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Home My WebLink About204-169 e e Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ~ Q Lb - 1 ~ cr- Well History File Identifier Organizing (done) D Two-sided 11I111111I111111111 D Rescan Needed 111111111111111I111 R~CAN "If Color Items: D Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Diskettes, No. D Other, Norrype: D Poor Quality Originals: OVERSIZED (Non-Scannable) D Other: D Logs of various kinds: NOTES: D Other:: BY: ~ Date q /aD/Db /5/ tl1f Project Proofing BY: ¿Maria J 1111111111111111111 /5/ mP Scanning Preparation BY: + a,6 = TOTAL PAGES 5·!:r (Count does not include cover sheet) /5/ Date: Production Scanning 1111111111111111111 Stage 1 Page Count from Scanned File: 5 (P (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ~ YES ~ Date:C¡/30JDÞ If NO in stage 1, page(s) discrepancies were found: YES NO /5/ YV1f NO BY: Stage 1 BY: Maria Date: /5/ 1/11/111I11111 IIIII Scanning is complete at this point unless rescanning is required. ReScanned 11111111111111 ,,1/1 BY: Maria Date: /5/ Comments about this file: Quality Checked 111111111111 1111111 10/6/2005 Well History File Cover Page. doc • • � r SARAH PALIN, GOVERNOR 555 Cordova Street Anchorage, AK 99501 DEPT. OF ENVIRONMENTAL CONSERVATION PHONE: (907) 269 -3094 DIVISION OF SPILL PREVENTION AND RESPONSE FAX: 269 -7687 http / /www. w.dec.state.ak.us INDUSTRY PREPAREDNESS PROGRAM Exploration Production & Refineries April 23, 2007 AP ` Q . 20 [ 07 APR �JC l',�r / M . 41 a" "P�j0 @ .9 b ll Ms. Faye Sullivan = -• Union Oil Company of California - UOCC (formerly Unocal) 909 West 9 Avenue Anchorage, AK 99501 Tv) Z ?cc L Z a Re: Oil Discharge Prevention and Contingency Plan for Alaska Red Well, Plan Number 044 -CP -5103 J \- '°`\ \ 11 %1-04 `� rrco ) �4`-t t� Dear Ms. Sullivan: ,:)(t. l X15 -c�� i 'r"� �, �ylyC 4v� --‘b� c�v�cct The above - referenced oil discharge prevention and contingency plan (plan) is an Alaska Department of Environmental Conservation (ADEC) approved plan, even though exploration activities have not been conducted since 2004. The plan will expire on May 24;2009. In January of this year, I sent an email to you with a letter outlining the guidelines for implementing our recently promulgated pollution prevention regulation revisions. I have attached a copy of the letter for your convenience. Please be aware that significant revisions to the Red Well plan must be submitted to ADEC by August 1, 2007. This is a good time for UOCC to consider whether further exploration activities will be conducted under this plan. If not, 1 suggest that you submit a request to rescind the plan before August 1, 2007. ADEC can consider a request to rescind your plan once the following issues are addressed: a. Wells must be adequately plugged and abandoned in accordance with Alaska Oil and Gas Conservation Commission (AOGCC) regulations. Please contact the AOGCC regarding the appropriate P &A requirements for your well(s). ADEC must receive confirmation, in writing (email is adequate) from the AOGCC that the abandoned well(s) meet their requirements; OR b. You must request a determination from AOGCC that the well has not penetrated a formation capable of flowing oil to the ground surface. AOGCC will send the determination to ADEC. c. Once item (a) or (b) is completed, ADEC will be able to determine that AS 46.04.030 (Oil Discharge Prevention and Contingency Plans) and AS 46.04.040 (Proof of Financial Responsibility) no longer apply to this facility since no additional exploration, production or drilling activity into potential oil bearing zones will be performed. AS 46.04.900(8).When we make the determination that the provisions of AS 46.04.030 and AS 46.04.040 do not apply, then you can request a modification of the plan approval, such as to rescind that approval. UOCC, not a contractor or consultant, must request the rescission of the plan approval in writing. i la Printed on '_tc •\ • • Ms. Faye Sullivan 2 April 23, 2007 Union Oil Company of California Once the requirements described above are met, ADEC can officially rescind the Oil Discharge Prevention and Contingency Plan (ODPCP) for Alaska Red Well. If you have any questions regarding this process, please contact me at (907) 269 -7680. Sincerely, rykuro Lydia Miner Section Manager Attn: January 23, 2007 letter re: implementation of new oil pollution prevention regulations cc: Betty Schorr, Industry Preparedness Program Manager, ADEC Laurie Silfven, EPR, ADEC Chris Pace, Financial Responsibility, ADEC Tom Maunder /Steve Davies, AOGCC Jean Bodeau, UOCC s=A=E 0 F4k AsKA SARAH PAL1N, GOVERNOR 555 Cordova Street ` Anchorage, AK 99501 PHONE: (907) 269 -3094 DEPT. OF ENVIRONMENTAL CONSERVATION FAX: (907) 269 -7687 DIVISION OF SPILL PREVENTION AND RESPONSE http://www.dec.state.ak.us INDUSTRY PREPAREDNESS PROGRAM January 23, 2007 Via email Fax Oil Discharge Prevention and Contingency Plan Holder Subject: Implementation of New Oil Pollution Prevention Regulations (18 AAC 75) Dear Plan Holder: On December 1, 2006 the Lieutenant Governor signed into law new regulations regarding oil pollution prevention. These regulations became effective on December 30, 2006, and several of them will impact how you operate and also your oil discharge prevention and contingency plan (C- Plan). This letter provides guidance on how the Alaska Department of Environmental Conservation (ADEC) will implement the new regulations, and how you may ensure continued compliance. A copy of the new regulations can be found on -line at http: / /www.dec. state .ak.us /spar /ipp /docs /18AAC75Artl Dec2006.pdf. The effects of the new regulations generally fall into two categories: 1. Changes in required pollution prevention methods and means as described in 18 AAC 75 Article 1, and 2. Changes in the format and content required in the C -Plan, as described in 18 AAC 75 Article 4. ADEC's regulations at 18 AAC 75 Article 1 pertain to oil pollution prevention activities, such as personnel training, design and construction of oil storage tanks and piping, and inspection of tanks and piping. Most of the revisions to the regulations are effective as of December 30, 2006. The exceptions include some regulations that involve development of a program, such as a preventative maintenance program for flow lines, which have a one year phase -in period, and design and construction standards for new construction, which generally have a two -year phase - in period. Table 1 provides general guidance to implementation of the regulations in 18 AAC 75 Article 1. This implementation schedule covers general subject areas only and is not meant to be fully inclusive. It is incumbent upon you as a plan holder to review the changes to the regulations and take appropriate actions to maintain compliance. • 2 Implerraktation 18 AAC 75 January 23, 2007 s r u l $ f • e t t�. rr " f? ,g Y' ki� t• } Compliance Regulation Subject Date December 30, Inspections and operational activities listed in 18 AAC 2006 General 75 Article 1 without a phase -in date (previously existing and new regulations). 18 AAC 75.047(c) Corrosion control programs for flow lines. 18 AAC 75.047(d) Preventative maintenance programs or leak detection for flow lines. December 30, 18 AAC 75.047(e) Line markers for flow lines. 2007 18 AAC Operation and maintenance of cathodic protection 75.065(h), systems on field - constructed aboveground oil storage 18 AAC 75.065(i) tanks. 18 AAC 75.080(j) Maintenance and inspection of facility oil piping. 18 AAC 75.045(d) Design and installation of wellhead sumps at production or exploration wells. 18 AAC 75.047(b) Design and construction standards for flow lines. 18 AAC 75.065(g) Installation of internal lining systems on field - constructed aboveground oil storage tanks. 18 AAC 75.065(j) Design, construction, and installation of field - constructed aboveground oil storage tanks. December 30, 18 AAC 75.065(k) High liquid level alarms on field - constructed 2008 • aboveground oil storage tanks. 18 AAC Cathodic protection systems for field - constructed 75.065(m) aboveground oil storage tanks. 18 AAC 75.066 Shop- fabricated aboveground oil storage tanks. 18 AAC 75.080(c) Design and construction standards for facility oil piping. 18 AAC 75.080(e) Construction and installation of buried facility oil piping. 18 AAC 75.080(f) Cathodic protection systems for facility oil piping. Changes to your C =Plan format and content will be implemented according to the schedule in Table 2. All.plan holders must submit an amendment to the Department incorporating changes to their plan due to the revisions to Article 4 regulations no later than August 1, 2007. • 3 Impletation 18 AAC 75 January 23, 2007 � �t) :t S l tmflex 4nta = Scliedule� Y : Edits to these plans may be submitted to meet the new regulations before approval or changes to these plans must be submitted to meet the new C -Plans Currently in regulations no later than August 1, 2007. Review or Submitted for Review before If your C -plan expires within 3 months of the date of this letter, please May 15, 2007 contact the Section Manager for your review and discuss your amendment options with him/her. C -Plans Currently Changes to currently approved C -Plans to meet the new regulations Approved or (detailed in 18 AAC 75.425) may be submitted with the new or renewal Submitted for application, if it is submitted by August 1, 2007. Revisions to ALL Review after May PLANS must be submitted to ADEC no later than August 1, 2007. 15, 2007 Please contact the appropriate section manager for your facility if you have any questions. Sincerely, Betty Scho Industry Preparedness Program Manager • • a_ ~~~. ; ~~ -, :~~.: ~ MICROFILMED 43/01/2008 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE .~.~~a ~ ~.' F:\LaserFiche\CvrPgs_Ins~erts\Nlicrofilm Marker.doc RE: Red #3 ( API 50-231-20026-00 ) . . This well was permitted 9/3/04, but never drilled From: Howard Okland [mailto:howard_okland@admin.state.ak.us] Sent: Thursday, September 28, 20069:15 AM To: Oudean, Debra Subject: Red #3 ( API 50-231-20026-00 ) Debra, I need some help. Would you please tell me if Red # 3 has been drilled? TNX Howard 1 of 1 9/28/2006 1 :29 PM . . FRANK H. MURKOWSKI, GOVERNOR AI4ASIiA OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Philip Krueger Drilling Manager Union Oil Of California (Unocal) P.O. Box 196247 Anchorage, Alaska 99519 Re: Red #3 Union Oil Of California (Unocal) Permit No: 204-169 Surface Location: 367' FNL, 431' FWL, SEC. 8 T4S, R13W, SM Bottomhole Location: 908' FSL, 1202' FEL, SEC 6 T4S, R13W, SM Dear Mr. Krueger: Enclosed is the approved application for permit to drill the above referenced exploratory well. This permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659-3 ager). BY ORDERW THE COMMISSION DATED this.;L day of September, 2004 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. W~A- i /3 /21)0 { 1a. Type of Work: Drill ~ Redrill U 1b. Current Well Class: Exploratory 0 Development Oil ~ Multiple Zone D Re-entry D Stratigraphic Test D Service D Development Gas D Single Zone D 2. Operator Name: 5. Bond: Blanket L:J Single Well LJ 11. Well Name and Number: Union Oil of California (Unocal) Bond No. 86-103515406 BCM Red #3 3. Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 196247 Anchorage, AK 99519 MD: 10,046' TVD: 9,494' n/a 4a. Location of Well (Governmental Section): 7. Property gesignation: .- Surface: 367' FNL, 431' FWL, Section 8 T4S, R13W, SM 01 ADL 389227/ ADL 390514 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 785' FSL, 1040' FEL, Section 6 T4S, R13W, SM n/a 7 -SeD-04 Total Depth: 9. Acres in Property: 14. Distance to Nearest 908' FSL, 1202' FEL, Section 6 T4S, R13W, SM .I 1789 Property: 4372 ft 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation 15. Distance to Nearest Well .' "" Surface:x- 212836 y- 2140979 Zone- 4 (Height above GL): 894' MSL feet Within Pool: 3260 ft ~ 16. Deviated wells: Kickoff depth: 4600 feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 37 degrees Downhole: 4111 " Surface: 3240 '" 18. Casing Program: Specifications Setting Depth Quantity of Cement Size Top Bottom c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) n/a 16" Welded 50' Surf. Surf. 67' 67' n/a 12-1/4" 9-5/8" 40 ppf L-80 BTC 1483' Surf. Surf. 1500' 1500' 664 cu ft "..- 8-1/2" 7" 26 ppf L-80 BTC-mod 4483' Surf. Surf. 4500' 4500' 428 cu ft " 6-1/8" 3-1/2" 9.2 ppf L-80 IBTC-mod 10029' Surf. Surf. 10046' 9494' 961 cu ft ",,- 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Structural CI::f"t: 1\ IL..l "1 Conductor . '- y-- Surface C'L'O - Q I "InnA Intermediate V'-' r..vv Production AI....!." na R. t::!lt r.1 In!! CommissIOn Liner . ..-, Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee ~ BOP Sketch ~ Drilling Program ~ Time v. Depth Plot U Shallow Hazard Analysis U Property Plat 0 Diverter Sketch 0 Seabed Report 0 Drilling Fluid Program 0 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Philip J. Krueger Title Drilling Manager Signature yL"I¡lVf~ Phone (907)-263-7628 Date t¡ )é""'-cd / Commission Use Only , Permit to Drill 2Dt./- / be¡ API Number: , z¡; Permit Approval See cover letter for other Number: 50- 2. 3 1- 2CX::> - 06 Date: requirements. Condition, of app"","" ~ BOP E to 3 'S 00 f <: , A, t(;,1\ us · G ~s LldlL \ I d>" e..rte.-- [1""..... t<c t- ¡.. w<ù ' Sam¡:¡ s ~ quired Yes 0 No I)? Mud log required Yes I No 0 fì ~Hy o¡¡e ,".de mea,""" It. Ye, 0 No.p<¡ o;<ect~"e' "',:",Y ,",,";..d k Ye, ~ No D Other: P1 (i~e/ ~' OSO(h.'), "'l li"Y'J1A...te ù..Ué( JOYe. ~UdJ~ lH71CR K. íc.. 'tfP¡,oved. ~ BY ORDER OF 0 ~/ 1Jt/ ,..-/ Approved by:/ 7J I _T~E..CÇ)I\.It1'fSION Date: ~ 3 FO~-40~ed 1212~ OK\b\\~f\L I su(mit in¿licate I STATE OF ALASKA . A[ SKA Oil AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 MC 25.005 I!d, . . Waiver Requests WAIVER #1: Unocal respectfully requests waiver to AOGCC regulations 20 MC 25.035 (c) Unocal requests permission to drill the 12-114" surface hole to a depth of +1- I, 1,500' MD I 1,500' TVD without a diverter. Red #1 and Red #2 were drilled vertically on either side of this planned wellbore down to the surface casing depth with no signs of shallow gas. No seismic anomalies are seen shallower than ./ 3,000' TVD. WAIVER #2: Unocal requests permission to drill the 12 %" surface hole to +1-1,500' without ~ surveying until after the 9 5/8" casing is cemented. AOGCC regulation 20 MC 25.050 (h) stipulates: (h) "Upon application, the commission will, in its discretion, waive all or part of the directional survey requirements of this section or approve alternate means for determining the location of a wellbore if the variance at least equally ensures accurate surveying of the wellbore to prevent well intersection, to comply with spacing requirements, and to ensure protection of correlative rights." Due to plans to drill the 12 %" surface hole vertically to 1 ,500', there is no cost- effective means to survey once each 500' as required in regulation 25.050 (C)(1). Unocal will obtain the required surveys at the first opportunity after cementing the 9 5/8" casing, before drilling the 8 %" hole, to ensure accuracy of the final BHL. WAIVER #3: Unocal requests a waiver for the requirements of AOGCC regulation 20 MC 25.065. Unocal has drilled two exploration wells off from the same surface location with no sign of H2S. Red #3 will not penetrate into any horizons deeper than was penetrated on Red #1 and Red #2. e/"o/1 .[)f I<-'Qq_'? ' )b ~. .r . . Outline Summary 1. Move in and rig up Nabors Rig 129 on Red #3. 16" 5/8" W.t. conductor will be driven prior to rig-up and 13 5/8" 5M slip on wellhead adapter will be installed. 2. Nipple up 13 5/8" riser and bell nipple. 3. Mix KCL spud mud. 4. Drill 12 X" surface hole vertically to 1,500' MD 11,500' TVD. ,I 5. Run and cement 9 5/8" 40# L-80 BTC surface casing to 1,500' MD 11,500' TVD. Pressure test 9 5/8" to 3,500 psi after bumping the plug. / 6. Nipple down riser and bell nipple. 7. Nipple up 11" 5M BOP stack wi 2 7/8" x 5" VBRs on top, blinds in middle and 7" pipe rams on bottom. Test BOPs wi AOGCC notification for witness. 8. Run gyro. 9. After drilling at least 20' of new hole, but no more than 50', perform Leak off Test as per Unocal standard LOT procedure. 10. Drill 8 %" vertical hole wi KCL mud system to 4,500' MD I 4,500' TVD. 11. Run and cement 7" 26# L-80 BTC intermediate casing to 4,500' MD I 4,500' TVD. Pressure test 7" to 3,500 psi after bumping the plug. 12. Change bottom BOP rams to 4" and test. 13. Change over mud to Oil Based Mud before drilling out shoe track. 14. After drilling at least 20' of new hole, but no more than 50', perform Leak off Test as per Unocal standard LOT procedure. 15. Directionally drill 6 1/8" hole to 10,046' MD 19,494' TVD. 16. Log 61/8" hole wi PEX, CMR, FMI, Dipole. Pull GR up to surface. .l ,/ 17. Run and cement 3 %" 9.2# L-80 IBTC liner from 4,300' MD I 4,300' TVD to 10,046' MD I 9,494' TVD. 18. Tie-back liner to surface with 3 %" 9.2# L-80 IBTC tubing string. Methanol injection manderal will be run at 2,500' MD. 19. Pressure test 3 %" completion to 4,500 psi. 20. Test 7" x 3 %" annulus to 1 ,500 psi. / 21. Install BPV. Nipple down 11" BOP stack. e . 22. Nipple up 3 1/8" production tree and test. 23. Remove BPV and commence with production testing the well. / Red 16" 5/8" w.t 9 5/8" 40# L-80 BTC 12 y." Hole 7" 26# b80 BTC Mod 8 y." Hole Jewelry 1 - BOT Methanol Injection Nipple 2500' MD 2 - BOT X' Seal Assembly 3 - BOT ZXP Packer 4 - BOT Flexlöck Hanger 5 - X' PBR wI 4.0" ID 3 y." 9.2# L-80 IBTC Mod 6 1/8" Hole 80' MD (80' TVD) 1500' MD (1500' TVD) Planned (4300' TVD) 4500' MD (4500' TVD) Formation Tops Beluga - Surface Tyonek - 5623' MD 10,046' MD (9494' TVD) 1°~ LCJ) :> W ~ H o ~ H NIKOLAEVSK UNIT 18 NIKOlAEVSK UNIT RED #3 EXHIBIT A N A 750 o 1,500 ¡ Feet Alaska State Plane Zone 4, NAD27 . ¢:: 0 lC) -500 N II E () 0 aJ (ij () C/) 500 1000 1500 2000 2500 3000 - 3500 - CD .æ - .c 4000 - C. CD C 4500 CO U :e 5000 ~ CD 5500 ;j ~ t- . V 6000 6500 7000 7500 8000 8500 9000 9500 10000 UNOCAL . I UNOCAL8 1ft. "fILs ¡-NTiQ-- Location: Kenai Peninsula, Alaska Field: South Kenai Gas Field Installation: Red Slot: Well: Well bore: I Slot Red#31 Red#3 Red#3 Vers#3 I -_._~~.~~ Begin Drop 32.49 28.49 DLs: 2.00 deg/100ft 20.49 16.49 Target - EOD , i I I I I i j]l I I I I I I I I I RKB Elevation: 894' 9 5/8" Casing PI. jjl 7" Casing PI. KOP 6.00 12.00 DLS: 3.00 deg/100ft 24.00 30.00 EOC Scale 1 em = 125 ft East (feet) -> Created by: Planner Date plotted: 1-5ep-2004 Plot reference is Red#3 Versl/3. Ref wellpath is Red#3 Vers#3. Coordinates are in feet reference Slot Red#3. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 894.00 ft. Plot North is aiigned to TRUE North. ..- -2000 -1750 -1500 -1250 -1000 -750 -500 -250 o 250 Target - EOD Begin Drop EOC / 7" Casing PI. 9 5/8" Casing PI. ~ KOP I WELL PROFILE DATA Point MD tne Azi TVD North East deg/100ff V. Seet Tie on 0.00 0.00 76046 0.00 0.00 0.00 0.00 0.00 KOP 5000.00 0.00 76.46 5000.00 0.00 0.00 0.00 0.00 I End of BuildfTurn 6224.01 36.72 307.36 6141.91 229.98 -301.23 3.00 378.99 End of Hold 7888.58 36.72 307.36 7476.17 833.92 -1092.31 0.00 1374.25 Target 9099.60 12.50 307.35 I -1490.20 2.00 1874.82 I 8569.00 11137.66 T.D. & End of Hold 10047.06 12.50 307.35 9494.00 11262.08 -1653.21 0.00 2079.891 ~ TD-3 1/2" Casing Pt. -500 -0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 Scale 1 em = 250 ft Vertical Section (feet) -> Azimuth 307.35 with reference 0.00 N, 0.00 E from Slot Red#3 I ~ I ~ r ~ ~ r r- L I I t l 1750 1500 1250 1000 ^ . Z 750 0 ;:¡ ::r - 500 i' CD - - 250 o en ¡;¡ ø C') 3 II -250 N 01 := Tie-In 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 36.72 212178.22 511.52N 0.0 72 36.72 212131.57 547.80N 0.00 73 36.72 212084.91 584.08N 0.00 74 36.72 212038.26 620.36N 0.00 75 36.72 211991.60 656.64N 0.00 76 36.72 211944.94 692.92N 0.00 77 36.72 211898.29 729.21N 0.00 78 36.72 211851.63 765.49N 0.00 79 36.72 211804.97 801.77N 0.00 80 36.72 211763.65 833.91 N 0.00 81 36.49 7485.34 211758.33 838.04N 2.00 82 34.49 7566.75 211713.03 873.27N 2.00 83 32.49 7650.14 211669.97 906.75N 2.00 84 30.49 7735.41 211629.21 938.45N 2.00 85 28.49 7822.45 211590.80 968.32N 2.00 86 26.49 7911.15 211554.78 996.33N 2.00 87 24.49 8001.41 211521.20 1022.45N 2.00 88 22.49 8093.12 211490.09 1046.63N 2.00 89 20.49 8186.16 211461.51 1068.86N 2.00 90 18.49 8280.42 211435.47 1089.11N 2.00 91 16.49 8375.80 211412.02 1107.35N 2.00 92 14.49 8472.16 211391.18 1123.56N 2.00 93 12.50 8569.00 211373.04 1137.66N 2.00 94 12.50 8569.39 211372.97 1137.71N 0.00 95 12.50 8667.02 211356.08 1150.85N 0.00 96 12.50 8764.65 211339.19 1163.98N 0.00 97 12.50 8862.28 211322.31 1177.12N 0.00 98 12.50 8959.91 211305.42 1190.25N 0.00 99 12.50 9057.54 211288.53 1203.38N 0.00 100 12.50 9155.17 211271.64 1216.52N 0.00 101 12. 9252.80 211254.75 1229.65N 0.00 102 12.50 9350.43 211237.86 1242.79N 0.00 103 12.50 9448.06 211220.97 1255.92N 0.00 104 12.50 9494.00 211213.02 1262.10N 0.00 e . Maximum Anticipated Surface Pressure Red #3 Kenai Peninsula, Alaska Assumptions: 1. Based on offset drilling & well test data, the pore pressure gradient is predicted to be a o.~~/ft gradient from ,/ surface to planned total depth at 9,494' TVO RKB. Unocal has reviewed data from the thréEfÔffset wells. These are Red #1, Red #2, NFU #41-35 and NFU #11-4. 2. The MAS.P. during drilling operations will be governed by the 7" shoe frac gradient, and is calculated based on a full column of gas between the 7" shoe and the surface. 3. The MAS.P. during production operations will be the estimated SIBHP minus the gas hydrostatic pressure between TO & the surface. The 7" intermediate casing must be designed to handle a potential burst load case based on a shallow leak in the 31/2" pipe early in the life of a 9,494' TVO gas completion (i.e. before reservoir pressure declines). M.A.S.P. Calculation During Production Phase: Max. pore pressure at T.O. = 9494 TVO x ~ = 4111 psi ",. MAS.P. (tbg leak at surface) = 4111 psi - (0.096 psi/ft * 9494 ft) = = 3200 psi MAS.P. Calculation During Drilling Phase: Est. Frac pressure at 7" shoe 4500 ft. x 0.8 psi/ft = = 3600 psi MAS.P. during drilling = 3600 psi - (.08 psi/ft x 4500 ft.) = = 3240 psi . . Red #3 Casing Design / / Size Weie:ht Grade Connection Tensile Burst Collapse 9-5/8" 40# L-80 BTC 916,0001b 5,750 psi 3,090 psi 7" 26 # L-80 BTC mod. 604,000 lb 7,240 psi 5,410 psi 3-1/2" 9.2 # L-80 IBTC mod. 207,200 lb 10,160 psi 10,540 psi 9-5/8" Surface Casin2 Calculated Capacity Safety Factor Tension 1500' x 40# = 60.0k 916k 15.3 Burst (4500' TVD x (0.433 psi/ft- 5750 psi 3.8 0.1 psi/ft))= 1499 psi Collapse (1500' TVD x (0.433 psi/ft- 3090 psi 6.2 0.1 psi/ft)) = 500 psi ,,/ 7" Intermediate Casin2 Calculated Capacity Safety Factor Tension 4500' x 26# = 119.6k 604k 5.2 Burst (9494' TVD x (0.433 psi/ft - 7240 psi 2.3 0.1 psi/ft)) = 3162 psi Collapse (4500' TVD x (0.433 psi/ft - 5410 psi 3.6 0.1 psi/ft)) = 1499 psi /" 3 ~" Production Strio2 Calculated Capacity Safety Factor Tension 5746' x 9.2# = 52.9.1k 207.2k 3.9 Burst (9494 TVD x (0.433 psi/ft - 10160 psi 3.2 0.1 psi/ft)) = 3162 psi Collapse (9494' TVD x (0.433 psi/ft - 10540 psi 3.3 0.1 psi/ft)) = 3162 psi /~ 13 3/8" outlet . . Schlumberger * CemCADE well cementing recommendation for 9-5/8" Surface Operator Country State : UNOCAL : USA :AK Well Field RED #3 RED Prepared for Proposal No. Date Prepared : Rob Stinson : #1 : 08-30-2004 Location Service Point Business Phone : FAX No. Ninilchik Kenai (907) 776-8155 (907) 776-8158 Prepared by Chinedu F. Akwukwaegbu Phone (907)273-1739 E-Mail Address:CAkwukwaegbu@slb.com Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made conceming results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. · Mark of Schlumberger . Client Well String District Country Loadcase : UNOCAL RED #3 9-5/8 Kenai USA 9-5/8 in Surface (a) Section 1: well description Configuration : Casing Stage : Single Rig Type : Land Mud Line : 0.0 ft Total MD : 1500.0 ft BHST : 62 degF Bit Size : 121/4 in ID Landing Collar MD : 1420.0 ft Casingfliner Shoe MD : 1500.0 ft L-80 Mean OH Diameter : 12.250 in Mean Annular Excess : 30.0 % Mean OH Equivalent Diameter: 12.934 in Total OH Volume : 230.8 bbl (including excess) The Well is considered VERTICAL Geothermal Tern erature Profile MD TVD Temperature ft ft de F 0.0 2000.0 . Sil.IPgep Thread Lithology Sandstone BTC ./ Red_#3.cfw; 08-30-2004; loadCase 9-5/8 in Surface (a) ; Version wcs-cem441_51 Page 2 . . Client Well String District Country Loadcase : UNOCAL RED #3 9-5/8 Kenai USA 9-5/8 in Surface (a) Se_I..rger Section 2: fluid description Mud DESIGN Fluid No: 1 Density : 9.30 Ib/gal Rhea. Model : BINGHAM Pv : 12.000 cP At temp. : 80 degF Ty : 15.00 Ibf/100ft2 Gel Strength : (lbf/100ft2) MUD Mud Type :WBM Job volume : 107.7 bbl Water Type : Fresh Fresh Water DESIGN Fluid No: 2 Rhea. Model At temp. : NEWTONIAN : 80 degF Density : 8.32 Ib/gal Viscosity : 5.000 cP Job volume : 5.0 bbl MUDPUSH II DESIGN Fluid No: 3 Rhea. Model At temp. : BINGHAM : 80 degF Density Pv Ty Job volume : 10.50 Ib/gal : 18.000 cP : 19.00 Ibf/100ft2 : 40.0 bbl Lead Slurry DESIGN Fluid No: 4 Rhea. Model At temp. : BINGHAM : 81 degF Density Pv Ty Gel Strength : 12.80 Ib/gal : 11.936 cP : 16.99Ibf/100ft2 : (lbf/100ft2) DESIGN BLEND Name : G Dry Density : 199.77lb/ft3 Sack Weight: 94 Ib BASE FLUID Type : Fresh water SLURRY Mix Fluid Yield Porosity : 11.064 gal/sk : 1.97 ft3/sk : 75.1 % Job volume (p. 7 :3ljbl Quantity . 1~:45 sk Solid Fractio .": 24.9 % Density : 8.32 Ib/gal Base Fluid : 11.064 gal/sk Additives Code 0079 S002 D046 Conc. 1.500 %BWOC 1.000 %BWOC 0.200 %BWOC Function EXTENDER Accelerator ANTI FOAM Thickening Time Compressive Strength Schedule ( ) Schedule ( ) 100 Bc 500 psi at at 03:05 hr:mn 29:40 hr:mn Page 3 Red_#3.cfw; 08-30-2004; loadCase 9-5/8 in Surface (a) ; Version wcs-cem441_51 . Client Well String District Country Loadcase : UNOCAL RED #3 9-5/8 Kenai USA 9-5/8 in Surface (a) . Sil..rger Tail Slurry DESIGN Fluid No: 5 Rhea. Model At temp. : BINGHAM : 80 degF Density Pv Tv Gel Strength DESIGN BLEND Name : G Dry Density : 199.77lb/ft3 Sack Weight: 94 Ib BASE FLUID Type : Fresh water SLURRY Mix Fluid Yield Porosity : 5.098 gal/sk : 1.17 ft3/sk : 58.2 % Density : 8.32 Ib/gal Additives Code 0065 S002 0046 Conc. 0.300 %BWOC 1.500 %BWOC 0.200 %BWOC Function DISPERSANT Accelerator ANTIFOAM Thickening Time Compressive Strength Schedule ( ) Schedule ( ) 100 Bc 2573 psi Section 3: fluid sequence Original fluid Mud pv: 12.000 cP 107.7 bbl 271.3 bbl O.Oft Displacement Volume Total Volume TOC : 15.80 Ib/gal : 25.749 cP : 24.73 Ibf/100ft2 : (lbf/100ft2) -~~"" Job volume ~. 4 bJ/ Quantity . 03.Q9'sk Solid Fractio ,;µ.,< 41.8 % Base Fluid : 5.098 gal/sk at at 03:04 hr:mn 24:00 hr:mn 9.30 Ib/gal Ty: 15.00 Ibf/100ft2 Name Fresh Water MUDPUSH II Lead Slurry Tail Slurry Mud Rheology viscosity:5.000 cP Pv:18.000 cP Pv:11.936 cP pv:25.749 cP pv:12.000 cP Ty:19.00 Ibf/100ft2 Ty:16.99Ibf/100ft2 Ty:24.73Ibf/100ft2 Ty:15.00 Ibf/100ft2 Static Security Checks: Frac 9 psi Pore 19 psi Collapse 2710 psi Burst 5750 psi Csa.Pump out 14 ton at 80.0 ft at 80.0 ft at 1420.0 ft at 0.0 ft Page 4 Red_#3.cfw; 08-30-2004; LoadCase 9-5/8 in Surface (a) ; Version wcs-cem441_51 . . Client Well String District Country Loadcase : UNOCAL RED #3 9-5/8 Kenai USA 9-5/8 in Surface (a) Sc~I.lIerger Section 4: pumping schedule Start Job: Ensure that hole and mud are properly conditioned as per program Pumping Schedule Name Flow Rate Volume Stage Time Cum.Vol Inj. Comments (bbl/min) (bbl) (min) (bbl). Temp. (deaF) Fresh Water 5.0 5.0 1.0 5.0 80 Fluid pack lines Pause 0.0 0.0 5.0 0.0 80 3-Pressure Test Lines MUDPUSH II 5.0 40.0 8.0 40.0 80 7-Start Pumping Spacer Pause 0.0 0.0 5.0 0.0 80 4-Drop Bottom Plug Lead Slurry 5.0 76.3 15.3 76.3 80 13-Start Mixing Lead Slurry Tail Slurry 5.0 42.3 8.5 42.3 80 16-Start Mixing Tail Slurry Pause 0.0 0.0 5.0 0.0 80 18-Drop Top Plug Mud 5.0 107.7 21.5 107.7 80 19-5tart Displacement Total 01 :09 271.3 bbl hr:mn End Job: Record returns to surface and plug bumping. Dynamic Security Checks: Frac 8 psi Pore 2 psi Collapse 2710 psi Burst 5379 psi at 80.0 ft at 80.0 ft at 1420.0 ft at 0.0 ft Temperature Results BHCT 74 degF Simulated Max HCT 77 degF Simulated BHCT 77 degF Max HCT Depth 1500.0 ft CT at TOC 73 de F Max HCT Time 01 :09: 15 hr:mn:sc WELLHEAD PRESSURE 0 0 _ Well Head Pressure v ---- Acquired WHP 0 LO M 0 0 M 0 LO N "(ñ 80 Q.~ :r ~ 0 ~ 0 0 ~ 0 LO 0 0 25.0 50.0 75.0 Time (min) Page 5 Red_#3.cfw; 08-30-2004; LoadCase 9-5/8 in Surface (a) ; Version wcs-cem441_51 Client Well String District Country Loadcase : UNOCAL RED #3 9-5/8 Kenai USA 9-5/8 in Surface (a) ECD l() 25.0 50.0 75.0 <D Frac Pore ;! ! ~~ f!' ::> N (j) ~ (j) <l> a: ¿ ~ ~ ~ o CIJ- <X> o Tim e (m in) FLOWRATE COMPARISON 00 o 25.0 50.0 75.0 CIJ r- <D ê 13£ :5lO ~ .$ (!) lY"'<T ~ ü: M N o Tim e (m in) Red_#3.cfw; 08-30-2004; LoadCase 9-5/8 in Surface (a) ; Version wcs-cem441_51 Page 6 : centralizer placement Top of centralization :0.0 ft Bottom Cent. MD Casing Shoe NB of Cent. Used NB of Floating Cent. Client Well String District Country Loadcase . UNOCAL RED #3 9-5/8 Kenai USA 9-5/8 in Surface (a) Section Bottom MD ft 1500.0 Nor. 7 :1500.0 ft :1 :1 Cent. ! Joint 1/5 Centralizer Placement Cent. Name Code A161239S-9 S/8-0-RIGlD W184 Centralizer Description Cent. Name Code Casing Max. Min. 00 Rigid 00 00 (in) (in) (in) A1612395-95/8-0- W184 95/8 12.000 12.000 Yes RIGID Origin Hole Size (in) Force (Ibf) N.A. N.A. (!þf) N.A. Houma (1) - Centralizer performance data is based on tests by WEATHERFORD as per the current API10D specifications Running Force Calculations: Travelling Block Weight Friction Factor Centralizer/Formation Total Drag Force Hook load DownStroke Hook load Up Stroke :100 ton :0.3 :0 ton :126 ton :126 ton ft % o o o o Pipe Standoff Red_#3.cfw; 08.30-2004; loadCase 9--518 in Surface (a); Version wcs.cem441_51 Page 7 . . Schlumberger * CemCADE well cementing recommendation for 7" Intermediate Operator Country State : UNOCAL : USA :AK Well Field RED #3 RED Prepared for Proposal No. Date Prepared : Rob Stinson : #1 : 08-30-2004 Location Service Point Business Phone : FAX No. Ninilchik Kenai (907) 776-8155 (907) 776-8158 Prepared by Chinedu F. Akwukwaegbu Phone (907)273-1739 E-Mail Address:CAkwukwaegbu@slb.com Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made conceming results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. · Mark of Schlumberger . Client Well String District Country Loadcase : UNOCAL RED #3 7 Kenai USA 7 Section 1: well description Configuration Stage Rig Type Mud Line Total MD BHST Bit Size : Casing : Single : Land : 0.0 ft : 4500.0 ft : 99 degF : 8 1/2 in ID Landing Collar MD : 4420.0 ft Casing/liner Shoe MD : 4500.0 ft OD L-80 Mean OH Diameter : 8.500 in Mean Annular Excess : 30.0 % Mean OH Equivalent Diameter: 8.901 in Total OH Volume : 230.9 bbl (including excess) The Well is considered VERTICAL Formation Data Pore Name silft 0.433 MD ft 0.0 4500.0 . S~I..rger Thread BTC Lithology Sandstone .", Page 2 Red_#3.cfw; 08-30-2004; loadCase 7" Intermediate; Version wcs-cem441_51 . . S~llDlløpgep Client Well String District Country Loadcase ; UNOCAL RED #3 7 Kenai USA 7 Section 2: fluid description Mud DESIGN Fluid No: 1 Density : 9.50 Ib/gal Rheo. Model : BINGHAM Pv : 15.000 cP At temp. : 80 degF Ty : 18.00 Ibf/100ft2 Gel Strength : (lbf/100ft2) MUD Mud Type :WBM Job volume : 169.1 bbl Water Type : Fresh Fresh Water DESIGN Fluid No: 2 Rhea. Model At temp. Density : 8.32 Ib/gal : NEWTONIAN : 80 degF Viscosity : 5.000 cP Job volume : 5.0 bbl MUDPUSH II DESIGN Fluid No: 3 Rhea. Model At temp. : BINGHAM : 80 degF Density Pv Ty Job volume : 10.50 Ib/gal : 22.000 cP : 22.00 Ibf/100ft2 : 35.0 bbl Lead Slurry DESIGN Fluid No: 4 Rheo. Model At temp. : BINGHAM : 80 degF Density Pv Ty Gel Strength : 12.80 Ib/gal : 31.504 cP : 33.84 Ibf/100ft2 : (lbf/100ft2) DESIGN BLEND Name : G Dry Density : 199.77 Ib/ft3 Sack Weight: 94 Ib BASE FLUID Type : Fresh water SLURRY Mix Fluid Yield Porosity : 11.067 gal/sk : 1.98 ft3/sk : 74.7% Job volume : 5y1fbí Quantity : ~6.5 k Solid Fractio ~': 25.3 % Density : 8.32 Ib/gal Base Fluid : 11.067 gal/sk Additives Code Conc. Function 0046 0.200 %BWOC ANTI FOAM 0079 2.000 %BWOC EXTENDER 0167 0.800 %BWOC FLUID LOSS S002 0.750 %BWOC Accelerator Thickening Time Compressive Strength Schedule 9.4-1 Schedule ( ) 100 Be 1137 psi at at 03:30 hr:mn 46:00 hr:mn Page 3 Re<C#3.cfw; 08-30-2004; loadCase 7" Intermediate; Version wcs-cem441_51 . Client Well String District Country Loadcase : UNOCAL RED #3 7 Kenai USA 7 . SmlRllerger Tail Slurry DESIGN Fluid No: 5 Rhea. Model At temp. : BINGHAM : 80 degF Density Pv Ty Gel Strength DESIGN BLEND Name : G Dry Density : 199.77lb/ft3 Sack Weight: 94 Ib BASE FLUID Type : Fresh water SLURRY Mix Fluid Yield Porosity : 5.091 gal/sk : 1.16 ft3/sk : 58.6% Density : 8.32 Ib/gal Additives Code 0167 0065 0046 Cone. 0.400 %BWOC 0.300 %BWOC 0.200 %BWOC Function FLUID LOSS DISPERSANT ANTI FOAM Thickening Time Schedule 9.18- 4 Schedule ( ) 1 00 Be Compressive Strength 2351 psi Section 3: fluid sequence Original fluid Mud Pv: 15.000 cP 169.1 bbl 285.6 bbl 2000.0 ft Displacement Volume Total Volume TOC : 15.80 Ib/gal : 72.013 cP : 10.82 Ibf/100ft2 : (lbf/100ft2) Job VOlumetE·· 'AU~~. 6bl\ Quantity . 85.8~ Solid Fracti "....: 41.4 % Base Fluid : 5.091 gal/sk at 04:38 hr:mn at 18:30 hr:mn 9.50 Ib/gal Ty: 18.00 Ibf/100ft2 Name Fresh Water MUDPUSH II Lead Slurry Tail Slurry Mud Rheology viscosity:5.000 cP Pv:22.000 cP pv:31.504 cp Pv:72.013 cP pv:15.000 cp Tâ2.00 Ibf/100ft2 Ty:33.84 Ibf/100ft2 Ty:10.82Ibf/100ft2 Ty:18.00 Ibf/100ft2 Static Security Checks: Frac 321 psi Pore 117 psi Collapse 4652 psi Burst 7229 psi CSQ.Pump out 40 ton at 1500.0 ft at 1500.0 ft at 4420.0 ft at 780.1 ft Page 4 Red_#3.cfw; 08-30-2004; LoadCase 7" Intermediate; Version wcs-cem441_51 . . Scil..rgør Client Well String District Country Loadcase : UNOCAL RED #3 7 Kenai USA 7 Section 4: pumping schedule Start Job: Ensure that hole and mud are properly conditioned as per program Pumping Schedule Name Flow Rate Volume Stage Time Cum.Vol Inj. Comments (bbl/min) (bbl) (min) (bbl). Temp. (deQF) Fresh Water 5.0 5.0 1.0 5.0 80 Fluid pack lines Pause 0.0 0.0 5.0 0.0 80 3-Pressure Test Lines MUDPUSH " 5.0 35.0 7.0 35.0 80 7-Start Pumping Spacer Pause 0.0 0.0 5.0 0.0 80 4-Drop Bottom Plug Lead Slurry 5.0 58.7 11.7 58.7 80 13-Start Mixing Lead Slurry Tail Slurry 5.0 17.7 3.5 17.7 80 16-Start Mixing Tail Slurry Pause 0.0 0.0 5.0 0.0 80 18-Drop Top Plug Mud 5.0 169.1 33.8 169.1 80 19-5tart Displacement Total 01:12 285.6 bbl hr:mn End Job: Record returns to surface and plug bumping. Dynamic Security Checks: Frac 112 psi Pore 81 psi Collapse 4652 psi Burst 6285 psi at 4500.0 ft at 1500.0 ft at 4420.0 ft at 0.0 ft BHCT Simulated BHCT CT at TOC 90 deg F 78 degF 78 de F Temperature Results Simulated Max HCT Max HCT Depth Max HCT Time 80 degF 3949.0 ft 00:06:00 hr:mn:sc WELLHEAD PRESSURE o o o ~ ë¡; .eo a.. :I: ~ o o 10 20 30 40 Tim e (m in) 50 60 70 80 Page 5 Red_#3.cfw; 08-30-2004; loadCase T' Intermediate; Version wcs-cem441_51 Client Well String District Country Loadcase : UNOCAL RED #3 7 Kenai USA 7 ECD :;! 10 20 30 40 Tim e (m in) 50 60 70 80 to ~ (") ~ 1ii OJ g~ 2: :;:¡ (j) (j) (!) Q:~ ¿ c « o ~ Q) co o FLOWRATE COMPARISON ro Fluids at 4500 ft CJ') ..... '" í? ï~ J5 l{) B .$ '" a:: "<t 3: o IT: '" N o o 10 20 30 40 Tim e (m in) 50 70 80 Red_#3.cfw: 08-30-2004: loadCase 7" Intermediate: Version wcs-cem441_51 Page 6 Client Well String District Country Loadcase : UNOCAL RED #3 7 Kenai USA 7 Section 5: Centralizer placement Top of centralization :150().0 ft Bottom Cent. MD :4480.0 ft Casing Shoe :4500.0 ft NB of Cent. Used :15 NB of Floating :15 Bottom MD ft 4500.0 Nbr. 15 Cent. / Joint 1/5 Centralizer Placement Cent. Name Code 6412070-7 -O-RIGlD W159 Centralizer Description Cent. Name Code Casing Max. Min.OD Rigid Origin Hole Size Running OD OD (in) (in) Force (in) (in) (Ibf) 6412070-7-0-RIGID W159 7 8.000 8.000 Yes Houma N.A. N.A. (1) - Centralizer performance data is based on tests by WEATHERFORD as per the current API10D specifications Running Force Calculations: Travelling Block Weight Friction Factor Centralizer/Formation Total Drag Force Hook load Down Stroke Hook load Up Stroke :120 ton :0.3 :0 ton : 170 ton :170 ton ft % o Pipe Standoff Red_#3.cfw: 08-30-2004: LoadCase r Intermediate: Version wcs-cem441_51 . . Schlumberger * CemCADE well cementing recommendation for 3.5" Production Operator Country State :UNOCAL : USA :AK Well Field RED #3 RED Prepared for Proposal No. Date Prepared : Rob Stinson : #1 : 08-30-2004 Location Service Point Business Phone : FAX No. Ninilchik Kenai (907) 776-8156 (907) 776-8158 Prepared by Chinedu F. Akwukwaegbu Phone (907)273-1739 E-Mail Address:CAkwukwaegbu@slb.com Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made conceming results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. . Mark of Schlumberger . Client Well String District Country Loadcase : UNOCAL RED #3 3.5 Kenai USA 3.5inch Production Casing (a) Section 1: well description Configuration : Liner Stage : Single Rig Type : land Mud Line : 0.0 ft Total MD : 10046.0 ft BHST : 166 degF Bit Size : 6 1/8 in ID Drill Pipe ID Liner Hanger : 4300.0 ft landing Collar MD : 9966.0 ft Casingfliner Shoe MD : 10046.0 ft Casing/Liner Weight ID Grade Ib/ft 9.2 L-80 Mean OH Diameter : 6.125 in Mean Annular Excess : 20.0 % Mean OH Equivalent Diameter: 6.524 in Total OH Volume : 229.3 bbl (including excess) Max. Deviation Angle : 37 deg Max. DlS : 3.000 deg/100ft Formation Data Pore Name si/ft 0.433 0.433 MD ft 0.0 10046.0 Grade . S~I.lrg8r S-135 Thread BTCM Lithology Sandstone Sandstone Page 2 Red_#3.cfw; 08-30-2004; LoadCase 3.5inch Production Casing (a) ; Version wcs-cem441_51 . Client Well String District Country Loadcase : UNOCAL RED #3 3.5 Kenai USA 3.5inch Production Casing (a) Section 2: fluid description CW 101 DESIGN Fluid No: 2 Rheo. Model At temp. Density : NEWTONIAN : 80 degF Viscosity : 5.000 cP Gel Strength : (lbf/100ft2) Job volume : 20.0 bbl . Sil.lrgar : 8.31 Ib/gal MUDPUSH " DESIGN Fluid No: 3 Rhea. Model At temp. : BINGHAM : 80 degF Density Pv Ty Job volume : 10.50 Ib/gal : 22.000 cP : 22.00 Ibf/100ft2 : 45.0 bbl #4 Base Oil DESIGN Fluid No: 4 Rheo. Model At temp. Density : 7.40 Ib/gal : NEWTONIAN : 80 degF Viscosity : 3.000 cP Job volume : 95.9 bbl LiteCRETE DESIGN Fluid No: 6 Rhea. Model At temp. : BINGHAM : 80 degF Density Pv Ty Gel Strength DESIGN BLEND Name : 12# LiteCRET Dry Density : 112.13 Ib/ft3 Sack Weight: 151 Ib BASE FLUID Type : Fresh water SLURRY Mix Fluid Yield Porosity : 8.189 gal/sk : 2.46 ft3/sk :44.5% Density : 8.32 Ib/gal Additives Code Cone. Function 0047 0.100 gal/sk blend ANTIFOAM 0800 0.200 %BWOC RETARDER C359 0.025 %BWOC VISCOSIFIER 0065 0.750 %BWOB DISPERSANT : 12.00 Ib/gal : 92.092 cP : 12.39Ibf/100ft2 : (lbf/100ft2) Job vo,umeb. 17 .66~) Quantity . 91.63--sk Solid Fracti - - : 55.5 % Base Fluid : 8.089 gal/sk Thickening Time Schedule 9.20- 100 Be at 03:51 hr:mn 2 Compressive Strength Schedule () (psi) at (hr:mn) Page 3 Red_#3.cfw; 08-30-2004; loadCese 3.5inch Production Casing (a) ; Version wcs-cem441_51 Client Well Stri ng District Country Loadcase : UNOCAL RED #3 3.5 Kenai USA 3.5inch Production Casing (a) Displacement Volume Drill Pipe Volume Total Volume TOe Section 3: fluid sequence Original fluid Mud pv : 67.000 cP 95.9 bbl 46.6 bbl 332.5 bbi 4200.0 ft 9.50 ib/gal Ty: 18.00 Ibf/100ft2 CW 101 MUDPUSH Ii LiteCRETE #4 Base Oil Rheology Name viSCO$ity:5.000 cp pv:22.000 cP pv:92.092 cP viscosit :3.000 cP Frac Pore Collapse Burst Cs .Pump out 954 psi 360 psi 8252 psi 10160 psi 39 ton at 4500.0 ft at 4500.0 ft: at 9966.0 ft: at 9966.0 ft: ft o o o o ~ o o o N Fluid Sequence Static Well Security Page 4 Red_#3.cfw; 08-30.2004; loadCase 3.5inch Production Casing (a) ; Version wcs-cem441_51 Client Well String District Country Loadcase : . UNOCAL RED #3 3.5 Kenai USA 3.5inch Production Casing (a) . S~I.lrger Section 4: pumping schedule Start Job: Ensure that hole and mud are properly conditioned as per program Pumping Schedule Name Flow Rate Volume Stage Time Cum.Vol Inj. Comments (bbl/min) (bbl) (min) (bbl). Temp. (degF) CW 101 5.0 5.0 1.0 5.0 80 Fluid pack lines Pause 0.0 0.0 5.0 0.0 80 3-Pressure Test Lines CW 101 5.0 15.0 3.0 20.0 80 5-Start Pumping Wash MUDPUSH II 5.0 45.0 9.0 45.0 80 7-Start Pumping Spacer LiteCRETE 5.0 171.6 34.3 171.6 80 13-Start Mixing Lead Slurry Pause 0.0 0.0 5.0 0.0 80 36-Drop Dart #4 Base Oil 5.0 95.9 19.2 95.9 80 19-5tart Displacement Total 01:16 332.5 bbl hr:mn End Job: Record returns to surface and plug bumping. Dynamic Security Checks: Frac 667 psi Pore 223 psi Collapse 8228 psi Burst 8405 psi at 4500.0 ft at 4500.0 ft at 9966.0 ft at 4300.0 ft BHCT Simulated BHCT CT at TOC 137 degF 140 degF 122 de F Temperature Results Simulated Max HCT Max HCT Depth Max HCT Time WELLHEAD PRESSURE '<t" N "- ('oj - Well Head Pressure ---- Acquired WHP N oq c;- O 0 ~ .... ~ .... .¡¡; ~~ c.. J: ::: 0> ci CO ci M ci 0 0 140 degF 9841.0 ft 01: 16:29 hr:mn:sc 10 20 30 40 50 60 70 80 90 Time (min) Page 5 Red_#3.cfw; 08-30-2004; LoadCase 3.5inch Production Casing (a) ; Version wcs-cem441_51 Client Well String District Country Loadcase : ECD !D ~ ~ (") ,,- N ,,- ~ ::> (/) (/) () ð: ~ ,,- ¿ c: <t: 0 ~ 0> co 0 UNOCAL RED #3 3.5 Kenai USA 3.5inch Production Casing (a) Frac Pore Hydrostatic Dynamic 10 20 30 40 50 Tim e (m in) 60 70 80 90 FlOWRATE COMPARISON <D !D "<t :£ .ê 15 e.. () (") rn a::: ~ ü: N o o 10 20 40 50 Time(min) 60 70 80 90 Red_#3.cfw; 08-3()C2004; LoadCase 3.5inch Production Casing (a) ; Version wcs-cem441_51 Page 6 Client Well String District Country Loadcase : UNOCAL RED #3 3.5 Kenai USA 3.5inch Production Casing (a) PRESSURE DIFFERENTIAL Red_#3,cfw; 08-30-2004; LoadCase 3.5inch Production Casing (a) ; Version wcs-cem441_51 Page · I Halliburton BAROID . UNOCAL Mud Program ! 8AROJO UNOCAL Red #3 Kenai Peninsula, Alaska Baroid Mud Program Halliburton Baroid Name (Printed) Signature Date Originator Dave Higbie Reviewed by Don Shaw I John Rose Customer Approval Rob Stinson Version No: Date: 1.1 August 30, 2004 Red #3 v1.1 08/30//04 . I Halliburton BAROID . UNOCAL Mud Program Red #3 Exploration Introduction: The following mud program was prepared for an exploration well on the Kenai Peninsula, Alaska. This well will be spudded with a 6% KCI drilling fluid and be drilled vertically to the 1,500' MD range. It will be drilled with a 12 X" hole size, cased with 9 5/8" and cemented. The surface casing will be drilled out with the existing mud system. The 8 %" interval will then be drilled to section TD at -4,500' MD. Seven inch casing will be run and cemented at this depth. The 7" will be drilled out with the existing mud system and a leak off performed. A 6 1/8" hole will be directionally drilled building to 36° then dropping to 12° by TD at 10,046' MD (9494' TVD). A 3 %" production liner will then be run and cemented in place. Spud the well with a 6% KCI/PHPA mud - 8.6 ppg. The mud weight will then be held in the 8.6 - 8.9 ppg mud weight range to the surface hole TD unless hole conditions dictate otherwise. Our primary focus for surface hole drilling operations will be adequate mud weight for well control and sufficient mud viscosity for efficient hole cleaning. This spud mud is formulated with two mechanisms to provide waste minimization and effective well bore stabilization, ionic inhibition (KCI),and polymer encapsulation (PHPA). This same 6% KCI/PHPA mud will be maintained through the intermediate interval. This mud offers good LCM responses if losses are encountered. Special emphasis should be placed on maintaining low ECD's and surge/swab pressures to minimize the potential for lost circulation. The production interval will begin with an 84/16 OWR used oil base fluid (saved from Star #1). The ratio will then slowly be raised to 90/10 by TO' to reduce rheological parameters. CaCI levels will be maintained in the 29-32% (290,000 - 320,000 ppm WPS) range. The mud weight will be held in the 9.2 - 9.8 ppg range or as required for hole stability. Primary Drillina Objectives: · Zero fluid related HSE incidents · Achieve wellbore stability · Achieve good hole cleaning considering hole angle, geometry and anticipated ROP rates · Lost circulation mitigation/control · Achieve good Zonal Isolation as per plan · Achieve minimal formation damage · Minimize fluids related NPT · Minimize drilling wastes Critical Fluid Issues: · Eliminating/controlling losses. · Maintaining a low ECO in the production zone to reduce risk of lost returns. · Maintaining a stable wellbore through coal seams. · Reducing drilling wastes with the inhibited drilling fluid system. Red #3 v1.1 2 08/30//04 . I Halliburton BAROID Well Specifics: . UNOCAL Mud Program Casing progr MD TVD FootaQe Red #3 12 X" hole (9 5/8" casinq) -1500' 1500' 1500' 8 Yz" hole ( 7 " casing) -4500' 4500' 3000' 6 1/8" Hole (3 Yz" liner) 1 0046' 9494' 5546' Surface Hole Recommendations Mud Type: 6%KCI, EZ Mud P rf rope les: Dens it-\' ~)Viscositv Plastic Viscosity Yield Point APIFL m:!. 0-1500' 8.6 ..,l8.9 ;' 60 - 85 6 -16 25 - 40 N/C 8.5-9.0 System FormulaHo~~ Product Water KCI KOH Barazan 0 EZ Mud DP Aldacide G Baracor 700 Barascav D 6%KCI, EZ Mud Concentration 0.905 bbl 20 ppb (30K chlorides) 0.2 ppb (9 pH) 1.25-1.5 ppb (as required 35 YP) 0.75 ppb 0.1 ppb 1 ppb 0.5 b add as the well suds Special Mixing Instructions: . Mix in order as listed . Add polymers slowly to minimize fisheyes. Concerns and Continaencies Surface Interval - ( 0 - 1.500' MD ) Mud TVDe: 1. Mud weight: 2. Rheology: 3. Filtrate control: 6 % KCI/PHPA Maintain the 8.6 - 8.9 ppg density or as directed. Maintain a YP between 25 - 40 or as needed to achieve adequate hole cleaning.. No filtrate control is required prior to reaching 1500' MD. Additions BOF-263 may be required to control screen blinding/bit balling. Seepage losses in this interval can be controlled with additions of 3-5 ppb BAROFIBRE or by dedicated LCM pills but are unlikely to occur. Operations Summary: This section will drill a 12 %" hole. Build the 6% KCI fluid in the proper order of addition. Maintain a reduced pit volume during spud as losses are not expected in this section. Be prepared for sloughing gravels in the upper interval; increasing the system rheology with BARAZAN-D/N-Vis will assist in bringing this material out of the well, as will pumping dedicated high-viscosity sweeps. It is recommended that the pump rate be increased to the maximum practical rate while the hole is unloading gravel. Sweep Formulation: 30 barrels mud (500' annular coverage), add ca. 1.0 ppb BARAZAN 0 to achieve a tauO > 25. When penetrating high-clay content sections additions of BDF-263 ester are recommended to reduce the incidence of bit balling and shaker blinding. Red #3 v1.1 3 08/30//04 . I Halliburton BAROID . UNOCAL Mud Program Be prepared to increase the YP if hole cleaning becomes an issue. Run DFG (Drilling Fluid Graphics) to confirm hole cleaning efficiency based on current rheology, flow rates and cuttings size. At TD, a Wallnut (20 bbl pill with 15 ppb of Wall nut F) or carbide "flag" should be pumped to gauge hole washout and to calculate the required cement volume. The cement will then be pumped and drilling mud will be used to bump the plug. Pretreat this chase mud with 1 ppb Bicarb and 0.5 ppb citric acid. Hazards I Concerns - Surface Interval: · Preventing lost circulation through ECD management. · Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. · Maintain YP between 25 - 40 to optimize hole cleaning and to control ECD. · Pump high viscosity sweeps to enhance hole-cleaning efforts. Monitor sweep effectiveness. · Successfully cement casing. Maximum Acceptable ROP in fph at Specified GPM and RPM GPM~ 550 600 650 80 rpm 179 206 230 100 rpm 179 206 230 Baroid's recommended flowrate for this interval is 550-650 gpm to maximize hole cleaning at high penetration rates. RPM's have no effect on hole cleaning in this vertical section. Intermediate Hole Recommendations Mud Type: 6%KCI, EZ Mud p . ropertles: Density Viscosity Plastic Viscosity Yield Point API FL Iili 1,500 - 4500' 8.9 - 9.2 40-53 6 - 15 13 - 20 <8 8.5-9.5 ",. System Formulation: 6%KCI, EZ Mud Product Concentration Water 0.905 bbl KCI 19.8 ppb (30K chlorides) KOH 0.2 ppb (9 pH) Barazan 0 1.25 ppb (as required 35 YP) Dextrid 1-2 ppb EZ Mud DP 0.75 ppb Aldacide G 0.1 ppb Baracor 700 1 ppb Barascav 0 0.5 ppb (maintain per dilution rate) Special Mixing Instructions: . Mix in order as listed . Add polymers slowly to minimize fisheyes. Red #3 v1.1 4 08/30//04 . . I Halliburton BAROID Concerns and continaencies UNOCAL Mud Program Intermediate Interval - ( 1500 - 4500' MD ) Mud Tvpe: 6 % KCI/PHPA ......~. 1. Mud weight: 2. Rheology: 3. Filtrate control: Maintain the 8.9 t'9.2 R-pg density or as directed. Maintain a YP betWeen 13-20 or as needed to achieve adequate hole cleaning. Add Dextrid and/or Pac L to reduce filtrate to the <8 cc/30 min range. Additions of BDF-263 may be required to control screen blinding/BHA balling. Losses in this interval can be controlled with additions of 1-2 ppb BAROFIBRE and 1-2 ppb of Baracarb 50 or by dedicated LCM pills; see appendix for LCM decision tree. Operations Summary: Drill out the cement/casing with the existing mud system. Bicarb or soda ash and citric acid should be used to pretreat for any negative effects of the cement. BARAZAN-D/N-Vis should be used to maintain rheological parameters. Maintain the mud as clean as possible while drilling. Should sweeps be required a high viscosity sweep is recommended. Daily additions of Aldacide G and/or X-Cide 207 should be made to control bacterial action. Sweep Formulation: 25 bbl of mud with 1 ppb of Barazan added. Dextrid and/or PAC L should be used for filtrate control. While drilling, monitor the torque and drag to determine if liquid lubricant is required. When penetrating high-clay content sections additions of BDF- 263 ester are recommended to reduce the incidence of bit balling and shaker blinding. Maintain the pH in the 8.5 - 9.5 range with caustic soda. The system rheology may be relaxed as hole conditions allow. This will lower the ECD for any weak zones which are encountered. However, be prepared to increase the YP if hole cleaning becomes an issue. Run DFG (Drilling Fluid Graphics) to confirm hole cleaning efficiency based on current rheology, flow rates, angle and cuttings size. Ensure that the mud weight is maintained as low as possible through this area. However this is an exploration well so monitor all kick warning signs at all times. Stress slow pipe movement to the drillers to reduce surge/swab on this fragile zone. Stage pumps on slowly after connections and begin rotation prior to pumping (this will break the gels and reduce the pressure required to break the gels). Should all these efforts fail and losses occur, please refer to the LCM decision tree appendix. If the losses are still high (above 30 bbl/hr static) after attempting an LCM pill, STOP running the fluid as a KCI/EZ Mud system. All additions of these products should be halted and allow the system to slowly break back to an LSND system. Run the fluid loss and rheology as with the inhibited system. When running the LSND, stop addtions of Baracor and Barascav D when the chlorides drop below 6,000 ppm's. All pit monitoring devices should be watched closely as this zone is cut. Maximum Acceptable ROP in fph at Specified GPM and RPM GPM~ 450 500 550 80 rpm 184 209 235 90 rpm 201 228 258 Baroid recommends a flowrate in the 500-550 gpm range to maximize hole cleaning efficiencies at these high penetration rates. However if losses occur, the flow rate can be reduced in conjunction with a slower penetration rate which would reduce the ECD/losses. Reduce system YP with Therma Thin as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology Red #3 vU 5 08/30/104 I Halliburton BAROID UNOCAL Mud Program I once the casing is landed to a YP < 20 ( check with the cementers to see what yp value they have targeted). The plug will be bumped with mud. If operations allow, the plug can be bumped with OBM. . . Hazards / Concerns - Intermediate Interval: · Preventing lost circulation. · Optimize solids control equipment to maintain density and sand content. · Maintain YP between 13-20 to optimize hole cleaning and to control ECD. · Pump high viscosity or Barolift sweeps to enhance hole-cleaning efforts. · Successfully land and cement casing. Production Hole Recommendations Production Hole Recommendations System Formulation Product Concentration Base Oil 0.696 bbl EZ MUL NT 4 ppb INVERMUL 4 ppb GEL TONE V 4 ppb Lime 5 ppb DURA TONE 4 ppb RM63 0.5 ppb Water 0.178 bbl CaCI2 24.6 ppb AK-70 4 ppb BAROID to a 9.2 DDQ Mud Type: Invermul System Mud Pro erties PV YP ES HTHP FL 4500 - 9,337 18 - 29 9 -18 1000- <6 1100 Additional mud weight maybe required for effective coal/ shale stabilization or for gas shows. WPS 290 to 320K 80/20 o/W ,/ · Concerns and continaencies Production Interval (6 1/8" hole. 3.5" casina ): 4500' MD - TD ',' Mud Type: 1. Mud weight: 9.2 ppg INVERMUL System. 2. Rheology: Maintain the density at 9.2 ppg or as directed; use solids control and whole mud dilution. Increase density as required for well control, hole stability or coal sloughing. Maximize solids control usage. A 9.2 ppg was used at this wells TVD on Red #1. Maintain a YP between 9 and 18. Pump high viscosity sweeps throughout the interval as needed, particularly prior to POH for casing. Optimized mud rheology and flow rate will be the primary mechanisms for achieving hole cleaning in this deviated well bore. Maximize pipe rotation (ideally ~ 60 RPM). 3. Other issues: The use of good drilling practices to minimize excessive swab and surge pressure should be employed to minimize the chances for losses and differential sticking. Please see the Coal Drilling recommendations attachment. Red #3 v1.1 6 08/30//04 . I Halliburton BAROID . UNOCAL Mud Program Operations Summary: The water base mud system will be displaced prior to drilling cement (unless operations can be worked out to bump the plug with the Invermul). Approximately 600 bbls of oil mud will be required for displacement. Used mud is available so it will be reconditioned at the rig and displaced into the wellbore. Prepare the pit system for the INVERMUL as follows: · Clean pits, solids control equipment, all lines and pumps. · Flush all lines with a small volume of oil and discard. · Disconnect all water lines to the pit area and rig floor. · Check all steam fittings in pit room for leaks and repair as needed. Once the shoe has been drilled, displace the well to the ENVIROMUL system designated for this interval of the well. Pump the following spacers ahead of the oil mud as follows (for Nabors 129): Spacer Formulations: · 30 barrels of water · 30 bbls of base oil · Follow with the INVERMUL mud system. Displacement procedure: · Monitor pump strokes to obtain correct displacement. · Maintain maximum pump rates. · Have the bit on bottom as the oil mud exits the bit. · Reciprocate the drill string by one joint every 15 minutes · Rotate the pipe as rapidly as allowed during the actual displacement. · Do not shut down during the displacement. · Use an E.S. meter at the flow line to determine when the fluid is water free enough to start taking the returns back into the system. An ES of 300-500 should be sufficient to indicate when displacement is complete. A retort should also be run at this time to confirm fluid quality. · Clean possum belly and any troughs which were used. Maintenance: 1. Additions of Geltone V and RM-63 will maintain/modify the system rheology to a YP between 9 and 18 to provide effective hole cleaning while controlling ECD and surge/swab pressures. Run the rheology checks at flowline temp until-6800' then at 120°F to TD. This will give a more accurate reflection as to the rheology the hole is experiencing. 2. OMC 2 and OMC 42 will be available to condition (thin) the mud as required; however, caution should be used when using these oil mud thinners (particularly the OMC-2) to avoid over-thinning the system. 3. Drill this interval with a tight DURATONE HT / AK-70 filtration mechanism « 6 cc/30 min @ 2000 F). Barablok and Barotrol will also be available to improve the filtration control mechanism. 4. For formation bridging/LCM, graded calcium carbonate (Baracarb(s)), cellulose fiber material (Barofibre) and SteelSeal are available. 5. The electrical stability of the mud should be run in the 1000-1100 volt range with INVERMUL and EZ MUL as the primary and secondary emulsifiers. DRIL TREAT will be available as an effective wetting agent, if needed. One drum of Driltreat should be ran in slowly while weighting. Red #3 vU 7 08/30//04 . . I Halliburton BAROID UNOCAL Mud Program 6. Maintain the water phase salinity between 290,000 - 320,000 mg/I range with sack calcium chloride. This level of salinity will provide an effective mechanism for good wellbore stabilization. 7. The excess lime content will be maintained in the 3 ppb range to provide an effective reserve alkalinity source and to improve the emulsion stability of the mud system. 8. The initial oil:water ratio will be 80:20. However if the OIW ratio is higher in the used mud do not adjust it down. From there, the system will be maintained with base oil allowing the ratio to drift to the 90: 1 0 range by TD. This will help reduce the cost of the original fluid and then help control rheology/ECD's with the 90:10 ratio in the lower depths of the well. Solids Control · Initially, screen shakers with 110 mesh. Adjust screen shakers as solids loading, flow rate, and rheology allow. Inspect the screens frequently, taking time to replace/repair damaged screens. · Run the desilter at all times. · Run the centrifuge at all times unless barite is required for a higher mud weight. Then run it on an as needed basis. Suggested Drilling Parameters Pump rate and drill string rotation should be optimized through the real-time use of the DFG software for the actual ROP while drilling. The table below highlights the maximum ROP recommendations above which hole cleaning will become an issue. Maximum Acceptable ROP in fph at Specified GPM and RPM GPM~ 200 250 300 60 rpm 174 201 267 80 rpm 195 242 301 ROP rates above these levels or with no (sliding) or low rpm will require an increased frequency of the following remedial hole cleaning practices: · wiper trips · back reaming · extended periods of circulation (with maximum pipe rpm, targeting> 80 rpm) · hole cleaning sweeps (change flow regime of base mud by using fibers, density or rheology for carrying capacity) · connection practices - employing extended gpm, rpm and back reaming during the connection Sweeps Two types of hole cleaning sweeps can be used if the high vis sweeps are inadequate: · Increase the sweep density with SWEEPWATE to 2 ppg over system density. The SWEEPWATE will increase the sweep carrying capacity yet will be removed at the shakers; this will result in no density increase from running weighted sweeps. · To reduce the density/viscosity build up in the system, sweeps can be built by adding 0.25 ppb BAROLlFT in place of clay. The fibrous BAROLlFT will be removed at the shakers. Note: Properly size all sweeps for 300 - 400 ft of annular coverage Supplement the hole cleaning of the drilling fluid as dictated by hole cleaning indications. Monitor all sweeps pumped and report on their effectiveness. Maximize drill pipe rotation at high rates on a frequent basis (particularly during connections) to assist in disturbing any potential cuttings accumulations down- Red #3 v1.1 8 08/30//04 . . I Halliburton BAROID UNOCAL Mud Program I hole. The objective of the sweep is to change the flow characteristics / carrying capacity that is inherent with the mud system. Select sweep type accordingly. Coal Drilling The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The hole stability risks when drilling coal seams are often high, and the fluid design and drilling operations have been optimized to combine reduced risk with reduced costs. The need for good planning and drilling practices is also emphasized as a key component for success. · Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. · Use asphalt-type additives to further stabilize coal seams. · Increase fluid density as required to control the running coal. · Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROL pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss ( based on ECD values using the DFG software). System density increases can also be employed in increments of 0.5 ppg. Solids Control Equipment Maximize the use of all solids control equipment to ensure that the solids content of the system is kept to a minimum during this interval. 1. Run the shale shakers with as fine a screen size as possible. · Size shakers screens with coarse mesh initially · Adjust screen size as solids loading, mud rheology and flowrates allow · Inspect the shakers frequently, taking time to repair / replace damaged screens 2. Maximize the use of the centrifuge, keeping the fluid as clean as possible. Running Casing I Cementing Preparation Monitor hole fill/returns closely while running the liner to insure losses haven't occurred. Refer to Baroid's DFG+ program if calculated surge/swab values are needed. Condition the mud prior to the cement job. Displace the cement with 3% KCI or Freshwater. Use Baracor 100 for corrosion inhibitor in the tubing annulus. Production Hole - Hazards / Concerns: · Optimize solids control equipment to minimize colloidal solids build up and dilution requirements. · Maintain flow profile based on PV, YP and tauo flow parameters. · Pump sweeps as required to enhance hole-cleaning efforts. Monitor the effectiveness of any sweeps pumped. · Follow the hole cleaning guidelines to assist in drilling parameter selection. Use connections for high RPM and pump rate support when these parameters are limited during drilling operations. · Follow the coal drilling guidelines. Estimated Fluid Costs: 8,000** 18,000 68,000 $94 000 20,000 50,000 120,000 $190,000 12 W' Surface 4,000 8 W' Intennediate 14,000 61/8" Production OBM 37,000 Total $55,000 ** The surface hole estimate assumes 500 bbls of recycled mud. Red #3 v1.1 9 08/30//04 · I Halliburton BAROID Losses Seepage 5·10 bbllhr Static 40 ppb LCM/Mud Pill: 10 ppb Baroseal F 10 ppb Baroseal M 1 0 ppb Barofibre 10 ppb Wallnut M No Proceed to 'Partial Losses' Pill Red #3 v1.1 . UNOCAL Mud Program UNOCAL Lost Circulation Decision Tree f/lnhibited Mud Systems Partial 15-60 bbllhr Static No 70 ppb LCM/Mud Pill: 20 ppb Baroseal F 20 ppb Baroseal M 20 ppb Barofibre 10 ppb Wallnut M No Contact Drilling Engineer or Engineer on eall to determine if additional LCM treatments are to be made or to proceed to Gunk Squeeze pill Severe 60·200 bbllhr Static 100 ppb LCMlMud Pill: 20 ppb Baroseal F 20 ppb Baroseal M 30 ppb Barofibre 20 ppb Wallnut M 10 ppb Wallnut F Pump Gunk Squeeze pill 10 Pump Gunk Squeeze pill (Volume to be determined based upon losses) Total > 200 bbllhr Static Pump Gunk Squeeze pill to allow POH (Volume to be determined based upon losses Contact Drilling Engineer or Engineer oneall POH, PU dumb iron BHA Consider cement I plugback contingency Notes: 1) Drill across fault or loss zone 1.5·2.0 times the length of the throw before spotting Gunk Squeeze. 2) PBl sub should be run in BHA to spot pills if 'Partial loss' cases or above are anticipated prior to drilling to allow the spotting of lCM pills. 3) lCM ~II volume = 300'-600' column based upon actual hole diameter. 4)pRIOR TO ANY lCM Pill, APPROPRIATE DISCUSSIONS AT THE RIG MUST BE MADE TO MINIMIZE THE POTENTIAL FOR PLUGGING THE DRill STRING. 08/30//04 . . I Halliburton BAR OlD Mud Program Losses No 20 ppb LCM/Mud Pill: 20 bbls base mud 10 ppb Baracarb 50 10 ppb Baracarb 150 No Proceed to 'Partial Losses' Pill Red #3 v1, 1 UNOCAL UNOCAL Lost Circulation Decision Tree fl Payzone Mud Systems No , Contact the Engineer on call to determine if additional LCM treatments are to be made or to proceed to reverse gunk squeeze pill Seepage Partial Severe Total 20-60 bbl/hr 5-20 bbl/hr Static Static 60-200 bbllhr Static > 200 bbllhr Static Treat Active System Treat Active System with 5 sxlhr Baracarb with 1 0 sxlhr Baracarb 50/150 150 Pump reverse gunk squeeze ~II to allow 100 ppb LCMlMud Pill: POH (Volume to be Pump reverse determined based Yes 20 ppb Baroseal f upon losses 20 ppb Baracarb 50 gunk squeeze pill 30 ppb Barofibre to allow POH 20 ppb SteelSeal (Volume to be Contact Drilling 10 ppb Baracarb 150 No determined based Engineer or Engineer Increase Treatment to upon losses) on call 10 sxlhr Baracarb 501 50 ppb LCM/Mud Pill: 150 20 bbls Base mud 10 ppb Baracarb 25 20 ppb Baracarb 50 20 ppb Baracarb 150 Pump reverse gunk squeeze pill (Volume to be determined based upon losses Plan to pump a second 50-80 bbl reverse gunk squeeze pill if massive losses continue. Consider cement I plugback contingency 1 )UNOCAL must approve any steps past PARTIAL losses. 2) Drill across fault or loss zone 1.5 - 2.0 times the length of the throw before spotting reverse gunk squeeze pills. 3) PBl sub should be run in BHA to spot pills jf 'Partial loss' cases or above are anticipated prior to drilling to allow the spotting of lCM pills. 4) lCM pill volume = 300'-600' column based upon actual hole diameter, 5)PRIOR TO ANY lCM PilL. APPROPRIATE DISCUSSIONS AT THE RIG MUST BE MADE TO MINIMIZE THE POTENTIAl FOR PLUGGING THE DRill STRING. II 08/30//04 UNOCAL BAROID Surface Modeling 5 10 15 20 25 0 50 1000 78 157 30 60 90 8.90 9.40 ':ì hI îllT tim.. Rotation has no effect in this vertical hole section. Good hole deaning with low 550 to 650 gpm range. BAROID Intermediate Modeling UNOCAL 1000 5 10 15 20 25 0 50 1000 216 432 A hr fliT IÎmp 2000 3000 4000 500 to 550 gpm will provide excellent hole cleaning while keeping the ECD in the 9.6- BAROID Production Modeling UNOCAl 1000 5 10 15 20 250 50 0 246 492 1 n hr rm limp 2000 3000 4000 5000 6000 7000 0000 9000 10000 The pump rate can be dropped to 250 gpm and still clean the hole effectively while staying in the 10.4 _ 10.5 ppg ECD range. 60 rpm's is the minimum which should be used. · Unocal Corporation . P.O. Box 196247 Anchorage, AK 99501 Telephone (907) 263-7660 UNOCALe Phil Krueger Drilling Manager Thursday, September 2,2004 Alaska Oil and Gas Conservation Commission 333 West th Avenue Anchorage, Alaska 99501 Attn: Commission Chair John Norman Re: Application for Permit to Drill (Form 10-401) Red #3 - Exploration Well Dear Commissioner Norman, Attached for your approval is an application for permit to drill (Form 10-401) for the Red #3 exploration well. This will be Unocal's third exploratory project in the Nikolaevsk Unit, with the Prim.'~. ..... jec~:as a down-dip dilenation well ( Excess mud and cuttings will be hauled to thevwell and disposed into the annulus of that well.·· A waiver will bë""requested for wellbore surveys in the 12 ~" hole section, drilling without ~ a diverter and removal of special H2S provisions. The planned spud date is September th , 2004 and the contracted rig will be Nabors Rig I #129. A spacing exception will not be required for this well. If you have any questions please contact myself at 263-7628 or Mr. Rob Stinson at 263-7804. Sincerely, V·/I~/ ~- -=> Phil Krueger Drilling Manager RECEIVED SEP - 3 2004 Alaska Oil & Gas Cons. CommiSSton Anchorage OR\G\NAL . . Table of Contents 1. 10-401 Permit to Drill 2. Waiver Requests 3. Outline Summary 4. Red #3 Schematic 5. Plat Map 6. Red #3 Directional Plan 7. MASP Calcs 8. Casing Design Cales 9. 11" 5M BOP Stack Drawing 10. Cement Program 11. Mud Program I 151 36 00 VI I 151 34 00 VI I 15 32 00 VI Ù1 cD Ù1 , RED #3 Explor ory 2041690 Sec.S <::> <::> z SFD 9/3/2004 "... i:'J' T4S, R13W, . CITIBANK DELAWARE A Subsidiary of Citicorp ONE PENN'S WAY NEW CASTLE, DE 19720 2007814 . Pay One Hundred Dollars And 00 Cents************************************************************** To the order of STATE OF ALASKA ALASKA OIL & GAS CONSERVATION COMMISSION 333 WEST 7TH AVENUE SUITE 100 ANCHORAGE, AK 99501 United States 01-SEP-04 **********100.00 frOll1 above --Arl~ III 20078 . ~III 1:0 j . .00 20 gl: j g . . 8 . j 7 III . . TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERIP ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER í26b ?f 3 WELL NAME P1D# zoL/- Ib1 /~ Development Service Exploration Stratigraphic CHECK WßA T ADD-ONS "CLUE". APPLIES (OPTIONS) M1JLTI Tbe permit is for a new weJlboresegment of LATERAL existing wen . Permit No, API No. . (If API number Production. sbould continue to be reported as last two (2) digits a function· of tbe original API number. stated are between 60-69) above. PILOT BOLE ]n accordance witb 20 AAC 25.005(f), all (PH) records, data and logs acquired for tbe pilot bole must be dearly differentiated In botb name (name on permit plus PH) ,. and API Dumber (SO - 70/80) from records, data and logs acquired for well (name on permit). SPACING Tbe permit is approved subject ·to fun EXCEPTJON compliance witb 20 AAC 25..05S~ Approval to perforate and produce is contingent upon issuance of ~ conservation order approving a spacing e:J ception. (Company Name) assumes tbe liability of any protest to tbe spacing .e:Jception tbat may occur. DRY DITCH AU dry ditcb samp)e sets submitted to tbe SAMPLE Commission must be in no greater 1ban 30' samp)e intervals from be)ow tbe permafrost or from wbere samples are first caught aDd ] 0' samp)e inter:vals through target zones. Well Name: RED3 Program XP Well bore seg 0 RNIA Initial Class/Type ---EP/PEND GeoArea 820 Unit _ On/Off Shore On Annular Disposal 0 - - Administration P~rmit fe~ attacheØ Yßs_ 2 _Leas~numb~r _appropriate_ YßS __ 3 _U_nique welt flarn~ .anq Ollmb_er _ _ _ . . _ _ _. _. _. YßS __ - - - - - - - - - - - - -- . -- - - - - - - - - - - - - - -- - - - - -- 4 WellJocat~d in_ad_efil1eØ-pooL _ _ _ No_ Delineation wel/lo undefil1ed pool - - - - - - 5 Well Jocat~d proper distance_ from driJling ul1itb_oul1d~ry_ _ Yßs_ 8DL 389227 8. adjacentJease ADL 38820a cornpri$e Se_ctio_ns 6&, 7; _both are 100%_ UnocaJ owners_hip & 6 Well Jocat~d prop~r distance_ from Qther wel!s_ Yßs_ 10_0%_ state tandownership. _In shaJlowe_st pay _Zone, se-paration_ will be. --::3,3.00', _ 7 _S.ufficientacreage_ayailable indrilJiog l!njt Yes. _ - - - - - - 8 Jf.d~viated, js. weJlbore plaUncJu_ded _ Yes - - - - - - 9 .O-perator only affeçteq party. _ - - - - - Yßs 10 .O-perator bas.appropriate.bond in.fQrçe . . . . . . . . . . . . . .. - . . .Y~s.. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -. - - - - - - - - - - - - . - - - - - - - - - - - - - 11 Pßrmit can be iSSl!ed without ço_nserva.tio11 order_ Y~s_ _ - - - - - - Appr Date 12 Pßrmit c.an be i_sSl!ed without admini$tratille_approvaJ _ _ - - Y~s_ . SFD 9/3/2004 13 Can permit be approved before 15-day wait Yes 14 Well Jocatßd withil1 area and_strata .authorized by_lnjectioo Ordßr # (PuIIO# in. cOOlrnßots). (For .NA _ _ - - - - 15 AJlweUs.withtn.1t4.rTJite.area.ofreyiewidßotifieq(For$eNjceweUOl1ly)............... .NA.. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- 16 Pre-produ.ced injector; øuratiQn.of pre-production IßSs_ than 3 mOl1ths_ (For.service well Qnly) _ _ .NA 17 ACMP_ Finding 9f CQn_si;;tency.has been i$sued_ forJbis project NA CQn_sistency.deterroioatioo dQe;; _not impact permit to_drill apprQval, .5fD. _ Engineering 18 .C9nductor $t(ÌngprQv!ded . _ YßS _ . 16"@6,('.. . 19 .Suúaceca$ing_pJQtect$ all_known USOWs _ Yßs 20 _CMT v.ot adeQ uate. to çirc_utate _ on .cOnduçtor_ 8. SUJf. C$g . _ Yßs 8de~uate ex.ce$S, . 21 .CMT vol. adeQuateJo tie-inJQngstring tosuú C$g. _ No_ - - -- - - -- 22 _CMTwill coyeraJlkoownpro.ductiye horizon.s_ . _ Yes_ - - - - - - - - - - 23 C.asiog designs adequaJe for C,T. B.&perroafr.ost. ._.YeSd - - - - 24 .Adequatet'mkage.oJ reserve pit. . Yßs Nab.ors.129. 25 Jf.a_re-d(ÌI~ bC!sa. 10,403 for abandonlTJent beßO apPJoved . NA New well, - - -- 26 Adequate.we!lbore$eparatjo.n-PfopO~ed. . . . . . . . . . . . . . . . . . . . . . . .. . . .Yßs.. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- 27 Jf.divect~r JeqlJired, dQes iLmeet reguJatiol1s. .No Waiyeuequßsted. . Appr Date 28 _DriUiog fluid program schematic_& ~quipJistadequale_ . . . .Yß$ _ Max MW9,8 ppg._ e WGA 9/3/2004 29 .BOPEs,.dp Jhey meet reguJatioo . .Yes - - - - - - - - - - - - - 30 BOPE.pr~ss ratiog appropriate; .test to (put psig incommeots). _ .Yes _ Test tp35QO psi. .MSf' 3240 psi.. . - - -- - - - -- 31 _C.hokeroanifold cOlTJpJies w/APIRf'-53 (May 84) Y.es 32 Work will occ.ur withoytoperatjonsbl!tdown. . Yes - - - - - 33 J$ pre$ence of H2S gas. proQable. . . _ . No_ 34 MeçlJa.nicalcpodilionot weBs within 808 yerified (Focs.erviCß wel) only) _ .NA. . Geology 35 Pßrmit can be issued wto. hydrogen s.utfide meC!SIJ(es _ Yßs_ No (aport ofH2S jn 2 prelliQus ßJc<pJoratory welJs.drilJed.frorn. same pad through. $arn.egeologic ~eçtjon, 36 _D_ata_PJeseoted on_ pote_ntial oveJpres_sure _zones _ . _ Yßs_ Norl11alpJes$yre gradieote1<pe.cted bas.ed 00 previous.e1<ploratory w.elJs_. . . Appr Date 37 S~isl11ic.analysjs_ of shaJlow gas.zooes_ . NA Third wel) trQro same_ pad~ prevjo_us 2 wel)s djd not el1coYfltershallow haz_ards. SFD 9/3/2004 38 Seabed _condjtipo Sl!rvey(if off-shore) . . .NA 39 . CQnta.ct l1am.elphone}or.weekly progre$sreports [e1<ploratory .only} _ . .Yßs PhiLKrueger .901-263," 162S - - Geologic Date: Engineering Date {l; Date Commissioner: Commissioner omm . ner Ù't.Ç 1}3 ft