology\perm its\checklist.doc )-- Comments/lnstructions: