Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
HOME
EVENTS
DATA
Data List
Drilling
Production
Orders
Data Miner
Document Search
REPORTS
Reports and Charts
Pool Statistics
FORMS
LINKS
Links
Test Notification
Data Requests
Regulations
Industry Guidance Bulletins
How to Apply
ABOUT US
History
Staff
HELP
Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
204-084
• • AOGCC Memorandum Date: 7/27/2017 To: File; AOGCC Docket 15-38 7(z�/ 7 From: Jim Regg, Petroleum Engineer Subject: Closeout—Missing Outer Annulus Pressure Gauges Deep Creek Unit Happy Valley B-14 (PTD 2120540) Deep Creek Unit Happy Valley B-15 (PTD 2121320) Niko aevs' -ed#aPT R 141:41 Hilcorp Alaska LLC (Hilcorp) was sent a letter dated December 21, 2015 advising that AOGCC inspections at the Happy Valley and Nikoleaysk production sites found 3 wells that were not equipped with the required outer annulus pressure gauges. Instructions included in the letters required Hilcorp to describe what has been or would be done to correct and prevent recurrence. AOGCC also required with the response a list of Hilcorp-operated wells that do not have the required pressure gauges as outlined in 20 AAC 25. 200(c). Hilcorp responded on January 22, 2016 (after being granted an extension on January 8, 2016) with the required information. As follow-up to Hilcorp's letter, AOGCC performed inspections of the wells noted as not equipped with the required gauges for monitoring annulus pressures. Corrective actions have been implemented as described. AOGCC continues to monitor all wells during site visits for compliance with the pressure gauge requirements. This docket (OTH 15-38) is considered closed with Hilcorp's response and AOGCC inspections. SCANNED AUG 0 4 2017, • • Hilcorp Alaska, LLC Post Office Box 244027 Anchorage,AK 99524-4027 I< 2 2 3800 Centerpoint Drive January 22,2016 Suite 'F ( Anchorage,AK 99503 Cathy P. Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage,AK 99501-3572 Re: Docket No. OTH-15-038 Missing Outer Annulus Pressure Gauges Deep Creek Unit Happy Valley B-14 (PTD 2120540) Deep Creek Unit Happy Valley B-15 (PTD 2121320) Niko aevs Red#1 (PTD 204b ear Chair Foerster: We write to provide additional information concerning our review of all Hilcorp Alaska-operated wells. On December 21, 2015, you wrote stating that safety valve system inspections performed by an AOGCC Inspector at the Happy Valley B-Pad and the Nikolaevsk Pad revealed three wells not equipped with pressure gauges to monitor the outer annuli. We responded by letter dated January 8, 2016, noting that a gauge had been installed on well Nikolaevsk Red#1 (PTD 2040840), the Happy Valley wells B-14 and B-15 did not require outer annulus pressure gauges as the wells were constructed with only a tubing-casing annulus, and requesting additional time to complete the review directed in your December 21 letter. You replied by letter dated January 11, 2016, providing additional time and requiring a response by January 22,2016. This letter is our response. We appreciate the extension of time to complete a thorough review of Hilcorp Alaska-operated wells. The additional time was necessary so well schematics and well head designs could be reviewed to ensure all proper annuli had valves and gauges, based on design, and not just what was visible on the well. Our review found that all wells operated by Hilcorp Alaska had the required annuli valves. The review identified the following wells did not have the required annuli gauges on the wells (see attached photos): Well PTD# Gauge Status Correction Ivan River 41-01 192-109 Missing OOA Gauge OOA Gauge Installed 01/12/16 Nikolaevsk Red#2 204-084 Missing OA Gauge OA Gauge Installed 12/29/2015 Swanson River 12-15 160-022 Missing OA Gauge OA Gauge Installed 01/14/2016 Swanson River 32A-15 194-084 Missing OA Gauge OA valve was below mud in cellar.The cellar (Note:2 IA Gauges bottom needed to be thawed to be able to suck out Were Installed) mud below valves to install gauge. OA Gauge will be installed before 02/01/16. ECOPY • • Cathy P.Foerster Docket Number:OTH-15-038 January 22,2015 Page 2 of 2 The monobore wells that have only one monitorable casing have only one gauge. The following fields have active monobores: Cook Inlet Fields Monobore Count North Slope Fields Monobore Count Beaver Creek 4 Milne Point 36 Cannery Loop 2 Happy Valley 3 Kenai Gas Field 5 Ninilchik 2 Swanson River 2 During this review of all wellheads in Hilcorp Alaska's inventory we identified a knowledge deficiency with some of the field operations staff where some did not fully understand wellhead design below the master valve. We are currently developing a general wellhead training module that will become part of the field operator training package for the Alaska employees. We expect this to be completed in early March and will be reviewed with all Hilcorp Alaska field operators. Hilcorp is available at the commission's convenience to inspect the wells that were missing the correct gauges in Swanson River,Nikolaevsk Field and Ivan River, to close this matter. Should you have any additional questions, please contact Chad Helgeson(777-8405). Sincerely, HILCORP ALASKA, LLC David ilkins Senior Vice President Hilcorp Alaska, LLC Attachments— Ivan River 41-01 Casing Gauge Photos Nikolaevsk Red#2 Casing Gauge Photos Swanson River 12-15 Casing Gauge Photos Swanson River 32A-15 Casing Gauge Photos cc: Jim Regg-AOGCC Chet Starke] -Hilcorp Larry Greenstein -Hilcorp David S Wilkins-Hilcorp Bo York -Hilcorp Stan Golis—Hilcorp Mike Dunn -Hilcorp MIIM • AOGCC Docket W .OTIC-15-038 Missing Outer Annulus Pressure Gauges Corrective Actions �`—.si rte^ e¢. A ' : „. . k o-: as3i n Nr, 't 1 - „, ' litils'i444,.'1",404$ .• N.. 1,44s), sp,,,,i4,:-*,,,... 4 a \ . , 4,‘Nsloi, . 0.,. ,.,,.: ,,,,,,,,,kn . '.:. t , \ -.,.„,: -*AQP 3 ,,, . '. . ,,,,.... Ivan River 41-01 Outer Outer Annulus gauge 0 , ' . t I r 1 i � ` 1 : `711 Nikolaevsk Red#2 Outer Annulus gauge Mk • ft 11llcon)Alaska,LL(; SWANSON RIVER UNIT 12•'5 ISRU"2'5, ... ,,.-1 API #50.133 10138-00 00 _.fT -)-j PTD# 160.022 Al. 4to;w,r LEASE#FED A028406 SURFACE LOCATION: t SW1.4,WW1 4 SEC 15,T8N.R9W SM 4 :.r < - r'. 1 + Swanson River 12-15(Tree removed above Master Valve for Drilling Activity) c 4 iti A . i ValftimmintsiA 1 y � x 1. - �NRllERL�;T32A151SrU S 7331a1ai-01-� API#:1L)4') 4r. .1-084- . FT`: D A0:78406 P• �-uREA`C i y't!5 TO F94 AK ,, w} SWI 4 m-""9 `, o,r "�"i`'�-". Swanson River 32A-15 (Tree Removed for Drilling Activity). 2 gauges installed on IA valves, and OA valve is below the mud line in the cellar(found during wellhead and well schematic review). :._. � -a7'_ } +y,; a —C"__.ccwf+ '-�-t.`-cyst.-�._.-" , .^,',n 1 3, Dr ,',44"i s T';s. WVqq IP w - ..._ s\fr I;!%, il THE STATE Alaska ..=I Gas in _�N2 333 West Seventh Avenue ®��i� � GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 y, Main: 907 279 1433 �` Fax 907.276.7542 www.aogcc.alaska.gov January 8, 2016 CERTIFIED MAIL— RETURN RECEIPT REQUESTED 7015 0640 0006 0779 5852 Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Re: Docket No. OTH-15-038 Missing Outer Annulus Pressure Gauges Deep Creek Unit Happy Valley B-14 (PTD 2120540) Deep Creek Unit Hap y Valley B-15 (PTD 2121320) '' ' olaevsk Red#1 (PTD 0840 tear Mr. Helgeson: The Alaska Oil and Gas Conservation Commission (AOGCC) received Hilcorp Alaska LLC (Hilcorp)'s response to the notice of violation dated December 21, 2105. Information included well schematics for each of the wells that were observed to be missing outer annulus pressure gauges. In the case of Happy Valley wells B-14 and B-15, AOGCC agrees with Hilcorp that the outer annulus pressure gauges would not be required based on the well schematics provided (wells are constructed with only a tubing-casing annulus). Hilcorp confirms that the required pressure gauge has been installed on the outer annulus of Nikoleaysk Red #1 but that has yet to be confirmed by AOGCC. Hilcorp has requested an extension until January 22, 2016 to complete a review of all Hilcorp- operated wells and provide a timeline for installing the required annulus valves on those wells that are not in compliance with 20 AAC 25.200(c). Hilcorp's requested extension is APPROVED. The AOGCC will not close this enforcement action until the required information has been provided by Hilcorp and an AOGCC Inspector has been able to confirm compliance with 20 AAC 25.200(c) for all wells identified as missing the required annulus valves and pressure gauges. Questions regarding this letter should be directed to Jim Regg at 907-793-1236. 4 • Docket No.OTH-15-038 Notice of Violation January 8,2016 Page 2 of 2 Sincerely, Cathy . Foerster Chair, Commissioner cc: AOGCC Inspectors C. Helgeson(Hilcorp, by email) RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a),within 20 days after written notice of the entry of this order or decision,or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed,then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration,upon denial,this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction,in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration,this order or decision does not become final. Rather,the order or decision on reconsideration will be the FINAL order or decision of the AOGCC,and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails,OR 30 days if the AOGCC otherwise distributes,the order or decision on reconsideration. In computing a period of time above,the date of the event or default after which the designated period begins to run is not included in the period;the last day of the period is included,unless it falls on a weekend or state holiday,in which event the period runs until 5:00 p.m.on the next day that does not fall on a weekend or state holiday. 0 0 Hilcorp Alaska,LLC Post Office Box 244027 Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 100 Anchorage,AK 99503 January 5, 2016 Cathy P. Foerster Chair,Commissioner Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage,AK 99501-3572 Re: Docket No. OTH-15-038 Missing Outer annulus Pressure gauges Deep Creek Unit Happy Valley B-14(PTD 2120540) Deep Creek Unit Happy Valley B-15 (PTD 2121320) Nikolaevsk Red#1 (PTD 2040840) Dear Chair Foerster: We respond to the Alaska Oil and Gas Conservation Commission's (AOGCC's) letter dated December 21,2015, in regards to Missing Outer Annulus Pressure Gauges. The Happy Valley 14 & 15 wells do not have a casing-casing(outer) annuli and therefore did not have a gauge installed in the conductor valve. This was communicated to the AOGCC inspector by the Hilcorp Alaska LLC (Hilcorp)representative during the visit in October. Attached are the current wellhead schematics, which show the bottom valve/flange is mounted to the conductor (10-3/4" Pipe). These conductors were driven into the ground and are not designed to hold pressure. The conductors are designed as a support during drilling, to flowback returns while drilling and cementing of the surface casing, and prevent collapse of the loose soil near the surface. The Nikolaevsk Red #1 well did not have a gauge in the casing-casing annulus. Attached is a picture of the casing-casing valve that was not plugged, and until a full wellhead review was completed on this well, it was not clear by the Hilcorp operators that this was a casing-casing valve that would monitor the 9-5/8"x7" annulus of this well. A gauge has been installed on the valve and is being monitored by operations. There are many wells operated by Hilcorp that are monobore completions and do not have casing-casing annuli. We are currently conducting a review of all the wells and wellhead designs to understand which wells do not have an outer annulus and therefore may not comply with 20 AAC 25.200(c). A preliminary list of wells that have this configuration are: Happy Valley #9, 14, 15 & 17, KBU 41-07X & 31-06X, Falls Creek 5, Paxton 5, Beaver Creek 23, 24 &25, SRU 213-15 &213B-15. 0 • Cathy P.Foerster Docket Number:OTH-15-032 January 5,2016 Page 2 of 2 Hilcorp is requesting an extension until January 22°d to complete a review of the entire I-lilcorp Alaska well inventory and provide a list to the AOGCC of wells that do not have casing-casing annuli. In the last two weeks of field reviews only one other well (Shut-in Nikolaevsk Red #2) with a casing-casing annuli was found that did not have a gauge on casing-casing annuli. Please let us know if this additional time will be allowed to complete this list of wells that do not meet 20 AAC 25.200(C). Should you have any additional questions, please contact Chad Helgeson(777-8405 or chelgeson@hilcorp.com). Sincerely, HILCORP ALASKA,LLC David Wilkins Senior Vice President Hilcorp Alaska,LLC Attachments— Happy Valley B #14 Wellhead Schematic& Wellbore Schematic Happy Valley B #15 Wellhead Schematic& Wellbore Schematic Nikolaevsk Red#1 casing photo, Wellhead Schematic& Wellbore Schematic cc: Jim Regg—AOGCC Chet Starkel—Hilcorp Larry Greenstein—Hilcorp David S Wilkins—Hilcorp Bo York- Hilcorp Stan Golis—Hilcorp Mike Dunn—Hilcorp • 4110 , Happy Valley HV#14 Current 01/05/2016 I l d....p 11.4,4.1.1. Happy Valley Tubing hanger,FMC-TC-EN- HV#14 CL,7 X 2 7/8 IBT lift and susp, 10%X75/8X5'%X w/2%Type H BPV,5% 2 3/8 Extended neck,'''/control line port,Alloy material BHTA,Bowen,2 9/16 5M X 2.5 Bowen quick union 0 NI4-EINNIIIIIIIIIIII ,c IIMIIII 44 ' 41,"' Valve,Swab,WKM-M, ���� ��� J�•��`Z�O Q,<<<c„,ss� 2 9/16 5M FE,HWO,DD trim ) 1� e, ��c.' _4. Q6, .- -. Jai,h.. axi -,A1` o IN I 1 Nlb Cross,stdd,2 9/16 5M X = v ' , 3 1/8 5M +!i 1' i QO I, MENEM. , ""fir" 3 1/8 5M API stdd Valve,Master,WKM-M, _ 2 9/16 5M FE,HWO,DD trim ......„1.19 J ...L. ... i Valve,Master,WKM-M, .� 2 9/16 5M FE,HWO,DD trim Tubing head,TCM,11 5M X i pl 'IIi a1' 7 1/16 5M w/2-2 1/16 5M Of dip kt1 2 I1 16 5M API stdd SSO,7"bottom prep - 5 i S 1/2 x 2 3/8 1 i {•(°�.� � annulus jill ■11.x `` -.§.2..ir-i i 1=E._ I Multibowl Wellhead,SMB- Ai I' III i 22,11 5M X 10' SOW,w/ 4-21/165MSS0 S �' .� 1.1 758x5% , ! 4 1 7 5/8 mandrel hanger and f 1��u MI= 4.. :( r.(o)�a .—111•t• / I packoff installed in head ; I� annulus i !"i' 1r — Ii sa%, iver M �' [�(°)„1liii 10%conductor liw I 110 7 5/8" 5%" 2 3/8 Happy Valley Well: HV B-14 SCHEMATIC PTD: 212-054 i. API: 50-231-20036-00 Surface Location: KB 610'Above MSL CASING DETAIL X:223720 Y:2190914 SIZE WT GRADE CONN ID TOP BTM. CMT 10-3/4" Weld Surf. 112' None 7-5/8" 29.7 L-80 BTC 6.875 Surf. 998' Surf. 5-1/2" 17 L-80 VAM ST-L 4.892 791' 2,005' 790' TUBING DETAIL 5-1/2" 17 L-80 VAM ST-L 4.892 Surf. 790' N/A VELOCITY STRING DETAIL Surface Hole: 9-7/8"Hole,9.2 ppg WBM 2-3/8" 4.7# L-80 8rd 1.995 Surf. 1,684' Cement to Surface JEWELRY DETAIL NO DEPTH ID ITEM 1 790' 4.892 JMZX Liner Hanger PERFORATION DETAIL ZONE TOP(MD) BTM(MD) TOP(TVD) BTM(TVD) FT SPF DATE Sterling A 1,689' 1,703' 1,689' 1,703' 14 6 7/30/2012 Production Hole: 6-3/4"Hole,9.2 ppg WBM Cement to TOL @ 790' Sterling A TD=2,005'MD/TVD PBTD=1,894141D/TVD Revised 3/31/2014 by TDF , , • Happy Valley Eli HV#15 01/05/2016 Happy Valley Tubing hanger,SMB-22 11)1-11-171— 4-1-ti Irlj ported,11 X 5'A LC susp X 10%X 7 5/8 X 5 1/2 5.875-4 stub acme left hand lift,5"H BPV,4.930"min bore,7"extended neck BHTA,OTIS,5 1/8 5M X 9%2 Otis quick union top 1111 ICI ■ i,o, O O - � (c �\\S(Valve,Swab, ,.,,■ %, �, WKM-M,5 1/8 5M FE,HWO, Ja\-A \\`bh��tc ��h�S� DD trim (�'( o* �,'' Op yciJ y\� CR, i it(o"--1 I\ . (W ) [-N ,■„■1 pais., Valve, Valve,Upper Master WKM-M,5 1/8 5M FE,HWO, (ti(..( o-c; * DD trim `� �U,v Nu Tile, MONEM Valve,Master,WKM-M, . J 5 1/8 5M FE,HWO,DD trim �( o„ Uuuv m uT u, 1r7.11 :. ram...... � l 1' .1 It 75/8x5/: o ■— �n •d o i 1• "�"'` ; ,l �.� low � c. .1� �; ;� Annulus o Multibowl Wellhead,SMB- s I'. I 22,115MX10%SOW,w/ I El i-I1 :FII1. 10%conductor �; packoff installed in head ( � I I 'I 10%" 7 5/8" 5�" i 0 Happy Valley 11 SCHEMATIC Well: HV B-15 As Completed 10/26/12 wk..",114‘sIa.1.IA. Ground Elev:593'Above MSL KB-THF:14.7' v / :.) 10-3/4" CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 10-3/4" Conductor 45.5 L-80 - 9.95 Surf 98' 7-5/8" Prod Casing 29.7 L-80 Buttress 6.875 Surf 1,139' 5-1/2" Prod Liner 17 L-80 VAM STL 4.892 924' 3,056' TUBING DETAIL 5-1/2" Production 17 L-80 VAM STL 4.892 Surf 924' s4, s.; o JEWELRY DETAIL ,-- No. Depth ID OD Item . 1 924' 4.892" -- JMZX Liner Hanger 2 2,507' -- -- Comp Bridge Plug 3 2,745' -- -- Fish:Weatherford Pulling Tool 4 2,750' 4 892" WRP Retrievable Plug w/2.875" OD Fishing neck i l . ,`, PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Feet SPF Date Status e Beluga A 2,360' 2,374' 2,026' 2,036' 14 6 3/13/13 Open ' Beluga C 2,425' 2,432' 2,074' 2,079' 7 6 3/13/13 Open Beluga D 2,467' 2,487' 2,105' 2,120' 20 6 10/26/12 Open Beluga D 2,472' 2,492' 2,109' 2,123' 20 6 12/15/12 Open Beluga E 2,530' 2,535' 2,152' 2,156' 5 6 12/15/12 Isolated Beluga F 2,600' 2,612' 2,205' 2,214' 12 6 12/15/12 Isolated Beluga H 2,812' 2,822' 2,366' 2,373' 10 6 12/15/12 Isolated 44 Beluga I 2,844' 2,848' 2,390' 2,393' 4 6 12/15/12 Isolated 111 7-5/8" 4;- 1 r Beluga A Beluga C Beluga D `.. 2l Beluga D r*-4=` _ =Beluga E Beluga F 4`olititrull Beluga H ,: =Beluga I 5-1/2" Z - -- -, TD=3,069'MD/2,558'ND PBTD:2,898' MD/2,431'ND Updated by DMA 11/24/14 • i R - .,s '$,. 'k, ' 4, • , 0 - r• ,, —•,............,. ,,.., ,,,,,,,,,..„,.............„,„„, ............._ _,„..._,................,__ t. eilm ° 4 k„, v C _,,,„ 1 7c,, Joa.yiak.,..*.m.w,„,,,„,,„,,,,,,,„„,,,,,a,..,,,o0,oioawsowo*o, f '' . .. , ,.,,,,t#,,,,,,,,,,,o__„.._.......„_„.„ ,.f-a '^moi.^ 1 D ..... ,,,,,,...,..,--, ,.„,.... ,. ,.., . , , ,, ..„.„. ..„:„,„,„. „„„,...._.z - ..,:. Nrx,.”,A- i*,'-,*' '-,: , , , , -..Nw.,o.....tra.....„........w., t Nikolaevsk Red#1 wellhead Photo December 9th Casing-casing valve 0 II , Red Pad Red#1 11.1“../.u.,.�,,,.r.ri 01/05/2016 Red Pad Tubing hanger,er,CIW-CXS 11 Red#1 X 3'/:IBT lift and susp,w/3" 16x95/8 x 7x 3''/: type H BPV profile,N"non 1 continuous control line,9 I. EN BHTA,Bowen,3 1/8 5M FE x 2 f Bowen union top ° 1 es, Valve,Swab,CIW-FL, X1 \ L� ��cai a� 3 1/8 5M FE,HWO,AA trim 'a �: 1 $'' O e, 4 0,.. , p 1 7 94 rlyi i I ' /-/C6--- LI..1- .4. Valve,Upper Master,CIW-FL, i_i/ \ 2 :� .j 3 1/8 5M FE,HWO,AA trim .' ',:tom ___;7111 I F.n Valve,Master,CIW-FL, , M 31/8 5M FE,HWO,AA trim •r ��, 7.,),r1 ir t■1 ■I w ''"i"mI =will■ § rim... =_ Casing Spool,Cameron MBS- — upper,115M stdd top and bottom,w/2-2 1/16 5M SSO : III l J—I'L' o),� umi .. 7 x 3'A annulus =m■II■IiIr il11■IEi= Csg head,Cameron MBS- , � Lower,11 5M x T-103 pocket in lei bottom,w/2-2"LPO —..."-- 1111111111.i ' O — 9 5/8 x 7 annulus —. _ua ,C i - Casinn hanger,Surface,B I 1 Cameron,133 5/8/85 x 9 5/8 BTC box bottom x LH acme, w/T-103 neck li I 16" 9 5/8" 7" 3 W' yw��\\I//7,,�� THE STATE AlaskaOil aide Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 sLAg"� Main: 907.279.1433 • Fax: 907.276.7542 www.aogcc.alaska.gov December 21, 2015 CERTIFIED MAIL— RETURN RECEIPT REQUESTED 7015 0640 0006 0779 5876 Mr. Chad Helgeson Kenai Operations Manager Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Re: Docket Number: OTH-15-038 Missing Outer Annulus Pressure Gauges Deep Creek Unit Happy Valley B-14 (PTD 2120540) Deep Creek Unit Happy Valley B-15 (PTD 2121320) Nikolaevsk Red #1 (PTD 2040840) Dear Mr. Helgeson: On October 31, 2015 an Alaska Oil and Gas Conservation Commission (AOGCC) Inspector accompanied by a Hilcorp Alaska LLC (Hilcorp) representative performed well safety valve system inspections at the Happy Valley B-pad and Nikolaevsk pad. Three wells —Happy Valley B-14, Happy Valley B-15 and Nikolaevsk Red #1 were not equipped with pressure gauges to monitor the outer annuli. AOGCC performed follow-up inspections at Red #1 on December 9, 2015 and at Happy Valley B-14 and B-15 on December 12, 2015 to determine if the outer annulus pressure gauge issues were resolved. The three wells were again observed to be missing outer annulus pressure gauges. Regulation 20 AAC 25.200(c) requires wellhead equipment to include appropriate gauges and valves installed in the tubing, casing-tubing (inner) annulus, and casing-casing(outer) annuli. The facts reported by the AOGCC Inspectors indicate a failure to equip Happy Valley B-14, Happy Valley B-15, and Nikolaevsk Red #1 with the required pressure gauges. Within 14 days of receipt of this letter, you are requested to provide for AOGCC review and approval a written plan describing what has been or will be done in the future to prevent its recurrence at Hilcorp- operated fields in Alaska. Included in the requested response should be a list of Hilcorp-operated wells that do not have the required pressure gauges as outlined in 20 AAC 25.200(c), and the timeline for installing the required valves. Failure to comply with this request will be an additional violation. • •• Notice of Violation Docket Number:OTH-15-038 December 21,2015 Page 2 of 2 The AOGCC reserves the right to pursue additional enforcement action in connection with missing outer annulus pressure gauges on the three listed wells. Questions regarding this letter should be directed to Jim Regg at 907-793-1236. Sincerely, Cathy . Foerster Chair, Commissioner cc: AOGCC Inspectors RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a),within 20 days after written notice of the entry of this order or decision,or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed,then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration,upon denial,this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction,in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration,this order or decision does not become final. Rather,the order or decision on reconsideration will be the FINAL order or decision of the AOGCC,and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails,OR 30 days if the AOGCC otherwise distributes,the order or decision on reconsideration. In computing a period of time above,the date of the event or default after which the designated period begins to run is not included in the period;the last day of the period is included,unless it falls on a weekend or state holiday,in which event the period runs until 5:00 p.m.on the next day that does not fall on a weekend or state holiday. Ze 4-004 0 Regg, James B (DOA) From: Herrera, Matthew F (DOA) (I( Sent: Wednesday, December 09, 2015 3:00 PM �� tvf°� To: Regg, James B (DOA) Subject: RE: Red #1 Well Completion Report and Schematic Attachments: IMG_1626.JPG;IMG_1627.1PG;IMG_1628.JPG;IMG_1629.JPG Here are some of the pics From: Regg, James B (DOA) Sent: Wednesday, December 09, 2015 2:14 PM To: Herrera, Matthew F (DOA) Subject: RE: Red #1 Well Completion Report and Schematic Ok;thanks. Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-7934236 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information. The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. From: Herrera, Matthew F (DOA) Sent: Wednesday, December 09, 2015 2:11 PM To: Regg, James B (DOA) Subject: RE: Red #1 Well Completion Report and Schematic I can swing out there and get better pics with a camera if you'd like driving by there Friday. From: Regg, James B (DOA) Sent: Wednesday, December 09, 2015 1:58 PM To: Herrera, Matthew F(DOA) Subject: RE: Red #1 Well Completion Report and Schematic Did you get any pictures? Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 1 • , CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information. The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Jim Regg at 907- 793-1236 or iim.reggPalaska.gov. From: Herrera, Matthew F (DOA) Sent: Wednesday, December 09, 2015 1:36 PM To: Regg, James B (DOA) Subject: RE: Red #1 Well Completion Report and Schematic Well all they have for an OA valve is a Balon 2" Ball valve with no plug or bushing with a gauge.The IA has a standard Gate valve on each side with a Gauge on one side. From: Regg, James B (DOA) Sent: Wednesday, December 09, 2015 1:32 PM To: Herrera, Matthew F (DOA) Subject: Red #1 Well Completion Report and Schematic This is from of our well files. Not a monobore—should be IA and OA annulus valves and gauges. Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information. The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Jim Regg at 907- 793-1236 orjim.regg@alaska.gov. 2 Well Name: Red #1 Field: Wildcat State: Alaska API:50-231-20021 I Conductor: 16" 82.77 f K-55 to 50' AOGCC:204-084 PP' 352'FNL&392'FWL Sec.8,T4S,R13W,SM • Surface Casing:9%",47 ppf,L-80, RT-THF: 17.22' BTC to 1790' Cmnt with 110 bbl of 12.8 ppg lead and Tbg lift threads-3W IBT 45 bbl of 15.8 ppg tail"G" Tree cxn-2W Bowen cxn Intermediate Casing:7",29 ppf,L-80,BTC to 4601' Cmnt with 53 bbl of 12.8 ppg"G"lead Production Tubing:3W,9.2 ppf,L-80,IBT lead and 30 bbl of 15.8 ppg"G"tail. to 4412' , , -Annulus loaded with 7.4 ppg base oil Completion -Chemical injection sidepocket mandrel at 2502' (Macco SFO-IC-I)with 1/4", 0.049"wall SS chemical injection line -Locator sub @4378' -Baker 80-40 seal assembly — 13'of 4.00"OD seals — Open Perfs: -Muleshoe at 4412' T-??:8768'-8777'(6 spf,8/3/04) T-65:8795'-8820'(3 spf,7/23/04) `•`' T-??:9056'-9076'(6 spf,8/3/04) $ Isolated Perfs T-81:9210'-9280'(3 spf,7/19/04) _ T-130: 10565'-10610'(3 spf,7/17/04) Plugs: -EZ-Drill CIBP at 9192'capped — with 40'of cement(7/23/04) -EZ-Drill CIBP at 10420'(7/19/04) Production Liner:3W,9.2 ppf,L-80,IBT liner from 4379' -10,930' Directional Data: Baker ZXP packer,Flexlock liner hanger& max hole angle=29.1 deg , 80-40 sealbore at 4373' KOP=4800' Cemented with 209 bbl of 12.0 ppg max dogleg<3 deg/100' PBTD=9152' Litecrete TD=12,458' Red-1 schematic 8-4-2004 Updated by:JGE • 0166tetev5i6- i<7eetil • Pm zokeito Regg, James B (DOA) From: Regg, James B (DOA) IL'1� 15- Sent: Wednesday, December 09, 2015 1:32 PM f To: Herrera, Matthew F (DOA) Subject: Red #1 Well Completion Report and Schematic Attachments: Red-1 completion rpt and schematic.pdf This is from of our well files. Not a monobore—should be IA and OA annulus valves and gauges. Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC.),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information. The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. 1 ' A • STATE OF ALASKA Eic -, _ . ALASKilk AND GAS CONSERVATION COMMIS EP 0i10 Gas OR RECOMPLETION REPORT AND& , ;J, Status:1a.WeII ❑ ❑ Plugged a ❑ ❑ Suspended❑ WAG❑ 1 b.Well Gass: 20AAC 25.105 20AAC 25.110 Development ❑ Exploratory0 GINJ❑ WINJ❑ WDSPL❑ No,of Completions 1 Other Service ❑ Stratigraphic Test❑ 2.Operator Name: 5.Date Comp.,Susp.,or 12.Permit to Drill Number: Union Oil Company of California Aband.: July 17,2004 204-084 3.Address: 6.Date Spudded: 13.API Number: PO Box 196247,Anchorage,AK 99519-6247 June 9,2004 50-231-20021 4a.Location of Well(Governmental Section): 7.Date TD Reached: 14.Well Name and Number: Surface: 352'FNL,392'FWL,Sec.8,T4S,R13W June 28,2004 Red-01 Top of Productive Horizon: 8.KB Elevation(ft): 15. Field/Pool(s): 1,176 FNL,1,564 FWL,Sec.8,T4S,R13W 895'above MSL Total Depth: 9.Plug Back Depth(MD+TVD): Nikolaevsk Unit/Tyonek 1,616 FNL,2,307 FWL,Sec.8,T4S,R13W 9,152/8,831' 4b.Location of Well(State Base Plane Coordinates): 10.Total Depth(MD+TVD): 16,Property Designation: Surface: X=212,798 Y=2,140,995 12,458/12,047' Red Pad TPI: X=213,934,Y=2,140,130 11.Depth Where SSSV Set: 17.Land Use Permit: Total Depth: X=214,668 Y=2,139,672 n/a n/a 18.Directional Survey: Yes 0 No ❑ 19.Water Depth,if Offshore: 20.Thickness of Permafrost: n/a feet MSL n/a 21.Logs Run: 8.5 Quad Combo,6-1/8 PEX,CMR,DSI,MSCT 22. CASING,LINER AND CEMENTING RECORD CASING WT.PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT. TOP BOTTOM TOP BOTTOM PULLED 16" 82.77 K-55 0 50' 0' 49' n/a Driven 9-5/8" 47 L-80 0 1,790' 0' 1,789' 12-1/4" 110bb1,12.8ppg Iead/45bb1,15.8ppg"G" 7" 29 L-80 0 4,601' 0' 4,600' 8-1/2" 53bbI,12.8ppg Iead/30bbI,15.8ppg"G" 3-1/2" 9.2 L-80 0 10,930 0' 10,551' 6-1/8" 209 bbl of 12.0 ppg Utecrete 23.Perforations open to Production(MD+TVD of Top and Bottom 24. TUBING RECORD Interval,Size and Number;if none,state"none"): SIZE DEPTH SET(MD) PACKER SET(MD) 8768'-8777'(6 spf,8/3/04) 3-1/2",9.2#L-80 4,412' Baker ZXP pkr @ 4,373' 8795'-8820'(3 spf,7/23/04) 4................. 9056'-9076'(6 spf,8/3/04) C I ' ek 25. ACID,FRACTURE,CEMENT SQUEEZE,ETC. dr DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED fr.l IES} 3 26. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): n/a flowing • Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-BbI: Choke Size: Gas-Oil Ratio: 8/4/2004 24 Test Period 0 5777 0 20/64" n/a Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-BbI: Oil Gravity-API(corr): Press. 1985 0 24-Hour Rate 0 5777 0 n/a 27. CORE DATA Brief description of Iithology,porosity,fractures,apparent dips and presence of oil,gas or water(attach separate sheet,if necessary). Submit core chips;if none,state"none". 5736':Ss fg slty; 5792':Ss fg slty; 5814':Ss fg slty; 5826':Ss fg slty; 5854':Ss fg slty spyrt; 6072':Ss f-mg slty; 6138':Ss f-mg vslty; 6334':Ss fg slty; 6390':Ss f-vcg vslty Ig incls; 6564':Ss fg slty thn lams; 6675':Ss fg slty thn lams; 6772':Ss fg slty; 8810':Ss mg slty thk shy lam; 8814':Ss m- cg slty; 8818':Ss m-vcg slty; 9064':Ss fg slty; 9069':Ss fg slty Ig incls; 9214':Ss mg vslty thn org lams; 9238':Ss m-cg vslty Ig incls; 9285':Ss m- cg vslty Ig incls; 9298':Ss fg vslty; 9308':Ss fg vslty; 9413':Ss fg slty scalc;10068':Ss fg slty scalc;10534':Ss fg sit)/scalc;10606':Ss fg slty scalc; 10754':Ss fg slty Ig incl scalc;10768':Ss fg slty scalc;10982':Ss f-vcg scalc;11245':Ss f-cg slty Ig incls;11677':Ss fg slty thn lams;11681':Ss fg slty;11781':Ss fg slty;11785':Ss fg slty scalc;11790':Ss f-mg sltyI •11930':Ss fg slty• 12260':Ss fg calc frac fll; oa IGI dL /� Form 10-407 Revised 12/2003 CONTINUED ON REVERSE RBDMS B . NQVLI 6 7UO4' & r28. GEOLOGIC MARKERS 1111 29. MATION TESTS NAME _ TVD Include and briefly nze test results. List intervals tested,and attach detailed supporting dalJlas necessary. If no tests were conducted,state Tyonek 5,633 5,613 "None". T20 7,231 7,036 Testing operations summarized in daily operations reports(attached). T25 7,560 7,333 T35 7,711 7,472 T50 8,119 7,851 T40 8,234 7,959 T63 TOP 8,614 8,320 T63 BOS 8,625 8,330 T65 TOP 8,798 8,494 T65 BOS 8,818 8,513 T70 TOP 9,047 8,731 T70 BOS 9,075 8,758 t: ; OA T81 TOP 9,210 8,886 30. List of Attachments: Directional Survey,Schematic,Summary of Daily Operations 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Rob Stinson 907-263-7804 Printed Name: Tim C.Brandenburg Title: Drilling Manager �R l 9 Signature: C. j` Phone: 907-276-7600 Date: ^L7 ,41 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1 a: Classification of Service wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection,Observation,or Other.Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI(Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,showing the data pertinent to such interval). Item 26: Method of Operation: Flowing,Gas Lift,Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other (explain). Item 27: If no cores taken,indicate"none". Item 29: List all test information. If none,state"None". CONFIDENTIAL Form 10-407 Revised 12/2003 • • • Well Name: Red #1 Field: Wildcat UNOCAL.p State: Alaska APL 50-231-20021 I ` Conductor: 16",82.77 ppf,K-55 to AOGCC:204-084 50' 352'FNL&392'FWL Sec.8,T4S,R13W,SM Surface Casing:9W,47 ppf,L-80, BTC to 1790' RT-THF:17.22' Cmnt with 110 bbl of 12.8 ppg lead and 45 bbl of 15.8 ppg tail"G" Tbg lift threads-3Y2"IBT Tree cxn-2W Bowen cxn Intermediate Casino:7",29 ppf,L-80,BTC to 4601' Cmnt with 53 bbl of 12.8 ppg"G"lead Production Tubing:3W,9.2 ppf,L-80,IBT g g , lead and 30 bbl of 15.8 ppg"G"tail. to 4412' 1116. -Annulus loaded with 7.4 ppg base oil Completion -Chemical injection sidepocket mandrel at 2502' (Macco SFO-IC-I)with 1/4", 0.049"wall SS chemical injection line -Locator sub X4378' — -Baker 80-40 seal assembly ..- Open Perfs: 13'of 4.00"OD seals T-??:8768'-8777'(6 spf,8/3/04) -Muleshoe at 4412' T-65:8795'-8820'(3 spf,7/23/04) T-??:9056'-9076'(6 spf,8/3/04) Isolated Perfs T-81:9210'-9280'(3 spf,7/19/04) Plugs: _ T-130:10565'-10610'(3 spf,7/17/04) -EZ-Drill CIBP at 9192'capped — with 40'of cement(7/23/04) -EZ-Drill CIBP at 10420'(7/19/04) Production Liner:314",9.2 ppf,L-80,IBT liner from 4379' -10,930' Directional Data: Baker ZXP packer,Flexlock liner hanger& max hole angle=29.1 deg A 16. 80-40 sealbore at 4373' KOP=4800' PBTD=9152' Cemented with 209 bbl of 12.0 ppg max dogleg<3 deg/100' TD=12,458' Litecrete Red-1 schematic 8-4-2004 CONFiDENTIAL Updated by:JGE • • , i • a. y 6.O O 0 L70.ri t IjI(42 ti 0 OA t. ;to 0 . a LCC/gr C' 01) L ca ? e y d o ti z z G .4 C C7 O O c, CA4-4 ; O. N cua e t I= N V L at, 4 v I�//�� a h 0 VI ., .L � h2, E d .--i 4) w ti ° w 3 5-1 0 L" 1 yvo O Cl) s °~ o LA 74 (1) t ca0w C,4>-, C7 r—'+ L) . — (I) :o a °o E• x A rtL cn V > 7,3 Ov Lz CZt O. ca fl O Q U P. C42 ''117" n Ct w ci) CZ cv O. h FC.r 6v) d 0 P. O rte. cn ti' O O {Qif E L p8p N Ooi .•� V 7 0 .'�. o V) 4z N w .. U U o E a ° 44 el a c Z z - I _ s z .5 a, .... v 3 • • Regg, James B (DOA) From: Jones, Jeffery B (DOA) / Sent: Saturday, December 12, 2015 11:36 AM ``ef I 7-114r/r To: Regg, James B (DOA) III Subject: HV-14, HV-15 OA gauges Attachments: IMAG0096jpg;IMAG0095jpg Jim, tf, "1" I checked &there were no OA gauges on Happy Valley HV-14 & 15. HV-14 cellar was full of snow/ice so I couldn't really see below the IA. The cellar gratings were frozen down & we couldn't get them up. It was dark & with the flash against the grating, the pictures didn't turn out well. It was the middle of the night & couldn't find an operator on either A or B pad so I told Hilcorp Saxon 169 WSL Shane Barber to get with operations & get the cellar cleaned out on HV-14 & install OA gauges on both wells. Jeff Jones AOGCC Petroleum Inspector 907 659 2714 - Office 907 744 4446 - Mobile 1 • S aa 4 • 3 a 8 Id d v ez g a; (-) rn V 1c ou 0a y H i40 h 01 1� At E N y .r..d OG O z z z z hL V/ Ov. J C0000 y AJ 4') d Z z z Z ) +4 C7 O O 00 CA a a • 44 z• a F d U aL y e 0 3 N a o 0 C s. g:11C Q v........4U ¢ ; 3� � a o CI) 4 ° yH� zzzz — a vi 4i Cr.t a6 E U a. a a. a .. 0 co„LN in 44 Ea O Cs, 0.. w a bn N C U P. V/ Ls. M O� M M ("• Vl N N M �� O O T^ ^ 0 c. O O Vl O v la . a. l0 M M -.1- O. H 1.1 Q.V) O O O O CO I W CA,.• Li = V O O O O O.N„ e .: p U . N • W i a z O O N N 0 1 W O ti CZ a) -it ise S V X E '= L A t d <>1; U CI ca Z o e V .a z ch ca as ca 7.4 et a w 3 DATA LOGGED STATE OF ALASKA ' A NI%2o11 ALP1PA OIL AND GAS CONSERVATION COM SION M.K.BENDER REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon Li Plug Perforations U Fracture Stimulate U Pull Tubing U Operations shutdown U Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Coil Clean Out Q 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑ Exploratory ❑✓ 204-084 3.Address: 3800 Centerpoint Dr,Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6.API Number: AK 99503 50-231-20021-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0390514 Red 1 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Nikolaevsk/Tyonek Undefined Gas 11. Present Well Condition Summary: 9,025'; E C E I V E Total Depth measured 12,458 feet Plugs measured 9,192; 10,420 feet •w true vertical 12,047 feet Junk measured N/A feet APR 1 9 2017 Effective Depth measured 9,011 feet Packer measured 4,373 feet al nGCC true vertical 8,697 feet true vertical 4,372 fee Casing Length Size MD TVD Burst Collapse Structural Conductor 50' 16" 50' 49' Surface 1,790' 9-5/8" 1,790' 1,789' 6,870psi 4,760psi Intermediate 4,601' 7" 4,601' 4,600' 8,160psi 7,020psi Production 10,930' 3-1/2" 10,930' 10,551' 10,160psi 10,540psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic SCANNED MAY 0 9 2417, Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.2#I L-80 4,412'MD 4,412'TVD Seal Assembly Packers and SSSV(type,measured and true vertical depth) in Baker ZXP Pkr; N/A 4,373'MD 4,373'TVD N/A;N/A 12.Stimulation or cement squeeze summary: Intervals treated(measured): Fracture stimulated 8768'-8777'and 8795'-8820',with 58,791 gallons of fluid and 122,585 lbs.of proppant. ISIP=2,051 psi Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 237 9 0 286 Subsequent to operation: 0 1671 155 0 780 14.Attachments(required per 20 AAc 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑� W \� Exploratory❑✓ Development Service ❑ Stratigraphic 01Copies of Logs and Surveys Run IIIik`ti�O 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ Printed and Electronic Fracture Stimulation Data LI GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 317-058 Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkrameranhilcorp.com Authorized Signature: �W4 Date: Contact Phone: 777-8420 GDW 412.'Il7Y z�-� 6 ,t Form 10-404 Revised 4/2017 G/o4/17 RBDMS L vAPR 1 9 2U 17 Submit Original Only • • *� r 571 HilcorpAlaska, LLC � r Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Red 1 E-Line 50-231-20021-00 204-084 3/8/17 3/23/17 Daily Operations: 03/08/2017-Wednesday PJSM, MIRU Halliburton EL. Test lubricator 2,500psi, good test. RIH w/2.85" GR to 8,700'. POOH. PU/MU 2.80" RBP and ,(�"i! set @ 8,600' (middle ofjt). POOH. Fluid at 7,325'. RDMO EL. SITP 2,000psi, bled off tbg to Opsi. MIRU Pollard pump i truck. Pumped 65 bbls of 3% KCL and 3 bbls of methanol. Pressured up on tbg to 5,000psi, charted and held for _ 30mins, good test. Bled off tbg. Hooked pump line to IA and pressured up to 3,500psi, charted and held for 30mins, good test. Bled off pressure. RDMO Pollard pump truck. 03/09/2017 -Thursday PJSM, MIRU Halliburton SL. RIH w/equalizing prong and tagged plug @ 8,600'. Monitored well on vac. POOH. RIH w/GS pulling tool and latched RBP @ 8,600'. POOH and L/D RBP. RDMO SL, j1. 03/10/2017- Friday Built containment and spotted frac tanks. 03/13/2017 - Monday Continue filling frac tanks. 03/14/2017 -Tuesday Continued filling frac tanks. Hooked up 2 glycol heaters to heat frac water. Built containment for tanks and fuel cell. 03/15/2017 -Wednesday Continued filling frac tanks and preparing pad for Red 1 frac. 03/16/2017-Thursday PJSM, MIRU Cruz 25Ton crane, installed stingers tree saver. Scoped and tested good. Continued heating frac tanks. Offloaded flowback equipment from KGF. '('-`1' ;'•.L-- 03/17/2017 - Friday PJSM, continued heating water w/Pollard. Laid containment for frac equipment. Hauled sand from KGF to and staged at Greystone pad. 03/18/2017-Saturday MIRU SLB frac equipment, hooked up circulating lines filled sand king with 110,000 lbs. of RCR-LT 20/40 sand. Hooked up flowback iron from IA to the opentop tank with POV set @ 3,400psi. 03/19/2017 -Sunday Warmed and fueled heaters. Stopped Pollard hot oil truck to heat tanks. Waited on frac crew to arrive. Frac crew on location. Set the GORY. Finished hooking up bled off lines. Performed per job fluid test. Warmed up equipment. Fill hopper with 3,000Ibs of 100 mesh. PT lines to 9,500psi, good test. Held PJSM, performed DFIT test as designed. Fraced iw Red 1 per design as follows: ATP: 3,749pssiMTP 6,328psi, ATR 22.6bpm, MTR 25.4bpm1 total propant 2,879Ibs of 100mesh and 120,604Ibs of 20/40 RC,total of 123,604Ibs of proppant pumped. ISIP 2,051psi, 5min 1,901psi, 10min 1,864psi, 15min 1,839psi. SI Well. Flushed and blew down treating lines. RD 4" stand pipe, secured well and SDFN. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Red 1 E-Line 50-231-20021-00 204-084 3/8/17 3/23/17 Daily Operations: 03/20/2017 - Monday Rig Down Stinger Wellhead tree saver. SLB Frac crew on location. RDMO. Pollard S/L on location. RU PT lubricator 250/3000 psi. RIH with 2.5" dump bailer to 5400' RIH rate slowed down. Only able to drop down 20 ft/min. Continued to 6040' Talked about bad spang action. Decided to POOH and add more weight stem and attempt a run with 2.0" Bailer. (thick fluid possibly x-link gel) At surface. Break down BHA. MU 2" dump bailer . RIH to 5400' wlm thick fluid falling slowly. Lost weight at 8403' Picked up and attempted to make hole. POOH to surface. Continue POOH. At surface. Pop off Bailer had a cup of frac sand and some gel. Rig down Pollard. Location secure. 03/21/2017 -Tuesday Empty frac tanks and continue mixing up 3% KCL. Fill coil tank. Weaver Bros on location to move last two frac trailers. SLB CTU 12 on location. Rigging up. Start BOPE test. Test witness notification sent to state on 3/20/17 @ 14:27. Witness waived by Michael Quick 3/20/17 @ 16:23. Draw down test. Test all rams and valves to 250 psi low 4,500 psi �1" high. Good BOPE test. Shut down equipment. Location secure. 03/22/2017 -Wednesday Fire equipment. Hold safety meeting. Pick inj head. Stab 10' lubricator. Make up BHA. 1.75" CC. Pull test 25K. 1.75" DFCV, 2x 1.75" WT bar, 2.125" down jet nozzle. Stab on well. PT stack to 250/4,500 psi. Open well. 0 psi WHP.Tag _top of frac sand at 8,383'. Pick up clean. Come online at 1.6 bbls/min with 3 % KCL. Clean out to 9,100'. Returns started as gel and then frac sand. 287 bbls pumped for FCO. Online with N2 at 1,000 scf/min with CT at 8,700'. RIH and tag at 9,113'. Blow well dry. 78.5 bbls returned. Shut down N2. Pick up to 8,700'. 670 psi WHP. WHP starting to drop from 670 pis. Still unloading fluid. No signs of frac sand. WHp 40 psi. No signs of gas. Online with N2 500 scf/min. CT @ 9,014'. Unload for 30 minutes. Down on N2. Let well unload. 40 bbls returned. Online 9,100', 500 scf/min. 180 psi WHP. 10 % LEL/Gas. Shut down N2. 30% LEL/Gas. 15 bbls returned. 9,100' online 500 scf/min. Shut down after 30 minutes. Wait 30 minutes. WHP 580 psi. Dropped to 160 psi. 20 bbls returned. Online 500 scf/min. 141 psi WHP. 1,293 scf circ pressure. Shut down, 15 bbls returned. 60 % LEL/Gas. Let well unload. Start POOH. POOH to surface. Tag up. Shut in well 100 psi. SITP. Last gas reading 90 % Lel/Gas. 23 bbls unloaded while POOH. Total unloaded from wellbore 191 bbls. Pop off well. Break down tools. Install night cap. SDFN. o • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Red 1 E-Line 50-231-20021-00 204-084 3/8/17 3/23/17 Daily Operations: 03/23/2017 -Thursday Fire equipment. Hold safety meeting. Check WHP. 2,260 psi. Talk with town. Decision to flow well to test separator. Production crew en-route to location. Flow test well. 2,261 psi after two hours. WHP down to 860 psi. No water recovered. Tubing volume bleeding down. Pick inj head. Stab 10' lubricator. Make up wash out nozzle/down jet. Stab on well. PT stack 250/4,500 psi. Bleed down to 900 psi. Open master swab valve. RIH with choke cracked. At 2,500' start cooling down N2. 6000' online N2 1,000 scf/min. Tag 9,011'. Drop rate to 500 scf/min. 822 psi WHP. After on bottom for 1 hr 79 bbls were returned to surface. After the 79 bbls fluid returns continue but at a lower rate. 26 more bbls were returned to surface to make a total of 105 bbls of water for the day. Start POOH while still pumping 500 scf/min WHP 687 psi. Shut down N2 at 5,000'. Pinch in choke to be able to flow down flow line once at surface with CT. Tagged up. Swab closed. Start flowing to gas buster. Rack back CT injector head. Reports from production operator flowing to flow line at 862 psi and 1.3 mcfd. CT SDFN. Location secure. 105 bbls returned. 153,000 SCF N2 pumped. • • Well Name: Red #1 SCHEMATIC Field: Nikolaevsk State: Alaska API:50-231-20021 Conductor: 16",82.77 ppf, K-55 to AOGCC:204-084 50' 352'FNL&392'FWL Sec.8,T4S,R13W,SM Surface Casing:9%',47 ppf, L-80, BTC to 1790' RT-THF: 17.22' Cmnt with 110 bbl of 12.8 ppg lead and Tbg lift threads-3%"IBT 45 bbl of 15.8 ppg tail"G" Tree cxn-2%"Bowen cxn Intermediate Casing:7",29 ppf,L-80, BTC to 4601' Cmnt with 53 bbl of 12.8 ppg"G"lead lead and 30 bbl of 15.8 ppg"G"tail. Production Tubing:3'/2',9.2 ppf, L-80, IBT to 4412' -Annulus loaded with 7.4 ppg base oil Completion -Chemical injection sidepocket mandrel at 2502' (Macco SFO-IC-I)with 1/4", Open Perfs: 0.049"wall SS chemical injection line T-80:8768'-8777'(6 spf,8/3/04) -Locator sub @4378' T-80:8795'-8820'(3 spf,7/23/04) -Baker 80-40 seal assembly T-80:8800'-8820'(5 spf, 11/11/16) _ - 13'of 4.00"OD seals Isolated Perfs LE- T-90:9056'-9076'(6 spf,8/3/04) T-100:9210'-9280'(3 spf,7/19/04) X Production Liner:3'/2',9.2 ppf, L-80, IBT G-1: 10565'-10610'(3 spf,7/17/04) _ liner from 4379' 10,930' Baker ZXP packer, Flexlock liner hanger& 80-40 sealbore at 4373' Cemented with 209 bbl of 12.0 ppg 5Z Litecrete Plugs: -Halliburton CIBP @ 9025'capped with 14'of cement(5/19/11) -EZ-Drill CIBP at 9192'capped with 40'of cement(7/23/04) -EZ-Drill CIBP at 10420'(7/19/04) Directional Data: max hole angle=29.1 deg , , KOP=4800' max dogleg<3 deg/100' PBTD=9152' TD= 12,458' 3/29/2017 Updated by DMA • • Schlumberger Client:Hilcorp Well:Red#1 Formation:Nikolaevsk District:Prudhoe Bay Country:United States Section 3: Red-1 Frac 1, Propped Frac: As Measured Pump Schedule As Measured Pump Schedule Slurry Slurry Pump Fluid Max Prop Prop Step Step Volume Rate Time Fluid Name Volume Proppant Name Prop Conc Mass # Name (bbl) (bbl/min) (min) (gal) (PPA) (PPA) (Ib) 1 PAD 285.7 23.7 14.1 YF125FIexD 12089 0 0 0 2 0.5 PPA 48.7 25 2 YF125FIexD 2019 100 Mesh Sand 0.8 0.3 900 3 PAD 261 25 10.4 YF125FIexD 10915 0.5 0 0 4 1.0 PPA 26.1 25 1 YF125FIexD 1047 100 Mesh Sand 1.2 0 961 5 1.0 PPA 100.5 25 4 YF125FIexD 4026 CarboBOND Lite 20/40 1.2 0.8 4083 6 2.0 PPA 104.2 25 4.2 YF125FIexD 4037 CarboBOND Lite 20/40 2 1.8 7847 7 3.0 PPA 135.8 25 5.4 YF125FIexD 5052 CarboBOND Lite 20/40 3.1 1.1 14974 8 4.0 PPA 141.4 25 5.6 YF125FIexD 5066 CarboBOND Lite 20/40 4.2 1.6 20036 9 5.0 PPA 147 25 5.9 YF125FIexD 5081 CarboBOND Lite 20/40 5.1 3.9 25186 10 6.0 PPA 106.8 25 4.3 YF125FIexD 3545 CarboBOND Lite 20/40 6.2 1.3 21120 11 8.0 PPA 117.7 24.9 4.7 YF125FIexD 3769 CarboBOND Lite 20/40 8.1 0 27479 12 Flush 37 24.7 1.5 WF125 1548 0 0 0 13 Flush 35 12.3 3.2 Freeze Protect 1470 0 0 0 Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step# Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 PAD 23.7 25.2 3839 4692 131 2 0.5 PPA 25.0 25.0 3914 3928 3894 3 PAD 25.0 25.0 3990 4033 3927 4 1.0 PPA 25.0 25.0 4002 4011 3992 5 1.0 PPA 25.0 25.1 3929 4018 3853 6 2.0 PPA 25.0 25.1 3778 3855 3716 . __ 7 3.0 PPA 25.0 25.1 3636 3718 3593 _ 8 4.0 PPA 25.0 25.1 3606 3631 3565 9 5.0 PPA 25.0 25.1 3678 3757 3617 10 6.0 PPA 25.0 25.0 3788 3855 3752 11 8.0 PPA 24.9 25.0 3956 4289 3799 12 Flush 24.7 25.2 4254 4373 3473 13 Flush 12.3 25.2 1780 5265 12 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (lb) 1546.9 75.1 58791 122585 • Schlumberger Client:Hi!core Well.Red r Formation:Nikolaevsk District:Prudhoe Bay Country:United States Average Treating Pressure: 3714 psi Maximum Treating Pressure: 5265 psi Minimum Treating Pressure: 12 psi Average Injection Rate: 24.0 bhl/min Maximum Injection Rate: 25.2 bbl/min Average Horsepower: 2250.5 hhp Maximum Horsepower: 3222.4 hhp Maximum Prop Concentration: 8.1 PPA . • • Zit m • CVE « \03 E 06 E o › © g :1- 11.1 � a_ = ocx = a)0 §Eeg ± / a ./ � / \ . e 2 II \ d _ 4, \W | % \ /Q @ } E e f e E 0 E Q tom 'k@oe * »� ƒ I / 7/ / \ o u_ o E CU.... IuI 8 \ \ / \ / � � \ ) C 61) N- - % . % C @ .» 2 % CO / 0 j \ 0 0 N- / / / / / 0)n CL \ \ G ° G u m / / c r e m c 7 E a G & f 9 co- E f o / ® / % \ � O / / ® / \ 2 \ �/ \ % 7 GCr) F Q CO§ \ \ \ = G ƒ TS © O $ CL E o 73 o47. / 2 0 3 2 . . 0. z m Cr) . . . . o . . « z o ) / a m m e = _ ^ _ _ _ •= 0 0 u) E \ 7 3 / > \ O CD \ _/ / / t = ® \ % Z 7 \ O \ % 0 ° / � = E E _ _ _ U a $ Z 0 5 \ [ c CO 9 2 ® = J \ 7 \ G e e k E \ / LL \ k J / / ® \ 0 m @ o E m $ = u = z / \ z ut E 2 % / \ g co " I / 7 13 / / 2 = H- H 2 \ \ . ' 0 I o o \ \ / \ \ / $ $ 3 3 $ 5 a $ m m m m m m m in 7 7 7 7 7 7 7 2 g « f g « g « « 5 2 2 2 2 2 2 2 f \ a) T2-Ea < } 0 a) g \ \ \ - CD sa. < _ > - / \ © 4 2 / __ m = m a. \ 0 < < 0 b G 6 ¥ G 6 b 6 G E e e e e e e e e ± 2 ± 2 ± ± ± ± ± E E E E E E E E E D D g 2 g 3 2 3 D o 0 0 0 0 0 0 £ 0 m e @ m m m m m @ 0 o CO LO / \ \ < R E 3 E / \ 3 10 \ g k 0 • • O O) O Lc) 0) O N N O) — in in M LC) CO N LO N- O O CO O) N CO LC) CO CO d" CO Ln CO N CO Cfl d' 0) N CO O - - CO CO CC) d- O O CO CO CO LO N N N N O O O O O O O O O O O O O O O O O O O O O Ln N- O N- CO O N- Lc) - CO CO O N- N CO O O CO V Cr) t N CO CO 00 M CO O O O V O) r r CO 6) N N CO O) CO co co co N- CO LO LC) " V' N CO CO t CO CO N O O O O Ln N- - c- O O O O O O O O O O CO u) N- V' 00 CO CO O O O d. O c-- co Q) a) O a O o0 Ln O N N m m 00 CO CD Cf) O CO CO rf O N D 0 -p C CO N CO CO N CO Lf) N CO CO CD a) Cl.) O O CO O CO Ln 6) N- co i M 6) CO 00 O O CO r N oo N- CO O J J J -O '� CD O O r N- r CO r M O r LO > CD O) 0) CO CO CO N. CO CO CO N �i .0 -o E Q) r 0 a) 0 = a) C n Cn c0 If ._ >,M c0 T O a)C . O >+ c0— (6 — Z a) a) p O CD a0 (B N - .0 C Z C a) C ° ( 'U N 7 L C >, • E II X lin' ® o U cU oooj N 73 coCO vi a) >, as E —! c6 2 2 w c4 >, a1 o c4 • -C 2 E o O O >, 7 Q- O o ->, O C a) c6 .0 7 L E -E 'O co N O ca N 0 0 _c so 2 o C C - O C� O 3 d C� N 1E o LL 2 L'� co a o Q cn W N d Q 6 > 0 0 H a) J as Um L O O U J > C o --- O 0 - QN LL < X ID a) a`) a) s a) a) ID f N cn E E E D D m - E Z o O I as o o N I) O Ln O m W • I co co LO O '.,Y V' Lf) U) co M Cfl LC) _O O) L.() V' CO I,- N- 'V CO CO CO co co O co co co O O O I— N- CO O O O 0 O O O O O 0 O O r O O 0 O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O N cn c0 I` co O O O CO N- LO N CO (.0N Nt V LO 0) - = U) Cr) CO 0) LO CO Lo N- LO O O) O 0) CO to LO CO N r O C 2 N Lf) = O O O) CO CO N r r O O O O O O O O a Cfl V' V N O O O O O O O O O O O O O O 2 Y O O O O O O O O O O O O O O O O O O O Cr) Mu O O O O O O O O O O O O O O O O O O O r Ns > m o as s 0 O >, N N 7 N O O U) Ws L.0 co co co co V O N 3.ris > c i r "a a: N 'V' 6) 6) O M O COM O CO N O a C -o ca CO O CO CO CO CO O) CO Ln CD V CD V r U 3 .5 N- a) ' N r M N 00 r g N co co 11) In O o0 N Co > 0 O w O CO CO N r LO Nt r O I— r Cfl N O LO N co M - o_ O r CO O O N CO CO CO CO O LO LO CO N- NC ' o c._ CO CO CO Ln Cfl V' O CO N O N 0) Cfl N '�' t a U Q ✓ r CO N r 0) r N- r — N I— 0) r Lf) N r r CO co c 7 o= O COo0 0 C E C @ O O L O O 3 c, CD CO OWN CIS U O a) C. 'O w � L @•c a• o a) aa)i '� o a c o a� ca D -0 0 3 E m X _0 O - C O a) — a--, O c 2 6 p O- .T O O 2 N 'N 'C UQ fl-m o o a) 'O N O O = U C co 0 >, 0 a" 03 L �- @ (O r >,LLJ c00 U @ N j j N j N C E 0 0 >' T (O C) (O 'O U 'u3 N o O in i 01 >, CO MO (O 3 0 x 7 _� p C o x c0 C U C CO C O C (00 O 75 O U 2 o 0 'O o N T >, MO O U c C Q cm 0) _c -c t� A u) 0• ,--2- o o O a) -c o -c L O MO (O 7 O E c0 (O U p (O O _� 7 c U N .L U o>> C3 0 n U) (n 0 0 a) 0- O _c ai Li O o r z Ln .N o 0 0 N o < w 0 < E 3 cn Q C) C �-0 O ma CL• m c O 03 LL O CD w. o C6 2 c 3 c o 3 0 O U D1 N c U N O.• OU N .0 cc w`O"O mLL N w 0 (3 O._ o O. o a) a • Q� O () N y U >,X @7 N a m CO U E E U Q E (i) 0 2- Q C L N U f0 7 C- O O OA Q 0 N N'C 7,-5 O 9 7 6 U TD ci)U E >'-- U a ,O C 5 O E C @.r N LL._ Ea Lict E O > "O O c V- O N H—. 0 0) . . « z- • • Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Thursday, March 09,2017 3:06 PM To: Ted Kramer Cc: Donna Ambruz; 'Gunther Rutzinger' (grutzinger@slb.com);Wade Hudgens- (C) Subject: RE: Pressure Changes to the Red#1 Frac Procedure Section#12 PTD#204-084, Sundry#317-058 Ted, Approval granted to modify treating pressures as presented below(generally lower than previously proposed). Update the MOC as needed.The tubing was already tested to 5000 psi(limited by wellhead)as we discussed yesterday by setting a retrievable plug just above the perfs. Guy Schwartz Sr. Petroleum Engineer SCANNED MAR 1 42017 AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-U26) or(Guy.schwartz@alaska.gov). From:Ted Kramer[mailto:tkramer@hilcorp.com] Sent:Thursday, March 09,2017 11:59 AM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Cc: Donna Ambruz<dambruz@hilcorp.com>; 'Gunther Rutzinger' (grutzinger@slb.com)<grutzinger@slb.com>; Wade Hudgens-(C)<whudgens@hilcorp.com> Subject: Pressure Changes to the Red#1 Frac Procedure Section#12 PTD#204-084,Sundry#317-058 Guy, A pre-Frac meeting was held this past Tuesday with Hilcorp,our Frac Consultant(Dan Ryan),Wade Hudgens(Hilcorp on site Supervisor)and our Vendor—Schlumberger. One of the topics we refined during this meeting was the pressure limits and settings for the job. As a result,the pressures listed in Section 12 of the Sundry have changed somewhat. Most went down, but one(the back side pop off)did go up. I wanted to show this to AOGCC in order to keep all apprised of the limits on this job. I have attached a word document which contains two copies of Section 12 from the Sundry. The first copy is of Section 12 as it appears in Approved Sundry#317-058. The second copy shows the changes in pressure settings of the equipment. The pressure changes have been color coded by font color(Blue if the pressure decreased from what is in the Approved Sundry and Red if the pressure increased from what is in the Approved Sundry). As previously discussed,the pressure setting of the Annular Pressure Relief Valve(PRV) has been increased from 3,300 psi to 3,400 psi. This change was made in order to provide more room for adjusting the pressure on the backside. It is still our intention to hold 3,000 psi on the backside during the job. Please let me know if you have any stions or concerns. • Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 2 0'4-- • 4--• (-Il Section 12—Proposed Hydraulic Fracturing Program 20 AAC 25.283(a)(12) All information required in this section is included below. 17,1 f Proposed Hydraulic Fracturing Procedure: wl p -'' ' 1.) Perform Pressure test on casing.Test to 3,500 psig for 30 min. Fc:.'. 2.) MIRU frac fleet. MIRU frac and slop tanks. MIRU CTU and associated equipment. Stump test CT BOPE, if possible. Isolate from Frac flow path. MIRU all ancillary support equipment. .?,c.` a. Provide 24-hr notice to AOGCC if BOP is tested and connected for witness. i--0 3.) Fill frac tanks with fresh water. Heat water as needed. 4.) Lay all hardlines and manifolds. Install pressure monitoring equipment on wellhead and tree. 5.) RU 15K tree Saver and hard line. 6.) Pressure test all high pressure treating lines to 9,200 psi (maximum anticipated surface pressure is 8,800 psig.See Figure 6 on Page 9 of the Fracture Modeling Study by Frac Diagnostics). 7.) Set the GORV(gas operated relief valve) at±7,900 psi. Set the staggered pump kickouts between 7,600 psi and 7,700 psi. 8.) Pressurize annulus to 3,000 psi. Set annular PRV(pressure relief valve)at 3,400psi. 9.) Prepare frac fleet to pump. 10.)Pump DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. 11.)Fracture stimulate interval with 100 mesh and Carbo Bond Lite 20/40 proppant in cross-linked gel. See "Proposed Treatment Schedule"for proposed design. 12.) Shut well in. RDMO. *Refer to section 13 of this application for the post stimulation procedure. Table of Pressures Maximum Predicted Treating Pressure 8,800 psi Maximum Planned Rate 25 BPM Maximum Planned Sand Concentration 8 ppa Annulus Pressure 3,000 psi Maximum Allowed Working Pressure 7,900 psi Nitrogen GORV 7,900 psi Highest Pump Trip 7,700 psi Annular PRV 3,400 psi • S Section 12—Proposed Hydraulic Fracturing Program 20 AAC 25.283(a)(12) All information required in this section is included below. �� Proposed Hydraulic Fracturing Procedure: — j..12/c, 1.) Perform Pressure test on casing.Test to 3,500 psig for 30 min. ?.) MIRU frac fleet. MIRU frac and slop tanks. MIRtt CTU aru associated equipment. Stump test CT BOP[,if possible,Isolate from Frac flow path. MIRU a fincillary support equipment. a. Provide 24-hr notice to AOGCC if ROP is tested and connected for witness. 3.) Fill frac tanks with fresh water. Heat water asineeded. 4.) Lay all hardlines and manifolds. Install pressure monitoring equipment on wellhead and tree. 5.) RU 15K tree Saver and hard line. 6.) Pressure test all high pressure treating lines to 10,000 psi(maximum anticpated surface pressure is 8,800psig.See Figure 6 on Page"9 of the Fracture Modeling Study by Frac Diagnostics). 7.) Set the GORV(gas operated r,e1ief valve)at±8,800 psi. Set the staggered pump kickouts between 8,500 psi and 7,520 psi. 8.) Pressurize annulus to 3, '0 psi. Set annular PRV(pressure relief valve)at 3,300 psi. 9.) Prepare frac fleet to imp. 10.)Pump DFIT and an yze the results to obtain fluid loss coefficients. Adjust frac design. 11.)Fracture stimulate interval with 100 mesh and Carbo Bond Lite 20/40 proppant in cross-linked gel. See"Propose Treatment Schedule"for proposed design. 12.)Shut well' . RDMO. *Refer to sepfion 13 of this application for the post stimulation procedure. OF 7'4, 4)**8 I�y, 4. THE STATE Alaska Oil and Gas of® LAsKA Conservation Commission _ 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OF * jpir ^+'mnTM e. Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager r ': , 22;Z/ Hilcorp Alaska, LLC SCANNED 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: Nikolaevsk Field, Tyonek Undefined Gas Pool, Red 1,: _. Permit to Drill Number: 204-084 Sundry Number: 317-058 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, / Cathy ' Foerster Chair DATED this'28 day of February, 2017. RBDMS t,L, !,:f - 1 2017 RECEIVED STATE OF ALASKA FR1 U 1Z21aiP 1[7 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AGC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate 0' Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Coil Clean Out 0• 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number: Exploratory Q • Development ❑ 204-084 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic IllService ❑ 6.API Number: Anchorage,Alaska 99503 50-231-20021-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 20 AAC 25.055(a) Will planned perforations require a spacing exception? Yes ❑ No 2Red 1 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0390514 • Nikolaevsk/Tyonek Undefined Gas ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): 9,025'; Junk(MD): 12,458' . 12,047' ' 9,011' 8,697' 8,800 psi 9,192';10,420' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 50' 16" 50' 49' Surface 1,790' 9-5/8" 1,790' 1,789' 6,870psi 4,760psi Intermediate 4,601' 7" 4,601' 4,600' 8,160psi 7,020psi Production 10,930' 3-1/2" 10,930' 10,551' 10,160psi 10,540psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.2#/L-80 4,412' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Seal Assembly in Baker ZXP Pkr;N/A 4,373'MD/4,372'ND;N/A 12.Attachments: Proposal Summary 0 Wellbore schematic U 13.Well Class after proposed work: Detailed Operations Program ❑., BOP Sketch ❑ Exploratory ❑Q • Stratigraphic❑ Development❑ Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: February 20,2017 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑✓ • WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Ted Kramer-777-8420 Email tkramert hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature t...,1-7r ' - Phone 907-777-8405 Date Z/j/( 7 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: e� 3‘---/ -Ow Plug Integrity ❑ BOP Test [ Mechanical Integrity Test Ill Location Clearance CI c- 2-I7.-q 0 Other: # r cra--,--C : o'•-,.. Z.-e>/44-c- ZS'.Z g'3 C Z IC 1) ;.0...) i AP- rete, 5`f-rit pv^C �- •4•t-g E'' p— Zo . ,11-. j, e £y (2) Post Initial Injection MIT Req'd? Yes ❑ No ❑ - ti C 2 p7•- 0(5 fr - CC r) Spacing Exception Required? Yes ❑ No j Subsequent Form Required: /®'`SQL f RBDMS 1,<- r.1, - 1 2017 P / APPROVED BY Approved by: ,. hs,..41,11.0.N... COMMISSIONER THE COMMISSION Date: —2,8 -/7 -zf�� RINGamtAteid SubmitForm and Form 10 403' aZ vised 11/2015015 for 12 months from the date of approval. Attachmentssin Duplicate OW 2114-rl.i'7 = `-. 2 - <.7 Hilcorp Alaska, LLC RECEIVED Post Office Box 244027 Anchorage,AK 99524-4027 300 FEB 01 2017 Suite 1400 Centerpoint Drive Anchorage,AK 99503 AOGCCChad Helgeson February 1, 2017 Operations Manager (907)777-8405 Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Hydraulic Fracturing Application,Nikolaevsk Unit,Red#1 Dear Commissioner Foerster, Hilcorp Alaska, LLC ("Hilcorp"), as Operator of the Nikolaevsk Unit, herein submits its application to fracture stimulate Red#1. ' Please do not hesitate to contact Ted Kramer at 907-777-8420 should you have any questions regarding this application. Sincerely, HILCORP ALASKA, LLC ("1,77: Chad Helgeson Operations Manager Enclosures: Form 10-403 Sundry Attachments Section 1—Affidavit 10 AAC 25.283(a)(1) 1.andowner Notiticalion I.etter Red Well No. t Page 3 of 3 VIRIFIA'I ION OF NOTICE PER 20 AAC 25.283(a) NIKOLAEVSK UNIT RED WELL NO. I I, Chad Helgeson, Operations Manager,do hereby verify the following: I am acquainted with I lilcorp Alaska, LLC's application for sundry approval to the Alaska Oil and Gas Conservation Commission to enhance production of the Nikolaevsk Unit Red Well No. 1 via hydraulic fracturing. Pursuant to pending regulation 20 AAC 25.283, I assert that all owners, landowners, surface owners, and operators within a one-half mile radius of the current or proposed wellbore trajectory have been provided notice of I-lilcorp Alaska, LLC's proposed operations. DATED at Anchorage, Alaska this ls'day of February 2017. iet Chad Hei exon, Operations Manager Hilcorp Alaska, LLC STATE OF ALAKSA ) ) ss THIRD JUDICIAL DISTRICT ) SUBSCRIBED TO ANI) SWORN before me this Ig'day of February, 2017 STATE OFA ASICA G �NOTARY PUBLIC ':: 4,t4dAiL ARY PUBLIC IN AND FOR Judith A. Stanek c' l� THE STATE OF ALSKA My Corixi�isstori I~xptraa Maroh 13,2018 My Commission expires: 3 ,13 /g' Section 2—Plat 20 AAC 25.283 (a)(2) H"GLEWIS I-nEQJA ■ Gal,. • A tortoise ."`".N 8 � . C5RGeNK UNIT FMK onnBTw�ROlaa }KG 1731.12.5,:„"" LIAG4 TncR VIVT RreR Mr ANC,UNITs;,t Y_ 4* V fOr:DIM UNI • Mir,'J MF CRGGA U MIT4 P N TRACeWGi J BAY WIRT TRAIMG arfCl1GN ISM!ANT LIGItTS UNTd. ma r; [..1 HILL ATV' IJA�T PCARTYCRtlA4 Ati150' RINE/I 1:41T 'r Mir YP LC 111U100147 Tir BLkVGR0 CREEK UNIT a Ken :i STGRLINi M��„; ,.„,Nr Sterling Cooper LD3P UNIT - Landing KORAI 1111 Soldotna 1.. Kenai Peninsula L-� ..4. Cook Inlet Ki4NR CHIK UNIT' of Nini1chik C-PICC% idols _., 1 CDSWDPOUTAN r �.�``(� WWI I 1\cI1 Lot at1on. a {��, NIKOLA.EV9K UNIT nd nhor ,,4 M.ri Lege A Pala' 49$ Red k1 Wel Locaticr MOM' i CII and Gas Urtr E undar. Homer .:_,1: II NIkolaevsk Unit II...A4..111 Red Pad C.I • ,, WR*Dob TT Q2D1T Well Red#1 Figure 1 u ci ill E.1 I, e] p IYIIII.CfIN(NATIVE 2 NINILCHIK NATIVE ALASKA O p ASSOCIATION.INC ASSOCIATION.INC STATE (.0 V! Sec..31 n N R I G-061684 80038013W 1 Sec. 33 80048013W J r KENAI K.ENAI .E N INSUL.. PENINSULA BOROUGH BOROUGH Sec. 1 ADL388209 Sec E, COOK INLET Sec... 5 ALASKA REGION INC, ADL389227 C SCK INLET Sec.4 STATE P.EGGO*4 INC C,NFt 5+�1*��rst•.141 l�„ir4er.k. ALASKA I:. }♦r*t 'STATE 4 o N R NIKOLAEVSK UNIT ____.. AD 92663 RE[)I Water WeilIlk Surface[bale Location' IAIr3niculcdl ii ------1(1.-M Sand I J It } a, .:A V rrl STATE II- y'l RED 1` CC,OK INLET ii 0 0 o t,F: A r EHL ce) co Q co AKIL38922.7 Sec 81 5Er ION INC. CI. p ADL390514 fn Ch -. .. REO:C,,4 IN.!. COOK INLET zir vee, 9 RED 2i �1r REGION INC OHL _ M,ar t _ itr'.raarrrrc:rt+11a11A**r. Legend COOK sNLET REGION INC WAX-Well Lacallan Parcels KP3 iSurlace Oarsrshfp; _ ADL392663 r S.rface*late Locations'SRL. =1 OH and Gas ISLE Boundary :Sec. 18 5'F'_ Tap el Fsac 1Rad 11 SHL 1.2 ole la.n3rr 0 N F }1V1! X Try of T-4,0 Red 21 11.,..,1 Tee,of Frac 1.2 Me bullet ......_ _--__ Wel Paths Ur Nlkolaevsk Unit HAK Petra well oan0ase: No Achore Water Wells Within 6.3 Mlle Radius Red Pad 0 1,006 2.090 3,009 Well Red#1 Fee, Plat depicting all well types within a %2 mile radius of Red 1. Section 3—Freshwater Aquifers 20 AAC 25.283(a)(3) The Red 1 well did not run a resistivity tool in the shallow hole,which would've helped define freshwater zones, but the well did employ a gas chromatograph from the surface conductor to total depth, and the well only registered one or two units(negligible) below 850', and the first 100 unit gas show didn't occur until 2,080' measured depth. There are no permanent inhabitants within Nikolaevsk Unit, and therefore no recorded or suspected water wells. See notes below. Red # 1 : Nikolaevsk Unit „ , . .. f, i }4 I g }f Y i : .. x troop Mkolaevsk ppEP r ", 11ld 1IMI� ,7-1_, ,., Ml . H.....1.......................... T 6`' i .5� 6 MIN ,,,,y_. p �A 7 y s 1 e ' ,► 7,- i 1,' +44,00 °ir �' r i"j ,{ " 47 � ar . „ t- s;- i Pi_ d ,, r . K ti V:, IA 4444.-+,.-_.�- 00 "4.^�. .r_..w_. � 4444.. MIT.1'QRA V 71 R ;F, ' "... )'4' l''''., —4 , '- .' ate 4,444, j.. Blue triangles are water wells and their depths; they show that the nearestwater well to Red #1 is 3,23 miles to the southwest. There are artesian springs thatfeed the village of Nikolaevsk to the south, and the water well drilled for drilling operations at the Red #1 well exhibited artesian freshwater flows at the surface . Section 4—Plan for Baseline Water Sampling for Water Wells 20 AAC 25.283(a)(4) To identify water wells for potential inclusion in the sampling program, Hilcorp reviewed the following publically available and electronic data sources for wells within a %-mile radius of the Red 1 wellbore trajectory (study area), encompassing and running between the well surface location and the proposed fracture zone (Figure 2): • ADNR Well Log Tracking System (WELTS) (https://dnr.alaska.gov/welts/#show-welts-intro-template) • Subsurface water rights(http://dnr.alaska.gov/mlw/mapguide/water/wr start tok.cfm) • USGS(http://nwis.waterdata.usgs.gov/nwis/inventorv) • ADEC Drinking Water Protection Areas(https://dec.alaska.gov/eh/dw/DWP/protection areas map.html) The four sources identified no active water wells. One decommissioned water well, incapable of being sampled,was identified on Red Pad.Additional investigative efforts included an aerial imagery review and landowner outreach. August 2015 aerial imagery showed no improved properties within the study area other than the Hilcorp-operated Red Pad. Hilcorp reached out to CIRI,the sole landowner in the study area,to see if CIRI had any knowledge of potential water well locations in the area. CIRI consulted with the Ninilchik Natives Association, Inc. and on February 1, 2017, confirmed the absence of water wells within the study area. Hilcorp, therefore, is unable to select representative water wells for the collection of baseline samples and post-fracturing samples. Section 5—Detailed Cementing and Casing Information 20 AAC 25.283(a)(5) 9-5/8"47#/ft L-80 BTC Surface casing set at 1,790' MD cemented with 110 bbl of 12.8 ppg lead and 45 bbl of 15.8 ppg tail "G". 7" 29#/ft L-80 BTC Intermediate Casing set at 4,601' MD cemented with 53 bbl of 12.8 ppg"G" Lead and 30 bbl of 15.8 ppg "G"tail. 3.5" 9.2#/ft L-80 IBT Production liner from 4,379' MD to 10,930' MD cemented with 209 bbl of 12.0 ppg Litecrete. Casing Length Size MD TVD Pipe Body Yield(lbs) Burst Collapse Conductor 50' 16" 50' 49' N/A - - Surface 1,790' 9-5/8" 1,790' 1,789' 1,086,000 6,870 psi 4,760 psi Intermediate 4,601' 7" 4,601' 4,600' 676,000 8,160 psi 7,020 psi Production 10,930' 3-1/2" 10,930' 10,551' N/A 10,160 psi 10,540 psi Section 6—Assessment of Each Casing and Cementing Operation to be Performed to Construct or Repair the Well 20 AAC 25.283(a)(6) The Red#1 well was constructed in accordance with 20 AAC 25.030. 9-5/8"Surface Casing:The 9-5/8" surface casing was run on 6/11/2004.The casing ran to a depth of 1,790'.While running casing the pipe was circulated and washed to bottom. Pumped 3 bbls of water and tested lines to 3,000 psi.Tested good. Reciprocated pipe and pumped 30 bbls mudpush XL, 110 bbls Lead,45 bbls tail.Switched to rig pumps and displaced 127.5 bbls of mud. Bumped plug. Cement in place and was pumped properly with no issues.Tested casing to 3,060 psig for 30 minutes. 7" Intermediate Casing:The 7" intermediate casing was run on 6/15/2004 to 4,601'. Circulated down the last 80'to bottom and saw one tight spot at the shoe depth 4,585'.Worked through same spot and didn't have any further issues.Circulated well clean.Cement program consisted of pumping 53 bbls of "G" lead followed by 30 bbls of"G"tail. Program was pumped with no issues for a total 83 bbls.This calculated the top of cement in the 7"casing at 895'.Cement in place was tested to 3,000psig for 30 minutes. No CBL was run for the intermediate casing. 3-1/2" Production Casing—The 3-1/2" production liner was run 7/4/2004. It was run with 4" DP. Liner was filled while running in the hole to 10,952'. 209 bbl Litecrete cement was mixed and pumped,the rig dropped the dart, and and followed with 106.7 bbl of displacement fluid. Plug bumped with 3,700 psig. / Reciprocated pipe with no issues during cementing.As drill pipe was bled off,the float was not holding. 1 As a result, pressured again to 3,700 psi. Float held. Bled off and rotated off C-2 profile to set liner. Pressured back up to 1,200 psig and picked up. Set back down with 35,000 lbs to shear ZXP baker packer. Bumped down three more times to confirm packer set successfully. Production liner was pressure tested on 7/5/2004 to 4,000 psi for 30 minutes.Successful test. The cement bond log(CBL)that is attached is 500'above and below T-80 is below.The entire CBL log is J availble by request. Reviewing the CBL,the top of cement in the liner is at^'4,404'.The bond amplitude shows good bond to^'5,100 where the bond strength increases from good to great. Below 6,300', strong bond and isolation continues throughout the proposed stimulation area to TD. Based on the data above, Hilcorp feels that the depth of stimulation is completely isolated from the .1 intermediate and surface casing.Additionally the intermediate and surface casing are cemented properly and isolated. Red #1 CBL: Time Mark Every 60 S CM 3,11 Transit Time(TT) GoodBond 400 (US) 200 From ACBI to GOBO Tension(TENS} Good Bond(LOBO) 5000 (LBF) 0 0 (MV) 10 Cbl 5#Transit Time(G5TT1 CUL Amplitude(CBL) 500 (US) 0 (MV) 100 Discriminat Min Amplitude Max Gamma Ray(GR) ed CCL CBL Amplitude(CBL) 141/111 0 (GAM: 150 (CCL)) 0 (MV) 10 VDL VariableDensity(VDL) 3 (VI -1 200 (US) 1200 '''''--- i , ) r 1 ' . , , .:, ,,,„. ''._,: 1 '. i ''''it...17.:. 'i il 10:;\,:- . '<-13 1 • . f ' } t E a . { 6 ;e ) itI :.1:,,Iv I. MEP � v 1 N jl I ( T: ' t (a k : i't4:4'i*i--'--- ,: _. .._ .... . 5 ) .: --...0....T F frit _.." . Ill'.1 _.w. 1 asoa r 44 '� UPS ;t, V'' gik 111 in 11111111 AN : . t• L. ___ � - S. ___ t ! , yam+, l :11'ai, . Qp6�q( £y [h 00 . { a i s k �, tl I 1 ( . r M MINi 1 i. t , 4 I f4. IIIIPI — 1 $. L i' 11 f I I' IMM -.41111111 - iii 11.1 II. lq w or 1 i ' wici [VS(0 : b Ali.. 1 ' , fo- . , ...E WEIMIE n ■ min 4 Ilt 11•11 ■ A ■ ' II w II �_ ■ ..._... S ii 1 rt.o aaa IIIMMINIMP aaa► 1111111111..... 111 111111111 Mk II i , 1 t, '411111111.111.11.1111EN II II " fit MK t i!r ri. ., s■ -1111 t I 1 sr- ma ..,... 11_ 1_. p 11111111L”. • ! %. Y 4 �1 se II -1 M, Al ) N MN !fi ■, !F I t` 1 1 r Nis- _.. err IIIMMEMMEMINI AM Intervals I I 11111�i.ire s' r raaaialir rs .i. .' NIWNINONINM '"""NIEM K fil 4;„'"1:1:4.,'!,.: dosiwrazu ! .tea W' I: IIIIIIMIIIIINWt .. �� R , . INIINIIIMILva �J � +' r IMINNIMMIIMillimifilingr .L.,11 11 doimm, ::1 �iminit,., Illaaalta W _. ,t " r • r A, /...,!: /! i . is ,� is . V i�1 _ . �r �I ' ., rr��� ii— 't, - Short Joint • '�� ® W, _ . imomminimmerti i'', ��rrrr■_tI_ rli���� • d �; i� __lI_ imi��o i �__ir•MINIMMIBINIIMMIMM Mr a 1N AI _ '.."1111111111111111111B11 IN e II� ::� i , IIIIMINIIIIIIMP►�IMMItal1 �IIr• � S MI IIIIINIIIIIIIIIIII MI �.� Li7— .e ''. a:itry fib 711111111•111 OW 0111111 ,N , .•.r_MkIIN .._..aIIIIIIMIIIIIII MI IIIIK II IN NM=MN MffilIEN EMMIP:1111•1111111 I r a 1 �S1•�ffINM 6900 •sil`i�� ! 1I �r/���tI i Ir�c��r! ��_NMI ME Iaa�= } �r�W��Mir aSI AIS } ; ",=11111111 !.III��Mii • , i h �� : t 'i.I. '` 4 =.111111 :to , ,la 1 ' 91(0r , - ci c't -mummuseimemmoriglidauza I cli.,1,1_ ,,,,,. 11112 - C glismia imir- : . ,. f I t ' 1' !, -"11.111111iiiiiii d( It 1 r I iiii r 1 .ti..1' ' ' 'A '.Oil,*ile ,,, (4?....., 7 OIL F . il . i- c I":. ' t i ,-,1 1.,' : imvssi f f r�j. a t , ' _ .......‘,_., : .i aill:41,.LI :e'l''...1 *iiimmilweilliallii.11.1.1.1111 :! ' ' 'tql 4 r., . , !.. Mr. 1.11111= r . ( l' '. 'i''''. ';': ai awl iT :!! ' i y Discrirnmat Mn Amplitude Max Gamma Ray(GR) ed CCL CBL Amplitude(CBL) 1 I 0 {GA150 (COLD) 0 {MV) 10 VDL VariablaDansity(VDL) 3 (V) -1 200 (US) 1200 Cbl Sit Transit Time(CSTT) COL Amplitude(CBL) 500 (US) 300. 0 IMV) 100 Tension STENS) _ Good Bond(0000) 5000 (LOP) 0 a (MV) 10 - Cbl 3.ft Transit Time T GoodBond 400 (US) 200 From ACBL to G080 Section 7—Supplement Hilcorp proposes to pressure test the 3-1/2"tubing to 5,000 psi by the following means: 1.) MIRU Slickline unit and pressure test Lubricator. 2.) PU RIH with plug to 8,600'and set the same.. 3.) RU Pump truck and test lines to 6,000 psi. 4.) Open well to pump truck. Pressure test 3-1/2"tubing to 5,000 psi on chart for 30 min. 5.) Bleed off Pressure. RIH and Retrieve the plug. 6.) RDMO Slickline and pump truck. tek 02/24/17 Section 7—Pressure Test Information and Plans to Pressure Test Casings and Tubings Installed in the Well 20 AAC 25.283(a)(7) Casing Pressure Test Duration Date 9-5/8" 3,060 psi 30 min 6/11/2004 7" 3,000 psi 30 min 6/15/2004 1,500 psi 30 min 7/6/2004 3-1/2" 4,000 psi 30 min 7/5/2004 Hydraulic Stimulation Pressure Testing Plan Please see procedure in section 12 of this document. The 7" intermediate casing will be pressure tested to 3,500 psig for 30 min.Tubing movement claculations suggest 3,000 psig be held on the casing for the duration of the pumping to prevent the packer from unseating.Additionally this casing pressure reduces the maximum realized internal pressure to 5,800 psi on the tubing string.This is 55%of the burst pressure rating. For additional protection from overpressure,a pressure relief device will be installed on the casing in the event of a tubing failure. Section 8—Pressure Ratings and Schematics for the Wellbore 20AAC 25.283(a)(8) Casing Length Size MD TVD Pipe Body Yield(lbs) Burst Collapse Conductor 50' 16" 50' 49' N/A - - Surface 1,790' 9-5/8" 1,790' 1,789' 1,086,000 6,870 psi 4,760 psi Intermediate 4,601' 7" 4,601' 4,600' 676,000 8,160 psi 7,020 psi Production 10,930' 3-1/2" 10,930' 10,551' N/A 10,160 psi 10,540 psi Tubing 4,412' 3-1/2" 4,412' 4,411' N/A 10,160 psi 10,540 psi Device Pressure Limit Tree Saver 15,000 psi Wellhead »—b;566rpsY 4$1, StkOrst Coil BOPE(tested) 4,500 psi *Post Frac Cleanout/If Required Red#1 Weill Schematic: Well Name: Red #1 SCHEMATIC Field: Nikolaevsk State: Alaska API:50-231-20021 Conductor 167,8277 ppf,K-55 to AOGCC:204-084 50' 357 FNL&392'FWL Sec.8,T4S. R13W,SM Surface Casino:9g4-,47 ppf.L-80, 4 i L I RT-THF: 17.22' BTC to 1790'Cant with 110 bbl of 12.8 ppg lead and Tbg lift threads-3'h'I BT A5 15.8 ppg tail'G" Tree cxn-21/2'Bowen am Intermediate Casing:7". 29 ppf.L-80,BTC to 4601' Grunt with 53 bbl of 12.8 ppg"G'bead ead and 30 bbl of 15.8 ppg"G"ta,l. Production Tubing: 31/2'.9.2 ppf. L-80. IBT to 4412' -Annulus loaded wth 7.4 peg base oil Completion '(G F� ` -Chemical injection sidepocket mandrel at 2502' :MacoOSFO-1C-1)with 114". Oven Perfs: 0.049"wall SS chemical injection line 1-80:8768'-8777'(6 spf,8/3/04) -Locator sub X4378' 1-80:8795'-8820'(3 spf,7/23/04) -Baker 80-40 seal assembly 1-80:8800'-8820'(5 spf„11/11/16) _ S D 13'of 4.00"OD seals Isolated Perfs — 1%76Q 1-90:9056'-9076'(6 spf,8/3/04) T-100:9210'-9280'(3 spf,7/19/04) s Pin Liner:3W,9.2 ppf,L-80,IBT liner frorn 4379' -10,930' G1:10565'-1061(!'(3 spf.7117!04) Baker DP packer,Flodock liner ganger& 80-40 sealbore at 4373' Cemented with 209 bbl of 12.0 ppg 5 Z Litecrete Plugs: 10416 -Halliburton CIBP 9025'capped •with 14'of cement(5;19/11) =( -EZ-Drill CIBP at 9192'capped with 40'of cement(7/23/04) -EZ-Drill CIBP at 10420'17/19/04) Directional Data: max hole angle=29.1 deg . 1 (°130' ,,, ) KOP=4800' max dogleg<3 degi 100' PBTD=9152' TD= 12.458' Red#1 Wellhead Schematic: Red Pad Tubing hanger,CIW-CXS,11 Red#1 X 3 34 lBT lift and susp,w/3" 16x95/8x7x3Y typeHBPVprofile,Y."non continuous control line,9'/. EN BHTA,Bowen,3 1/8 SM FE x 2 Y:Bowen union top 0 o i ni .-imp \� 4,be Valve,Swab,CIW-FL, (41.1.1P'4.5, o��0?P 44�,e 31/8 SMFE,HWO,AAtrim .O34� ,Z, e, ys F . r O ��e `�`` Jai°«`-<<:'c`. \\ v7 4''' ''y,4. $y`S 46 N t: ::04 Q0 ).:41 . ,__ _j___ 1 . LI, \L. .. Valve,Upper Master,CIW-FL, ©� J\ 3 1/8 5M FE,HWO,AA trim ��Op 411uTp Valve,Master,CIW-FL, ^' Op (.i' 3 1/8 5M FE,H WO,AA trim :r �7 JYv / 2. lsill i 0 0 ENil■IN=1►d I 411111141 I- Casing Spool,Cameron MBS- — upper,11 5M stdd top and • bottom,w/2-21/165MSS0 10 l Ilito g i •. 7x3'/=annulus 'nal �Ir IINEN Ilia Csg head,Cameron MBS- Lower,11 5M x1-103 pocket * , 11, 11111)3D bottom,w/2-2"LPO U I ' = = 95/8x7annulus „C „ I;! y — i Casing hanger,Surface, I Cameron,133 5/8 x 9 5 5/8 BTC box bottom x LH acme, II w/T-103 neck 16" 11 9 5/8" 7„ 3%" Tree Saver Schematic: raiznilVII. STATES PROPOSAL: Casing isolation Tool Energy Sepitces;Canada)Inc. Maximum Allowable Pumping Rates CSG 2.260 3.760 10 11r Big Bore '1.750 2.750 6 neernin —2-7,3-3 3 1 1.436 2.360 j 4 nerimin 23J8' 1 000 1.900 2 ne(nilri 3 VIA 4 lila Amiffstapored inewelnpa 2 180 4.00(4 4 1/16 X Tool Mandrel 8.610 4.760 i 24 nVo'mln Om Pomo* Gam Poem* r 4 X I.-I- , •• •• 1 I 11 .41 I I 11111111111111W , NI AIM 1.1.144,0 ...1•1•11 ommok news 04 tile' 0.0471.10411. t',;.1 I C; 30 wrovw StingurCanacta.carn 1SM Treating Head Section 9—Data for Fracturing Zones and Confining Zones 20 AAC 25.283(a)(9) Subsection A: Three rotary sidewall cores were obtained in the T-80 gas zone that we intend to fracture. In general, the zone consists of a medium to coarse grained feldspathic-lithic arenite,with net confining stress porosities of 5.9 to 13.7%and Klinkenberg permeabilities of 2.27 to 205 millidarcys.Specific detailed lithologic descriptions with respect to sample mineralogy follows: 8810.0' MD: This sample consisted of 90%shale with a small portion of very coarse sandstone at one edge. The SEM sample was taken from the thin sand, but not enough of this material was available for clay XRD analysis. I did manage a bulk XRD using a special background slide. The SEM sample was too small to perform hydrocarbon extraction and ended up charging badly. In spite of these problems,the sand appears to have moderate intergranular porosity. It contains large masses of pore-filling kaolinite, moderate amounts of siderite and minor quartz cement, but showed no evidence of thick pore-lining smectite. Apparently,the sandy layer is primarily kaolinite cemented.This results in an increase in the microporosity component of total porosity and raises the potential for fines migration problems.The sandy layer has fairly low Vshale (10%), but may not be very meaningful due to the very small size of the sample. The shaley material has a clay assemblage that includes major amounts of illite, with lesser amounts of kaolinite and chlorite, but not much smectite. Evidently the shale is influenced primarily by metamorphic provenance and is not influenced much by volcanic detritus. 8814.0' MD: This sample consists of coarse-grained feldspathic lithic sandstone with moderate sorting and low amounts of depositional matrix. The sand has excellent porosity and should have fairly high permeability. Diagenetic cements include grain-rimming siderite and pore-filling kaolinite,with minor Fe-chlorite (metamorphic grunge)and only traces of smectite.Quartz overgrowths are small relative to the grain-size and do not significantly reduce intergranular porosity.There is some fine debris that may contribute to fines migration damage, along with the potential for kaolinite movement during production. 8818.0' MD: This sample consists of very coarse-grained to pebbly sandstone with moderate amounts of depositional clay matrix and diagenetic clay cement. The clay assemblage is dominated by diagenetic kaolinite that occurs as pore-filling material. In addition, there is a minor amount of illitic-chloritic detrital clay that has infiltrated the sand. Siderite occurs as a grain-rimming carbonate cement.The sample contains only a trace of smectite. Vshale is<10-12%. The rock has fair reservoir quality and should be productive. 'UNOCAL Cook Inlet,Alaska (Red No. 1 Well File:A-87003 Sample Permeability, Porosity, Grain Sample Sample Depth, millidarcys percent Density, Lithological Number I Number feet to Air Klinkenberg Ambient NCS gm/cc Description 1 13 8810.0 2.92 2.27 6.1 5.9 2.66 Ss mg sIty thk shy lam 1 14 8814.0 54.0 46.7 12.8 12.7 2.62 Ss m-cg slty 1 15 8818.0 224. 205. 14.0 13.7 2.62 Ss m-vcg slty The zone of interest to fracture (8768-8824' MD) is bounded above and below by several hundred feet of dusky brown to brownish gray carbonaceous shales, medium light to medium gray and brownish gray tuffaceous claystones,tuffaceous siltstones,and coals. Abundant platy laminations with an absence of reservoir-quality sandstones would effectively confine the proposed fracture to the perforated sandstone of interest at 8768-8824'. Subsection B: The sand section described above is the T-80 Sand Subsection C: The measure depth of this sand is 8,766' MD with a true depth of 7,569'TVDSS. Subsection D: The measured thickness of this sand is 57'with a true vertical thickness of 54'. Substection E: The fracture pressure is calculated to be a within a range of 4,800-^'5,500' psi. Section 10—Location,Orientation and a Report on Mechanical Condition of Each Well that may Transect Confining Zone 20 AAC 25.283(a)(10) No other wells transect the confining layer(T-80 sand) in the%2 mile radius surrounding Red#1.See • attached map in section 2 of this document. Section 11-Location of,Orientation of and Geological Data for Faults and Fractures That May Transect the Confining Zones 20 AAC 25.283(a)(11) There are no known faults that exist in the area or depth of the T-80 sand. Section 12—Proposed Hydraulic Fracturing Program 20 AAC 25.283(a)(12) All information required in this section is included below. „` �" ' 5.--c '" Proposed Hydraulic Fracturing Procedure: /� T: j- ' Pfr"- 1 1. 1.) Perform Pressure test on casing.Test o 3,500 psig for 30 min. 2.) MIRU frac fleet. MIRU frac and slop tanks. MIRU CTU and associated equipment. Stump test CT BOPE, if possible. Isolate from Frac flow path. MIRU all ancillary support equipment. a. Provide 24-hr notice to AOGCC if BOP is tested and connected for witness. 3.) Fill frac tanks with fresh water. Heat water as needed. 4.) Lay all hardlines and manifolds. Install pressure monitoring equipment on wellhead and tree. 5.) RU 15K tree Saver and hard line. 1A ‘i 6.) Pressure test all high pressure treating lines to 10,000 psi(maximum anticpated surface pressure is 8,800psig.See Figure 6 on Page 9 of the Fracture Modeling Study by Frac Diagnostics). 7.) Set the GORV(gas operated relief valve)at±8,800 psi. Set the staggered pump kickouts between 8,500 psi and 7,500 psi. 8.) Pressurize annulus to 3,000 psi. Set annular PRV(pressure relief valve)at 3,300 psi. 9.) Prepare frac fleet to pump. 10.)Pump DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. 11.)Fracture stimulate interval with 100 mesh and Carbo Bond Lite 20/40 proppant in cross-linked gel. See"Proposed Treatment Schedule" for proposed design. 12.) Shut well in. RDMO. *Refer to section 13 of this application for the post stimulation procedure. eCtl ,A- c7 o� - 3o , �" Z kr 0're / At 0 rie,s LZ ii G C,00 p g�UGD p / G P 20 AAC 25.283(a)(12)cont'd Frac Design: ramilFD Frac Diagnostics Fracture Modeling Study Hilcorp Alaska, LLC Red #1 Final Report#1221 Prepared for Jason Ewinb Report Date: 1/13/2017 By:Brian Dzubin Frac Diagnostics, LLC 1450 W Grand Parkway S Suite G-121 Katy,Texas 77494 Disclaimer No Person acting on behalf of Frac Diagnostics. LLC: • Makes any warranty or representation, express or implied, with respect to the accuracy. completeness or usefulness of the information contained in this report, or that the use of any apparatus. method or process disclosed in this report may not infringe privately owned rights;or • Assumes any liability with respect to the use of, or for damages resulting from the use of. any information, apparatus, method or process disclosed in this report. Fracture Modeling Study Hilcorp Alaska,LLC Red#1 Table of Contents Table of Contents introduction .... 3 Discussion 5 Proposed Treatment Schedule 5 Anticipated Surface Treating Pressure 6 Simulation Results 6 Fluid Friction Curves 6 Influence of Fracture Propagation on Surface Pressure ...8 Anticipated Fracture Geometry 9 Recommendations 13 Appendix 14 Frac Diagnostics..LLC 1450 W Grand Parkway S. Ste G-121.Katy,Texas USA 77494 www.fracdiagnostbcs corn 2 Fracture Modeling Study Hilcorp Alaska.LLC Red#1 Introduction Introduction In 2004, the Red#1 well (API#50-231-20021)was drilled and completed in the Nikolaevsk Field in the Cook Inlet Basin (Figure 1). Since that time, the gas-producing T-80 interval (Figure 2)in the subject well has been tested, shut-in, and also produced. Presently, Hilcorp Alaska, LLC has targeted this interval for a propped hydraulic fracture treatment. i ' 0, 4... .0 I. * , ' Figure 1-Map image depicting the approximate location of the Red 01 well. y. R: "rGroa F.,.--'- I a* ,, — , ip....L—...... MN i �r ... ,~ t- lr _ 4 .--.—'-- 11 Pliii7 _ , LIM ayst ---..46•06...,.._ .404 >... ----- . i1 m,„ ... . . :--..., ...... .._,..01.... .....,._ i ._ _.: Figure 2-Red#1 openhole log data. The stimulation target is highlighted. Frac Diagnostics.LLC 1450 W Grand Parkway S.Ste G-121,Katy,Texas USA 77494 wv w.fracdiagnsostics.corn 3 Fracture Modeling Study Hilcorp Alaska,LLC Red#1 Introduction Frac Diagnostics, LLC was contracted by Hilcorp to develop a fracturing design for the T-80 interval. Results from this effort are presented in this report. Hilcorp provided Frac Diagnostics with openhole logs(triple combo and dipole sonic),a current wellbore schematic, and directional surveys from the subject well. Additionally, Hiloorp noted that the anticipated permeability and pore pressure in the high-porosity interval at 8,807-8.820 ft were 27 m0 and 2900 psi, respectively_ These values were derived from pressure-transient analysis. Depletion in the interval is anticipated. As a final note on the design, Hiloorp requested that the design should achieve a propped length of at least 200 ft and conductivity of at least 2,000 mD-ft. Frac Diagnostics used all items noted here to develop the proposed design_ Frac Diagnostics, LLC 1450 W Grand Parkway S.Ste G-121,Katy,Texas USA 77494 www.fracdiagnostcs_com 4 Fracture Modeling Study N Hilcorp Alaska,LLC Red#1 Discussion Discussion This section divided into three parts, each discussing a particular aspect of the proposed design for the T-80 interval in the Red#1:. • Proposed Treatment Schedule • Anticipated Surface Treating Pressure • Anticipated Fracture Geometry Proposed Treatment Schedule The proposed treatment schedule for the T-80 interval in the Red #1 is presented in Table 1. The design assumes injection at 25 bpm down the 31/2 tubing string and into two perforated intervals listed as Table 2. The schedule consists of 54.500 gal of borate-crosslinked gel and 3,160 gal of fluid used for flush. (As noted by Hilcorp, Schlumberger's YF125.ST system will be used.) Additionally, the schedule will utilize 2.000 lbs of 100-mesh sand (as a proppant slug in the pad)and 109,000 lbs of 20.40 CarboBond Lite. Table 1:Red ifl'1 Proposed Design Schedule Stage She Type Elapsed Fluid Clean Prop Stage Slurry ( Proppant Time Tjpe Volume Conc Pimp. Rate Type min:sec (gal) (hpg) (bb.) LbFoil Webore Fluid Linear gel 3212 1 Main frac pad 1 -'112-51 BXL Gel 12000 0.00 0.0 25.00 2 Prop slug 13:25 ° BXL Gel 2000 1.00 2.0 25.00 100 mesh ✓ 3 Main frac pac 24:51 BXL Gel 12000 0.00 0.0 25.00 4 Main frac slurry 28:50 BXL Gel 4000 1.00 4.0 25.00 CarboBond Lite 20140" S Main frac slurry 33:00 ' BXL Gel 4000 2.00 8.0 25.00 CarboBond Lite 20!40 O Main frac s.urry 3b:25 BXL Gel 5000 3.00 15.0 25.00 CarboBond Lite 20140 7 Main bac slurry =4:1:4 BXL Gel 5000 4.00 20.0 25.00 CarboBond Lite 20040 i Main frac slurry 49:55 BXL Gel 5000 5.00 25.0 25.00 CarboBond Lite 20140 9 Main frac slurry 5410 BXL Gel 3500 6.00 21.0 25.00 CarboBond Lite 20140 10 Main frac slurry 56:47 ,, BXL Gel 200D 8.00 16.0 25.00 CarboBond Lite 20140 11 , Main frac flush 50:47, Linear gel 3160 0.00 0.0 25.00 12 Shut-in 179:47 SHUT-IN 0 0.00 0.0 0.00 Design dean volume(bids) 1372.9 Design proppant striped{Ws) '11.0 Design slurry ti+dume(bbis) 1495.0 Table 2: Perforated Intervals Interval#1 ' Interval#2* Top of Perfs-MD(ft) 8768 8795 of of Perfs-MD(ft) _._. 8777 8823 of Perforations j 54 175 'Interval 2 is a combination of two sets of perforations at 8795-8820 and BB03-8823 Frac Diagnostics.LLC 1450 W Grand Parkway S. Ste G-121,Katy.Texas USA 77494 www.fracdiagrostc,s.com w.fracdiagnostc-s.com c Fracture Modeling Study Hilcorp Alaska,LLC Red#1 Discussion Anticipated Surface Treating Pressure Frac Diagnostics used FRACPRO to simulate fracture geometry and generate a predicted pressure response from the treatments. This section is divided into three parts, each discussing the following topics: • Simulation Results • Fluid Friction Curves • Influence of Fracture Propagation on Surface Pressure Simulation Results Figure 3 depicts the simulated treatment plot for the proposed design. Under the modeled conditions. the surface treating pressure varied between 5,000-6.000 psi while pumping. Values were calculated from the modeled bottomhole pressure, hydrostatic pressure, pipe friction values,and components of excess friction (perforation and near-wellbore). Slurry rate(bpat - Surf Pressure(psi; Prop Conic Opp) Eltn h Pressure(psi) - Btm Prop Cane{,ppg) 75 25 FRACCPRO Z® . iDD 2D 03010 r� 60;0 20 ID X030 SD 1 20'10 O 0 'e i 0 DOD 15 D_ ?d DC 03 r!WM Imin7 Figure 3—Red#1 Simulated Treatment Plot Fluid Friction Curves For the simulation runs described in this report. Frac Diagnostics used a fluid description for a delayed borate-crosslinked fluid system and gave it the generic designation, "BXL Gel". At the time of this report, discussions have centered around the need for a treesaver. Hilcorp expressed concern regarding the 6,500 psi pressure limit on the wellhead and inquired how Frac Diagnostics. 1141454 W Grand Parkway S.Ste G-121.Katy,Texas USA 77494 www.fracdiagnastscs_com 6 Fracture Modeling Study Hilcorp Alaska,LLC Red#1 Discussion pressure predictions might change for the YF125.ST system (which has little or no delay in its crosslink reaction). To address the question. Figure 4 was prepared to show a comparison of pipe friction data in FRACPRO's internal library. Based on this information. use of the YF125.ST data would have resulted in lower calculated pressures. s000B34.Gel ••ir�YFfl5.ST •..•hoiect u i ki Yl t. '. ••1 rke 11 • 0 lboml Figure 4-Pipe Friction Data from FRACPRO Fluid Library It should be noted that field conditions may yield friction pressures that are higher than values. used in the model. Calibration of this data will be necessary. This also applies to values of entry friction in the perforations or near-wellbore region. In a case where the combined friction (pipe, perforations,or near-wellbore)values are 1.000 psi higher than values used in simulation, the surface treating pressure may approach or exceed the pressure limit of the wellhead (Figure 5). Frac Diagnostics. LLC 1450 W Grand Parkway S.Ste G-121.Katy,Texas USA 77494 www.faacdiagnostcs corn 7 Fracture Modeling Study Hilcorp Alaska,LLC Red#1 Discussion - Suri pure {{ ia,",— ,1 O(1tt pst Fricfi (ps) -WN�eed trrr r; }U psr r r..;,, :n: " ° FRACPRO :110: 5 Moo am cc io . _ ..... ' Fxi+tB . ������,:...,,�,��______________ ._._�. ...+r..' . 8[110 000 !/ 2,e411 ?1,rm 1 Figure 5-Comparison between Modeled surface Treating Pressure and Scenarios with Higher Friction Influence of Fracture Propagation on Surface Pressure Depending on the fracture azimuth, the combination of wellbore deviation and perforated height yields a condition where multiple competing fractures could propagate from the wellbore. Should this occur, elevated treating pressures are anticipated. To illustrate the potential impact. an additional simulation run was performed and allowed propagation of two competing fractures. The modeled surface pressure from this scenario("A") was plotted in Figure 6 and compared to values calculated in the original simulation. From this data, one might anticipate elevated treating pressures due to competition between fracture strands. Also. elevated leakoff rates from the additional fracture surface area may induce faster tip-screenout behavior The presence of multiple fractures should be investigated in the field using pre-frac diagnostics (minifrac with a rate step down test). In a case where multiple fractures are identified. the treatment schedule should be modified in order to mitigate potential risks. This might include the use of additional proppant slugs (with varying concentrations) or adjustments to the proppant schedule. Frac Diagnostics.LLC 1450 W Grand Parkway S.Ste G-121,Katy,Texas USA 77494 wlww.fracdiagnosacs.com 8 Fracture Modeling Study Hilcorp Alaska,LLC Red#1 Discussion Suri Pressure -- Wellhead Idllit 6500 (pail SVlrt Pre55ure(A)4p5R1 • FRACPRO 01 75.00 Figure.6—Comparison between Modeled Surface Treating Pressure and Scenario"A"with Two Multiple Fractures Anticipated Fracture Geometry Frac Diagnostics used FRACPRO to simulate fracture geometry resulting from the proposed design. The model response was based on properties outlined in the Appendix of this report. During simulation runs, the upper set of perforations ("Interval 1") accepted a limited quantity of fluid during the pad stage. Injection into the upper perforations stopped once the first proppant stage reached the formation_ As will be seen in the summary tables for this section, this behavior had an impact on the final fracture geometry for the upper perforation cluster. Based on the simulated conditions. the fracture model predicted propagation of a 250 ft fracture from the lower perforation cluster ("Interval 2'). Illustrations of the final proppant concentration and conductivity are depicted in Figure 7 and Figure 8, respectively. Frac Diagnostics,LLC 4460 W Grand Parkway S.Ste G-121.Katy,Texas USA 77494 www_frac iagr cam 9 Fracture Modeling Study Hilcorp Alaska,LLC Red#1 Discussion Low_REQ1..lowitatiAPT y1 etrxi rw,e{iu�t P,m144.0 P,w_^ur,x,mi .. ..... .... .. 7'..,: : i'...''0.....''t". ' )5 b] lY5 ]kl1i! ie' .11793= ,4456. 17 APO irq5..]cxelo444 �] ."41 4 'ra ar.nt.rw7.Yi .il tO4 P2ki.11wjll¢i U=i ICk-0 ;awe-.rp 54 ,11! 441,) 1145, u:v.P 44 4apffic MiuS IS4i: - Awil.P'ef3sa Caxssll►riyl.'1't L.hY 23- -FqO- MB .111190- P cigaa C.aa.w...ytJK1 Figure 7—Red#1 SimuiWd Frwegum Gtoai■itYand Final Proppant Concentration Low PIED,1 blit hur-flPT Fntthao Cortlu taily lmt}(If - 91 tE iil I1 1 1% oda "3:5 x§a "a7s F?Y 7311 �4� its idF •t150 F1 PPLW/#a N-.y.4.3-wo.it. 4.14 li{3 41.14111 v,ti 44 tal i 1M.Rc{p.i lw�t f.� as 4t :win rap aa�.Py�i1��fl 1141.0.) MI5 :win 14M-1 15119 Ater..Pausal Garaaamandt. i LOU Zit 4q0+ I -1190_ ionr Ca aeaeq Kati Figure 8—Red#1 Simulated Fracture Geometry and Final Proppant Conductivity Frac Diagnostics.LLC 1450W Grand Parkway S.Ste G-121.Katy,Texas USA 77494 www.iracdiagnosb s corn 10 Fracture Modeling Study Hilcorp Alaska,LLC Red#1 Discussion Additional output tables are provided for reference: • Table 3 and Table 4 summarize the fracture dimensions (length, height, and width)of fractures propagating from the two perforation intervals. • Table 5 and Table 6 summarize average fracture conductivity, applied damage factors, and the amount of proppant embedment. • Table 7 and Table 8 summarize propped fracture properties by distance from the well. Values are reported at the fracture center at a specified depth Table 3:Fracture Geometry Summary'-Interval#1 Fracture Half-Length(ft) 0 Propped Half-Length(ft) 0 Total Fracture Height(ft) 0 Total Propped Height(ft) 0 Depth to Fracture Top(ft) 8470 Depth to Propped Fracture Top(ft) 8470 Depth to Fracture Bottom(ft) 8470 pepth to Propped Fracture Bottom(ft) 8470 Equivalent Number of Multiple Fracs1.0 Max.Fracture Width(in) 0.01 Fracture Slurry Efficiency"' 0.00 Avg.Fracture Width(in) 0.00 Avg.Proppant Concentration(lbIft2) 0.00 Table 4:Fracture Geometry Summary"-Interval#2 Fracture Half-Length(ft) / 250 rapped Half-Length(ft) 249 Total FractureHeight(ft) 1 107 otal Propped Height(ft) 107 Depth to Fracture Top(it) 8452 pth to Propped Fracture Top(ft) 8452 Depth to Fracture Bottompl 8559 pth to Propped Fracture Bottom(ft) 8559 Equivalent Number of Maputo Fracs 1-0 ax.Fracture Width(In) 0.56 Fracture Slurry Efficiency" 0.30 vg.Fracture Width(M) 0.32 vg.Proppant Concentration 2-61 All values reported are for tie entire fracture system at a model brise 179.81 mei tend of Stage 12 Shut-in eller Mat(lac flush) •'V'attle is reported lcr the end of the last purnprg s'.age(Siege 11.Main jrac lut) Table 5:Fracture Conductivity Summary'-Interval#1 Avg.Conductivity"(mD-ft) ! 0.0 Avg.Frac Width(Closed on prop)(in) 0.325 Dimensionless Conductivity*" 0.00 Ref.Formation Permeability(mD) 13.5 Proppant Damage Factor 0.52 Undamaged Prop Perm at Stress(mD) 345119 Apparent Damage Factor""' 0.01 Prop Perm with Prop Damage(m0) 165657 Total Damage Factor0.53 Prop Penn with Total Damage(mD) 163325 Effective Propped Length(ft) _ 0 Proppant Embedment(in) , 0.011 Table 6:Fracture Conductivity Summary'-Interval#2 Avg.Conductivity"(mD-ft) 4128.1 Avg.Frac Width (Closed on prop)(in) 0.325 Dimensionless Conductivity" 0.62 Ref.Formation Permeability(mD) 13.5 Proppant Damage Factor 0.52 Undamaged Prop Perm at Stress(mD) 34.5119 Apparent Damage Factor"*" 0.01 Prop Penn with Prop Damage(mD) 165657 Total Damage Factor 0.53 Prop Penn with Total Damage(rnD) 163325 Effective Propped Length(R) 249 Proppant Embedment(in) , 0.011 'Al values reported are for the erre fracture system. Actual conductivity could be lower if equivalent multiple fractures have been modeled Total Damage Factor and Proppant Embedment have been applied Apparent Damage due to ron-Darcy and multi-phase flow Frac Diagnostics.LLC 1450 W Grand ParkwayS.Ste G-121.Katy,Texas USA 77494 a9 www.fracdiagnostcs 11 Fracture Modeling Study Hilcorp Alaska,LLC Red#1 Discussion Table 7: Propped Fracture Properties by Distance from the Well at Fracture Center at Depth of 8470ft- lnterval#1 Distance Fracture Conductivity I Frac System Prop Cone per Frac System from Weil System per Frac" Conductivity+"" Frac Prop Conc"" (ft) Width' (mD•ft) (mD•ft) (lbJft2) (Iblft2) (in) it- 0.0 0.000 0.0 0.0 0.00 0.00 0.0 0.000 0.0 0.0 0.00 0.00 0.0 0.000 0.0 0.0 , 0.00 0.00 0,0 0.000 0.0 0.0 ' 0.00 0.00 0.0 0.000 0.0 0.0 1 0.00 0.00 0.0 0000 ' 0.0 0.0 0.00 0-00 0.0 0000 4 0.0r O O 4.00 _ 0.00 its 0.000 0.0 0.0 0.00 0.00 0.0 0.000 0.0 0.0 0.00 0.00 0.0 0.000 1 0.0 0.0 0.00 0.00 Table B: Propped Fracture Properties by Distance from the Well at Fracture Center at Depth of B510ft- Interval#2 Distance ' Fracture Conductivity Frac System Prop Cone per Frac System from Well System per Frac" Conductivity"' Frac Prop Cone" (ft) Width' (mD•ft) (mD•ft) (lbift2) (Ibift2) (in) 24.9 C.559 7276.1 7276.1 4.40 4.40 49.7 0.551 7160.3 7160.3 4.34 4.34 74.60.537 69632 6963.2 422 ' 4.22 99.4 0.516 6677.9 6677.9 4.06 4.06 124.3 0.488 6293.1 6293.1 3.84 3.84 149.1 0.451 5789.8 5789.8 3_54 3.54 174.0 0.404 5135.25135.2 3.17 3.17 199.9 0.341 4264.0 4264.0 2.66 .__ _ _ 2.66 223.7 0.251 3000.6 3000.6 1.94 1.94 248.5 0.059 0.0 0.0 0.00 0.00 'Width values reported are for the entre fracture system, ""Fracture conductivity reported for total prapipant damage of 0.53 and 0.011 in of prcppa a embedment ""Frac system conductivity reported for 1.0 equivalent multiple fractures with'Ion co^-+sidered conductive_ •••'Frac system proppant concentration reported for 1.0 equivalent multiple fractures Frac Diagnostics.LLC 1450 W Grand Parkway S.Ste G-121.Katy,Texas USA 77494 www.fracdiagnostie-s.com 12 Fracture Modeling Study Hilcorp Alaska,LLC Red#1 Recommendations Recommendations Frac Diagnostics presents the following recommendations for consideration: 1. Utilize a treesaver while stimulating the T-80 interval in the Red #1. Although simulations predicted pressures in the range of 5.000 to 6,000 psi during pumping, a number of factors could push the actual treating pressure beyond the 6,500 psi limit of the wellhead. 2. Perform tubing-movement calculations in verify that wellbore components will withstand forces exerted during the stimulation. 3. Although not outlined in the design schedule, pre-frac diagnostic tests (minifrac and rate step-down test) should be performed ahead of the main frac. These diagnostics can be used to characterize the leakoff rate, obtain a measurement of closure stress, identify the presence of multiple fractures, and quantify the amount of entry-friction (perforation or near-wellbore). In cases where potential problems are identified by diagnostics.the treatment design should be modified. 4. Pre job fluid viscosity tests should simulate pipe-transit by exposing fluids to a higher shear rate during the first few minutes of the test. As mentioned in SPE 143962. wellbore shear rates can influence the time it takes for borate fluids to develop&recover viscosity. The composition of the fracturing fluid should be optimized to minimize recovery time of the fluids so that viscosity inside the fracture is maximized. 5. In order to help control leakoff in the depleted interval. the service company should pump a biodegradable fluid-loss control additive in the pad. 6. During execution of the treatment, monitor the surface treating for signs of proppant bridging and be prepared to hold out or decrease the proppant concentration if needed. Depending on the fracture azimuth. it is possible for multiple fractures to propagate from the perforated interval(s). As these fractures grow in height. they will compete for fracture width development. Consequently, the chances of proppant bridging and risk of screenout increase. 7. Place an aggressive amount of live (not encapsulated) breaker in the flush. After shutting the pumps down at the end of flush, I would anticipate that some of the flush will continue to inject while fluid leak off into the formation. The aggressive breaker package should assist with near-wellbore conductivity. Frac Uiagrostics.LLC 1450W Grand Parkway S.Ste 6-121.Katy,Texas USA 77494 www.fracdiagnostics.com 13 Fracture Modeling Study Hilcorp Alaska,LLC Red#1 Appendix Appendix Table 9: Leakoff Pararne:ers Reservoir type User Total compressibility(1tpsi) 60e-Cvl _____ SPec Filtrate to pore fluid perm. ratio, KpWKI 10.00 Reservoir Viscosity(cp) 0.0Z Reservoir pore pressure(psi) 2900 'Porosity X0.15 Average pressure in fracture(psi) : 6000 Gas Leakoff Percentage(%) 13000 Reservoir Parameters Reservoir Temperature;"F i '56 V! Perforated trrery t and Initial Frac Depth are for Internal$12 Depth to censer of Perfs(ft) 8505 Perforated interval(ft) 27 Initial frac depth It 8510 Table 10: Layer Parameters Layer Top of Top of Stress Stress j Young's Poisson's Leakoff Pore Fluid # zone TVD zone MD (psi) Gradient modulus ratio Coefficient Perrn. (ft) (ft) (psi/it) (psi) (ft/mini/2) (mD) 1 0.0 176.2 5696 0.692 2.25e+06 0.311 2_584e-03 1.000e-01 --2 8216.0 85522 5500 0.680 2.75e+06 0.300 2.564e-03 1.000e-01 -3 8225 0 8561.4 5841 0.710 2.17e+06 0.325 2.584e-03 1.000e-01 4 8237.0 8573.6 5512 ► 0.669 2.68e+060290 2.584e-03 1.000e-01 5 8248.0 8584.8 5699 .... 0.690 2.41¢+06 r__.. 0.309 2.584¢-03 . 1.O00e-01 6 8261.0 8598.1 5980 0.723 1.73e+06 0.336 2..584e-03 1.000e-01 7 8274.0 8611.3 6545 0.791 1.20e+06 0.385 2.584e-03 1.000e-01 8 8283.0 8620.5 5901 0.712 2.41e+06 0.327 2.584e-03 1.000e-01 9 8291.0 8628.7 5613 0.677 2.83e.06 0.297 2.584e-03 1.000e-01 10 8300.0 8637.8 58480.704 2.33e+06 0.320 2..584e-03 1.000e-01 11 8325.0 8663.3 5641 0.677 2.71e+06 0.297 2.584e-03 1.000e-01 12 R350.0 8688.8 672.1 0.807 1.80e+06 0.396 2.584e-03 1.0000-01 13 8353.0 8691.9 5578 0.668 2.70e+06 0.289 2.584e-03 1.000e-01 14 8357.0 8696.0 7561 0.904 6.72e+05 0.453 2.584e-03 1.000e-01 15 8375.0 8714.3 5593 0.667 2.57e+06 0.288 2.584e-03 1.000e-01 16 8407.0 8746.9 5681 0.676 2.52e+06 0.296 2.584e-03 1.000e-01 17 8413.0 8753.0 5347 3 0.635 3.05e+06 0.258 2.584e-03 1.000e-01 16 8434.0 8774.5 5495 i 0.651 2.65e+060.274 2.584e-03 1.000e-01 19 - 84390 8779.5 5519 mm - 0.653 2.73e+06 �Y__0.276 2.584e�i1.000e-01 20 8452.0 8792.8 5462 0.646 2.73e+06 0.269 2.584e-03 1.000e-01 21 8457.0 8797.9 5920 0.688 2.80e+06 0.307 2.584e-03 1.000e-01 _ 22 8460.0 8801.0 6005 0.710 2.41e+06 0.3252.584e-03 1.000e-01 8806.1 41111MillinEle 4-233e-03 1.000e+00 24 8479.0 8781.6 6818 0.780 1.960+06 0.378 2.584e-031.000e-01 23 f 8482.0 8784.8 5594 0.659 2.835408 0.281 2.584e-03 1.000e-01 268500.0 8803.8 4564 0.537 ' 2.94e+06 0.229 4233e-03 1.000¢+00 27 8503.0 8807.0 " 4346_. . 0,511 288¢+06 .-_ 0205 _4.7920-03 2.700e+07 Frac Diagnostics.LLC 1450 W Grand Parkway S.Ste G-121,Katy,Texas USA 77494 wviw fracdtagroostIts.com 14 Fracture Modeling Study Hticorp Alaska,LLC Red#1 Appendix Layer{ Top of Top of Stress Stress Young's Poisson's Leakaff Pore Fluid 8 zone TVD1 zone MD (psi) Gradient modulus ratio Coefficient Penn. (ft) (ft) (psifft) (psi) (ft/min' ) (mD) 28 8516.0 8820.7 4713 0.553 3.53e+06 0244 4.233e-03 1.000e+00 29 8520.0 8824.9 5472 0.642 3.00e+06 0265 2.584e-03 _ 1.000e-01 30 , 8530.0 8835.5 4971 0.583 2.20e+06 0.203 2.584e-03 1.000e-01 31 8533.0 8838.7 6421 0.752 + 7.72e+05 0.358 2.584e-03 1.000e-01 32 8537.0 8842_95734 0.671 2.70e+06 0.292 2.584e-03 1.000e-01 33 9554.0 8860.8 5424 0-634 3.17e+06 0.257 2_584e-03 1-000e-01 34 8564.0 8871.4 5489 0.641 2.76e406 0264 2.584e-03 1.000e-01 35 8567.0 8874.6 5163 0.603 2.26e+06 0225 2.584e-03 1.000e-01 36 8569.0 8876.7 6093 0.711 2.34e+06 0.326 2.584e-03 1.000e-01 37 8575.0 8883.0 5842 0.681~ 2.35e+06 0.301 2.584e-03 1.000e-01 38 8578.0 8886.2 5700 0.664 2.63e+06 0.286 2.584e-03 1.000e-01 39 r 8582.0 8890.4 5478 0.638 . 3.14e+06 0.261 2 584e-03 1.000e-01 40 8597.0 8906.2 5887 0.683 2.4e+06 0.303 2.584e-03 1.000e-01 41 8630.0 8940.8 5719 0.662 2.80e+06 0284 2.584e-03 1.000e-01 42 8644.0 8955.4 5219 0.604 1.83e+06 0.226 2-584e-03 1.000e-01 43 8650.0 8961.7 7133 0.824 1.63e+06 0.407 2.584e-03 1.000e-01 44 8655.0 8967.0 5928 0-685 2.51e+06 0.304 2.584e-03 1-000e-01 45 i 8662.0 8974.3 5741 0.662 2.71er}06 0.284 2.584e03 1.000e-01 Table 11: Ethology Parameters Layer Top of Top of Lithology [ Fracture Toughness Composite Layering # zone TVD zone MD (psi.in1 ) Effect (ft) (ft) 1 0.0 176.2 Shale 1706.3 25.00 2 8216.0 85522 Sandstone 1327.4 25.00 3 8225.0 8561.4 Shaley Sand 1656.9 25.00 4 8237.0 8573.6 Sandstone 1272.3 25.00 5 "' 8248.0 8584.8 Shaley Sand 1587.9 25.00 6 8261.0 8598.1 Shaky Sand 1420.9 25.00 7 8274 0 8611.3 Coal 1294.9 25.00 8 8283 0 8620.5 Shale1859.8 25.00 9 8291 0 8628.7 Shaley Sand 1564.9 25.00 10 8300.+3 8637.8 Shale 1876.8 25.00 11 8325.0 8663.3 Shaley Sand 16052 , 25.00 12 8350.0 8688.8 Shaley Sand 1776.1 25.00 13 8353.0 8691.9 Shaley Sand 1467.2 25.00 14 8357.0 6696.0 Coal 1127.6 , 25.00 15 8375.0 8714.3 Shale 1705.2_.. .W ........_ 25.00 16 8407.0 8746.9 Shale 1886.9 25.00 17 8413.0 8753.0 Shaley Sand 1515.3 25.00 18 8434.0 8774.5 Shaley Sand 1584.2 25.00 19 8439.0 8779.5 Shale 1902.7 25.00 20 8452.0 8792.8 Shaley Sand 1446.9 25.00 21 8457.0 8797.9 Coal i 1192.5 25.00 22 8460.0 8801.0 Shale 1840.8 25.00 23 ._8465.0 8806.1 Sandstone ` ,. 1.00 24 8479.0 8781.6 Coal 1507.2 25.00 25 8482.0 8784.8 Shale 2000.0 25.00 Frac Diagnostics.LLC 1450W Grand Parkway S.Ste G-121,Katy,Texas USA 77494 www.fracdiagnostics-corn 15 Fracture Modeling Study Hilcorp Alaska,LLC Red#1 Appendix Layer Top of Top of '' Lithology Fracture Toughness Composite Layering # zone TVD zone MD (psi•in') Effect (ft) (ft) 26 8500.0 8803.8 Shaley Sand 1834.2 25.00 _ 85030 8807.0 Sandstone MIIIIIIL 11845 1.00 28 9516.0 8820.7 Sandstone 1123.3 25.00.___. 29 9520.3 8824.9 Shale 1993.2 25.00 30 8530.0 8835.5 Coal 1503.2 25.00 31 8533.0 ' 8838.7 Coal - 1379.1 ! 25.00 32 8537.0 8842.9 Shale 1953.8 1 25.00 33 8554.0 8860.6 Shaley Sand 1424.1 1 25.00 34 1 8564.0 8871.4 Shale 1872.0 25.00 35 t 8567.0 8874.6 Coal 1418.9 25.00 36 " 8569.0 8876.7 Shale 1813.0 25.00 37 8575.0 8883.0 Sandstone 15612 25.00 38 8578.0 8886..2 Shale 1966.7 '25.00 39 8582.0 8890.4 Sandstone 1419.8 2500 40 8597.0 89062 Shale 1947.3 25.00 41 8630.0 8940.8 Shaley Sand 1495.5 25.00 42 8644.0 8955.4 Coal 1356.8 25.00 43 8650.0 89617 Shale 1672.7 25.00 44 8655.0 8967.0 Shale1686.5 25.00 45 , 8662. 8974.3 Shaley Sand 1542.8 25.0(? Frac Diagnostics.LLC 1450W Grand Parkway S. Ste G-121.Katy,Texas USA 77494 www.fracdiagnostics.corn 16 Frac Chemical Listing: Client: Hilcorp Alaska,LLC Sbloberger Well: Red-1 Basin/field: Nikolaevsk State: Alaska County/Parish: Kenai Peninsula Borough Case: 6964637 Disclosure Type: Pre-Job Well Completed: 3/5/2017 Date Prepared: 1/30/2017 1:39 PM Report 10: RPT-47507 Fluid Name&Volume Additive Additive 0e<crict F103 Surfactant 1.1 Gal/1000 Gal 80.0 Gal J218 Breaker 0 9 Lb/1000 Gal 70.0 Lb J450 Stabilizing Agent 0,5 Gal/1000 Gal 40.0 Gal J475 Breaker 4 7 Lb/1000 Gal 350.0 Lb VF1Z5FIeeD:WF125 74.508 Gal 1580 Gelling Agent 25.1 Lb/1000 Gal 1.8700 Lb J604 Crosslinker 2.4 Gal/1000 Gal 180.0 Gal 1071 Clay Control Agent 2 Gal/1000 Gal 150.0 Gal 6 M002 Additive 2 Lb/1000 Gal 150.0 Lb M275 Bactericide OA Lb/1000 Gal 30.0 Lb 5526-2040 Propping Agent varied concentrations 111,050.0 Lb rnr total ta4rrneNoe a t'ere rohtrs choir represents thcanon or eemer and edeiros.Water u supaned be chine CAS Numb, Water(Including Mix Water Supplied by Client)* "'84% 64-19-7 Acetic acid(impurity) c 0.0001 96 67-48-1 2-hydroxy-N,N,N-trimethyletharwminium chloride _ <1 96 67-63-0 Propan-2-ol <0.1 96 102-71-6 2 2",2"-nitrilotriethanol <0.1 96 107-21-1 Ethylene Glycol <0.1 % 110-17-8 Fumaric acid <0.01 96 111-76-2 2-butoxyethanol •:0.1 96 -_._,- 112-42-5 1-undecanol <0.01 96 -. .... " Acetic acid,potassium salt — �— � 127-08-20.0001 % 1310-73-2 Sodium hydroxide a 0.1 96 1319-33-1 Boronatrocalcite a 1 96 1330-43-4 Sodium tetraborate c 0:01 96 2682-20-4 _ 2-methyl-2h-.sothiazol-3-one -0.0001 96 _ 7631-86-9 Non-crystalline silica(timpurity) -0.001 % 7704-73-6 Monosodium'umarate -0.01 96 7727-54-0 Diammon,umperoxidisulphate <0.1 % 7786-30-3 Magnesium chloride <0.001 96 9000-30-0 Guar gum <1 % 9002-84-0 polyStetrafluoroethy,ene) c 0.001 96 10043-35-3 Boric acid <0-01 96 10377-60-3 Magnesium nitrate c 0.001 96 14464-46-1 Cristobalite -0.0001 96 14807-96-6 Magnesium silicate hydrate(talc; <0.001 96 14808-60-7 Quartz,Crystalline silica <C.0001 % ' 25038-72-6 Vinylidene chlondQ/ copolymer _e rryl' methylacrylate a 0 O1 26172-55-4 5-chloro-2-methyl-2h-isothiazolol-3-one •:0.001 % 34398-01-1 Alcohol,C11 linear,ethoxylated a 0.1 96 66402-68-4 Ceramic materials and wares,chemicals -15 96 68131-39-5 C12-15 alcohol ethyoxylated a 0:01 96 91053-39-3 Diatomaceous earth,cakined c 0-01 96 125005-87-0 Diutan- m <0.001 96 r i •Mewoteruswished bithe client.Schlu tbeWetrhaspei zrmednoanaysuatthewaterandcannaprosrdeabethdat nofcommentsthatnayhawbentaddedtoIketweetbythird-prones. •The evottween of a tern d documen 4 performed bawd an the renvwsmon cf the identified produces to the event that such tacpasamaatt mjormon'ae,on,010110/1t0 GOC-Chetatals os of the dote of the document was produced.Any new updates walnut beeetectedIra this docvme t. Section 13: Post Fracture Wellbore Cleanup and Fluid Recovery Plan 20 AAC 25.283(a)(13) Post fracture stimulation flow back well to a tank(s)to bleed down pressure and clean up the well. After the well flows back on its own,a Coil Tubing Unit will be placed on the well to clean out the remaining well bore using nitrified fluids. If the well loads up and is unable to sustain flow. If well will flow, it will be lined up to production. Coiled Tubing Procedure: 1. Set CTU BOPE and PT to 4,500 psi. (Note: Notify Inspector of BOP test giving 24 hours notice to witness) 2. RIH and cleanout frac sand/frac fluid to a blowdown tank until it maintains pressure to use portable test separator,with filtered 2%KCI brine and N2 as needed to 9,011' MD. 3. POOH jetting liner and tubing clean. RD CTU. 4. RU SL. Drift and tag tubing to maximum TD with GR/JB. 5. RDMO Coil. RDMO Pumping equipment. Once well fluids have cleaned up with gas to surface,the well will be turned over to production and placed into the system. Note:All flowback fluids will be taken to Hilcorp's Kenai G&I disposal facility and injected. 1_ � A• N N N N N N 0 W ,--I c-I c-I 1-1 c-I c-I N CO 0 0 0 0 OOO 0 0 0 0 N 0 cv NI rss CQ• LL \ LL \ LL \ LL \ LL -"•••• LL \ N G N rl N ci N rl In rl rl In c-1 i V N N N N N N j L 13 CU C c LL C v N a, C a) o v cNi as +� +, ra o z o 4- `v vi v 3 LY.3 as o c r° N o E N ben Y 0 c ° - N (/) a) Ln L 3 QJ • — E a) L Q 4-, rn tD co i - ~ o w F- T r+- Cvs O 0 -C _C -0 Cl) 0 LLo C ai p COC CD ^ c a) O a E u — .� to E N cc tin ° - 00 c 1 O i O - Q ro O a) r- L i C ° L L O C .'CS U CO }, L a) v Ln ac a) O O 2 O co 0 L L 0 a) a) LA L./ 'a L 0 �' Z • a +� :5-. Cl) 1 ) m r1 ao •L' ;° 0N t° o P +, � +, cr °; C g ° v ' O N Q ° n ° 3 O to '3 L ., Ln U •@ ro co coo •N L N a co -° N > ci -0 .4-, u0 L L 0 •L O c °) = C a L v ° Cl) IX -C) v co Lf) 0 °�' CL -0 *+ CA O _ +J as" L a) O 7 0 rt N a Cl.) ,, ° r° 0 CIO ••v CO V 0J y CO 4-co c u do Ln v ° - r`o a s +' C tin c co 3 t = tint L C • Z H C C c c ON t v LL O 3 C > ° .Li a) O $ m C - 0 a) 3 ^� ` o o o o o .Ln O In r1 a) O > 3 too L C .7 Y 0. >` '+•+ +; 4= +, _c E 't' .3 N '� -0 LL }, do Ln — L,) 0 0 '5 .0 2 ,V N C 03 oi u co as a a s a u +, (1), r1 a) -0 a) c eL a) o c 3 C ••- v c a a aoo L u C 3 ro co co co co Ln „Cl)� CC v�Y- ° v o o 1_ L LI- Q C m ti° CU I- - a) o a) Ln L v) C a) + vi 0 ° O a) 4 +' Ln oo "-' t C �' a 3 • 3 3 3 2 '3 v v 3 8- ro aui n T '3 E m f_ c "' °u •E Ln ori a) N cti 3 o L a) a) O V' C o n a) V v N 0 CL a) off CU v • u c z a 0- ~ C 0> co 0 00 ° -a M °°° � °) o Q a) t ,-,(1'm o 'a '4- ---1- o a, I o 0 0 o - E r1 ro o -5 2 ° r° 8 —„,° 3 L o o C -0 0 u tip LL 41. a a a Pc a` 0 3 o ro L L n o t 0 1? o o a) c V Q C (cc -° co N g d '° •v) ° L2 Ln — C ro r1 (.) cC 2 a) a 3 N ( 0 v \ ../F4 -p Z E •-, IC 3 0 .L'Imm t 0- a § a 00 = v N r-I Lo °i 'v `� LA 0 L. 3 3 a a a c) o a s V L. �n 3 °1 v c iCt -3 v u °i Q -01 a 3 v °a) O Q 'a Q m N N v Z1 E a a a -6',,... teaa ._ C L. r 4° a 000 O a 4 L Q a 0u CZ 12� 0 a h - N r, A• N n N N N N N. N O N r••I t--1 c-i ,--i r-1 1--1 e-I a--i N cm �5, o5, o5o 5o 5N J0 >. o oN N CL E U ami 0 .�—I 0 'moi U .�-1 U '1' w r�-1 .�-1 to T-11) i U N N N N N N • N N Co 1.2. Lu_ a) ;'J M •N O p 00 fn .N 3 • n o� v) a) U) o •N f° U) C co a in O o0 O a a O •c O a V co 0 00 " ate•) v c c 3 u io CU fl in 0u 'i O _o .- a O v O S ^` M EC 7 E � -aO Ln ny � L.) co ,N -It o O fp O O - p \ cp E co v, E a 44, c a4..)> 4-, co L >` a"'' Q co I . 0. y •'N a co ") a � M C °c o 00 o 4-, c m � t C as a) c c o 0 0 ay o a fco " CO v, O 3 _V O ani a o o a) I- c>o >- o •,"-J N a`) v N a) +-A 0 > _ - CO 00 co >' > L i.t -� C C C C C -p C `� vi 0 _ ++ "O a i f0cu I/�� ` O o O O O a O f^ O 4- co a s Y a ,u yi /` +� , ++ ++ N +� ay of •C t n N O O iri aJ Q L v+ u u co u u 0- c = 0 0 0 o0 `� CO b.0 = o n on. • 0_ 0- a -0 Q .� a o 3 4-v Z O C 3 o_ CO co co co co o co co o 00 N PO CO o c 'o a 00 co .� (/� *' _ � 000 'cc `n° cN o c - E -0 3 3 3 3 3 3 L 00 c vl °° `° � - Nona C Cr-: cc) ++ -o O + -o a o a cin o c c c o N t� C a a) a a) a v, a > U c (o m 4 a o 'O :2 a o0 -p o 0 L o +� N E O N i o 0ell n vi •> > > > > c > a C7 Q i o = ,n = u -a a N a LL 0 0 0 0 0 D 0 v IA n co U) -0 co U ,_ C o +' co d' tit 3 a a a` a` a .,_, a` }, 0. 0 U 00 ca -a U v) .- -i L a 6) Q N 3 c U) v CO 0 0 0 a) v c = a U fL 0 0 0 Z c 0 I.; c +, -c 0 0 0 N aa o ° o a a •c N v v I , c0 o : iC3 d1= c o, a1N4,oat `ti O 0 0. a, o, ,p `tiMI c cn a., 0 u0 h en V 1 rt) a 0 00 1 a`o o c c o p .Q o ° a s U v 0 L. r-I �, v a) c ui a O c vL a N ra L E E a, v N u ° a, m a c p v L A a u u nI) 3 ¢ V) c o 0 o p 0) v (Si 3 = s a o v a 'a, ✓ CC %N j aJ o O s v N t v v v u ° -zc QL. a, a, , H L a 3 a 'c, a v ° a m v v E 4- ° t'm 11 a v v a v• Q 'a, m v w 0 I 'if,' E 0 v a _ ° ° a L -� '� -� H -� C -� ° --� N H - . a) -'� -crl C -S - • v -� a 0 a v, a ° ° aa L c a a 0 0 0 t , a, L 01 fa 1 M a. u u c.9 0 Q 1 —_ N r1 A• N N N N N N N N N 0 a) c-1 c-1 r-I r-I ri i--1r-1 r-1 1--1 r-1 N w >N0 > ON 0 0 > > N > o N > N > N > N Ea 0 0 I1 0 0 0 0 0 0 0 N V t1 V r•I N c-I (..) ri V r•1 U c-I U c-1 V ri V c-1 V c-1 i U N N N N N N N N N N CO 12- a) 0 11 C 23 N O L CO 7 r-I pp a- L a.) f6 -0 c U 3 ••- a, -0 v CO OO 0 (0 u) +, -C 0"i% (a - . c c Ir, c cr 0 .0- 'c +, N O 0 �t N ,co V CO oo ,r ° o cco o I G 00 00 Y 'Lo -0,_, _0 O ;F 4O a) u) Om a) r0 C to *- O +, La •- (o (a E o 0 CI r'lc 3 ON L i y J qo 4-0 M v CO MS t .0 a) v c °c° o up 0000 (� Q d c Y v p .+ N 0 o •— Z of O u +� = a .4 r1 = . '� ro ^Q p +' O O O a) -� 0 c' a30 O O O O O O N O CL /` E a) '+, •+, +•' L r0 -0 a) ++ +, +, . j., L!1 '+� Q L LL v o v w c CO CO v v o cro - 0 vi - o_ SZ oS- 0 ' r6 O a1 C. Cl. a Q 0. O •+, 0- a) on O O_ ' o_ a an -c 4, +, N 0. o_ } a a 0. a C C 00 CO CO Cl) a) O L to (o C ro ro (o °; ro 3 _ •_M (o X •L (n >- 1__ +�, +�_, L +, a) O 4-) ate-+ o_ aCO te- S ,�-, 3 •. 3 3 N 3 3 oa 3 3 a) g 3 ✓ IZr -C � a) a) a a) E a) v y a) a a) v o ami - 03 c a o 3 ,� -a -a a -a -a E N -c en O +, '> '> ,�„ +-' 'X 1--+ +� > '> c '> '> ' VI > o N In > a) _ -D 0 ro 0 v o o 0 0 0 ra a) a, o oA V C' �', COL o L X a) 12 L L L 0 L L L L L L L (o 3 +.4 a n. H Cl) ac . E a a a a a a 11 a0, a a a, L. N = a, 4S , O z O a, O 0 t o >` Q 'a a ao v •• ti LI i a QQ Co h Qj a, a 2 0 H' tu u o I� Ln• 04. 04) is d sa c uo •o "o� a) c° aa, ao • _c c s cM 0 � � c o v a a, vL v o a v3 vu v • aN ` v ` � a `E a, o an z fa c o 0 q) O. I u init o a• ° cv; i N o a o Eo Ce = _ v 3I- i .c 4, vic _ a 0 '0 NH y . S H a Q o O ' c •c o Q °• ti , oQ o c t0 c a ` a, 3 I0r4 0v0 O •-I .. •-.1 +, ti E IN a N N a) N )N EIO N N u °� o � 0.a ° ' L. aaE �o ' 3 �a o� ac � aO aa �a o `a o o aa a E r a L. ao R L m a u U C7 O a r N r-1 N G! % r�-1 r�-I .x-11 .--1 r.-I .-I .-1 NJ O w 30 o o' � o o oo CV CD N CCNI N-- al 0 p p J O O - 0 N ,I,o . V a�•1 U c�-I V c�-1 N U c�-I V —1-1 V rri i o !.... N N N N N N N j L a) C V L.L. l6 _• C2 co .N a 4! -o E V, t C 41 O 0 a CO a co N V O - cu •- N i v1 O 3 c CU .0 ^ 0 0 vim •'-" va °+-, V CO v, co v a, °1 g +, L v I cu 11'1 co = CCO VI E O a) ao >= N V+ u C o2• o cu a Q v a op 0 l7 a on ..... x 4-, L v, •N }' M c Co f° 4-4 c a a v 0 VG� a) N L = O O a 0 y !_ ? C O coo O 00 `� - Z I C _o — o N u1 > C c Q1 ` O a O - N O t r-1 pc O of QL. U N co v L .� co •� c _ - . _ a _0°3 ao floes X0000 0 co m m L V) 1 v 0 0 0 0 N 0 3 co m on Ln Ln }, 00 3 as c +� +•, -a .0 Co CV N 0 'o •_0 �• aj - • Q O ••- -O GI N -a Q_ - O O Y !? a s- 0, •'o in o 'o '� 0 o 0 ' a cc °' LL lizrL O L > N L O to c� O a m ° a m 0. = vY m 0L Q a - N 3 cu v CZ H L Z cu O +0 d u a. 4 0 v o � a H ° oc , 025 - _ � a a CO fa aO a O O o+ a;co L ov(N a _ 30 ocoa a4..., cis a)v a o .a Qv ' v CI. ° o v a 0a o, CC 0 cu < 0 v-4 U O v1 a v) v 4,1 o f u O O O .t.)CD 0 � ti �I a o ti °'� N c o ti N 10) v +" c o Cs •a a, 1 �L. °_ •' a v L '0 _ 1 °L ' vcc°1 140 a EvvOov ovO 4� u) c . N v p L O v o v --. v p L. o o t -. C.7 Q h N 0 c1) N4 d N:- O. O. N E >. U = - o 4-+ m N a) ... Q to U c V 0 LII 4- O a) + 4- O iio M C C V le c • co Z E 0. o C2. L (11 n '0 o b.12 c C C 3 c 'i (i) c 3 • ' a 4-10 144 aa) U 00 -0 L O a) + oo a) co U - a N0 3 • v I Z 4, E Q c H a, o 2 d s v 'N M ._. 0. E 00 a`o v cu c o co a Ti u co N LA a L — H cV o a Yoc Q c c co Q o 0 • U u N L. a HI 3 a, a, L U a, cm {, L 4- a 3 c a 4-) 0 ea 0 1 v ov a a 0 . i at a.. c i c aav to - c • acEvo co Ul. ao C7a ` c v z Q r N n. O Na) i+ d N Q. N E i O f0 V E v u_ N N ,fi,I _A p) (--iv .1\...(---,,) 1---, .4_,\1 '116,,,v, \,,i1\.-01 ,-/.\r/-\.,\,) V 00 ,� L.1 LA o Oil o a ac� 4I 0 \.4%.414ecv, o cn = z r �'I III ce4m/ eel 0 Ixv N P4 2 ut z 111/ 1111I1m1111l_ •a ,, it 21 OA _ C 3 o o \ m a ' c 1- t = ••• I ci o 0 ..E. 000 0 u, v L ami .. HIM_� 1 ; to) CO CC Cr Ce 1111 III N U p MEM 1-4-3 innit MOM to N a to — 0 _ R L Z = CJ r 75 L (n Q L = > — �` L C > 2 CU _ ° 3 C v n CI. �, V D c JO OU E 00 M v OA O 40 000 0 • 1 N I 00 I N § UCe m N C ` 41 Q '. A '.' - 44 4 ' C = z a Q N * t Q N _ H u L C7 ° % -- i,v - -- f6 CO1\i\\,.,,,,,,,) \VI 7 0 f6 _ �O O O O I s .442 U1 II ' u U � � � 1 6 a t E. m f c l.1 I i N Q u� I d 0 a GI c. s. • • Schwartz, Guy L (DOA) From: Ted Kramer <tkramer@hilcorp.com> Sent: Saturday, February 25, 2017 9:59 AM To: Schwartz, Guy L(DOA) Cc: Chad Helgeson Subject: Red# 1 Frac Sundry Application Section 7 Request for Variance Attachments: Frac Application Section 7- Supplement.docx Guy, Hilcorp requests a variance from 20 AAC 25.283 (a) (7) . Although the treating pressure of the proposed fracture stimulation is estimated to be 5,800 psi, Hilcorp requests to pressure test the tubing to 5,000 psi. The reason for the lower test pressure is that the tree and wellhead on the well are both rated to 5,000 psi. Although the safety factor of the tree and tubing hanger allow for pressures as high as 6,500 psi., Hilcorp does not believe it is best engineering practice to rely on the safety factor for the purposes of conducting a pressure test. Hilcorp also believes that a 5,000 psi pressure test is adequate for this application for the following reasons: A.) During the fracture treatment, Hilcorp plans to hold 3,000 psi pf back pressure on the 3-1/2"tubing by 7" 29# casing string. Therefore,the effective pressure exerted on the tubing will be 3,800 psi.which is well below the 5,000 psi recommended tubing test pressure. B.) During the fracture treatment,the wellhead and tree will be protected by using an Oil States Tree Saver which will effectively isolate these items from seeing treating pressures. The tree saver is rated for 15,000 psi. For these reasons, Hilcorp requests that this variance be granted. Attached is a supplement document of how Hilcorp plans to pressure test the 3-1/2"tubing. Please include this Supplement document into the Sundry application. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. O 907-777-8420 C 985-867-0665 1 • • Wallace, Chris D (DOA) From: Wallace, Chris D (DOA) Sent: Friday, February 24, 2017 10:34 AM To: Ted Kramer Cc: Schwartz, Guy L(DOA) Subject: RE: Hydraulic Fracturing Sundry Application 317-058 Red 1 (PTD 2040840) Ted, After some discussions here,we do need a pressure test of the tubing and cannot grant a waiver based on a tubing caliper log. Please coordinate the revised procedure with Guy as he is progressing the sundry application. Thanks and Regards, Chris Wallace,Sr. Petroleum Engineer,Alaska Oil and Gas Conservation Commission,333 West 7th Avenue,Anchorage,AK 99501, (907)793-1250(phone), (907)276-7542(fax),chris.wallace@alaska.gov CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From:Ted Kramer[mailto:tkramer@hilcorp.com] Sent: Friday, February 17,2017 4:10 PM To:Wallace, Chris D(DOA)<chris.wallace@alaska.gov> Subject: RE: Hydraulic Fracturing Sundry Application 317-058 Red 1(PTD 2040840) Chris, Thanks for your e-mail. The water well mentioned in Section#3 is on the Section#2 Plat Map as Water Well#1 (Abandoned). This water supply well was drilled exclusively for providing water for the drilling operation. The well was Plugged and Abandoned in September of 2008(prior to Hilcorp taking over operations). We are checking pour records but so far have not found any testing information performed on the well. The abandonment of the well involved pumping grout from the bottom of the well up to 37' below ground level. The wellhead was then cut off 22 feet below ground level. Unocal held a Temporary Water Use Authorization Permit for the well (TWP A2004-07) until February 3,2009. With regards to the tubing pressure test in Section 7, Hilcorp would like to ask for a waiver of 20 AAC 25.283(c)(2). In lieu of a tubing pressure test, Hilcorp proposes to perform a caliper survey of the tubing. The rational of substituting this test is as follows: 1.) The tubing of the Red#1 well is rated to 10,160 psi. The 6,400 psi pressure test is 63%of the tubing rating. Running a caliper will verify that the tubing is in good shape. Therefore,the frac pressures anticipated will be well within the pressure ratings of the tubing. 2.) Hilcorp will still perform the 3,500 pressure test on the IA. This will pressure test the casing and the liner top packer to 3,500 psi. Since we will be holding 3,000 psi of pressure on the backside during the frac,the differential pressure across the liner top packer is not expected to exceed the 3,500 psi test pressure. 3.) Not performing the pressure test on the tubing will prevent dumping outside water on the formation in advance of the frac and having it sit on the perforations(we would want to perform the test ahead of time.). • • 4.) If the caliper log demonstrates that there are anomalies in the tubing; then a decision could be made to either a.) perform a pressure test,or b.) pull the tubing and run a frac string. Please let me know if the this method of testing the tubing(with a caliper log) is acceptable to the commission. Sincerely, Ted Kramer Sr.Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 From:Wallace, Chris D(DOA) [mailto:chris.wallace@alaska.gov] Sent:Tuesday, February 14, 2017 10:58 AM To:Ted Kramer<tkramer@hilcorp.com> Subject: Hydraulic Fracturing Sundry Application 317-058 Red 1(PTD 2040840) Ted, We are reviewing the stimulation sundry for Red 1. Section 3 has a comment about a "water well drilled for drilling operations at the Red 1 well". What is this and is it identified on the plots and was it tested? Section 7 does not make mention of a 3.5 inch production casing/tubing testing plan? With an expected 8800 psi max treating surface pressure, 3000 psi backpressure on the 7" IA,the differential pressure of 5800 psi would necessitate a minimum test of 6380 psi for the tubing? The pressure test requirement of 20 AAC 25.283(a)(7)tubing/frac string does seem to be met. The 110%testing requirement of 20 AAC 25.283(c)(2)tubing/frac string does seem to be met for these pressures. Thanks and Regards, Chris Wallace,Sr. Petroleum Engineer,Alaska Oil and Gas Conservation Commission,333 West 7th Avenue,Anchorage,AK 99501, (907)793-1250(phone), (907)276-7542(fax),chris.wallace@alaska.gov CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.Qov. 2 STATE OF ALASKA v ' ALIIIL OIL AND GAS CONSERVATION COMINSION LFA(; 0 9 2016 REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Plug Perforations H Fracture Stimulate H Pull Tubing ❑ Operations shutdown H Performed: Suspend ❑ Perforate 0 Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: Reperforate El 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑ Exploratory ❑✓ 204-084 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-231-20021-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0390514 Red 1 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Nikolaevsk/Tyonek Undefined Gas 11.Present Well Condition Summary: 9,025'; Total Depth measured 12,458 feet Plugs measured 9,192;10,420 feet true vertical 12,047 feet Junk measured N/A feet Effective Depth measured 9,011 feet Packer measured 4,373 feet true vertical 8,697 feet true vertical 4,372 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 50' 16" 50' 49' Surface 1,790' 9-5/8" 1,790' 1,789' 6,870psi 4,760psi Intermediate 4,601' 7" 4,601' 4,600' 8,160psi 7,020psi Production 10,930' 3-1/2" 10,930' 10,551' 10,160psi 10,540psi Liner Perforation depth Measured depth See Attached Schematic r i-< SCANNED MAR 3 0 201 r True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.2#/L-80 4,412'MD ND Seal Assembly Packers and SSSV(type,measured and true vertical depth) in Baker ZXP Pkr;N/A 4,373'MD 4,372'ND N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 266 12 0 262 Subsequent to operation: 0 353 16 285 301 14.Attachments(required per 20 AAC 25.070,25.071,8 25.283) 15.Well Class after work: Daily Report of Well Operations Ili Exploratory❑ Development❑ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL 7 Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG H GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-551 Contact Taylor Nasse-777-8354 Email tnasse(a hilcorp.com Printed Name Chad Helgeson Title Operations Manager *z� //// Signature Phone 907-777-8405 Date ) ?IV)G Form 10-404 Revised 5/2015 f - /j /4 /7--, ,..,(74 y4 Submit Original Only J RBDMS vDEC 9 2016 • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date Red 1 E-Line 50-231-20021-00 204-084 11/11/16 11/11/16 Daily Operations: 11/11/2016- Friday Shut well in around 8 am. PTW and JSA. Spot and rig up lubricator.Arm gun, pressure test to 250 psi low and 3,500 psi high. RIH with 1-11/16" GG, 2-3/8" x 20', 5 spf, 60 deg Connex perf gun to 8,970'. Ran correlation log and send log to town. Log was off 3' so we got ok to perf from 8,803' to 8,823' by Jacob Dunstan (procedure said 8,800' to 8,820'). Spotted gun from 8,803' to 8,823' and fired with 1,650 psi on well. POOH and all shots fired'. TP- 1,725 psi. Rig down lubricator and turn well over to field. • Well Name: Red #1 SCHEMATIC Field: Nikolaevsk State: Alaska API:50-231-20021 Conductor: 16",82.77 ppf, K-55 to AOGCC:204-084 50' 352'FNL&392'FWL Sec.8,T4S,R13W,SM Surface Casing:9%",47 ppf, L-80, BTC to 1790' RT-THF: 17.22' Cmnt with 110 bbl of 12.8 ppg lead and Tbg lift threads-3W IBT 45 bbl of 15.8 ppg tail"G" Tree cxn-2'/2'Bowen cxn Intermediate Casing:7",29 ppf,L-80, BTC to 4601' Cmnt with 53 bbl of 12.8 ppg"G"lead lead and 30 bbl of 15.8 ppg"G"tail. Production Tubing:3'/z',9.2 ppf,L-80, IBT to 4412' -Annulus loaded with 7.4 ppg base oil 7 >Z Completion -Chemical injection sidepocket mandrel at 2502' (Macco SFO-1C-I)with 1/4", Open Perfs: 0.049"wall SS chemical injection line T-80:8768'-8777'(6 spf,8/3/04) -Locator sub @4378' T-80:8795'-8820'(3 spf,7/23/04) -Baker 80-40 seal assembly T-80:8800'-8820'(5 spf, 11/11/16) — 13'of 4.00"OD seals Isolated Perfs T-90:9056'-9076'(6 spf,8/3/04) Production Liner:3'/i',9.2 ppf,L-80, IBT T-100:9210'-9280'(3 spf,7/19/04) liner from 4379' -10,930' G-1: 10565' 10610'(3 spf,7/17/04) = Baker ZXP packer,Flexlock liner hanger& 80-40 sealbore at 4373' Cemented with 209 bbl of 12.0 ppg Litecrete Plugs: g -Halliburton CIBP @ 9025'capped with 14'of cement(5/19/11) -EZ-Drill CIBP at 9192'capped with 40'of cement(7/23/04) -EZ-Drill CIBP at 10420'(7/19/04) Directional Data: max hole angle=29.1 deg , , KOP=4800' max dogleg<3 deg/100' PBTD=9152' TD= 12,458' 12/9/2016 Updated by DMA fV OF � • • yb",\1//7s., THE STATE Alaska Oil and Gas � f LAS :A Conservation Commission - _= oA 333 West Seventh Avenue ! GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF ALAS� Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager9 `j 1i Hilcorp Alaska, LLC �NED 1"�-fl 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Nikolaevsk Field, Tyonek Undefined Gas, Red#1 Permit to Drill Number: 204-084 Sundry Number: 316-551 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P Foerster Chair 5f' DATED this 01 day of October, 2016. RBDMS V' NOV - 1 7n16 • • RECEIVED STATE OF ALASKA i`}f T2 5 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS /A0 3// /.620 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate 0 Repair Well ❑ Operations shutdown 0 Suspend ❑ Perforate Q • Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Reperforate ❑� 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number: Exploratory Q ' Development ❑ 204-084 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-231-20021-00 . 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? 20 AAC 25.055(a) Red 1 Will planned perforations require a spacing exception? Yes ❑ No ❑., 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0390514 . Nikolaevsk/Tyonek Undefined Gas • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD: Effective Depth ND: MPSP(psi): Plugs(MD): 9,025'; Junk(MD): 12,458' • 12,047' • 9,011' ' 8,697' 2360psi 9,192';10,420' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 50' 16" 50' 49' Surface 1,790' 9-5/8" 1,790' 1,789' 6,870psi 4,760psi Intermediate 4,601' 7" 4,601' 4,600' 8,160psi 7,020psi Production 10,930' 3-1/2" 10,930' 10,551' 10,160psi 10,540psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.2#/L-80 4,412' Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): Seal Assembly in Baker ZXP Pkr;N/A 4,373'MD/4,372'ND;N/A 12.Attachments: Proposal Summary Q Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory Q Stratigraphic ❑ Development❑ Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: November 8,2016 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS L ' WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Nasse-777-8354 Email tnasseehilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature ('/7r Phone 907-777-8405 Date IC/Zy//G COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. \ Plug Integrity ❑ BOP Test iiMechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes No Subsequent Form Required: ( -- O' RBDMS t'— ❑ f `-� NuV - 1 2016 .k-Aad'" iAl. itto APPROVED BY Approved by:ot-ye, � COMMISSIONER THE COMMISSION Date:/ 3-3 �-�/ Submit Form and Form 10-403 Revise 1/2�- 10-26,16 015 for 12 months from the date of approval. Atta ments in Duplicate ofttotNioAstid (old /0.2.5 „/4 • • Well Prognosis Well: Red#1 Ililcora Alaska,LL. Date: 10/24/2016 Well Name: Red#1 API Number: 50-231-20021-00 Current Status: Active Gas Well Leg: N/A Estimated Start Date: November 8th, 2016 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 204-084 First Call Engineer: Taylor Nasse (907) 777-8354(0) (907)903-0341(M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907)229-4824(M) AFE Number: Current Bottom Hole Pressure: 3,042 psi @ 8,652' TVD (Based on Static Survey 11-13-15) Max. Potential Surface Pressure: 2,360 psi (Based on 3 month pressure buildup) Brief Well Summary The Red#1 was drilled and tested in 2004 but didn't flow until 2012 when Hilcorp Alaska ran a pipeline and installed production equipment. The well has since produced—0.8 Bscf with rapid production runoff. Recent pressure buildup analysis indicates substantial damage (high skin)suspected to be from fines migration. • The purpose of this work/sundry is to reperforate the T80 sand. Notes Regarding Wellbore Condition • Make GR run and tag bottom prior to performing work. • Well is currently flowing 275mcf at 261psi tubing pressure. E-line Procedure: 1. MIRU E-line, PT lubricator to 3,500 psi Hi 250 Low. 2. If necessary, bleed pressure down as requested by the RE to establish a drawdown on the formation. 3. Perforate the Tyonek sands with 2-3/8" 6 SPF 60 deg phased perf guns. All intervals are planned for 12 SPF so each zone may be shot twice. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. Proposed Perforated Intervals Zone Sands Top(MD) Btm (MD) FT Tyonek T80 ±8,800' ±8,820' 20 4. RD E-line. 5. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic • • Well Name: Red #1 Field: Nikolaevsk State: Alaska API:50-231-20021 I Conductor: 16",82.77 ppf, K-55 to AOGCC:204-084 50' 352'FNL&392'FWL Sec.8,T4S,R13W,SM Surface Casing:9%",47 ppf, L-80, RT-THF: 17.22' • BTC to 1790' Cmnt with 110 bbl of 12.8 ppg lead and Tbg lift threads-3'/z'IBT 45 bbl of 15.8 ppg tail"G" Tree cxn-2W Bowen cxn Intermediate Casing:7",29 ppf, L-80, BTC to 4601' Cmnt with 53 bbl of 12.8 ppg"G"lead lead and 30 bbl of 15.8 ppg"G"tail. Production Tubing:3'/z',9.2 ppf, L-80, IBT to 4412' X -Annulus loaded with 7.4 ppg base oil Completion -Chemical injection sidepocket mandrel at 2502' (Macco SFO-IC-I)with 1/4", 0.049"wall SS chemical injection line Open Perfs: -Locator sub @4378' T-80:8768'-8777'(6 spf,8/3/04) -Baker 80-40 seal assembly T-80:8795'-8820'(3 spf,7/23/04)) ' 13'of 4.00"OD seals -Muleshoe at 4412' Isolated Perfs T-90:9056'-9076'(6 spf,8/3/04) T-100:9210'-9280'(3 spf,7/19/04) Production Liner:3W,9.2 ppf,L-80, IBT G-1: 10565'-10610'(3 spf,7/17/04) liner from 4379' -10,930' •• Baker ZXP packer,Flexlock liner hanger& 80-40 sealbore at 4373' Cemented with 209 bbl of 12.0 ppg Litecrete Plugs: X -Halliburton CIBP @ 9025'capped with 14'of cement(5/19/11) -EZ-Drill CIBP at 9192'capped with 40'of cement(7/23/04) -EZ-Drill CIBP at 10420'(7/19/04) Directional Data: , , max hole angle=29.1 deg KOP=4800' max dogleg<3 deg/100' PBTD=9152' TD= 12,458' Red-1 Schematic 06-25-11.xlsx Updated by DMA 10-21-16 • • Well Name: Red #1 PROPOSED SCHEMATIC Field: Nikolaevsk State: Alaska API:50-231-20021 I Conductor: 16",82.77 ppf,K-55 to AOGCC:204-084 50' 352'FNL&392'FWL Sec.8,T4S, R13W,SM Surface Casing:9%",47 ppf, L-80, RT-THF: 17.22' "n1 BTC to 1790' Cmnt with 110 bbl of 12.8 ppg lead and Tbg lift threads-31/2 IBT 45 bbl of 15.8 ppg tail"G" Tree cxn-2'/z"Bowen cxn Intermediate Casing:7",29 ppf, L-80, BTC to 4601' Cmnt with 53 bbl of 12.8 ppg"G"lead lead and 30 bbl of 15.8 ppg"G"tail. Production Tubing:3'/2',9.2 ppf, L-80, IBT to 4412' -Annulus loaded with 7.4 ppg base oil Completion -Chemical injection sidepocket mandrel at 2502' (Macco SFO-1C-I)with 1/4", Open Perfs: 0.049"wall SS chemical injection line T-80:8768'-8777'(6 spf,8/3/04) -Locator sub @4378' T-80:8795'-8820'(3 spf,7/23/04) -Baker 80-40 seal assembly 1-80.8800'-8820'PROPOSED 13'of 4.00"OD seals Isolated Perfs T-90:9056'-9076'(6 spf,8/3/04) • T-100:9210'-9280'(3 spf,7/19/04) X Production Liner: 3'/2',9.2 ppf, L-80, IBT G-1: 10565'-10610'(3 spf,7/17/04) _ liner from 4379' -10,930' Baker ZXP packer,Flexlock liner hanger& ..,, 80-40 sealbore at 4373' Cemented with 209 bbl of 12.0 ppg Litecrete Plugs: -Halliburton CIBP @ 9025'capped with 14'of cement(5/19/11) -EZ-Drill CIBP at 9192'capped with 40'of cement(7/23/04) -EZ-Drill CIBP at 10420'(7/19/04) Directional Data: max hole angle=29.1 deg A , KOP=4800' max dogleg<3 deg/100' PBTD=9152' TD= 12,458' • Red-1 Proposed Schematic 10-20-16.xls Updated by:JGE 01. Ty • • ew�� l//%i s� THE STATE Alaska Oil and Gas ��►;,.-s���, of Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907,279.1433 OF ALASI‘P Fax: 907.276.7542 www.aogcc.alaska.gov December 21, 2015 CERTIFIED MAIL— RETURN RECEIPT REQUESTED 7015 0640 0006 0779 5876 Mr. Chad Helgeson Kenai Operations Manager Hilcorp Alaska, LLC P.O. Box 244027 SCANNEV Anchorage, AK 99524-4027 Re: Docket Number: OTH-15-038 Missing Outer Annulus Pressure Gauges Deep Creek Unit Happy Valley B-14 (PTD 2120540) Deep Creek Unit Happy Valley B-15 (PTD 2121320) Nikolaevsk Red#1 (PTD 2040840) Dear Mr. Helgeson: On October 31, 2015 an Alaska Oil and Gas Conservation Commission (AOGCC) Inspector accompanied by a Hilcorp Alaska LLC (Hilcorp) representative performed well safety valve system inspections at the Happy Valley B-pad and Nikolaevsk pad. Three wells —Happy Valley B-14, Happy Valley B-15 and Nikolaevsk Red #1 were not equipped with pressure gauges to monitor the outer annuli. AOGCC performed follow-up inspections at Red #1 on December 9, 2015 and at Happy Valley B-14 and B-15 on December 12, 2015 to determine if the outer annulus pressure gauge issues were resolved. The three wells were again observed to be missing outer annulus pressure gauges. Regulation 20 AAC 25.200(c) requires wellhead equipment to include appropriate gauges and valves installed in the tubing, casing-tubing (inner) annulus, and casing-casing (outer) annuli. The facts reported by the AOGCC Inspectors indicate a failure to equip Happy Valley B-14, Happy Valley B-15, and Nikolaevsk Red #1 with the required pressure gauges. Within 14 days of receipt of this letter, you are requested to provide for AOGCC review and approval a written plan describing what has been or will be done in the future to prevent its recurrence at Hilcorp- operated fields in Alaska. Included in the requested response should be a list of Hilcorp-operated wells that do not have the required pressure gauges as outlined in 20 AAC 25.200(c), and the timeline for installing the required valves. Failure to comply with this request will be an additional violation. • Notice of Violation • Docket Number:OTH-15-03 8 December 21,2015 Page 2 of 2 The AOGCC reserves the right to pursue additional enforcement action in connection with missing outer annulus pressure gauges on the three listed wells. Questions regarding this letter should be directed to Jim Regg at 907-793-1236. Sincerely, Cathy . Foerster Chair, Commissioner cc: AOGCC Inspectors RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a),within 20 days after written notice of the entry of this order or decision,or such further time as the , AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed,then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration,upon denial,this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction,in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration,this order or decision does not become final. Rather,the order or decision on reconsideration will be the FINAL order or decision of the AOGCC,and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails,OR 30 days if the AOGCC otherwise distributes,the order or decision on reconsideration. In computing a period of time above,the date of the event or default after which the designated period begins to run is not included in the period;the last day of the period is included,unless it falls on a weekend or state holiday,in which event the period runs until 5:00 p.m.on the next day that does not fall on a weekend or state holiday. 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 If - () g ~ Well History File Identifier D Two-sided III II 11111111I " III Organizing (done) D Rescan Needed "1111111111111111I R~AN ~ Color Items: D Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Diskettes, No. D Other, No/Type: D Poor Quality Originals: D Other: OVERSIZED (Non-Scannable) ~9S of various kinds: NOTES: Dale. g l:lq foCo D Other:: BY: ~ 151 iV1P Dale Cd jJ-q lOb 1111111111111' "III Project Proofing BY: (Maria ~ 151 Y\1P Scanning Preparation BY: ~ q x 30 =d 70 +:;15 = TOTAL PAGES aQ.s- 0. /. 7 I (Count does not include cover sheet) tl\A. ýJ Date: b ¿} c¡ D I/.) 151 I V I' r 1111111111111' "III Production Scanning Stage 1 Page Count from Scanned File: ~ q Íp (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES Date: 8' Id-q /D ~ If NO in stage 1, page(s) discrepancies were found: ~ 151 NO MP BY: Stage 1 YES NO BY: Maria Date: 151 1II1IIII11III1I1I11 Scanning is complete at this point unless rescanning is required. ReScanned 111111111111111111I BY: Maria Date: 151 Comments about this file: Quality Checked 11111111111I 111111I 10/6/2005 Well History File Cover Page.doc • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg� 1 Z v DATE: December 21, 2012 P. I. Supervisor l FROM: Bob Noble SUBJECT: Chemical Inj. Port placement Petroleum Inspector Hilcorp Alaska LLC. Red #1 (PTD 2040840) Nikolaevsk Unit Friday, December 21, 2012: I traveled to the new Red pad to witness the initial safety valve system (SVS) tests on Hilcorp Alaska LLC well Red #1. As part of that inspection, I observed a possible failure point in the wellhead assembly. There was one penetration into the side of the flange just below the master valve. I was told this line was for methanol injection. I observed a needle valve where the line ties into the flange and a check valve in the line approximately 1 foot upstream of the tie -in point. The following configuration for the methanol injection line below the wellhead was described as follows: - the line goes down the tubing- casing annulus to about 2500 feet deep and then ties into the tubing; - a check valve where the methanol injection line ties into the tubing. made the operator away that there might be some issues with this line. Attachments: photos (2) Non - Confidential SCANNED APR 11 2013 - /UGC C c ss?ok ss u e C A crud, -Fear 1114+ C s r e i ,4 (*-Q J ,. c:4tr 1 -6 re v s/ e c1 e 7 kkeirt,t, `f j mpeo -' — NRA 32 -3 - Sik 5e7(.1'..k CSC4-7-w'S A-0 cu;vie An^^-54n eiAtz l Cctl`r'e.Sec c e kkevri.. Z "3 Z 2 t 1 p cL e w-ake ( 6e- to,,,; s+.�;Jc4. 5 W/ ail( R 14 j °aas i1E L pp " f� p 1 le„4 -a- e , cfr: �,�tL 4 u tbie e a( is /I.ez+ 2 Lt( (AJ sss ■/ 2012-122 1 Tree Red -1 chem- injport_bn.docx 1 of 3 • 0 Red #1 Production Tree Chemical Injection Port Photos by AOGCC Inspector B. Noble Inspection Date: 12/21/2012 Photo #1 - Chemical Injection Port between Tubing Head Adapter and Lower Master Valve V .1tiot,...;1; m. A 4 , ....„- 0 irk . 0Apirlyi .........,,,,,........ , f . � 40: 'IA& Inkf; NI / AI° . if * 4110 l i f 4 0 Air 41% yti 11 . . ' \ ' 11 lil ' " ' 1, If / , 4 ' d i, 151140116" i # 1 4# 2012 -1221 Tree Red -1 chem- inj _port_bn.docx 2 of 3 • • Red #1 Production Tree Chemical Injection Port Photos by AOGCC Inspector B. Noble Inspection Date: 12/21/2012 Photo #2 — Check and Block Valves in the Methanol Injection Line Upsteam of Tie -in to Flange { Oil . w i g r u ` ' ly i r":416. r4 i V' '4 rif f" I . ' * ' A 044, 4r iv 4 #0 ' ' 4v4r4Prilre APO 4 i r A r 40 O 07 . , oi i !Ira r Ati IF/ IOWA& 44r4 0 4p Aigiviy ......A.,,. , Air , jr ,, if . - . . ' ' . 4 i red r ", ' 4 14 #01,171ifs , L Aso ' i iffi Ali rA i rs 1 ref 4 . ,. . .... Ai _ .,.., w it, ' e Y Atli . 4 flirt, ' ill Ay / i okm I 0 i . - 4 . . ':?' el f i apse , i fik ,..... .., , ino, x ir amini ..-- ilam 4 , , — , 2012 -1221 _Tree_Red -1 chem-inj_port_bn.docx 3 of 3 z646,, Regg, James B (DOA) From: Regg, James B (DOA) atnf- Q Sent: Tuesday, December1h2012 1 :5e4Pstein Stan Golis e t To: Christopher Walgenbach; Larry Cc: Bruce Hershberger; Sandy McMillan; Richard Musgrove; Dean Gardner; David Vienna-(C); Chad Helgeson; Steve Tressler-(C); DOA AOGCC Prudhoe Bay; Roby, David S (DOA); Schwartz, Guy L (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Norman, John K(DOA); Ballantine, Tab A(LAW) Subject: RE: Red Pad SSV Testing Where's the meter? AOGCC has no record of an application for ultrasonic meter(or any custody transfer meter for that matter)for Red pad production. Refer to AOGCC regulations at 20 AAC 25.228, specifically paragraph (b). Jim Regg AOGCC SCAM 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 From: Christopher Walgenbach [mailto:cwalgenbach@hilcorp.com] Sent: Tuesday, December 18, 2012 12:29 PM To: Regg, James B (DOA); Larry Greenstein; Stan Golis Cc: Bruce Hershberger; Sandy McMillan; Richard Musgrove; Dean Gardner; David Vienna - (C); Chad Helgeson; Steve Tressler - (C); DOA AOGCC Prudhoe Bay; Roby, David S (DOA); Schwartz, Guy L (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Seamount, Dan T(DOA); Norman, John K(DOA); Ballantine, Tab A(LAW) Subject: RE: Red Pad SSV Testing Jim, Your answers are in black. C 6e10,A)) Thanks, ekta 7e/dyed/ad Hilcorp Alaska LLC Production Foreman Swanson River Happy Valley Westside Baker Dillon Red Pad Office 907-283-2541 Cell 907-690-1727 From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Tuesday, December 18, 2012 10:38 AM To: Christopher Walgenbach; Larry Greenstein; Stan Golis Cc: Bruce Hershberger; Sandy McMillan; Richard Musgrove; Dean Gardner; David Vienna - (C); Chad Helgeson; Steve Tressler - (C); DOA AOGCC Prudhoe Bay; Roby, David S (DOA); Schwartz, Guy L (DOA); Ferguson, Victoria L (DOA); 1 Foerster, Catherine P (DOA); Seamount, Dan T(DOA); Norman, John K (DOA); Ballantine, Tab A (LAW) Subject: RE: Red Pad SSV Testing I have checked our well database and find there are 2 Red wells completed as gas producers: Red 1 (PTD 2040840) and Red 2 (PTD 2041480). Last correspondence in our files regarding either well was the report of sundry operation Form 10-404 for Sundry approval 311-151 dated 6/30/2011 (results of a flow test for Red #1). According to DNR Public Notice dated 10/3/2012 for the Nikolaevsk Unit plan of development (http://notes3.state.ak.us/pn/pubnotic.nsf/1604e1912875140689256785006767f6/ad41edb3b70a35c689257a8b00762 d53?OpenDocument), a gas pipeline is was being constructed to transport gas produced from Red Pad to the existing gas transmission line along the Sterling Highway". Please answer the following questions: - When was production commenced? 12/16/12 at 13:30 - Only Red #1 producing? What about plans for Red #2?At this time we only have plans for Red Well#1. - What are the flowing conditions for the Red well (FTP,temp, separator pressure)? 2295# FTP/ 59 F on sales meter/790#separator pressure. - What custody transfer measurement equipment is being used at Red pad? Multipath Ultrasonic custody transfer meter . I'd appreciate your answers before AOGCC performs the required inspections. Jim Regg AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 From: Christopher Walgenbach [mailto:cwalgenbach@ hilcorp.com] Sent: Tuesday, December 18, 2012 8:01 AM To: Regg, James B (DOA); Brooks, Phoebe L (DOA) Cc: Larry Greenstein; Stan Golis; Bruce Hershberger; Sandy McMillan; Richard Musgrove; Dean Gardner; David Vienna - (C); Chad Helgeson; Steve Tressler - (C) Subject: Red Pad SSV Testing Jim, At this time Red Pad is producing and the facility is running smoothly. We plan on conducting the SSV test on Friday 12/21/12. Thanks, e' 7t/a19edaca Hilcorp Alaska LLC Production Foreman Swanson River Happy Valley Westside Baker Dillon Red Pad Office 907-283-2541 Cell 907-690-1727 2 • • Chevron Erin O'Brien - Authier Union Oil Company of California %.1 Reservoir Engineer 3800 Centerpoint Dr., Suite 100 Anchorage, AK 99503 Tel 907 263 7653 Fax 907 263 78484 7 Email eodm @chevron.com R June 30, 2011 oil & s lw C �� rnlSsIOf Mr. Daniel T. Seamount, Jr. Oil & Gas Conservation Commission (AOGCC) Mota 333 West 7 Avenue, Suite 100 8 / Anchorage, AK 99501 a®4 - O `t Re: Forms 10 -404 and 10 -422 Nikolaevsk Field, Tyonek OiI Pool, Red 1 Sundry Number 311 -151 Dear Mr. Seamount: As required in the approved Application for Sundry Approval to re -test the above referenced well, please find forms 10 -404 and 10 -422 and other relevant information attached. The Red 1 was re- tested early in June 2011 to help confirm the economic justification for the installation of a pipeline and facility for the Red Nikolaevsk Unit. History: The Red 1 well was drilled and tested in 2004. The well had been shut in since August 2004. Reserve uncertainty and distance to pipeline (N15miles) precluded earlier hookup due to marginal economics. The newly constructed "Armstrong Pipeline" has improved the project economics by significantly cutting the pipeline length (6 miles). The DNR has granted a unit extension and POD if Chevron commits to building a pipeline by Jan 1, 2011 and produces gas in 2013. The primary zone, T -65 was perforated and tested in July 2004. Two additional zones (T -63 above, and T -70 below) were perforated before leaving the well in 2004. The flow rates dropped due to water influx from the lower zone (T -70) which was also verified by a water fluid level found in a PLT log run August 4, 2004. All perfs have been open for the past seven years. The re -test was successful and went very close to plan. The re- testing rates and pressure buildup analysis indicated skin damage, but rates were enough to allow Environmental and Engineering to progress so a commitment to move forward with the pipeline /facility project can be reached before end of 2011. Union OiI Company of California / A Chevron Company http: / /www.chevron.com • • Mr. Daniel T. Seamount, Jr. Alaska Oil & Gas Conservation Commission (AOGCC) 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 Summary of ACTUAL Re -test Procedure: 1. MIRU test equipment. 2. Pull BPV. RU slickline. Tag pbtd at 9134'KB. Fluid level at 8800'KB. 3. RU E -line and set plug at 9025'. Set 14' of cement on top of plug. 4. RU slickline, run stops and tandem pressure gauges 6' below T -65 open perfs, @ 8826'MD. RD slickline. 6. Unload well and flow above unloading rate ( >5mmcfd), building to 6.5mmcfd for one hour followed by —3 hours at 5mmcfd. Collect sample of any water produced during testing and report rate and pressure to project engineer. Measured rate and flowing tubing pressure implied some wellbore damage, but the decision to not reperforate was made and the testing continued. 7. Because historical rate of 6.5mmcfd was attained, we continued to test @ — 5000mcfd for 48 hours. Actual gas volume vented = 10.75mmcf, very close to estimated volume of «11 mmcf. 8. The well was shut in for a 15 day bottomhole pressure buildup (gauges remained in well). 9. RU slickline to retrieve gauges and replace BPV. RD slickline. The testing minimized the total volume of gas vented to that amount necessary to obtain sufficient data needed to evaluate the well and project for economic viability. Daily reports and a summary of test results are included with form 10 -404. Please contact me with any questions at 263 -7653. Sincerely, 644: t9Pike Erin O'Brien - Authier Reservoir Engineer EODM Attachment cc: Dave Whitacre Sharon Sullivan Gary Ross Chris Kanyer File Union Oil Company of California / A Chevron Company http: / /www.chevron.com 1,,./Pk STATE OF ALASKA �1 �oG /L�II ALAS L AND GAS CONSERVATION COMMISSION • REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Stimulate ❑ Other 0 Test subsequent to Performed: drilling Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver ❑ Time Extension❑ Change Approved Program LI Operat. Shutdown ❑ Perforate ❑ Re -enter Suspended Well❑ 2. Operator Name: 4. Well Class Before Work: 5, Permit to Drill Number: Union Oil Compnay of Califomia Development ❑ Exploratory 0 204 -084 ^ 3. Address: Stratigraphic❑ Service ❑ 6. API Number: 3800 Centerpoint Dr, Ste 100, Anchorage, AK 99503 50- 231 -20021 ) 0 -- O '3 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0390514 4 Red 1 9. Field /Pool(s): . Nikolaevsk Unit/ Tyonek 10. Present Well Condition Summary: Total Depth measured 12,458' feet Plugs measured 9025', 9192', 10420' feet true vertical 12,047' feet Junk measured feet Effective Depth measured 9,011' feet Packer measured 4,373' feet true vertical 8,697' feet true vertical 4,372' feet Casing Length Size MD TVD Burst Collapse Structural Conductor 50' 16" K -55, 82.77ppf 50' 49' Surface 1790' 9 5/8" L -80 47ppf 1790' 1789' — — Intermediate 4601' 7" L- 80BTC, 29 -ppf 4601' 4600' Production 10930' 3 1/2" L -80, 9.2 ppf 10930' 10551' Liner Perforation depth Measured depth 8768' 8777' MD open 8795' - 8820' MD open 9056-9076' MD iso. w /plug 9210' -9280' MD iso. w /plug 10565'- 10610' MD iso. w /plug True Vertical depth 8465'- 8474' TVD ` 1. ` a , ' $ ' ;101 j 8491'- 8515' TVD 8740' 8759' TVD i & �ryf#�i. L 930 6)1$$10/1 8886'- 8952' TVD 10192'- 10236' TVD Ant rte® . Tubing (size, grade, measured and true vertical depth) 3 1/2" L -80 9.2ppf 10,930' MD 10,551 TVD Packers and SSSV (type, measured and true vertical depth) Baker ZXP Pkr, Flexlock liner hanger & 80- 4,373' MD 4,372' TVD 40 sealbore 11. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run Summary of test results Exploratory 10 Development ❑ Service ❑ Stratigraphic ❑ Daily Report of Well Operations Attached 15. Well Status after work: Oil ❑ . GaC✓ WDf GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUS❑ SPILT 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: Contact Erin O'Brien - Authier Printed Name Erin O'Brien - Authier Title Engineer Signature 10., 62 Phone 907- 263 -7653 Date 6/29/2011 RBDMS JUL 05 2011 n 1 Form 10 -404 Revised 10/2010 Submit Original Only Red 1 Re -Test June -2011 Surface Testing 2848psig 2867psig 7 3500 2888psig - \ I 6 - 2900psig 3000 • M • • _ _ _ .— 2500 ♦• ■ 4 ♦ • 2000 E ` t • E a 4J 1953psig ! ! 6L CO 3 1500 Ct • Metered GAS RATE MMCFD \( Surf Digital data, psig Flowtest: 51.33hours, cum gas 10.75 mmcf 2 1000 • Metered Tbg Pressure PSIG • 1 - 500 0 0 0 20 40 60 80 100 120 140 Time, Hours • Chevron 1100 Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) Red #1 RED 1 ADL390514 5023120021 HP5589 17.22 Jobs • • Primary Job Type Job Category Objective Actual Start Date Actual End Date Completion - Reconfigure Well 5/16/2011 Services Primary Wellbore Affected Wellbore UWI Well Permit Number Red #1 502312002100 2040840 Daily Operations 5/16/2011 00:00 - 5/17/2011 00:00 Operations Summary Arrive at Red Pad. Pull back pressure valve. Rig up slickline unit. Pressure test. Tag fill at 9134' KB. Tag fluid at 8800' KB. Rig down slickline. 5/18/2011 00:00 - 5/18/2011 00:00 Operations Summary Rig up pump, pressure test lubricator, Rig down and return to PWL shop 5/18/2011 00:00 - 5/19/2011 00:00 Operations Summary R/U Schlumberger Eline on Red #1 set Halliburton CIBP @ 9025' RKB. POOH with eline. Rig down for day. 5119/2011 00:00 - 5/20/2011 00:00 Operations Summary Pick up Lub set back pressure valve- put fence back together 5/19/2011 00:00 - 5/20/2011 00:00 Operations Summary Arrive at Red Pad. Rig up pump truck pressure test lubricator to 3500 PSI. Rig down pump. 5119/201100:00 - 5/20/2011 00:00 Operations Summary R/U Schlumberger Eline on Red #1. Set 14' of cement on top of CIBP @ 9025'. Set 3" type H BPV in well. Bleed down tree, shut in all valves. Rig down and cleared off location. 5/31/2011 00:00 - 6/1/2011 00:00 Operations Summary Move in and set up Peaks Atco Camp. 6/1/2011 00:00 - 6/2/2011 00:00 Operations Summary Hang Gauges 6/1/2011 00:00 - 6/2/2011 00:00 Operations Summary WBI hauled T -Pak from SRF to Red Pad. Layed out supplies for test equipment containment. Pollard ran pressure gauges and installed data logger. Pulled BPV. 6/2/2011 00:00 - 6/3/2011 00:00 Operations Summary Set choke skid and vent stack scrubber. Installed SSV on wing valve. 6/3/2011 00:00 - 6/4/2011 00:00 Operations Summary Stand Flare Stack 6/3/2011 00:00 - 6/4/2011 00:00 Operations Summary Stood vent stack, hydro test hardline to 4000 psi & inspect vessels. SITP= 2888 psig. Started flow test @ 20:30. Flow well at various rates. 6/4/2011 00:00 - 6/5/2011 00:00 Operations Summary Continue flow test and collected sample of fluid and gas. 6/5/2011 00:00 - 6/6/2011 00:00 Operations Summary Continue flow test. Shut in well at 23:30. Finished testing 6/6/2011 00:00 - 6/7/2011 00:00 Operations Summary Lay down flare stack; download spider gauges. 6/6/2011 00:00 - 6/7/2011 00:00 Operations Summary Shut in tubing pressure 2841 psig @ Pollard data logger at 03:15. Started breaking down test equipment and loading trailers 6/7/2011 00:00 - 6/8/2011 00:00 Operations Summary Finish loading trailers and camp. Move off Location. 6/23/2011 00:00 - 6/24/2011 00:00 Operations Summary Rig up Slickline, found fluid level at +/- 8500, pulled gauges from 8827', rig down slickline, move off location. 6/25/2011 00:00 - 6/26/2011 00:00 Operations Summary Reset BPV, bled off tree, shut all valves and chained up handwheels. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION FACILITY REPORT OF PRODUCED GAS DISPOSITION 1. Facility Number 2. Facility Name 3. Field 4. Operator 5. Month/Year of Disposition 2310000004 Nikolaevsk Nikolaevsk Unit/ Tyonek Union Oil Company of California Jun -11 Disposition Volume MCF 20. For production from multiple pools, list contribution of each pool as a percent of 6. Sold Total Volume. Pool Name Pool Code Percent 7. Reinjected 8. Flared or vented 1 hour or less 9. Flared or vented more than 1 hour (see instr.) 10, 750 10. Pilot and Purge • 11. Assist Gas 12. Fuel gas used in lease operations. 13. Other (see instructions),��, r . : Authorization >1 hr: MCF 10,750 Safety 14. TOTAL VOLUME (ITEMS 6 -13) Lease Use MCF 15. NGL Gas Equivalent Conservation MCF 16. Purchased gas Waste: MCF 17. Transferred from: 18. Transferred to: (Express as a negative #) • Commissioner Date 19. Remarks: I hereby certify that the foregoing is true and correct to the best of my knowledge. f�� Note: All volumes must be corrected Signature T itle Engineer to pressure of 14.65 psia and to a temperature of 60o F. Authority 20 Printed Name Erin O'Brien - Authier Phone 907 - 263 -7653 Date 6/29/2011 AAC25.235. Form 10-422 Rev. 5/2009 INSTRUCTIONS ON REVERSE SIDE Submit in Duplicate ��� ' m��� �N�u • �� GAS DISPOSITION IMPORT FORM FOR NG EVENTS GREATER THAN 1 HOUR 'Ctatt WOW istartroi teriOaiteMlaildid Began re-test of well to estimate damage due to extended shut in time of 7 Monitor fiowing tubing pressure and 07m1/2011 1*5000 2310000004 06/03/2011 20:30 23:59 06m3/2011 680 years. rate continuously to kick off well. Continure re-test of well to max rate ot 6.5mmcfd and Monitor flowing tubing pressure and p held one hour, then dropped rate continuously and flowed at rate to 5.Ommcfd to estin,ate maximum rate for a minimum damage due to extended amount of time to evaluate 07/01m011 1*5000 2310000004 06/04/2011 0:00 23:59 06m3m011 5119 shut in time of 7 years. damage. Completed re-test of well by Monitor fiowing tubing pressure and sustaining rate of 5.0 mmcfd rate continuously and flowed at p to measure drawdownto help constant rate for a minimum evaluate reservoir volume amount of time considered and economic viability of necessary to evaluate drawdown 07/01/2011 145000 2310000004 06m5o011 0:00 23:30 06m4/2011 4951 prospect. prior to pressure buildup. This Excel spreadsheet has column headings and data forniatting to import flarin events over one hou into the AOGCC databas Copy and paste the headings Directions into an Excel sheet and enter all flaring events over one hour for the month under the appropriate columns per instructions below. One operator can enter all events from all associated facilities. RptDate mm/01/yyyy Lise first day of the month. Operator Names Operator Numbers Op No Six digits. See list of operators in next column. AURORA GAS LLC 110800 Facility No Ten digits. On form 10-422 or call (907) 793-1241 BP EXPLORATION 112300 Date Flared mmmo/yyyy MARATHON OIL CO 129000 Start Time Military time: 00:00 to 23:59 NORTH SLOPE BOROUGH 131300 Ending Time Military time: 00:00 to 23:59 PACIFIC ENERGY 131900 End Date mm/dd/yyyy CONOCOPHILLIPS 134200 Planned 'U' for unplanned event or "P' for planned event. PIONEER NATURAL 135300 MCF Flared gas arnOunt in MCF. NO DECIMALS. rsoxoow/wooALASKA 1*1200 UNION OIL uoop 145000 XTO ENERGY INC 146700 e • scirtgl[E [11F ELAsim SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 X (907) W . 7th AVENUE 279 - -, SUIT7542 1433 E 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) FA Gary D. Ross a Operations Supervisor CJI�Y �� 9 Union Oil Company of California P Y 3800 Centerpoint Drive, Suite 100 czb''r Q 'ti- Anchorage, AK 99503 Re: Nikolaevsk Field, Tyonek Oil Pool, Red 1 Sundry Number: 311 -151 Dear Mr. Ross: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 1 Daniel T. ' eamount, Jr. ", Chair DATED this 3 day of May, 2011. Encl. • RECEIVE' ' e • • STATE OF ALASKA � • ALASKA OIL AND GAS CONSERVATION COMMISSION APR 2 9 2011 APPLICATION FOR SUNDRY APPROVALS has Cans. Corinission 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change 4{9(pre§Iram ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: test subsequent to drilling 0 - 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Union Oil Compnay of California Development ❑ Exploratory 0 204 -084 - 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: 3800 Centerpoint Dr, Ste 100, Anchorage, AK 99503 50- 231 - 20021- 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No 0 Red 1 - 9. Property Designation (Lease Number): 10. Field / Pool(s): ADL0390514 Nikolaevsk Unit/ Tyonek - 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): / Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 12458 12047 - 9152 , 8831 9192', 10420' Casing Length Size MD / TVD Burst Collapse Structural Conductor 50' 16" K -55, 82.77ppf 50' 49' Surface 1790' 9 5/8" L -80 47ppf 1790' 1789' Intermediate 4601' 7" L- 80BTC, 29 -ppf 4601' 4600' Production 10930' 3 1/2" L -80 10930' 10551' Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 8768- 8777'MD 8465- 8474'TVD 3 1/2" L -80 9.2ppf 10930' 8795- 8820'MD I 8491- 8515'TVD 9056- 9076'MD 8740- 8759'TVD Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker ZXP pkr 4373' MD, 4372' TVD / 12. Attachments: Description Summary of Proposal El 13. Well Class after proposed work: Detailed Operations Program ❑ ,;'- BOP Sketch ❑ Exploratory Q - Development ❑ Service ❑ 14. Estimated Date for Mid4ay 2011 15. Well Status after proposed work: Commencing Operations: ' ✓ Oil ❑ Gas El - WDSPL ❑ Suspended Q 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Gary D. Ross Printed Name Gary D. �Ross Title Operations Supervisor Signature —'/ Phone 907-263-7952 4/29/2011 COMMISSION USE ONLY f Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 ` t \ t � t Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Subsequent Form Required: 10 _ 4c'4 ) 10 y 2 2 • , APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 5 J7Ji Form 10 -403 Revised 1/2010 ORIGIN A L Sub D plicate • • Testing Red 1 Procedure Permit to Drill #2040840 We are requesting permission to retest the Nikolaevsk Unit Red 1 well. Retesting the well will confirm the economic justification for the installation of a pipeline and facility for the Red Nikolaevsk Unit. The Red 1 well was drilled and tested in 2004. The well has been shut in since August 2004. Reserve uncertainty and distance to pipeline ("15miles) precluded earlier hookup due to marginal economics. The newly constructed "Armstrong Pipeline" has improved the project economics by significantly cutting the pipeline length (6 miles). The DNR has granted a unit extension and POD if Chevron commits to building a pipeline by Jan 1, 2011 and produces gas in 2013. The primary zone, T -65 was perforated and tested in July 2004. Two additional zones (T -63 above, and T -70 below) were perforated before leaving the well in 2004. The flow rates dropped due to water influx from the lower zone (T -70) which was also verified by a water fluid level found in a PLT log run August 4, 2004. All perfs have been open for the past seven years. The retest procedure includes setting a plug over the water in T -70 and re- testing the T -65 and T -63 to repeat /confirm test results from 2004. Positive test results in May 2011 will allow Environmental and Engineering to progress so a commitment to move forward with the pipeline /facility project can be reached before end of 2011. Summary of Retest Procedure: 1. MIRU test equipment. 2. Pull BPV. RU slickline. Tag pbtd. Last PBTD 9' D. Establish fluid level (FL). 3. If PBTD <9056'MD (T -70 top perf), bail fill to 9056'MD and collect fill sample. RD slickline. 4. RU E -line and set plug at ^'9025' (above T -70 perfs as deep as possible to preserve rat hole) using ref log, Schlumberger SCMT 7/9/04 -Run 1, BHP"3500psi. RD E -line. 5. RU slickline, run stops and tandem pressure gauges 6' below T -65 open perfs, @ 8826'MD. RD slickline. 6. Unload well and flow above unloading rate ( >5mmcfd) for 3 hours, building t . 6.5 mcfd for final hour. DO NOT EXCEED 6.5 mmcfd. Collect sample of any water produce during testing and report rate and pressure to project engr. for decision on possible reperf. 7. If historical rate of 6.5mmcfd is attained, continue to test @ ^'5000mcfd (or max achievable rate less than 5000mcfd) for 48 hours. Adjust choke to achieve a rate of 5000mcfd and then hold rate steady by adjusting choke and monitor rate and pressure for 48 hours. Initially record Q and FTP every 15 minutes until stabilized. Then record Q and FTP every hour. Estimated maximum volume vented = 1 mcf. Ve` 8. SI well for 15 day buildup (ti will remain in well). 9. RU slickline to retrieve bomb and replace BPV. RD slickline. 10. If well will not flow or significantly reduced rate is observed, pull pressure gauges and reperf 14' T -65 (8806 -8820' MD). Repeat steps 5 -8. It is intended to minimize the total volume of gas vented to that amount necessary to obtain sufficient data needed to evaluate the well and project for economic viability. • • Well Name: Red #1 ALASKA ='' •Ml1L.L1NG Field: Wildcat UNOCAL e State: Alaska API: 50- 231 -20021 Conductor: 16 ", 82.77 ppf, K -55 to AOGCC: 204 -084 50' 352' FNL & 392' FWL Sec. 8, T4S, R13W, SM Surface Casing: 9 % ", 47 ppf, L -80, • BTC to 1790' RT -THF: 17.22' Cmnt with 110 bbl of 12.8 ppg lead and Tbg lift threads - 3'/2' IBT 45 bbl of 15.8 ppg tail "G" Tree cxn - 2Y2" Bowen cxn Intermediate Casing: 7 ", 29 ppf, L -80, BTC to 4601' Cmnt with 53 bbl of 12.8 ppg "G" lead Production Tubing: 3Y2', 9.2 ppf, L -80, IBT lead and 30 bbl of 15.8 ppg "G" tail. to 4412' , - Annulus loaded with 7.4 ppg base oil Completion - Chemical injection sidepocket mandrel at 2502' (Macco SFO -1C -I) with 1/4 ", 0.049" wall SS chemical injection line - Locator sub @4378' - - Baker 80 -40 seal assembly 13' of 4.00" OD seals — Open Perfs: - Muleshoe at 4412' T -63: 8768' - 8777' (6 spf, 8/3/04) T -65: 8795' - 8820' (3 spf, 7/23/04) T -70: 9056' - 9076' (6 spf, 8/3/04) Isolated Perfs T -81: 9210' - 9280' (3 spf, 7/19/04) T -130: 10565' - 10610' (3 spf, 7/17/04) Plugs: EZ -Drill CIBP at 9192' capped — with 40' of cement (7/23/04) - EZ -Drill CIBP at 10420' (7/19/04) Production Liner: 3Y2 ", 9.2 ppf, L -80, IBT liner from 4379' - 10,930' Directional Data: Baker ZXP packer, Flexlock liner hanger & max hole angle = 29.1 deg 4 , 80 -40 sealbore at 4373' KOP = 4800' Cemented with 209 bbl of 12.0 ppg max dogleg <3 deg /100' PBTD = 9152' Litecrete TD = 12,458' /` Updated by: JGE LOADED FCBNRed -1 schematic4- 21- 11.xis ECOA 4-21-11 Red pad data for proposed well tesg • Page 1 of 1 Aubert, Winton G (DOA) From: Greenstein, Larry P [Greensteinlp@chevron.com] Sent: Monday, May 02, 2011 3:51 PM To: Aubert, Wnton G (DOA) Subject: Red pad data for proposed well testing Attachments: Red Test Equip.jpg; Red Close Labeled.jpg; Red Far Labeled.jpg Here you go Winton. The sketch of the testing equipment on the pad with the prevailing wind direction noted. The closest structure we can find looks like towards the village of Nikolaevsk — 2.4 miles away, as the crow flies. No roads connect to the village and it is almost exactly upwind of the prevailing winds. The road that leads to Red pad comes in from the west and north, but dead ends at the pad with no structures along the road until you get —3.5 miles to the west, as the crow flies. Hope this helps. Larry «Red Test Equip.jpg» «Red Close Labeled.jpg» «Red Far Labeled.jpg» 5/3/2011 00 R L � �F : � t ell .�� '1,440.,,'"!' °. r } ° pia >; ' ... t _ ~ '1f . '-:,(',14,:i . �' ' r, v tk .. : ` y t. - e a rt ' t MM . ` $ . y • v.... t�,u. v ^' }T• r S h ss io y 1t �' " a by4 a q #r se I h4. ,...,,11',1 F W. ..€ x 1 « . y S y, 1 4 < 'r °�' a s ` y N x } , ,. ,, . ,•S « �., *k to i r s. ",,� � rc i�_� 3 a q, 1 ' ;r n .Pt ,ra.. T Xis may �� �r .44,jf i e.- K , . �4.. "# K . ^,e '� i"�k " 4}, y i y • "� k , b' '" - �` •T .: �i.•I;',11...‘;: ,g' . fit• r g, V'' �~ � "� � "l � i � +�,�"� . . � }' '� is , { _ , . 4i • t r 4 " S F ~ 4 ,; ... ,' ' . ; t y ,( s* F+ hi ' r►.Il.: , , � , rMei . ht`, as aP �� yy//,, �` ' ' . , r . a . b y F S-. , " • r H "t'. v + �; ` dr. �' » 1- • f - ,� 0.A V. x 1 0 K� v b 1 . r4 I .;,<. `► , yr .„. .., .. i ........., r } - - i. ' 1-...',,T4.11117i,, ',- , ., : ' - e i . , / �} ' r a p y ,r ',,r ' +Z r 1 if; r iR e: !�,r�� •.� ° +fit. 0 i � a of j ;� W r t ,« , .. ;. +i I ,. ., , V. , t '. ,, a i > ,� 'N 71 A y ::++ • ,' . .. , - .• ' 1 ** -1, ,41„.„10174„ ..,- .0. .41 r ,..„ , * -4 -** I', 14 ' - i i ,1 *14 - * -4%**-14' , . - - ,ti ", .,.. ;I:.' ,: - '', . .., ., , ... . ,,. ' ,.....„ •-,- -1 ' — ,„ ' ' - ,"..• . • , '':- -...'.., `' -.' - I - 7 ,, .,' , • ..-.. "•• 4..",; a, „,,, ' A - I' --- • ,• . .-"- -"',....-•-' . "" '• .;"•!, ff‘,",.,t,4.;-", ."4' •' , "-s ' '', :;...-- . ). ;1 ,•„':, •_ ",,. "...." . • < ,.;."/ ) ,- „r . ". ,.., " '''''. - " -• ..., ,„,, ,.,- - • ---T.--.--,4' ,.„ ---..":4 .,...,-;:-' ,,, ' i. • , „,.,. ,''', ' f .-: '... \ ;'.... , ',',`'ri- ' :. • ;',t--- It''...,4...' . *,),. :!, -*, .t . 4. N, ,,,,,,,, , -' , -- ,,, , ••• ',/ -, ''' ' '' 1: gf, , _ ',"' ,'" '''. ''':'.. - .qt. !." ,- ; ''..". f...... 4...... .;,--..r.ligt...f 1°' \'''' ''''• '', ' t - ' , ‘,...; ...!_.......:Af.t...,1---J-44,.T, -, 0 ,4, i....‘,.., . , • ,. , v , ," " ,:•,, 1, ' - , '"•:•,,,..4441Ftli- ..- - -. 4, ---. ,,,, - 43.*" - , , ,,,•'„ " - .."‘ .r.„'' , ',',".: , r ., l'' •,,,, ,. ,,,, '',•,..",*'"7",';- '"•.',, - 4 , ...-, 4,..: 4 4 . AN* 1 • ' P ; 4.':".* .1 , ' •44P* ' ' : -',", %-,' '",',*,4, ' * " " *-• ** ',• ' '441 744*!" 4 ' '.* 4 ***.' *. '''' ' '''' .' ' .7 . . * - ..:1; .4'....! *,.. - , ..* ' L 4.'„ ''*. , * ' * **4 .- ',.' , ' • ' '*'. ' - ' ' ' ' il, ;42- •-,',""';'''- 4V.' ti .:*. - "4- ' ts ' "*''', 4 t ...'"' . 4 4 , 44,_ "'P . . ' ' ,. "....?..—i - i L 4 + , .. ,, :.:.. - 4 , __, , , , ,,.,:„. „ .,....-,,,--,„:.,.:,,-,,,:. ,:.,:.- .,:.,--....,,,,.........„.,„ •,• . .. . . ,....,,' - . ..,-•,.. „,-- ,,,,,,........,- ..., 4 ',., , • - -4" , " - " .. ....- _. 41" • '- 4 ' 4 - fl‘ -' '441„4".."-iTior." ' - " • . -,- r . ;4" • ..',..t .. I , , , ,-- 4 ,- „. r .".*:;:. ,,,.-•!°-. ,,i, .... 1,,- ,,' - it*- -v * tellet.,.,- ,_.f.....".....e.r.14i.,..01,*4-,N., ' • 4 ; '....,'-'-*, , At!' i --:.-„,";;; A' . t 1- -`**. ,.... - .Aii.:- . -.;" '''' t • 4/..:. - I,,, A..-- 047.4,f' ** ' :teCtilkit; ' ' ';',',...; ' .*' - '.,u.'. ' ' 1 .-*-., - - A '.° ;.'"': --H ' : 4 ';' . ;** !:; --, . • . 1 * ' — .. 4 ' 4,, - - ..- 'A- - - * --*' ' A''-','-=! 't **!' .A. * '. • . --- A - f.rifr - , t ' - -..!.-. A . , ''..-- ....."4/14..., 7.7 "' ' ;',.'j . .- - ,--; %v. ''''' • ' '" -.. "°*1!--%-° ... ._ „,„, i , - .. ' •,• ,,.. ;.,, - , •,,,...,•_.,-„,.„, 80 ' .. ' '..:.:,'N.,,,,,..„,,,, ..P.w. ' ' .' ''...: -. ' . ',;,. ' .' '' . -7; .' , ..'.'-' , ".''' i . I.... „. , " : .,04 r„, j .77 0, - , -4,r*iall*'1.,. i'-,_.:, -., 1. , "1 • • • - , 7 ,,,, 4- - t• . , ' . ,./ -•.,.. , . , - 4 . • • -i., i,... ' ,----,,-- - - - •-..,,.' - • ' - .-44•• - .- "..;,,...'" - ,,,, .,,: . , f - t - . 7. , ''' -a ' ,.. ' •0 p * ' 1 ,, , - • fr,. ...-.- ,..,,,,„ ._ , . ; - r ' , , . , ..„: - , . ... .., , -.....4 \ ' ., -„:".„ '' 44 , . ";" , " - "4%,*:--,;-,..- ,,-$1.'11.;-.":-.:`,:,,,,,---,-.'"' . " ,-, - : - • f" ,.'" - - .„:". ,.- ' ' . '" -4. "...,,,,,‘,-,,•••••ii,-'`."- , , , . , , , " ' ' ' - ''' ' "•,- . ' , ,-•".• , ri' . .:,:'"•- 4. '" , • ., • " *,...4 - _..,,•-•- w.-77,'.' f: , '-'''' 1 '` , "•40 4 :-''I''',0-$ .., , ,• • - i ,,:‘.. -. •• . • • : .. is 3 ..,. . ... . ; nu*. * • . , ..„,,,,,• . ,,, . ,,,....._, .0 . t ,.: )--, k * isr v , ,, t= ', , ,„, , i , , , ,.. ,. ,, :., . I It. ,..., ,,, , , .. ._ ir•-.44,:.,4„,,,,u.4,..,„ ., , . ,:,,, ...,, * . ,,,.„ t:‘,0*..„.-!`‘,1#., ;.. e , - Igv. .. ....4, ,,,..,..,, ,,. ,. . 4 0 Iti, '`-!. r ) •, '" , Jt , : -. A„.„,,„. ) .. ,- — . . -„, .,,,,,,.--,..;•AI,„,,,,-.T,,,., .. - -.4,; .. , .4,,. .- , -. . ... . .., :'-_ ,. :.;:..„„, .04, .„,•,.....- 4 ,,,.„1,- ,; „..t. t „..„ „. it .., I .4 , . ....,,,, ..,,, „ ..„, .-, -• „-,.... ,.., , _ ' • 1 _ 4,`• ;.,--", a - f''' „.„,,, ._,..,,, • ,,,I, . .....; 7/ , : -,,, - ...", ":4"",-,- -, -,..., ...-..‘"....,.." ‘,...,„ . „.14,V,` 4A,,,/ •• i 7 .„ ' ':. . ,-,;(,• , , " . . ... „.. `' ;' ' - :•.: 't, r i,114.1.16- ..i,., ;-:. .-wt-. ,,. ,-.. :„.., -,,,,... i.,, • .,,,-;4. ,, ,:r.,:. -- . „ .„...-. r ,,": ,,,,qt-Vir." ,..' -1 ..). ''' . "i, , 1 - « ' ''. '''' - 114 • t..!...r.t1-*:: ',/il'.'. 1 :ba .,.. .4ilt.! - :..! , . '-•:;' •-'', ,,,„* 4 ,-, : : .-....7.: -0 ..41,, . P . j; .p 7 .4:1:i7tg*....A71;7111,L7f7!..,,I:61. ...4 • ',..,.:......4( •-- . .,,• "... .1" 3....,,;.-. -,,-;"-,,,,;:,"4,"Ii ...* " ... f ,. •A , , :„., ...'•,„ ;,,,t_. -,, - , ,--• ' ...: - ., ,„ •2.,„2,.„„,,,,, -' *,,‘,„ **,. --).„ ,, A . 7 ,,,:-..: , , . :'-',. '. ,,- . ' ,,,i,. . . A:- ':',' eit:,,, ' ,,.. if . 7s. - „, ""4. •''',-:..,,'"' .,• •• .,, i --. •'-'-•.-Or.' -, 44,, - - -cr .- •-„,:';', ." / 4 - -"-- • 7*,,..0,1) 1 (. .., l i t ' . ; . ' : , ..' . ° ,,P . _ * * .**1 „ , *:- ,0 - 7 - 1 '''s 4 .: - - 4, i f. q .7' ;'''i 7 **:,,- . ''' * 4* . „' ; .,' ...; 4. : : ' , - r ; . ,-- .:, , *, ' -' ,, 4 It -*•:-. t P -- - ...i - -- .■ 4 ' .'*4!'""*.*, A * * '4.,' , '', * t i ..7.111,. ,. r. : . 1 '.4.,,__7 $ C il . i * , '111. ,; ‘146 7. w iv 7 . if 1. . .'.,. . .0.-.'#". _,, A e. .„ ,1 -. ,. ',- .• ii ..u- o , - , -,,,i, , ...i. - i .._ , v .._ , . ,,,, ,,,,, ..:...4. ,....0,4 k ,, -,,,,,, , -- • i„ .s,-0 - , i. ' -r,„,..., i'.,;.,<" ,,, ., , '44 - ,,,, "" , jor ' . - A:4' '0. -zit :; - . ..- ft.* ..if14*; 7: t7 4, Y, '. 4 • 4, i 4 6,41k'' ..- :,,,- i. .: ,,,.. .0 ,..:;;;. **.,',.....A. . ' 9 ' ....':'*-, ' ',. ,•."'`)94,.' ' '. ,L; 3,,,, 4 A„,,„.° „:1-. .-', -Y .,, . \,%-,* v - ,.! ,, ,A!.. ..,,,, • , !. , '*:',..4.-- - . . 'A.,.. osr' 0,, Vk..,... - • ' -' ...* .. - , • 4 ..,1-1 '7-- * .' 1 ".'":"* . - 1 * - -.; ..i .' , ''`'., - ".-; 71 ' ' i . • ., '.• .4" ;;' % ":" .• ' " :Niko,laevsk•: ..A." ''' A .,,..l...., -,•"„, ---• _",,j ',,' . 4:- 4,', . 4 " -"JAI ,77:11,.,,;,,- . ,„..;,.......- 0........'s,„:t twgt.s. a .:;"'" ..'.7 .4rial • 4 : * "I'''. ' 4 ' . 4' ' p 4 71 t..' . : ',._ ' ,.<4..; '1 ' :4111'0 -- , • . ' W0.0i ''''''....:• i . . .04744; : .4444.iO441' ...,' ..-, 5. ,,%.--, , :-r. .. :to*, 1,,f.s,;-,,I...--,f,,-,,,i.,i,,s,,,if , .•-•' ,.. ,i . ,. ,.',,,,.,,, 0., :::'-ie;!-, ---7 l '' r '.- .i. ;Iititt,4;'4•;:j4,1' AP *.o....- '..:* ** - ' ... 1410 ,,.......-..."-•*; r'.'-. .11..*!';'..,*..,.: *'' ;11';'",t4: ",:-1'....;'7' - ::7;;:' j ' At'''P's4;''' ' # *• ' '••••:: A i T , '''.. it ' . 1'1112 V:P!"1"::44i;:f16. 4 1,1111 ',7 • • *4.1*,,-.,!W: 4 ," ' 4 :: .. .:.; ,,e -.; 4.: 4 ' it;,: 4 •..t':Af -;.,le',A ,e „ford000 * Oh. ', '''''. :!!"...., .1 , • '0' ' ' , ii,. "' t.: le... ri ' : ',,_'1!,;...ti. ' l' :::'' ' ''''' .4! ' ' .if,' ..;.: , , ' • ..,; ,-, 104A.j , 0,:- ( -14 % .K...,:'. _ts,;,....,.4,!---.441,4 4,,,,,,,......0.7r,. IN, .„ , 47," w .*:. P t /I' . 7 ' . V ...-, ,, " ,.„4„,.. Ltil•:",;ipilt,po' ,'";,)--7-,;:.,.,. -, ,,' 4,'„•:..''''.,,;:,;,..;-- Ttit.f.,4 T.,. ‘ '...,...414.,.$ ...w.; ,... . '- 4 "" , ,, A - . i • AA, A:_-i' 'A*-AAA . .. # ‘.;."!. A t a er 1 Gii 0 ' 't 1 : 1 4. 4 ' _.• i.:„.•..: - N, ....,v . „,s4r.r.,*;-'.- 4 . , _ ., , 4,,,,,,;: .. *,',' - :, .. ,, .f, t.'.......-, ,I. ,,'- ,,,--%,...4-1 • 4 , 4 - - - , tlaP '-'11 - k r...... 4 ..:: ,ic'' ..'",',:.:.-i;-• -; ::1 - ' ..'--Y 4 .4 it:' , . - ' '...t.?' 1:17,1,, ,'''''4 : • :'' ' 7;44,4Ht.P4.1):# ; 44 0:1 . '`.. i ,--," •*44;,,.--,;,°- ,1,- 4. - "•''''-:.- .. , : . i -'' • .,,,, , -4* - 4, - ,,N, ,, • A , .# vt • ,F;`,4•;1_,i.:.,..- , ,: , - ,,,..,1%; '• A 4,- v7 .,' _.• !.. „..,,, ',•' ,:,, ..' 1 . - -* 4- w W„,, __ 4 *.,„"..,,,... ' . .. *.t' " .._ ..,, eiG,..,i0 11- GOODPq '74-- ..t - .w . - 1' . . - : 7 ".• `i 77' '''. ' „ :" 1. * .....,. Z77:1 _.7°:kot.40,,4t.,40i1,_. 77.7;77..„. , 4 4:,.. A „ , , A,.. ,- ). - ':-i E ,,-..,. - A.... ..-. :- . .„. - A ": . 44 . :, `7 !r. **4' '"*"74, * ' ''';t4.1'414!4411... ' '). ''''. ' 4, ii• !.-. '... • '0.----- - — • - ‘ ,.,,I I ., .4 , .,„: ....4 .., - 7 - 7 - H , - •• 1 .7.„-•' .— - T • stifty ay D 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. dec. state. ak. us INDUSTRY PREPAREDNESS PROGRAM Exploration Production & Refineries D APR 1 '2. r2�� April 23, 2007 APR 2 6 2007 Alaska °alga: . r . u • Ms. Faye Sullivan Anchorage Union Oil Company of California — UOCC (formerly Unocal) 909 West 9 Avenue Anchorage, AK 99501 ct ` t Re: Oil Discharge Prevention and Contingency Plan for Alaska Red Plan Number 044 -CP -5103 a%--■ _ Wty Dear Ms. Sullivan: 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, ,I 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. .�9 dam Printed on • 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, r 711111#3 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 oF ALAsKi:\ SARAH PALIN GOVERNOR 555 Cordova Street Anchorage, AK 99501 PHONE: (907) 269 -3094 DEPT. OF ENVIRONMENTAL CONSERVATION FAX: (907) 269 -7687 http://www.dec.state.ak.us DIVISION OF SPILL PREVENTION AND RESPONSE 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 /18AAC75Art1 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 Implientation 18 AAC 75 January 23, 2007 n 7 r ® �.°Y � e, 8 °,�' °"`4� °� � � 4 4 ®`,i x x wx , . <.� . . � r ?£, � x y1 :14 f q @ Q ? '� Q G1 � y ® h -^ f .d � Q <r !Q " a -; `• 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 Imp.entation 18 AAC 75 '++�� January 23, 2007 • 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 • • -,4~ --~ MICROFILMED 03/01/2008 DO NOT PLACE _, ~. ~: .-> ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFichelCvrPgs_Inserts\Microfilm Marker.doc .. , .' _ STATE OF ALASKA . ALA_ OIL AND GAS CONSERVATION CO ION GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a. Test: ~ Initial U Annual U Special 1b. Type Test: U Stabilized U Non Stabilized ~ Multipoint o Constant Time o Isochronal o Other 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Chevron North America Exploration and Production Company 7/17/2004 204-084 3. Address: 6. Date TD Reached: 12. API Number: 909 West 9th Avenue Anchorage, AK 99501 6/28/2004 50- 231-20021 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 338' FNL, 409' FWL, Sec. 8, T4S, R13W, S.M. 895' above MSL Red-01 Top of Productive Horizon: 8. Plug Back Depth(MD+ TVD): 14. Field/Pool(s): 816' FNL, 1,113' FWL, Sec. 8, T4S, R13W, S.M. 9,152' 18,831' Field: Nikolaevsk Unit Total Depth: 9. Total Depth (MD + TVD): Pool: Tyonek 1,551' FNL, 2,130' FWL, Sec. 8, T4S, R13W, S.M. 12,458' 114,047' 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 212,798 y- 2,140,995 Zone- 4 nla Red Pad TPI: x- 213,934 y- 2,140,130 Zone- 4 16. Type of Completion (Describe): Total Depth: x- 214,668 y- 2,139,672 Zone- 4 3 perforated zones 17. Casing Size Weight per foot, lb. I.D. in inches Set at ft. 19. Perforations: From To 7" 29 6.094" 4,601' MD 8/3/04 (6 spf) 8768 8777 18. Tubing Size Weight per foot, lb. I.D. in inches Set at ft. 7/23/04 (3 spf) 8795 8820 3.5" 9.2 2.992" 10,930' MD 8/3/04 (6 spf) 9056 9076 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 4412' MD SI nla 0.56 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): o Tubing 0 Casing 154 FO 3915 psia @ Datum 8700 TVDSS 14.7 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: I % CO2: %N2: %H2S: Prover: I Meter Run: I Taps: nla nla 0.57 0 0 0 - - - 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Ditt. Temp. Pressure Temp. Pressure Temp. Duration of Flow No. Line X Orifice Size (in.) Size (in.) psig Hw FO psig FO psig FO Hr. 1. 1.75 X 14/64 360 28 - 2494 58 - - 1.25 2. 1.75 X 16/64 420 51 - 2345 68 - - 8.5 3. 1.75 X 18/64 480 36 - 2292 74 - - 6.5 4. 1.75 X 20/64 490 44 - 2161 77 - - 9.75 5. X Basic Coefficient -J Pressure Flow Temp. Gravity Factor Super Compo Rate of Flow No. (24-Hour) hwPm Pm Factor Fg Factor Q1 Mcfd Fb or Fp Ft Fpv 1. - - - ~-.1Ul 1 ,UUI 3188 2. - - - - - - 4681 3. - - - - - - 5871 4. - - - -1' 11 :=n - - - 6638 5. nr- -L-I Y - ...!.,;',~ >.# "'4':-,";"-'~''U,':"'''''~·--'''''-'''''' - for Separator for Flowing No. Pr J te1Pf~9~7 Tr z Gas Fluid Gg G .. 1. ........ Gal ÇOM. - - - 2. - - . - - - 3. - - - - Critical Pressure - - 4. - - - - Critical Temperature - - 5. Form 10-421 Revised 1/2004 CONTINUED ON REVERSE SIDE Submit in Duplicate .. Pc Pc2 . pf No. Pt pf pc2 -pf Pw ~ pc2 -P~ Ps PS2 pf·PS2 1. - - - - - - - - - 2. - - - - - - - - - 3. - - - - - - - - - 4. - - - - - - - - - 5. 25. AOF (Mcfd) Remarks: n I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Title Date DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/ -J hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= {1ïZ" dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back-pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 1/2004 Side 2 Permit to Drill 2040840 I ì ,q.~ DATA SUBMITTAL COMPLIANCE REPORT 8/2/2006 Well Name/No. RED 1 Operator UNION OIL CO OF CALIFORNIA MD 12458'-/· TVD 12047/' Completion Date 7/17/2004 /' REQUIRED INFORMATION Completion Status 1-GAS Mud Log Yes Samples No DATA INFORMATION Types Electric or Other Logs Run: 8.5 Quad combo, 6-1/8 PEX, CMR, DSI, MSCT Well Log Information: Electr Digital Dataset Med/Frmt Number /C ~ Name Completion Mud Log Sample Pds 12664 Completion Cement Evaluation Log Log Run Scale Media No I C{ ~\.l,~ ~ 'i ~ 1 2 Sep ~ l-o.,s E'iC ~ 12663 Cement Evaluation 1fc) C Pds 12662 Completion ¿ L: ~C /' ,.5EY. C Ä 12662 Completion 12661 Completion Pds 12661 Completion Pds 12660 Completion K- 12660 Completion 2^-J\N~ ~ '1 ~ BS/ (iJf.Å~ ~v( BS ~ ~~'1 ""'/ BS Current Status 1-GAS .spo..L crJ~~vf.. API No. 50-231-20021-00-00 UIC N Dir~ctional Survey Q (data taken from Logs Portion of Master Well Data Maint Interval Start Stop 10150 10500 OH/ CH . Received Comments 9/22/2004 Completion Record Halliburton EZ-Drill Plug 2.5" Powerjet HSD 3SPF 28 12458 Open 9/16/2004 9/16/2004 10150 10500 9/22/2004 4000 10850 Case 9/22/2004 4000 10850 Case 9/22/2004 10150 9198 9/22/2004 10150 9198 9/22/2004 10565 10610 9/22/2004 10565 10610 9/22/2004 8771 9079 9/22/2004 8771 9079 9/22/2004 Omni Labs Rotary Core Analysis Report w/Photographs ~ N....,. /)1 ~ r~1 Completion Record Halliburton EZ-Drill Plug 2.5" powerjet HSD 3SPF Slim Cement Map Tool, DSN 12663 Slim Cement Map Tool Completion Record/Halliburton EZ Bridge Plug, 39' Cement 2.5" Powerjet HSD 3 SPF Completion Record/Halliburton EZ Bridge Plug, 39' Cement 2.5" Powerjet HSD 3 SPF DSN 12662 Completion Record/2.5" HSD Powerjets Completion Record/2.5" HSD powerjets Completion Record/2.5" HSD Powerjets Completion Record/2.5" HSD Powerjets . DATA SUBMITTAL COMPLIANCE REPORT 8/2/2006 Permit to Drill 2040840 Well Name/No. RED 1 Operator UNION OIL CO OF CALIFORNIA API No. 50-231-20021-00-00 ~ 12458 TVD 12047 Completion Date 7/17/2004 Completion Status 1-GAS Current Status 1-GAS UIC N I nd uction/Resistivity 25 ~g:/ 110 4601 12459 Open 9/22/2004 Multiple Propagation Resistivity Neutron, Density, GR, RWD DSN ~ ",- 12659 Induction/Resistivity 25 Bs/1'VD 4601 12459 Open 9/22/2004 Multiple Propagation Resistivity Neutron, Density, GR, RWD DSN 12659 ~ Las 12659 Induction/Resistivity 25 4601 12459 Open 9/22/2004 Multiple Propagation . Resistivity Neutron, Density, GR, RWD DSN 12659 ~ C Pds 12658 Production 8700 9140 Case 9/22/2004 Production Profile, SPIN, , Gradio, GR, CCL, Pres, ~ ~1 Temp 12658 Production 8700 9140 Case 9/22/2004 Production Profile, SPIN, Gradio, GR, eeL, Pres, I Temp. DSN 12658 ¥C Pds 12657 Induction/Resistivity 4620 12474 9/22/2004 Platform Express w/Array ~/ Induction 12657 Induction/Resistivity Ælu ìV/) 4620 12474 9/22/2004 Platform Express w/Array Induction, DSN 12657 ,~ .,..-/ f'/.lJ 12657 Induction/Resistivity BS 4620 12474 9/22/2004 Platform Express w/Array Induction, DSN 12657, u.eg/ Dipole-Compressional Only Sonic 25 B~ 'till) 4620 12474 9/22/2004 Dipole Shear Sonic Tool, P & S, Lower Dipole, TVD . ~/ HÐ DSN 12657 Sonic 25 ~1 4620 12474 9/22/2004 Dipole Shear Sonic Tool, P & S, Lower Dipole, DSN ~ 12657 Magnetic Resonance 25 BS 149 5600 12474 9/22/2004 Combinable Magnetic Resonance Too, DSN 126571 ~ Magnetic Resonance 25 BS ì\f~ 5600 12474 9/22/2004 Combinable Magnetic Resonance Too, DSN ~ 126571 See Notes ~s/. 5722 12260 9/22/2004 Mechanical Sidewall Coring Tool, DSN 12657 i ~!;) B "" 2Ü'40 Gamm3 Ray 8021 18071 9/28/2004 GR, IËWrM, GNP, SLD, I Bi)p, ACAI DATA SUBMITTAL COMPLIANCE REPORT 8/2/2006 Permit to Drill 2040840 Well Name/No. RED 1 Operator UNION OIL CO OF CALIFORNIA Sample Set Number Comments Cores and/or Samples are required to be submitted. This record automatically created from Permit to Drill Module on: 5/24/2004. MD 12458 Rpt TVD 12047 Completion Date 7/17/2004 LIS Verification Completion Status 1-GAS R¡5(" Report: Final Well R .J.ag t:õ9 LO~' 2 2 2 Col Col Col Mud Log See Notes Mud Log Well Cores/Samples Information: Name Interval Start Stop Received Sent ADDITIONAL INFORMATION Well Cored? l]/ N 5 ~ c.... tt. ..0\).''"'\ Daily History Received? Chips Received?..... Y I N Analysis ~ N Received? Formation Tops Comments: Compliance Reviewed By: _ ~ 8021 Current Status 1-GAS 18071 9/28/2004 o 9/7/2004 o 28 28 28 12458 Open 9/18/2004 12458 Open 9/18/2004 12458 Open 9/18/2004 (úN 7JyN API No. 50-231-20021-00-00 UIC N GR, EWR4, CNP, SLD, ROP, ACAL, DSN 12646 Epoch Final Well Report w/CD Drilling Dynamics Log Custom View . . Date: ?-l ~ ~ Co _ STATE OF ALASKA . ALAS~ AND GAS CONSERVATION COMMIS . WELL COMPLETION OR RECOMPLETION REPORT AN~ít\OG Oil U Gas ~ Plugged D Abandoned U Suspended D WAG D 1 b. Well tlass: 20MC 25.105 20MC 25.110 Development D Exploratory 0 No. of Completions 1 Other Service D Stratigraphic TestD 5. Date Comp., Susp., or 12. Permit to Drill Number: Aband.: July 17, 2004 204-084 6. Date Spudded: 13. API Number: June 9, 2004 50-231-20021 7. Date TD Reached: 14. Well Name and Number: June 28, 2004 Red-01 8. KB Elevation (ft): 15. Field/Pool(s): 895' above MSL 9. Plug Back Depth(MD+ TVD): 9,152/8,831' 10. Total Depth (MD + TVD): 12,458/12,047' 11. Depth Where SSSV Set: n/a 19. Water Depth, if Offshore: n/a feet MSL 1a. Well Status: GINJ D WINJ D WDSPL D 2. Operator Name: Union Oil Company of California 3. Address: PO Box 196247, Anchorage, AK 99519-6247 4a. Location of Well (Govemmental Section): Surface: 352' FNL, 392' FWL, Sec. 8, T4S, R13W Top of Productive Horizon: 1,176 FNL, 1,564 FWL, Sec. 8, T4S, R13W Total Depth: 1,616 FNL, 2,307 FWL, Sec. 8, T4S, R13W 4b. Location of Well (State Base Plane Coordinates): Surface: X = 212,798 Y = 2,140,995 TPI: X = 213,934, Y = 2,140,130 Total Depth: X = 214,668 Y = 2,139,672 18. Directional Survey: Yes ~ No U 21. Logs Run: 8.5 Quad Combo, 6-1/8 PEX, CMR, DSI, MSCT 22. CASING WT. PER GRADE FT. 16" 82.77 K-55 9-5/8" 47 L-80 7" 29 L-80 3-1/2" 9.2 L-80 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD TOP BOTTOM TOP BOTTOM HOLE SIZE o 50' 0' 49' o 1,790' 0' 1,789' o 4,601' 0' 4,600' o 10,930 0' 10,551' n/a 12-1/4" 8-1/2" 6-1/8" 23. Perforations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): 8768' - 8777' (6 spf, 8/3/04) 8795' - 8820' (3 spf, 7/23/04) 9056' - 9076' (6 spf, 8/3/04) 26. Date First Production: n/a Date of Test: Hours Tested: 8/4/2004 24 Flow Tubing Casing Press: Press. 1985 0 27. 24. SIZE 3-1/2",9.2# L-80 Nikolaevsk UnitITyonek 16. Property Designation: Red Pad 17. Land Use Permit: n/a 20. Thickness of Permafrost: n/a CEMENTING RECORD I AMOUNT PULLED Driven 110bbl, 12.8ppg lead/45bbl, 15.8ppg "G" 53bbl, 12.8ppg lead/30bbl, 15.8ppg "G" 209 bbl of 12.0 ppg Litecrete I TUBING RECORD DEPTH SET (MD) PACKER SET (MD) 4,412' Baker ZXP pkr @ 4,373' 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED Choke Size: GaS-Oil Ratio: 20/64" n/a Oil Gravity - API (corr): n/a Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". 5736': Ss fg slty; 5792': Ss fg slty; 5814': Ss fg slty; 5826': Ss fg slty; 5854': Ss fg slty spyrt; 6072': Ss f-mg slty; 6138': Ss f-mg vslty; 6334': Ss fg slty; 6390': Ss f-vcg vslty Ig incls; 6564': Ss fg slty thn lams; 6675': Ss fg slty thn lams; 6772': Ss fg slty; 8810': Ss mg slty thk shy lam; 8814': Ss m- cg slty; 8818': Ss m-vcg slty; 9064': Ss fg slty; 9069': Ss fg slty Ig incls; 9214': Ss mg vslty thn org lams; 9238': Ss m-cg vslty Ig incls; 9285': Ss m- cg vslty Ig incls; 9298': Ss fg vslty; 9308': Ss fg vslty; 9413': Ss fg slty scalc; 10068': Ss fg slty scalc; 10534': Ss fg slty scalc; 10606': Ss fg slty scalc; 10754': Ss fg slty Ig incl scale; 10768': Ss fg slty scalc; 10982': Ss f-vcg scalc; 11245': Ss f-cg slty Ig incls; 11677': Ss fg slty thn lams; 11681': Ss fg ,lty; 11781'. '" fg "ty. 11785'. S, fg "ty ,,,,,.11790'. S, 1~0 ,Ity ü'~TG T ~Ì\'[O'. S, 10 ",,, moo ftI. IDENT..AI.. Fo~ 1M07 RaW"'" 1212003 CONTINUED ON REVERSE RBDM{~;J 6 1004,_ Production for Test Period Calculated 24-Hour Rate PRODUCTION TEST Method of Operation (Flowing, gas lift, etc.): flowing Oil-Bbl: -+0 Oil-Bbl: ..... 0 Gas-MCF: 5777 Gas-MCF: 5777 CORE DATA Water-Bbl: o Water-Bbl: o ..; \, \w' b 28. GEOLOGIC MARKERS , NAME . 5,633 7,231 7,560 7,711 8,119 8,234 8,614 8,625 8,798 8,818 9,047 9,075 9,210 TVD Tyonek T20 T25 T35 T50 T40 T63 TOP T63 BOS T65 TOP T65 BOS T70 TOP T70 BOS T81 TOP 5,613 7,036 7,333 7,472 7,851 7,959 8,320 8,330 8,494 8,513 8,731 8,758 8,886 30. List of Attachments: Directional Survey, Schematic, Summary of Daily Operations 31 I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name: Tim C. Brandenburg S;900"'" '2.2.- cþ_ ~ 29. FORMATION TESTS Include and briefly .. rize test results. List intervals tested, and attach detailed supporting . as necessary. If no tests were conducted, state "None", Testing operations summarized in daily operations reports (attached). Contact: Rob Stinson 907-263-7804 Title: Drilling Manager INSTRUCTIONS Phone: 907-276-7600 Date: / I-~ -01 General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 CONFiDENTIAL . UNOCALe API: 50-231-20021 AOGCC: 204-084 352' FNL & 392' FWL Sec. 8, T4S, R13W, SM RT-THF: 17.22' Tbg lift threads - 3Y>" IBT Tree cxn - 2Y>" Bowen cxn Production Tubino: 3Y>", 9.2 ppf, L-80, IBT to 4412' - Annulus loaded with 7.4 ppg base oil Completion - Chemical injection sidepocket mandrel at 2502' (Macco SFO-1C-I) with 1/4", 0.049" wall SS chemical injection line - Locator sub @4378' - Baker 80-40 seal assembly 13' of 4.00" OD seals - Muleshoe at 4412' Pluos: - EZ-Drill CIBP at 9192' capped with 40' of cement (7/23/04) - EZ-Drill CIBP at 10420' (7/19/04) Directional Data: max hole angle = 29.1 deg KOP = 4800' max dogleg <3 deg/100' Red-1 schematic 8-4-2004 ~ · · · · · · · · · · · · · · .- ... z ~ z ... I ~ ~ ~ PBTD = 9152' TD = 12,458' . Well Name: Red #1 Field: Wildcat State: Alaska 'Iconductor: 16",82.77 ppf, K-55 to I 50' .. Surface Casino: 9%", 47 ppf, L-80, BTC to 1790' Cmnt with 110 bbl of 12.8 ppg lead and 45 bbl of 15.8 ppg tail "G" Intermediate Casino: 7", 29 ppf, L-80, BTC to 4601' Cmnt with 53 bbl of 12.8 ppg "G" lead lead and 30 bbl of 15.8 ppg "G" tail. Open Perfs: T-??: 8768' - 8777' (6 spf, 8/3/04) T-65: 8795' - 8820' (3 spf, 7/23/04) T-??: 9056' - 9076' (6 spf, 8/3/04) Isolated Perfs T-81: 9210' - 9280' (3 spf, 7/19/04) T-130: 10565' - 10610' (3 spf, 7/17/04) Production Liner: 3W', 9.2 ppf, L-80, IBT liner from 4379' - 10,930' Baker ZXP packer, Flexlock liner hanger & 80-40 seal bore at 4373' Cemented with 209 bbl of 12.0 ppg Litecrete CONFIDENTIAL Updated by: JGE >Information >Well >Directional Surveys >Fervey - ~îm~ . Select Well: RED 1 Report Name Well Date Created Position Log RED 1 11/3/2004 Well Name CURRENT STATUS API KB Surf X Surf Y (ft) (ft) (ft) r Jdt~ij)dlâtê RED 1 UNKNOWN 502312002100 895 212,798 2,140,995 MD rvD SSTVD X Off Y Off X Y Inc Azimuth (ft) (ft) (ft) (ft) (ft) (ft) (ft) (deg) (deg) 0 0 895 0 0 212,798 2,140,995 0.0 0 50 49 846 0 0 212,798 2,140,995 0.1 291 100 99 796 0 0 212,798 2,140,995 0.1 284 150 149 746 0 0 212,798 2,140,995 0.1 164 200 199 696 0 0 212,798 2,140,995 0.1 140 250 249 646 0 0 212,798 2,140,995 0.0 252 300 299 596 0 0 212,798 2,140,995 0.1 260 350 349 546 0 0 212,798 2,140,995 0.1 10 400 399 496 0 0 212,798 2,140,995 0.1 322 450 449 446 0 0 212,798 2,140,995 0.2 263 500 499 396 0 0 212,798 2,140,995 0.1 273 550 549 346 0 0 212,798 2,140,995 0.1 273 600 599 296 0 0 212,798 2,140,995 0.2 286 650 649 246 0 0 212,798 2,140,995 0.2 274 700 699 196 0 0 212,798 2,140,995 0.2 281 750 749 146 -1 0 212,797 2,140,995 0.2 282 800 799 96 -1 0 212,797 2,140,995 0.2 302 850 849 46 -1 0 212,797 2,140,995 0.3 297 900 899 -5 -1 0 212,797 2,140,995 0.2 284 950 949 -55 -1 0 212,797 2,140,995 0.2 267 1,000 999 -105 -1 0 212,797 2,140,995 0.3 262 1,050 1,049 -155 -2 0 212,796 2,140,995 0.3 265 1,100 1,099 -205 -2 0 212,796 2,140,995 0.4 254 1,150 1,149 -255 -2 0 212,796 2,140,995 0.4 245 1,200 1,199 -305 -3 0 212,795 2,140,995 0.5 260 1,250 1,249 -355 -3 0 212,795 2,140,995 0.4 263 1,300 1,299 -405 -3 0 212,795 2,140,995 0.4 257 1,350 1,349 -455 -4 0 212,794 2,140,995 0.4 262 1,400 1,399 -505 -4 0 212,794 2,140,995 0.4 262 1,450 1,449 -555 -4 0 212,794 2,140,995 0.3 259 1,500 1,499 -605 -5 0 212,793 2,140,995 0.2 247 1,550 1,549 -655 -5 0 212,793 2,140,995 0.3 237 1,600 1,599 -705 -5 0 212,793 2,140,995 0.3 245 1,650 1,649 -755 -5 0 212,793 2,140,995 0.4 256 1,700 1,699 -805 -6 0 212,792 2,140,995 0.5 250 1,740 1,740 -846 -6 0 212,792 2,140,995 0.6 219 1,806 1,805 -911 -6 -1 212,792 2,140,994 0.3 196 1,900 1,899 -1,005 -6 -1 212,792 2,140,994 0.5 180 1,995 1,994 -1,100 -6 -2 212,792 2,140,993 0.4 198 2,184 2,183 -1,289 -7 -3 212,791 2,140,992 0.4 213 2,373 2,372 -1,478 -8 -4 212,790 2,140,991 0.4 216 2,562 2,561 -1,667 -8 -5 212,790 2,140,990 0.3 205 2,751 2,750 -1,856 -9 -7 212,789 2,140,988 0.4 203 CONFIDENTIAL 2,940 2,939 -2,045 -10 -8 212,788 2,140,987 0.6 230 3,130 3,129 -2,235 -12 -9 212,786 2,140,986 0.6 233 3,319 3,318 -2,424 -13 -10 .,785 2,140,985 0.6 234 . 3,508 3,507 -2,613 -15 -11 ,783 2,140,984 0.6 240 3,697 3,696 -2,802 -17 -12 212,781 2,140,983 0.6 242 3,887 3,886 -2,992 -19 -13 212,779 2,140,982 0.9 254 4,076 4,075 -3,181 -22 -13 212,776 2,140,982 0.6 272 4,265 4,264 -3,370 -24 -13 212,774 2,140,982 0.6 264 4,454 4,453 -3,559 -25 -14 212,773 2,140,981 0.6 254 4,562 4,561 -3,667 -27 -14 212,771 2,140,981 0.8 249 4,642 4,641 -3,747 -28 -15 212,770 2,140,980 0.9 254 4,736 4,735 -3,841 -29 -15 212,769 2,140,980 0.5 196 4,831 4,830 -3,936 -28 -17 212,770 2,140,978 1.8 108 4,926 4,925 -4,031 -24 -19 212,774 2,140,976 3.5 115 5,021 5,020 -4,126 -17 -23 212,781 2,140,972 5.7 130 5,115 5,113 -4,219 -9 -30 212,789 2,140,965 8.4 128 5,210 5,207 -4,313 3 -40 212,801 2,140,955 10.6 122 5,304 5,299 -4,405 20 -50 212,818 2,140,945 13.4 120 5,399 5,391 -4,497 40 -63 212,838 2,140,932 16.0 122 5,494 5,482 -4,588 63 -79 212,861 2,140,916 17.9 124 5,588 5,571 -4,677 88 -96 212,886 2,140,899 19.6 122 5,683 5,659 -4,765 116 -113 212,914 2,140,882 21.6 120 5,777 5,746 -4,852 147 -132 212,945 2,140,863 24.3 120 5,872 5,832 -4,938 182 -154 212,980 2,140,841 26.5 122 5,967 5,916 -5,022 218 -179 213,016 2,140,816 28.6 124 6,061 5,999 -5,105 253 -205 213,051 2,140,790 27.2 125 6,155 6,083 -5,189 288 -230 213,086 2,140,765 26.8 125 6,250 6,167 -5,273 323 -257 213,121 2,140,738 27.8 126 6,345 6,252 -5,358 356 -283 213,154 2,140,712 25.5 126 6,440 6,338 -5,444 389 -308 213,187 2,140,687 25.8 126 6,534 6,421 -5,527 424 -334 213,222 2,140,661 29.1 125 6,629 6,505 -5,611 461 -360 213,259 2,140,635 28.5 124 6,723 6,587 -5,693 498 -386 213,296 2,140,609 28.6 123 6,818 6,670 -5,776 536 -412 213,334 2,140,583 29.0 123 6,913 6,754 -5,860 573 -438 213,371 2,140,557 28.5 124 7,007 6,837 -5,943 610 -463 213,408 2,140,532 27.6 124 7,102 6,921 -6,027 645 -488 213,443 2,140,507 26.7 125 7,196 7,005 -6,111 678 -513 213,476 2,140,482 26.6 125 7,291 7,090 -6,196 713 -539 213,511 2,140,456 26.8 124 7,386 7,175 -6,281 747 -563 213,545 2,140,432 25.7 125 7,480 7,261 -6,367 779 -587 213,577 2,140,408 24.1 125 7,575 7,347 -6,453 810 -610 213,608 2,140,385 23.8 125 7,669 7,433 -6,539 840 -633 213,638 2,140,362 23.7 126 7,764 7,521 -6,627 869 -655 213,667 2,140,340 22.7 127 7,859 7,609 -6,715 898 -678 213,696 2,140,317 22.1 126 7,953 7,696 -6,802 925 -699 213,723 2,140,296 21.3 127 8,048 7,785 -6,891 952 -720 213,750 2,140,275 20.7 127 8,142 7,873 -6,979 977 -741 213,775 2,140,254 19.8 128 8,237 7,962 -7,068 1,001 -761 213,799 2,140,234 18.6 128 8,332 8,053 -7,159 1,024 -780 213,822 2,140,215 18.2 128 8,395 8,112 -7,218 1,040 -793 213,838 2,140,202 18.6 127 8,458 8,172 -7,278 1,055 -805 213,853 2,140,190 18.1 127 8,521 8,232 -7,338 1,071 -817 213,869 2,140,178 17.9 127 8,647 8,351 -7,457 1,103 -842 213,901 2,140,153 19.6 124 8,774 8,471 -7,577 1,137 -866 213,935 2,140,129 18.9 124 8,900 8,591 -7,697 1,171 -888 213,969 2,140,107 18.6 122 CONFIDENTIAL 9,026 8,711 -7,817 1,202 -910 214,000 2,140,085 16.2 124 9,152 8,831 -7,937 1,232 -932 214,030 2,140,063 18.6 127 9,279 8,951 -8,057 1,264 -958 .,062 2,140,037 19.2 127 . 9,406 9,071 -8,177 1,297 -983 ,095 2,140,012 18.7 124 9,532 9,190 -8,296 1,330 -1,006 214,128 2,139,989 19.2 123 9,658 9,310 -8,416 1,363 -1,028 214,161 2,139,967 17.2 122 9,785 9,432 -8,538 1,394 -1,048 214,192 2,139,947 16.0 121 9,911 9,553 -8,659 1,423 -1,067 214,221 2,139,928 16.2 122 10,037 9,675 -8,781 1,450 -1,084 214,248 2,139,911 13.1 119 10,164 9,799 -8,905 1,474 -1,098 214,272 2,139,897 12.6 119 10,290 9,922 -9,028 1,498 -1,112 214,296 2,139,883 12.1 118 10,416 10,045 -9,151 1,520 -1,124 214,318 2,139,871 11.1 120 10,543 10,170 -9,276 1,540 -1,136 214,338 2,139,859 10.3 119 10,669 10,294 -9,400 1,558 -1,148 214,356 2,139,847 9.6 121 10,790 10,413 -9,519 1,576 -1,158 214,374 2,139,837 9.7 121 10,885 10,507 -9,613 1,590 -1,167 214,388 2,139,828 10.3 120 10,980 10,600 -9,706 1,604 -1,176 214,402 2,139,819 10.3 119 11,075 10,694 -9,800 1,619 -1,184 214,417 2,139,811 10.3 119 11,170 10,787 -9,893 1,634 -1,193 214,432 2,139,802 10.8 119 11,265 10,880 -9,986 1,650 -1,203 214,448 2,139,792 11.5 119 11,359 10,973 -10,079 1,666 -1,212 214,464 2,139,783 11.3 120 11,454 11,066 -10,172 1,682 -1,222 214,480 2,139,773 11.6 118 11,549 11,159 -10,265 1,698 -1,231 214,496 2,139,764 11.8 118 11,644 11,252 -10,358 1,716 -1,241 214,514 2,139,754 12.3 117 11,738 11,343 -10,449 1,734 -1,250 214,532 2,139,745 12.6 116 11,833 11,436 -10,542 1,752 -1,260 214,550 2,139,735 12.6 116 11,928 11,529 -10,635 1,770 -1,270 214,568 2,139,725 12.6 116 12,117 11,713 -10,819 1,807 -1,289 214,605 2,139,706 12.6 117 12,212 11,806 -10,912 1,825 -1,298 214,623 2,139,697 12.8 115 12,307 11,899 -11,005 1,844 -1,308 214,642 2,139,687 12.3 119 12,391 11,981 -11,087 1,858 -1,317 214,656 2,139,678 11.2 118 12,458 12,047 -11,153 1,870 -1,323 214,668 2,139,672 11.2 118 CONFIDENTfAl 5/24/2004 From To Hours 0:00 0:00 24 5/25/2004 Remarks Picked up water samples from water well del to HV for Sclumberger. Haul 400 bbl water tanks from NNA to Red pad. Tolloff mob crane from Nikiski to Red rig up and prepare for driving conductor tomorrow am. From 0:00 6:00 21:00 To 6:00 21:00 0:00 Hours Remarks 6 No Operations 15 Drive Conductor /40' 3 Shut Down for night 5/26/2004 From 0:00 6:00 To 6:00 12:00 Hours 6 6 12:00 22:00 10 22:00 0:00 2 5/27/2004 From To Hours 0:00 6:00 6 6:00 20:00 14 20:00 0:00 4 5/28/2004 From To Hours 0:00 6:00 6 6:00 20:00 14 . Remarks Operation suspended Drive conductor 50' stopped at 164blows per ft. Cut Off Accept Rain for rent tanks and put in berm 4-4000bbl tanks close in berm, Move in and set up Nabors camp DSM camp set generator package, Set water tanks, Spot satellite, Pre -load ISO tanks for am delivery. Accepted and tested road with loads of rig matts. Suspend Operations Remarks Operations Day Crew only Start Mobilization of O.B.M. From Happy Valley to Red Pad 320 bbls. Set Matt boards over Stariski river bridge to Road Nabors Substructure to pad.Set Diesel tank and berm, Excavate and install cellar. Send I.S.O. back to be reloaded at Happy Valley for . tomorrow. Worked on tank farm berm and load and unload containment area. Set up communications in DSM and Toolpushers . Trailer. Shut down Remarks Operation Day Crew Only Start Mobilization of O.B.M F/ Happy Valley Shipped 4- ISO 80 bbls each and vac truck 60 bbls total 360 bbls. 720bbls delivered to Red. Send ISO Back F/loading @ Happy V1;illey. Seam liner toge.ther Lay felt and liner. 150x1 00' pieces. Double liner and felt set rig Matts. Wired water pump and pump failed. Bring out drilling connex to use as peak parts room. Red-01 morning report summary_AFE162461 page 1 CONFIDENTIAL: last revised 11/8/2004 20:00 0:00 5/29/2004 From 0:00 To 7:00 Hours 7 7:00 19:00 12 19:00 0:00 5 5/30/2004 From To Hours 0:00 6:00 6 6:00 18:00 12 18:00 0:00 6 5/31/2004 From To Hours 0:00 5:30 5.5 5:30 6:00 0.5 6:00 19:00 13 19:00 19:00 0 19:00 19:00 0 19:00 19:00 0 19:00 19:00 0 19:00 19:00 0 19:00 19:00 0 19:00 19:00 0 4 Operations shut down for night Remarks Operations working day shift only Transfer O.8.M. from happy Valley to Red pad 200bbls last transfer ,Total bbls on Red pad 1,065bbls. Move 4 - rain for rent tanks out of Happy Valley containment to G&I to do initial cleaning before sending to S&R for final cleaning and return. Need to pull up liner and do dirt work pad real soft. Load out equipment needed on red pad ship to red pad from happy valley. Pull Water pump wire on pump had come apart rewire run pump back in well test worked good start filling 400 bbl water tanks. Set up dock in front of Co.man trailer. Work on final cut for drive pipe. Operations working day shift only . Remarks Operations working day shift only Measured spools and had Peak cut off conductor weld on nipples, landing plate. Adapter spool would not fit was ordered for .500 wall and conductor is .625 wall. Will take it to a machine shop and have it milled down to fit today and pick up on Monday to have ready for welder Tuesday am. Cleaned last 2 rain for rent tanks at NNA from HV tank farm. Operations working day shift only Remarks Operations Suspended ( working day lights only) PTSM wI peak Sucked out cellar & prep for welding PJSM wI CIW & weld starting head & ladder in cellar . Finished RIup of water lines to Camps Installed Water meter on water well ' " , First load of Nabors rig #129 arrived @ 1100 hrs Talk wI driver & called Peak trk pusher about there plan forward will attempt two regular loads & 4-5 permit loads also having problem getting permits - forward plan is to spot same on location & will be on location 6/2 - Called Nabors Tool pusher & confirmed same & will be on location 6/2 also wI hands (only 2 regular loads & one permitted load showed) One W81 trks came & hauled out Toloff support equipment due to problems with toloff tractor & roaded out toloff tractor One W81 trks came & attempted to hook up to Toloff trailer wI D-32 hammer staged on first pull out 0.5 miles from location & started having problems wI soft shoulder & called rig for support - Peak drilling support loader & ASRC D-4 cat assisted Talked wI Tom Sopkowiak on forward plan of ASRC equipment on road for Star pad & found out there walking Cat To location Went to Star pad & chk progress of pad Red-01 morning report summary _AFE 162461 page 2 CONFIDENTIAL: last revised 11/8/2004 19:00 19:00 0 19:00 0:00 5 6/1/2004 From To Hours 0:00 5:30 5.5 5:30 6:00 0.5 6:00 19:00 13 19:00 19:00 0 19:00 19:00 0 19:00 19:00 0 19:00 19:00 0 19:00 19:00 0 19:00 19:00 0 19:00 19:00 0 19:00 19:00 0 19:00 0:00 5 6/2/2004 From To Hours 0:00 6:00 6 6:00 6:30 0.5 6:30 10:00 3.5 10:00 18:00 8 18:00 18:00 0 18:00 18:00 0 18:00 18:30 0.5 18:30 0:00 5.5 Sent vac trk to NNA G&I to transfer fluid out of cutting box to hot house tank for Dump test of Vacuum tank & returned to Red pad Suspend operations (Daylights only) Set up office - work on paper work - orient Night foreman Larry McAllister Remarks Operations Suspended ( working day lights only) PTSM wI peak Sucked out cellar & prep for welding PJSM wI CIW & weld starting head & ladder in cellar Finished Rlup of water lines to Camps Installed Water meter on water well First load of Nabors rig #129 arrived @ 1100 hrs Talk wI driver & called Peak trk pusher about there plan forward will attempt twA regular loads & 4-S permit loads also having problem getting permits - forward plan is to spot same on location & will be on locati. 6/2 - Called Nabors Tool pusher & confirmed same & will be on location 6/2 also wI hands (only 2 regular loads & one permitted load showed) One WSI trks came & hauled out Toloff support equipment due to problems with toloff tractor & roaded out toloff tractor One WSI trks came & attempted to hook up to Toloff trailer wI 0-32 hammer staged on first pull out O.S miles from location & started having problems w/ soft shoulder & called rig for support - Peak drilling support loader & ASRC D-4 cat assisted Talked wI Tom Sopkowiak on forward'plan of ASRC equipmenfon road for Star pad & found out there walking Cat To location Went to Star pad & chk progress of pad Sent vac trk to NNA G&I to transfer fluid out of cutting box to hot house tank for Dump test of Vacuum tank & returned to Red pad Suspend operations (Daylights only) Set up office - work on paper work - orient Night foreman Larry McAllister Remarks Suspended operations daylights only . PJTM w/ Peak Day Drill Site Crew. Peak Crew work/on containment barrel storage racks & ready connex & drive pipe for haul 1 st of Sloads of Rig pkg arrived @ Loc. w/3 Nabors personnel. Tool Pusher arrived @ 11 :30 AM. Total of S loads + 2 Rlu Trucks - Another Sloads wI Unocal Equip. Set Sub-base, Drawworks, & Pumps 1 & 2 skids. Pits & Gen Set spotted. Drilling Crew ended tour @ 18:00 hrs. Two Pushers on location for night WI no crew. Medic set/up helipad, equip & office. Mud Man arrived @ 18:00 Hrs. PTSM w/ Peak Night Drill Site support crew. Support crew Spotted septic for Service Hand Camp & hooked/up same. Set Nabors Camp stairs - Finish bbl strg racks in tank farm & loaded same as/per mud man. Red-01 morning report summary_AFE162461 page 3 CONFIDENTIAL: last revised 11/8/2004 6/3/2004 From To Hours 0:00 6:00 6 6:00 6:30 0.5 6:30 8:00 1.5 8:00 8:30 0.5 8:30 10:00 1.5 10:00 18:00 8 18:00 18:00 0 18:00 18:00 0 18:00 18:00 0 18:00 18:00 0 18:00 18:00 0 18:00 18:30 0.5 18:30 0:00 5.5 6/4/2004 From To 0:00 6:00 6:00 6:30 6:30 6:30 6:30 6:30 6:30 6:30 6:30 18:00 18:00 0:00 Hours 11.5 6 Remarks No work by Nabors - Peak PM crew finished bbl storage in tank farm - Finished truck apron @ tank farm - Finished parking lot & organized pad & Equip PTSM wI Peak Day crew Ready pad for Rig Equip & R/u - 4) Nabors hands arrive on location (2 TP's already here) PTSM w/ Nabors crew Ready Rig & Pad for Trucks & R/u - 1 st load arrived @ 10:00 hrs 7 Peak truckloads of Rig hauled to locatiqn& 1 WBI truckload wI suction pit on Lo-boy - WBI roaded Lo-boy & trailer to 1 Mile/out staging area & .. . returned to location & hauled mud products, not to be used, to OSK - 1) DSM, Peak day foreman & operator roaded vac truck to HV Pad -- Vac'd/out . Coil Tank & prepped same for mobe - Observed test of vac tank system & returned to Red Pad - Nabors set suction tank, gen house, water tank & dog house - Raised dog house & lowered landing to rig floor & installed hand rails - Rig units left to spot & set = boiler house, parts connex, shaker pits, T/drv SCR house hyd unit, Can Rig gen set, & three sections of derrick - Nabors Electrician arrived @ 16:00 hrs & plugged juice to service camp - Nabors shut/dn for the night. PJSM wI Peak Support PM crew Unload 3) WBI trucks wI Mud Shack, Epoch, & misc jewelry - Road Radio Shack w/ loader & pilot car to outer staging area. Remarks 6 0.5 WBI haullin & stage@1mile/outstagingarea3cementsilos&CoiITbgTank - Continue to organize & stage equipment Ion pad._ PTSM wI Peak Day Support Crew _ Held PTSM for Nabors - Safety walk-a-bout - housekeeping - - Organized pump, dog houses, parts connex - spot PPE lock - set fans for pump house cooling - Check centrifugal impellers & bowls - Peak arrived @ 09:00 hrs - Turn A-legs around & spot to assemble derrick - Pin derrick section together, set crown section on truck - Move derrick into position to set/on sub-base @ 15:00 hrs - Stringlup derrick blocks, uncoil service loops & tie to derrick - String electrical to doghouselkoomey - Change tugger sheaves & crown. Mike Muller wI Arctic Wire Rope inspected equip. Peak PM Support Crew - Spot BHI house - General maintenance of camps, equip, & pad housekeeping. o o o Red-01 morning report summary_AFE162461 page 4 CONFIDENTIAL: last revised 11/8/2004 6/5/2004 From To Hours 0:00 7:00 7 7:00 0:00 17 6/6/2004 From To Hours 0:00 5:00 5 5:00 7:30 2.5 7:30 10:30 3 10:30 12:00 1.5 12:00 18:00 6 18:00 0:00 6/7/2004 From To Hours 7:00 7 7:00 0 7:00 0 10:00 3 13:00 3 0:00 7:00 7:00 7:00 10:00 Remarks No Nabors night crew - Road loader & repossession radio shack - Continue pad maintenance & prep to set service support equipment Set water transfer pump - dig ditch - PTSM wI peak & run water line to rig - Nabors crew on location - PTSM wI both crews - Installed Canrig beam in A-legs - Installed kelly hose - Finished installing New tugger sleeves - Rigged Trks up to pin derrick - PJSM - Pinned derrick - set crown on stand - raised A-legs - Set shaker pit - Set boiler house - Set shop - String up derrick - Set chg house - Set Canrig SCR & gen set - Prep derrick for raising - Raise derrick - Rig up tuggers & lines - fuel, air, water, Glycol tI brakes & steam - set mouse hole to chk sleeve angle & mouse depth - Used Peak Pole trk when Nabors was done & set centrifuge & raised service hand trailer - WBI hauled out Mud & set coil tank, centrifuge tank, Epoch shack, shaker cutting tank & BHI shack- No Nabors crews - Set & stand 3 Cmt silos & continue digging cellar for 20" sleeve angle & mouse hole depth Nabors had P.S.I out go thru gas detection system .- 6 Remarks No Nabors crews - Set & stand 3 Cmt silos & continue digging cellar for 20" sleeve angle & mouse hole depth & offload & stack mud products Nabors day crew on location - PJSM - Set Hawk jaw Power pack - Set stairs I floor to pit - set gas buster - String man rider - Assemble tarp wind walls @ shaker pit - One DSM & peak operator wI vac trk to Happy valley pad - for coil tbg operations Organize rig floor - reposition Service loop - make up mud manifold - tie back bridle line - Prep to rlup top drive String wires to pits - move gen-set arm - Prep to extend grass hopper - work on Canrig genset - work on vent on doghouse- set choke house -line up trk to plup top drive load two bulk trksinto silos PJSM - RIup & raise top drive torque tube - Connect blocks to Top drive - RIup top drive line to rig floor RIup floor , Mud manifold, weight indicator - general house keeping - RIup chutes off shakers into cutting's tank - 2 Peak & DSM 2nd attempt to set 20" mouse hole sleeve @ correct angle work wash & sledge hammer 20" 5' into cellar floor & pour 16-18" of concrete under base plate & 1-2" above base plate .- .. Remarks Finish pour of cement in cellar floor wI Peak Support - Nabors moved outside service loop - Silicone rig floor - Clo 8" valve & install shaker dump line - Peak support finished cmt pour of cellar floor - Nabors Iyldn mouse hole - hang tongs & add wt to buckets - Install 5 112" liners & swabs in #1 & #2 pumps - Peak held PTSM - Nabors move catwalk & measure slide for welder Run Can-Rig wires to J-Box - Hook/up hydraulic hoses - Hook/up wires to Can-RigTop/drv All personnel to Unocal Spud Meeting @ Up Chuck Saloon - Presentations by: Evan, Shane, Safety men, Environmental & Regulatory Red-01 morning report summary_AFE162461 page 5 CONFIDENTIAL: last revised 11/8/2004 13:00 0:00 11 6/8/2004 From To Hours 0:00 6:00 6 6:00 7:00 1 7:00 10:00 3 10:00 10:30 0.5 10:30 12:00 1.5 12:00 18:00 6 18:00 0:00 6 6/9/2004 From To Hours 0:00 4:00 4 4:00 7:00 3 7:00 8:00 1 8:00 10:30 2.5 10:30 11:30 1 11:30 14:30 3 14:30 0:00 9.5 6/10/2004 From To Hours 0:00 14:00 14 14:00 15:00 1 Nabors set CIW spool on conductor & test to 1000 psi w/CIW- Set diverter spool & align - Set knife valve & diverter line - Weld snub post pockets - Rlu centrifuge wI Swaco - Put MP's in service - Wire Tldrv & test same - P/u elevator bails - Nipplelup Surface Annular on diverter spool & tighten Peak support hauled 95 Bbls base oil frml HV#6 to Red Pad & pump same into Tank #1 - Install pad liner & spot Dowell Cmt Equip & berm same Nabors berm in/front of sub & under catwalk - Set cat walk & beaver slide Remarks Level pipe racks - finish diverter line - Hang kelly hose - Adjust gooseneck on Tdrv =- Install 4" HP fittings to mudline - Install flowline Ton possum-belly - Test-fit flow line - Peak crew organize & clean/up pad Test-fit flow line - Test-fire Mud Pumps 1 & 2 motors - PTSM w/ Peak support Make cuts in top of beaver slide for snub posts - P/u derrick-climber & anti-fall climber - Install crown lights & geronimo line Function-test annular & knife valve to diverter - Good test Run blocks thru derrick - Check service line & kelly hose - Hook/up mud line jumper hose - Tighten clamps on mud line. PTSM - Hang line for Hawk Jaws - H20 in pits to check integrity - work on rig acceptance & accepted rig @ 18:00 hrs Mix mud & prep for spud . Remarks Finish walkways - Mix mud - Prep test pump - Press test hi-press mud system to 5000 psi - OK Ready rig & location for spud & acceptance - Install 4" ball valves on conductor - Also 2) 1" plugs - Prep to P/u DP & caliper BHA Set mouse hole - P/u 1) jt 4" DP & attempt wash 1 st joint Rlu spinner-hawk & P/u 60 jts 4" DP P/u & rack/bk 18 jts 4" Spiral HWDP . P/u BHA #1 SPUD - Drill/out 16" conductor to shoe @ 50' RKB & to 708 @ Mid PM Remarks Drill 12-1/4" hole f/ 708' U 1800' rkb Circ btm/up pump 6 oz carbide flag & continue to circ clean (9.4 bbls over cal.) flow chk (ok) Red-01 morning report summary_AFE162461 page 6 CONFIDENTIAL: last revised 11/8/2004 15:00 21:30 6.5 21:30 22:30 1 22:30 23:30 1 23:30 0:00 0.5 -- 6/11/2004 From To Hours 0:00 1:00 1 1:00 3:00 2 3:00 3:30 0.5 3:30 6:00 2.5 ---- 6:00 8:00 2 8:00 12:30 4.5 12:30 15:30 3 15:30 17:00 1.5 17:00 17:30 0.5 17:30 19:30 21:00 22:30 19:30 21:00 22:30 0:00 2 1.5 1.5 1.5 6/12/2004 From 0:00 2:30 To 2:30 3:00 Hours 2.5 0.5 3:00 0:00 21 6/13/2004 From -~----- 0:00 To 1:00 Hours Remarks 1 Shell tst BOP & CHK Mnfld 3000 PSI - OK Attempt pump pooh had top drive problems & air to drillers console (1-1/2 dn time) Had numerous 20-30k over tight spots starting @ 1549' work thru & clean up same Hung pipe & pack off @ 1261', 854' & 328' (Lost 33 bbls mostly on pack offs , lots of cutting over shakers Clay sand stone coal Lldn 1 jt of 5" HWOP & plup jars Rih w/ no problems Safety Wash & ream last 53' to btm (no fill ) Remarks Circulate & condition mud & hole POOH - Smooth to 5" HWOP Chg/out elevators to 5" & std/bk same Std/bk 4" HWOP & 4" OP & Ly/dn 8" portion of BHA . P/u & Rlu to run 9 5/8" Casing P/u & run 9 5/8" casing ,P/u Jt #44 & Circ/head Circulate hole clean & wsh to btm (1800' TO) No fill Ly/dn Jt #44, P/u Cmt Head - Circulate & Reciprocate pipe Hold PJSM wI all personnel Rlu OS- Pump 3 bbls H20 ahead, Test surface lines 3000 psi- OK - Pump 30 Bbls Mudpush XL --Follow w/ 110 bbls Lead (12.8 ppg - G wI 2% 079, .75% S002, .2 % 046) - follow w/45 bbls tail (15.8 ppg - G .5% S002, .3% 065, .2% 046) follow wI 5 bbls H20 - Switch to rig pumps- Pump 127.5 bbls Oisplacement- Bump Plug @ calc. - CIP @ 19:08 hrs - Test csg U 3060 - 3060 psi in 30 min. (on chart) chk floats (ok) Ly/dn Landing jt, clean & drain stack - Cmt from stack = 12.8 ppg Rlu & run Gyro survey on WL - Good log - .57 deg @ TO = worst Ly/dn mouse hole & beaver slide - Ly/dn pitcher nipple & Nip/dn Annular Remarks Nipple/down diverter system & remove from cellar Install CIW MBS wellhead & test to 5000 Psi . Nipple lup BOPE -Install choke & kill valves - Install newly fabricated Split pitcher nipple - Install VBR in top rams & 4" in btm set rams wI blinds in middle - Rlup choke house & lines & function test choke - Function test BOP equipment - General housekeeping of work areas - Install BHI depth monitor on draw works - Trouble shoot top drive problems - Rlu & attempt shell test - Repair leaks. Red-01 morning report summary_AFE162461 page 7 CONFIDENTIAL: last revised 11/8/2004 1:00 2:30 2:30 6:30 6:30 7:30 7:30 9:00 9:00 12:30 12:30 15:00 15:00 16:00 16:00 17:30 17:30 18:30 18:30 19:30 19:30 20:30 20:30 22:30 22:30 0:00 6/14/2004 From To 0:00 22:30 22:30 0:00 6/15/2004 From To 0:00 0:30 0:30 2:30 2:30 3:00 3:00 7:30 7:30 8:30 8:30 12:30 12:30 15:00 15:00 23:00 1.5 4 1 1.5 3.5 2.5 1 1.5 P/u tst Jt & install test plug Test BOPE 250/4500 Psi - Witnessed by AOGCC - Good Test Pull & Iyldn test jt & install wear ring Re-install 7" rams & test door seals 3000 Psi - OK P/u & stdlbk 30 jts 4" DP P/u BHA #2 Mud motor & MWD wI Bit #2R1 & orient tool RIH wI 4" HWDP & P/u Ghost Reamer wI XO's P/u 4" DP & RIH & tag cmt @ 1723' - Hold choke drill for crew wI Unocal - Good & Safe drilling practices stressed - Entire crew got a feel for the choke, guided by S. Hauck Break Circulation - RIH & tag FC @ 1744' DPM - Drilledlout FC , Shoe (cmt= semi firm) & 20 feet of new hole Circulate & condition mud into system & dump cement contamination PJSM - for LOT - R/u OS & test surface lines to 1000 Psi - OK - Perform LOT according to Unocal SOP - EMW = 15.01 Ppg- Confirm wI Supt Drill 8 1/2" hole to 2047' . 1 1 1 2 1.5 Hours Remarks Drill 8 1/2" hole from 2047' to td @ 4615' - Orient slide frml 3939' to 3969,4146' to 4159', & 4317' to 4322'. Very difficult holding tool 22.5 face. All else rotary. Actual onlbtm drilling time = 14.6 hrs. (Apig =117.2 fph) 1.5 Circulate & condition mud & hole - Run carbide sweep (calc'd 15 bbls over gauge hole) Remarks Cont Cir & Cond hole for wire line logs 8 POH from 4,615 to 3,440 - Had some tight spots 3,970 + 3,906 + 3,883 + 3,845 Worked through same & they cleaned up well Mix & Pump Dry job . Cont POH for wire line logs Rig up Schlumberger - Hold pre-Job safety meeting on loading sources & Logging program RIH with Schlumberger Quad Combo - Had trouble with opening caliper at 95/8" shoe thought we had problem fixed - Cont RIH - Set down at 4,544 e-line measurement - Could not work past that point - Attempt to open caliper - Would not function - made decision to pull logs to 9 5/8" shoe - Then trip wire for repairs - Talked to G&G Mr. Buthman - Tripped out and found broken wire on Caliper function - Fixed same - RIH & Re-pull quad combo - Pull Logs from T.D. 4,615 to 9 5/8" shoe - Pulled GR to surface logged w Rig down Schlumberger - Pull Wear Ring - Rig up to run 7" casing Pre Job Safety Meeting Cont RIH with casing Cir down last 80' to btm - Saw one tight spot at a shoe depth of 4,585 - Worked through same & did not have any more trouble - Cir well clean for cement Job Hours 0.5 2 0.5 4.5 1 4 2.5 Red-01 morning report summary_AFE162461 page 8 CONFIDENTIAL: last revised 11/8/2004 23:00 0:00 6/16/2004 From To 0:00 0:30 0:30 2:00 2:00 2:30 2:30 4:00 4:00 7:30 7:30 8:30 8:30 15:00 15:00 15:30 15:30 16:00 16:00 19:00 19:00 21:00 21:00 0:00 6/17/2004 From To 0:00 1:00 1:00 6:30 6:30 8:30 8:30 10:30 10:30 13:30 13:30 14:30 14:30 17:30 17:30 18:30 18:30 20:30 20:30 0:00 6/18/2004 From To Hours 0.5 1.5 0.5 1.5 3.5 1 6.5 0.5 0.5 3 2 3 Hours 1 5.5 2 2 3 1 3 1 2 3.5 1 Make up Landing joint and land out with 7" shoe at 4,601 & FIC at 4,517 - Note had +1- 10k drag just before landing 7" string - Decided to Drain stack & confirm landed - Make up cement head during this time - Hanger was landed OK Remarks Rig up Cement Head - Pre job safety meeting Mix and Pump Cement job (description 06-15-04) Pressure test casing against plug to 3,000psi for 30min Rig down Cement head and landing joint Set packoff - Energize Seals & pressure test to 5000psi for 30min OK Change BTM pipe rams to 4" Install test plug and pressure test all BOP equipment - Pipe Rams & annular on 4" + CSO + HCR & Choke line valve + Kill Line Valves + Choke Manifold & valves . Pull Test plug & rig down test equipment Set wear ring Install Drip Pan - Change pump Liners to 5" - Strap D.P. - Condition OBM for change over Make up BHA BHI Upload and test electronics - Load sQurces Remarks RIH with HW DP from Derrick RIH picking up 4" D.P. - Tagged FIC at 4,534- 17' deep - Checked Casing tally and found mistake - Corrected depth of Shoe = 4,615 FIC = 4,531 Casing tally Measurements Break Cir - Conduct Choke Drill with NAD Drill Crew - Talked threw Drillers Method of Well Control & Best Drilling Methods Slip & Cut Drilling line - Service Rig Change over to Oil Base Mud - Had problems with hitting correct Mud Weight - See #4 Drill Float collar & Clean out shoe track to within 10' of shoe. . Cir & Cond Mud to get weight up to 8.9ppg prior to Drilling out shoe Clean out Shoe and Drill 20 I of New hole to 4,638dpm Pull into shoe - Rig up Schlumberger for LOT - Perform LOT to a 13.2ppg MWE at 4,615dpm - Max pressure seen before Break = 1,529psi Rotary Drill to 4,723 - Start Directional Work Hours Remarks Red-01 morning report summary _AFE 162461 page 9 CONFIDENTIAL: last revised 11/8/2004 0:00 0:00 6/19/2004 From To 0:00 0:00 6/20/2004 From To 0:00 0:00 Drill from 4818' - 6426', TPIG 1608, APIG 67 FPH. Inc: 28.64, Azi: 123.36.37' behind, 5' right. Try putting more WOB to hold angle, 24 still wanting to drop. Putting 30' - 40' slides in on each stand to get above line before vertical section. Hours Remarks Drill from 6426'-8413' TPIG 1,987' APIG 82.7' fph. Inc 18.63, Azi 128.49. Hole is drilling good with a few slides, not seeing much 24 connection gas and cutting looking same. (building mud for HV in active system while drilling) Hours Remarks 24 Drill & slide from8413 to 9361'.( Continue to build mud for Happy Valley #7 Approximately 380 barrels sent to HV as of Midnight. Incl. 19.21; Azim. 127.24 @ 8952 TVD/9279 MD TPIG = 948'; APIG = 39.5 6/21/2004 From To Hours Remarks 0:00 0:00 24 Drllslide to 10075'. Incl 13.08 Azim 121.6 TPIG 714 APIG 30 FPH 6/22/2004 From To Hours Remarks 0:00 22:30 22.5 Drl to 10765'. Bit would not drill any more. 22:30 23:30 1 Work to get bit to drill. . 23:30 0:00 0.5 CBU to POH. Incl 9.57 Azim 120.6 10,295 TVD TPIG 690 APIG 29 6/23/2004 From To Hours Remarks 0:00 1:00 1 Circ bottoms up ~._.,._"'- 1:00 8:00 7 POH to BHA 8:00 10:00 2 LD BHA (PJSM on removing sources and handling BHA) 10:00 10:30 0.5 Pick up tools; clean floor Red-01 morning report summary_AFE162461 page 10 CONFIDENTIAL: last revised 11/8/2004 10:30 11:30 1 11:30 12:00 0.5 12:00 19:00 7 ~-_..- 19:00 19:30 1 20:00 20:30 0.5 20:30 0:30 4 6/24/2004 From To Hours 0:00 3:00 3 ~,--- 3:00 5:00 2 5:00 9:30 4.5 9:30 10:00 0.5 10:00 0:00 14 6/25/2004 From 0:00 To 0:00 6/26/2004 From 0:00 To 0:00 6/27/2004 From To Hours 24 Drain BOP's; pull wear ring Rig up to test BOP's. Test BOP's for 4" and 3.5"; 250/4500; Hyd 250/3500 RD Test Equipment; Install wear ring Hang crown saver bell PU and orient BHA; test MWD, Gamma ray, Resistivity; Resistivity failed test, no consistency in signal, put out numbers sporadically. LD resistivity tool. PU tool from previous bit run which was putting out a good signal. Remarks Finish PU and testing MWD, GR & RES. Resistivity tested good. PU DP, RIH RIH wI DP. Fill pipe @ 2000' RIH Fill pipe, 98' off bottom @ 10666'. Circ @ safety ream to bottom; careful to start new bit track. Rotate drilling; keep close tabs on geology. Check for connection gas; not much trip gas or background gas Build staging area at Mile 9; move Safeguard tanks; black cuttings tank. Rack & strap Inr. Incl 11.26 Azim 119.69 TPIG 565' APIG 40 FPH . Remarks Drilling wlNB #4 11,898'. Angle slightly building, direction about the same; On targets. Inc112.64 Azim 116 TPIG 568' APIG 30 Sufficient Drll pipe on location to drill to 13,400'. . Hours Remarks -- 24 Dr~g_from 11898' to 12,190 at midnight. Penetration rate has fallen off due to change of formation. Inc112.6 Azim 116.9 TPIG 292 APIG 15 Hours Remarks Red-01 morning report summary_AFE162461 page 11 CONFIDENTIAL: last revised 11/8/2004 0:00 0:00 6/28/2004 From To 0:00 6:00 6:00 7:00 7:00 7:30 7:30 9:00 9:00 10:00 10:00 11:30 11:30 12:00 12:00 15:00 15:00 17:30 17:30 18:00 18:00 18:30 18:30 20:30 20:30 22:00 22:00 0:00 6/29/2004 From To 0:00 1:30 1:30 2:30 2:30 5:00 5:00 6:00 6:00 7:30 7:30 18:30 18:30 19:30 19:30 0:00 ---~---"--_. 6/30/2004 Hours 6 1 0.5 1.5 1 1.5 0.5 3 2.5 0.5 0.5 2 1.5 2 Hours 1.5 1 2.5 1 1.5 11 1 4.5 24 Drl from 12190' to 12,415'. Drlg to 12371'; make the connection. The well was slightly flowing. The drlrs have been checking for flow @ conn. Also have 1.0 ECD. Drl ahead watching bottoms up for conn gas; got 150 u from bottoms up. Weight up mud to 9.7 from 9.5. After weighting up to 9.7, check for flow; no flow. Resume drlg at 12,400' watching for conn gas; 80 u from bottoms up. Continue drlg watching parameters closely. Background gas = 30-45 units. Incl 12.25 Azi 118.6 TPIG 225 APIG 24.7 Total bit run. Remarks Drl to 12,458'. Circ bottoms up Check for flow CBU; ck for gas---112 units Ck flow; gain 4.1 bbl over 1 hour CBU, gas 154 units; mw cut .3 ppg Chk flow; 1 min intervals CBU; catch sample for mud test on bottoms up. Shut well in;SIDPP = 200 and SICP = 95. Circ hole; wt up 9.7 to 10.0 ppg. Monitor hole; ck flow; dead Ck slow pump rates; pump dry job. POH 6 stds.; Improper hole fill, RIH CBU; monitor gas(110 u}, catch sample, ck chlorides; looks like water cut Pump out of hole to 11,518'; 10 stds of a 20 std sh trip . Remarks Pump/out to Std #20 (old hole wI no problems)- Monitor well - Ok RIH to Std #118 - Prep to Mad Pass Mad Pass f/11 ,898' to 12,182' - RIH - Wash Std # 123 Circ Btm/up (w/30 units gas) Circulate & Condition mud - WUup to 10.2 PPG POOH - Pump Out to Shoe (with no problems 14.2 bbls over Displacement) Monitor Well (ok) & Held safety awareness meeting concerning "C" Plan spill drill wI all hands & chg ESD's Continue POOH - Pump Out . Red-01 morning report summary_AFE162461 page 12 CONFIDENTIAL: last revised 11/8/2004 From To Hours 0:00 2:00 2 2:00 3:30 1.5 3:30 5:00 1.5 5:00 13:30 8.5 13:30 15:00 1.5 15:00 19:00 4 19:00 20:30 1.5 ~"_._- 20:30 23:00 2.5 23:00 0:00 1 7/1/2004 From 0:00 5:00 7:30 13:00 15:00 16:30 17:30 22:00 22:30 7/2/2004 From 0:00 3:00 4:00 4:30 7:00 15:00 17:00 To Hours 5:00 5 7:30 2.5 13:00 5.5 15:00 2 16:30 1.5 17:30 1 22:00 4.5 22:30 0.5 0:00 1.5 To 3:00 4:00 4:30 7:00 15:00 17:00 18:00 Hours 3 1 0.5 2.5 8 2 1 Remarks POOH & Ly/dn BHA & clean to road worthy condition Monitor well on TT & clean A legs, rig floor PJSM - R/u SWS Wireline tools - PJSM Radioactive Materials RIH w/ PEX ~ CMR - AIT Logging Run #1 - SeUdn @ 6561' WLM - Work thru - RIH & Tag TD @ 12,473' WLM - Run Log & pull to Rig Floor PJSM - R/dn PEX-CMR-AIT Tools - P/u DSI Tools RIH to TD & Log DSI- POOH to Rig floor R/dn DSI Tools & P/u M-set Tools RIH wI M-set Tool & Obtain 3 Sidewall Cores - Tool Failed on 4th Sidewall Attempt x 2 to re-set M-set Solenoid & obtain Sidewall Core #4 - Tool failed . Remarks Made 3rd attempt to obtain Sidewall Core #4 - Tool failed - POOH to 5854' & re-attempt - Panel in unit smoking - Repaired - Obtained 7 Sidewall Cores - Tool working - RIH to 9425' & cut core - P/u to 9200' As/per Geologist & Cut Cores till total of 16 - Tool Failed again POOH & Chg/out Tool RIH wI New Tool fl Run #2 - Cut Sidewall Cores @ Geologist's direction - POOH - Recovered 25 Cores w/25 attempts. R/dn SWS Change/out Saver-Sub, Adjust Bklup Wrench, Replace Die Keepers Drain Stack, Pull Wear ring, Set Test plug & fill stack & lines Test BOPE 250/4500 Psi (Annular 250/3500 Psi) - Good Test - Witness waived by John Spaulding Pull Tst Plug, Drain Stack, Set Wear Ring & tighten set screws R/u & Ly/dn HWDP & Clean OBM from OD & ID - Attempted Brklout in Mouse Hole - T J's too Hi Remarks Ly/dn HWDP - Clean OBM frm/ OD & ID - Used Vacuum & wiper plug Pipe Rack 27/8" Stinger & Tubing & strap same Chg/out Elevators & prep to P/u 2 7/8" Tubing P/u & RIH w/2 7/8" Cmt Stinger Ass'bly (26 jts - mule shoe & perforations included on jt #1) RIH w/4" DP to 11,440' - Stagelin & Circ Btm/up @ 2330', 4590', 6490', 8380' - 96 units Gas @ 6490' Circulate & Condition mud for balanced cement plug R/u DS & hold PJSM . Red-01 morning report summary_AFE162461 page 13 CONFIDENTIAL: last revised 11/8/2004 18:00 19:00 19:00 20:00 20:00 21:30 21:30 0:00 7/3/2004 From To 0:00 1:30 1:30 3:00 3:00 7:30 7:30 10:30 10:30 12:00 12:00 12:30 12:30 20:30 20:30 21:30 21:30 22:00 22:00 0:00 7/4/2004 From ~- 0:00 4:00 To 4:00 8:00 Pump 1 Bbl H20 w/ DS to fill line, Press Tst Lines to 2000 Psi - OK - Pump 5 Bbls Mudpush 2 ahead w/ Rig Pump - DS Batch Mix Cement to slurry wt of 15,8 Ppg & displace surface line (1 bbl) w/ same - Pump 18.2 Bbls of Cmt Slurry - Displace w/1 Bbl mix H20 - 1 Pump 1 Bbl Mudpush displacement wI Rig Pump & 106 Bbls OBM - CIP = 18:50 hrs 1 POOH Slowly @ 20 fUmin to 10,940' Space/out & Circulate down DP to clear pipe & dispose of mud flushes - Got Mudpush bk@ +/- Btms/up - Pump Dart/wiper to clean 1.5 DP (pressure spiked on entry into stinger/tailpipe) 2.5 Pump 15 Bbl Dry-job, Ly/dn working single & POOH Hours 1.5 1.5 4.5 3 1.5 0.5 8 1 0.5 2 Hours 4 4 8:00 11:45 3.75 11:45 14:30 2.75 14:30 21:00 6.5 21:00 22:30 1.5 22:30 0:00 1.5 7/5/2004 Remarks POOH w/4" DP - Monitor Well @ Shoe - OK Continue POOH Standing/bk to Last 20 Stds DP Lay/dn & Clean 20 Stds 4" DP & 23 Jts 2 7/8" Tbg Stinger Clear & Clean Floor & Rlu to Run 3 1/2' Liner - Plu Cmt Head & Install Plug - PJSM P/u & run 3 1/2" Liner Test Float - Ok Plu & Run 3 12" Liner - Fill every Jt & Top/off every 5th Plu Bake Tools & Ly/dn Wotco Tongs Brklcirculation wI Baker tools, clean floor Run Liner to bottom wI 4" DP & fill every ~ 0 Stds . Remarks Run 3 1/2" Liner on 4" DP - M/u Cmt Hd/on pup - RIH to 10,930' Brklcirculation - RIH & attempt tag/up to 10,952' - Circ Btm/up - Rlu Cmt Head - Circ 1/2 Btm/up& hold PJSM f/ º-mt Job DS pump 3 bbls Chem/wsh to fill lines' - Press/tst lines to 4500 Psi - Pump 18 bbls Mudpush wI Rig Pump - DS Mix & Pump 209 bbls Litecrete w/ .75% D065, .25% BI55, .04% C359, .2 Gallsk D047, & 1.5 Gallsk D6006 to a Slurry Wt of 12 PPG - ShuUdn, Clear " s & Drop Dart - Pump Base Oil Displacement of 106.7 bbls (2.7 bbls over 104 bbls calc'd) - Plug bumped wI 3700 Psi - CIP 10:50 Reciprocated Pipe thu-out most of Cmt job - Bleed/off - Floats not holding - ShuUin & discuss wI Superintendent - Press/bk up to 3700 Psi - Bld/off to drip - rotate/off C-2 profile w/12 RH turns, Presslup to 1200 Psi - Plu - Press bled/to 900 Psi - SeUdn wI 35,000 Ibs - ZXP Pkr Sheared - Bumped/dn 3 more times to verify set. Circulate hole wI Base Oil- Got Mudpush/bk almost immediately, followed by Contaminated Cement & Base/oil- Dumped +1- 165 bbls of same - Ly/dn Cmt Head & xo's, Std/bk 1 Std 4" - Circulate hole wI Base/oil while reciprocating pipe. Chklf/flow - POOH & Iy/dn 4" DP Chk & I/dn baker running tools (ok & clean) & clear floor Rih bare foot Red-01 morning report summary_AFE162461 page 14 CONFIDENTIAL: last revised 11/8/2004 From To Hours 0:00 1:00 1 1:00 2:00 1 2:00 10:00 8 10:00 12:30 2.5 12:30 13:30 1 13:30 14:00 0.5 14:00 20:00 6 20:00 22:00 2 22:00 0:00 2 7/6/2004 Remarks Continue RIH Vo TI tie back Circulate Btm/up PJSM - POOH & Clean & ly/dn 4" DP - RIH w/13 STds DP - POOH & Clean & ly/dn Same Pull Wear Ring, Clean Rig Floor, ly/dn Hawk-Jaw Bundle Test well to 4000 Psi & Hold 30 Min - Good Test (on Epoch Chart) Finish Slip Drilling Line - 100' Onto Drum & Re-set COM R/u Wotco tongs & Run 3 1/2" completion - 2 hour wait to swap XO pups on Pollard Chem Inj Mandrel - Pickedlup Tbg & RIH w/ 12 Stds & POOH w/ same to install Chem Inj Mandrel & Pups - Installed new seal rings on connections PJSM & R/u Chem Line & Sheave in Der~ick - Test Line to 5000 Psi - Hold 900 Psi for completion RIH & P/u 3 1/2" Completion & run & band Chem Inj Line . Hours Remarks From To 0:00 4:30 4:30 7:00 4.5 Continue RIH & P/u 3 1/2" Completion & "tui1& band 1/4" S8 Co¡'trolline for Chem Inj Mandrel - Sting/in & Space/out - P/u Hanger 2.5 land Hanger w/2 6' Pups & 1 10-' Pup - Tst Control line 5000 Psi - OK - Press Test CsglAnn 1500 Psi - Ok - Good Test - Set BPV 7:00 16:30 9.5 16:30 20:30 4 20:30 0:00 3.5 7/9/2004 From To Hours 0:00 5:30 5.5 5:30 7:00 1.5 7:00 10:00 3 10:00 18:00 8 18:00 22:30 4.5 22:30 23:30 1 23:30 3:00 3.5 R/dn Tbg Tongs & tools, blowldn mud lines, clean floor & flush lines to pits - Remove pipe racks, clean beaver slide - Lldn Bales & Ru Pick/up lines - Attempt pull Mouse hole (cemented in) - Clean & Vac Cellar - Prep f/ welder - Work/on catch can & Bell Nipple- Pull Mouse hole, ly/dn Beaver Slide, Pull drip pan, Iy/dn pitcher nipple - Clean & Iy/dn flow line - Nippleldn Stack & clean same & load on Trailer -Set 2-way chk & Nip/up Adapter Flange wI Master Valve - test 2 Hanger S Seals 5000 Psi Each - OK - Nipple/up CIW Tree & test to 5000 Psi f/30 Min- OK - Pull2-way Chk & Install BPV Clean Pits & General Housekeeping - Release Nabors Rig #129 to Turnkey Move @ Mid/PM . Remarks None Activity Time. Attended Sim-Ops Meeting with Plant personnel Swanson River. Traveled to Red Pad. Welder working on cellar grading around well. Lined up Schlumberger El, Cameron, and Test pump. El moved in spotted equipment, Held JSA with personnel. Cameron rigged up and pulled 3" BPV. Picked up CBl and Temperature Tool RIH to 10,860' RKB tagged 3.92' above landing Collar (10,863.92). Correlated with Open hole log 6/3/04, logged from 10,860' RKB to 4,000' RKB (378' above Liner Top) Top of Cement 4,400', Bottom hole temperature 181-degrees. Rigged down Schlumberger Red-01 morning report summary~AFE162461 page 15 CONFIDENTIAL: last revised 11/8/2004 7/10/2004 From 0:00 3:00 To 3:00 6:00 Hours 3 3 6:00 20:00 14 7/11/2004 From To Hours 0:00 5:00 5 5:00 6:30 1.5 6:30 7:00 0.5 7:00 9:00 2 9:00 11:00 11:00 13:30 13:30 14:30 14:30 18:00 18:00 18:30 18:30 20:30 20:30 22:30 7/12/2004 From To 0:00 5:30 5:30 9:00 9:00 15:00 15:00 16:30 16:30 19:00 7/13/2004 Remarks EL finished CBL TOC 4,400' Rigged down. None Activity Time. Schlumberger traveled Swanson River picked up Nitrogen Truck and went to Red Pad #1. Traveled to Happy Valley picked up hard line and swivels (Chicksans). Moved in spotted CT equipment, worked on hydraulic leak. Picked up BOP, flanged up on Well Head, spotted choke manifold, layed out hard line. Informed Alaska O¡"I and Gas about project. Shutdown for the Night. Remarks None Activity time. Traveled to Star Pad turned in morning report. Arrived @ Red Pad, Held JSA with Schlumberger and Peak crew. Finished laying out hard lines made up same, Picked up Injector Head. . Stabbed Coil through Injector Head Installed turbine plug in 1-1/2" Coil tubing, filled and pumped plug through Coil Tubing with fresh 2 water. Pressure tested BOPE to Unocal Specification 250-Lo & 3,,500 High. Piped rams 250-10 & 3,OOO-psi High. Good Test. 2.5 Cooled down N2 pump unit, discharge line started leaking shutdown to fix. 1 Displaced water out of Coil Tubing w/N2. Picked up dual BPV's, jet nozzle RIH jetting with 400-scf N2 to 10,847' CTM (10,864' RKB) Increased N2 to 1,OOO-scfm Unloaded 85· 3.5 bbls. OBM into No.1 tank. Switched returns to No.2 tank Circulation pressure 1 ,900-psi Annulus 1,650-psi. 0.5 Finished unloading remaining mud totaled 95-bbls. Tubing volume. 2 Pulled out of hole, recovered all mud. 2 Rigged down Schlumberger BOP and hard lines. Secured well for the night. Remarks None Activity Time. Traveled to Star Pad turned in daily report. Went to Red Pad Held safety mtg. Finished breaking down hard line, backloaded Schlumberger equipment. Prepared location for PTS equipment, cleaned location. PTS Equipment arrived on location off loaded 3-truck loads of equipment. .~ Hours 5.5 3.5 6 1.5 2.5 PTS personnel arrived spotted equipment on Pad. Well safe started hooking up LEL & H2S equipment. Secured well with 3,125-psi. Red-01 morning report summary_AFE162461 page 16 CONFIDENTIAL: last revised 11/8/2004 From To Hours 0:00 6:00 6 6:00 11:00 5 11:00 16:00 5 16:00 20:00 4 20:00 22:00 2 7/14/2004 From To Hours 0:00 6:00 6 6:00 7:00 1 7:00 8:00 8:00 11:00 11:00 13:00 13:00 17:00 17:00 19:00 19:00 21:00 7/15/2004 From To 0:00 0:00 7/16/2004 From 0:00 To 0:00 Remarks No activity WBI backload last of Schlumberger equipment. WBlloader operator on site spotting PTS equipment. Production testing making up hard lines. Peak building berms. Called R&K for Vac Truck for tomorrow to haul hydro test water. Ordered Light Plant, Air Compressor, Blow Down Trailer, Triplex Test Pump and Methanol from Happy Valley to be hauled out to Red Pad. Released Peak crew after pit liner set, berms built and equipment spotted, Sent PTS home after getting flare stack in the air. Hard lines to flare and systems testing left to do tomorrow. Sent WBlloader operator and truck driver home at 22:00 hrs after getting all equipment unloaded and spotted. Had WBI back haul Unocal chicksand back to SRF for production. Sent WBlloader back and should be done with their services until testing is finished. . Remarks No activity:_SIMOP's at Star Pad Called Dean Bush for equipment operator. PTS showed up and finished hard line to flare scrubber. Called production and got Rick Musgrove headed to pad (when he arrived I went over all equipment including safety and outstanding action items & included attending SIMOP's.) Talked to PTS and Rick about reporting requirements coming and going. Gary Eller 1 called for Slickline work and ordered out crew. Peak operator moved loader over to Red from Star Pad. PTS worked on controls after hooking up generator and air compressor. 3 Pollard wireline on location. PJSM and rig up. 2 Musgrove spotting methanol pump, tanks, blow down trailer and test pump. Pollard made 2.50" GR run and tagged at 10850' RKB. 4 Pollard ran Gradient Pressure - Temperature Survey. R&K showed up with Vac truck with hydro test water. 2 Pollard pulled dummy gas lift valve and installed chemical injection valve (tested good in pocket). 2 PTS and Rick Musgrove hydro testing system. Pollard rigged down. . Hours Remarks Finish rigging up miscellaneous PTS well test equipment. Standing by waiting for Schlumberger. Maintaining 24-hour presence on 24 pad. Hours 24 Remarks Standing by waiting on Schlumberger to perforate. Maintaining 24-hour manned presence on pad. Red-01 morning report summary _AFE 162461 page 17 CONFIDENTIAL: last revised 11/8/2004 7/17/2004 From To Hours 0:00 7:00 7 7:00 11:00 4 11:00 13:00 2 13:00 15:00 2 15:00 16:30 1.5 16:30 17:45 1.25 17:45 18:30 0.75 18:30 19:00 0.5 19:00 23:00 4 23:00 0:00 1 7/19/2004 From To Hours 0:00 7:00 7 7:00 9:00 2 9:00 11:30 2.5 11:30 15:00 3.5 15:00 17:30 2.5 17:30 20:00 2.5 20:00 21:30 1.5 21:30 22:00 0.5 Remarks Standby waiting for Schlumberger. MIRU Schlumberger. Conduct prejob safety meeting. Bled tubing pressure down to 1900 psi through PTS flowback iron to achieve 2000 psi perforating underbalance. Pressure test Schlumberger lubricator to 3000 psi. MU 25' of 2.5" hollow carrier guns loaded 3 spf, 120-deg phase with 10.5 gm PJ2506 charges and SAFE firing head. RIH. located fluid level at 9860' (same as identified by slickline survey of 7/14). Tie in with CCl to short joint at 10,250' against SCMT log of 7/9/2004. Perforate the T-130 Sand 10,565' -10,590' with 2000 psi underbalance. SITP = 1979 psi prior to perforating. POOH. SITP = 1968 psi by the time Schlumberger was out of the hole. lD guns, all shots fired. MU 20' of same 2.5" hollow carrier guns. RIH, tie in with CCl to SCMT log of 7/9/2004. Fluid level appears unchanged from previous perforating run. Perforate the remaining T-130 Sand 10,590' - 10,610' with 2000 psi underbalance. SITP = 1977 psi prior to perforating. POOH. SITP = 1967 psi by the time Schlumberger was out of the hole. lD guns, all shots fired. RDMO Schlumberger. Elected not to blow well down yet due to lack of any signs of inflow. Waiting on wireline. MIRU slickline. Conduct prejob safety meeting and pressure test lubricator to 3000 psi. RIH with a 2.25" sample bailer. Tag fluid level at 9850' WlM. Continue RIH, tag fill at 10,862' WlM. POOH. Recovered mud plus some sand and perf debris. . MU tandem pressure gauges and depth encoder. RIH at 120 fpm to 10,850'. Get 5-minute stationary stop, then POOH at 120 fpm. Download gauges. RDMO slickline. Remarks Operations Secured _ Dry Watch Only RIH up Schlumberger E-Line. SITP = 1980 psi. Pre Job Safety Meeting - Pressure test lubricator - Make up HOWCO EZSV RIH with same - Tie into Schlumberger Slim Cement Map tool dated 07-09-04 - Set EZSV at 10,420 - Bleed Pressure to 1, 700psi while POH to check plug Trip for perf Gun - Pre-Job Safety Meeting - load 35' of 2.5",3spf 120deg phase 10.5gm PJ2506charges - RIH & tie in to SCMT-- perforate interval from 9,213 to 9,248 at14:47hrs with a calculated underbalance of 2,OOOpsi - Tubing pressure at gun fire = 1 ,52~ Trip out with Guns - Monitor Tubing Pressure - Slowly Building 15:55hrs = 1683psi - Shot Fluid level at 8,064'. load Gun #2, 35' - RIH & Tie in to SCMT log dated 07-09-04 - (Note tagged fluid level at 8,130' on way in hole) - Space out & Perforate 9,248' to 9,283' at 17:10 hrs - with 18: 18psi tubing pressure - Trip out with E-line (Note saw fluid level at 7,680' on way out - Monitor tubing pressure. E- Line out of hole - Shot Fluid level with 2,034psi tubing pressure at 6,950' - Rig down Schlumberger -Cap tree Open Well to Production with 2, 197psi shut in tubing pressure - Opened on 3/64 - Changed to 2/64 at 1 ,OOOpsi - Shut well in with 1 ,OOOpsi at 21 :16hrs - Nitrogen only to surface, No flare. Monitor Tubing Pressure & shoot Fluid levels with Unocal Echo meter (well analyzer Model "E", some interpretation required)- 4,394',4,361',4,305' Red-01 morning report summary _AFE 162461 page 18 CONFIDENTIAL: last revised 11/8/2004 22:00 23:00 1 23:00 0:00 1 7/20/2004 From To Hours 0:00 7:00 7 7:00 10:00 3 10:00 10:45 0.75 10:45 12:15 1.5 12:15 17:00 4.75 17:00 18:45 1.75 18:45 19:30 0.75 19:30 23:00 3.5 ------ 23:00 0:00 1 7/21/2004 From To Hours 0:00 9:00 9 9:00 9:30 0.5 9:30 13:00 3.5 13:00 17:00 4 17:00 0:00 7 7/22/2004 From 0:00 To 6:00 Hours 6 Opened well up on 11/64 - Blow down to 500psi nitrogen only, No flare - Shut well in at 22:30 with 500psi tubing pressure Monitor Tubing pressure and Shoot fluid Levels 22:30 t.p. = 500 FL= 3,325', 3,303' Remarks Continue to monitor tubing pressure and shoot fluid levels. Fluid level appears to be between 2800' - 5000' but difficult to interpret. SITP = 583 psi. MIRU slickline. Conduct prejob safety & operations meeting. Pressure test lubricator. RIH with 2.75" blind box. Tag fluid level at 1300'. Continue to RIH to 9632', do not tag bottom. POOH. MU 2" bailer and RIH to 4000'. Capture fluid sample and POOH. Fluid appears to be base oil. RIH with bailer again to 4000', capture a second sample of same fluid. Confirm that fluid samples have a specific gravity of approximately 0.88. RIH with bailer to 9250' (mid-point of perfs), work bailer to make sure it is purged. Collect fluid sample, POOH. Recover same type of fluid with same specific gravity. . MU tandem pressure bombs and RIH. Make stops at 0',2000',4000',6000',8000', and 9500'. POOH at a constant 60 fpm to surface. Download data and briefly analyze. Confirm water gradient of 0.435 psi/ft for several thousand feet. MU 2.25" bailer. Configure it without a spring to close the ball check, RIH. Tag fill at 10,425' MD. Pack sufficient fill to plug end of bailer, POOH. Recover quart of formation water and coarse formation sand. MU and RIH with same bailer once again to 10,425', PºOH. Recover another quart offormation water. RDMO slickline SITP = 448 psi. Bleed well to zero to see if any fluid will flow to surface. Do not get any liquid recovery. Shut in well, monitor tubing pressure. Remarks Monitor shut-in tubing pressure. Built to 40 psi overnight. RU test pump to 7" casing. Pressure up 7" casing to 2800 psi using methanol. RD test pump. Wait on Schlumberger nitrogen pump. . MIRU Schlumberger nitrogen unit. Conduct prejob safety meeting. Close wing valve to isolate PTS equipment. Pressure test . nitrogen lines to 6000 psi. Bullhead nitrogen down tubing at 1500 scfm to displace fluid into perfs. Pumped a total of 1677 gallon f nitrogen into the well bore. Final pump pressure = 3700 psi. RDMO nitrogen pumping unit. SITP = 3110 psi. Bled casing to 1480 psi. Leave well shut in over night allowing fluid to displace into perfs. Monitoring tubing and casing pressure. Remarks Well SI to allow fluid displacement by Nitrogen Red-01 morning report summary_AFE162461 page 19 CONFIDENTIAL: last revised 11/8/2004 6:00 8:30 2.5 8:30 9:00 0.5 9:00 11:00 2 11:00 12:00 1 ----- 12:00 12:30 0.5 RU SLB WL and Halliburton Tools. SITP = 2900 psig, SICP=1500 psig Shoot FL at 8800' Held Safety Meeting with all persons on Pad. Outlined procedure, objectives, and safety and environmental importance. PT lubricator to 4,000 psig using methanol. Held Fine. Bleed back methanol to tank and dump 5-10 gallons downhole RIH w/Halliburton 10K rated EZ~Drill CIBP. Did not detect a fluid level. Ran plug down to 9203' max (Did not enter the T-81 perfs from 9213-9283'). Set BP @ 9192' (top of plug) Tag Plug. All Depths correlated to SLB SCMT dated 9-Jul-2004. This log has been correlated to OH logs. ... Rig down Halliburton, Re-shoot fluid level at 8791' for reference. Bleed Nitrogen pressure from tubing from 2900 to 2150 psi to __~chieve a 25% underbalance for perforating. Reshoot fluid level for a negative test of CIBP - no change indicating plug had held. PU 36 foot x 2-1/8" 00 bailer on 0.23 wire set with 2960# maximum safe pull . . Red-01 morning report summary_AFE162461 page 20 CONFIDENTIAL: last revised 11/8/2004 e Unocal Alaska 909 W. 9th Avenue Anchorage, AK 99501 Tele: (907) 263-7889 Fax: (907) 263-7828 E-mail: oudeand@unocal.com e. ;<ot/~ 01'1 RECEIVED SEP 2 ;. 200/j UNOCAL Alaska Oil & Gas Cons, COmmiSSI() Anchorage Debra Oudean G & G Technician Date: September 15, 2004 To: AOGCC Helen Warman 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 rmq1m~~'t~'IIIII~"" Red 1 ·?i5 INCH 6ï~;2ÕÕ4Y6Õ-1-124S9 ··i 2I5INCH6/28/2004i 46~1-12459 SINCH 8/4/2004: 8700-9140 ,I . .1·······" r RED 1 MULTIPLE PROPAGATION RESISTIVITY NEUTRON, DENSITY GR MD IRED 1 MULTIPLE PROPAGATION RESISTIVITY NEUTRON, I DENSITY GR TVD ¡RED 1 PRODUCTION PROFILE SPIN,GRADIO,GR,CCL,PRES,TEMP IRED 1 COMPLETION RECORD HALLIBURTON EZ-DRILL I PLUG 2.S POWERJET HSD 3 SPF ¡RED 1 ¡COMPLETION RECORD 2.5 HSD POWERJETS [REÓ'1' cÜMsïNÄSLEMAë3'NETiCRESÒÑANCETOOL [RED 1 . .... OMBI~ABLEMAGNETICRESONANCE TOOL TV 1RED1]MECHANICAL SIDEWALLCORING TOOL"".. . .. SCALE ¡REÕ-1]DIP-Õ¡:E'SHÊAFïsÖt:JICfÒºrp&~ LO~E~...DIPqL("~'·2ISI~CH6/30/2004:1~2Õ~·1Eïr. iRED 1 DIPOLE SHEAR SONIC TOOL P&S LOWER DIPOLE 1?i5INCH 6/30/2004i,...fI4620-12474 I vol . I:::, JpJi:~!i~~i~i::::;~:~~:~::LE !:::~;I:;~t::::::~4 IREÖ1 ICOMPLETION RECÒÃî:i2.S-HSDPOWERJETS --'-'"íSINCH 7/17/2004 [lOS6S-1061 0 I 1 .11 ¡RE61:sLíi~1"cEME·ÑT-MA·FÎTÒÖL"'-'··'''-. .... .... ... .. ........... . ..........--'-·I SINC~ 7/9/20Ô4"[4ÕÕÕ=1'õá5êi""']']='~1r,,~"-n--1-"~=-~--]'-"'"".,~"'" JRED 1 ,~~~;~~,T6~~~~~~.~~~~Li~~~~~~~ ~ZS~~IDGE' tINCHiI7/2?i2oot0150-91~8 ..' ··,,1] ..1ifj' ... DATA COMBINED ON l' ONE CD 7/11/2004.·1101·S0-1.0S00 71-9079 DATA COMBINED ON ONE CD Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to (907) 263-7828. /~ //; - /1//' ReceiveiHJy. ){/~o ·VU~ Date: ~;:çt RHo AGL 16.68' .... . . "'" RT to top LDS '" 17.22' ... 16" for 9-S/8" , below grade 1"\ 3.0S" ?f , . "'" ^ 2.7S' .,...., n ... 1.S2" 'M' ^ 'III!' n ~y ^ _ _ _ __ _ _ _ _ __ _ _ _ _ _ _ _ __ _ _ _ ___ _ __ _ _~_:!...90' rl 1 2" threaded bull plug 7" X 9-S/S"outlet WI 3k 2" Ball valve 4.00 - - --- - - - -- - - - ----------------------- --- "III-- 16" X 9-518"outlet Cmted to surface 1+- 18" of cmt just over I base plate '11" thick base plate welded to 16" ( 1:: 11.80' l11.00· culvert insúded eClCled to acomadate mouse 110le 4.70' .... .. .... ~ 7' HI" 16" driven wI D·32 hammer tlSO' 9-5IS" Set@ 1790' 7" set @ 4615' 'I"f 3.4S" 1.65" 1.79' Ground Level Rig Mat'" 6" + " n " t! ~ ,.. . Debra Oudean G & G Technician To: AOGCC Helen Warman 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 . Unocal Alaska 909 W. 9th Avenue Anchorage, AK 99501 Tele: (907) 263-7889 Fax: (907) 263-7828 E-mail: oudeand@unocal.com UNOCAL Date: September 16, 2004 rmq¡m~~'~'111I!II Red 1 ¡RED 1 L DRILLING DYNAMICS LOG FINAL WELL REPORTS .... .IF?R~~!ION MUDLOG MD FORMATION MUDLOG TVD LAS DATA, RW EXPLORER FILES & FINAL REPORT _A_A_A~~.·.·.'~.'.'.'.·.m~"mwnn LWD COMBO LOG- CUSTOM VIEW I H 6/28/2004 1~'~c~1~/28/2??~lm f l' 6/28/2004 J~[~~O~[ 1 1 1 11, NOTEBOOK, 01 i '-t 0 '1... l... 1 o t.m~t~~i~L ....J......................ol.~........~f. of........ Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to (907) 263-7828. /Î/ '( /.;/ I Rece;ved BY.~. UJ,£,i / 7 ) J.//' M'-d '--! I Date: ,., " I I >,.J 'vi (,~GI..- -Dû' F: /¿ . . Unocal Alaska 909 W. 9th Avenue Anchorage, AK 99501 Tele: (907) 263-7889 Fax: (907) 263-7828 E-mail: oudeand@unocal.com UNOCAL Debra Oudean G & G Technician To: AOGCC Helen Warman 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 Red 1 Notebook containing: Omni Laboratories, Inc Rotary Core Analysis Report File: A-87003 Date: September 16, 2004 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to (907) 263-7828. /'Î/ I /i/l ¡1 Received BY/./kvv-cJ(. l) kl"vCJ I Date: / ì LjJ-~r'VJ '1 ) CJL/--Û g Y F:/-t · ~f)4 -- 0 ~4 If Winton, We TD'd the Red #1 exploration well earlier in the week at 12,458' MD. We are currently in the final stages of our wireline logging program. We will be running a 31/2" liner in the well as indicated in the well plan. Due to the absence of zones of interest in the bottom of the well and the desire for a good cement job in the Tyonek, we are planning on setting a 500' balanced plug from 10,940' to 11,440' MD. The 3 1/2" liner will be run with this new PBTD of 10,940' MD. Am I correct in assuming that AOGCC will not require a tag of the balanced plug? Once the liner is run, it will be tied back to surface with a seal assembly. Production testing of the well will commence once the drilling rig is released. Thanks, Rob Stinson Senior Drilling Engineer Unocal - Alaska Business Unit stinsonr@unocal.com (907)-263-7804 (office) (907)-263-7884 (fax) (907)-830-0563 (cell) . . FRANK H. MURKOWSKI, GOVERNOR AI,ASIiA OIL AND GAS CONSERVATION COMMISSION Phil Krueger Drilling Manager Union Oil of California (Unocal) P.O. box 196247 Anchorage, Alaska 99519 Re: Exploratory Red #1 Union Oil of California (Unocal) Permit No: 204-084 Surface Location: 338' FNL, 409' FWL, SEC. 8, T4S, R13W, S.M. Bottomhole Location: 1551' FNL, 2130' FWL, SEC. 8, T4S, R13W, S.M. 333 w. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Dear Mr. Krueger: Enclosed is the approved application for permit to drill the above referenced exploration well. This permit to drill does not exempt you rrom obtaining additional permits or approvals required by law rrom 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. A weekly status report is required rrom the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the Commission's internal use. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals rrom below the permarrost or rrom where samples are first caught and 10' sample intervals through target zones. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals rrom below the permarrost or rrom where samples are first caught and 10' sample intervals through target zones. 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 0 witness any required test. Contact the Commission's petroleum field inspector at 65 (pager). BY ORDER OF THE COMMISSION DA TED thi~day of May, 2004 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. · Unocal Corporation . P.O. Box 196247 Anchorage. AK 99501 Telephone (907) 263-7660 RECEIVED MAY 1 8 2004 Alaska Oil & Gas Cons. Commission Anchorage UNOCALe Phil Krueger Drilling Manager Tuesday, May 18, 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 #1 - Exploration Well Dear Commissioner Norman, Attached for your approval is an application for permit to drill (Form 10-401) for the Red #1 exploration well. This will be Unocal's first exploratory project in the Nikolaevsk Unit. ~ Excess mud and cuttings will be hauled to the NNA #1 well and disposed into the annulus of that well. A waiver will be requested for well bore surveys in the 12 %" hole section and for using a / diverter line smaller than the specified 16" minimum. The planned spud date is June 15\ 2004 and the contracted rig will be Nabors Rig #129. A spacing exception will not be required for this well, as per discussion between Kevin ,,/ Tabler and Bob Crandall. If you have any questions please contact myself at 263-7628 or Mr. Rob Stinson at 263-7804. Sincerely, Y~/6'J'-----_-/ Phil Krueger Drilling Manager OR\G\NAL ~GA- ~J1~ . STATE OF ALASKA. REC ALASKA OIL AND GAS CONSERVATION COMMISSIONMA'< 1 ß LÛ\J~ . . n PERMIT TO DRILL I¡ß\(a Oil & Gas Coos. Comro\SS\O 20 MC 25.005 þ" j\t\cMfage 1a. Type of work Drill: X Re-Entry: 2. Name of Operator Union Oil of California (Unocal) 3. Address P.O. Box 196247 Anchorage, AK 99519 4. Location of well at surface 338' FNL, 409' FWL, Sec. 8, T4S, R13W, S.M. At top of productive interval 816' FNL, 1113' FWL, Sec. 8, T4S, R13W, S.M. At total depth 1551' FNL, 2130' FWL, Sec. 8, T4S, R13W, S.M. 12. Distance to nearest 13. Distance to nearest well property line 5689 feet 16. To be completed for deviated wells Kickoff depth: 4700 feet 18. Casing program size Casing 16" 95/8" Redrill: Deepen: 1b. Type of well Service: Exploratory: X Developement Gas: 5. Datum Elevation (DF or KB) 894.5' KB to MSL feet 6. Property Designation ADL 390514 7. Unit or property Name Nikolaevsk Unit 8. Well number / Red #1 9. Approximate spud date 06/01/04 / 14. Number of acres in property Stratigraphic Test: Single Zone: 10. Field and Pool Wildcat in Beluga ../ & Tyonek Gas Sands & Hemlock / West Foreland Oil 11. Type Bond (see 20 AAC 25.025) Development Oil: Multiple Zone: X / Number U 62-9269 Amount $200,000 15. Proposed depth (MO and TVO) 1.5 miles 640 13,365' MD /13,000' rvD feet 17. Anticipated pressure (see 20 AAC 25.035 (e)(2)) Maximum suñace 3312 /' psig At total depth (TVO) 5629 psig Setting Depth Maximum hole angle: 25° Hole N/A 12 1/4" 8 1/2" 61/8" Weight 82.77 40 26 9.2 Specifications Grade Coupling A-252 (welded) L-80 BTC-mod L-80 BTC-mod L-80 IBTC-mod Top Bottom Quantity of cement Length MD rvD MD rvD (include stage data) 60-80' O' 0' 60-80' 60-80' N/A - driven to refusal 1800' 0' 0' 1800' 1800' 138 bbls (484 sx) 4600' 0' 0' 4600' 4600' 78 bbls (271 sx) 8,965' 4400' 4400' 13,365' 13,000' 288 bbls (875 sx)· ·Contingent upon log analysis. 7" 31/2" 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary 20. Attachments: Filing fee: X Property Plat: X BOP Sketch: X Drilling fluid program: X Time vs. depth plot: Refraction analysis: 21. I herby certify that the foregoing is true and correct to the best of my knowledge: Signed~\ .-/L'.:. (Ä'//~il Krueger Title: Drilling Manager Date: 5/18/04 / /' ( Commission Use Only Permit Number ~ / I API number I Approval dat~ ,I; / I See cover letter ;z ð $I - 0 ,. T 5ð - .2..3/- <. 00 <. / 6 d-V /&1 7: _ for other requirements Conditions of approval Samples required: )cfYes [] No Mud l0ltr:,qui ed: )a, Yes [] No ,...L. ~ Hydroge..nsulfidemeaSUre~Yes []No Directional survey required ,,"Yes []NO. Te-st BoPE tLl 4-5'"(JO '(JSC. Requiredworkin prÄi..tfo~~OPE []2M~ [13M; []5M; []10M; []lM(, ' t, Cl.f{?YTJI/e.J Other: Þ~1' 0 c '~-s~-~l~) ~t)eJvft~fitex.1itÞcw~'f~1::;¿tê~J:¿y£ ís ~p~~"eJi' (j___ Appro'. by .Ii A Comm.ission. er . ... Comm;,,;on Dat.. ¢ 11JJ ð, . 12-'1'-85'- 0 R , G..., I ~ I A L Submi n tripli te . , j I\! Diverter Sketch: Seabed report: N/A Drilling program: X 20 AAC 25.050 requirements: . . Table of Contents 1. 10-401 Permit to Drill 2. Waiver Requests 3. Outline Summary 4. Red #1 Schematic 5. Plat Map 6. Red #1 Directional Plan 7. MASP Cales 8. Casing Design Cales 9. 11" 5M BOP Stack Drawing 10. Shallow Hazard Discussion 11. Cement Program 12. Mud Program . . Waiver Requests Unocal respectfully requests waiver to; (1.) AOGCC regulations 20 MC 25.035 (c)(1) (A) and (8) WAIVER #1: Unocal requests permission to drill the 12-1/4" surface hole to a depth of +/- 1,800' MD / 1,800' TVD with a diverter, fitted with a 12" diverter outlet and line. ,/ AOGCC regulations 20 MC 25.035 (c)(1) (A) and (8) stipulate: (1) the diverter system must consist of a remotely operated pack-off device, a full opening vent line valve, and a diverter vent line with a diameter (A) (B) of at least 16 inches, unless a smaller diameter is approved by the commission to account for smaller hole size, geological conditions, rig layout, or surface facility constraint; and at least as large as the diameter of the hole to be drilled, unless a pilot hole with a diameter no larger than that of the vent line is drilled first; the commission will waive the requirement of this paragraph if the operator demonstrates, based on drilling experience in the near vicinity, that drilling a pilot hole will not be necessary for safety; Unocal has scrutinized the two closest offset wells and recent seismic in an attached shallow hazard analysis and believes that there is little risk of any / shallow gas down to well below the planned surface casing depth. These two offset wells are the NFU #11-4 and NFU #41-35. The first seismic amplitudes show up in the 3,000' TVD to 3,700' TVD depth range. Due to the local topography, there is a chance of slightly overpressured water aquifers. For the purpose of basic risk mitigation, Unocal will utilize a spud mud which is expected to weigh approximately 9.2 ppg when drilling at the planned surface / hole TD of 1,800' MD / 1,800' TVD', to eliminate the risk of a shallow water flow. WAIVER #2: Unocal requests permission to drill the 12 X" surface hole to +/-1,800' 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 X" surface hole vertically to 1,800', 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. . . Outline Summary 1. Move in and rig up Nabors Rig 129 on Red #1. 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" diverter wi 12" diverter line and test. AOGCC to be notified prior to test for possible witness. // 3. Mix KCL spud mud. 4. Drill 12 'W' surface hole vertically to 1,800' MD I 1,800' TVD. / 5. Run and cement 9 5/8" 40# L-80 BTC surface casing to 1,800' MD I 1,800' TVD. /" Pressure test 9 5/8" to 3,000 psi after bumping the plug. 6. Nipple down diverter. 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~ pc.:, . / 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 W' vertical hole wi KCL mud system to 4,600' MD 14,600' TVD. /' /~ 11. Log 8 W' wi quad combo, pull GR to surface. 12. Run and cement 7" 26# L-80 BTC intermediate casing to 4,600' MD I 4,600' // TVD. Pressure test 9 5/8" to 3,000 psi after bumping the plug. 13. Change bottom BOP rams to 4" and test. / 14. Change over mud to Oil Based Mud before drilling out shoe track. / 15. After drilling at least 20' of new hole, but no more than 50', perform Leak off Test as per Unocal standard LOT procedure. 16. Directionally drill 6 1/8" hole to 13,365' MD 113,000' TVD. // 17. Log 61/8" hole wi quad combo. 18. Run 3 W' 9.2# L-80 IBTC liner to 13,365' MD 113,000' TVD. Top of liner will be planned for 4,400' MD I 4,400' TVD. /___) 19. Pressure test liner, liner top packer and intermediate casing é~~Si. 20. Run 3 %" 9.2# L-80 IBTC tubing tie-back wi methanol injection mandrel at -2,500' MD I 2,500' TVD. / . . 21. Test 3 W' completion to 4,500 psi. 22. Test 7" x 3 ~" annulus to 1 ,500 psi. 23. Install BPV. Nipple down 11" BOP stack. 24. Nipple up 3 1/8" production tree and test. 25. Remove BPV and commence with production testing the well. / 16" 1 ,# 95/8" 40#L-80 BTCMod 12 :,{" Hole 7" 26# L~80 BTC Mod 8 }f," Hole 2 3 4 5 Jewelrv 1 - BOT Methanol Injection Nipple 2 - BOT X' Seal Ä$sembly 3 - BOTZXP Packer 4 - BOT Flexlock Hanger 5 - X' PBR wI 4.0" ID 3 %" 9.2# L-80 IBTC Mod 6 1/8" Hole 80' MD (80' TVD) 1800' MD(1800' TVD) Planned TOL@ 440q' MD (4400' TVD) 4600' MD (460Q'TVD) Formation Tops Beluga - Surface Tyonek - Hemlock - West Foreland- Cretaceous - 13,365' MD (13,000' TVD) -= 0 -800 0 "<t II E 0 0 Q) Iii 0 fJ) 800 1600 2400 3200 4000 - - CÞ .æ 4800 - .r::: - c. 5600 CÞ C CU 6400 CJ :e CÞ > 7200 CÞ ~ l- I- 8000 . V 8800 9600 10400 11200 12000 12800 13600 . e UNOCAL Location: Kenai Peninsula, Alaska Field: South Kenai Gas Field Installation: Red Slot: Slot Red#1 Well: Red#1 Wellbore: Red#1 Vers#1 Scale 1 cm = 100 ft East (feet) -> ,,/ -200 800 1600 1800 2000 2200 2400 1000 1200 1400 o 200 400 600 T-20 Tgt Rvsd 5-Apr-04 6.00 12.00 DLS: 2.00 deg/1 OOft 24.00 T-100 Tgt Rvsd 5-Apr-04 T-20 Tgt Rvsd 5-Apr-04 22.10 19.10 West Foreland Tgt Rvsd 5-Apr-04 __ T-100 Tgt Rvsd 5-Apr-04 15.49 12.47 DLS: 1.00 deg/100ft 6.45 3.43 j U .4... 0.4_2 -------+---- West Foreland Tgt Rvsd 5-Apr-04 TD Tgt Rvsd 5-Apr-04 -800 -0 800 1600 2400 3200 sca,eVertiG,1 Section (feet) -> Azimuth 125.80 with reference 0.00 N, 0.00 E from Slot Red#1 200 o -200 -400 -600 ^ . -800 Z o ;:¡. ::r - - -1000 ër CD - - - -1200 - -1400 - -1600 en £ CD - -1800..... o 3 II - -2000 <5 o ;::> Created by: Planner Date plotted: 6-Apr-2004 Plot reference is Red#1 Vers#1. Ref wellpath is Red#1 (PWP#1). Coordinates are in feet reference Slot Red#1. True Vertical Depths are reference Rig Datum. i Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 900.00 ft. Plot North is aiigned to TRUE North. 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 6845.11 213450.46 450.948 72 6935.05 213485.32 476.518 73 6950.00 213491.11 480.778 74 7025.24 213519.73 501.778 75 7116.17 213552.91 526.128 76 7207.81 213584.81 549.538 77 7300.13 213615.43 572.018 78 7393.11 213644.77 593.538 79 7486.72 213672.80 614.118 80 7580.92 213699.54 633]38 81 7637 213714.82 644.958 82 7675.66 213725.06 652.468 83 7770.49 213750.35 671.028 84 7865.32 213775.64 .588 85 7960.15 213800.93 708.148 86 8054.99 213826.22 726.708 87 8149.82 213851.51 745.268 88 8244.65 213876.80 763.838 89 8339.48 213902.09 782.398 90 8434.32 213927.38 800.958 91 8529.15 213952.67 819.518 92 8623.98 213977.97 838.078 93 8718.81 214003.26 856.638 94 8813.65 214028.55 875.198 95 8908.48 214053.84 893.758 96 9003.31 214079.13 912.318 97 9098.14 214104.42 930.888 98 9192.98 214129.71 949.448 99 9287.81 214155.00 .008 100 9382.84 214180.29 101 9477.47 214205.58 1005.128 102 9572.30 214230.87 1023.688 103 9667.14 214256.16 1042.248 104 9670.00 214256.93 1042.808 105 9765.11 214281.55 1060.888 106 9860.74 214304.85 1077.978 107 9956.87 214326. 1094.088 108 10053.47 214347.41 1109.218 109 10150.50 214366.66 1123.348 110 10247.95 214384.56 1136.478 111 10345.77 214401.09 1148.618 112 10443.95 214416.25 1159.738 113 10542.44 214430.04 1169.858 114 10641.22 214442.45 1178.968 115 10740. 214453.48 1187.068 116 10839.52 214463.13 1194.138 117 10938.98 214471.38 1200.198 118 11038.61 214478.24 1205.238 119 11138.3 214483.71 1209.248 120 11238.24 214487.79 1212.238 121 11338.18 214490.47 1214.208 122 11438.16 214491.75 1215.148 123 11480.00 214491.88 1215.238 124 11535.14 214491.88 1215.238 125 11550.00 214491.88 1215.238 126 11635.14 214491.88 1215.238 127 11735.14 214491.88 1215.238 128 11835.14 214491.88 1215.238 129 11935.14 214491.88 1215,238 130 12035.14 214491.88 1215.238 131 12135.14 214491.88 1215.238 132 12235.14 214491.88 1215.238 133 12335.1 214491.88 1215.238 134 12435.1 214491 1215.238 135 12535.1 214491. 1215.238 136 12635.14 214491.88 1215.238 137 12735.14 214491.88 1215.238 138 12835.14 214491.88 1215.238 139 12935.14 214491.88 1215.238 140 13000.00 214491.88 1215.238 . . Maximum Anticipated Surface Pressure Red #1 Kenai Peninsula, Alaska Assumptions: 1. Based on offset drilling & well test data, the pore pressure gradient is predicted to be a 0.433 psi/ft gradient from surface to planned total depth at 13,000' TVO RKB. Unocal has reviewed data from the two offset wells. These are NFU #41-35 (-5 miles SW) and NFU #11-4 (-1.5 miles NE). 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 M.Ä.S.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 13,000' TVO gas completion (Le. before reservoir pressure declines). M.A.S.P. Calculation During Production Phase: Max. pore pressure at T.O. = 13000 TVO x 0.433 = 5629 psi MAS.P. (tbg leak at surface) = 5629 psi - (0.096 psilft * 13000 ft) = = 4381 psi / M.A.S.P. Calculation During Drilling Phase: Est. Frac pressure at 7" shoe 4600 ft. x 0.8 psi/ft = = 3680 psi M.Ä.S.P. during drilling = 3680 psi - (.08 psi/ft x 4600 ft.) = = 3312 psi / Size 9-5/8" 7" 3-1/2" . Red #1 Casing Design Weight 40# 26# 9.2 # Grade L-80 L-80 L-80 Connection BTC mod. BTC mod. IBTC mod. 9-5/8" Surface Casin!;! Tension Burst Collapse Calculated 1800' x 40# = 72.0k (4600' TVD x (0.433 psi/ft - 0.1 psi/ft)) = 1532 psi (1800' TVD x (0.433 psi/ft - 0.1 psi/ft)) = 599 psi 7" Intermediate Casin!;! Tension Burst Collapse Calculated 4600' x 26# = 119.6k (13000' TVD x (0.433 psi/ft -0.1 psi/ft)) = 4329 psi (4600' TVD x (0.433 psi/ft- 0.1 psi/ft)) = 1532 psi 3 Yz" Production Liner Tension Burst Collapse Calculated 8965' x 9.2# = 82.5k (13000' TVD x (0.433 psi/ft -0.1 psi/ft)) = 4329 psi (13000' TVD x (0.433 psi/ft -0.1 psi/ft)) = 4329 psi Tensile 916,0001b 604,000 Ib 207,2001b Capacity 916k 5750 psi 3090 psi Capacity 604k 7240 psi 5410 psi Capacity 207.2k 10160 psi 10540 psi e Burst 5,750 psi 7,240 psi 10,160 psi Collapse 3,090 psi 5,410 psi 10,540 psi Safety Factor / 12.7 3.8 5.2 Safety Factor /" 5.1 1.7 3.5 Safety Factor 2.5 2.3 / 2.4 T' outlet I) 5/~" outlet c: :::J 133/8" outlet . . UNOCAL@) Alaska Resources Shallow Hazard Analysis in Support ofUnocal Red #1 Exploratory Well PotmtialShalow IIamrds We do not anticipate encountering shallow gas hazards during the drilling of the Unocal # 1 Red well. At wells in the vicinity, no non-coal gas shows have been logged nom surface in to shallow Sterling formation to a depth of 1800' +/- TVD, nor have any drilling problems been encountered historically. At the North Fork #11-4 well located two miles to the northeast, the first logged gas shows were nom Beluga coals at approximately 3800'. Primary gas reservoir objectives at the Red #1 well Upper and Middle Tyonek sandstones at depths between -4455' TVD SS and -10,780' TVD SS, and primary oil and / or gas objectives are nom Hemlock, West Forelands, and Cretaceous between -10,500' and -11,500'. The proposed total depth is minus 12,100' TVD SS /13,365' MD. Structure The Red structure consists of a pre-Middle Beluga and deeper moderate-sized four-way anticline based on 2D seismic, gravity, and magnetics data. From the surface to the Middle Beluga, at approximately 3800' MD, beds dip monoclinally to the east, culminating in a high- angle reverse fault approximately one mile to the east of the Red # 1 bottom hole location. The structure builds progressively with depth, and primary reservoir objectives include gas in the Upper and Middle Tyonek, and gas and/or oil in the Lower Tyonek, Hemlock, W estF orelands, and Uppermost Cretaceous sandstones. Stratigraphy and Reservoir Objectives Sterlinf! Formation The Red # 1 will spud in Lower Sterling formations consisting of interbedded sandstones, siltstones, mudstones, carbonaceous shale, and lignitic coals. The sandstone is mainly tan or bufIyellow, and fmes upward nom coarse to very fine grained. The most common bedforms consist of trough crossbeds and convoluted, planar crossbedded and ripple laminated beds. Siltstones and mudstones are dark to light gray and are ripple laminated, rooted or burrowed. Confidential Page 1 5/17/2004 O:IDR/LUNGIOnShoreISKGIRedIRegu/atory\051704_ Red1_ sha//owhazard.doc The carbonaceous shales and coals are dark fissile, or black, laminated, banded. The sandstones appear fluvial point bar deposits with fair to poor lateral extent. coals and carbonaceous shale beds reflect deposition in overbank-floodplain and mire environments. Overall, the Sterling is sand-rich, with no indications of sealing capacity for shallow gas hazards. Additionally, nowhere does the Sterling produce gas within the first 2000' of the surface. Lost circulation zones have been encountered coarser clastic facies of the Sterling, associated with interstitial porosity and fracturing, but without associated gas shows. Beluga Formation Where the Beluga Formation crops out to the south, just south of the Anchor River, it consists of interbedded siltstone, mudstone, carbonaceous shale, and sandstone. broken and papery coal beds occur in places. sandstones are drab gray or buff yellow and upward from medium to very fme grained. The sandstones are mainly trough crossbedded, with some planar bedding and ripple laminations. The first gas shows encountered the Lower Beluga at the North Fork #1 wen was at 3800' MD. Lost circulation zones have been encountered in certain fractured and porous of the Beluga in the Happy Valley Field area to the north, but none have been reported in the Beluga in either the North Fork #11-4 or the North Fork #41-35 wells. Cook Inlet Tertiary Stratigraphy Time Per. Epoch M.Y. Cook Inlet Fm. Quaternary Pliocene -10- eI) c eI) 0) 0 eI) -20- z -30- Olig. eI) -40- c eI) 0) 0 Eocene eI) "'ii -50- 0- -60- Paleo. Figure 1: Tertiary Stratigraphic column for the Cook Inlet Basin (after McGowen and Doherty, 1992) 061203_hv2_ shallowhazard,doc O:IDRILLlNGIOnShoreISKGIRedlRegulatoryI051704_Red1_shaffowhazard.doc Northwest-southeast depth intervals from 566...714 depths in the Beluga containingjirst North Fork #11-4 welllocCltedtwo miles seismic line shot March, 2004. 061203 _hv2_shallowhazard.doc O:IDRILUNGIOhShoreISKGIRecARegl.1latoryI051704_ Red1_shEJllowhazard. doc satellite image. 061203_ hv2_shallowhazard.doc . . Schlumberger * CemCAD E well cementing recommendation for 9-5/8" Surface Operator Country State Prepared for Proposal No. Date Prepared Prepared by Phone E-Mail Address : UNOCAL : USA : AK Well Field RED #1 RED : Rob Stinson : #1 : 04-17-2004 Location Service Point Business Phone FAX No. Ninilchik Kenai (907) 776-8155 (907) 776-8158 Chinedu F. Akwukwaegbu (907) 273-1739 CAkwukwaegbu@slb.com (jS\GN Q<i) ~~ ~iÙATE 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 UNDCAL RED#! 9-5/8 Kenai USA 9-5/8 in Surface (a) Section 1: well description Configuration Stage Rig Type Mud Line Total MD BHST Bit Size : Casing : Single : Land : 0.0 ft : 1800.0 ft : 62 degF : 12 1/4 in MD (ft) 100.0 Previous String OD Weight (in) (Ib/ft) 16 109.0 ID (in) 14.688 Landing Collar MD : 1760.0 ft Casinglliner Shoe MD : 1800.0 ft MD (ft) 1800.0 Casing/liner ID Grade (in) 8.835 L-80 OD (in) 9 5/8 Joint (ft) 40.0 Weight (Ib/ft) 40.0 Mean OH Diameter : 12.250 in Mean Annular Excess : 30.0 % Mean OH Equivalent Diameter: 12.934 in Total OH Volume : 276.3 bbl (including excess) The Well is considered VERTICAL MD (ft) 2000.0 Formation Data Pore Name (Ib/gal) 8.33 Frac. (lb/gal) 15.00 Geothermal Temperature Profile MD TVD Temperature Gradient (ft) (ft) (degF) (degF/100ft) 0.0 0.0 60 0.0 2000.0 2000.0 62 0.1 RED#I]relim.cfw; 04-18-2004; loadCa.. 9-5/8 in Surface (a); Version wcs-cem441_51 . Collapse (psi) 3090 Lithology Sandstone Sc~llßllørger Burst (psi) 5750 Thread BTC Page 2 Client Well String District Country Loadcase . . UNOCAL RED#I 9-5/8 Kenai USA 9-5/8 in Surface (a Sc~ln.pgep Section 2: fluid description Mud DESIGN Fluid No: 1 Density : 9.30 Ib/gal Rheo. 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 : 133.5 bbl Water Type : Fresh Fluid No: 3 Rheo. Model At temp. Fluid No: 4 Rheo. Model At temp. MUDPUSH " DESIGN : BINGHAM : 80 degF Density Pv Ty Gel Strength : 10.50 Ib/gal : 18.000 cP : 19.00 Ibf/100ft2 : (lbf/100ft2) Job volume : 40.0 bbl Lead Slurry DESIGN : 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 : 199.77 Iblft3 Sack Weight : 94 Ib BASE FLUID Type : Fresh water Code D079 S002 D046 SLURRY Mix Fluid Yield Porosity Job volume: 99.0 bbl Quantity : 282.15 sk Solid Fraction : 24.9 % : 11.064 gal/sk : 1.97 ft3/sk : 75.1 % Density Base Fluid : 11.064 gal/sk : 8.32 Ib/gal Additives Conc. 1.500 %BWOC 1.000 %BWOC 0.200 %BWOC Function EXTENDER Accelerator ANTIFOAM Thickening Time Compressive Strength Schedule ( ) Schedule () 03:05 hr:mn 29:40 hr:mn 100 Bc 500 psi at at Page 3 RED#l]relim.cfw: 04-18-2004: loadCase 9-5/8 in Surtace lal: Version wcs-œm441_51 . . Client Well String District Country Loadcase UNOCAL RED#I 9-5/8 Kenai USA 9-5/8 in Surface (a) Sc~llßlI8rg8r Tail Slurry DESIGN Fluid No: 5 Rheo. Model At temp. : BINGHAM : 80 degF Density Pv Ty Gel Strength : 15.80 Ib/gal : 25.749 cP : 24.73 Ibf/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 : 5.098 gal/sk : 1.17 ft3/sk :58.2% Job volume: 39.3 bbl Quantity : 188.54 sk ' Solid Fraction : 41.8 % 149 1 ~l ÇfI Density : 8.32 Ib/gal Base Fluid : 5.098 gal/sk Additives Code D065 S002 D046 Cone. 0.300 %BWOC 1.500 %BWOC 0.200 %BWOC Function DISPERSANT Accelerator ANTI FOAM Thickening Time Compressive Strength Schedule () Schedule ( ) 100 Bc 2573 psi at at 03:04 hr:mn 24:00 hr:mn Displacement Volume Total Volume TOC Section 3: fluid sequence Original fluid Mud pv: 12.000 cp 133.5 bbl 316.7 bbl O.Oft 9.30 Ib/gal Ty: 15.00 Ibf/100ft2 Fluid Sequence Name Volume Ann. Len Top Density Rheology (bbl) (ft) (ft) (Ib/gal) Fresh Water 5.0 0.0 8.32 viscosity:5.000 cP MUDPUSH II 40.0 0.0 10.50 pv:18.000 cp Ty:19.00 Ibf/100ft2 Lead Slurry 99.0 1300.0 0.0 12.80 pv:11.936 cp Ty:16.99Ibf/100ft2 Tail Slurry 39.3 500.0 1300.0 15.80 pv:25.749 cp TY:24.73Ibf/100ft2 Mud 133.5 0.0 9.30 pv:12.000 cp Ty:15.00 Ibf/100ft2 Static Security Checks: Frac Pore Collapse Burst Csg.Pump out 11 psi 23 psi 2629 psi 5750 psi 17 ton at 100.0 ft at 100.0 ft at 1760.0 ft at 0.0 ft Page 4 REO#l]relim.cfw; 04-18-2004; loadCa5O 9-5/8 in Surface (a); Version wcs-cem441_51 . . Client Well String District Country Loadcase UNOCAL RED #1 9-5/8 Kenai USA 9-5/8 in·Surface la) Sc~I..rger 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) 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 99.0 19.8 99.0 80 13-Start Mixing Lead Slurry Tail Slurry 5.0 39.3 7.9 39.3 80 16-Start Mixing Tail Slurry Pause 0.0 0.0 5.0 0.0 80 18-Drop Top Plug Mud 5.0 133.5 26.7 133.5 80 19-5tart Displacement Total 01:18 316.7 bbl hr:mn End Job: Record returns to surface and plug bumping. Dynamic Security Checks: Frac 10 psi Pore 3 psi Collapse 2629 psi Burst 5303 psi at 100.0 ft at 118.2 ft at 1760.0 ft at 0.0 ft BHCT Simulated BHCT CT at TOC 72 degF 76 degF 73 degF Temperature Results I Simulated Max HCT Max HCT Depth Max HCT Time 76 degF 1800.0 ft 01 :18:20 hr:mn:sc WELLHEAD PRESSURE o g -WellHead Pressure -Acquired WHP o 0- <X> o 0- .... o 0- <.c ~o ~ g- o.. IO s: ~- o 0- <') o o- N o 0- ~ ~ 0- I , o 10 20 30 4'0 5 '0 Tim e (m in) 60 70 80 90 Page 5 RE0#1_Prelim.cfw; 04-18-2004; LoadCase 9-5/8 in Surtace lal; Version wcs-cem441_51 Client Weil String o istri ct Country Loadcase UNDCAL RED#1 9-5/8 Kenai USA 9-5/8 in Surface (a) ECD '" ~ D e p th = 1 8 0 0 ft ~ amk ~ ::::::-", ~~ g ¡¡:> ;;;¡N "'~ '" ¡¡:> a. ¿ <:: <C o ~ '" o 30 40 50 Time (min) 60 70 80 90 FlOWRATE COMPARISON 0'> Fluids at 1800 ft ê -Ë :Bll) e. .$ ro 0::..;- ~ ü: <D "" '" o 10 40 50 Tim e (m in) 60 70 Page 6 REO#1_Prelim.çfw: 04-18-2004: loadCase 9-5/8 in Surface lal: Version wcs-cem441_51 . . Schlumberger * CemCAD E well cementing recommendation for 7" Intermediate Operator Country State Prepared for Proposal No. Date Prepared Prepa red by Phone E-Mail Address : UNOCAL : USA : AK RED #1 RED Well Field : Rob Stinson : #1 : 04-17-2004 Location Service Point Business Phone FAX No. Ninilchik Kenai (907) 776-8155 (907) 776-8158 Chinedu F. Akwukwaegbu (907) 273-1739 CAkwukwaegbu@slb.com fip>f>N r.. Q<¡) ~k ~~lJATE 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 concerning 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 tl1an 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 tl1e well or wells accordingly. Prices quoted are estimates only and are good for 30 days from tl1e 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 UNDCAL RED #1 7" Intermediate Kenai USA 7 Section 1: well description Configuration Stage Rig Type Mud line Total MD BHST Bit Size : Casing : Single : Land : O.Oft : 4600.0 ft : 99 degF : 8 1/2 in MD (ft) 1800.0 Previous String OD Weight (in) (lb/ft) 95/8 47.0 ID (in) 8.681 Landing Collar MD : 4560.0 ft Casinglliner Shoe MD : 4600.0 ft MD (ft) 4600.0 Weight (Ib/ft) 26.0 Casing/Liner ID Grade (in) 6.276 L-80 OD (in) Joint (ft) 40.0 7 Mean OH Diameter : 8.500 in Mean Annular Excess : 30.0 % Mean OH Equivalent Diameter: 8.901 in Total OH Volume : 215.5 bbl (including excess) The Well is considered VERTICAL MD (ft) 6500.0 Formation Data Pore Name (psilft) 0.433 Frac. (psi/ft) 0.725 MD (ft) Geothermal Temperature Profile TVD Temperature Gradient (ft) (degF) (degF/100ft) 0.0 60 0.0 4600.0 99 0.8 6500.0 125 1.0 0.0 4600.0 6500.0 RED#l_Prelim.cfw: 04-07-2004. loadCa," 7" Intermediate: Version wcs-cem441_51 . Collapse (psi) 5410 Lithology Sandstone Sc~llßllørger Burst (psi) 7240 Thread BTC Page 2 . Client Well String District Country Loadcase UNDCAL RED #1 7" Intermediate Kenai USA 7 Section 2: fluid description Fluid No: 1 Rheo. Model At temp. : BINGHAM : 80 degF Fluid No: 3 Rheo. Model At temp. : BINGHAM : 80 degF Fluid No: 4 Rheo. Model At temp. : BINGHAM : 80 degF DESIGN BLEND Name : G Dry Density : 199.77 Ib/ft3 Sack Weight : 94 Ib BASE FLUID Type : Fresh water Additives Code D046 D079 D167 S002 Cone. 0.200 %BWOC 2.000 %BWOC 0.800 %BWOC 0.750 %BWOC Thickening Time Compressive Strength Mud DESIGN Density Pv Ty Gel Strength Job volume MUDPUSH II DESIGN Density Pv Ty Gel Strength Job volume Lead Slurry DESIGN SLURRY Mix Fluid Yield Porosity : 11.067 gal/sk : 1.98 ft3/sk : 74.7% Density Pv Ty Gel Strength 100 Bc 1137 psi . Sil..rger : 9.50 Ib/gal : 15.000 cP : 18.00 Ibf/100ft2 : (lbf/100ft2) : 174.5 bbl : 10.50 Ib/gal : 22.000 cP : 22.00 Ibf/100ft2 : (lbf/100ft2) : 35.0 bbl : 12.80 Ib/gal : 31.504 cP : 33.84 Ibf/100ft2 : (Ibf/100ft2) Job volume: 52.9 bbl Quantity : 149.85 sk Solid Fraction : 25.3 % Base Fluid : 11.067 gal/sk at at 03:30 hr:mn 46:00 hr:mn Density : 8.32 Ib/gal REO#1_Prelim.cfw; 04-07-2004; loadCasa 7" Intermediate; Version wcs-cem441_51 Page 3 Function ANTI FOAM EXTENDER FLUID LOSS Accelerator Schedule 9.4-1 Schedule ( ) e . Client Well String District Country Loadcase UNDCAL RED #1 7" Intermediate Kenai USA 7 SàllDllrgør Tail Slurry DESIGN Fluid No: 5 Rheo. Model At temp. : BINGHAM : 80 degF Density Pv Ty Gel Strength : 15.80 Ib/gal : 72.013 cP : 10.82 Ibf/100ft2 : (lbf/100ft2) \)'0 I ( \ 0\ DESIGN BLEND Name : G Dry Density : 199.77Ib/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% Job volume: 25.0 bbl Quantity : 121.01 sk Solid Fraction : 41.4 % Density : 8.32 Ib/gal Base Fluid : 5.091 gal/sk Additives Code D167 D065 D046 Conc. 0.400 %BWOC 0.300 %BWOC 0.200 %BWOC Function FLUID LOSS DISPERSANT ANTI FOAM Thickening Time Compressive Strength Schedule 9.18-4 Schedule ( ) 100 Bc 2351 psi at at 04:38 hr:mn 18:30 hr:mn Displacement Volume Total Volume TOC Section 3: fluid sequence Original fluid Mud pv : 15.000 cp 174.5 bbl 297.3 bbl 2000.0 ft 9.50 Ib/gal Ty: 18.00 Ibf/100ft2 Fluid Sequence Name Volume Ann. Len Top Density Rheology (bbl) (ft) (ft) (Ib/gal) Fresh Water 5.0 177.1 591.0 8.32 viscosity:5.000 cp MUDPUSH II 35.0 1231.9 768.1 10.50 pv:22.000 cp TY:22.00 Ibf/100ft2 Lead Slurry 52.9 1800.0 2000.0 12.80 pv:31.504 cp T Y:33.84 Ibf/100ft2 Tail Slurry 25.0 800.0 3800.0 15.80 pv:72.013 cp Ty:10.82Ibf/100ft2 Mud 174.5 0.0 9.50 pv:15.000 cp Ty:18.00 Ibf/100ft2 Static Security Checks: Frac Pore Collapse Burst Csg.Pump out 374 psi 152 psi 4567 psi 7229 psi 39 ton at 1800.0 ft at 1800.0 ft at 4560.0 ft at 768.1 ft Page 4 RED#l_Prelim.cfw; 04-07-2004; LoadCa5O 7" Intermediate; Version wcs-cem441_51 Section 4: pumping schedule Start Job: Ensure that hole and mud are properly conditioned as per program Pumping Schedule Stage Time Cum.Vol (min) (bbl). . Client Well String District Country Loadcase UNOCAL RED #1 7" Intermediate Kenai USA 7 Name Flow Rate (bbl/min) Volume (bbl) Fresh Water 5.0 5.0 1.0 5.0 Pause 0.0 0.0 5.0 0.0 MUDPUSH II 5.0 35.0 7.0 35.0 Pause 0.0 0.0 5.0 0.0 Lead Slurry 5.0 52.9 10.6 52.9 Tail Slurry 5.0 25.0 5.0 25.0 Pause 0.0 0.0 5.0 0.0 Mud 5.0 165.0 33.0 165.0 Mud 1.0 9.5 9.5 174.5 Total 01:21 292.3 bbl hr:mn End Job: Record returns to surface and plug bumping. Dynamic Security Checks: Frac 147 psi Pore 97 psi Collapse 4552 psi Burst 6302 psi at 4600.0 ft at 1800.0 ft at 4560.0 ft at 0.0 ft BHCT Simulated BHCT CT at TOe WELLHEAD PRESSURE Temperature Results I Simulated Max HCT Max HCT Depth Max HCT Time 91 degF 84 degF 82 degF o 8 -WellHead Pressure _Acquired WHP o 0- 0> o 0- 00 o 0- .... 8- CD ïii .e,0 c.. ß- J: :¡:o 0- '<t o o C') 1 '0 30 4'0 5'0 Tim e (m in) 20 RE0I1_Prelim.cfw; 04-07-2004; LaadCa50 7" Intermediate; Version wcs-cem441_5t . Inj. Temp. (degF) 80 80 80 80 80 80 80 80 80 Sc~IRlrger Comments Fluid pack lines 3-Pressure Test Lines 7 -Start Pumping Spacer 4-Drop Bottom Plug 13-Start Mixing Lead Slurry 16-Start Mixing Tail Slurry 18-Drop Top Plug 19-5tart Displacement 21-Bump Top Plug 99 degF 4036.7 ft 01 :22:03 hr:mn:sc ( 60 70 8'0 90 Page 5 Client Weil String District Country Loadcase UNOCAL RED#1 7" Intermediate Kenai USA 7 Ece to Depth:= 4600 ft ro ~ -ON :;:::..~ Frac Pore Hyd ros tatic Dynamic 2: ;j !J> æ a... ¿ c: « oc.-L , I 8'0 0 10 20 30 40 50 60 70 90 Time (min) FlOWRATE COMPARISON '" F lu ids at 4600 ft co- I'- <D ~ '2 -Ë ]5LO a.. (!) ro ex: .... ~ ¡¡: N ~ 1 '0 5'0 I 0 20 30 40 60 70 80 90 Time (min) Page 6 REO#1_Preiim.cfw: 04-07-2004 : LoadCas87" Intermediate; Version wcs-cem441_51 . . Schlumberger * CemCAD E well cementing recommendation for 3.5" Production Operator Country State Prepared for Proposal No. Date Prepared Prepared by Phone E-Mail Address UNOCAL USA : AK Well Field RED #1 RED : Rob Stinson : #1 : 04-17-2004 Location Service Point Business Phone FAX No. Ninilchik Kenai (907) 776-8156 (907) 776-8158 Chinedu F. Akwukwaegbu (907) 273-1739 CAkwukwaegbu@slb.com ~\ßN '<)4í ~~ ~<:lIATE 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 concerning 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 wnich 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 . UNDCAL RED #1 3.5 Kenai USA 3.5inch Production Casing (a) Section 1: well description Configuration Stage Rig Type Mud Line Total MD BHST Bit Size MD (ft) 4600.0 MD (ft) 4400.0 : Liner : Single : Land : 0.0 ft : 13364.9 ft : 214 degF : 6 1/8 in Previous String OD Weight (in) (Ib/ft) 7 26.0 ID (in) 6.276 OD (in) Weight (Ib/ft) 14.0 Drill Pipe ID (in) 3.340 4 Liner Hanger : 4400.0 ft Landing Collar MD : 13284.9 ft Casinglliner Shoe MD : 13364.9 ft MD (ft) 13364.9 OD (in) 31/2 Joint (ft) 40.0 Casing/Liner ID Grade (in) 2.992 L-80 Weight (Iblft) 9.2 Mean OH Diameter : 6.125 in Mean Annular Excess : 30.0 % Mean OH Equivalent Diameter: 6.715 in Total OH Volume : 384.0 bbl (including excess) Max. Deviation Angle : 26 deg Max. DLS : 2.001 deg/100ft MD (ft) 10000.0 13365.0 MD (ft) 0.0 6500.0 13364.9 Frac. (psilft) 0.725 0.725 Formation Data Pore Name (psi/ft) 0.433 0.433 Geothermal Temperature Profile TVD Temperature Gradient (ft) (degF) (degF/100ft) 0.0 60 0.0 6395.4 124 1.0 13000.0 214 1.2 Grade . S-135 Collapse (psi) 10530 Lithology Sandstone Sandstone RED#1_Prelim.cfw: 04·18·2004: LoadCase 3.5inch Production Casing lal: Version wos·cem441_51 S~I..rger Collapse (psi) 13800 Burst (psi) 17800 Burst (psi) 10160 Thread BTCM Page 2 . Client Well String District Co u ntry Loadcase UNDCAL RED#1 3.5 Kenai USA 3.5inch Production Casing (a) Section 2: fluid description Fluid No: 2 Rheo. Model At temp. : NEWTONIAN : 80 degF Fluid No: 3 Rheo. Model At temp. : BINGHAM : 80 degF Fluid No: 4 Rheo. Model At temp. : NEWTONIAN : 80 degF Fluid No: 6 Rheo. Model At temp. : BINGHAM : 80 degF DESIGN BLEND Name : 12# LiteCRETE Dry Density : 112.13 Ib/ft3 Sack Weight: 151 Ib BASE FLUID Type : Fresh water Additives Code D047 D600G D065 D800 C359 Cone. 0.100 gal/sk blend 1.500 gal/sk blend 0.750 %BWOC 0.200 %BWOC 0.025 %BWOC Thickening Time Compressive Strength CW 101 DESIGN Density Viscosity Job volume MUDPUSH " DESIGN Density Pv Ty Job volume #4 Base Oil DESIGN Density Viscosity Job volume LiteCRETE DESIGN SLURRY Mix Fluid Yield Porosity : 8.268 gal/sk : 2.47 ft3/sk :44.8% Density Pv Ty Gel Strength 100 Bc (psi) . Sål..rger : 8.31Ib/gal : 5.000 cP : 20.0 bbl : 10.50 Ib/gal : 22.000 cP : 22.00 Ibf/100ft2 : 55.0 bbl : 7.40 Ib/gal : 3.000 cP : 124.9 bbl : 12.00 Ib/gal : 92.092 cP : 12.39Ibf/100ft2 : (lbf/100ft2) Job volume : 202.2 bbl Quantity : 460.38 sk Solid Fraction : 55.2 % Base Fluid : 6.668 gal/sk at at 03:51 hr:mn (hr:mn) Density : 8.32 Ib/gal RED#1_Prelim.cfw; 04-18-2004; loadCa5O 15inch Production Casing lal; Version wcs-cem441_51 Page 3 Function ANTIFOAM GASBLOK DISPERSANT RETARDER Viscosifier Schedule 9.20-2 Schedule () Client Well String District Country Loadcase Fluid No: 5 Rheo. Model At temp. . UNOCAL RED#1 3.5 Kenai USA 3.5inch Production Casing (a) : BINGHAM : 80 degF DESIGN BLEND Name : G Dry Density : 199.77lb/ft3 Sack Weight : 94 Ib BASE FLUID Type : Fresh water Code D800 D046 D167 D065 D094 Additives Cone. 0.200 %BWOC 0.200 %BWOC 0.400 %BWOC 0.300 %BWOC 1.5 # per bbls Thickening Time Compressive Strength . S~I..rglr Tail Slurry DESIGN Density Pv Ty Gel Strength : 15.80 Ib/gal : 75.605 cP : 22.90 Ibf/100ft2 : (lbf/100ft2) SLURRY Mix Fluid Yield Porosity : 5.032 gal/sk : 1 .16 ft3/sk : 57.9% Job volume: 85.7 bbl Quantity : 414.58 sk Solid Fraction : 42.1 % 4~D ø- ~V·~ Density : 8.32 Ib/gal Base Fluid : 5.032 gal/sk Function RETARDER ANTI FOAM FLUID LOSS DISPERSANT CemNET FIBERs Schedule 9.18-4 Schedule ( ) 100 Bc 2351 psi at at 03:50 hr:mn 18:30 hr:mn Section 3: fluid sequence Original fluid Mud pv: 15.000 cP 124.9 bbl 47.7 bbl 487.8 bbl 4300.0 ft Displacement Volume Drill Pipe Volume Total Volume TOC Name Volume (bbl) 20.0 55.0 202.2 85.7 124.9 CW 101 MUDPUSH II LiteCRETE Tail Slurry #4 Base Oil 9.50 Ib/gal Ty: 18.00 Ibf/100ft2 Ann. Len (ft) 880.3 2420.8 6400.0 2664.9 Fluid Sequence Top Density (ft) (Ib/gal) 998.9 8.31 1879.2 10.50 4300.0 12.00 10700.0 15.80 0.0 7.40 Tâ2.00 Ibf/100ft2 Ty:12.39Ibf/100ft2 Tâ2.90 Ibf/100ft2 Rheology viscosity:5.000 cp pv:22.000 cP pv:92.092 cP pv:75.605 cp viscosity:3.000 cp Static Security Checks: Frac Pore Collapse Burst Csg.Pump out 955 psi 389 psi 6700 psi 10160 psi 47 ton at 4600.0 ft at 4600.0 ft at 13284.9 ft at 13284.9 ft RED#l]relim.cfw; 04·18·2004, loadCase 3.5inch Production Casing lal; Version wcs·cem441_51 Page 4 Client Well String District Country Loadcase . . UNDCAL RED#l 3.5 Kenai USA 3.5inch Production Casing (a) Sc~IR.rg8r 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 MUD PUSH II 5.0 55.0 11.0 55.0 80 7 -Start Pumping Spacer LiteCRETE 5.0 202.2 40.4 202.2 80 13-Start Mixing Lead Slurry Tail Slurry 5.0 85.7 17.1 85.7 80 16-Start Mixing Tail Slurry Pause 0.0 0.0 5.0 0.0 80 36-Drop Dart #4 Base Oil 5.0 100.0 20.0 100.0 80 19-5tart Displacement #4 Base Oil 3.0 15.0 5.0 115.0 80 Slow down rate #4 Base Oil 1.0 9.9 9.9 124.9 80 37-Bump Dart Shut-In 0.0 0.0 20.0 0.0 80 38-Set Packer Total 01:57 487.8 bbl hr:mn End Job: Record returns to surface and plug bumping. Dynamic Security Checks: Frac 810 psi Pore 226 psi Collapse 6667 psi Burst 7365 psi BHCT Simulated BHCT CT at TOe WELLHEAD PRESSURE ... c.,j- ê ~- ~ ~ ~- .90 Q.. It) J: ~ 3: "!- o - o at 4600.0 ft at 4600.0 ft at 13284.9 ft at 4400.0 ft 168 degF 179 degF 124 degF Temperature Results I Simulated Max HCT Max HCT Depth Max HCT Time 181 degF 12819.4 ft 01:57:31 hr:mn:sc to M -WellHead Pressure M -Acquired WHP M- o M .... N m ó- to ó- 25 100 125 5 75 Tim e (m in) Page 5 RED#l_Prelim.cfw; 04·18·2004; LoadCase 3.5inch Production Casing (aJ ; Version wcs·cem441_51 Client Well String District Country Loadcase UNOCAL RED #1 3.5 Kenai USA 3.5inch Production Casing (a) ECD lO D e p th = 1 3 3 65ft ;:! Frac Pore Hydrostatic Dynamic. ;2- m .!2' ª- ~- i!:' :> u¡ u¡ i!:' a.-:: ¿ c: « ;:: m co o 25 50 75 100 125 Time (min) DIFFERENTIAL PRESSURE @ ZXP PACKER N .,.... Collapse Bur!>t Pseudo Hydrostatic 0'> - Dynamic ~ N .,.... , 25 50 75 100 125 Tìme (min) Page 6 REO#l ]relim.cfw ; 04-18-2004. loadCase 3.5inch Production Casing lal; Version wC&-cem441_51 Client Well String District Country Loadcase UNOCAL RED#l 3.5 Kenai USA 3.5inch Production Casing (a) Section 5: centralizer placement Centralizer Description Cent. Name Code Casing Max. Min. aD Rigid aD OD (in) (in) (in) NW-PO-3 1/2-4-POT W219 31/2 6.041 6.041 Yes 5 Top of centralization Bottom Cent. MD Casing Shoe NB of Cent. Used NB of Floating Cent. Bottom MD (ft) 13364.9 Nor. 56 :4400.0 ft :13344.9 ft : 13364.9 ft :56 :56 Cent. I Joint 1/4 Centralizer Placement Cent. Name Code Min. STO (%) @ Depth (ft) 11883.4 NW-PO-31/2-4-POT 5 W219 0.0 Origin Centralizer Tests Hole Size Running Restoring (in) Force Force (Ibf) (Ibf) NA NA NA Hannover (1) - Centralizer performance data is based on tests by WEATHERFORD as per the current API 10D specifications Running Force Calculations: Travelling Block Weight Friction Factor Centralizer/Formation Total Drag Force Hook load Down Stroke Hook load Up Stroke :120 ton ;(1.3 :1 ton :113 tOI1 :188 tOI1 ft 0- o o 0- o ~ o 0_ o I,(') Pipe Standoff Page 7 RED#l_Prelim.cfw: 04-18-2Q04: LoadCase 3.5inch Production Casing lal: Version wcs-cem441_51 Ciient Weil String District Co untry Loadcase UNOCAL RED#1 3.5 Kenai USA 3.5inch Production Casing (a) Section 6: WELLCLEAN II Simulator 1'1 % 0- 100 ¡ 0- 0 0- 0 0 0 0- IJ:") Cement Coverage Fluids Concentrations Risk Mud on the Wall ;: i ~ i: i '" ;¡¡:. ;¡¡¡. ~ -!>I)OO /Woo -7000 -1\1.000 ..... ,.... ;:;. Ec. "- -¡¡Ooo .<; ";, 1000Cl ~ "000. 12001} l:5ooô , .. ~ .. .. .. :go "" j ~ j ~ =: ¡¡ '" 2 !:t4 Base Oil T ail Slurry LiteCRETE MUDPUSH II CW 101 High Medium Low None RED#l_Prelím.cfw; 04·18·2004; LoadCase 3.5inch Production Casing lal; Version wcs-cem441_51 Page 8 . . I Halliburton BAROID UNOCAL Mud Program ! BAR 010 UNOCAL Red #1 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: 1.0 April 9, 2004 Red #1 v1.0 04/09//04 . . I Halliburton BAROID UNOCAL Mud Program Happv Vallev Producer I ntrod uction: 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 1,800' MD range. It will be drilled with a 12 W' 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 vertically to section TD at -4,600' MD. Seven inch casing will be run and cemented at this depth. The 7" will be drilled out with an INVERMUL system and a leak off performed. A 6 1/8" hole will be directionally drilled building to 26° by 5,896' then dropping to vertical by 11,845' MD (-11,480' TVD). The well will then TD at 13,364'. 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 wellbore 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 80/20 OWR (if available) used oil base fluid. The ratio will then slowly be raised to 90/10 by 10,000' 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 -9.6 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 in Tyonek sands · Minimize fluids related NPT . Minimize drilling wastes Critical Fluid Issues: · Eliminating/controlling losses. · Maintaining a low ECD in the production zone to reduce risk of lost returns. · Maintaining a stable well bore through coal seams. · Reducing drilling wastes with the inhibited drilling fluid system. Red #1 v1.0 2 04/09//04 . . I Halliburton BAROID Well Specifics: UNOCAL Mud Program Casing Program HV#3 12 ~" hole (9 5/8" casing) 8 W' hole ( 7 .. casing) 6 1/8" Hole (3 W'liner) MD TVD Footaae -1800' 1800' 1800' -4600' 4600' 2800' 13365' 13,000' 8765' Surface Hole Recommendations Mud Type: 6%KCI, EZ Mud Properties: 0-1500' 1500-1800 Densitv 8.6-8.9 8.6 -8.9 Viscosity 60 - 85 60 - 85 Plastic Viscosity 6 - 16 6 - 16 Yield Point 25 - 40 25 - 40 API FL N/C 8-10 e!:i 8.5-9.0 8.5-9.0 System Formulation: 6%KCI, EZ Mud Product Concentration Water 0.905 bbl KCI 20 ppb (30K chlorides) KOH 0.2 ppb (9 pH) Barazan D 1.25-1.5 ppb (as required 35 YP) EZ Mud DP 0.75 ppb Aldacide G 0.1 ppb Baracor 700 1 ppb Barascav D 0.5 ppb (add as the well spuds) Special Mixing Instructions: . Mix in order as listed . Add polymers slowly to minimize fisheyes. Concerns and Continaencies Surface Interval- ( 0 -1.800' MD ) Mud Tvpe: 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 of PAC will bemade to lower the filtrate to the 8-10 range at this depth. 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. Red #1 v1.0 3 04/091104 . . I Halliburton BAROID UNOCAL Mud Program I When penetrating high-clay content sections additions of BDF-263 ester are recommended to reduce the incidence of bit balling and shaker blinding. Reduce the filtrate to the 8-10 range with PAC L at 1,500'. 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 or carbide "flag" (20 bbl pill with 15 ppb of Wallnut M) 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--. 500 550 650 80 rpm 149 179 220 100 rpm 149 179 220 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 Properties: Densitv Viscosity Plastic Viscosity 1,800 - 4600' 8.9 - 9.2 40-53 6 - 15 Yield Point 13 - 20 APIFL <8 ID:!. 8.5-9.0 System Formulation: Product Water KCI KOH Barazan D Dextrid EZ Mud DP Aldacide G Baracor 700 Barascav D 6%KCI, EZ Mud Concentration 0.905 bbl 19.8 ppb (30K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 35 YP) 1-2 ppb 0.75 ppb 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) Special Mixing Instructions: . Mix in order as listed . Add polymers slowly to minimize fisheyes. Red #1 v1.0 4 04/09/104 [ Halliburton BAROID Concerns and ContinQencies . . UNOCAL Mud Program Intermediate Interval- ( 1800 - 4600' MD ) Mud Type: 6 % KCI/PHPA 1. Mud weight: 2. Rheology: 3. Filtrate control: Maintain the 8.9 - 9.2 ppg 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 SDF-263 may be required to control screen blinding/SHA balling. Losses in this interval can be controlled with additions of 1-2 ppb SAROFISRE and 1-2 ppb of Saracarb 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-Vís should be used to maintain rheological parameters. Maintain the mud as clean as possible while drilling. Should sweeps be required a BAROLlFT sweep is recommended (check with the G&I plant to ensure compatability). This sweep will help clean the hole with no neQative impacts on svstem mud weiQht or rheoloQV. Daily additions of X-Cide 207 should be made to control bacterial action. Sweep Formulation: 25 bbl of mud with .25 ppb of Barolift added. Shear thou roughly prior to pumping. 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 - 9.0 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~ 400 550 600 80 rpm 221 284 338 100 rpm 221 284 338 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. Red #1 v1.0 5 041091104 . . I Halliburton BAROID UNOCAL Mud Program 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 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 I 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 System Formulation Product Base Oil EZ MUL NT INVERMUL GEL TONE V Lime DU RATON E RM63 Water CaCI2 AK-70 BAROID Concentration 0.696 bbl 4 ppb 4 ppb 4 ppb 5 ppb 4 ppb 0.5 ppb 0.178 bbl 24.6 ppb 4 ppb to a 9.2 ppg Mud Type: Invermul System Mud Properties Density Viscosity PV YP ES HTHP FL WPS OIW 4600 -10,000 9.2-9.3* 55-80 18 - 29 9-18 1000- <8 290 to 320K 80/20 1100 10,000- TD 9.6-10.0 * 55-80 18 -30 9 -18 1000- <5 290 to 320K 90/10 1100 . Additional mud weight may be required for effective coal or shale stabilization or gas shows. System Formulation Product Base Oil EZ MUL NT INVERMUL GEL TONE V Lime DURATONE RM63 Water CaCI2 AK-70 BAROID Concentration 0.696 bbl 4 ppb 4 ppb 4 ppb 5 ppb 4 ppb 1 ppb 0.178 bbl 24.6 ppb 4 ppb to a 9.2 ppg Red #1 v1.0 6 04/09//04 . . I Halliburton BAROID Concerns and Contin~encies UNOCAL Mud Program Production Interval (6 1/8" hole, 3.5" casin~ ): Mud Type: 1. Mud weight: 2. Rheology: 3. Other issues: 4600' MD - TD 9.2 ppg INVERMUL System. Maintain the density at 9.2 ppg or as directed to 10,000 then increase it to 9.6 ppg with barite; use solids control and whole mud dilution. Increase density as required for well control, hole stability or coal sloughing. Maximize solids control usage. Maintain a YP between 9 and 18. Pump high viscosity or Barolift 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 ~ 80 RPM). 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. By 10,000 feet reduce the HTHP to < 5 cc 30 min with DURATONE HT/AK-70 treatments. Please see the Coal Drilling recommendations attachment. 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 well bore. 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 a 25 bbl spacer ahead of the oil mud as follows: Spacer Formulation: · 20 barrels of the OBM treated with GEL TONE to a YP > 30 (app. 4-6 sx). Weight this pill to 2 ppg over the OBM weight. · Follow with 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. Red #1 v1.0 7 04/09//04 . . I Halliburton BAROID Maintenance: UNOCAL Mud Program 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 DURA TONE HT / AK-70 filtration mechanism « 8 cc/30 min @ 1500 F to 10,000' then <5cc/30 min @ 2000 to TD). Sarablok and Sarotrol will also be available to improve the filtration control mechanism. 4. For formation bridging/LCM, graded calcium carbonate (Saracarb(s)), cellulose fiber material (Sarofibre) 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 up at 10,000' 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 well bore 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 O/w 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 90:10 range by 10,000'. This will help reduce the cost of the original fluid and then help control rheology/ECD's with the 90: 1 0 ratio in the lower depths of the well. 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 40 rpm 102 128 158 60 rpm 152 186 221 80 rpm 180 220 262 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 Red #1 v1.0 8 04/09/104 . . I Halliburton BAROID Sweeps Two types of hole cleaning sweeps can be used: · 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. UNOCAL Mud Program 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- 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 base diesel oil- ensure availability. Red #1 v1.0 9 04/09//04 I Halliburton BAROID UNOCAL Mud Program Production Hole· Hazards I 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. No sweeps have been needed in this hole section to date on the Happy Valley wells. · 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: 12 y.." Surface 19,000 8 Y2" Intennediate 14,000 6 118" Production (OBM) 46,000 Total $79,000 **The P-50 estimate assumes 800 bbls of reconditioned oil mud to be used. 31,000 19,000 68,000** $118,000 ... P90 38,000 50,000 165,000 $253,000 Red #1 v1.0 04/09/104 10 . . I Halliburton BAROID UNOCAL Mud Program Losses UNOCAL Lost Circulation Decision Tree f/lnhibited Mud Systems + + + + Seepage Partial Severe Total 15-60 bbllhr 5-10 bbl/hr Static Static 60-200 bbllhr Static > 200 bbllhr Static + + . . ~ I Treat Active System I I Treat Active System I I 60-150 bbVhr Static I 1150-200 bbl/hr Static I Drill Across Fault with 5 sxlhr Barofibre with 10 sxlhr Barofibre t t t I Drill Across Fault I I Drill Across Fault I Pump Gunk Squeeze + pill to allow POH 100 ppb LCMlMud Pill: (Volume to be Yes Yes 20 ppb Baroseal F . determined based ~ + 20 ppb Baroseal M upon losses 30 ppb Barofibre I Contact Drilling Engineer I + I Drill Ahead I I Drill Ahead I 20 ppb Wallnut M or Engineer on call No 10 ppb Wallnut F Contact Drilling I M","" Jt.¡,~ ì No + Engineer or Engineer , on call 5 sxlhr Barofibre 70 ppb LCM/Mud Pill: I Contact Drilling Engineer or I y + 5 ixlhr B,acarb 50 Engineer "On Call" 20 ppb Baroseal F Pump Gunk I POH, PU dumb iron I 20 ppb Baroseal M Squeeze pill BHA 20 ppb Barofibre (Volume to be ~ 10 ppb Wallnut M determined based Yes upon losses) ~ Consider cement I I Drill Ahead I No plug back contingency , 40 ppb LCMlMud Pill: Yes . 10 ppb Baroseal F t Pump Gunk 10 ppb Baroseal M I Drill Ahead I Squeeze pill 1 0 ppb Barofibre No 10 ppb Wallnut M , Contact Drilling ( '\ Engineer or Engineer Notes: on call to determine if additional LCM 1) Drill across fault or loss zone 1.5·2.0 times the length of the Yes throw before spotting Gunk Squeeze. + treatments are to be 2) PBL sub should be run in BHA to spot ~lIs if 'Partial Loss' cases or made or to proceed to above are anticipated prior to drilling to allow the spotting of LCM I Drill Ahead I Gunk Squeeze pill pills. 3) lCM pill volume = 300'-600' column based upon actual hole No diameter. , 4)PRIOR TO ANY lCM Pill, APPROPRIATE DISCUSSIONS AT Proceed to 'Partial THE RIG MUST BE MADE TO MINIMIZE THE POTENTIAL FOR Losses' Pill PLUGGING THE DRill STRING. \ ./ Red #1 v1.0 04/09/104 II I Halliburton BAROID Losses + Seepage 5·20 bbllhr Static , Treat Active System with 5 sxlhr Baracarb 50/150 Yes ¡ I Drill Ahead I No , Increase Treatment to 10 sxlhr Baracarb 50/ 150 , No , Yes + I Drill Ahead 20 ppb LCM/Mud Pill: 20 bbls base mud 1 0 ppb Baracarb 50 10 ppb Baracarb 150 Yes + I Drill Ahead I No , Proceed to 'Partial Losses' Pill Red #1 v1.0 04/091104 . UNOCAL . Mud Program UNOCAL Lost Circulation Decision Tree fl Payzone Mud Systems + Partial 20-60 bbllhr Static , Treat Active System with 10 sxlhr Baracarb 150 Yes + I Drill Ahead I No , 50 ppb LCM/Mud Pill: 20 bbls Base mud 10 ppb Baracarb 25 20 ppb Baracarb 50 20 ppb Baracarb 150 Yes t I Drill Ahead I No , Contact the Engineer on call to determine if additional LCM treatments are to be made or to proceed to reverse gunk squeeze pill Severe 60-200 bbllhr Static t I 60-150 bbllhr Static I t I Drill Across Fault I 1 + 100 ppb LCMlMud Pill: 20 ppb Baroseal f 20 ppb Baracarb 50 30 ppb Barofibre 20 ppb SteelSeal 10 ppb Baracarb 150 + I Contact Drilling Engineer or I Engineer "On Call" . Pump reverse gunk squeeze pill (Volume to be determined based upon losses + t 1150-200 bbl/hr Static I t Drill Across Fault + Pump reverse gunk squeeze pill to allow POH (Volume to be determined based upon losses) ¡ I Contact Drilling Engineer I or Engineer on call ( + Total > 200 bbllhr Static + Drill Across Fault t Pump reverse gunk squeeze pill to allow POH (Volume to be determined based upon losses , Contact Drilling Engineer or Engineer on call l . 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 faun 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 if '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. \. .J ]2 I Halliburton BAROID Drillina Fluids Proaram Synopsis . . UNOCAL Mud Program General Discussion A KCI drilling fluid will be used to drill the surface and intermediate hole sections of these wells. This fluid offers hole stability, waste reduction and many options to address/prevent lost circulation. This fluid will yield a more gauge hole which reduces the waste (both while drilling and for cement jobs). This gauge hole, however, can also lead to challenges with swabbing on trips. The production hole will be drilled with an INVERMUL system. This oil based fluid will offer added hole stability and lubricity for this section with the added benefit of lowering waste stream costs. Please refer to the mud program for details. Suaaested Fluids Properties Surface Hole (12.25" hole to 9 5/8" casing point at 1,800') Mud Type: 6%KCI, EZ Mud Properties: Density Viscosity Plastic Viscosity Yield Point API FL .e.!:!. 0-1500' 8.6 - 8.9 60 - 85 6 - 16 25 - 40 N/C 8.5-9.0 1500-1800 8.6-8.9 60-85 6-16 25-40 8-10 8.5-9.0 Comments: This interval will be drilled with a 6% KCI, EZ Mud fluid. Primary focus for this intervel will be adequate hole cleaning for the large diameter (12 'X") hole and maintaining the drill solids I mud weight. Intermediate Hole (8 %" hole to 7" casing point at 4,600' ) Properties: Density Viscosity Plastic Viscosity Yield Point API FL 1,800-4600' 8.9-9.2 40-53 6-15 13-20 <8 Comments: The mud system from spud will be conditioned and used to drill this section. primary importance. An LCM decision tree is attached should losses develop. .e.!:!. 8.5-9.0 Maintaining low ECD's is of Production Hole (6 1/8" hole to 3 %" casing point at 13,365' ) Properties Density Viscosity PV YP ES HTHP FL WPS O/W 4600 - 10,000 9.2-9.3* 55-80 18 - 29 9-18 1000- <8 290 to 320K 80/20 9.6Æ~} 1100 10,000- TD 55-80 18 -30 9 -18 1 000- <5 290 to 320K 90/10 1100 . Additional mud weight may be required for effective coal or shale stabilization or gas shows. Comments: The well will be displaced to an INVERMUL system prior to drilling out the 7" casing if rig ops didn't allow bumping the plug with OBM. This will be used mud from previous wells. Maintaining a clean, low solids content and raising the OWR to 90/10 prior to 10,000 feet will keep the rheological profile low and reduce chances of lost circulation, excessive pump pressures, and lay down a thinner more durable wallcake. Maintain the mud weight as programmed but be prepared to weight up if hole conditions warrant. Reduce the 2000 HTHP fluid loss to <5 by 10,000' and maintain to TD. Red #1 v1.0 04/09//04 13 Alaslrn Depmimenl of Natnrnl Resources RidS Office Imaging... htlP.IIWWW.dn,.Stale¡sIIaslCase_Abstrn,t,fin?File T ype~ADL&F... " Lalld Administl"lltioll System Menu I Credit Card Payment Land Administration System .Case Abstract Information File Type: File Number: ( 389227 See Township, Range, Section and Acreage? Œ Yes 0 No Case Summary I Case Detail ¡Land Abstract 10f7 5/19/2004 1 :08 PM Alaska Department of Natural Resources Recorder's Office Imaging... http://WWW.dnr.state.s/las/case_Abstract.Cfm?FileTYPe=ADL&F... . 2 00 5/19/2004 1 :08 PM Abska Department ofNaturnl ResoutCes R¡"'S Office Imaging... hrtP.¡/WWW.dm.SIa..s/laslCa.._AbStract.CIin ?FileT ypor AD L&F ... 3 of? 5/19/2004 1 :08 PM Alaska Department of Natural Resources Recorder's Office Imaging... . http://www.dnr.state.ak.us/las/CaseAbstract.cfin ?FileTypeo= AD L&F... . - 40f7 '" 5/19/2004 I :08 PM Alaska Department of Natural Resources Recorder's Office Imaging... . http://www.dnr.state.ak.us/las/Case Abstract.cfm ?File Type= AD L&F... . - 50f7 5/19/20041:08 PM Alaska Department of Natural Resources Recorder's Office Imaging... htlP:llwww.dnr.state..ak.US/las/case_Abstract.Cfin?FileTYPe=ADL&F. ,.,' . End of Case Abstract 60f7 5/19/2004 1 :08 PM Alaska Department of Natural Resources Recorder's Office Imaging... http://WWW.dnr.state..ak.us/las/case_Abstract.Cfm?FileTYPe=ADL&F... .... . Land AdminÎstration System Menu I Land Records/Status Plats I Dept. of Natural Resources Home Page I State of Alaska HomeP~lge I Corn.'rillht Privacy ·· Uisc!aimer Last updated on 05/19/2004. Report technical problems with this page to the Webmaster. This site works best with 4.x or newer version of Internet Explorer andNetscape. This. site also requires that all COOKIES must be accepted. 70f7 5/19/2004 I :08 PM CITIBANK DELAWARE A Subsidiary of Citicorp ONE PENN'S WAY NEW CASTLE, DE 19720 62-20 31T UNOCAL Union Oil Company of California Accounts Payable Field Disbursing 2007792 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 ANCORAGE, AK 99501 United States III 20077'1 2111 1:0:\ ~ ~OO 20 '11: :t:a :Q) c.t JoI;- Q1 E :r::.¡:(Q ;::J r":t :::I- e:. ""' ~ = m (' s: -J 3 ë:;' C'I ¿:ï :::s ~;o ~rn () tT1 - ,- '71 r::J ."-. :;(? .r-...; <::) <::) ..þ., Date Check Amount 18-MAY-04 ********100.00 Void after six rnonths from above date. . --- --Y_ i<-- D.A. PAGE MAY 1 d 2004 :\ '1 ~ ~ a ~ :\ ? III . e e (ill r~ , I LL FRANK H. MURKOWSKI, GOVERNOR AI1ASIiA OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 April 28, 2004 ~.().~~'+ Mr. Wade Gilpin Alaska Department of Environment Conservation Division of Spill Prevention and Response 555 Cordova Street Anchorage, AK 99501-2617 Re: Red Well, Maximum Open-hole Blowout Potential Rate Dear Mr. Gilpin: You requested on March 31, 2004 that the Alaska Oil and gas Conservation Commission ("AOGCC") provide an estimate of open hole potential of the planned Red Well, Nikalaevsk Unit, for purposes of detennining required spì11 response needs. I have met with Rob Stinson and Jack MacArthur of Unocal to review the infonnation provided within the original Response Planning Standard. They had originally estimated 2000 BOPD. We concluded that while this is reasonable for the Hemlock zone, it does not account for the potential of gas production from upper zones augmenting oil production rate from the Hemlock in an open hole scenario. The worst case estimated blowout rate is 4,900 barrels of oil per day (BOPD). Gas rate for this scenario, is 4.7 million standard cubic feet (MMSCF), assuming a fonnation GOR of 350 SCF/STB and gas contribution from upper zones of 3 MMSCFD. This assumes a maximum productivity index of 1.0 BOPD/psi based upon historical Hemlock production from the most productive wells within the Swanson River Field and Middle Ground Shoal. Reservoir quality likely deteriorates to the south of these fields, and therefore, the productivity of the Hemlock in this well is likely lower than the analogues evaluated. Based upon my conversations with Rod and Jack, I believe Unocal is in agreement with my assessment. I can provide detailed documentation of the methodology used for the estimate if you wish. Please call if you have questions. Yours truly, 9~f,tJ~ Jane Williamson Reservoir Engineer cc: Bob Crandall, Sr. Petroleum Geologist, AOGCC John Nonnan, Chair, AOGCC Daniel Seamount, Commissioner, AOGCC Rob Stinson - Unocal {!OJ\llcIø..~.I7/J1J I A/J/J{..y11 '5 lece¿ /eo. ~ / / -.. I l' Cl¡:?erú/Clr IlL- Ú·/Jó{d? (}JI7Ilcff7IJ TJ/) I ;::J J e . 14:43 FAI2697687 . ADEC !.1\{CRORAGE e STATE OF ALASKA DEPARTlY.IENT.Oli'ENV1RONMENTAL CONSERVAT1öN 1ft ~ Division of Spill Prevention and Industty Pr~paredness'Þrogratn .'1 itìO q 1") v t);& . 555 Cordova street ð· Anchorage, AIS: 99501-2617 rEQELV~D APR'· .. 0) l'" ..... C j ..'~ .~': . -"QI&1ìII('r,..-, " ,4-" -III, ~iIR...^~ . ''''JI ~ ~ " .." c. . WAD¿:, (;; L(J~(\! ~~ f'J..4\f- q 4- ..t1'-~Ø6'"- .rJn- ~, j ,. '1'0 .:1à c:..k. A ò (; (.c.. t{f-\.(L TZ- Fro~ Coœpany Phone No. . Date Phone. . No. - FM: No. : .;).7/..0 ....;. 15~ . Fax No. 907~269~7687 1::. 4'1 0 Number ofpagès including coveJ:' sheet: "2-. COMMENTS: Jt~ r r4r·' JV£b. . . { '\Ib~)' ., · L ~. .J.-4I ~'. . ..¡ .f'L".. JI K LLmAr Q.,-..,¿' ~ ?~~ W¿u...Ì5 tN~ ~I~~ .. .......... ......... ~ I:.....- ~t4 ~.~ ~.~ ~~ .~~~~ f-)J.JI ~l'l)1~~ ~~ .~&.t. *--\:Þv.~ ~~ ~~ck-,~~~I~d.~K r~" . w-- .. ~4/01/04 14:44 FAX 2697687 e ADEC ANCHORAGE 1.0 RESPONSEPlANN1NG STANDARD e 141 002 The Response Planning Standard (RÞS) for a blowout at Unocal's Red Wen Exploration is based on 2,000 b~ríels of oil perÒI;IY (bopd). .T'rtle 1S of.the Alaska Administrative Code (AAG), Chapter 75, part 434 (18 MC 75.434) allows the use of a lower discharge rate based on adequate well data and supporting documentation. Data frorrisixwel!s with sÎmilar characteristics to Red Wen were used to support a volume of 2.000bopdand a gas-to-oIl ratio (GOR) of 200. The wells are: - -. .....~.. -. WaJl Mãrathon Oil c'ômpany 5, Beaver Creek Unit, Tyonek G Zone 15461-511 Soldoina CreeK Unit21-3 . $oldotna Creek Unit 314-4 .,-.. ...... .... Middle Ground Shoal State 14 Middle Groul'ld ShóalState 14 . 4 Beaver Creek Unit Størìchkoff State #1 \ "B~rrels of Oil per Day 383 390~640 390 232 361 -..... ·Ú¿t9~ 56 The RPS for Red Well is 1,260 bopd using the following prevention creòits: Alcohol and drug testing - 5% Well Control Certification credit - 5% F'ormal safety analysis credit - 5% Operations Management System and Risk Analysis - 10% Assurance of well tubular integrjty ..:. 5% On-site drilling fluid system - 5% Overbalanced drilling - 5% Four-preventer BOP stack: - 5% \ ~s~to--Oil Rat,õ ! 326 153~289 289 228 95.8 180 :""'75 Oil travels from the well in an aerial plume. The deposition of the aerial plume u$ed in thé re$ponse Scenario 1 in Section 1.6.12 is based on the Oil Deposition Modeling for Surface Well Blowouts by SL. Ross Environmental Research Ltd for Alaska Clean Seas. .,,-.:........ Red Well 2004 Exploratìon 1.0-1 February 2004 . . TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/P ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME ~J HJ PTD# :2CJ9-0?Lj Development Service CHECK WBA T APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API num ber last two (2) digits are between 60-69) X Exploration Stratigraphic ~'CLUEn Tbe permit is for a new weUbore segment of existing weD Permit No, API No. Production.sbould continue to be reported as a function' of tbe original API number. stated above. BOLE In accordance witb 20 AAC 25.005(1), all records, data and logs acquired for tbe pilot hole must be clearly differentiated in both name (name on permit plus PH) and API Dumber (50 70/80) from records, data and logs acquired for we)) (name on permit). Pll..OT (PH) SPACING EXCEPTION x DRY DITCH SAMPLE The permit is approved subject ·to fuD compliance with 20 AAC 25..055~ Approval to perforate and produce is contingent upon issuance of ~ conservation order approving a spacing exception. (Company Name) assumes tbe liability of any protest to tbe spacing exception tbat may occur. All dry ditch sample sets submitted to tbe Commission must be in no greater -tban 30' sample intervals from below tbe permafrost or from where samples are first caugbt and 10' sample intervals tbrough target zones. Field & Pool Well Name: RED #1 _Program EXP Well bore seg 0 PTD#: 2040840 Company UNION OIL CO OF CALIFORNIA nitial ClasslType EXP /1 0-2G _ GeoArea Unit On/Off Shore On Annular Disposal 0 Administration 1 P~rmit fee attaçhed. . - - - - - - y~s - - - - - 2 Leas~numberapprORriate. . . Xes 3 .U.nlque welln.am~.a[1d Ol!.mb.er . . . . ..... . . . .Y~s..... . .. .. . . ..... .... .. . - - - - - - - - - - - - - - - -- - - - - - - 4 Well IQc¡¡t~d in.a. define.dpool. . . . No · THIS IS AN EXPLORA tORX WELL" POTENTIAL TARGEtS INCLUOE;BELUGA FM. (GAS), JYONf;K FMc (GA 5 Well IQc¡¡t~d proper dlsta[1ce from driJling unitb.ound.al)'. ....Xes · . HEMLOCK fM..(OlL) AND WEST.FOREIAND (OIL) . I 6 WeIlIQc¡¡t~d prOper .dlstance. from Qtber w~lJs Y~s. . · . THE WELL MAY .BEGAS. PROOUGTNE WItHIN 1500' OF A. LEA.SE 60UNDRY HOWEVER THE OWNER A.I\ID 7 .S.uffiçient açreag.e .ayailable in drilliog unit. . - - - - - y~s . . . . . . 60TH PROPER1IES.. - - - - - - - - - - 8 If.d~viated, js wellbQre pl¡¡tinclu.ded . Xes - - - - - - - - i9 Operator only af1'eçt~d party. . Xes - - - - - - - - - ~ - - - - 10 .Op~rator bas. appropriate. Qond LnJQrçe . . . . . . . . . . . . . . . . . . Y~s. . . . . . . ~A LARGE CHANGE IN fORMA110N WAT.ERTHAJREPRESENTS THE 6ASE Of UNDf;RGROUND. . . . 11 Permit can be issued without conservation order Xes . . · SOURCES Of DRlNKJNG WATER IS PRESENT IN .THE ADJACENT NORTH FORK 11-4 WELL AJ850' MD. Appr Date 12 P~rmit can Þe lSSl!.ed witbQut ad.milJistratÎ\leapproval . . .. Y~s. RPC 5/19/2004 13 Can permit be approved before 15-day wait Yes . 14 WeJIJQc¡¡t~d withjn area and.str¡¡ta .authorized by.lnjectioo Ord~r # (PutlO# in.co01ments).(For NA. - - - - - - - - - - - - 15 .All w~lJs.withLn .1l4.lTJile.are.a.of reyi~w id~otifi~d (FOr ~eJVjc.e.we!l only). . . . . . . . . . . . . . . .NA . . . . . . . . . . . . . - - - - - - - - - - - - - - - - .. . 16 Pre-produced. i!1j~ctor; duratiQnof pr~-productiolJ less than 3 months. (Fors~rvlce well Qnly) . . NA 1 17 .ACMP.FJndjng.of Con.sLstency.has Þeenjssued for. tbis projeçt NA. . - - - - - - ~ - Engineering 18 C.ondu.ctor str.ing.prQvid~d . - - - - - - - - - - - Xes . . - - - - - 19 .Surfac~casingprotec.ts all. known USOWs . Y~s. . 20 CMT.volad~quate.to çircµIateon.cooduçtof& su.rfcsg . . · . . .Y.es · . A.de~uate ex.cess, 21 .CMT v.ol ad~ql!.ate.to tie-LnJongstri[1g to.surf çsg. . ... No. 22 .CMT. will coyer.all knQwnpro.ductiye bQrizon.s y~s 23 .C.asing designs adeCllJa.te for C.t. B.&.permafrost . . . . . Xes . . [24 Mequate.tankage.or reserve pit. . y~s . . . . . . . Nab.ors 129. - - - - - 25 If.are-drilt has a 10A03 fOJ abandonment be~n ¡¡pprov~d . NA. ... . . New well, . 26 .Adequate.we!lbore. ~epar¡¡tjo.n.proposed. . . . _ _ . _ _ _ . _ . _ . . . _ . · . _ _Y~s _ _ _ _ _ _ _' _. . . . . _ _ _ _. _ _. . _ _ . . . 27 Jfdiv~r:ter req.uíred, dQes it me~t r~gulatiolJs. - - - - - · . . Xes . · . WaiYerrequ~sted. fOr 12" vent jn~. Appr Date 28 .Drilliog fluid. program sc.h~matic& eqµip listadequ¡¡t~. . . ... y~s · Max. MW.l0.0ppg. WGA 5/20/2004 29 BQPEs..d.othey me~U~gulatioo . . Y~s. . . 30 BQPE.press raiing approPriate; test to (put psig in comments) y~s · Test to 4500 psi.I\lISf' 3312 psi. 31 C.hokelTJanjfold çQmp.lie~ w/API RF'-53 (May 84) .Y~s. _ 32 WQrk wi!! OCCUr withpyt.operatjonsbutdown. . . Y~s. . - - - - - - 33 I~ presence Qf H2S gas. Rrob_abl~. . - - - - ~ .N.o. . - - - - - - 34 Meçbanical. coodJt[O[1 of wells within AOR yertfied (For service welJ only) NA. . - - - - - - Geology 35 P.e(mit ca[1 Þe lSSl!.ed wlQ hydrogen s.ulfide O1~as.Ures .N.o_ . 36 .D.ata.pres~oted on. pote.ntial overpres.sure .zone;;. . . Yes. Appr Date 37 S~tsm¡canalysjs. Qf shaJlow gas.zones. . Y~s. . ~ - - - - RPC 5/19/2004 138 Seabedconditioo survey.(if off-shore) . . . . NA.. - - - - -- 139 CQnta.ct namelphone.forwe~kly progre~sreports [I Yes · r:>HIL KRUGER .273-7628 Geologic Date: Engineering Date r~y Commissioner Commissioner: e e Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify fìnding information. information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. ·. . ~& '1-08''/ ICEIVED 12.£,1fQ SEP 2 8 2004 Sperry-Sun Drilling Services LIS Scan Utility $Revision: 3 $ LisLib $Revision: 4 $ Mon Sep 13 09:36:25 2004 AiaWaOi&ca,eo..c. "'b -....... Reel Header Service name.... ...... ...LISTPE Date.................... .04/09/13 Origin. . . . . . . . . . . . . . . . . . . STS Reel Name. .............. .UNKNOWN Continuation Number......Ol Previous Reel Name.......UNKNOWN Comments.................STS LIS Writing Library. Scientific Technical Services Tape Header Service name... ..... .....LISTPE Date.................... .04/09/13 Origin. . . . . . . . . . . . . . . . . . . STS Tape Name... ...... .......UNKNOWN Continuation Number......Ol Previous Tape Name...... .UNKNOWN Comments.................STS LIS Writing Library. Scientific Technical Services Physical EOF Comment Record TAPE HEADER Colville River Unit (Alpine) MWD/MAD LOGS # WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: # JOB DATA CD2-31 501032049300 ConocoPhillips Alaska, Inc. Sperry Sun 09-SEP-04 JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: MWD RUN 2 MW0003109992 R. KRELL D. BURLEY MWD RUN 3 MW0003109992 R. KRELL D. BURLEY MWD RUN 4 MW0003109992 M. HANIK D. LUTRICK # SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: ELEVATION (FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: 2 llN 4E 1875 1526 .00 52.84 15.90 # WELL CASING RECORD 1ST STRING 2ND STRING 3RD STRING PRODUCTION STRING OPEN HOLE BIT SIZE (IN) 8.500 8.500 6.125 CASING SIZE (IN) 9.625 9.625 7.000 DRILLERS DEPTH (FT) 3302.0 3302.0 13598.0 # REMARKS: 1. ALL DEPTHS ARE MEASURED DEPTHS (MD) REFERENCED TO BIT, UNLESS OTHERWISE NOTED. 2. ALL VERTICAL DEPTHS ARE TRUE VERTICAL DEPTHS (TVD). 3. MWD RUN 1 IS DIRECTIONAL ONLY AND NOT PRESENTED. . . 4.MWD RUN 2 IS DIRECTIONAL WITH DUAL GAMMA RAY (DGR) , ELECTROMAGNETIC WAVE RESISTIVITY PHASE-4 (EWR4) , COMPENSATED THERMAL NEUTRON POROSITY (CTN) WITH INTEGRAL ACOUSTIC CALIPER (ACAL), AND AZIMUTHAL STABILIZED LITHO- DENSITY (ASLD). THE POROSITY INFORMATION IS PRESENTED ONLY ON CD2-31 PB1 LOG RESISTIVITY-GAMMA RAY INFORMATION IS PRESENTED ON THIS LOG AS IT IS THE SUITE THAT CONTINUES TO TD OF THE WELL. THIS WELL KICKS OFF FROM CD2-31PB1 AT 8021' MD,4725'TVD. 5. MWD RUNS 3-4 ARE DIRECTIONAL WITH DUAL GAMMA RAY (DGR) AND ELECTROMAGNETIC RESISTIVITY PHASE-4 (EWR4). 6. MWD DATA ARE CONSIDERED PDC PER DISCUSSION OF ALPINE LOGGING REQUIREMENTS AT PHILLIPS/VENDOR MEETING HELD ON 26 SEPTEMBER 2001. 7. MWD RUNS 2-4 REPRESENTS WELL CD2-31 WITH API# 50-103-20493-00. THIS WELL REACHED A TOTAL DEPTH (TD) OF 18131'MD, 7312'TVD. SROP SMOOTHED RATE OF PENETRATION WHILE DRILLING SGRC SMOOTHED GAMMA RAY COMBINED SEXP SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (EXTRA SHALLOW SPACING) SESP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (SHALLOW SPACING) SEMP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (MEDIUM SPACING) SEDP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (DEEP SPACING) SFXE SMOOTHED FORMATION EXPOSURE TIME (RESISTIVITY) $ File Header Service name.. ....... ....STSLIB.001 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......04/09/13 Maximum physical Record..65535 File Type............... .LO Previous File Name.......STSLIB.OOO Comment Record FILE HEADER FILE NUMBER: EDITED MERGED MWD Depth shifted DEPTH INCREMENT: # FILE SUMMARY PBU TOOL CODE GR FET RPD RPM RPS RPX ROP $ 1 and clipped curves; all bit runs merged. .5000 START DEPTH 3274.5 3292.0 3292.0 3292.0 3292.0 3292.0 3312.5 STOP DEPTH 18064.0 18071.5 18071.5 18071.5 18071.5 18071.5 18131. 0 # BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE DEPTH $ # MERGED DATA SOURCE . . PBU TOOL CODE MWD MWD MWD $ BIT RUN NO 2 3 4 MERGE TOP 3274.5 8021.0 13608.0 MERGE BASE 8020.5 13608.0 18131. 0 # REMARKS: MERGED MAIN PASS. $ # Data Format Specification Record Data Record Type............ ......0 Data Specification Block Type.....O Logging Direction.............. ...Down Optical log depth units...........Feet Data Reference Point..............Undefined Frame Spacing.................... .60 .1IN Max frames per record.............Undefined Absent value..................... .-999.25 Depth Units. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD FT/H 4 1 68 4 2 GR MWD API 4 1 68 8 3 RPX MWD OHMM 4 1 68 12 4 RPS MWD OHMM 4 1 68 16 5 RPM MWD OHMM 4 1 68 20 6 RPD MWD OHMM 4 1 68 24 7 FET MWD HRS 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 3274.5 18131 10702.8 29714 3274.5 18131 ROP MWD FT/H 0 594.61 167.127 29638 3312.5 18131 GR MWD API 30.76 407.65 97.5885 29580 3274.5 18064 RPX MWD OHMM 0.58 1876.79 11. 8318 29510 3292 18071.5 RPS MWD OHMM 0.07 1744.29 12.0471 29510 3292 18071.5 RPM MWD OHMM 0.14 2000 12.4873 29510 3292 18071.5 RPD MWD OHMM 0.09 2000 14.4366 29510 3292 18071.5 FET MWD HRS 0.16 103.58 0.861273 29509 3292 18071.5 First Reading For Entire File..........3274.5 Last Reading For Entire File...........18131 File Trailer Service name... ...... ....STSLIB.001 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......04/09/13 Maximum Physical Record..65535 File Type................LO Next File Name.......... .STSLIB.002 Physical EOF File Header Service name.............STSLIB.002 Service Sub Level Name... Version Number...........1.0.0 Date of Generation. ......04/09/13 Maximum Physical Record..65535 File Type............... .LO Previous File Name.......STSLIB.001 Cormnent Record FILE HEADER FILE NUMBER: 2 RAW MWD Curves and log header data for each bit run in separate files. . BIT RUN NUMBER: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE GR RPD RPM RPS RPX FET ROP $ 2 .5000 START DEPTH 3274.5 3292.0 3292.0 3292.0 3292.0 3292.0 3312.5 STOP DEPTH 8020.5 8020.5 8020.5 8020.5 8020.5 8020.5 8020.5 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO VENDOR TOOL CODE DGR EWR4 $ BOTTOM) TOOL TYPE DUAL GAMMA RAY ELECTROMAG. RESIS. 4 # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type. . . . . . . . . . . . . . . . . .0 Data Specification Block Type.....O Logging Direction.................Down Optical log depth units...........Feet Data Reference Point..............Undefined Frame Spacing.....................60 .1IN Max frames per record........ .... .Undefined Absent value..................... .-999.25 Depth Uni ts. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O . 12-JUN-04 Insite 0.43 Memory 8021.0 3274.5 8021.0 56.1 63.8 TOOL NUMBER 124725 151812 8.500 3302.0 LSND 9.70 36.0 9.3 250 7.0 5.000 2.561 5.200 4.000 72.0 147.0 7.2 72.0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 . . ROP MWD020 FT/H 4 1 68 4 2 GR MWD020 API 4 1 68 8 3 RPX MWD020 OHMM 4 1 68 12 4 RPS MWD020 OHMM 4 1 68 16 5 RPM MWD020 OHMM 4 1 68 20 6 RPD MWD020 OHMM 4 1 68 24 7 FET MWD020 HRS 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 3274.5 8020.5 5647.5 9493 3274.5 8020.5 ROP MWD020 FT/H 14 466 219.88 9417 3312.5 8020.5 GR MWD020 API 52.23 196.43 114.157 9493 3274.5 8020.5 RPX MWD020 OHMM 0.58 1489.81 5.38908 9458 3292 8020.5 RPS MWD020 OHMM 0.07 1499.94 5.41268 9458 3292 8020.5 RPM MWD020 OHMM 0.14 2000 5.72192 9458 3292 8020.5 RPD MWD020 OHMM 0.09 2000 8.75725 9458 3292 8020.5 FET MWD020 HRS 0.16 51. 78 0.597339 9458 3292 8020.5 First Reading For Entire File..........3274.5 Last Reading For Entire File...........8020.5 File Trailer Service name.............STSLIB.002 Service Sub Level Name... Version Number...........l.0.0 Date of Generation.......04/09/13 Maximum Physical Record..65535 File Type. .............. .LO Next File Name...........STSLIB.003 Physical EOF File Header Service name.............STSLIB.003 Service Sub Level Name... Version Number.......... .1.0.0 Date of Generation.......04/09/13 Maximum Physical Record..65535 File Type.............. ..LO Previous File Name. ..... .STSLIB.002 Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE ROP FET RPD RPM RPS RPX GR $ 3 header data for each bit run in separate files. 3 .5000 START DEPTH 8021. 0 8021.0 8021.0 8021.0 8021. 0 8021.0 8021.0 STOP DEPTH 13608.0 13562.0 13562.5 13562.5 13562.5 13562.5 13570.0 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): 16-JUN-04 Insite 0.43 Memory 13608.0 8021. 0 13608.0 . BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO VENDOR TOOL CODE DGR EWR4 $ BOTTOM) TOOL TYPE DUAL GAMMA RAY ELECTROMAG. RESIS. 4 # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type................ ..0 Data Specification Block Type.....O Logging Direction.................Down Optical log depth units... ........Feet Data Reference Point.... ........ ..Undefined Frame Spacing.................... .60 .1IN Max frames per record............ .Undefined Absent value.... . . . . . . . . . . . . . . . . . . -999.25 Depth Units. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O . 55.7 80.3 TOOL NUMBER 124725 151812 8.500 3302.0 LSND 9.70 38.0 9.0 350 6.6 3.000 1. 806 3.500 3.200 90.0 154.0 90.0 90.0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD030 FT/H 4 1 68 4 2 GR MWD030 API 4 1 68 8 3 RPX MWD030 OHMM 4 1 68 12 4 RPS MWD030 OHMM 4 1 68 16 5 RPM MWD030 OHMM 4 1 68 20 6 RPD MWD030 OHMM 4 1 68 24 7 FET MWD030 HRS 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 8021 13608 10814.5 11175 8021 13608 ROP MWD030 FT/H 7.62 315.47 195.837 11175 8021 13608 GR MWD030 API 46.99 407.65 116.056 11099 8021 13570 RPX MWD030 OHMM 1.18 32.82 6.44006 11084 8021 13562.5 RPS MWD030 OHMM 1. 04 32.32 6.50921 11084 8021 13562.5 RPM MWD030 OHMM 1. 08 32.56 6.81983 11084 8021 13562.5 RPD MWD030 OHMM 1. 46 127.83 7.2298 11084 8021 13562.5 FET MWD030 HRS 0.18 103.58 0.420625 11083 8021 13562 First Reading For Entire File..........8021 . . Last Reading For Entire File...........13608 File Trailer Service name.............STSLIB.003 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......04/09/13 Maximum Physical Record..65535 File Type............... .LO Next File Name...........STSLIB.004 Physical EOF File Header Service name... ..........STSLIB.004 Service Sub Level Name... Version Number.......... .1.0.0 Date of Generation.......04/09/13 Maximum Physical Record..65535 File Type................LO Previous File Name.......STSLIB.003 Comment Record FILE HEADER FILE NUMBER: RAW MWD Curves and log BIT RUN NUMBER: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE GR RPD RPM RPS RPX FET ROP $ 4 header data for each bit run in separate files. 4 .5000 START DEPTH 13575.0 13588.0 13588.0 13588.0 13588.0 13588.0 13608.5 STOP DEPTH 18064.0 18071.5 18071.5 18071.5 18071.5 18071.5 18131. 0 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: 24-JUN-04 Insite 6.02 Memory 18131. 0 13608.0 18131. 0 87.1 94.2 # TOOL STRING (TOP TO VENDOR TOOL CODE DGR EWR4 $ BOTTOM) TOOL TYPE DUAL GAMMA RAY Electromag Resis. 4 TOOL NUMBER 91360 156401 # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): 6.125 13598.0 # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) Oil Based 8.90 60.0 .0 42000 3.6 . . MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: .000 .000 .000 .000 .0 173.0 .0 .0 # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # REMARKS: $ # Data Format Specification Record Data Record Type..................O Data Specification Block Type.....O Logging Direction.................Down Optical log depth units..... ..... .Feet Data Reference Point..............Undefined Frame Spacing.................... .60 .1IN Max frames per record.............Undefined Absent value......................-999.25 Depth Units. . . . . . . . . . . . . . . . . . . . . . . Datum Specification Block sub-type...O Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 ROP MWD040 FT/H 4 1 68 4 2 GR MWD040 API 4 1 68 8 3 RPX MWD040 OHMM 4 1 68 12 4 RPS MWD040 OHMM 4 1 68 16 5 RPM MWD040 OHMM 4 1 68 20 6 RPD MWD040 OHMM 4 1 68 24 7 FET MWD040 HRS 4 1 68 28 8 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 13575 18131 15853 9113 13575 18131 ROP MWD040 FT/H 0 594.61 76.7443 9046 13608.5 18131 GR MWD040 API 30.76 87.99 57.3033 8979 13575 18064 RPX MWD040 OHMM 5.79 1876.79 25.2906 8968 13588 18071.5 RPS MWD040 OHMM 5.95 1744.29 25.8885 8968 13588 18071.5 RPM MWD040 OHMM 0.26 2000 26.627 8968 13588 18071.5 RPD MWD040 OHMM 6.51 2000 29.3334 8968 13588 18071.5 FET MWD040 HRS 0.53 84.7 1. 6842 8968 13588 18071.5 First Reading For Entire File..........13575 Last Reading For Entire File...........18131 File Trailer Service name.............STSLIB.004 Service Sub Level Name... Version Number...........1.0.0 Date of Generation. .... ..04/09/13 Maximum physical Record..65535 File Type......... ...... .LO Next File Name...........STSLIB.005 Physical EOF Tape Trailer Service name............ .LISTPE Date. . . . . . . . . . . . . . . . . . . . .04/09/13 Origin. . . . . . . . . . . . . . . . . . . STS Tape Name................UNKNOWN Continuation Number......01 Next Tape Name.......... .UNKNOWN ~ . . Comments.................STS LIS Writing Library. Scientific Technical Services Reel Trailer Service name... ..........LISTPE Date.................... .04/09/13 Origin. . . . . . . . . . . . . . . . . . . STS Reel Name.............. ..UNKNOWN Continuation Number......Ol Next Reel Name...........UNKNOWN Comments.................STS LIS Writing Library. Scientific Technical Services physical EOF Physical EOF End Of LIS File II ¡ I · · · URDCAL. Red #1 TABLE OF CONTENTS WELL RES U ME..... II..... II..........,....................... II............................................................................... II..... II.............................. 3 PROCEDURES AND GENERAL DISCUSSION .............................................................5 GEOLOGICAL DISCU 5510N .................................................................................... ......................... ................... ........................ 6 CAlLY ACTIVITY SUM MARy...................... ....... .... ........................ ... ..... ........ ... ............... ....... 8 LITHOLOGY REVI EW .... ...... ....... ................. ....... ... ......... ........ .................. ............................. 10 SURVEY IN FORMATION.. .......... ........... ....... ............... ........................... .......................... ......... ....... 39 DAILY MUD PROPERTIES....... ............ ............ .................. ........................................... 44 BIT RECORD ............. ..... .............. ............... ........ ......... ... .... .................... ....... .... .... ...... 45 MORN I NG REPORTS..................................... _... _ _................... _ fI-.... _..................... _ _ ..... ....46 FINAL WELL LOGS...... ................................. ................ ......... ...................... .... ............47 g EPOCH 2 . . . UNOCALe Red #1 WELL RESUME Company: Unocal Alaska. Well: Red #1 Field: Nicolaevsk Unit Region: Cook Inlet Location: Section 8 T 4 S R 13 W SM Coordinates: 338' FNL,409' FWL Elevation: RKB = 'AGL RKB Elevation = 694.5' GL = ' AMSL County, State: Kenai Borough, Alaska API Index: 50 - 231 - 20021 - 00 Spud Date: June 9th , 2004 Total Depth: 12458' on June 28th, 2004 Contractor: Nabors Drilling Alaska Company Representative: Shane Hauck, Larry McCallister RigfType: Nabors #129/ Land Epoch Logging Unit #30 Epoch Personal: Brian Q'Fallon Lees F. Browne Jr. Company Geologist Mark Lynch Dave Buthman U EPOCH 3 · · · Casing Data: Hole size: Mud Type: Logged Interval: Electric Logging Co: Logs Run: UNOCALe Red #1 16" landed at 66' 9 5/8" @ 1800' 7" @ 4601' 3%"@' 12 %" to 1800' 8 %" to 4615' 6 1/8" to 12458' Spud to 1800' LSND to 4615' INVERMUL Oil Base to 12458' Full Logging under 7" casing pipe Schlumberger TRIPLE COMBO: GRlRes LWD APLS (azimuthal density/neutron) APLS first bit run only under 7" csg ~ EPOCH 4 URDCAL. Red #1 . PROCEDURES AND GENERAL DISCUSSION Epoch supplied a fully computerized Rigwatch system (which included measurements block height, drill rate, pit volumes, pump rates, pump pressure, flow line, return flow, hook load, torque, and rotary speed) for all operations. Display monitors for the company man, tool pusher and mud éngineer, and touch-screen (Azonix) displays for the driller and pit watcher provided graphics of the information. Hydrogen flame ionization (FID) Total Gas and (FID) Gas Chromatograph instruments detected and analyzed formation gases. Mud gas was continuously generated by an optimally positioned Quantitative Gas Measurement (QGMTM, Texaco patent) electrically driven gas trap, and drawn to the detectors by vacuum pump. The gas system was tested and calibrated on a regular basis. . Unocal Alaska Resources, Inc. spudded Red Pad #1 on June 9th, 2004 with Nabors Drilling Alaska #129. Epoch commenced DML TM logging on the same day at the base of the 16" conductor pipe at 66'. The 12Y4" Surface hole was drilled with water base mud from surface' to 1800' and completed on June 11 th, 2004. Mud weight was 8.7 increased to 9.1 ppg. Cuttings collection and analysis commenced from surface conductor hole section began on June 9th, 2004. Cuttings samples were caught at 30' intervals and at smaller intervals if the drill rate allowed during high gas intervals. Attention was paid to optimum sampling during these and all gas shows. The intermediate hole section was drilled with water base mud from 1800' to 4615'. A slight amount of sliding was necessary to keep and maintain a target tangent angle of approximately 0.770. Mud weight was gradually increased from 8.9+ ppg to 9.1 + ppg. Intermediate hole was completed on June 15, 2004, with a carbide drop showing a 15 bbl wash out over a gauged hole with no drilling problems. After swapping from water base mud to oil base mud, the 6%" deep hole section commenced on June 17th, 2004. Continued sliding was required to maintain 2° tangent angle per 100' to 27.3° @ 125.8 AZI, to hit the mid Tyonek gas sands and then to drop angle to 1 °/1 00' in the West Forelands to the total depth. The mud weight of 8.9 ppg at the 7" shoe was increased in steps to 9.2+ ppg and again to 10.0 at Total Depth, in response to connection and swab gases and the well flowing slightly. Down hole electric wireline data was obtained by a Schlumberger Service Quad-Combo Assembly. 3%" production tubing was run in the hole on 5" drill pipe, the hanger set, and the tubing string cemented on July 3, 2004 Epoch was given its release to rig down . after cementing. U EPOCH 5 URDCAL. Red #1 · GEOLOGICAL DISCUSSION Red #1 The primary objectives of the Red Pad #1 were quality Tyonek Formation gas sands. Secondary objectives were more marginal Hemlock zones and some of the lower West Foreland. From 1800' to 4615', the intermediate hole was drilled through the Sterling to Lower Beluga Formations. The interval averaged 88.5 units of gas, with a maximum of 147 units at 1837' in a coal. The highest gas measured from sandstone was 80 units at 1670' to 1680'. The 61/8" hole was drilled from 4615' to a total depth of 12458', included Lower Beluga and Tyonek Formations. Gas averaged 96 units, with a maximum of 221 units in a conglomerate sand from 8795' to 8810'. · This zone showed an eight foot drill break from 80 ftIhr to a maximum of 190 ftlhr and decreasing to 90 ftIhr. Samples displayed conglomerate sand with a fine to medium grain sand matrix. Samples were medium light gray to light gray, fine matrix sands to coarse grains with scattered coarse to pebble clasts. Coarser grains tended to be more angular with bit impaction and finer grains being sub round to rounded. Some poor consolidation noted with most samples being unconsolidated. Both matrix and grain supported were noted with occasionally moderate to well con$olidated in slight calcareous to slight siliceous cement. Composed of 80% quartz and 20% black to gray to green to red carbonaceous clasts and silicates with slight dark gray streaks do to the reworking of carbonaceous clasts and minor alteration of silicates with fair porosity and permeability. · Drill gas from a number of coals exceeded 100 units up to 195 units at 9687'. The most significant gas was 180 units when drilling the 9230' to 9300' conglomerate sand. The rate of penetration increased from 80 ftIhr to an average of 140 ftIhr drilling erratically through the conglomerate. Gas readings slowly increased over the zone from 120 units to a maximum of 195 and decreasing to an average background gas of 125 units after the sand body. Samples were 100% conglomerate sand being light gray in color. Clast size ranged from very coarse to fine grained matrix sands. Sphericity of the grains was sub angular coarse grains to sub rounded matrix grains; overall poorly sorted with no abundant faction. Texture of the grains ranged from chipped larger clasts to pitted and some polished lower. Grains showed non to very slight siliceous cement and non calcareous with a slight silt/ash matrix showing a dominant grain support composed of 90% quartz and 10% chert and various lithic fragments. Fair to good porosity and permeability exhibited throughout the entire zone. Chromatograph C-3 readings appeared from a zero background to a maximum of 21 ppm over this zone. g EPOCH 6 · · · . ---·-·0·· .........~ UN . CA...., Red #1 After a bit trip at 10765' connectión gases were observed at 3850 to 4025 strokes after the pumps were turned on and at every connection to 12458' (TO). These connection gases were lagged back to the conglomerate sand zone of 9230' to 9300'. Scattered loose sands were noted (with no more than 20-30% of the samples) between 12175' to 12300'. These sands and sandstones were angular conglomeratic grains with overall slight loose very fine to coarse grains with trace streaks grading to sandstone. No large sand bodies noticed. The majority of the samples were tuffaceous claystone being very homogeneous and uniform with a sub greasy appearance. Gas readings over this zone increased from 38 units to a maximum of 60 units with a 9.5 ppg mud weight. No drill rate increases were noted. The well was flowing slightly at 12371' (connection) and two distinct connection gases were noted at each down time of circulating. The first and smaller kick came from the 9230' to 9300' conglomerate sand (50 to 80 units over background gas at 3850 to 4025 strokes) and the second and larger kick (80 to 120 units over background gas) coming from just off bottom at 5550 to 5780 strokes. The mud weight was increased from 9.5 to 9.7 and no flow was detected at the connection at 12406'. Upon reaching total depth at 12458' the well was allowed to flow for 46.5 minutes and collected 4.1 bbls of drilling fluid. The mud weight was increased to 10.0 ppg for proper fill and conditioning for tripping out of the hole. [:I EPOCH 7 · · · UROCAL. Red #1 DAILY ACTIVITY SUMMARY (Note: All daily summaries reported at 24:00:00 of listed date.) 6110104 Finished rigging up and mixed spud mud. Attempt to wash fill out of the conductor pipe resulted in losing drilling mud over the shaker. Picked up 60 joints of 4" drill pipe and 18 joints of 4" HWDP for the BHA and changed out the shaker screens while picking up the BHA. Tagged fill at 23' and drilled out under conductor pipe at 700' 6111104 Drilled to 1800' and circulated the hole clean and pumped out of the hole with the hole being tight. Lay down one joint of HWDP and picked up one set of jars and tripped into the hole without problems. Washed and reamed 53' to bottom. No fill was on bottom. Circulate and condition the hole to run 9 5/8" casing. 6/12104 Circulate and conditioned mud for running 9 5/8" casing. Trip out of the hole and rig up and run 9 5/8" casing. Pump 193 bbls of cement and rig down Dowell. Run gyro on wire line logs and begin to nipple down diverter. 6/13/04 Finish nipple up and test BOP. Pick up drill pipe and stand in derrick. Pick up BHA and run in hole with singles. Drill cement and shoe, and formation from 1800' to 1820'. Displace well dumping old mud, and perform leak off test, 15.0 ppg EMW. Drill from 1820' to 2047'. 6/14/04 Drill from 2047' to 4615',7" casing depth, and circulate bottoms up. Drop carbide, and continue circulating and conditioning hole. 6/15/04 Drill to 4615' and circulate one hole volume and drop carbide (15 bbl over gauged hole). Continue to circulate the hole clean. 6/16/04 Tripped out of the hole to 3440' (above the ghost reamer). The hole became tight at 3970', 3906', and 3883' and 3845'. Pumped q dry job and tripped out to the 5" HWDP. Lay down the BHA and rig up and ran the wire line logs. Rigged down the wire line loggers and rigged up and ran the 7" casing. Circulated the hole and conditioned the mud with the casing on bottom. 6/17/04 Cemented 7" casing and tested it to 3000 Ibs. Installed "pack off" and changed the lower rams. Nippled up the BOPE and tested the BOPE. Installed a drip pan under the rig floor and started to pick up the BHA. 6/18/04 Tripped in the hole with 4" drill pipe (singles) and tagged cement at 4534'. Cut drilling line and displaced to oil base mud. Weighted up to 8.9 from 8.6+ and drilled out cement and float shoe plus 20' of new hole and performed a leak off test to 13.3 ppg EMW. g EPOCH 8 . . . UNOCALe Red #1 6/19/04 Drilled formation. 6/20/04 Drilled formation. 6/21/04 Drilled formation. 6/22/04 Drilled formation. 6/23/04 Drilled formation to 10765' and circulated the hole clean and pull out of the hole for a bit trip. 6/24/04 Picked up a BHA and tripped into the hole to 10666' and reamed to bottom with drilling formation. 6/25/04 Drilling formation 6/26/04 Drilling formation 6/27/04 Dr'illing formation and increasing mud weight from the well slightly flowing at connection. 6/28/04 Drilled to 12458 (TD) and monitored the well. The well was flowing and circulated up 112 units of gas. The mud weight was 9.4 on the regular scale and 9.7 on the pressure scale. Allowed the well to flow for 45 minutes @ 4.1 bbls and shut the well in and monitored. Circulated bottoms up and weighted up to 10.0 ppg and continued to monitor the well. The well was dead and pumped a pill and short tripped six stands. Improper fill was noted and tripped into the hole to bottom and circulated bottoms up. [:I EPOCH 9 UtlOCALe Red #1 . LITHOLOGY REVIEW Conglomerate sand (30' to 70') = light gray to medium light gray; clast size ranges from pebble to coarse lower with inter granular medium grain sand matrix; sub round coarse to sub angular matrix; moderate sphericity; impacted to pitted texture; slight clay matrix with dominant grain support; increase clay content with depth; composed of quartz and various lithic fragments; good porosity and permeability; no oil shows. Tuffaceous claystone (70' to 130') = medium gray; brittle; lumpy to clumpy; clustered to clotted; gelatinous to mush; amorphous fracture and habit; moderate to dull earthy luster; ashy to colloidal texture; massive beds of homogeneous clay; becoming very hydrophilic and going into solution; scattered coarse grained sands. Tuffaceous claystone (130' to 180') = medium gray; brittle, lumpy to clumpy; clustered to clotted; gelatin to mushy; amorphous fracture; amorphous to sub earthy habit; colloidal to clayey text; massive beds of homogeneous clays; some interbedded with coarse grain sand; very hydrophilic with most going to mud. . Tuffaceous siltstone (190' to 220') = light brownish gray to medium gray; poor indurations; brittle; crumbly; slightly malleable; slightly sectile; slightly flexible; slightly elastic; clustered to clotted; mushy to pasty; earthy to amorphous fracture; sub nodular to amorphous habit; dull earthy luster; silty to clayey texture. Conglomerate sand/sand (230' to 310') = light gray some becoming yellowish gray to light greenish gray; clast size range from coarse upper/pebble to fine upper; sub angular to sub round; some angular bit impacted fragments; moderate some low developed sphericity; poor sorting; chip to impact texture; sub mature; non to very slight silica cement; slight clay matrix with dominant grain support; comp of 90% quartz, 10% chert, argillite, green stone; tuff and various lithic fragments; good estimated porosity and permeability; no oil indicators. Tuffaceous siltstone (330' to 360') = pale yellowish brown to light brownish gray; very poorly indurated; lumpy to clumpy; clustered to clotted; amorphous fracture; sub nodular to amorphous habit; dull earthy luster; silty to colloidal texture; thick to massive beds of tuffaceous silt; composed of 70% silt 30% carbonaceous fragments, tuff, very fine grained sand and various detrital material; scattered muscovite and other mica (sericite, chlorite). Tuffaceous claystone (390' to 430') = pale yellowish brown; very soft; brittle lumpy to clumpy; clustered to clotted; gelatinous some mushy; various consistency; amorphous fracture and habit; moderate to dull earthy luster; clayey to colloidal texture; massive beds of homogeneous silts and clays; some interbedded sands. . g EPOCH 10 . . . UROCAL. Red #1 Tuffaceous siltstone (430' to 490') = pale yellowish brown to light brownish gray; poor to moderate indurations; brittle to malleable; sectile in parts; slightly flexi to elastic; various consistency from clustered to mushy; non to moderate cohesiveness to slightly adhesive; amorphous to earthy fracture; sub nodular to amorphous habit; dull earthy luster; silty to clayey texture; massive gradational silts and clays; thin beds of coal with no visible bleeds of gas. Sand (490' to 550') = pale yellowish brown to medium gray; clast size ranges from coarse lower to fine upper; moderate developed sphericity; poor sorting; impacted to chip texture; sub mature nature; non to very slight silic cement; slight to moderate silUclay hydrophilic matrix; dominant grain support with secondary matrix support with depth; composed of quartz with minor meta, greenstone, and various lithic fragments; fair estimated porosity and permeability; no oil. Tuffaceous siltstone/claystone (560' to 610') = pale yellowish brown to light brownish gray; poor to moderate induration; brittle to firm; sectile in parts; slightly flexi to elastic; earthy to amorphous fracture; sub nodular to amorphous habit; grading between clay and silt; moderate earthy luster; silty to clayey texture; massive beds of silt and clay; visible relic shards in matrix Sand (650' to 690') = medium gray; clast size ranges from medium upper to fine upper; sub angular to sub round; moderate developed sphericity; moderate sorting; chip to impacted texture; sub mature nature; non to very slight silic cement; slight hydrophilic clay matrix; dominant grain supported matrix; composed of 90% quartz, 10% chert, meta, ign, greenstone and various lithic fragments fair to good porosity and permeability; No oil indicators Sand (700' to 740') = medium gray to medium light gray; very fine upper to coarse lower, especially fine to medium; subrounded to angular; high to moderate sphericity; moderately to poorly sorted with probable mostly slight clay matrix to some grading sandy claystone; mostly unconsolidated in sample to occasional slightly siliceous to slightly calcareous cement with a grayish yellow to light gray clay matrix; 65% quartz, and 35% black to brownish black to green to gray to rust to brown grains including silicates and minor coal and clay lithics; silicates mostly metalithics and some igneous; estimate fair to good porosity. Tuffaceous claystone (690' to 800') = medium gray to medium light gray, often with faint brownish to brownish hue, to often with faint greenish to greenish hue; moderately soft to moderately firm; soluble to slightly soluble and overall slightly hydrophilic; clayey to earthy to silty/fine sandy texture; brownish due slightly organic; lightly scattered fines, flakes, and partings of carbonaceous matter, generally increasing with increase in organic clay, and locally grading to carbonaceous claystone; locally interbedded with coal; non to slightly calcareous. g EPOCH 11 . . . UNOCALIÞ Red #1 Siltstone/sandstone (780' to 900') = medium gray to medium light gray with brownish hue; slightly firm to firm; slightly to some moderately soluble; silty to fine lower grains with scatter of fine upper to medium grains; poorly to moderately sorted; slight to moderate argillaceous/clay matrix; slight to very slight siliceous cement; mostly quartz with slight coal fines and scattered silicates, with silicates increasing in coarser fraction; mostly very poor to some poor to fair porosity. Sand/sandstone (890' to 970') = medium light gray to medium gray; very fine to coarse lower, especially fine to very fine to locally increasing medium, and grading conglomerate associated with coal; subangular to locally subrounded; poorly to moderately sorted; slight to moderate ashy clay matrix; mostly grain supported to locally grading sandy claystone; 70% quartz, and 30% black to brownish black to gray to green to rust grains including silicates and minor coal and clay lithies; occasional yellowish gray calcareous clay lithics; silicates mostly metalithics and minor igneous; estimate some fair to good porosity. Sand (970 to 1030') = medium light gray to medium gray; very fine to coarse lower, especially fine to medium; subangular; moderately to poorly sorted in slight to moderate ashy matrix; composition similar to above sand; estimate mostly fair to some good porosity. Tuffaceous claystone/siltstone (1030' to 1100') = medium light gray to medium gray, some with brownish hue, to occasionally brownish gray; moderately soft to slightly firm; moderately soluble to soluble; clayey to earthy to silty texture; often grading to siltstone; occasionally sandy with interbedded sand; some slightly organic occasionally grading grayish brown carbonaceous shale; some with carbonaceous fines, flakes, and partings, to locally interbedded coal, mostly lignite. Sand (1100' to 1180') = medium light gray to medium gray; very fine to coarse lower, especially fine to medium, and locally scattered coarse; subangular to angular; moderately high sphericity overall; moderately to poorly sorted; grain and some matrix supported in ashy clay; locally grading to tuffaceous claystone; 60% clear to opaque quartz, and 40% black to dark gray to gray to green to rust to trace yellow green grains, including mostly silicates and minor coal, clay, and trace slightly calcareous yellowish gray clay lithics; estimate some fair to good porosity. Conglomeratic sand/sand (1170' to 1270') = medium light gray to medium gray; fine to very coarse grains, especially medium to very coarse, and scattered coarse fragments to minor pebble; subrounded to subangular; moderately well to moderately and some poorly sorted; mostly grain and occasionally matrix supported; some interbedded ashy light gray sandy claystone; 65% clear to opaque quartz, and 35% mostly black to dark gray to some gray to green to rust grains; mostly silicates with trace coal and clay lithies, estimate mostly good to fair porosity. g EPOCH 12 UNOCAUÞ Red #1 . Tuffaceous claystone/siltstone (1240' to 1450') = medium gray to medium light gray, some with faint brownish hue, and some with faint greenish to greenish hue; moderately soft to moderately firm; soluble to moderately soluble; clayey to silty to very fine sandy texture; some slightly organic often with slight carbonaceous fines, flakes, and partings to trace coal lamina; some grading very fine grained sandstone, and interbedded fine to medium grain sands; occasional streaks hard calcareous gray to greenish gray shale. Sandstone/sand (1340' to 1450') = medium light gray to light gray, often with faint brownish hue; very fine to coarse lower, especially very fine upper to medium lower; subangular to subrounded; poorly to some moderately sorted; grain and matrix supported; 60-70% quartz, and 40-30% black to brownish black to gray to green to rust grains including mostly silicates to minor coal clasts; coal clasts increasing in poorly sorted finer sands and often associated with slightly organic clay with thin beds of coal; mostly poor to some fair porosity. . Conglomeratic sand/sand (1450' to 1535') = medium gray to medium light gray; fine to very coarse and scattered fragments and pebbles; subangular to subrounded, and some rounded in coarser fraction; poorly to moderately sorted; mostly unconsolidated in sample to rare moderately consolidated with calcareous clay matrix; 50% translucent to opaque quartz, and 50% dark gray to black to gray to green to white to minor rust, including mostly silicates and minor coal, and hard siltstone and firm claystone clasts; silicates mostly metalithics and minor chert; often grading poorly sorted conglomerate; massive to interbedded with claystone; mostly poor to fair and some good porosity. Coal (1540' to 1545') = black to occasionally brownish black; very firm and brittle; angular to blocky to platy fracture; subbituminous to some lignite. Tuffaceous claystone (1545' to 1660') = medium light gray to medium gray; moderately soft and hydrophilic; clayey to some slightly silty texture; some very slight floating sand grains; very slight to locally increasing fine disseminated to minor flakes carbonaceous matter; trace thinly laminated to locally thinly bedded coal; noncalcareous. Sand (1660' to 1690') = medium gray to medium dark gray; clast size ranges from medium upper to fine lower; sub round; moderate sphericity; moderate sorting; sub mature; non to very slight calc cement; slight silUclay matrix being very hydrophilic; dominant grain support composed of 80% quartz, 20% chert, meta, greenstone and various lithic fragments; appears arenaceous; good porosity and permeability; no oil indicators. . Tuffaceous claystone (1700' to 1750') = light brownish gray to pale yellowish brown; very soft to brittle; lumpy to clumpy; clustered to clotted; gelatin to mushy; amorphous to earthy fracture; amorphous to sub nodular habit; moderate to dull earthy luster; clayey to silty some colloidal texture; massive beds of gradational silts and clays' thin coal seams scattered. U EPOCH 13 UNOCAUÞ Red #1 · Sand/sandstone (1770' to 1800') = light gray to light brownish gray; clast size ranges from medium upper to fine upper; sub round; moderate sphericity; moderate sorting; impacted texture; immature nature; non to very slight calc cement; abundant silUclay matrix; dominant matrix support; composed of 90% quartz, 10% chert and various lithic fragments; poor estimated porosity and permeability; no oil indicators. Coal/carbonaceous shale (1825' to 1845') = black to dusky brown; firm with some hard; resinous to earthy luster; matte smooth texture; blocky fracture in coal sections to planar along shale partings in carbonaceous shale; slight visible bleeding gas from cuttings; composed of lignitic to sub bituminous. Tuffaceous claystone (1850' to 1930') = medium gray becoming very light brownish gray in parts; very poor to moderate induration; brittle to crumbly; slightly seetite in parts; various consistency from clotted to mushy and pasty; amorphous to pdc bit grooved fracture and habit; moderate earthy luster; silty to clayey texture; massive beds of gradational silts and clays; composed of 70% silt, 30% clay and various detrital material; visible pyro clastic relic shards in matrix; minor coal and carbonaceous shale beds. · Tuffaceous claystone/siltstone (1930' to 2050') = medium light gray to medium gray to trace light brownish gray; moderately soft and hydrophilic; clayey to silty texture with abundant apparent microshard silt grains; some sandy with very fine to fine grains grading to matrix and grain supported soft sandstone; occasionally slightly to moderately organic with traces carbonaceous fines to locally grading carbonaceous shale with thinly bedded coal; scattered calcite especially associated with sandstone and coal Sandstone (1980' to 2050') = medium gray to light brownish gray; very fine grain to silty; matrix and grain supported in variably argillaceous clay matrix; often slightly organic, and mostly with slight to moderate carbonaceous silts and fines; noncalcareous; interbedded and grading to claystone and siltstone; noncalcareous; locally thin beds and laminations of coal; locally interbedded firm calcareous siltstone. Coal (2080' to 2170') = black to brownish black; very firm and brittle with irregular to angular fracture, to slightly firm and crumbly with hackly to flaky fracture; lignite to subbituminous; resinous to vitreous luster; some organic clay on flaky to hackly parting; locally grading and interbedded with carbonaceous shale. Tuffaceous claystone (2050' to 2170') = medium gray occasionally with greenish hue, some brownish gray to medium dark gray; non organic clays moderately soft and hydrophilic with clayey to slightly silty texture; occasionally grading to siltstone, and rare sandy with very fine to fine grains; some slightly to occasionally mOderately organic and moderately soft to slightly firm often with carbonaceous partings grading to carbonaceous shale. · U EPOCH 14 · UNOCALe Red #1 Tuffaceous claystone (2170' to 2220') = medium gray to medium light gray; moderately soft and hydrophilic; clayey to slightly silty texture; locally sandy with occasional interbedded fine to medium grained sandstone; often with slight coal and carbonaceous fines with possible occasional thin coal stringers and minor carbonaceous shale; noncalcareous. Tuffaceous claystone (2220' to 2320') = medium gray to medium light gray, some with faint brownish hue; moderately soft and hydrophilic; clayey to often slightly silty texture; locally sandy with occasional interbedded fine to medium grained sandstone; some with slight coal and carbonaceous fines with possible occasional thin coal stringers and minor carbonaceous shale; noncalcareous. Tuffaceous shale (2280' to 2310') = medium dark gray, to some medium light gray occasionally with brownish hue; very firm to moderately firm; grainy texture due to calcite and minor sand, to some earthy texture; very to moderately calcareous grading calcite. Tuffaceous claystone (2320' to 2380') = medium light gray to medium gray, rare with brownish hue to occasionally brownish gray; moderately soft and hydrophilic; clayey to slightly silty texture; very slight disseminated carbonaceous silts and fines; very slight scattered specs of grayish yellow clay matter, rarely calcareous; rare slightly organic to trace carbonaceous shale and possible thin coal streaks; overall non calcareous. · Coal (2380' to 2480') = brownish black to black to dusky brown; slightly firm to very firm; flaky to hackly, to some dense and slightly brittle; lignite to streaks subbituminous; occurs as thin beds and lamina in tuffaceous to carbonaceous claystone. Tuffaceous claystone (2380' to 2500') = medium gray to medium light gray, some with brownish hue, to occasionally light brownish gray to rare grayish brown; locally very light gray ash fall tuff; moderately soft and hydrophilic to occasionally slightly firm; smooth to silty texture; locally with slight floating fine to medium sand grains to possible thinly bedded sand; very slight carbonaceous silts and fines, to locally variably organic with some carbonaceous partings and grading carbonaceous shale. Sand/conglomeratic sand (2490' to 2620') = medium gray to medium light gray; fine to coarse lower, especially medium to fine upper, and slightly scattered very coarse and fragments; subangular to subrounded; moderate to moderately high sphericity; occurs as loose grains in sample to rare floating grains in clay; estimate poorly to moderately sorted with variable ashy clay matrix; 40% clear to opaque quartz, and 60% very dark gray to some dark grayish brown to rare green grains including silicates, mostly mafics, some chert, minor coal and carbonaceous grains; estimate some possible fair to good porosity. · Tuffaceous claystone/siltstone (2500' to 2650') = medium gray to some light brownish gray to occasionally grayish brown; moderately soft to slightly firm; hydrophilic, to moderately hydrophilic with increase in organics; mostly very slight carbonaceous g EPOCH 15 · · · UNOCALe Red #1 silts and fines increasing in organic claystone grading to carbonaceous shale; some thinly bedded to thinly laminated coal. Sand/conglomeratic sand (2650' to 2710') = medium gray to medium light gray; fine to coarse lower, especially medium to fine, and scattered very coarse and trace pebble; angular to subrounded, especially subangular; estimate grain and matrix supported and poorly to moderately sorted; unconsolidated in sample; 50-60% quartz, and 50-40% dark gray to black to dark grayish brown to rare green grains, mostly silicates including mafics and some chert, and minor coal and carbonaceous lithics; estimate some fair to good porosity. Tuffaceous claystone (2740' to 2800') = medium light gray to medium gray, occasionally with brownish hue to brownish gray; moderately soft and hydrophilic, to occasionally slightly firm when slightly organic; clayey to siltylfine sandy texture; some grading siltstone to minor sandstone; mostly very slight carbonaceous fines to rare grading carbonaceous shale with thinly bedded coal; non calcareous. Coal (2888' to 2888') = black to brownish black to dusky brown; very firm to slightly firm; dense and slightly brittle with angular to irregular platy to hackly fracture, to flaky fracture with organic clay partings; thin beds and laminations of lignite grading carbonaceous shale, to some bedded zones grading to subbituminous. Tuffaceous claystone (2800' to 2980') = medium light gray to medium gray, some with brownish hue, to some brownish gray to grayish brown; occasionally light gray grading to ash fall tuff; moderately soft to slightly firm; occasionally firm to very firm and calcareous; clayey to earthy to silty texture; often slightly to moderately organic clay; often slight coal and carbonaceous silts, fines, flakes, and micro parings, increasing grading to carbonaceous shale; overall non calcareous. Sand/conglomeratic sand (2890' to 2960') = medium gray; fine to very coarse, especially medium, and slightly scattered medium; subangular to subrounded; high to moderate sphericity; unconsolidated in sample; estimate moderately to poorly sorted and mostly grain supported in ashy clay; 50% quartz, and 50% dark gray to black to minor green grains including silicates (mafics and chert), and minor lithics; estimate some fair to good porosity and permeability. Coal (2980' to 3010') = black to brownish black; very firm to some slightly firm; dense with hackly to angular to platy fracture with some visible lamina; to flaky and crumbly with increasing organic clay; interbedded in carbonaceous shale and organic to tuffaceous claystone; lignite to subbituminous. Tuffaceous claystone (2980' to 3100') = medium light gray, some with faint brownish hue to occasionally light brownish gray, to some light gray grading to ash fall tuff; moderately soft and hydrophilic; clayey to moderately silty texture; often with very slight carbonaceous silts, fines, flakes and partings, locally increasing associated with variably organic claystone and carbonaceous shale. g EPOCH 16 UNOCAut Red #1 · TUffaceous claystone (3100' to 3160') = medium light gray, some with faint brownish hue to occasionally light brownish gray, to rare light gray grading to ash fall tuff; moderately soft and hydrophilic; clayey to some silty texture; often with very slight carbonaceous silts, fines, flakes, and partings, occasionally increasing associated with variably organic claystone and minor carbonaceous shale and coal. Tuffaceous claystone (3160' to 3220') = medium light gray to medium gray, occasionally with brownish hue to brownish gray; moderately soft and hydrophilic; smooth clayey to some silty texture; slight loose fine to medium sand grains; very slight fines and flakes to trace partings of carbonaceous matter; some slightly organic to rare carbonaceous shale and interbedded coal; non calcareous. Tuffaceous claystone (3220' to 3280') = medium light gray to medium gray, occasionally with brownish hue to brownish gray; moderately soft and hydrophilic; smooth clayey to some silty / fine sandy texture; occasionally grading siltstone to very fine sandstone; mostly trace to very slight fines, flakes, and partings of carbonaceous matter; locally organic grading to carbonaceous shale with increase in partings and associated with thinly bedded coal. · Tuffaceous claystone (3280' to 3340') = medium light gray to medium gray, some with slight brownish hue to brownish gray; moderately soft and hydrophilic; clayey to some silty / very fine sandy texture; occasionally grading siltstone to very fine sandstone; mostly trace to very slight fines, flakes, and partings of carbonaceous matter; locally organic grading to carbonaceous shale with increase in partings and associated with thinly bedded coal. Tuffaceous siltstone (3350' to 3430') = medium gray; very poor induration; lumpy to clumpy; clustered to clotted; gelatin slight mushy; amorphous fracture; subnodular to amorphous habit; moderate earthy luster; silty to clayey some colloidal texture; very hydrophilic; composed of 70% silt, 30% clay, carb fragments and various lithic fragments; some rare tuffaceous shale; gradational silts and clays with scattered interbedded sands. Tuffaceous claystone (3450' to 3490') = medium light gray; very soft; lumpy to clumpy; clustered to clotted; gelatin; mushy in parts; amorphous fracture and habit; dull to moderate earthy luster; clayey to colloidal texture; massive gradational beds of silt and clay; composed of 50% clay, 50% silt, carbonaceous fragments and various lithic fragments; minor thin coal and carbonaceous shale sections. Carbonaceous shale/coal (3500'to 3520') = black to brownish black; firm to brittle earthy some resinous luster; matte to smooth texture; planar fracture along shale partings; composed of very carb shale with some grading to sub lignite. · g EPOCH 17 UNOCALe Red #1 · Sand (3560' to 3580') = medium gray; clast size ranges from coarse lower to fine upper; sub round; moderate to well developed sphericity; moderate to poor sorting; impacted texture; immature nature; non to very slight silic cement; dominant matrix supported; abundant clay matrix fills and support; abundant dark gray to gray meta to quartz grains; appears as a sub greywacke; possible graded beds; poor porosity and poor permeability; no oil Tuffaceous claystone (3580' to 3640') = medium light gray; very soft; very hydrophilic; lumpy to clumpy; clustered to clotted; amorphous fracture; amorphous to sub nodular habit; moderate earthy luster; clayey to colloidal texture; massive beds of homogeneous clay; composed of 90% clay 10% silt, carbonaceous fragments and various lithic fragment and detrital material; scattered thin coals and carb shale beds. Carbonaceous shale/coal (3650' to 3700') = black to brownish black; firm; resinous to earthy luster in shale's; matte text; sub planar fracture along shale partings and irregular fracture in coals; composed of sub lignitic to very carbonaceous shale; very slight visible bleeding gas in sample cuttings; occurs as thin beds. · Tuffaceous claystone (3710' to 3790') = medium gray; very soft; lumpy to clumpy; clustered to clotted; gelatinous with some mushy to pasty; amorphous fracture; amorphous to sub nodular habit; moderate earthy luster; clayey to silty with most colloidal texture; composed of 80% clay, 20% silt, carbonaceous fragments and various detrital material; thin coal bed and carbonaceous shale have scattered. Carbonaceous shale/coal (3760' to 3820') = black to brownish black; brittle to firm resinous to earthy luster; matte to smooth texture; planar fracture along shale partings to irregular fracture in coal sections; composed of very carb shale grading to sub lignitic coal; occurs as thin beds; slight visible bleeding gas from coal cuttings. Tuffaceous claystone (3800' to 3850') = medium gray; very soft; lumpy to clumpy; clustered to clotted; gelatinous with some mushy to pasty; amorphous fracture; amorphous to sub nodular habit; moderate earthy luster; clayey to colloidal text: composed of 80% clay, 20% silt, carb fragments and various detrital material. Carbonaceous shale/coal (3850' to 3880') = black mottled brownish black in parts; brittle to firm; resinous to earthy luster; matte to smooth texture; planar fracture along shale partings to irregular fracture in coal sections; composed of very carbonaceous shale to lignitic coal; visible bleeding gas. · Tuffaceous claystone (3890' to 3940') = light gray to medium light gray; lumpy to clumpy; clustered to clotted; gelatin; mushy to pasty; some tacky; amorphous fracture; amorphous to sub nodular habit; moderate earthy luster; clayey to colloidal texture; massive beds of homogeneous clay composed of 80% clay, 20% silt, carbonaceous fragments and various detrital material. g EPOCH 18 · UNO £ALe Red #1 Tuffaceous claystone (3940' to 4000') = light gray to medium light gray; very soft; lumpy to clumpy; clustered to clotted; gelatinous; mushy to pasty; some tacky; amorphous fracture; sub nodular to amorphous habit; moderate earthy luster; clayey to colloidal text; massive beds of gradational clay and silt; composed of 70% clay, 30% silt, carbonaceous fragments and various detrital material; scattered thin coal beds and carbonaceous laminae. Carbonaceous shale (4050 to 4070') = brownish black some black; brittle to firm; dominant earthy luster with some resinous luster in parts; smooth to matte texture; blocky to irregular fracture; composed of predominantly very carbonaceous shale grading to sub lignitic coal; visible bleeding gas from coal cuttings. Tuffaceous siltstone (4070' to 4120') = medium light gray some grading to light brownish gray; poor induration; lumpy to clumpy; clustered to clotted; gelatin mushy to pasty; hydrophilic; amorphous fracture and habit; moderate earthy luster; silty/clayey to colloidal text; massive beds of gradational silt, clay and very carbonaceous shale and sub lignitic coal. · Tuffaceous claystone (4130' to 4180') = medium gray; very soft to soft; slightly sectile in parts; slightly flexi; lumpy to clumpy; clustered to clotted; gelatin mushy to pasty; various consistencies; amorphous to sub earthy fracture; amorphous to sub nodular habit; moderate to dull earthy luster; silty to clayey some colloidal texture; massive gradational silts and clays; composed of equal parts; scattered loose sand <5% and carbonaceous fragments. Tuffaceous claystone (4180' to 4240') = medium gray; very soft to soft; slightly sectile; lumpy to clumpy; clustered to clotted; gelatinous; mushy to pasty; various consistency; amorphous fracture; amorphous to sub nodular habit; moderate to dull earthy luster; silty to clayey becoming colloidal texture; hydrophilic; massive beds of homogeneous clay; composed of 80% clay, 20% silt, carbon material and various detrital material; scattered carbonaceous laminae Tuffaceous claystone (4250' to 4300') = medium light gray to medium gray; very soft to soft; slightly sectile in parts; clustered to clotted; gelatinous; mushy to pasty; various consistencies; sub earthy to amorphous fracture; sub nodular to amorphous habit; moderate to dull earthy luster; clayey to colloidal texture; massive gradational beds of homogeneous clay composed of 70% clay, 30% silt, carbonaceous frags and detrital material. Sand (4330' to 4370') = medium gray to medium dark gray; clast size ranges fromcoarse lower to medium lower; sub round; moderate developed sphericity; moderate to poor sorting; impacted text; non to very slight silic cement; dominant clay structured matrix; loose scattered sand interbedded; composed of dark gray meta to quartz; appears as a sub greywacke; poor porosity and permeability; no oil indicators. · U EPOCH 19 UtlOCALe Red #1 · Carbonaceous shale/coal (4375' to 4395') = brownish black to black; brittle to firm Earthy luster in shale to resinous in coal laminae; matte to smooth texture; irregular fracture; composed of very carbonaceous shale and clay with thin beds of lignitic coal; visible bleeding gas in cuttings. Tuffaceous claystone (4400' to 4480') = medium light gray; very soft; lumpy to clumpy; clustered to clotted; gelatin; mushy to pasty; amorphous fracture; amorphous to sub nodular habit; very hydrophilic; moderate earthy luster; clayey to colloidal texture; scattered loose sand grains in clay matrix. Coal/carbonaceous shale (4510' to 4520') = black to brownish black; brittle to firm resinous in coal to earthy luster in shale's; matte to earthy texture; irregular fracture; composed of very carbonaceous shale to lignitic coal; visible bleeding gas from coal cuttings. Tuffaceous claystone (4530' to 4570') = medium gray; very soft to soft; lumpy to clumpy; clustered to clotted; gelatinous mushy to pasty; various consistency; amorphous fracture; amorphous to sub nodular habit; moderate earthy luster; clayey to colloidal texture; massive bed of homogeneous clays, very hydrophilic; composed of 90% clay, 10% silt, carbon fragments and various detrital material. · Tuffaceous claystone (4580' to 4615') = medium gray; very soft to soft; lumpy to clumpy; clustered to clotted; gelatinous mushy to pasty; various consistency; amorphous fracture; amorphous to sub nodular habit; earthy luster; clayey to colloidal texture; hydrophilic; composed of 80% clay, 20% silt, carb and various detrital material; scattered loose 10%sand interbedded. Coal (4645' to 4660') = black; firm; resinous luster; matte to smooth text; sub blocky fracture; composed of sub lignitic to sub bituminous coals with very carbonaceous shale's at contacts; visible bleeding gas from cuttings. Tuffaceous claystone (4660" to 4720") = dark gray to medium dark gray; firm; stiff; pdc bit grooved fracture and habit; dull earthy luster; clayey to smooth texture; gradational beds of carbonaceous clay, tuffaceous silt and tuffaceous clay; some visible bleeding gas from carbonaceous clay cuttings. Tuffaceous claystone (4720' to 4810') = dark gray to medium dark gray; some brownish black to grayish black in carbonaceous sections; firm; stiff; pdc bit grooved fracture and habit; dull earthy luster; clayey to smooth texture; homogeneous beds of tuffaceous clay grading to carbonaceous clay in parts; organic look to most fragments. · Tuffaceous siltstone (4720' to 4810") = medium gray; moderately firm to slightly firm; soluble and slightly hydrophilic; very clayey; silty to very fine sandy texture; slight disseminated silts and fines of carbonaceous matter giving slight salt and pepper appearance; interbedded to interlaminated with tuffaceous claystone. U EPOCH 20 . UNOCALJ. Red #1 Coal (4780 to 4905') = brownish black to black; firm to slightly firm; brittle to crumbly; hackly to platy to flaky fracture; common visible lamina to rare dense; thinly bedded to interlaminated in carbonaceous shale and variably organic claystone; lignite. Tuffaceous shale (4820' to 4875') = medium gray to medium dark gray; firm to very firm; slightly silty texture; sub platy fracture; slightly soluble overall; some slightly organic; mostly moderately calcareous to calcareous decreassing grading to claystone and siltstone. Tuffaceous claystone (4875' to 4990') = medium gray to some medium dark gray; slightly firm to firm; clayey to some variably siltyl very fine sandy texture; occasionally grading to siltstone and minor sandstone; very slight disseminated fines, flakes and micro laminations of carbonaceous matter with a slight increase in silty zones; locally with brownish hue to occasionally brownish gray with increase carbonaceous matter and grading to carbonaceous shale and with thin beds and laminations of coal; non to slightly calcareous. . Tuffaceous claystone (4990' to 5050') = medium gray to medium light gray to medium dark gray, some with slight brownish hue to occasionally brownish gray; slightly firm to firm; soluble to some slightly soluble; clayey to moderately siltyl very fine sandy texture occasionally grading to siltstone; very slight fines, flakes, mottling, and micro lams of carbonaceous matter, some included in organic claystone; occasionally grading to carbonaceous shale with rare thin beds and laminations of coal; non to some slightly calcareous; trace isolated micro pyrite throughout. Coal (5010' to 5140') = brownish black to black; firm to slightly firm; brittle and laminated to dense, to flaky and crumbly; some grading dusky brown carbonaceous shale; thinly bedded and laminated in carbonaceous shale and tuffaceous claystone. Tuffaceous claystone (5050' to 5170') = medium gray to medium dark gray to brownish gray to medium light gray; slightly firm to firm; soluble to some slightly soluble; clayey to some moderately silty to some earthy texture; occasionally grading siltstone; mostly slight flakes and very slight fines of carbonaceous matter; locally increasing carbonaceous matter commonly associated with variably organic claystone with thin beds and laminations of coal; non to slightly calcareous. Tuffaceous siltstone (5110' to 5290') = medium light gray; slightly firm to firm; very clayey; silt to very fine sand grains and scattered fine; grading to and thinly bedded in claystone; moderately soluble, to some slightly soluble and slightly calcareous; very light to slight carbonaceous fines and minor flakes and lamina. . Tuffaceous claystone (5170' to 5320') = medium gray to medium dark gray to brownish gray to medium light gray; lightly firm to very firm; soluble to some slightly soluble; clayey to some moderately silty to some earthy texture; occasionally grading siltstone; mostly slight flakes and very slight fines of carbonaceous matter; locally increasing carbonaceous matter commonly associated with variably organic claystone U EPOCH 21 · UNOCALIÞ Red #1 with thin beds and laminations of coal; some slightly to moderately calcareous grading shale. Tuffaceous claystone (5320' to 5410') = medium gray to some medium dark gray to brownish gray; slightly firm to firm; soluble, to occasional slightly soluble and slightly to moderately calcareous; clayey to moderately silty texture occasionally grading to siltstone; some slightly to moderately organic with earthy to slightly silty texture; very slight to sli fines, flakes, and clasts carbonaceous matter, to locally increase especially organic claystone and grading carbonaceous shale with thinly interbedded coal. Coal (5360' to 5430') = brownish black to black; firm to slightly firm; brittle to crumbly; laminated to some dense; often grading dusky brown carbonaceous shale with flakes and clasts of carbonaceous matter and coal; lignite; interbedded with carbonaceous shale and tuffaceous claystone. Tuffaceous siltstone (5380' to 5470') = medium light gray to occasionally brownish gray; slightly firm to firm; very clayey; silt to very fine sand grains and scattered fine; grading to and thinly bedded in claystone; moderately soluble, to some slightly soluble and rare slightly calcareous slight carbonaceous fines and minor flakes and lamina locally increasing with brownish gray. · Tuffaceous claystone (5480' to 5530') = medium dark gray to dark gray some grading to grayish black in carbonaceous sections; firm; stiff; pdc bit grooved fracture and habit; dull earthy luster; clayey - waxy texture; massive grading beds of carbonaceous clay and silt; minor laminae of very fine grain sand interbedded. Carbonaceous shale/coal (5535' to 5600') = black to grayish black; firm; earthy to resinous luster; matte to smooth text irregular to blocky texture; composed of very carbonaceous clay to lignitic coal; vis bleeding gas from coal cuttings. Sand (5610' to 5620') = medium light gray; clast size ranges from medium grading to silt; sub round; moderate to well developed sphericity; poor sorting; impacted texture; immature nature; non silic cement; slight calcareous; dominant silt packed matrix support; composed of 90% quartz, 10% chert and various lithic fragments; poor porosity and permeability; occurs as loose interbedded sand grains in silt matrix. Tuffaceous siltstone (5630' to 5680') = medium dark gray; moderate induration; stiff in parts; pdc bit grooved fracture and habit; dull earthy luster; silty to gritty texture; massive gradational beds of tuffaceous silt and clay. · Sand/sandstone (5680' to 5740') = medium gray; clast size ranges from medium upper to fine lower grading to silt at 5740'; sub round to rounded; moderate to well developed sphericity with some prolated; moderate sorting becoming poor after 5720'; impacted texture; sub mature to mature grading to immature at 5740'; slight to moderated calcareous cement; slight silt/clay structured matrix; loosely attached with dominant grain support grading to matrix support at 5720'; composed of 80% quartz, 20% chert, g EPOCH 22 · UNOCALe Red #1 argillite and various lithic fragments; fair porosity and grading to poor at 5720'; no oil indicators. Sand (5750' to 5830') = medium light gray; clast size ranges from medium lower to very fine lower; rounded; well developed sphericity; poor sorting; polished to pitted texture; sub mature; some mature in parts; non to slight calcareous cement; moderate silt and clay packed matrix; gradational with both grain and matrix support; composed of >90% quartz; fair overall porosity and permeability; no oil indicators. Tuffaceous siltstone (5840' to 5890') = medium dark gray; poor to moderate induration; crumbly to crunchy; slight cohesiveness to non adhesive; earthy fracture; patchy to sub blocky habit; dull earthy to greasy luster; silty to gritty texture; massive beds of uniform tuffaceous silt; composed of 70% friable silt, 30% clay, very fine grained sand and various detrital material. Carbonaceous shale/clay and coal (5900' to 5950') = black to grayish black; firm with some hard; resinous luster to earthy luster in carbonaceous shale and carbonaceous clay; matte to smooth texture; sub blocky fracture; composed of thin to thick beds of very carbonaceous shale and clay grading to sub lignitic coal at center mass; slight visible bleeding gas from coal cuttings. · Tuffaceous claystone (5960' to 6010') = medium dark gray; firm some becoming hard; stiff in parts; moderate cohesive to non adhesive; pdc bit grooved fracture and habit; dull earthy luster; clayey to silty texture; massive beds of gradational tuffaceous clay and silt; composed of 70% clay, 30% silt and fine carbonaceous material. Tuffaceous siltstone (6020' to 6040') = dark gray to medium dark gray; moderate induration; slight cohesiveness to non adhesiveness; earthy fracture; sub nodular to sub blocky fracture; dull earthy luster; silty to gritty texture; massive beds of gradational silt; composed of 70% friable silt, 30% tuffaceous clay and various detrital material. Coal/carbonaceous shale and clay (6050' to 6070') = black mottled brownish black; firm some stiff; earthy to resinous luster; matte to smooth texture; sub hackly fracture; composed of very carbonaceous shale and clay with lignitic coal at mass. Sandstone (6070' to 6130') = medium gray clast size ranges from medium upper to silt; sub round to rounded; moderate to well developed sphericity; poor sorting; polished texture; sub mature nature; non to very weak silic cement; non calc; both grain and matrix supported; moderate silt and clay packed matrix; composed of 90% quartz with minor chert meta and various lithic fragments; poor to fair porosity and permeability; no oil indicators. · Tuffaceous siltstone (6140' to 6180') = dark gray to medium dark gray; moderate induration; non cohesive to moderate adhesive; earthy fracture; sub nodular to sub blocky fracture; dull earthy luster; silty to gritty texture; massive beds of gradational silts and sands; composed of 70% friable silt, 30% clay and various detrital material. g EPOCH 23 UNOCAUÞ Red #1 · Tuffaceous siltstone (6190' to 6255') = dark gray to medium dark gray; moderate induration; stiff; moderate cohesiveness; non adhesive; earthy to pdc bit grooved fracture and habit; dull earthy luster; silty to clayey texture; massive beds of gradational silts and tuffaceous clay; composed of 50% silt, 40% clay, 10% very carbonaceous clay and other carbonaceous material. Tuffaceous siltstone (6260' to 6310') = light gray to light olive gray; poor to moderate induration; brittle in parts to stiff in others; slightly cohesive to no adhesive; earthy fracture; sub blocky to sub nodular habit; greasy to earthy luster; silty to ashy texture; gradational beds of tuffaceous silt; composed of 80% silt, 10% clay, 10% ash; appears very detrital ish. Sand (6310' to 6340') = yellowish gray; clast size ranges from coarse lower to medium lower; sub round to rounded; moderate to well developed sphericity; moderate sorting; polished and impacted texture; mature nature; non to very slight silic cement; non calcareous; moderate ash/silt matrix; dominant grain support with secondary matrix support in parts; composed of 90% quartz, 10% chert; fair porosity; no oil indicators. Coal (6360 to 6410') = brownish black to black; very firm to slightly firm; dense and brittle with some visible lamina and angular to hackly fracture, to some sub platy to flaky fracture along laminations; subbituminous to lignite; thinly bedded in various lithologies. · Sand (6370' to 6400') = light gray to medium gray, some with slight brownish hue; fine to medium grains; sub rounded to subangular; high to some moderate sphericity; grain and matrix supported in clay matrix; rare calcareous cement; 80% quartz, and 20% chert and lithics; estimate fair porosity; no oil indicators. Tuffaceous claystone (6405' to 6460') = medium gray to medium light gray, often with slight brownish hue to occasionally brownish gray; slightly firm to moderately firm; soluble to moderately soluble; smooth to earthy to silty to very fine sandy texture; often slightly organic to occasionally organic clays; very slight carbonaceous silts, fines, and minor flakes and micro lams, locally increasing grading carbonaceous shale with minor interbedded coal; some Slightly to moderately calcareous especially grading to siltstone and sandstone. Tuffaceous siltstone/sandstone (6460' to 6620') = medium gray to medium light gray to light brownish gray; slightly firm to moderately firm; silt to fine grains; subangular; poorly sorted and mostly matrix supported in ashy, often slightly organic matrix; mostly quartz grains, some coal and carbonaceous silts, fines, and micro lenses, and minor other lithics; estimate very poor to some poor porosity; no oil indicators. · g EPOCH 24 · · · UNOCALe Red #1 Tuffaceous claystone/carbonaceous shale (6520' to 6790') = medium gray to grayish brown to brownish gray; slightly firm to moderately firm; soluble to moderately soluble; clayey to earthy to silty/very fine sandy texture; variably organic, often with slight silts of carbonaceous matter; grading to and interbedded with siltstone, sandstone, and coal; non to locally slightly calcareous. Sandstone (6640' to 6680') = light gray to medium light gray; very fine to coarse lower, especially very fine to medium lower; angular to subrounded; matrix supported in clay and calcite matrix, with streaks grain supported; grading to ash fall tuff; poorly sorted; 80% quartz, and 20% black to dark brown to trace green, including coal clasts, mafics, and other lithics; common dark grayish streaks from carbonaceous matter; possible poor to fair streaky discontinuous porosity. Sandstone (6730' to 6790') = medium light gray some with light brownish hue; fine to very fine and scattered medium; subrounded; moderately high sphericity; moderately to poorly sorted and mostly grain supported in ashy overall slightly calcareous silty clay matrix; 80% quartz, and 20% coal fines and other lithics; massive to grading sandy claystone and siltstone, and occasional interlaminated to thinly bedded coal; estimate poor to streaks fair porosity; no oil indicators. Tuffaceous claystone (6790' to 6880') = medium light gray to medium gray to brownish gray; slightly firm to firm; soluble to moderately soluble; clayey to earthy to slightly silty texture; mostly slightly organic, to grading grayish brown to dusky brown carbonaceous shale; very slight carbonaceous silts overall to micro lams of carbonaceous matter in carbonaceous shale; occasionally grading clayey siltstone to very fine sandstone; trace coal; non calcareous. Coal (6880' to 6910') = black to grayish black to brownish black; slightly firm to very firm; crumbly, to dense and brittle; hackly to flaky to angular fracture; mostly lignite to streaks sub bituminous; grading to dusky brown carbonaceous shale. Tuffaceous claystone (6880' to 6970') = medium gray to medium light gray, some with brownish hue, to brownish gray to dusky brown; slightly firm to moderately firm and soluble, to occasionally very firm and variably calcareous; clayey to earthy to silty texture; occasionally grading to siltstone; locally grading to very fine to fine grained clayey sandstone, commonly with shard-like grains grading ash fall tuff Sandstone (6970' to 7000') = medium light gray to light gray, some with light brownish hue; very fine to fine grains; subrounded to subangular; high to moderate sphericity; poorly to moderately sorted; grain and matrix supported in ashy clay; mostly quartz with disseminated carbonaceous fines and minor other lithics; trace coal laminae; estimate poor porosity. U EPOCH 25 · UNOCALe Red #1 Ash fall tuff (7015' to 7030') = off white to very light gray and moderately soft and soluble with clay texture and dull porcelain luster, to streaks translucent and firm and non to slightly soluble with greasy luster. Tuffaceous claystone/siltstone (7030' to 7150') = medium gray to brownish gray to grayish brown to medium light gray; slightly firm to moderately firm; soluble to moderately soluble; clayey to silty to earthy texture; variably tuffaceous to variably organic; often grading dusky brown carbonaceous shale; with streaks and laminations low grade lignite especially associated with carbonaceous shale; non calcareous. Carbonaceous shale/coal (7090' to 7150') = dusky brown to brownish gray shale; earthy to clayey to slightly silty; soluble to moderately soluble; moderately to very organic clay, commonly with flaky carbonaceous partings and grading to and with streaks and thin beds of brownish black to black lignite. Sandstone (7150' to 7180') = medium light gray to medium gray, some with light brownish hue; very fine to fine grains; angular to subrounded; poorly to moderately sorted; grain and matrix supported in ashy clay matrix occasionally grading to ash fall tuff and clayey siltstone; 80% quartz, and 20% mostly black to brownish black to minor tan and green, including carbonaceous fines and minor other lithics; estimate poor to occasional streaks fair discontinuous permeability; no oil indicators. · Tuffaceous claystone (7170' to 7300') = medium gray to light brownish gray to medium light gray to brownish gray; slightly firm to firm; moderately soluble to soluble; earthy to clayey to silty texture; mostly slightly to occasionally moderately organic especially non to slightly silty; occasionally grading carbonaceous shale with flaky fracture due remnant carbonaceous partings, and locally micro lams to minor thin beds lignite; some slightly to occasionally moderately calcareous grading to silty/sandy ash fall tuff. Tuffaceous claystone (7300' to 7360') = medium gray to light brownish gray to medium light gray to brownish gray; slightly firm to firm; moderately soluble to soluble; earthy to clayey to silty texture; often slightly to occasionally moderately organic; occasionally grading dusky brown carbonaceous shale; often grading tuffaceous siltstone and very fine to fine grained sandstone. Tuffaceous siltstone (7370' to 7480') = various colors transcending depth; light brownish gray to medium gray; olive gray to brownish black in carbonaceous sections to medium gray in ashy sections overall firm becoming soft in ashy sections; moderate cohesiveness to non adhesive; irregular to pdc bit grooved fracture and habit; dull earthy luster; clayey to silty texture; some carbonaceous laminae thinly layered throughout; composed of gradational tuffaceous silt, clay and very carbonaceous shale. · g EPOCH 26 UNOCALe Red #1 . Coal/carbonaceous shale (7470' to 7510') black to brownish black; firm; resinous to earthy luster; smooth to matte texture; sub blocky to irregular fracture composed of lignitic coal grading to very carbonaceous shale and clay at contacts; visible bleeding gas from coal cuttings. Tuffaceous claystone (7520' to 7540') = dark gray to medium gray with some brownish gray in parts; firm to stiff; moderate cohesive to non adhesive; irregular to pdc bit grooved fracture and habit; dull earthy luster; clayey to silty texture; composed of uniform tuffaceous siltstone composed of 80% silt, 20% clay, carbonaceous fragments and various detrital material. Sand (7550' to 7630') = light gray to pinkish gray; clast size ranges from medium upper to very fine grading to silt; sub round to rounded; moderate to well developed sphericity; moderate to poor sorting; polish to pitted texture; sub mature nature; non to very weak silic cement; non calcareous; moderate silt/ash structured matrix loosely attached; both grain and matrix support; composed of >90% quartz, 10% chert and various lithic fragments; fair porosity; fair to poor permeability; some coarse grain grains scattered becoming slightly coarser with depth. . Tuffaceous siltstone (7640' to 7670') = medium light gray to light brownish gray moderate to well indurated in parts; crumbly to crunchy; stiff overall; moderate to well cohesive; non adhesive; earthy fracture; sub nodular habit; greasy to earthy luster; silty to gritty texture; massive beds of homogeneous silt; some minor sandstone beds; composed of 80% silt, 20% very fine grained sand, very carbonaceous fragments, clay and various detrital material. Coal (7685' to 7700') = black; firm with some hard fragments; resinous luster; matte to smooth texture; hackly to blocky fracture; composed of lignitic coal with no visible bleeding gas from cuttings. Tuffaceous claystone (7730' to 7780') = brownish gray; firm; stiff; moderate cohesiveness; non adhesive; blocky to pdc bit grooved fracture and habit; dull earthy luster; smooth texture; massive homogeneous beds of tuffaceous clay; composed of 80% clay, 20% silt with various detrital material. Tuffaceous siltstone (7790' to 7840') = medium dark gray to medium gray with some becoming light gray at 7840' with increased ash content; moderate induration; stiff; moderate cohesiveness non adhesive; earthy to pdc bit grooved fracture and habit; dull earthy luster; silty to clayey texture; gradational bed of silt, very fine grain sand and ash. . Carbonaceous shale/clay/coal (7850' to 7880') = black grading to brownish black to brownish gray; soft to firm; slightly cohesive to non adhesive; earthy fracture; sub nodular habit; dull earthy luster; ashy/clay to silty texture; gradational beds of very carbonaceous clay and shale with thin beds of sub lignitic coal; no visible bleeding gas; grading to tuffaceous siltstone and interbedded with fine grain sand most grading to silt. U EPOCH 27 UNOCALe Red #1 · Coal (7945' to 7960') = black; firm with some becoming hard; resinous to some earthy lusters; matte to smooth texture; irregular to hackly ground-up fracture; composed of lignitic to sub bituminous coal; slight visible bleeding gas from the coal cuttings. Tuffaceous siltstone (7960' to 7990') = medium gray to light brownish gray; poor to moderate induration; crumbly to crunchy; slightly cohesive to non adhesive; earthy to pdc bit grooved fracture; sub nodular to pdc bit grooved habit; dull earthy to greasy luster; ash to silt texture; massive beds of uniform beds of tuffaceous silt; composed of 80% friable silt, 10% ash, 10% clay and various detrital material. Coal (7990' to 8020') = black; firm; resinous some earthy luster in carbonaceous shale; matte to smooth texture; irregular to hackly fracture; composed of lignitic to sub bituminous coal; slight visible bleeding gas in cuttings. Tuffaceous siltstone (8030' to 8080') = light brownish gray; poor to moderate induration; crumbly to crunchy; slightly cohesive; non adhesive; earthy to pdc bit grooved fracture; sub nodular to pdc bit grooved habit; dull earthy to greasy luster; ashy to silty texture; massive gradational beds to tuffaceous silt; composed of 80% friable silt, 20% ash, clay and various carbonaceous material. · Coal (8090' to 8115') = black; firm some hard; resinous luster; matte to smooth texture; sub conchoidal to hackly fracture; composed of bituminous coal; visible bleeding gas from cuttings. Tuffaceous siltstone (8120' to 8170') = light brownish gray; poor to moderate induration; crumbly to crunchy; earthy fracture; sub nodular habit; greasy to earthy luster's; silty to ashy texture; becoming slight carbonaceous after 8150' massive bedding of gradational tuffaceous siltstone; composed of 80% friable silt and 20% clay, ash and various carbonaceous detrital material. Coal/carbonaceous shale (8220' to 8230') black; firm with some harder; resinous to earthy luster's; matte to smooth texture; sub conchoidal to sub blocky fractures; composed of very carbonaceous shale/clay at contacts to lignitic to sub bituminous coal at mass; slight visible bleeding gas in cuttings; cuttings are pdc ground up. Tuffaceous siltstone (8240' to 8290') = light brownish gray; poor to moderate induration; crumbly to crunchy; earthy fracture; sub nodular habit; greasy to earthy luster; silty to ashy texture; massive gradational beds of thin sands, carbonaceous shale and coal with uniform tuffaceous siltstone composed of 80% friable silt, 20% ash, clay and various detrital material. · g EPOCH 28 UNOCAUÞ Red #1 · Sand (8305' to 8320') = light brownish gray to medium gray; clast size ranges from fine upper to silt; sub round to rounded; moderate to well developed sphericity; poor sorting; polished to pitted texture; immature nature; no visible cement; dominant silt packed matrix; sand appears as interbedded; composed of 90% quartz, 10% chert, meta, and various lithic fragments; poor porosity and permeability; no oil indicators = oil base mud. Coal (8335' to 8440') = black to brownish black; slightly firm to very firm; crumbly with visible lamina and slightly soluble due to organic clay content, to some dense with polished to vitreous luster and angular fracture; lignite grading carbonaceous shale to some thin beds subbituminous. Tuffaceous claystone/carbonaceous shale (8330' to 8440') = medium gray to light brownish gray to grayish brown to dusky brown; firm to slightly firm; moderately soluble to soluble; clayey to earthy to occasionally silty texture; variably organic; often slightly to some moderately calcareous, especially grading tuffaceous siltstone and ash fall tuff; trace disseminated mica; locally interbedded coal. · Sandstone (8350' to 8560') = light gray to medium light gray; very fine to medium lower; subangular to subrounded; moderate to high sphericity; poorly sorted and mostly matrix supported in ashy clay and calcite matrix; streaks grain supported; mostly poorly consolidated to streaks moderate to well consolidated in slightly calcareous to siliceous cement; grading silty/sandy ash fall tuff; 90% quartz, and 10% black to dark brown to trace green grains including carbonaceous matter and minor other lithics; estimate poor porosity; oil mud contamination. Carbonaceous shale/coal (8505' to 8590') = dusky brown to brownish gray shale; slightly firm to firm; clayey to earthy to slightly silty texture; soluble to moderately soluble; often slightly calcareous; often with finely disseminated carbonaceous matter and micro lams, grading to lignite with flaky partings along lamina, to thinly bedded platy to angular subbituminous coal. Tuffaceous claystone (8590' to 8680') = medium light gray to medium gray to light brownish gray; firm to slightly firm; soluble to moderately soluble; slightly calcareous to calcareous; variably organic to variably tuffaceous grading silty ash and siltstone, and occasional carbonaceous shale with minor coal lamina and possible thin beds. Coal (8645' to 8670') = brownish black to black; brittle to crumbly; dense to laminated; hackly to platy to flaky fracture; vitreous to resinous luster; lignite to subbituminous, massive to interlaminated in carbonaceous shale. · g EPOCH 29 UNOCALIÞ Red #1 . Sandstone/ash fall tuff (8680' to 8770') = medium light gray to light gray; very fine to fine and scattered medium grains; angular to subrounded; poorly sorted and mostly matrix supported in ashy clay and calcite; some streaks grain supported and moderately to well consolidated in slightly .calcareous to siliceous cement; 80% quartz, and 20% black to minor gray to green lithics including carbonaceous fines and clasts, and minor silicates; some weathering of silicates and carbonaceous matter becoming part of matrix; streaks poor to fair porosity mostly discontinuous. Sand/conglomeratic sand (8790' to 8830') = medium light gray to light gray; fine to coarse grains, and scattered very coarse to pebble fragments and grains; variably angular to rounded, subangular overall; moderate sphericity overall; mostly unconsolidated in sample, to some poorly consolidated and matrix and grain supported in ashy clay and slight calcite matrix; occasionally moderate to well consolidated in slight calcareous to slight siliceous cement; 80% quartz, and 30% black to gray to green to red carbonaceous clasts and silicates; slight dark gray streaks do reworking of carbonaceous clasts, minor alteration of silicates; estimate some fair porosity and permeability. . Tuffaceous siltstone (8840' to 8920') = dark gray to brownish gray; moderate induration; stiff; moderate cohesive to non adhesive; pdc bit grooved fracture and habit; dull earthy luster; silty to clayey texture; decreasing ash content with depth; massive beds of gradational tuffaceous silt, clay and various carbonaceous material. Coal (8940' to 8955') = black; firm; resinous luster; matte to smooth texture blocky to hackly fracture; composed of bituminous coal; no visible bleeding gas from cuttings. Sand (8955' to 8995') = light brownish gray to medium light gray; clast size ranges from medium lower to silt; sub round to rounded; moderate to well developed sphericity; poor sorting; pitted to polished texture; immature nature; non visible cement; non calc; dominant silt packed structured matrix; dominant matrix support; composed of 90% quartz, 10% chert and various lithic. Tuffaceous siltstone (9000' to 9040') = brownish gray to medium dark gray; moderate induration; stiff in parts; moderate cohesive to non adhesive; pdc grooved to earthy fracture and habit; dull earthy luster; silty to clayey text grading to very carbonaceous clay with thin laminae of coal grading to coal; composed of 70% silt, 30% clay, ash and very carbonaceous detrital material. Tuffaceous siltstone (9050' to 9100') = brownish gray to light brownish gray; poor induration; brittle; crumbly to mushy; increase in ash content; very poor cohesive to very slight adhesive; earthy to pdc grooved bit fracture and habit; dull earthy to greasy luster; silty to ashy texture; massive beds of gradational silt interbedded with ash and minor ash laminae; becoming softer and mushy with depth. . U EPOCH 30 . UHOUL. Red #1 Tuffaceous siltstone (9100' to 9160') = brownish gray; very poorly indurated; brittle; mushy to pasty in part; very slight cohesive; non adhesive; earthy to pdc bit grooved fracture and habit; dull earthy to greasy luster; silty to ashy texture; massive gradational beds of tuffaceous ashy siltstone becoming carbonaceous in part. Sand/sandstone (9190' to 9220') = light gray to light brownish gray; clast size ranges from medium lower to fine lower; sub round to rounded; moderate to well developed sphericity; moderate sorting becoming poor with depth; pitted texture immature nature; non to very slight silic cement; non calcareous; moderate to dominant silt/ash structured matrix; dominant matrix support with secondary grain support in faster drill rates; composed of 90% quartz, 10% chert, meta and various lithic fragments; fair to poor porosity and permeability; no oil. Conglomerate sand (9230' to 9300') = light gray; clast size ranges from very coarse to fine grained; sub angular to sub round; moderate to well developed sphericity; poor sorting with no large faction; chip to pitted to polished texture; sub mature nature; non to very slight siliceous cement; non calcareous; slight silt/ash structured matrix; dominant grain support; composed of 90% quartz, 10% chert and various lithic fragments; fair to good porosity and permeability; no oil indicators. . Tuffaceous claystone (9300' to 9400') = medium gray to medium light gray to light brownish gray; slightly firm to firm; soluble; slightly to moderately silty; often variably organic grading brownish gray to dusky brown carbonaceous shale; trace micro lams of carbonaceous matter to locally laminated to thinly bedded coal; some sandy grading matrix supported sandstone and ash; slightly calcareous overall. Conglomeratic sand (9400' to 9420') = medium gray to medium light gray; fine to very coarse grains and fragments, and scattered coarse fragments and minor pebble; subangular to angular, to some subrounded to rounded especially coarser fraction; variable sphericity; poorly sorted and mostly matrix supported in ashy clay and slight calcite matrix; occasional calcareous cement; some quartz fragments from siliceous streaks in altered ash; 80% quartz, and 20% black to green to gray to red including silicates (chert in part); some interlaminated to thinly interbedded coal; estimate poor porosity. Tuffaceous claystone (9420' to 9520') = medium gray to medium light gray, often with brownish hue to occasionally light brownish gray; slightly firm to firm; slightly to moderately silty texture; often slightly to occasionally moderately organic with locally interbedded carbonaceous shale and coal; some sandy grading matrix supported sandstone; slightly to moderately calcareous grading mudstone. . Tuffaceous claystone (9520' to 9580') = medium gray to light brownish gray; slightly firm to firm; soluble; slightly to moderately silty/fine sandy texture; some slightly to moderately organic occasionally grading to carbonaceous shale with interbedded coal; mostly slightly calcareous. g EPOCH 31 . . . UNOCALe Red #1 Coal (9540' to 9610') = black to brownish black to dusky brown; firm and brittle with hackly to angular fracture and polished to vitreous luster, to flaky to crumbly with increasing organic clay content; lignite to some sub bituminous, massive to grading carbonaceous shale. Tuffaceous siltstone (9620' to 9670') = brownish gray; poor some moderate induration; brittle; crumbly; mushy; some stiff; very slight cohesiveness; non adhesive; pdc bit grooved fracture and habit; dull earthy to streaky luster ashy to silty texture; micro laminae of carbonaceous clay throughout section; overall organic appearance; composed of 70% silt, 30% clay, ash and carbonaceous detrital material. Coal (9680' to 9700') = black; firm; resinous luster; matte to smooth texture hackly fracture; composed of very carbonaceous shale at contacts to bituminous coal at mass; abundant visible bleeding gas from cuttings. Tuffaceous siltstone (9710' to 9760') = brownish gray to light brownish gray; poor some with moderate induration; brittle to semi stiff; crumbly to crunchy; slight cohesiveness to non adhesive; pdc bit grooved to earthy fracture and habit; dull earthy to greasy luster; silty texture; massive beds of homogeneous tuffaceous siltstone composed of 70% silt, 30% ash, clay and various detrital material; carbonaceous in parts; coal laminae. Coal (9765' to 9800') = black; firm; resinous luster; matte to smooth texture hackly with some tabular fractures; composed of bituminous coal with very carbonaceous shale at contacts; slight visible bleedings gas from cuttings. Ash (9835 to 9900') = white mottled medium light gray; very soft; greasy to earthy luster; ashy to silty texture; composed of altered and redeposited waxy to greasy devitrified ash; expansive and interbedded with tuffaceous siltstone; composed of 60% ash, 40% silt and various detrital material. Tuffaceous siltstone (9850' to 9910') = medium light gray mottled light brownish gray; poor to moderate induration; crumbly to crunchy; slimy; stiff in parts; slight to moderate cohesive; non to slight adhesive; pdc bit grooved fracture and habit; greasy to earthy luster; ashy to silty texture; massive beds of gradational and interbedded silt and ash; composed of 60 silt, 40% ash; reworked and redeposited; minor coal beds scattered. Sand/sandstone (9920' to 9945') = very light gray; clast size ranges from medium upper to very fine lower; round to sub round; well developed sphericity; poor sorting; pitted to polished texture immature nature; no visible cement; non calcareous; dominant ash structured matrix; dominant matrix support; compose of >90% quartz; poor porosity and permeability; occurs mostly as interbeds in very fine to fine grain size (ashy). g EPOCH 32 · · · UNOCALIÞ Red #1 Tuffaceous siltstone (9950' to 10030') = brownish gray; moderate induration; crumbly to crunchy; stiff in parts; moderate cohesive; non adhesive; pdc bit grooved fracture and habit; dull earthy luster; silty and ashy texture; streaky appearance with carbon laminae to very thin coals; massive beds of gradational silt composed of 80% silt, 20% ash and clay. Sandstone/ash fall tuff (10030' to 10130') = medium light gray; medium to very fine grains throughout overall coarsening downward to include scattered coarse to trace very coarse and fragments in lower sands; subangular to angular; some loose grains, but mostly matrix supported in silty ashy clay and spotty calcite matrix; greasy to earthy luster with faint streaks and lamina of carbonaceous matter; 80% quartz, and 20% coal, and minor green, trace red, and other lithics mostly silicates; gradational to silty ash fall tuff and tuffaceous claystone, some interbedded zones increasingly organic grading to carbonaceous shale and minor interbedded coal; very poor porosity. Coal/carbonaceous shale (10030' to 10220") = grayish black to black to brownish black; very firm to slightly firm; lignite with angular to platy fracture and common visible lamina, to crunchy to crumbly with increase organic clay content grading carbonaceous shale; coal occurs as thin beds and laminations in carbonaceous shale and some tuffaceous claystone and ash. Ash fall tuff/sandstone (10120" to 10270') medium light gray to pale yellow brown; medium to fine grains and scattered coarse grains throughout with increasing coarse fraction and scattered coarse to very coarse fragments below 10210'; angular to sub angular; overall moderate sphericity; matrix and grain supported and poorly consolidated in ashy clay and slight overall calcite cements; to some grain supported and moderately well consolidated in slight siliceous cement; 80% quartz, and 20% black to minor gray to green to trace pink grains including coal and silicates; coal and carbonaceous reworked occurring as clasts and streaks, and minor clay alteration of silicates; poor visible porosity due clay and calcite infill and angular grain Contacts. Coal (10300' to 10340') = black to occasionally brownish black; very firm and brittle with hackly to angular fracture; resinous to vitreous luster; massive subbituminous to lignite; locally grading to dusky brown carbonaceous shale. Sandstone/ash fall tuff (10340" to 10370") = medium light gray to pale yellow brown; very fine to coarse lower, especially fine to medium; subangular overall; moderate to high sphericity; matrix and grain supported and poorly consolidated in ashy clay and slight calcite matrix; some moderate to well consolidated and grain supported in slight siliceous to slight calcareous cement; composition similar to above sandstone; poor visible porosity. U EPOCH 33 UNOCALIÞ Red #1 · Tuffaceous claystone (10370' to 10480') = medium gray to medium light gray to brownish gray; slightly firm to moderately firm; soluble; earthy to silty to locally sandy texture; variably organic locally grading to carbonaceous shale with interbedded coal; locally grading matrix supported sandstone and ash fall tuff. Tuffaceous siltstone (10485' to 10510') medium gray mottled light gray' poor to moderate induration; brittle to stiff in parts; crumbly to crunchy; slight to moderate cohesiveness to non adhesive; pdc bit grooved fracture and habit; moderate earthy luster; silty to gritty texture; becoming interbedded with very fine to fine grain sand; composed of 70% silt, 20% vf-fgr sd, 10% ash. Coal/carbonaceous clay (10525 to 10540') = black to brownish black in carbonaceous clay; firm; earthy to resinous luster; matte to smooth texture; sub conchoidal to hackly fracture; no visible bleeding gas from cuttings; occurs as thin beds. · Conglomerate sand (10560' to 106001) = very light gray; clast in two factions: very coarse to coarse and medium to fine sub angular bit impacted coarse to sub round to rounded medium to fine matrix sands; poor to well developed sphericity poor sorting; chip to pitted to polish texture; sub mature nature; non to very slight silic cement; non calcareous; slight to moderate silt/ash matrix; dominant grain support; composed of 90% quartz, 10% chert and various lithic fragments; poor porosity and permeability; no oil indicators; most interbedded with silt and ash and scattered sub vitric tuff. Sand (106151 to 106701) = very light gray; clast size: medium upper to fine lower; moderate to well developed sphericity; some prolated, triaxial; moderate sorting; chip to polish to pit texture; sub mature; non to weak siliceous cement; moderate ash / silt matrix; both grain and matrix supported; composed of >90% quartz; fair to poor porosity and permeability; mostly interbedded grains; no oil indicators. Sand (10730' to 107601) = light gray; clast size range: coarse lower to fine lower; trace very coarse; sub round to rounded; moderate to well developed sphericity; moderate sorting; polish to pitted some chip texture; sub mature nature; non to very weak silic cement; non calcareous; slight silt/ash matrix loosely attached; dominant grain support; composed of >90% quartz, fair porosity and permeability; some becoming matrix support @ 10760' Tuffaceous siltstone (10770' to 10840') = light olive gray mottled light gray; very poor induration; very poor cohesiveness; non to very slight adhesiveness; pdc bit grooved fracture and habit; greasy to earthy luster; ashy to silty texture; some interbedded loose sands; composed of 70% silt, 30% ash, clay; very fine grained sand and various detrital material. · U EPOCH 34 UROCAL. Red #1 · Devitried ash (10850' to 10890') = white mottled medium light gray; poor to moderate induration; ashy to silty text; greasy to earthy luster; composed of 50% ash, 50% silt and various detrital material; slightly expansive in ashier sections; reworked and redeposited with some loose interbedded sand. Coal/carbonaceous shale (10890 to 10930) = black becoming brownish black to grayish brown in carbonaceous shale; firm; resinous coal to earthy shale; matte to smooth texture; sub hackly to granular fracture; composed of very carbonaceous clay/shale at contacts to ligniticlbituminous coal at mass; slight visible bleeding gas from coals. Tuffaceous siltstone (10940' to 10990') = pale yellowish brown (mottled); poor to moderate induration; resinous to greasy luster; ashy to waxy texture; composed of 50% silt, 50% devit ash and sub devit tuff; non to slightly calcareous; slight amount of loose sand; reworked and redeposited silt and ash; detritalish. · Sand (11005' to 11030') = light gray; clast size ranges from medium upper to silt; sub round; moderate sphericity; poor sorting; pitted texture; immature nature; non to very weak siliceous cement; dominant silVash structured matrix; loosely attached and pore filling; dominant matrix support with sand grading to matrix silts; composed of 90% quartz, 10% chert and various lithic fragments; poor porosity and permeability; no oil indicators. Coal/very carbonaceous shale (11030' to 11085') = black to brownish black; firm; resinous luster in coal to earthy luster in carbonaceous clay and shale; matte to smooth texture; sub hackly to granular fracture; composed of very carbonaceous shale and clay at contacts to lignitic to bituminous coal at mass; no visible bleeding gas from coal cuttings; occurs as thin beds. Tuffaceous siltstone (11090' to 11150') brownish gray mottled light gray to olive gray; poor to moderate induration; mushy to stiff; slight to moderate cohesive; non adhesive; pdc bit grooved fracture and habit; silty to ashy text; heavily reworked and redeposited ash blebs and silt framework; very detrital appearance. Sand (11155' to 11220') = medium light gray; clast size ranges from medium upper to silt; sub round; moderate to well developed sphericity; poor sorting; pitted texture; immature nature; non to very slight silic cement; dominant ash and silt matrix structure and support; sand heavily interbedded in ash; grading to matrix silt; poor porosity and permeability; no oil indicators. · Tuffaceous siltstone (12220' to 11260') = medium gray mottled light brownish gray moderate induration; slightly crumbly to crunchy; stiff; moderate cohesive; non adhesive; pdc bit grooved fracture and habit; dull earthy to greasy streaky luster; silty to gritty some abrasive texture; massive dense gradational beds of silt, very fine sand and ash; some very dense and tight (11225'). g EPOCH 35 · · · UNOCALe Red #1 Coal/carbonaceous clay (11280 to 11300') = black grading to dusky yellowish brown brittle to firm; resinous to earthy luster; granular to pdc bit fracture; composed of carbonaceous clay and coal at mass; no visible bleeding gas. Tuffaceous claystone (11300' to 11380') = medium gray to medium light gray to light brownish gray; slightly firm to firm; soluble and slightly hydrophilic; slightly to some moderately silty/ very fine to fine sandy; often slightly to some variably organic grading to grayish brown to dusky brown carbonaceous shale with thinly bedded coal; locally light gray and silty to sandy grading calcareous ash fall tuff and minor ashy matrix supported sandstone; non to slightly calcareous overall. Tuffaceous claystone (11380' to 11500') = medium gray to medium light gray with faint greenish hue and dark gray streaks from carbonaceous/coal matter; slightly firm and crumbly due to slightly grainy texture from silt, sand, and coal fines;soluble with slight silt to very fine sand residue; scattered fine to medium subangular quartz grains; slight to moderate silts, fines, and micro lams of coal/carbonaceous matter; slight overall calcareous debris/calcite. Carbonaceous shale (11380' to 11500') = grayish brown to dark brownish gray to dusky brown; moderately firm to firm; soluble to moderately soluble; clayey to slightly silty texture; occasionally grading to low grade lignite and with thin beds lignite included; interbedded with and grading to tuffaceous claystone. Tuffaceous claystone (11500' to 11600') = medium gray, to some medium light gray with dark gray streaks from carbonaceous matter and coal; slightly firm and crumbly from silt, sand, and coal fines to moderately firm and clayey texture; soluble with very slight to moderate silt to very fine sand residue; slight fine to medium lower sand grains, to streaks grading matrix supported ss; trace red and green spotty clay possibly from altered silicates; very slight calcareous/calcite matter; often slight silts, fines, micro lams, and locally banded carbonaceous matter/coal; rare thin beds of coal. Carbonaceous shale (11570' to 11650') = grayish brown to medium dark gray to dusky brown; moderately firm to firm; moderately soluble with very slight silt and sand residue overall; moderate to very organic grading low grade coal and with thinly interbedded lignite; non calcareous; gradational and interbedded with tuffaceous claystone. Tuffaceous siltstone (11650' to 11690') = brownish gray to medium gray and hues of both; poor to moderate induration; crunchy; slightly sectile in parts; mush to stiff; slight to moderate cohesive; non to slight adhesiveness; pdc bit grooved fracture and habit; dull earthy to greasy luster; silty to ashy texture; gradational beds of tuffaceous silt, clay and interbedded ash; detritalish. g EPOCH 36 UNOCALe Red #1 . Coal/carbonaceous clay and shale (11690' to 11730') = black to dark grayish brown in carbonaceous clays; soft in clay to firm some hard in coals; earthy clay luster to resinous in coal; smooth clay texture to matte in coal; pdc grooved bit clay/shale fracture to granular in coals; slight visible bleeding gas from resinous coals; overall grading from very carbonaceous clay and shale to bituminous and lignitic coal. Tuffaceous claystone (11740' to 11830') = brownish gray; brittle to soft some firm slightly cohesive to non adhesive; pdc bit grooved fracture and habit; dull earthy luster; smooth to clayey texture; massive homogeneous beds of uniform tuffaceous claystone; composed of 90% clay, 10% silt with micro laminae of very carbonaceous clay; thin to thick beds of carbonaceous clay and coal scattered. Coal/very carbonaceous shale (11840' to 11860') = black becoming grayish black at contacts; overall firm; resinous luster becoming earthy in carbonaceous shale; matte to smooth texture; hackly fracture; composed of bituminous to lignitic coal at mass; visible bleeding gas from cuttings. Note: Distinct color change in clays @ 11870' . Tuffaceous claystone (11870' to 11890') = light olive gray some greenish gray with scattered light brownish blebs; soft to firm; slight cohesive to non adhesive; pdc bit grooved fracture and habit; dull earthy luster; clay texture; distinct color change in clays; composed of 80%clay, 20% silt. Sandstone (11930' to 11940') = trace in sample; yellowish gray; medium to coarse grains; angular; moderately sorted; 50% quartz, and 50% dark gray to green to minor rust silicates; moderately well consolidated with slight calcareous cement; very poor visible porosity due angular grain contacts; interbedded in variably silty to fine sandy claystone. Tuffaceous claystone/siltstone (11890' to 12030') = olive gray to greenish gray to brownish gray to light greenish gray; colors gradational to interlaminated; moderately firm; soluble with very slight to moderate silt to very fine sand residue, and scattered very fine to medium lower grains; lenses and laminations grading siltstone and sandstone; spotty to streaks calcite; often very slight disseminated carbonaceous matter and micro lenses; brownish gray slightly to moderately organic especially common in upper clays associated with coal. Tuffaceous claystone (11900' to 12100') = light olive gray to olive gray; brittle to firm; some stiff; moderate cohesive; non adhesive; pdc bit grooved fracture and habit; dull earthy luster; smooth to waxy texture; thick to massive beds of homogeneous tuffaceous claystone; composed of 80% clay, 20% silt; some micro laminae of carbonaceous material. . ~ EPOCH 37 · · · UNOCAUÞ Red #1 Tuffaceous claystone (12110' to 12150') = olive gray; firm to brittle; stiff in larger cuttings; poor to moderate cohesiveness; non adhesive; pdc bit grooved to splintery fracture; granular to sub elongated habit; smooth to waxy texture; massive homogeneous beds of tuffaceous clay; composed of 80% clay, 20% silt, ash; very uniform. Tuffaceous claystone (12160' to 12250') = olive gray to light olive gray; waxy to granular texture; mostly malleable to crumbly with some firm streaks fragmenting in part to silt and sand; some flaky fracture and common light gray very thin flakes; moderately soluble and non to slightly hydrophilic with slight to occasionally moderate silt to fine sand residue; occasional medium to coarse grains and trace very coarse to pebble; occasional streaks grading to sandstone; very slight to occasional moderate carbonaceous silts, flakes, and clasts occurring as micro lenses to locally streaks and grading to carbonaceous shale. Tuffaceous claystone (12240' to 12300') = olive gray to light olive gray; waxy to granular texture; malleable and moderately soluble in part, to granular and slightly calcareous to slightly siliceous fragmenting in part to silt and sand to trace hard siliceous streaks angular conglomeratic grains; overall slight loose very fine to coarse sand; very slight to slight carbonaceous silts, micro lenses, flakes, and clasts, to locally very thinly bedded coal; non hydrophilic; slight to streaks moderate silt, sand, and carbonaceous residue after dissolving in water. Tuffaceous claystone (12310' to 12370') = olive gray grading in parts to brownish gray; brittle to soft; cuttings becoming small in size with depth and slower rop; earthy fracture; sub nodular to flaky to platy habit; some percussion chalking; earthy greasy luster; clayey to ashy texture; mushy in part; massive beds of homogeneous tuffaceous clay composed of 70% clay, 20% silt, 10% ash; micro laminae of coals scattered. Tuffaceous claystone (12370' to 12460') = olive gray; soft to slightly firm nodular cuttings, to slightly firm to firm and crumbly to brittle flaky to sub platy cuttings; partially siliceous fragmenting in part to angular flakes and grains, to slightly sandy with slightly scattered loose grains; overall slightly calcareous; slight to moderate carbonaceous silts, fines, and flakes and probable thinly laminated to thinly bedded coal. U EPOCH 38 UNOCAUÞ Red #1 . SURVEY INFORMATION Red #1 Measured TVD Inclination Azimuth E (-) W (+) N (+) S (-) Dog Leg . - Feet Feet Degrees Degrees Degrees/10 0 0 0 0 0 0 -1 50 50 0.1 291.12 -0.04 0.02 0.2 100 100 0.11 283.76 -0.13 0.04 0.03 150 150 0.07 163.51 -0.17 0.02 0.31 200 200 0.14 139.8 -0.12 -0.05 0.16 250 250 0.02 251.64 -0.09 -0.1 0.3 300 300 0.05 259.52 -0.12 -0.11 0.06 350 350 0.05 9.82 -0.13 -0.09 0.16 400 400 0.1 321.71 -0.16 -0.03 0.15 450 450 0.16 263.47 -0.25 -0.01 0.27 500 500 0.12 272.99 -0.38 -0.01 0.09 550 550 0.14 273.48 -0.49 -0.01 0.04 . 600 600 0.18 286.15 -0.63 0.02 0.11 650 650 0.17 274.46 -0.77 0.05 0.07 700 700 0.2 280.77 -0.93 0.07 0.07 750 750 0.15 282.04 -1.08 0.1 0.1 800 800 0.2 301.94 -1.22 0.16 0.16 850 850 0.25 297.16 -1.39 0.25 0.11 900 900 0.16 284.08 -1.56 0.32 0.2 950 950 0.21 266.71 -1.72 0.33 0.15 1000 1000 0.26 262.22 -1.92 0.31 0.11 1050 1050 0.28 264.94 -2.16 0.29 0.05 1100 1100 0.37 253.62 -2.43 0.23 0.22 1150 1149.99 0.43 244.52 -2.76 0.1 0.17 1200 1199.99 0.46 259.88 -3.12 -0.01 0.25 1250 1249.99 0.4 262.99 -3.49 -0.07 0.13 1300 1299.99 0.36 256.81 -3.82 -0.13 0.11 1350 1349.99 0.4 262.46 -4.15 -0.18 0.11 1400 1399.99 0.37 262.38 -4.48 -0.23 0.06 ~ 1450 1449',99 0.26 259.44 -4.75 -0.27 0.22 1500 1499.99 0.21 247.06 -4.95 -0.33 0,14 g EPOCH 39 UNOCALe Red #1 · SURVEY INFORMATION Red #1 Measured TVD Inclination Azimuth E (-) W (+) N (+) 5 (-) Dog Leg - Feet Feet Degrees Degrees Degrees/10 1550 1549.99 0.27 237.18 -5.13 -0.43 0.15 1600 1599.99 0.34 245.37 -5.36 -0.55 0.16 1650 1649.98 0.43 256.11 -5.68 -0.66 0.23 1700 1699.98 0.5 250.44 -6.07 -0.78 0.17 1741 1740.78 0.57 218.85 -6.36 -1 0.73 1806 1805.98 0.32 195.95 -6.62 -1.42 0.47 1900 1899.98 0.49 180.22 -6.69 -2.07 0.22 1995 1994.97 0.37 197.74 -6.78 -2.78 0.19 2184 2183.97 0.39 213.03 -7.33 -3.9 0.06 2373 2372.97 0.4 216.26 -8.07 -4.98 0.01 2562 2561.96 0.33 205.08 -8.69 -6 0.05 2751 2750.96 0.45 203.2 -9.21 -7.18 0.07 · 2940 2939.95 0.62 229.97 -10.29 -8.53 0.16 3130 3129.94 0.62 233.09 -11.9 -9.8 0.02 3319 3318.93 0.59 234.07 -13.5 -10.98 0.02 3508 3507.92 0.65 239.95 -15.21 -12.09 0.05 3697 3696.9 0.63 241.66 -17.06 -13.12 0.02 3887 3886.89 0.87 254.29 -19.37 -14.01 0.15 4076 4075.87 0.59 271.57 -21.72 -14.37 0.19 4265 4264.86 0.55 263.55 -23.61 -14.45 0.05 4454 4453.85 0.63 253.77 -25.52 -14.84 0.07 4562 4561.85 0.77 249.25 -26.77 -15.26 0.14 4642 4641.84 0.87 253.9 -27.86 -15.62 0.15 4736 4735.83 0.46 196.32 -28.65 -16.18 0.78 4831 4830.81 1.82 108.06 -27.32 -17.02 1.97 4926 4925.71 3.54 115.4 -23.24 -18.75 1.83 5021 5020.4 5.71 129.91 -16.96 -23.03 2.58 5115 5113.67 8.43 128 -7.95 -30.28 2.91 5210 5207.36 10.6 122.03 4.95 -39.2 2.5 · 5304 5299.3 13.38 120.15 21.68 -49.25 2.98 5399 5391.2 15.96 122.14 42.25 -61.72 2.77 g EPOCH 40 UNOCAUÞ Red #1 . SURVEY INFORMATION Red #1 Measured TVD Inclination Azimuth E (-) W (+) N (+) S (-) Dog Leg . - Feet Feet Degrees Degrees Degrees/10 5494 5482.08 17.92 123.87 65.44 -76.81 2.13 5583 5566.34 19.62 121.55 89.55 -92.26 2.09 5683 5659.93 21.61 120.21 119.77 -110.31 2.04 5777 5746.49 24.29 119.81 151.51 -128.64 2.86 5872 5832.31 26.5 122.43 186.35 -149.72 2.61 5967 5916.54 28.57 124.36 223 -173.91 2.38 6061 5999.63 27.18 124.69 259.21 -198.82 1.49 6155 6083.38 26.82 125.46 294.14 -223.34 0.54 6250 6167.81 27.77 125.88 329.52 -248.75 1.02 6345 6252.72 25.51 126.14 363.98 -273.79 2.38 6440 6338.37 25.76 126.18 397.16 -298.04 0.27 6534 6421.78 29.11 125.08 432.37 -323.25 3.6 . 6629 6505.01 28.55 123.52 470.21 -349.07 0.98 6723 6587.54 28.64 123.36 507.76 -373.86 0.13 6818 6670.76 29.02 122.5 546.21 -398.76 0.59 6913 6754.06 28.47 123.54 584.52 -423.65 0.78 7007 6837.03 27.59 123.58 621.33 -448.07 0.93 7102 6921.58 26.67 125.28 657.06 -472.55 1.27 7196 7005.62 26.56 125.29 691.43 -496.87 0.12 7291 7090.51 26.8 124.44 726.43 -521.25 0.47 7386 7175.71 25.69 124.9 760.99 -545.15 1.18 7480 7260.97 24.1 125.43 793.34 -567.94 1.71 7575 7347.8 23.76 125.19 824.79 -590.21 0.37 7669 7433.86 23.67 126.3 855.47 -612.29 0.49 7764 7521.18 22.73 126.56 885.58 -634.52 0.99 7859 7609.02 22.06 126.43 914.67 -656.05 0.71 7953 7696.36 21.33 127.03 942.52 -676.82 0.81 8048 7785.04 20.72 127.17 969.7 -697.38 0.64 8142 7873.21 19.84 128.46 995.44 -717.35 1.05 ~ 8237 7962.91 18.63 128.49 1019.94 -736.82 1.27 8332 8053.04 18.23 128.26 1043.48 -755.46 0.42 [:I EPOCH 41 UNOCALe Red #1 . SURVEY INFORMATION Red #1 Measured TVD Inclination Azimuth E (-) W (+) N (+) S (-) Dog Leg . - Feet Feet Degrees Degrees Degrees/10 8395 8112.81 18.58 127.27 1059.2 -767.65 0.74 8458 8172.61 18.13 126.92 1075.02 -779.61 0.74 8521 8232.52 17.9 127.32 1090.56 -791.37 0.41 8647 8351.81 19.65 124.09 1123.51 -814.98 1.62 8774 8471.71 18.85 123.53 1158.3 -838.29 0.65 8900 8591.05 18.58 122.35 1192.23 -860.27 0.37 9026 8711.27 16.22 124.01 1223.78 -880.86 1.92 9152 8831.48 18.64 126.98 1254.45 -902.81 2.04 9279 8951.62 19.21 127.24 1287.3 -927.67 0.46 9406 9071.74 18.68 124.01 1320.8 -951.69 0.93 9532 9190.91 19.22 123.36 1354.85 -974.38 0.46 9658 9310.61 17.17 121.88 1387.96 -995.61 1.67 . 9785 9432.31 16.03 121.45 1418.84 -1014.66 0.9 9911 9553.35 16.23 121.63 1448.67 -1032.97 0.17 10037 9675.24 13.08 119.32 1476.1 -1049.19 2.54 10164 9799.05 12.64 118.87 1500.81 -1062.94 0.36 10290 9922.13 12.06 118.08 1524.5 -1075.8 0.48 10416 10045.57 11.07 119.83 1546.61 -1088.01 0.84 10543 10170.37 10.31 119.05 1567.12 -1099.59 0.61 10669 10294.48 9.57 120.61 1585.99 -1110.4 0.62 10790 10413.78 9.67 120.59 1603.39 -1120.69 0.09 10885 10507.34 10.27 119.52 1617.63 -1128.93 0.65 10980 10600.81 10.31 119.39 1632.41 -1137.27 0.06 11075 10694.27 10.33 119.48 1647.23 -1145.64 0.02 11170 10787.66 10.81 119.13 1662.43 -1154.16 0.51 11265 10880.87 11.47 119.14 1678.46 -1163.1 0.7 11359 10973.03 11.26 119.69 1694.59 -1172.2 0.26 11454 11066.15 11.55 118.27 1711.03 -1181.29 0.43 11549 11159.18 11.84 118.46 1727.97 -1190.44 0.3 ~ 11644 11252.08 12.3 117.41 1745.51 -1199.74 0.53 11738 11343.87 12.61 116.36 1763.6 -1208.91 0.42 g EPOCH 42 · Measured Feet 11833 11928 12117 12212 12307 12391 · · UNOCAUÞ Red #1 SURVEY INFORMATION Red #1 TVD Inclination Azimuth E (-) W (+) N (+) S (-) Feet Degrees Degrees 11436.57 12.64 115.95 1782.23 -1218.06 11529.27 12.63 116.14 1800.9 -1227.18 11713.71 12.59 116.85 1837.84 -1245.59 11806.4 12.77 115.31 1856.57 -1254.76 11899.14 12.25 118.59 1874.91 -1264.07 11981.39 11.2 117.56 1889.97 -1272.11 g EPOCH Dog Leg Degrees/10 0.1 0.05 0.08 0.4 0.93 1.27 43 UROeAL. Red #1 DAILY MUD PROPERTIES Date FI Depth Den FV PV YP Gels API FiI Cake Solid NAPlWater Sand PH CI Ca Temp s 6/9/04 42 50' 8.7 36 3 3 1/2/2 20.0 1.0 0.5 0/97 0 8.0 29500 60 6/10/04 68 660' 9.1 56 14 23 9/12/14 8.4 2.0 3.6 0/94 0.75 8.5 29500 240 6/11/04 78 1800' 9.4 52 14 22 9/13/15 6.8 2.0 5.6 0/92 0.75 8.5 30500 320 6/12/04 1800' 9.4 52 16 20 8/12/14 7.0 2.0 5.6 0/92 0.25 8.5 30500 300 6/13/04 64 1800 9.0 41 12 16 6/819 9.2 2/0 2.6 0/95 0.10 8.0 29500 200 6/14/04 66 1800 8.90 46 14 19 617/8 7.2 2/0 2.5 0/95 0.10 9.5 30500 360 6/15/04 84 4615 9.10 43 13 18 6/15/19 7.2 2/0 3.5 0/94 0.25 8.5 30500 460 6/16/04 74 4615' 9.2 46 15 17 6/9/10 7.4 2/0 4.6 0/93 0.50 8.5 30000 380 6/17/04 4615' 9.5+ 15 28 8 5/12/15 0 0/3 13.6 75/10 0.10 0 0 2 0 6/18/04 62 4660' 8.9 10 45 13 7/12/15 0/3 7.4 81/11 0.10 4 6/19/04 72 5500' 9.2 75 38 10 6/14/16 0/3 7.5 82/10 0.10 6/20/04 87 8290' 9.3 74 42 12 5/12/14 0/3 8.7 79/11 0.10 6/21/04 90 8710 9.2 62 40 12 6/14/17 0/3 9.6 78/11 0.10 6/22/04 102 10062' 9.2 58 31 11 5/9/12 0/3 9.4 78/11 0.10 6/23/04 102 10765' 9.3 63 39 8 6/12/14 0/3 10.5 78/11 0.10 6/24/04 72 10767' 9.3 72 52 8 6/12/14 0/3 10.5 78/10 0.10 6/25/04 96 11263' 9.3 78 44 12 8/16/18 0/3 10.5 78/10 0.10 6/26/04 110 11887' 9.5 69 37 12 10/18/20 0/3 11.5 77/10 0.10 6/27/04 114 12167' 9.5 65 36 12 9/18/21 0/3 11.5 77/10 0.10 6/28/04 114 12396' 9.7 70 42 13 10/19/22 0/3 13.5 75/10 0.10 6/29/04 92 12458' 10.0 95 57 15 15/25/28 0/3 14.3 68/16 0.10 . ~ EP~CH 44 . UROeAL. Red #1 BIT RECORD Bit Grading I 0 D L B G 0 R N U U 0 E A T E N T L C A U H A E E L A R G E S R R T I E R 0 C I N N R R H 0 G C 0 0 A N S H P W W R A U S S R L L E D Bit Size Make Type SIN Jets Depth Depth Drilled Hours Ave Ave Ave Ave No. In Out FtlHr WOB RPM PSI 1 12.25 HTC M221A9 0.9 66' 1800' 1734 15.53 170 7.5 122 1131 0 1 W A X E TD T R 2rr 8.5 HYC DS70FNPV 21504 1800' 4615' 2815 15.81 224 3 95 1933 2 2 B A E - TD T 3 6.125 HC HCM505 7104732 5X12 4615' 10765' 6149 83.7 121 4.8 67 2649 3 8 R S X T TD 0 R 4 6.125 HC HCM406 7102176 3X16 10765' 12458' 1693 73.8 38.6 3.7 89 2729 2 8 R S X W TD 0 T . U EP~CH 45 . Unocal Alaska · RED #1 REPORT FOR Hauck/McAlister DATE Jun 9, 2004 TIME 24:02:00 CASING INFORMATION 17" @ 66' SURVEY DATA DAILY WELLSITE REPORT U EPOCH DEPTH 730.00 YESTERDAY 66.00 PRESENT OPERATION= Drilling surface hole. 24 Hour Footage 664 DEPTH INCLINATION AZIMUTH VERTICAL DEPTH none BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 12.25" HTC MX-C1 66 664 5.0 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 640.9 @ 184.00 13.1 @ 70.00 207.9 83.59163 ftIhr SURFACE TORQUE 7122 @ 730.00 678 @ 80.00 3171.6 7122.83545 amps WEIGHT ON BIT 25 @ 77.00 0 @ 353.00 6.5 16.21710 Klbs ROTARY RPM 144 @ 615.00 51 @ 80.00 120.1 126.52770 RPM PUMP PRESSURE 1117 @ 681.00 119 @ 68.00 962.9 1098.76160 psi DRILLING MUD REPORT DEPTH: 50' MW Fe 8.70 1/0 VIS SOL · MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL 36 0.50 PV SD 3 o YP 3 FL OIL 0 MBL 20.0 o Gels 1/2/2 8.0 CL- 29500 60 pH Ca+ CCI HIGH LOW AVERAGE 1 @ 435.00 0 @ 730.00 0.2 TRIP GAS= 0 @ 730.00 0 @ 730.00 0.0 WIPER GAS= CHROMATOGRAPHY(ppm) SURVEY= 187 @ 542.00 8 @ 89.00 37.8 CONNECTION GAS HIGH= 0 0 @ 730.00 0 @. 730.00 0.0 AVG= 0 0 @ 730.00 0 @ 730.00 0.0 CURRENT 0 0 @ 730.00 0 @ 730.00 0.0 CURRENT BACKGROUND/AVG 6 0 @ 730.00 0 @ 730.00 0.0 None LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 45% Conglomeratic Sand and Sand, 50% Shale and Siltstone, 5% Coal PRESENT LITHOLOGY 80% Sand, 20% Claystone. DAILY ACTIVITY SUMMARY Epoch logged on at 28' at 14:28 hours, drilling through conductor pipe, and drilled ahead to 730' at midnight. Epoch Personel On Board= 4 Daily Cost $2540 Report by: Brian O'Fallon · Unocal Alaska · AFE #162461 RED #1 REPORT FOR Hauck/McAlister DATE Jun 10, 2004 TIME 24:00:00 CASING INFORMATION 17" @ 66' SURVEY DATA DAILY WELLSITE REPORT DEPTH 1800.00 YESTERDAY 730.00 [:I EPOCH PRESENT OPERATION= Trip out to run casing 24 Hour Footage 1070 DEPTH NONE INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED 1 12.25" HTC MX-C1 TFA 0.9 26' 1800' 1774' 15.53 DRilLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 2023.8 @ 900.00 10.1 @ 1508.00 151.9 79.18755 ftIhr SURFACE TORQUE 7184 @ 1009.00 1048 @ 988.00 4096.8 5120.00830 amps WEIGHT ON BIT 20 @ 1550.00 0 @ 873.00 7.6 10.50397 Klbs ROTARY RPM 139 @ 798 83 @ 1685.00 125.2 122.54752 RPM PUMP PRESSURE 1387 @ 1286.00 1030 @ 800.00 1272.5 1322.99829 psi DRILLING MUD REPORT DEPTH: 1800 MW 9.4 VIS 52 PV 14 YP 22 Fl 6.8 Gels 9/13/15 Cl- 30500 FC 2/0 SOL 5.6 SD 0.75 Oil MBL 5.0 pH 8.5 Ca+ 320 eel · MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1 ) ETHANE(C-2) PROPANE(C·3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL HIGH lOW AVERAGE 28.3 0.0 TRIP GAS= 63@1800' WIPER GAS= SURVEY= CONNECTION GAS HIGH= 0 AVG= 0 CURRENT 0 CURRENT BACKGROUND/AVG 6/28 GAS DESCRIPTION 115 o @ 1726.00 0.5 @ 1064.00 @ 1800.00 0 @ 1800.00 CHROMATOGRAPHY(ppm) @ 1726.00 22 @ 731.00 @ 1800.00 0 @ 1800.00 @ 1800.00 0 @ 1800.00 @ 1800.00 0 @ 1800.00 @ 1800.00 0 @ 1800.00 NONE LITHOLOGY/REMARKS LITHOLOGY 45% Sand and Conglomeratic Sand, 50% Claystone and Siltstone, 5% Coal PRESENT LITHOLOGY 20% Sand, 80% Claystone and Siltstone DAILY ACTIVITY Drill surface hole from 730' to 1800', casing depth, and circulate bottoms up. Drop carbide, peak gas 68 units at 3864 strokes, SUMMARY and continue circulating and conditioning hole. Pump out of hole, tight, maximum 78 units of gas. Trip in washing and reaming 53 feet to bottom, no fill. Circulate and condition hole, 63 units of trip gas. Epoch Personel On Board= 4 Daily Cost $2540 Report by: Brian O'Fallon · 22001 o o o o 4977.8 0.0 0.0 0.0 0.0 Unocal Alaska · AFE #162461 RED #1 REPORT FOR Hauck/McAlister DATE Jun 11,2004 TIME 24:00:00 DAILY WELLSITE REPORT ~ EPOCH DEPTH 1800.00 YESTERDAY 1800.00 PRESENT OPERATION= Nipple Down Diverter CASING INFORMATION 95/8" @1800' 24 Hour Footage 0 SURVEY DATA BIT INFORMATION NO. SIZE 1 12.25 TYPE HTC MX-C1 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.4 VIS 52 Fe 2/0 SOL 5.6 · MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1 ) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY NA PRESENT LITHOLOGY NA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 1741' 0.57 degrees 218.85 1740.78' INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED TFA 0.9 26 1800 1774 15.53 Casing Depth HIGH LOW AVERAGE CURRENT AVG NA @ 1800.00 NA @ 1800.00 NA NA ftIhr NA @ 1800.00 NA @ 1800.00 NA NA amps NA @ 1800.00 NA @ 1800.00 NA NA Klbs NA @ 1800.00 NA @ 1800.00 NA NA RPM NA @ 1800.00 NA @ 1800.00 NA NA psi DEPTH: 1800 PV 16 YP 20 FL 7.0 Gels 8/12/14 CL- 30500 SD 0.25 OIL 0 MBL 5.0 pH 8.5 Ca+ 300 CCI HIGH LOW AVERAGE 20 @ 1800.00 2 @ 1800.00 NA @ 1800.00 NA @ 1800.00 CHROMATOGRAPHY(ppm) NA @ 1800.00 NA @ 1800.00 NA @ 1800.00 NA @ 1800.00 NA @ 1800.00 NA @ 1800.00 NA @ 1800.00 NA @ 1800.00 NA @ 1800.00 NA @ 1800.00 4 NA TRIP GAS= 20u@1800' WIPER GAS= NA SURVEY= NA CONNECTION GAS HIGH= NA AVG= NA CURRENT NA CURRENT BACKGROUND/AVG NA/4 NA NA NA NA NA NA LITHOLOGY/REMARKS GAS DESCRIPTION DAILY ACTIVITY SUMMARY Circulate and condition hole and drop carbide, peak 47 units at 3904 strokes. Trip out of hole, rig up and run 95/8" casing. Circulate and condition hole, 20 units of trip gas, cement casing, and bump and test plug. Run gyro survey, and nipple down diverter. Epoch Personel On Board= 4 Daily Cost $2540 Report by: Brian O'Fallon · Unocal Alaska · AFE #162461 RED #1 REPORT FOR Hauck/McAlister DATE Jun 12,2004 TIME 24:00:00 DAILY WELLSITE REPORT U EPOCH DEPTH 1800.00 YESTERDAY 1800.00 PRESENT OPERATlON= Nipple Up BOP CASING INFORMATION 95/8" @1800' 24 Hour Footage 0 SURVEY DATA BIT INFORMATION NO. SIZE 1 12.25 TYPE HTC MX-C1 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.2 VIS 47 PV FC 2/0 SOL 4.6 SD · MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY NA PRESENT LITHOLOGY NA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 1741' 0.57 degrees 218.85 1740.78' INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED TFA 0.9 26 1800 1774 15.53 Casing Depth HIGH LOW AVERAGE CURRENT AVG NA @ 1800.00 NA @ 1800.00 NA NA ftlhr NA @ 1800.00 NA @ 1800.00 NA NA amps NA @ 1800.00 NA @ 1800.00 NA NA Klbs NA @ 1800.00 NA @ 1800.00 NA NA RPM NA @ 1800.00 NA @ 1800.00 NA NA psi DEPTH: 1800 12 YP 17 FL 7.8 Gels 9/14/19 CL- 30000 0.50 OIL 0 MBL 5.0 pH 8.5 Ca+ 260 CCI HIGH LOW AVERAGE NA @ 1800.00 NA @ 1800.00 NA TRIP GAS= NA NA @ 1800.00 NA @ 1800.00 NA WIPER GAS= NA CHROMATOGRAPHY(ppm) SURVEY= NA NA @ 1800.00 NA @ 1800.00 NA CONNECTION GAS HIGH= NA NA @ 1800.00 NA @ 1800.00 NA AVG= NA NA @ 1800.00 NA @ 1800.00 NA CURRENT NA NA @ 1800.00 NA @ 1800.00 NA CURRENT BACKGROUND/AVG NAlNA NA @ 1800.00 NA @ 1800.00 NA NA LITHOLOGY/REMARKS GAS DESCRIPTION DAILY ACTIVITY SUMMARY Nipple down diverter and nipple up BOP. Epoch Personel On Board= 4 Daily Cost $2540 Report by: Brian O'Fallon · Unocal Alaska · AFE 162461 RED #1 REPORT FOR Hauck/McAlister DATE Jun 13, 2004 TIME 24:00:00 DAILY WELLSITE REPORT U EPOCH DEPTH 2047.00 YESTERDAY 1800.00 PRESENT OPERATION= Drilling 24 Hour Footage 247 CASING INFORMATION 95/8" @ 1800' DEPTH 1995' SURVEY DATA BIT INFORMATION NO. SIZE 2rr 81/2" TYPE HYC DS-70FNPV DRilLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRilLING MUD REPORT MW Fe 8.9 2/0 VIS SOL · MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL 46 PV 2.5 SD 27158 26 o o o INCLINATION 0.37 VERTICAL DEPTH 1994.97' AZIMUTH 197.74 INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED 21504 TFA 0.663 1800' 247' 1.26 HIGH LOW AVERAGE CURRENT AVG 667.9 @ 1826.00 39.6 @ 1981.00 243.6 145.72266 ftIhr 5120 @ 1800.00 423 @ 1859.00 2054.1 1518.18225 amps 10 @ 1800.00 0 @ 1954.00 2.2 3.09499 Klbs 122 @ 1800.00 22 @ 1859.00 76.4 78.19697 RPM 1674 @ 1827.00 949 @ 1821.00 1476.7 1456.78259 psi DEPTH: 1820 14 YP 19 Fl 7.2 Gels 6/7/8 CL- 30500 0.10 Oil 0 MBl 2.5 pH 9.5 Ca+ 360 CCI HIGH LOW AVERAGE 73.3 0.0 TRIP GAS= 11 U@1800' WIPER GAS= NA SURVEY= 0 CONNECTION GAS HIGH= 0 AVG= 0 CURRENT 0 CURRENT BACKGROUND/AVG 73/73 147 o @ 1837.00 1 @ 1818.00 @ 2047.00 0 @ 2047.00 CHROMA TOGRAPHY(ppm) @ 1836.00 235 @ 1818.00 @ 1926.00 0 @ 1821.00 @ 2047.00 0 @ 2047.00 @ 2047.00 0 @ 2047.00 @ 2047.00 0 @ 2047.00 12683.0 6.0 0.0 0.0 0.0 none LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 10% Sandstone, 40% Siltstone, 50% Claystone PRESENT LITHOLOGY 30% Siltstone, 70% Claystone DAILY ACTIVITY SUMMARY Finish nipple up and test BOP. Pick up drill pipe and stand in derrick. Pick up BHAand run in hole with singles. Drill cement and shoe, and formation from 1800' to 1820'. Displace well dumping old mud, and perform leak off test, 15.0 ppg EMW. Drill from 1820' to 2047'. Epoch Personel On Board= 4 Daily Cost $2540, cumulative: $27703.13 Report by: Brian O'Fallon · Unocal Alaska . AFE 162461 RED #1 REPORT FOR Hauck/McAlister DATE Jun 14, 2004 TIME 24:00:00 DAILY WELLSITE REPORT fJ EPOCH DEPTH 4615.00 YESTERDAY 2047.00 PRESENT OPERATION= Circulate and Condition 24 Hour Footage 2568 CASING INFORMATION 95/8"@ 1800' DEPTH 4562' SURVEY DATA BIT INFORMATION NO. SIZE 2 8 1/2" TYPE HYC DS-70FNPV DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.1 VIS 43 Fe 2/0 SOL 3.5 . MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL INCLINATION 0.77 AZIMUTH 249.25 VERTICAL DEPTH 4561.85' SIN 21504 INTERVAL IN OUT 1800 4615 CONDITION T/B/C REASON PULLED Casing Depth JETS TFA 0.663 FOOTAGE 2815 HOURS 15.81 HIGH LOW 607.2 @ 3897.00 9.9 @ 3969.00 9057 @ 4330.00 162 @ 4320.00 24 @ 4149.00 0 @ 4155.00 115 @ 4498.00 0 @ 4321.00 2725 @ 4526.00 1222 @ 2334.00 DEPTH: 4615' PV 13 YP 18 FL 7.2 Gels SD 0.25 OIL 0 MBL 5.0 pH AVERAGE 222.7 3234.7 3.0 96.6 1977.6 CURRENT AVG 160.99965 4116.87793 5.67566 96.63161 2382.39819 ftIhr amps Klbs RPM psi 6/15/19 8.5 CL- 30500 460 Ca+ eel HIGH LOW AVERAGE 144 @ 4513.00 1 @ 2547.00 89.9 TRIP GAS= NA 0 @ 4615.00 0 @ 4615.00 0.0 WIPER GAS= NA CHROMATOGRAPHY(ppm) SURVEY= 0 27940 @ 4513.00 303 @ 2547.00 16793.0 CONNECTION GAS HIGH= 0 92 @ 4072.00 0 @ 3821.00 19.4 A VG= 0 19 @ 4322.00 0 @ 4209.00 0.6 CURRENT 0 0 @ 4615.00 0 @ 4615.00 0.0 CURRENT BACKGROUND/AVG 35/90 0 @ 4615.00 0 @ 4615.00 0.0 NONE LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 15% Sand and Conglomeratic Sand, 5% Coal, 80% Claystone and Siltstone PRESENT LITHOLOGY 10% Sand, 90% Claystone DAILY ACTIVITY SUMMARY Drill from 2047' to 4615',7" casing depth, and circulate bottoms up. Drop carbide, and continue circulating and conditioning hole. Epoch Personel On Board= 4 Daily Cost $2540 cumulative; $30243.13 Report by: Brian O'Fallon . Unocal Alaska . AFE 162461 RED #1 REPORT FOR Marty Monnin DATE Jun 15, 2004 TIME 24:00:00 DAILY WELLSITE REPORT g EPOCH DEPTH 4615.00 YESTERDAY 4615.00 CASING INFORMATION 95/8" @ 1800' 24 Hour Footage 0 SURVEY DATA BIT INFORMATION NO. SIZE 2 81/2" TYPE HYC DS-70FNPV DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE PRESENT OPERATION= Begin cement job on 7" Csg. DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 4562' 0.77 249.25 4561.85' INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS TIBIC PULLED 21504 TFA 0.663 1800 4615 2815 15.81 Casing Depth HIGH LOW AVERAGE CURRENT AVG NA @ 4615.00 NA @ 4615.00 NA NA ftlhr NA @ 4615.00 NA @ 4615.00 NA NA amps NA @ 4615.00 NA @ 4615.00 NA NA Klbs NA @ 4615.00 NA @ 4615.00 NA NA RPM NA @ 4615.00 NA @ 4615.00 NA NA psi DEPTH: 4615 DRILLING MUD REPORT MW 9.2 VIS 46 PV Fe 2/0 SOL 4.6 SD . MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY NA PRESENT LITHOLOGY NA 15 0.50 YP 17 OIL 0 HIGH LOW FL MBL 7.4 5.0 Gels pH 6/9/10 8.5 CL- 30000 380 115 @ 4615.00 12 @ 4615.00 o @ 4615.00 0 @ 4615.00 CHROMA TOGRAPHY(ppm) NA @ 4615.00 NA @ 4615.00 NA @ 4615.00 NA @ 4615.00 NA @ 4615.00 NA @ 4615.00 NA @ 4615.00 NA @ 4615.00 NA @ 4615.00 NA @ 4615.00 NA LITHOLOGY/REMARKS Ca+ CCI AVERAGE 55 o TRIP GAS= 140u@4615' WIPER GAS= SURVEY= CONNECTION GAS HIGH= AVG= CURRENT CURRENT BACKGROUND/AVG 35/55 NA NA NA NA NA GAS DESCRIPTION DAILY ACTIVITY SUMMARY Finish circulating and conditioning and pull out of hole above ghost reamer to 3440', pulling tight at 3970', 3906', 3883', and 3845'. Circulate and pump dry job, maximum 60 units of gas. Pull out of hole and rig up and run e-Iogs, two runs as first tool run failed. Rig up and run 7" casing to bottom, and circulate and condition hole, maximum 140 units of gas, landing 7" hangar in wellhead. Rig up cement head. Epoch Personel On Board= 4 Daily Cost $2540 Report by: Brian O'Fallon . . UNOCAL ALASKA AFE 162461 RED #1 REPORT FOR Marty Monnin DATE Jun 16, 2004 TIME 24:00:00 DAILY WELLSITE REPORT U EPOCH PRESENT OPERATION Pick up BHA DEPTH 4615.00 YESTERDAY 4615.00 24 HOUR FOOTAGE 0 CASING INFORMATION 7" @ 4601' DEPTH SURVEY DATA 4562' BIT INFORMATION NO. SIZE TYPE 3 61/8" HC HCM505 . DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.55 VIS FC 0/3 SOL MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) DITCH GAS CUTTING GAS INCLINATION 0.77 VERTICAL DEPTH 4561.85' REASON PULLED FT/HR AMPS KLBS RPM PSI CL- 0 Ca+ 2 CCI HIGH LOW AVERAGE 73 @ 4615 25 @ 4615 49 TRIP GAS @ @ WIPER GAS CHROMATOGRAPHY (ppm) SURVEY NA @ NA @ CONNECTION GAS HIGH NA @ NA @ AVG NA @ NA @ CURRENT NA @ NA @ CURRENT BACKGROUND/AVG NA/49 NA @ NA @ NA LITHOLOGY/REMARKS GAS DESCRIPTION . EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 REPORT BY Brian O'Fallon AZIMUTH 249.25 INTERVAL CONDITION SIN JETS IN OUT FOOTAGE HOURS T/B/C 7104732 TFA 0.552 4615 0 0 HIGH LOW AVERAGE CURRENT AVG NA @ NA @ NA NA NA @ NA @ NA NA NA @ NA @ NA NA NA @ NA @ NA NA NA @ NA @ NA NA 150 13.6 DEPTH 4615' 28 YP 8 FL 0.0 Gels 0.10 OIL 75 MBL 0 pH 5/12/15 o PV SD METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY NA PRESENT LITHOLOGY 90% Claystone, 10% Sand DAILY ACTIVITY Pre-job safety for cement procedure, circulate and condition hole, maximum 73 units of gas, and cement 7" casing. SUMMARY Bump plug and test casing to 3000#. Change lower pipe rams to 4", nipple up and test BOP, while clean pits for oil base. Install drip pan under rig floor and pick up BHA while build oil mud in pits. · UNOCAL ALASKA AFE 162461 RED #1 REPORT FOR Marty Monnin DATE Jun 17,2004 TIME 24:00:00 DAILY WELLSITE REPORT U EPOCH PRESENT OPERATION Drilling Ahead. DEPTH 4829.00 YESTERDAY 4615.00 24 HOUR FOOTAGE 214 CASING INFORMATION 7" @ 4601' DEPTH SURVEY DATA 4831' BIT INFORMATION NO. SIZE TYPE 3 6 1/8" HC HCM505 · DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 8.9 VIS FC 0/3 SOL MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) DITCH GAS CUTTING GAS METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL TRIP GAS 19u@4615' WIPER GAS NA SURVEY 0 CONNECTION GAS HIGH 0 AVG 0 CURRENT 0 CURRENT BACKGROUND/AVG 40/67 INCLINATION 1.82 AZIMUTH 108.06 INTERVAL SIN JETS IN OUT FOOTAGE HOURS 7104732 TFA 0.552 4615 214 3.15 HIGH LOW AVERAGE 208.4 @ 4683.00 12.9 @ 4725.00 95.0 2396 @ 4781.00 163 @ 4827.00 1217.1 11 @ 4668.00 0 @ 4819.00 3.7 77 @ 4809.00 0 @ 4829.00 50.1 2410 @ 4795.00 992 @ 4616.00 2092.3 104 7.4 DEPTH 4660' 45 YP 13 FL 7.2 Gels 0.10 OIL 81 MBL pH PV SD 123 o HIGH LOW @ 4692.00 16 @ 4616.00 @ 4829.00 0 @ 4829.00 CHROMATOGRAPHY (ppm) @ 4692.00 2222 @ 4616.00 @ 4642.00 0 @ 4659.00 @ 4829.00 0 @ 4829.00 @ 4829.00 0 @ 4829.00 @ 4829.00 0 @ 4829.00 10226.6 1.1 0.0 0.0 0.0 AVERAGE 67.2 0.0 19600 11 o o o NONE LITHOLOGY/REMARKS VERTICAL DEPTH 4830.81' CONDITION T/B/C REASON PULLED CURRENT AVG 30.25841 163.73909 2.48736 0.78534 1989.33362 FT/HR AMPS KLBS RPM PSI 7/12/15 CL- Ca+ CCI GAS DESCRIPTION LITHOLOGY 60% Claystone, 20% Siltstone, 15% Carbonaceous Shale, 5% Coal PRESENT LITHOLOGY 80% Claystone, 10% Siltstone, 10% Carbonaceous Shale DAILY ACTIVITY SUMMARY Pick up and run in hole with BHA, and pick up and run in with singles down to 4534' tagging cement. Perform choke drill, cut drill line, and hold pre-job meeting before displacing water base with oil base. Begin drilling shoe track while displacing hole, and continue drilling to 4638', and perform Leak-off test, 13.3 ppg emw. Drill ahead from 4638' to 4829' EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 · REPORT BY Brian O'Fallon UNOCAL ALASKA · AFE 162461 RED #1 REPORT FOR Mrty Monnin DATE Jun 18, 2004 TIME 24:00:00 DAILY WELLSITE REPORT DEPTH 6437.00 YESTERDAY 4829.00 24 HOUR FOOTAGE 1608 CASING INFORMATION 7" @ 4601' DEPTH SURVEY DATA 6440' BIT INFORMATION NO. SIZE TYPE 3 61/8" HC HCM505 · DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.3 VIS FC 0/3 SOL MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) DITCH GAS CUTTING GAS METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL INCLINATION 25.76 AZIMUTH 126.18 ~ EPOCH PRESENT OPERATION Drilling ahead INTERVAL SIN JETS IN OUT FOOTAGE HOURS 7104732 TGA 0.552 4615 1822' 19.52 HIGH LOW AVERAGE 834.5 @ 6338.00 16.2 @ 5009.00 138.0 4367 @ 6200.00 133 @ 6433.00 1591.0 12 @ 6359.00 0 @ 5294.00 4.1 84 @ 6405.00 0 @ 5630.00 44.0 3156 @ 6202.00 1497 @ 5120.00 2370.0 73 7.4 DEPTH 6426 44 YP 11 0.1 OIL 89.1 FL 6.6 Gels MBL pH PV SD 182 o HIGH LOW @ 5984.00 2 @ 5133.00 @ 6437.00 0 @ 6437.00 CHROMATOGRAPHY (ppm) @ 6104.00 320 @ 5133.00 @ 6351.00 0 @ 5921.00 @ 6437.00 0 @ 6437.00 @ 6437.00 0 @ 6437.00 @ 6437.00 0 @ 6437.00 NONE LITHOLOGY/REMARKS VERTICAL DEPTH 6338.42' CONDITION T/B/C REASON PULLED CURRENT AVG 70.83984 1458.43396 1.18724 0.49058 2244.73218 FT/HR AMPS KLBS RPM PSI AVERAGE 110.4 0.0 33576 26 o o o 17001.1 5.2 0.0 0.0 0.0 7/15/17 CL- Ca+ CCI TRIP GAS WIPER GAS SURVEY CONNECTION GAS HIGH 4 AVG 2 CURRENT 0 CURRENT BACKGROUND/A VG 108/110 GAS DESCRIPTION LITHOLOGY 20% Sand and Sandstone, 5% Coal, 10% Carbonaceous Shale, 25% Siltstone, 40% Claystone PRESENT LITHOLOGY 20% Sand and Sandstone, 10% Carbonaceous Shale, 20% Siltstone, 50% Claystone DAILY ACTIVITY SUMMARY Drill, rotating and sliding, from 4829 to 6437'. EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 REPORT BY Brian O'Fallon · · UNOCAL ALASKA AFE 162461 RED #1 DAILY WELLSITE REPORT U EPOCH REPORT FOR Marty Monnin/ Jim Brown DATE Jun 20, 2004 TIME 24:00:00 DEPTH 9360.00 YESTERDAY 8413.00 PRESENT OPERATION Drilling ahead. 24 HOUR FOOTAGE 947 CASING INFORMATION 7" @ 4601' DEPTH SURVEY DATA 9152 BIT INFORMATION NO. SIZE TYPE 3 6 1/8" HC HCM505 · DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.3 VIS FC 0/3 SOL MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) DITCH GAS CUTTING GAS METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL TRIP GAS WIPER GAS SURVEY CONNECTION GAS HIGH 10 AVG 2 CURRENT 0 CURRENT BACKGROUND/AVG 106/118 INCLINATION 18.64 AZIMUTH 126.98 INTERVAL SIN JETS IN OUT FOOTAGE HOURS 7104732 TFA 0.552 4615 2745 HIGH LOW AVERAGE 236.3 @ 9253.00 8.0 @ 9089.00 92.8 5616 @ 9254.00 143 @ 8557.00 3419.8 13 @ 9288.00 0 @ 9302.00 4.0 83 @ 9301.00 0 @ 8554.00 63.8 3072 @ 9254.00 1797 @ 8793.00 2629.6 63 9.4 DEPTH 9350 43 YP 0.1 OIL 11 78/11 FL 6.4 Gels MBL pH VERTICAL DEPTH 8831.48 CONDITION T/B/C REASON PULLED PV SD 221 o HIGH LOW @ 8805.00 0 @ 8471.00 @ 9360.00 0 @ 9360.00 CHROMATOGRAPHY (ppm) @ 8805.00 50 @ 8471.00 @ 8805.00 1 @ 9027.00 @ 8805.00 0 @ 8742.00 @ 9360.00 0 @ 9360.00 @ 9360.00 0 @ 9360.00 21159.5 35.8 4.5 0.0 0.0 CURRENT AVG 101.17188 4296.83350 4.20692 77.51763 2762.96338 FT/HR AMPS KLBS RPM PSI AVERAGE 118.4 0.0 44710 137 24 o o 5/10/12 CL- Ca+ CCI 1 )8800-8820',Sand,221 u; 2)8981-8991 ',Sand, 156u; 3)9190-921 O',Sand, 176u; 4)9230-9300' ,Sand, 177u LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 30% Sand and Conglomeratic Sand, 30% Siltstone, 30% Claystone, 10% Coal PRESENT LITHOLOGY 20% Sandstone, 30% Siltstone, 40% Claystone, 10% Carbonaceous Shale DAILY ACTIVITY SUMMARY Drill ahead, picking up singles and drilling doubles, from 8413' to 9360'. EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 REPORT BY Brian O'Fallon · UNOCAL ALASKA AFE 162461 RED #1 DAILY WELLSITE REPORT U EPOCH · REPORT FOR Marty Monnin/Jim Brown DATE Jun 21,2004 TIME 24:00:00 DEPTH 10083.00 YESTERDAY 9360.00 PRESENT OPERATION Drilling ahead. 24 HOUR FOOTAGE 723 CASING INFORMATION 7" @ 4601' DEPTH SURVEY DATA 10164 INCLINATION 12.64 AZIMUTH 118.87 VERTICAL DEPTH 9799.10' BIT INFORMATION NO. SIZE TYPE 3 6 1/8" HC HCM505 INTERVAL SIN JETS IN OUT FOOTAGE HOURS 7104732 TFA 0.552 4615 5668 66.5 HIGH LOW AVERAGE 242.8 @ 9975.00 5.2 @ 9488.00 67.0 5006 @ 9773.00 143 @ 9379.00 3674.0 10 @ 9975.00 0 @ 9828.00 4.4 81 @ 9598.00 0 @ 9389.00 64.9 2928 @ 10059.00 1990 @ 9677.00 2622.8 CONDITION T/B/C REASON PULLED DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.20 VIS FC 0/3 SOL MWD SUMMARY INTERVAL TO TOOLS CURRENT AVG 48.49636 4560.60205 6.09231 75.45209 2801.93799 FT/HR AMPS KLBS RPM PSI DEPTH 10062 31 YP 11 FL 7.2 Gels 0.10 OIL 78 MBL pH 58 9.4 PV SD CL- 5/9/12 Ca+ CCI · GAS SUMMARY (units) DITCH GAS CUTTING GAS HIGH LOW @ 9688.00 46 @ 9833.00 @ 10083.00 0 @ 10083.00 CHROMATOGRAPHY (ppm) @ 9690.00 7278 @ 9762.00 @ 9869.00 12 @ 9762.00 @ 9991.00 0 @ 9761.00 @ 10083.00 0 @ 10083.00 @ 10083.00 0 @ 10083.00 AVERAGE 105.2 0.0 197 o TRIP GAS WIPER GAS SURVEY CONNECTION GAS HIGH 6 AVG 2 CURRENT 6 CURRENT BACKGROUND/AVG 91/105 METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL 37110 93 17 o o 18786.5 37.0 5.3 0.0 0.0 1 )9400-9420,Conglomeratic Sand, 168u, Poor visible porosity LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 20% Sandstone and Conglomerate, 10% Coal, 20% Siltstone, 40% Claystone, 10% Carbonaceous Shale PRESENT LITHOLOGY 40% Sandstone and Conglomeratic Sand, 10% Siltstone, 50% Claystone and Ash DAILY ACTIVITY SUMMARY Drill ahead, rotating and sliding, picking up singles and drilling doubles, from 9360' to 10083'. EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 REPORT BY Brian O'Fallon · UNOCAL ALASKA AFE 162461 RED #1 DAILY WELLSITE REPORT U EPOCH · REPORT FOR Marty Monnin/Jim Brown PRESENT OPERATION Circulate before Trip Out DEPTH 10765.00 YESTERDAY 10083.00 24 HOUR FOOTAGE 682 CASING INFORMATION 7" @ 4601' DEPTH SURVEY DATA 10669' DATE Jun 22, 2004 TIME 24:00:00 VERTICAL DEPTH 10294.48 INCLINATION 9.57 AZIMUTH 120.61 CONDITION T/B/C REASON PULLED BIT INFORMATION NO. SIZE TYPE 3 61/8" HC HCM505 INTERVAL SIN JETS IN OUT FOOTAGE HOURS 7104732 TFA 0.552 4615 10765 6150 83.7 HIGH LOW AVERAGE 260.2 @ 10207.00 4.5 @ 10751.00 59.2 5809 @ 10207.00 162 @ 10122.00 4583.3 9 @ 10276.00 0 @ 10247.00 4.0 83 @ 10354.00 0 @ 10122.00 76.3 2976 @ 10275.00 2077 @ 10562.00 2701.8 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.3 VIS FC 0/3 SOL MWD SUMMARY INTERVAL TO TOOLS CURRENT AVG 18.43872 4217.76123 2.38462 80.65256 2777.12695 FT/HR AMPS KLBS RPM PSI DEPTH 10765 39 YP 8 FL 5.2 Gels 0.10 OIL 78 MBL pH 6/12/14 CL- 63 10.5 PV SD Ca+ CCI · GAS SUMMARY (units) DITCH GAS CUTTING GAS HIGH LOW @ 10139.00 28 @ 10721.00 @ 10765.00 0 @ 10765.00 CHROMATOGRAPHY (ppm) @ 10137.00 4076 @ 10744.00 @ 10756.00 14 @ 10200.00 @ 10756.00 0 @ 10521.00 @ 10765.00 0 @ 10765.00 @ 10765.00 0 @ 10765.00 AVERAGE 70.7 0.0 TRIP GAS WIPER GAS SURVEY CONNECTION GAS HIGH 6 AVG 1 CURRENT 0 CURRENT BACKGROUND/AVG 45/70 153 o METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL 28920 295 41 o o 11964.6 72.5 11.9 0.0 0.0 10215-10227', Silt and Sand, 134u; 2)10360-10370',Sand,71u LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 20% Sand and Conglomeratic Sand, 10% Coal, 30% Siltstone, 40% Claystone and Ash PRESENT LITHOLOGY 50% Conglomeratic Sand, 20% Coal, 10% Carbonaceous Shale, 20% Siltstone DAILY ACTIVITY Drill ahead, rotating and some sliding, picking up singles and drilling doubles, from 10083' to 10765'. SUMMARY Circulate and condition hole before trip for bit. EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 REPORT BY Brian O'Fallon · · UNOCAL ALASKA AFE 162461 RED #1 DAILY WELLSITE REPORT U EPOCH REPORT FOR Marty Monnin/Jim Brown DATE Jun 23, 2004 TIME 24:00:00 DEPTH 10765.00 YESTERDAY 10765.00 PRESENT OPERATION Pick up BHA. 24 HOUR FOOTAGE 0 CASING INFORMATION 7" @ 4601' DEPTH SURVEY DATA 10669' BIT INFORMATION NO. SIZE TYPE 4 6 1/8" HC HCM406 · DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.3 VIS FC 0/3 SOL MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) DITCH GAS CUTTING GAS METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL INCLINATION 9.57 AZIMUTH 120.61 VERTICAL DEPTH 10294.48 INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7102176 TFA 0.589 10765 HIGH LOW AVERAGE CURRENT AVG NA @ @ FT/HR NA @ @ AMPS NA @ @ KLBS NA @ @ RPM NA @ @ PSI DEPTH 10765' 72 PV 52 YP 8 FL 5.0 Gels 6/12/14 CL- 10.5 SD 0.10 OIL 78 MBL pH Ca+ CCI HIGH LOW 30 @ 8@ NA @ @ CHROMATOGRAPHY (ppm) NA @ @ NA @ @ NA @ @ NA @ @ NA @ @ AVERAGE 15 TRIP GAS NA WIPER GAS NA SURVEY NA CONNECTION GAS HIGH NA AVG NA CURRENT NA CURRENT BACKGROUND/AVG NA/15 NA LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY NA PRESENT LITHOLOGY NA DAILY ACTIVITY Circulate and condition hole and trip out. Lay down BHA, and test BOPs. Pick up BHA and test logging tool, SUMMARY failed. Replace logging tool. EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 REPORT BY Brian O'Fallon · · UNOCAL ALASKA AFE 162461 RED #1 DAILY WELLSITE REPORT fI EPOCH REPORT FOR Shane Hauck/Jim Brown DATE Jun 24, 2004 TIME 24:00:00 DEPTH 11329.00 YESTERDAY 10765.00 PRESENT OPERATION Drilling ahead 24 HOUR FOOTAGE 564 CASING INFORMATION 7" @ 4601' DEPTH SURVEY DATA 11075' BIT INFORMATION NO. SIZE TYPE 4 61/8" HC HCM406 · DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.3 VIS 78 FC 0/3 SOL 10.5 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) DITCH GAS CUTTING GAS METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL INCLINATION 10.33 AZIMUTH 119.48 VERTICAL DEPTH 10694.33' INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7102176 TFA 0.589 10765 564 10.4 HIGH LOW AVERAGE CURRENT AVG 151.8 @ 11032.00 7.2 @ 11268.00 63.2 55.18466 FT/HR 5858 @ 11034.00 1478 @ 10893.00 5159.7 5051.14551 AMPS 6 @ 11223.00 0 @ 10768.00 3.1 3.12338 KLBS 93 @ 11047.00 23 @ 10893.00 88.5 89.02329 RPM 2954 @ 11327.00 1595 @ 11046.00 2760.7 2795.75000 PSI DEPTH 11263 PV 44 YP 12 FL 5.2 Gels 8/16/18 CL- SD 0.10 OIL 78/10 H2O MBL pH Ca+ CCI HIGH LOW 114 @ 10773.00 23 @ 11235.00 o @ 11329.00 0 @ 11329.00 CHROMATOGRAPHY (ppm) 10773.00 3574 @ 11108.00 10766.00 0 @ 11223.00 10766.00 0 @ 10961.00 11329.00 0 @ 11329.00 11329.00 0 @ 11329.00 NONE LITHOLOGY/REMARKS AVERAGE 57.6 0.0 TRIP GAS 166@10765' WIPER GAS SURVEY CONNECTION GAS HIGH 4 AVG 1 CURRENT 0 CURRENT BACKGROUND/AVG 33/58 21170 @ 170 @ 27 @ o @ o @ 8817.5 28.2 1.3 0.0 0.0 GAS DESCRIPTION LITHOLOGY 10% Sand and Sandstone, 10% Coal, 10% Carbonaceous Shale, 50% Siltstone, 20% Claystone and Ash PRESENT LITHOLOGY 75% Claystone and Ash, 5% Sandstone, 20% Carbonaceous Shale DAILY ACTIVITY SUMMARY Run in hole with BHA and 59 singles 4" DP. Trip in hole to 10666' and ream to bottom. Drill ahead, rotating, from 10765' to 11329'. EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 REPORT BY Brian O'Fallon · · UNOCAL ALASKA AFE 162461 RED #1 DAILYWELLSITE REPORT ~ EPOCH REPORT FOR Shane Hauck/Jim Brown DATE Jun 25, 2004 TIME 24:00:00 DEPTH 11903.00 YESTERDAY 11329.00 PRESENT OPERATION Drilling ahead. 24 HOUR FOOTAGE 574 CASING INFORMATION 7" @ 4601' DEPTH SURVEY DATA 11833' BIT INFORMATION NO. SIZE TYPE 4 61/8" HC HCM406 · DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.5 VIS 69 FC 0/3 SOL 11.5 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) DITCH GAS CUTTING GAS METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL INCLINATION 12.64 VERTICAL DEPTH 11436.62' AZIMUTH 115.95 INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7102176 TFA 0.589 10765 1138 HIGH LOW AVERAGE CURRENT AVG 118.0 @ 11349.00 5.3 @ 11899.00 36.4 15.66475 FT/HR 5747 @ 11713.00 3223 @ 11330.00 5231.9 5136.91406 AMPS 6 @ 11491.00 0 @ 11901.00 2.6 0.06582 KLBS 93 @ 11399.00 45 @ 11615.00 89.4 89.94981 RPM 2858 @ 11464.00 2198 @ 11804.00 2656.7 2640.52466 PSI DEPTH 11887 PV 37 YP 12 FL 5.0 Gels 10/18/20 CL- SD 0.10 OIL 77/10 H2O MBL pH Ca+ CCI 111 o HIGH LOW @ 11860.00 12 @ 11500.00 @ 11903.00 0 @ 11903.00 CHROMATOGRAPHY (ppm) @ 11860.00 823 @ 11864.00 @ 11781.00 0 @ 11679.00 @ 11781.00 0 @ 11665.00 @ 11903.00 0 @ 11903.00 @ 11903.00 0 @ 11903.00 NONE LITHOLOGY/REMARKS GAS DESCRIPTION AVERAGE 36.3 0.0 TRIP GAS WIPER GAS SURVEY CONNECTION GAS HIGH 60(uphole) AVG 40(uphole) CURRENT 60(uphole) CURRENT BACKGROUND/AVG 22/36 17946 254 50 o o 5799.1 37.5 8.3 0.0 0.0 LITHOLOGY 5% Sand, 10% Coal, 10% Carbonaceous Shale, 15% Siltstone, 60% Claystone PRESENT LITHOLOGY 70% Claystone, 20% Coal, 10% Carbonaceous Shale DAILY ACTIVITY SUMMARY Drill ahead from 11329' to 11903'. EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 REPORT BY Brian O'Fallon · · UNOCAL ALASKA AFE 162461 RED #1 DAILYWELLSITE REPORT U EPOCH REPORT FOR Shane Hauck/Jim Brown DATE Jun 26, 2004 TIME 24:00:00 DEPTH 12188.00 YESTERDAY 11903.00 PRESENT OPERATION Drilling Ahead. 24 HOUR FOOTAGE 285 CASING INFORMATION 7" @4106' DEPTH SURVEY DATA 12117' BIT INFORMATION NO. SIZE TYPE 4 61/8" HC HCM406 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.5 VIS 65 · FC 0/3 SOL 11.5 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) DITCH GAS 72 CUTTING GAS 0 METHANE (C-1) 12131 ETHANE (C-2) 254 PROPANE (C-3) 52 BUTANE (C-4) 14 PENTANE (C-5) 0 HYDROCARBON SHOWS INTERVAL INCLINATION 12.59 AZIMUTH 116.85 VERTICAL DEPTH 11713.76 INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PU LLED 7102176 TFA 0.589 10765 1423 48.8 HIGH LOW AVERAGE CURRENT AVG 72.8 @ 11935.00 1.4 @ 11993.00 18.4 20.01202 FT/HR 5572 @ 12042.00 2049 @ 12015.00 5040.8 5140.58838 AMPS 11 @ 12042.00 0 @ 11922.00 4.7 5.73953 KLBS 95 @ 12008.00 35 @ 12015.00 90.0 88.46706 RPM 3123 @ 12042.00 2185 @ 12015.00 2772.7 2746.06909 PSI DEPTH 12167 PV 36 YP 12 FL 4.6 Gels 9/18/21 CL- SD 0.10 OIL 77/10 H2O MBL pH Ca+ CCI HIGH LOW @ 11918.00 10 @ 12083.00 @ 12188.00 0 @ 12188.00 CHROMATOGRAPHY (ppm) @ 11918.00 1473 @ 12083.00 @ 12176.00 13 @ 11994.00 @ 12150.00 4 @ 12009.00 @ 12174.00 0 @ 12171.00 @ 12188.00 0 @ 12188.00 AVERAGE 30.7 0.0 TRIP GAS WIPER GAS SURVEY CONNECTION GAS HIGH 87(uphole) AVG 70(uphole) CURRENT 56(uphole) CURRENT BACKGROUND/AVG 40/31 4924.9 89.5 17.8 0.4 0.0 NONE LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 5% Sandstone, 25% Siltstone, 70% Claystone PRESENT LITHOLOGY 100% Claystone DAILY ACTIVITY SUMMARY Drill from 11903' to 12188'. EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 REPORT BY Brian O'Fallon · · UNOCAL ALASKA AFE 162461 RED #1 DAILY WELLSITE REPORT g EPOCH REPORT FOR Shane Hauck / Jim Brown DATE Jun 27, 2004 TIME 24:00:00 DEPTH 12415.00 YESTERDAY 12188.00 24 HOUR FOOTAGE 227 PRESENT OPERATION Drilling ahead. CASING INFORMATION 7" @ 4601' DEPTH SURVEY DATA 12307' INCLINATION 12.25 AZIMUTH 118.59 VERTICAL DEPTH 11899.19' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED 4 61/8" HC HCM406 7102176 TFA 0.589 10765 1650 66.7 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 35.7 @ 12273.00 5.0 @ 12352.00 14.2 5.39384 FT/HR SURFACE TORQUE 5544 @ 12337.00 3602 @ 12407.00 5142.3 5053.82324 AMPS WEIGHT ON BIT 10 @ 12319.00 1 @ 12297.00 6.2 10.08653 KLBS ROTARY RPM 91 @ 12405.00 52 @ 12278.00 89.0 90.43242 RPM PUMP PRESSURE 3006 @ 12234.00 1987 @ 12407.00 2806.9 2856.05957 PSI DRILLING MUD REPORT DEPTH 12396' MW 9.70 VIS 70 PV 42 YP 13 FL 4.6 Gels 10/19/22 CL- · FC 0/3 SOL 13.5 SD 0.10 OIL 75/10 H2O MBL pH Ca+ CCI MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) HIGH LOW AVERAGE DITCH GAS 91 @ 12404.00 24 @ 12349.00 45.5 TRIP GAS CUTTING GAS 0 @ 12415.00 0 @ 12415.00 0.0 WIPER GAS CHROMATOGRAPHY (ppm) SURVEY METHANE (C-1) 14117 @ 12404.00 3380 @ 12349.00 7236.1 CONNECTION GAS HIGH 114 ETHANE (C-2) 393 @ 12404.00 75 @ 12349.00 203.0 AVG 85 PROPANE (C-3) 75 @ 12404.00 17 @ 12349.00 38.2 CURRENT 114 BUTANE (C-4) 15 @ 12345.00 0 @ 12401.00 4.4 CURRENT BACKGROUND/AVG 38/46 PENTANE (C-5) 0 @ 12415.00 0 @ 12415.00 0.0 HYDROCARBON SHOWS NONE INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY 10% Sandstone, 10% Siltstone, 5% Coal, 75% Claystone PRESENT LITHOLOGY 10% Sandstone, 90% Claystone DAILY ACTIVITY SUMMARY Drill from 12188' to 12415' EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 REPORT BY Brian O'Fallon · · UNOCAL ALASKA AFE 162461 RED #1 DAILYWELLSITE REPORT U EPOCH REPORT FOR Shane Hauck, Jim Brown DATE Jun 28, 2004 TIME 24:00:00 DEPTH 12458.00 YESTERDAY 12415.00 PRESENT OPERATION Pumping Out 24 HOUR FOOTAGE 43 CASING INFORMATION 7" @ 4601' DEPTH SURVEY DATA 12391 BIT INFORMATION NO. SIZE TYPE 4 61/8" HC HCM406 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 10.0 VIS 95 FC 0/3 SOL 14.3 MWD SUMMARY INTERVAL TO TOOLS · GAS SUMMARY (units) DITCH GAS CUTTING GAS METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL INCLINATION 11.20 VERTICAL DEPTH 11981.44' AZIMUTH 117.56 INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7102176 TFA 0.589 10765 1693 72 HIGH LOW AVERAGE CURRENT AVG 15.3 @ 12419.00 3.0 @ 12417.00 9.3 13.88327 FT/HR 5511 @ 12451.00 4680 @ 12416.00 5254.8 5428.93652 AMPS 10 @ 12430.00 4 @ 12431.00 8.0 5.18200 KLBS 91 @ 12416.00 88 @ 12431.00 92.2 89.46357 RPM 2894 @ 12445.00 2657 @ 12431.00 2857.3 2774.70386 PSI DEPTH 12458 PV 57 YP 15 FL 4.5 Gels 15/25/28 CL- SD 0.10 OIL 68/16 H2O MBL pH Ca+ CCI HIGH LOW 50 @ 12443.00 28 @ 12433.00 o @ 12458.00 0 @ 12458.00 CHROMATOGRAPHY (ppm) 12443.00 5421 @ 12433.00 12443.00 117 @ 12433.00 12441.00 16 @ 12445.00 12443.00 2 @ 12433.00 12458.00 0 @ 12458.00 NONE LITHOLOGY/REMARKS AVERAGE 38.9 0.0 TRIP GAS WIPER GAS 109@12458 SURVEY CONNECTION GAS HIGH NA AVG NA CURRENT NA CURRENT BACKGROUND/AVG 25/38 9222 @ 288 @ 47 @ 6 @ o @ 7182.4 191.1 30.4 4.3 0.0 GAS DESCRIPTION LITHOLOGY 10% Sand, 5% Coal, 10% Carbonaceous Shale, 75% Claystone PRESENT LITHOLOGY 10% Sand, 10% Carbonaceous Shale, 80% Claystone Drill to total depth of 12458', and monitor well, flowing. Ciculate bottoms up, 112 units. Allow well to flow and circulate bottoms up, 154 units, and take mud sample. Allow well to flow and circulate bottoms up, 142 units, and take mud sample. Shut in well and build mud weight to 10.0 and circulate bottoms up, 84 units. Monitor well, no flow, and short trip 10 stands, improper fill. Circulate bottoms up, 109 units, and begin pumping out 20 stands. DAILY ACTIVITY SUMMARY EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 · REPORT BY Brian O'Fallon · UNOCAL ALASKA AFE 162461 RED #1 REPORT FOR Shane Hauck, Larry McAllister DATE Jun 29, 2004 TIME 24:00:00 DAILY WELLSITE REPORT U EPOCH DEPTH 12458.00 YESTERDAY 12458.00 24 HOUR FOOTAGE 0 PRESENT OPERATION Trip out for e-Iog CASING INFORMATION 7"@4601' DEPTH SURVEY DATA 12391 METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY NA PRESENT LITHOLOGY NA DAILY ACTIVITY Finish 20 stand short trip pumping out, and including 3 stand MADD pass on trip in, maximum 88 units of gas. SUMMARY Circulate and condition hole, 64 units uphole trip gas and 38 units bottoms up, and weight up to 10.2 ppg. Trip out of hole to BHA, pumping out, maximum 90 units of gas. BIT INFORMATION NO. SIZE TYPE 4 6 1/8" HC HCM406 · DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 10.2 VIS 104 FC 0/3 SOL 16.6 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) DITCH GAS CUTTING GAS INCLINATION 11.20 VERTICAL DEPTH 11981.44' AZIMUTH 117.56 INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7102176 TFA 0.589 10765 1693 72 HIGH LOW AVERAGE CURRENT AVG NA @ @ FT/HR NA @ @ AMPS NA @ @ KLBS NA @ @ RPM NA @ @ PSI DEPTH 12458 PV 67 YP 18 FL 4.5 Gels 8/23/26 CL- SD 0.10 OIL 71/11 H2O MBL pH Ca+ CCI HIGH LOW AVERAGE 90 @ 3 @ 40 @ @ CHROMATOGRAPHY (ppm) @ @ @ @ @ @ @ @ @ @ TRIP GAS 38(BU)/64(MAX)@12458' WIPER GAS SURVEY CONNECTION GAS HIGH NA AVG NA CURRENT NA CURRENTBACKGROUND~VG14 NA LITHOLOGY/REMARKS GAS DESCRIPTION · EPOCH PERSONNEL ON BOARD 4 DAILY COST $2600 REPORT BY Brian O'Fallon UNOCAL ALASKA AFE 162461 RED #1 REPORT FOR Shane Hauck, Larry McAllister DATE Jun 30, 2004 TIME 24:00:00 · DAILY WELLSITE REPORT U EPOCH DEPTH 12458.00 YESTERDAY 12458.00 PRESENT OPERATION e-Iog 24 HOUR FOOTAGE 0 CASING INFORMATION 7"@4601' DEPTH SURVEY DATA 12391 BIT INFORMATION NO. SIZE TYPE 4 6 1/8" HC HCM406 · DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 10.2 VIS 122 FC 0/3 SOL 16.6 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) DITCH GAS CUTTING GAS METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL INCLINATION 11.20 VERTICAL DEPTH 11981.44' AZIMUTH 117.56 INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7102176 TFA 0.589 10765 1693 72 HIGH LOW AVERAGE CURRENT AVG NA @ @ FT/HR NA @ @ AMPS NA @ @ KLBS NA @ @ RPM NA @ @ PSI DEPTH 12458 PV 72 YP 17 FL 4.5 Gels 10/26/29 CL- SD 0.01 OIL 71/11 H2O MBL pH Ca+ CCI HIGH LOW 4 @ 2 @ @ @ CHROMATOGRAPHY (ppm) @ @ @ @ @ @ @ @ @ @ AVERAGE 3 TRIP GAS NA WIPER GAS SURVEY CONNECTION GAS HIGH NA AVG NA CURRENT NA CURRENT BACKGROUND/AVG 3/3 NA LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY NA PRESENT LITHOLOGY NA DAILY ACTIVITY Trip out with BHA and lay down MWD tool. Rig up Schlumberger and run wireline, circulating through pits, SUMMARY 2-4 units of gas. EPOCH PERSONNEL ON BOARD 4 DAILY COST $1920 REPORT BY Brian O'Fallon · · UNOCAL ALASKA AFE 162461 RED #1 REPORT FOR Shane Hauck, Larry McAllister DATE July 1, 2004 TIME 24:00:00 DAILY WELLSITE REPORT U EPOCH DEPTH 12458.00 YESTERDAY 12458.00 24 HOUR FOOTAGE 0 PRESENT OPERATION lay down HWDP CASING INFORMATION 7"@4601' DEPTH SURVEY DATA 12391 METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY NA PRESENT LITHOLOGY NA DAILY ACTIVITY SUMMARY Finished wireline and tested BOPs. Laying down HWDP. BIT INFORMATION NO. SIZE TYPE 4 61/8" HC HCM406 · DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 10.2 VIS 75 FC 0/3 SOL 15.5 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) DITCH GAS CUTTING GAS INCLINATION 11.20 AZIMUTH 117 .56 VERTICAL DEPTH 11981.44' INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PULLED 7102176 TFA 0.589 10765 1693 72 T.D. HIGH LOW AVERAGE CURRENT AVG NA @ @ FT/HR NA @ @ AMPS NA @ @ KLBS NA @ @ RPM NA @ @ PSI DEPTH 12458 PV 62 YP 13 FL 5.6 Gels 6/16/18 CL- SD 0.10 OIL 73/10 H2O MBL pH Ca+ CCI HIGH LOW AVERAGE 3 TRIP GAS NA WIPER GAS SURVEY CONNECTION GAS HIGH NA AVG NA CURRENT NA CURRENT BACKGROUND/AVG 3/3 4 @ 2 @ @ @ CHROMATOGRAPHY (ppm) @ @ @ @ @ @ @ @ @ @ NA LITHOLOGY/REMARKS GAS DESCRIPTION EPOCH PERSONNEL ON BOARD 4 DAILY COST $1920 REPORT BY Brian O'Fallon · . UNOCAL ALASKA AFE 162461 RED #1 DAILY WELLSITE REPORT g EPOCH REPORT FOR Shane Hauck, Larry McAllister DEPTH 12458.00 YESTERDAY 12458.00 24 HOUR FOOTAGE 0 CASING INFORMATION 7"@4601' DEPTH SURVEY DATA 12391' METHANE (C-1) ETHANE (C-2) PROPANE (C-3) BUTANE (C-4) PENTANE (C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY NA PRESENT LITHOLOGY NA DAILY ACTIVITY Finish laying down HWDP, and pick up 26 stands (809') of 27/8" tubing. Trip in hole to 11444' in stages, circulating SUMMARY out after each stage, maximum 164 units of gas. Pump cement plug, pull out of hole to 10940', and circulate and condition hole, discarding 20 barrels of contaminated mud. Trip out of the hole. DATE July 2, 2004 TIME 24:00:00 BIT INFORMATION NO. SIZE TYPE 4 61/8" HC HCM406 . DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 10.2 VIS 115 FC 0/3 SOL 15.4 MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY (units) DITCH GAS CUTTING GAS PRESENT OPERATION Trip out after cement plug. INCLINATION 11.20 VERTICAL DEPTH 11981.44' AZIMUTH 117.56 INTERVAL CONDITION REASON SIN JETS IN OUT FOOTAGE HOURS T/B/C PU LLED 7102176 TFA 0.589 10765 1693 72 T.D. HIGH LOW AVERAGE CURRENT AVG NA @ @ FT/HR NA @ @ AMPS NA @ @ KLBS NA @ @ RPM NA @ @ PSI DEPTH 12458 PV 61 YP 22 FL 4.6 Gels 14/22/25 CL- SD 0.10 OIL 71/12 H2O MBL pH Ca+ CCI HIGH LOW 164 @ 4 @ @ @ CHROMATOGRAPHY (ppm) @ @ @ @ @ @ @ @ @ @ AVERAGE 60 TRIP GAS 164@10253' WIPER GAS SURVEY CONNECTION GAS HIGH NA AVG NA CURRENT NA CURRENT BACKGROUND/AVG 40/60 NA LITHOLOGY/REMARKS GAS DESCRIPTION . EPOCH PERSONNEL ON BOARD 4 DAILY COST $1920 REPORT BY Brian O'Fallon FINAL LOGS .I MNI )0 ,-(- ðJV Laboratories, Inc. August23,2004 Mr. David Buthman UNOCAL 900 W. 9th Avevue Anchorage, Alaska 99501 Red NO.1 Well Cook Inlet, Alaska File: A-87003 Subject: Rotary Core Analysis Report Dear Mr. Buthman: A study to determine basic core analyses parameters on rotary core material recovered from the subject site has been completed for UNOCAL. This study was authorized in a series of communications between representatives of UNOCAL and OMNI Laboratories in July, 2004. Wellsite, Transport and Lab Handling 37 rotary core analyses samples were collected at the rig site and transferred to Clif Posey of OMNI Laboratories Alaska. The sample boxes were then transported to OMNI Laboratories' Houston facility. Upon arrival at the laboratory, the samples were inventoried, CT scanned and photographed to determine suitability for analysis. The CT scans of the plugs are presented in an appendix to this report. The 37 samples were trimmed to right cylinders such that two end trims were obtained. A thin section was prepared from each well bore end trim by OMNI Laboratories. The formation end trims were provided to Reed Glassman for SEM and XRD analyses. Core Analysis Based on the CT scans, visual examination and completion needs, 11 samples were selected for expedited analyses using OMNI Laboratories Pressure Extraction System. The remaining samples were extracted using sohxlet chloroform-methanol azeotrope to remove residual hydrocarbons and salt. All samples were then dried to a constant weight in a vacuum oven at 140°F. Boyle's law helium grain volumes were measured and grain density calculated. Boyle's law helium pore volume and steady-state permeability to air were determined at 800 psi net confining stress using the Frank Jones permeameter/porosimeter. Klinkenberg permeability values were calculated from the observed steady-state data. Porosities were calculated using the following formula: ø = (PV)/ (GV+PV) *100 where: ø PV GV = Porosity, percent = Pore Volume, cc = Helium Grain Volume, cc Rotary core analysis results are presented in tabular and graphical formats on the pages that follow. Longitudinal (as received) white and ultraviolet light photos were taken of all samples. In addition, white and ultraviolet light end trim photos were taken of the samples where core analysis was performed. All photos are presented in this report, along with the associated routine data, where appropriate. Thank you for this opportunity to be of service to UNOCAL. If you have any questions concerning the enclosed information, or if we can be of any additional service, please contact me at 832-237-4000. Sincerely, ('flJ.J--D--~~ ~~___ Melanie F. Dunn Manager, Special Core Analysis Laboratory 8-3-04 SUMMARY OF ROTARY CORE ANALYSES RESULTS Vacuum Dried at 140°F Net Confining Stress: 800 psi UNOCAL Cook Inlet, Alaska Red No.1 Well File: A-87003 Sample Permeability, Porosity, Grain Sample Sample Depth, millidarcys percent Density, Lithological Number Number feet to Air I Klinkenberg Ambient I NCS gm/cc Description 1 1 5736.0 51.0 43.7 20.4 20.1 2.68 Ss fg slty 1 2 5792.0 37.5 31.6 19.1 18.7 2.67 Ss fg slty 1 3 5814.0 0.389 0.272 16.1 15.8 2.68 Ss fg slty 1 4 5826.0 0.599 0.444 15.1 15.0 2.67 Ss fg slty 1 5 5854.0 0.527 0.369 12.4 12.4 2.70 Ss fg slty spyrt 1 6 6072.0 0.620 0.421 15.1 14.9 2.65 Ss f-mg slty 1 7 6138.0 + 19.1 2.67 Ss f-mg vslty 1 8 6334.0 0.517 0.373 14.9 14.9 2.66 Ss fg slty 1 9 6390.0 39.4 33.7 17.4 17.3 2.65 Ss f-vcg vslty Ig incls 1 10 6564.0 0.046 0.024 12.1 11.8 2.69 Ss fg slty thn lams 1 11 6675.0 0.010 0.0036 10.3 9.9 2.67 Ss fg slty thn lams 1 12 6772.0 + 20.0 2.73 Ss fg slty 1 13 8810.0 2.92 2.27 6.1 5.9 2.66 Ss mg slty thk shy lam 1 14 8814.0 54.0 46.7 12.8 12.7 2.62 Ss m-cg slty 1 15 8818.0 224. 205. 14.0 13.7 2.62 Ss m-vcg slty 1 16 9064.0 0.413 0.290 13.5 13.4 2.66 Ss fg slty 1 17 9069.0 2.26 1.73 12.8 12.7 2.66 Ss fg slty Ig incls 1 18 9214.0 0.892 0.684 10.2 9.8 2.56 Ss mg vslty thn org lams 1 19 9238.0 26.9 22.5 11.9 11.4 2.62 Ss m-cg vslty Ig incls 1 20 9285.0 22.2 18.3 12.6 12.5 2.60 Ss m-cg vslty Ig incls 1 21 9298.0 20.1 16.5 13.7 13.5 2.62 Ss fg vslty 1 22 9308.0 12.1 9.61 13.0 12.8 2.58 Ss fg vslty 1 23 9413.0 1.24 0.898 15.9 15.8 2.65 Ss fg slty scalc 1 24 10068.0 0.023 0.010 7.9 7.6 2.69 Ss fg slty scalc 1 25 10534.0 8.88 6.71 13.4 13.1 2.61 Ss fg slty scalc 1 26 10606.0 0.014 0.0052 3.9 3.6 2.62 Ss fg slty scalc 1 27 10754.0 0.162 0.101 5.6 5.5 2.66 Ss fg slty Ig incl scalc 1 28 10768.0 0.109 0.064 9.7 9.5 2.66 Ss fg slty scalc 8-3-04 MNI Laboratories, Inc. SUMMARY OF ROTARY CORE ANALYSES RESULTS Vacuum Dried at 140°F Net Confining Stress: 800 psi UNOCAL Cook Inlet, Alaska Red NO.1 Well File: A-87003 Sample Permeability, Porosity, Grain Sample Sample Depth, millidarcys percent Density, Lithological Number Number feet to Air I Klinkenberg Ambient I NCS gm/cc Description 1 29 10982.0 0.047 0.024 5.1 4.9 2.65 Ss f-vcg scalc 1 30 11245.0 0.399 0.279 16.0 15.8 2.66 Ss f-cg slty Ig incls 1 31 11677.0 0.0094 0.0033 9.2 9.2 2.68 Ss fg slty thn lams 1 32 11681.0 0.061 0.033 10.7 10.4 2.64 Ss fg slty 1 33 11781.0 0.173 0.109 12.2 12.0 2.64 Ss fg slty 1 34 11785.0 0.107 0.063 11.1 11.1 2.64 Ss fg slty scalc 1 35 11790.0 0.508 0.356 14.2 14.1 2.65 Ss f-mg slty scalc 1 36 11930.0 0.0046 0.0013 10.1 10.1 2.64 Ss fg slty 1 37 12260.0 1.36 1.06 4.2 4.0 2.59 Ss fg calc frac fll Average values: 14.6 12.7 12.5 11.9 2.65 NI UNOCAL Red No. 1 Well PERMEABILITY VERSUS POROSITY Vacuum Dried at Net Stress: 800 1000 0.001 100 _________w,.' 10 1 0.1 ----.""-,,, -- ---------- ~-----,- 0.01 o . 4 8 . . . . 12 8-3-04 Cook Alaska File: A-87003 . . 16 20 8845 Fax 1 Well Location 0.5 1.0 8845 Fallbrook. Houston, Tx Phone 237·4000 Fax (832) 237- 4700 UNOCAL Red No.1 Well Cook 3:>: 1.0 __ 0.5 2x em 2.0 1.0 8845 FallbrOOk, Houston, 1:x. Phone (832) 237-4000 Fax (832) 4700 1 Well 0.5 1 Well -- 1.0 1.0-- 8845 Houston. Phone 237-4000 Fax (832) 237- 4700 I Well 0.5 I Fax Well Location 1.0-- 2_0 2x em I i 1.0 8845 Fallbrook_ Houston, Tx. Phone 237-4000 Fax (832) 237· 4700 _ 0.5 Well Location 2.0- 1.0 File 1.0 2x 8845 Fallbrook, Houston, (832) 237-4000 Fax 237- 4700 0.5 Fax 8845 Well Location em 1.0 em 2.0 6 8845 Fallbrook, Houston, Tx Phone (832) 237·4000 Fax (832) 4700 1 Fax Well location em 2, em 7 File 0,5 8845 Fa!!brook, Houston, Tx. Phone (832) 237-4000 Fax (832) 237- 4700 Location em 2.0 2.0·- File 0.5 8845 3X 237-4700 Well Location in 2.0- 2x 8845 Fallbrook. Houston, 4700 Phone 237-4000 1 Well Location :IX 8845 237~4000 Fax 1 Well Location 2x _ 0.5 1.0 0.5 8845 Fallbtook, 2.0 1.0 No. Well Cook Inlet, Alaska em 3X 8845 Fax Well Location 1.0 2.0- 11 If! 2x 8845 Fallbrook. Houston. Tx 237-4000 (832) 237- 4700 I Well Location ble em 1.0- 2.0 8845 Phone 3)( Fax 2x 1.0 2,0- 1,0 _ 0,5 2,0- 1.0 8845 Fallbrook. Houston, Tx. Phone (832) 237-4000 Fax (832) 237- 4700 1 Well 3X 8845 Fax 4700 1.0 2.0- _ 0.5 2.0 1 13 0.5 1 1 File: Weil Well Alaska 2.0- 8845 Fax Well 2x in 2.0 2x em 1.0- 2.0- 0.5 Tx. Phone (832) 237-4000 Fax (832) 4700 1 2,0- 1 location File _ 0.5 2.0- 1.0 in 1.0 8845 Fallbrook, Houston, Tx. Phone (832) 237·4000 Fax (832) 4700 - Well 3X em - 0.5 1.1:1- 2.0- 2. 2.0 2x em 1.0 _ 0.5 Weil Location UNOCAL Red Well Cook 1 em 2.0 8845 Fax 2x em 1.0- 1.0 0.5 8845 Houston, (832) 237-4000 Fax (832) 237- 4700 1 Well Location em __ 0.5 2.0 em _ 0.5 1 18 8845 Fallbrook, Houston, Tx. (832) 237-4000 4700 I 3X 1,0 2)( 1,0 05 0,5 8845 Fallbrook, Houston, Tx, 4700 Well UNOCAL 1 File No,: Well 2.0 I 1.0 _ 0.5 ·1.0 8845 Fallbrook, Tx Phone 237·4000 (832) 4700 Well Well 2x 2.0 _ 0"5 237·4000 (832) 4700 Well 1,0 2x _ 0,$ Fax (832) 237·4700 Tx Well JX 1.0- 2.0 1.0 2x Fallbrook, Houston, T)c Phone 237-4000 Fax 4700 I 1 1 2.0 .1.0 2x 1.0 Houston, Tx. Phone (832) 237-4000 Fax (832) 237- 4700 1 _ 0.5 1 o Well 2.0 1.0 2x in 8845 4700 1 em 0.5 1 UNOCAL Well 8845 Well 1.0- 1 1.0 em I ~ 1 em 2.0- 1.0 o Fallbrook, (832) (832) 4700 1 Well em 1 .0 u 2JJ·- 2. 0.5 8845 Fallbrook. Houston. Tx. Phone 237-4000 4700 11 0.5 1 Well 2x in a,s 8845 Fallbrook, Houston, Phone 237-4000 (832) 4700 11 Well 11 Location 2.0- em 1.0- _ 0.5 2.0 1.0 8845 Fallbrook. Houston. (832) 237-4000 Fax (832) 4700 1 11 em 1.0 2.0- -.- 1.0 1.0 11 1. Well 11 1 Well 1.0 1,0 em 1.0 ~ 0,5 2,0 0.5 237-4000 Fax (832) 4700 11 Well - 0.5 2,(J- 8845 Phone 11 em 1.!) 8845 237·4000 (832) 4700 11 11 1,0 2x in 2.0 0.5 11 Well 11 LO 0.5 1 1 File 1.0 APPENDIX A COMPUTED TOMOGRAPHY IMAGES (CT Scans) INDIVIDUAL PLUGS MNI
