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192-052
s,or ro //7,'• THE STATE Alaska Oil and Gas ofAT /\ KA Conservation Commission 333 West Seventh Avenue -.‘"'11' 11-16-* 1. GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF ALAS Fax: 907.276.7542 www.aogcc.alaska.gov December 27, 2016 Mr. Stan Golis Operations Manager—CI Offshore Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No-Flow Verification Trading Bay Unit G-29RD SCANNED APR PTD 1920520 ° � ' Dear Mr. Golis: On December 1, 2016, an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit G-29RD located on the Grayling Platform in Cook Inlet. The well is operated by Hilcorp Alaska, LLC (Hilcorp). The AOGCC Inspector confirmed that the proper test equipment — as outlined in AOGCC Industry Guidance Bulletin 10-004 — was rigged up on Trading Bay Unit G-29RD prior to the test. The well performance was monitored for nearly four hours with observed gas flow rates at the end of the flow monitoring periods less than the regulatory limit. There was no liquid flow to surface during the no-flow test. The well may be produced without a subsurface safety valve. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition in this well as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if Trading Bay Unit G-29RD demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a subsequent no flow test. Please retain a copy of this letter on the Grayling Platform. Sincerely, • , . cb � James B. Regg ( 1 Petroleum Inspection Supervisor cc: P. Brooks AOGCC Inspectors STATE OF ALASKA AL/111A OIL AND GAS CONSERVATION COMAION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Plug Perforations 0 Fracture Stimulate 0 Pull Tubing 0 Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well 0 Re-enter Susp Well 0 Other: Convert to G/L&Tubing Punch❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development❑ Exploratory❑ 192-052 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service 0 6.API Number: Anchorage,AK 99503 50-733-20374-01 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0017594 Trading Bay Unit/G-29RD 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A McArthur River Field/Hemlock Oil and Middle Kenai G Oil Pools 11.Present Well Condition Summary: Total Depth measured 13,538 feet Plugs measured N/A RECEIVED true vertical 9,803 feet Junk measured N/A feet DEC 19 2016 Effective Depth measured 13,386 feet Packer measured 11,489&11,533 feet true vertical 9,736 feet true vertical 8,813&8,824 feet 4 OGCC Casing Length Size MD TVD Burst Collapse Structural 324' 28" 324' 324' Conductor 911' 20" 911' 911' 1,530 psi 520 psi Surface 6,572' 13-3/8" 6,572' 5,608' 3,090 psi 1,540 psi Production 10,078' 9-5/8" 10,078' 7,810' 6,870 psi 4,760 psi Liner 3,771' 7" 13,538' 9,803' 11,640 psi 10,760 psi Liner 1,753' 5" 13,431' 9,756' 8,290 psi 7,250 psi Perforation depth Measured depth 11,788-13,240 feet True Vertical depth 8,958-9,672 feet Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 11,585(MD) 8 860(ND) LTB Packer 11,489(MD)8,813(ND) Packers and SSSV(type,measured and true vertical depth) SAB Packer 11,533(MD)8,824(ND) SSSV:N/A 12.Stimulation or cement squeeze summary: Intervals treated(measured): �p L� h yy� c r N/A SCANNED MA 0 1 L It, 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 0 0 1136 190 Subsequent to operation: 0 0 0 1230 1251 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory❑ Development Service ❑ Stratigraphic 0 Copies of Logs and Surveys Run 0 16.Well Status after work: Oil 0 Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR 0 WINJ ❑ WAG 0 GINJ 0 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: 316-567 Contact Dan Marlowe(907)283-1329 Email dmarioweOhilcoro.com Printed Name Stan W.Golis Title Operations Manager Signature 't*..... C-.) T1�....J Phone (907)777-8356 Date ('x`11 1 J(o c t i2 -,29-1 G ,1/Z7.0q�,( Form 10-404 Revised 5/2015 _ RBDMS L k/ DED 2 2 2016 Submit Original Only H . � McArthur River Field,TBU Well: G-29RD • EiSCHEMATIC Actual Completion: 9/25/14 PTD: 192-052 Hilcorp Alaska,LLC API: 50-733-20374-01 RKB to TBG Hanger=41.35' 1 CASING DETAIL SIZE WT GRADE CONN ID TOP BOTTOM Note L • 28" Driven Surf 324' 20" 94 H-40 Buttress 19.124" Surf 911' Cmtd 1814sx"G"1985 13-3/8" 61 K-55 Buttress 12.515" Surf 3,080' Cmtd 4110sx"G"1985 L 13-3/8" 68 K-55 Buttress 12.415" 3,080' 6,572' DV Collar 9-5/8" 47 N-80, Buttress 8.681" Surf 10,078' Cmtd 1575sx"G"1985 S-95 (TOW) Tubing Punch 7" 32 P-110 Buttress 6.094" 9,767' 13,538' Cmtd 1162sx"G"1992**235bb1s @ 2,996' pumped w/30bbl Excess Cmtd Scab Liner.2lbbls 13-3/8in 5./1i/it 5" 15 L-80 Hyd 511 4.408" 11,678' 13,431' 15.8ppg cmt.No cmt to surf. DV Collar I . 2002 TUBING DETAIL TPL 4-1/2" 113 556 are ned L-80 4040 3.598" Surf 11,585 Polycore ID=3.68in Drift=3.4in JEWELRY DETAIL L , No. Depth Depth ID OD Item (MD) (TVD) 1 11,489' 8,813' 3.560" 5.890" 7in 26-32#LTB Pkr(Ni) 2 11,495' 8,815' 2.920" 5.000" XO 4.5in LTC X 3.5in IBT • 3 11,526' 8,831' 2.810" 4.250" 3.5in XN Nipple 2.75in nogo 4 11,527' 8,831' 2.441" 4.270" X0 3.5in Btc X 2-7/8in Btc • 5 11,559' 8,847' 2.437" 3.220" Btm of 2-7/8 jnt&mule shoe(25.51ft) i ' 11,533' 8,834' 4.910" 5.980" Tag Top of Lwr 7in SAB Packer JD 'i 6 11,585 8,860 2.992" 3.500" Btm of 3.5in Original Tbg Tail li 7in liner top .,,,, 9-5/8in @ 9,76715 window @ Inc 49° 1 10,078ft PERFORATION DATA ZONE TOP BTM TOP BTM FT DATE Status MI 2 (MD) (MD) (TVD) (TVD) 3 6-1 11,788 11,809 8,958 8,978 21' 9/18/14 IMPI G-1 11,790 11,890 8,960 9,009 100' 4/29/02 6-1 11,826 11,835 8,977 8,982 9' 9/17/14 6-1 11,852 11,882 8,990 9,005 30' 9/17/14 5 G-2 11,960 11,990 9,044 9,059 30' 4/29/02 6-3 12,050 12,065 9,089 9,097 15' 4/29/02 Sin liner top6 G-4 12,085 12,115 9,107 9,122 30' 4/29/02 @ 11,678ft G-4 12,125 12,160 9,127 9,145 35' 4/29/02 Inc 61° ;N +`$ G-1 G-4 12,190 12,200 9,160 9,165 10' 4/29/02 PO t G-5 12,250 12,307 9,191 9,220 57' 9/17/14 `c* +r _, G 2 G-Zone G-5 12,318 12,326 9,225 9,229 8' 9/17/14 - G-3 622ft 6-5 12,333 12,365 9,233 9,249 32' 9/17/14 ,y * G-4 6-5 12,250 12,370 9,191 9,251 120' 4/29/02 t 5 G-5 12,385 12,410 9,259 9,271 25' 4/29/02 Tag12,599ft ,°''- HB-1 6-5 12,387 12,408 9,260 9,270 21' 9/17/14 HB-1 12,650 12,690 9,393 9,413 40' 4/29/02 Covered 6 Hemlock * ---1?-HB-3 590ft HB-3 12,940 12,960 9,534 9,543 20' 4/29/02 Covered HB-4 HB-3 13,010 13,040 9,567 9,581 30' 4/29/02 Covered • HB-4 13,190 13,240 9,650 9,672 50' 4/29/02 Covered 4/29/02:SLB TCP-Shot with 3.125"6SPF guns.4,650ft dry pipe and estimated 1,200psi underbalance L , under packer. 2002 Initial injection rate was 9-11 kbwipd. 2005 communication to IA. Went offline 2011 at 7-8kbwipd. TD=13,538'MD/9803'TVD 9/25/14 Completion:Initial bwipd=0. Perf:2.125in 11,788ft to 11,809ft 6spf.S-Line Tag 12,599ft(9-18). PBTD=13386'=5"landing collar Pump 100bb17%HCL.Final injection 2.5bpm-3,600bwipd. No injection when brought on-line at Max hole angle=64 deg @ 13,300' 3,200psi header pressure. 60+deg from 11,400'to TD Updated: 12/12/16 by JLL Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date G-29RD Slickline 50-733-20374-01 192-052 11/17/16 11/17/16 Daily Operations: 11/17/16-Thursday Meet w/ production and fill out permits. Safety meeting. Spot unit and rig up. P/T to 250 low/3200 high. RIH with single 9/16" tubing punch. Log into position at 2990' ccl depth with 6'from ccl to top shot. Putting the hole at 2996'. Run 1 Pass 3. Pressured up tubing to 200 psi. Shot fired,tubing and IA equalized, POOH, rig down. • S MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg iZV741 DATE: 12/01/16 P. I. Supervisor FROM: Guy Cook SUBJECT: No Flow Test Petroleum Inspector TBU G-29RD - Hilcorp Alaska PTD 192-052 12/01/16: Upon my arrival onto the Grayling Platform I met with Kenny Wingard and we discussed the job. We went over the setup of the gauges and flowmeter and associated equipment to make sure it was set up correctly. Kenny told me the well had been open to atmosphere for 48 hours with no fluid coming to surface. The flow meter was an Armor- Flo 0-18 SCFH, serial #991632 (last calibration February 2016). The pressure gauge was a SSI Test Digital Gauge, range 0-30 psi, serial #1506240084 (last calibration May 29, 2016). The following table shows test details: Time Pressures1 Flow Rate Remarks (psi) Gas - scf/hr Liquid - gal/hr 10:40 0/0/120 0 0 Well S/I. Pressures taken prior to S/1. Bled well to 0 psi. @ 3 min. 0 11:10 0.60/0/120 " 1100 " 0 flow @ 4 min. <1000 SCFH @ 1 min. 11:15 0/0/120 0 0 Well S/I. Pressures taken prior to S/l. 11:45 0.58/0/120 - 0 0 S/I Bled well to 0 psi. @ 3 min. 54 12:15 1/0/120 1450 0 sec. 0 flow @ 5 min. < 1000 SCFH @ 1 min 15 sec. 12:20 0/0/120 0 0 Well S/I. Pressures taken prior to WI. 12:50 0.51/0/120 0 0 S/I 13:20 0.86/0/120 - 0 0 S/I 13:50 1.16/0/120 . 0 0 S/I Bled well to 0 psi @ 4 min. 45 14:20 1.39/0/120 1700 0 sec. 0 flow @ 5 min 30 sec. < 1000SCFH @2min. 1 Pressures are T/IA/OA 2016-1201_No-Flow_TBUG-29RD_gc.docx Page 1 of 2 SCANNED MAY : 2012 • • Summary: TBU G-29RD was opened to flow after 30 minutes, 1 hour, and 2 hours of being shut in. No fluids were produced from the well during any of the flow monitoring periods. The test data showed a weakening trend as the test went on, making me believe that this well will not flow to surface unassisted, therefore meeting the criteria for producing TBU G-29RD without an SSSV installed. Attachments: Calibration Certificate —Armor-Flo Meter Calibration Certificate — SSI Pressure Gauge 2016-1201_No-Flow_TBUG-29RD_gc.docx Page 2 of-2,' • • � 0cn Certificate This is to certify that this instrument has been calibrated for the fluid conditions specified on the purchase order and embossed on the nameplate. Measuring devices that are traceable to the United States National Institute for Standards and Technology (NIST- formerly National Bureau of Standards) were used for this calibration. Technician Da Instrument Serial Number ERDCO Engineering Corporation 721 Custer Av ♦ Post Office Box 6318 Evanston, IL 60204-6318 USA • • Hililcorp Alaska, LLC HILCORP CALIBRATION CERTIFICATE Pressure Standards Referenced to NIST File TN822-256610-96,TN838-256609-96,P-8523 Gauge type: SSI Technologies Pressure range: 30 psi S/N number: 1506240084 Date: May 29, 2016 UOCD-4536 TEST PRESSURE INDICATION 0.00 0.00 7.50 7.50 15.00 15.00 22.50 22.50 30.00 30.00 F Calibrated by: -,. ,\, A Test equipment S/N: 9484040 This certificate expires in 1 year on May 29, 2017. For recertification, contact Gina Bogart 776-6825 or Cathy Marshall 283-1384. • • ti �� f/77 s THE STATE Alaska Oil and Gas Or Ttj, l, of�T As Conservation Commission t '� 333 West Seventh Avenue �, !<- C GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 101\-T7 Main: 907.279.1433 O4.ALA9*P Fax: 907.276.7542 www.aogcc.alaska.gov Stan W. Golis Operations Manager scosu tos 1 vs ,.L , Hilcorp Alaska, LLC 3 800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: McArthur River Field,Hemlock and Middle Kenai G Oil Pools, TBU G-29RD Permit to Drill Number: 192-052 Sundry Number: 316-567 Dear Mr. Golis: 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, /e)/4- Daniel T. Seamount, Jr. Commissioner DATED this �V day of November, 2016. RBDMS .,`/NOV 1 6 2016 RO • • • , STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGICA3 20 AAC 25.280 1.Type of Request: Abandon 0 Plug Perforations❑ Fracture Stimulate ❑ Repair Well 0 Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing El Change Approved Program El Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. Convert to G/L& Tubing Punch 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. iird:1--. fl-Z01> Hilcorp Alaska,LLC Exploratory 0 Development ❑ 192-052 3.Address: 3800 Centerpoint Drive,Suite 1400Stratigraphic ❑ Service 0 . 6.API Number. Anchorage,AK 99503 50-733-20374-01 . 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No 0 Trading Bay Unit/G-29RD 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0017594 McArthur River Field/Hemlock Oil and Middle Kenai Cr 0;( 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 13,538 9,803 13,386 9,736 2,697 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural 324' 28" 324' 324' Conductor 911' 20" 911' 911' 1,530 psi 520 psi Surface 6,572' 13-3/8" 6,572' 5,608' 3,090 psi 1,540 psi Production 10,078' 9-5/8" 10,078' 7,810' 6,870 psi 4,760 psi Liner 3,771' 7" 13,538' 9,803' 11,640 psi 10,760 psi Liner 1,753' 5" 13,431' 9,756' 8,290 psi 7,250 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 11,788-13,240 4 8,958-9,672 4-1/2" 12.6#/L-80 11,585 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): LTB Packer&SAB Packer/ SSSV:N/A ' 11,489'(MD)8,813'(TVD)11,533'(MD)8,824'(TVD)&N/A 12.Attachments: Proposal Summary 0 Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development 0• Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 11/21/2016 Commencing Operations: OIL 0 r 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 Dan Marlowe(907)283-1329 Email dmarlowechilcorp.com Printed Name Stan W.Golis Title Operations Manager S44.....Signature >i /( Phone (907)777-8356 Date ) t 1 (/ z_ ( 4 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. `k-e, - ies1 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: r,'V:. F./ex.,' (,,:01` r,4, 44--.4:-/-e...." hitt, �� � tb lt L. rIE- Post Initial Injection MIT Req'd? Yes ❑ No ❑,�,/ 1 Spacing Exception Required? Yes ❑ No L9 Subsequent Form Required: /() y U41 RBDMS L- NOV 6 2U16 PP y APPROVEDBY 1 1 Ott f0 Approved b : I COMMISSIONER THE COMMISSION Date: I i O/ �gil ii i -"a'J 0-9'`1, Submit Form and Form 10-403 Revised 11/2015 0 RtGilictcrtvalid for 12 months froulythe date of approval. ,, ///g Attachments in Duplicate • • • Well Prognosis Well: G-29rd Hilcorp Alaska,LL: Date:10/28/2016 Well Name: G-29rd API Number: 50-733-20374-01 Current Status: Waterflood Injector Leg: Leg#4 SW Corner Estimated Start Date: 11/21/16 Rig: E-Line Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 192-052 First Call Engineer: Dan Marlowe (907)283-1329(0) (907)398-9904 (M) Second Call Engineer: Stan Golis (907)777-8356(0) Current Bottom Hole Pressure: 3,583 psi @ 8,958'TVD 0.400 lbs/ft(7.69 ppg)SITP 0 psig wl 1,050'fluid level Maximum Expected: 3,583 psi @ 8,958'TVD 0.400 lbs/ft(7.69 ppg)SITP 0 psig w/1,050'fluid level Maximum Potential Surface Pressure:2,697 psi Using 0.1 psi/ft gradient 20 MC 25.280(b)(4) SITP:0 psig on 09/02/2016,with 1,050'Fluid level Brief Well Summary The McArthur River G-29rd is a shut-in waterflood injector completed in the G-Zone and Hemlock benches. Hilcorp attempted to workover the well in 2014 to restore tubing by Inner annulus integrity without success. This project will convert the well to a "poor boy"gas-lifted producer using a t.ubing_,punched hole to ift_the well. Note:At completion of this project AA 005.007 will need cancelled. Last Casing Test:09/23/2014 2,500psig for 30 minutes l/ Procedure: 1. MIRU E-Line 2. Pressure test to 250psi low and 3,000psi high. 3. RIH and shoot Tubing Punch/ Lift Button at±3,000'. 4. Turn well over to production. 5. Conduct S and No-flow tests per AOGCC regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Current/Proposed (Same) • • McArthur River Field,TBU Well: G-29RD • SCHEMATIC Actual Completion: 9/25/14 PTD: 192-052 ttacorp Alaska,LEX 50-733-20374-01 RKB to TBG Hanger=41.35' CASING DETAIL LSIZE WT GRADE CONN ID TOP BOTTOM Note G 28" Driven Surf 324' 20" 94 H-40 Buttress 19.124" Surf 911' Cmtd 1814sx"G"1985 13-3/8" 61 K-55 Buttress 12.515" Surf . 3,080' Cmtd 4110sx"G"1985 L 13-3/8" 68 K-55 Buttress 12.415" 3,080' 6,572' DV Collar 9-5/8" 47 N-80, Buttress 8.681" Surf 10,078' Cmtd 1575sx"G"1985 S-95 (TOW) 7" 32 P-110 Buttress 6.094" 9,767' 13,538' Cmtd 1162sx"G"1992**235bb1s pumped w/30bbl Excess Cmtd Scab Liner.21 bbls 5" 15 L-80 Hyd 511 4.408" 11,678' 13,431' 15.8ppg cmt.No cmt to surf. El 13-3/8M2002 DV Collar TUBING DETAIL 1 - 12.6 TPL 4-1/2 13.5Bined L-80 4040 3.598" Surf 11,585 Polycore ID=3.68in Drift=3.4in L JEWELRY DETAIL No. Depth Depth ID OD Item (MD) (TVD) 1 11,489' 8,813' 3.560" 5.890" 7in 26-32#LTB Pkr(Ni) 2 11,495' 8,815' 2.920" 5.000" XO 4.5in LTC X 3.5in IBT 3 11,526' 8,831' 2.810" 4.250" 3.5in XN Nipple 2.75in nogo 4 11,527' 8,831' 2.441" 4.270" XO 3.5in Btc X 2-7/8in Btc 5 11,559' 8,847' 2.437" 3.220" Btm of 2-7/8 jnt&mule shoe(25.51 ft) 11,533' 8,834' 4.910" 5.980" Tag Top of Lwr 7in SAB Packer 6 11,585' 8,860' 2.992" 3.500" Btm of 3.5in Original Tbg Tail 7in liner top i 9-5/8in @ 9,767ftI L window @ Inc 49" ' 1 10,078ft ,e PERFORATION DATA 2 ZONE TOP BTM TOP BTM FT DATE Status Mt (MD) (MD) (ND) (ND) 3 0-1 11,788 11,809 8,958 8,978 21' 9/18/14 ' 0-1 11,790 11,890 8,960 9,009 100' 4/29/02 0-1 11,826 11,835 8,977 8,982 9' 9/17/14 G-1 11,852 11,882 8,990 9,005 30' 9/17/14 5 0-2 11,960 11,990 9,044 9,059 30' 4/29/02 G-3 12,050 12,065 9,089 9,097 15' 4/29/02 5in liner top �6 G-4 12,085 12,115 9,107 9,122 30' 4/29/02 @ 11,678ft 0-4 12,125 12,160 9,127 9,145 35' 4/29/02 Inc 61" , ,,,,,,t ,. `'S G-1 G-4 12,190 12,200 9,160 9,165 10' 4/29/02 G-5 12,250 12,307 9,191 9,220 57' 9/17/14 0-2 G-Zone G-5 12,318 12,326 9,225 9,229 8' 9/17/14 -r G-3 622ft 0-5 12,333 12,365 9,233 9,249 32' 9/17/14 G-4 0-5 12,250 12,370 9,191 9,251 120' 4/29/02 G-5 0-5 12,385 12,410 9,259 9,271 25' 4/29/02 Tag 12,599ft . HB 1 0-5 12,387 12,408 9,260 9,270 21' 9/17/14 HB-1 12,650 12,690 9,393 9,413 40' 4/29/02 Covered HB 3 H590ft k HB-3 12,940 12,960 9,534 9,543 20' 4/29/02 Covered HB-4 HB-3 13,010 13,040 9,567 9,581 30' 4/29/02 Covered • HB-4 13,190 13,240 9,650 9,672 50' 4/29/02 Covered 4/29/02:SLB TCP-Shot with 3.125"6SPF guns.4,650ft dry pipe and estimated 1,200psi underbalance L , under packer. 2002 Initial injection rate was 9-1lkbwipd. 2005 communication to IA. Went offline 2011 at 7-8kbwipd. TD=13,538'MD/9803'TVD 9/25/14 Completion:Initial bwipd=0. Perf:2.125in 11,788ft to 11,809ft 6spf.S-Line Tag 12,599ft(9-18). PBTD=13386'=5"landing collar Pump 100bb17%HCL.Final injection 2.5bpm-3,600bwipd. No:injection when brought on-line at Max hole angle=64 deg @ 13,300' 3,200psi header pressure. 60+deg from 11,400'to TD Updated: 12-01-14 by JLL a • • McArthur River Field,TBU Well: G-29RD • PROPOSED Actual Completion: 9/25/14 PTD: 192-052 Aliteorp Alaska,IA(' API: 50-733-20374-01 RKB to TBG Ha , . nger=41.35' CASING DETAIL SIZE WT GRADE CONN ID TOP BOTTOM Note 28" Driven Surf324' 20" 94 H-40 Buttress 19.124" Surf 911' Cmtd 1814sx"G"1985 t 13-3/8" 61 K-55 Buttress 12.515" Surf 3,080' Cmtd 4110sx"G"1985 L V► 13-3/8" 68 K-55 Buttress 12.415" 3,080' 6,572' DV Collar 9-5/8" 47 N-80' Buttress 8.681" Surf 10,078' Cmtd 1575sx"G"1985 S-95 (TOW) Tubing Pun, 7" 32 P-110 Buttress 6.094" 9,767' 13,538' Cmtd 1162sx"G"1992**235bbls @±3,000 pumped w/30bbl Excess Cmtd Scab Liner.21 bbls 13-3/8in 5" 15 L-80 Hyd 511 4.408" 11,678' 13,431' 15.8ppg cmt.No cmt to surf. DV Collar • 2002 id''`. TUBING DETAIL 12 6 TPL 4-1/2 13.55gned L80 4040 3.598" Surf 11,585 Polycore ID=3.68in Drift=3.4in r, JEWELRY DETAIL L DepthNo' (MD) (TVD) ID OD Item 1 11,489' 3.560" 5.890" 7in 26-32#LTB Pkr(Ni) 2 11,495' 2.920" 5.000" XO 4.5in LTC X 3.5in IBT 3 11,526' 2.810" 4.250" 3.5in XN Nipple 2.75in nogo 4 11,527' 2.441" 4.270" XO 3.5in Btc X 2-7/8in Btc 5 11,559' 2.437" 3.220" Btm of 2-7/8 jnt&mule shoe(25.51ft) p 11,533' 4.910" 5.980" Tag Top of Lwr lin SAB Packer ' 6 11,585' 2.992" 3.500" Btm of 3.5in Original Tbg Tail vu F• 7in liner top .. 9-5/8in @ 9,767ftI v window @ Inc 49° L I{I 1 , 10,078ft PERFORATION DATA 2 ZONE TOP BTM TOP BTM FT DATE Status ni (MD) (MD) (ND) (ND) 3 0-1 11,788 11,809 8,958 8,978 21' 9/18/14 NIP 4 G-1 11,790 11,890 8,960 9,009 100' 4/29/02 G-1 11,826 11,835 8,977 _ 8,982 9' 9/17/14 0-1 11,852 11,882 8,990 9,005 30' 9/17/14 _ 5 G-2 11,960 11,990 9,044 9,059 30' 4/29/02 G-3 12,050 12,065 9,089 9,097 15' 4/29/02 5inliner top6 G-4 12,085 12,115 9,107 9,122 30' 4/29/02 Mil@ 11,678ft G-4 12,125 12,160 9,127 9,145 35' 4/29/02 Inc 61° G_1 G-4 12,190 12,200 9,160 9,165 10' 4/29/02 G-5 12,250 12,307 9,191 9,220 57' 9/17/14 „ G-2 G-Zone G-5 12,318 12,326 9,225 9,229 8' 9/17/14 G-3 622ft 0-5 12,333 12,365 9,233 9,249 32' 9/17/14 G-4 G-5 . 12,250 12,370 9,191 9,251 120' 4/29/02 G 5 0-5 12,385 12,410 9,259 9,271 25' 4/29/02 • Tag 12,599ft , G-5 12,387 12,408 9,260 9,270 21' 9/17/14 HB-1- HB-1 12,650 12,690 9,393 9,413 40' 4/29/02 Covered HB-3 Hemlock HB-3 12,940 12,960 9,534 9,543 20' 4/29/02 Covered 590ft HB-4..- HB-3 13,010 _ 13,040 9,567 9,581 30' 4/29/02 Covered HB-4 13,190 13,240 9,650 9,672 50' 4/29/02 Covered 4/29/02:SLB TCP-Shot with 3.125"6SPF guns.4,650ft dry pipe and estimated 1,200psi underbalance G \ under packer. 2002 Initial injection rate was 9-11 kbwipd. 2005 communication to IA. Went offline 2011 at 7-8kbwipd. TD=13,538'MD/9803'TVD 9/25/14 Completion:Initial bwipd=O. Pert 2.125in 11,788ft to 11,809ft 6spf.S-Line Tag 12,599ft(9-18). PBTD=13386'=5"landing collar Pump 100bbI 7%HCL.Final injection 2.5bpm-3,600bwipd. No injection when brought on-line at Max hole angle=64 deg @ 13,300' 3,200psi header pressure. 60+deg from 11,400'to TD Updated: 09/02/16 by JLL # ► 14 Grayling Platform G-29RD Current Hilrurp Aln.ku.I.i.t: Grayling 29RD Tubing hanger,CIW-DCB, 20 X133/8X95/8X 11X4Y EUE 8rd lift and 4 1/2 4'A TC-2 susp,w/4"type H BPV profile,7"EN,%" non continuous control line BHTA,CIW,4 1/16 5M Full Stainless Steel FE X Internal Acme knockup 101610/ w. Valve,swab,WKM-C, 4 1/16 5M FE,HWO, / �® ref®(o 1, Valve,Safety,WKM-M, T-26 4 1/16 5M FE,w/15" CO Safeco operator ■1�,tl _ T-26 Trim Tee,stdd,4 1/16 5M X I y 4 1/16 5M FF material In 11.:, ° ,111 Valve,lower master,WKM-C, • ®® 4 1/16 5M FE,HWO,T-26 tf& -.0- `g ®p® • NW ., Adapter,CIW-FBB,11 5M Stdd _ f' X 4 1/16 5M,prepped for 7" __ extended neck,no control line ' ' alport ' ■ ■ Ili. III — MI Tubing head,CIW-DCB, ,,, Valve,CIW-FC,2 1/16 5M FE, 13 5/8 5M X 11 5M,w/2- ® o ® HWO,AA 2 1/16 5M SSO,X-bottom I 1■ °�!" ti..: prepre w/R seal .I i:' :- • p p �i 1%VR profile1.1 * Ill 1.1 +11 '4 Test good 2/15/2012 1;"!" r 250/2500psi qn_I I- 11 MIL Test good 2/15/2012 till � f 250/1000psi Casing head,CIW-WF,21'A 2M X 20"SOW bottom, It/l 11!1 w/2-2 1/16 2M EFO71•• i - 1116 I .I■IM��1I,1 2"LP ball valve ill P ■r ` • • Schwartz, Guy L (DOA) From: Dan Marlowe <dmarlowe@hilcorp.com> Sent: Wednesday, November 09, 2016 2:44 PM To: Schwartz,Guy L(DOA) Cc: Bettis, Patricia K(DOA) Subject: RE:G-29RD (PTD 192-052) convert to Prod. G/Lift The biggest driver of this project is to give the platform a place to put liftgas as we are currently overlifting most of our wells as we cannot turn down the compression rate low enough.This well is a good candidate to cycle gas through and possibly even pick up a few bbls of production. It is a good candidate as we never were able to get a valid MITIA after the rig left even though we got a workover MITIA. In addition we were never were able to get the well to take any fluid. Our ultimate plan is to sidetrack the well but in the meantime would like to get some utility out of it.The tubing has a thick plastic liner in it that won't allow for a POGLM. From:Schwartz,Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:November 09,2016 2:32 PM To: Dan Marlowe<dmarlowe@hilcorp.com> Cc: Bettis, Patricia K(DOA)<patricia.bettis@alaska.gov> Subject:G-29RD(PTD 192-052)convert to Prod.G/Lift Dan, Can you elaborate on what the RWO in 2014 did not accomplish and why? Is there still a tubing leak or casing leak? Why not run a POGLM over the tubing punch to help regulate gas flow and keep the tubing integrity. Guy Schwartz Sr. Petroleum Engineer 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(907-793-12261 or(Guy.schwartz@alaska.gov). 1 • s Wallace, Chris D (DOA) From: Wallace, Chris D (DOA) Sent: Monday, September 19, 2016 3:57 PM To: 'Larry Greenstein' Subject: RE: Request for Temporary Injection into G-29RD PTD# 1920520 Larry, One month injection for diagnostics and monitoring coupled with the plan detailed below is approved. 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: Larry Greenstein [mailto:Igreenstein©hilcorp.com] Sent: Wednesday, September 14, 2016 1:10 PM To: Wallace, Chris D (DOA) Subject: Request for Temporary Injection into G-29RD PTD # 1920520 Hi Chris To summarize the integrity issue for the Grayling G-29RD well: The G-29RD well has been on the LTSI list since a couple of failed WO attempts to fix the mechanical integrity, one in 2012 and again in 2014 (see attached 404s which include schematics). We have temperature surveys from the 2000s when the well was on an AA(AIO 5.007), so we have baseline temp data, but we haven't done any surveys since the failed integrity WOs. Hilcorp would like to request a one month temporary injection period to establish a stable downhole temperature profile which will be compared to a baseline temp survey done previously. Should the overlay prove definitively that the injected water is going into the approved EOR strata, we will be requesting by separate e-mail a RTI for this well. Please let me know if anything else is needed to proceed with this request. Thank you Larry NNR JAN 0 2017 XHVZE Pages NOT Scanned in this Well History File This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. File Number of Well History File PAGES TO DELETE Complete RESCAN [] Color items - Pages: Grayscale, halftones, pictures, graphs, charts-. Pages: Poor Quality Original- Pages: [] Other- Pages: DIGITAL DATA Diskettes, No.t n Other, No/Type OVERSIZED · [] ' Logs-of various kinds [] Other COMMENTS: r'i Scanned by: Dianna Vincent Nathan Lowell -- TO RE-SCAN Notes: - Re-Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: /si t , Ty • • ®F 0�1 \ \I //7, 4. THE STATE Alaska Gil and Gas Of ms vatiGn COMMiSSiGEL GOVERNOR SEAN PARNELL 333 West Seventh Avenue ALAS'" Anchorage, Alaska 99501 -3572 Main: 907.279.1433 Fax: 907.276.7542 SCANNED JUN 0 7 20f Ted Kramer © 5 Sr. Operations Engineer a` Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: McArthur River Field, Hemlock Oil and Middle Kenai Gas Pools, TBU G -29RD Sundry Number: 313 -261 Dear Mr. Kramer: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this 3 day of June, 2013. Encl. • w ' STATE OF ALASKA te3 ` .. - ; z.4 9n ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS A0G 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pod ❑ Repair Well El • Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate El Pull Tubing El • Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other. ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Hilcorp Alaska, LLC Exploratory ❑ Development ❑ 192-052 3. Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic ❑ Service p - 6. API Number. Anchorage, AK 99503 50- 733 - 2037401 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No El Trading Bay Unit / G -29RD • 9. Property Designation (Lease Number): 10. Field /Pool(s): ADL 0017594. McArthur River Field / Hemlock Oil and Middle Kenai Gas Pools . 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): 13,538 ' 9,803 - • 13,386 • 9,736 None N/A Casing Length Size MD TVD Burst Collapse Structural 324' 28" 324' 324' Conductor 911' 20" 911' 911' 1,530 psi 520 psi Surface 6,572' 13 -3/8" 6,572' 5,608' 3,090 psi 1,540 psi Production 10,078' 9 -5/8" 10,078' 7,810' 6,870 psi 4,760 psi Liner 3,771' 7" 13,538' 9,803' 11,640 psi 10,760 psi Liner 1,753' 5" 13,431' 9,756' 8,290 psi 7,250 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 4 -1/2" 12.6# / L -80 833' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): SAB Inj Packer / SSSV - N/A • 11,544' (MD) / 8,840' (TVD) and SSSV - NA 12. Attachments: Description Summary of Proposal El • 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch El • Exploratory ❑ Stratigraphic ❑ Development ❑ Service El - 14. Estimated Date for 15. Well Status after proposed work: 8/1/2013 Commencing Operations: Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ G ' 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 Ted Kramer Email tkramertc7i_hilcorp.com Printed Name Ted Kramer Title Sr. Operations Engineer Signature �C��� �` Phone (907) 777 -8420 Date 5/24/2013 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31 2C0 1 Plug Integrity ❑ BOP Test i Mechanical Integrity Test IIQ / Location Clearance ❑ Other: >k Z 5'6o L ,36P lc s r BDMS JUN — 5 20i3 U/1--,04,....t. o p 2.-! /T'i O v. Spacing Exception Required? Yes ❑ No L1 Subsequent Form Required: /0 -- 40 cy APPROVED BY /1 Approved by: a, COMMISSIONER THE COMMISSION Date: C d 7 Form 10-403 (Revised 10/2012) Ap iliG1 iNli�o 12 months from the date of approval. Attach ents in Duplicate `\ \ on • • Well Work Prognosis Well: G -29RD Hilcorp Alaska, PLC Application Date: 05/24/2013 Well Name: G -29RD API Number: 50- 733 - 20374 -01 Current Status: Active Water Injector Leg: Leg #4 (SW corner) Estimated Start Date: August 1, 2013 Rig: Williams Rig 404 Reg. Approval Req'd? 10 -403 Date 10-403 submitted: Regulatory Contact: Juanita Lovett Permit to Drill Number: 192 -052 First Call Engineer: Ted Kramer (907) 777 -8420 (0) (985) 867 -0665 (M) Second Call Engineer: Mike Dunn (907) 777 -8382 (Office) (907) 351 -4191 (M) Pressures: The well is a shut -in injector. The well has 0 psi on the tubing and will not hold a full column of seawater. The estimated bottom hole pressures are based on previous static surveys and recent fluid level shots. Current BHP: — 3,500 psi @ 9,324' TVD/12,515' MD .38 psi /ft., (7.2 ppg) at mid -pert of G &H Max. Expected BHP: — 3,500 psi @ 9,324' TVD .38 psi /ft. (Same zone re- perforated) Max. Anticipated Surface Pressure: 0 psi Using 0.435psi /ft. SW gradient to surface Brief Well Summary G -29RD is currently a shut in water injector that has a bottom -hole location in the middle fault block of the Northwest feature. When injecting, it supports G -13 and G -28RD producers. When injecting, the well took between 9,000 and 11,000 bwipd from 2002 to 2005. In May 2005 the well experienced communication between the tubing and casing. Administrative approval was granted on September 23, 2005 to allow injection, with bi- annual temperature surveys run to confirm water was staying in zone. In September 2011. while attempting to run a temper ture survey, the tubing was found to be parted at 1,024'. M 5.c 7 - ( ,,�- , a e , ) l S 31 /3 In fall of 2012 an attempt was made to work over this well and repair the tubing. The tubing was removed but attempts to mill the packer were unsuccessful. At the time there was some question about possible casing damage. A Kill string was ran into the well and the well suspended. The ob'ective of this workover is to re •air the well. A camera will be run to confirm we have casing integrity. Then a work plan will be devised based on Camera results to finish milling the packer and remove it. The well will then be cleaned out to 13,290 feet, re- perforated and a new completion ran. Procedure: 1. Skid Williams Rig 404 over the G -29RD well slot. Raise mast. Prepare for wellwork operations. 2. Plumb FIW lines to circulate down the annulus and up the tubing, when the tubing is pulled out of the packer. 3. Notify AOGCC of pending BOPE test. Set BPV, ND tree, NU BOPE. Test all BOP equipment per AOGCC guidelines to 250 psi LOW and 2,500 psi HIGH. Test Annular BOP to 250 psi LOW and 1500 psi HIGH. 4. POOH with Kill String standing back. 5. PU RIH with 3 -1/2" PH -6 Workstring to 11,544 ft. • • • 11 Well Work Prognosis Well: G -29RD Hilcorp Alaska, LLC A pplication Date: 05/24/2013 6. Displace well fluid with Clear FIW. 7. RU E -line. RIH with camera to 11,544 to look at SAB Injection packer (partially milled). 8. Consult with town, develop plan for correct BHA, RIH with packer milling assembly to 11,544. Engage packer and mill up Packer. POOH with Mill. 9. PU TIH with overshot, assembly to 11,546', engage and remove packer. 40. PU 7" 32# C/O assembly. RIH with Same and clean out 7" liner to top of 5 -1/2" liner at 11,678'. POOH with same. , 11. PU RIH with 5" 15# c/o assembly and RIH cleaning out 5" liner from 11,678 to 13,386'. POOH and lay down same. 12. PU 7" RTTS test packer and RIH to 11,600 ft. Set and,pressure test 9 -5/9" and 7" casing to 1,500 psi for 30 min y es.Chart same. POOH with Test packer. 13. MU storfn pac�cerRIH to 100'. Set same. POOH to change out tubing head 14. ND BOP and install a new tubing head. NU BOP, test BOPs. RIH, pull storm packer. LD same. 15. MU Schlumberger TCP guns on workstring and RIH. RIH with E -line or memory GR tool on slickline. Position guns to perforate as follows, using the Hilcorp Digital Database Log (DDL) as the reference log. Proposed Perforations: Zone Top Bottom Feet G1 11,790 11,890 100 G2 11,940 11,950 10 G2 11,960 11,990 30 G3 12,050 12,065 15 G4 12,085 12,115 30 G4 12,125 12,160 35 G4 12,190 12,198 8 G5 12,250 12,370 120 G5 12,385 12,410 25 G7 12,544 12,590 46 HK1 12,650 12,700 50 HK3 -4 12,880 13,240 360 Total: 829' 16. Fire Guns. Circulate perf gas and shut down and monitor fluid level for one hour. • Note: It is OK to fill the hole periodically with clean FIW since this will be an injector. Do not pump polymer and /or salt to slow the fluid Toss. Once the well is determined to be static, POOH. 17. POOH with guns. LD same. Confirm that all charges fired. 18. PU 4 -1/2" X 7" packer and 4 -1/2" tubing. RIH. Space out and set packer at +/- 11,600'. Land the tubing hanger, and pressure up backside to confirm packer is set. Hold 2,500 psi for 30 minutes for the casing MIT test. If the pressure does not decline more than 250 psi in 30 minutes, the well has passed the Workover MIT. Provide Larry Greenstein with the pressure test results and the completed 10 -426 form for the MIT. • • Well Work Prognosis Well: G -29RD Hilcorp Alaska, LLC Application Date: 05/24/2013 19. Set BPV. ND BOPE and NU tree. Test tree. 20. Turn well over to Production. 21. Within 2 weeks of stable injection, schedule an Initial MIT with AOGCC. Provide the AOGCC 24 hour notice prior to the MIT test. All pressure test results and completed 10 -426 are to be provided to Larry Greenstein immediately following the test. �� � T-� / 04sses /'esc;hd ,47D 54 67 Attachments: CA Q +prod ) As -Built (Old) Wellbore Schematic Proposed (New) Wellbore Schematic BOP Schematic r 3113' Attachment #1 • • • 1 McArthur River Field, TBU S CHEMATIC Well: G -29RD Hilcorp Alaska, LLC Actual Completion: 4/30/02 CASING DETAIL RKB to TBG Hanger = 41.35' SIZE WT GRADE CONN TOP BOTTOM Note ,i 28" Driven Surf 324 20" 94 H-40 Surf 911 13-3/8" 68 K-55 Surf 6,572' 13 -3/8" 3,080' DV Collar z , 9 -5/8" 47 N -80, 5 -95 Buttress Surf 10,078' 7" 32 P -110 Buttress 9,767' 13,538' 5" 15 L -80 Hyd 511 11,678' 13,431' Cement Scab Liner TUBING DETAIL 13 - 3/8" • • 4 - 1/2" 12.6 L -80 SC BTC Surface 833' Kill String DV Collar 3 -1/2" 9.2 L -80 SC BTC 11,544' 11,625' JEWELRY DETAIL No. Depth Item 1 11,544' 3 -1/2" x 7" SAB injection packer w /MOE Model "K" anchor in top of pkr. Partially Milled 2 11,589' 3 -1/2" X nipple, 2.813" ID 3 11,625' 3 -1/2" tubing tail with Hydrotrip sub X 4 11,678' 5" x 7" ZXP liner top packer 5 13,386' 5" liner Float Collar Ak ‘,,or PERFORATION DATA t ZONE TOP(MD) BTM(MD) TOP(TVD) BTM(TVD) DATE G -1 11,790' 11,890' 8,960' 9,009' Perf 4/29/02 top @r G-2 11,960' 11,990' 9,044' 9,059' Perf 4/29/02 Perf 4/29/02 9,767, G-3 12,050' 12,065' 9,089' 9,097' 9-5/8" G-4 12,085' 12,115' 9,107' 9,122' Perf 4/29/02 L ' n'' 1 , window G 4 12,125' 12,160' 9,127' 9,145' 9,165' Perf 4/29/02 @ G-4 12,190' 12,200' 9,160' Perf 4/29/02 10,078' G -5 12,250' 12,370' 9,191' 9,251' Perf 4/29/02 MB 2 G -5 12,385' 12,410' 9,259' 9,271' Perf 4/29/02 I t l,7 g, HB-1 12650 12,690' 9,393' 9,413' Perf 4/29/02 3 " 4 HB -1 12,670' 12,680' 9,403' 9,408' 1992 Frac Stim. "it' HB -3 12,940' 12,960' 9,534' 9,543' Perf 4/29/02 r.'i ?°'I HB -3 13,010' 13,040' 9,567' 9,581' Perf 4/29/02 " ; s . t HB -3, 4 12,868' 13,215' 9,500' 9,661' Perf 92' - 7" , HB -4 13,190' 13,240' 9,650' 9,672' Perf 4/29/02 �,,* 5 ""Et., • tip$ TD = 13,538' MD/9803' TVD PBTD = 13,386' = 5" landing collar Max hole angle = 64 deg @ 13,300' 60+ deg from 11,400' to TD Revised 9.24.12 by TDF .. 14 • • McArthur River Field, TBU PROPOSED well: G -29RD Hilcorp Alaska, 11.1,C Actual Completion: Future RKB to TBG Hanger = 41.35' CASING DETAIL .] L. SIZE WT GRADE CONN TOP BOTTOM Note 28" Driven Surf 324 20" 94 H -40 Surf 911 13 -3/8" 68 K -55 Surf 6,572' 13 -3/8" 3,080' DV Collar L , 9 -5/8" 47 N-80, S-95 Buttress Surf 10,078' 7" 32 P -110 Buttress 9,767' 13,538' 5" 15 L-80 Hyd 511 11,678' 13,431' Cement Scab Liner 13 - 3/8" • • TUBING DETAIL DV Collar 4 - 1/2" 12.6 L Surf ±11,650' JEWELRY DETAIL No. Depth Item 1 ±11,600' 4 -1/2" x 7" SAB injection packer w /MOE Model "K" anchor in top of pkr 2 ±11,640' 4 -1/2" X nipple, 2.813" ID 3 ±11,650' 4 -1/2" tubing WLEG with Hydrotrip sub 7" liner top PERFORATION DATA @ 9,767' TOP BTM TOP BTM ZONE DATE (MD) (MD) (TVD) (TVD) 9-5/8" G -1 ±11,790' ±11,890' ±8,960 ±9,009 Perf 4/29/02; Reperforate Future window @ G -2 ±11,940' ±11,950' ±9,034 ±9,039 Perforate Future 10,078' G -2 ±11,960' ±11,990' ±9,044 ±9,059 Perf 4/29/02; Reperforate Future A 1 , G -3 ±12,050' ±12,065' ±9,089 ±9,097 Perf 4/29/02; Reperforate Future 2 G -4 ±12,085' ±12,115' ±9,107 ±9,122 Perf 4/29/02; Reperforate Future mom G -4 ±12,125' ±12,160' ±9,127 ±9,145 Perf 4/29/02; Reperforate Future G -4 ±12,190' ±12,198 ±9,160 ±9,164 Reperforate Future 3 G -4 12,190' 12,200' 9,160 9,165 Perf 4/29/02 G -5 ±12,250' ±12,370' ±9,191 ±9,251 Perf 4/29/02; Reperforate Future G -1 G -5 ±12,385' ±12,410' ±9,259 ±9,271 Perf 4/29/02; Reperforate Future i *" ` # *"." G -2 G -7 ±12,544' ±12,590' ±9,339 ±9,362 Perforate Future HB -1 ±12,650' ±12,700' ±9,393 ±9,418 Perf 4/29/02; Reperforate Future ` .a `, k� - - G -3 HB -1 12,670' 12,680' 9,403 9,408 1992 Frac Stim. „,/01-,0 " ' G -4 HB -3 12,940' 12,960' 9,534 9,543 Perf 4/29/02 ..+P G -5 HB -3 13,010' 13,040' 9,567 9,581 Perf 4/29/02 ° °' ` G -7 HB 3' 12,868' 13,215' 9,500 9,661 Perf 92' - 7" 4 _ HB-1 4 ' HB - 3 HB -3, 4 ±12,880' ±13,240' ±9,505 ±9,672 Perforate Future .. � HB -3,4 HB -4 13,190' 13,240' 9,650 9,672 Perf 4/29/02 .. i .r ys t _ HB -4 TD = 13,538' MD/9803' TVD PBTD = 13386' = 5" landing collar Max hole angle = 64 deg @ 13300' 60+ deg from 11400' to TD Updated: 05 -23 -13 by JLL . • • Grayling Platform Williams Rig BOP (rental) 1/18/2013 fiikn� , 11w4km. LIA; Grayling Platform 2013 Workovers BOP Drawing (Williams) 111 '11111111111 111 IN I I r l r1 rii tit 3.42' li l 1‘111111141 I1 11I I ti III III 4.54' — 1 41 , -- II Booster bon ets on botto —. IiI 111 lil lip III Kill Side 2 1/16 5M w/ check valve ; ; III up iv 111. Choke side 2. ��� { •} {w } {w } { ��� 2 1/16 5M w/ HCR and and Unibolt line �; • f II, ( l i t lit di Ii1 Iil 1 � °� 00' °�'�` Unibolt line connection connection 1.00' to 2.00' III 1I1 III III III Drill deck Riser 11 5M FE X 16.00' 11 5M FE 111 lil Ii, t1l 111 111 111141 1II III Spacer spool 3.00' 11 5M FE X 11 5M FE lil lip fit lip 111 • • Williams Rig 404 BOP Test Procedure Hilcorp Alaska, LLC Attachment #1 Attachment #1 Hilcorp Alaska LLC. BOP Test Procedure: Williams Rig 404, Grayling WO Program — Oil Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. • Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Shoot fluid level at least 24 hours before moving on well. 4) Shoot fluid level again, right before ND /NU. Confirm that well is static. Initial Test (i.e. Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2 -way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If BPV profile is eroded and /or corroded and BPV cannot be set with tree on, Profile and /or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. Conduct Rolling Test. 1) Attempt to set BPV through tree. If unsuccessful, shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV. As approved in the sundry, proceed as follows: a) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2 -way valve, or prepare lift- threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2 -way check valve by hand, or MU landing (test) joint to lift- threads d) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test, notify office via e-mail that neither profile will allow for a test of the BOP. As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE b) With stack out of the test path, test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) • • Williams Rig 404 BOP Test Procedure Hilcorp Alaska, LLC Attachment #1 d) Hold a constant pressure on the equipment and monitor the fluid /pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f) Record and report this test with notes in the remarks column that the tubing hanger /BPV profile wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests (i.e. Test Plug can be set in the Tubing -head) 1) Remove Wear bushing. a) Use inverted test plug to pull wear busing. MU to 1 jt. of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same, and RIH on 1 joint of tubing. Install a closed TIW or lower Kelly valve in top of test joint. 3) Break joint off test plug and pull up to space the bottom of tool joint above blind rams. 4) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2 -way check or test plug is set) 1) Fill stack with rig pump and install chart recorder on the stack side of the pump manifold. 2) Note: When testing, pressure up with pump to desired pressure, close valve on pump manifold to trap pressure and read same with chart recorder. 3) Referencing the attached schematics test rams and valves as follows. a) Close C -1 (inside gate valve on choke side of mud cross) and close the annular preventer. Pressure test to 200 psi for 5 minutes and 1,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open annular. b) Close Pipe Rams. Test to 200 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open pipe rams. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack, test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 200 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open rams. d) Open C -1. Flow through the choke manifold and purge air. Test the choke manifold starting with the outer most valves, to 250 psi low and 3,000 psi high, for 5 minutes each, as follows: (Valve numbers are in reference to Diagram B) i) Valves 1, 2, 10. After test, open same. • • Williams Rig 404 BOP Test Procedure Hilcorp Alaska, LLC Attachment #1 ii) Valves, 3, 4, 9. After test, open valves 3 & 4. Leave 9 closed. iii) Valves 5, 6, 9. After test, open valves 5 & 6, leave 9 closed. iv) Valves, 7, 8, 9. After test, open all valves. e) Close C -2. This is the HCR (the hydraulic controlled remote) valve just outside C -1 on choke side of mud cross. Test to 250 psi low and 3,000 psi high. After test, open HCR, close C -1. f) Blind Rams. Make sure test joint is above the blind rams. Close blind rams. Test to 200 psi Low for 5 minutes and 3,000 psi High for 5 minutes. Bleed down pressure. g) Bleed off all pressure. Line up pumps to pump down tubing. h) Test K -1, K -2, and K -3 on the kill (pump -in) side by pressuring up on tubing. Test to 200 psi Low for 5 minutes and 3,000 psi High for 5 minutes. i) Test floor valves TIW (or Lower Kelly Valve) and IBOP. STANDARD TEST PROCEDURE OF CLOSING UNIT (ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record "Accumulator Pressure ". It should be +/- 3,000 psi. 3) Close Annular Preventer, the Pipe Rams, and HCR. Close 2 " set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read "10 bottles at 2,150 psi "). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually +/- 30 seconds. 8) Once 200 psi pressure build is reached, turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut -off after the pressure to builds back to original pressure ( +/- 3,000 psi). Note: Make sure the electric pump is turned to "Auto ", not "Manual" so the pumps will kick -off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves, for correct operating position 3) Fill out the AOGCC BOPE Test Form (10 -424) in Excel Format and e-mail to AOGCC and Juanita Lovett. • • Williams Rig 404 BOP Test Procedure Hileorp Alaska, LLf. Attachment #1 Diagram A -1: Grayling BOP stack and Riser Arrangement — Typical for Single Completion Grayling Platform 2013 Workovers BOP Drawing (Williams) W 1; iii i .111 11111 '(i III 3.42' Shaffer 11 "5M II Iii 'hi Y 111 111 1 1 4.54' Cu C -- i[�I' .1i —d oll Booster bon: is on bottom •: •'I -- 111 r 1 1 ,1 1 11 Kill Side Choke side 21/16 5M w/ check valve A , ; A , . 1.1" I1� �!� �i� ; y,• 2.00' ; { •} ��; } •I ' { } 21/16 5M w/ HCR and and Unibolt line , I ,II, r , II { . c } 711 ( � IIQII �l connection I1�li1 III Ill 111 Unibolt line connection 1.00' to 2.00' 111 111 111 111 111 Drill deck Riser 11 5M FE X 16.00' 11 5M FE 111 ;11 lil iil III III 1/! III IF III Spacer spool 3.00' 11 5M FE X 11 5M FE III '.II 1'II :11 • • Williams Rig 404 BOP Test Procedure Attachment #1 Hilcorp Alaska, lit.. Diagram A -2: Grayling BOP stack and Riser Arrangement — Typical for Dual Completion Williams Workover Rig Grayling Platform BOP 2012 • - 111111 ___ — 1.44' 111 Ill lli 1 zoo I11 iii illlll1* 1 • • 1 li iii iii III I(I Weatherford Rental BOP • Width 4.16' 3. 74' Shaffer 13 5/8 6M lit Ile 13 5/8 6M LWS Shaffer 13 LWS 6M — a 5/8 =� dimensions Length 7.od © _ Length ].]3' 3.00' Width across body 2.72' .� _ Width across flanged - e ., outlets 4.00' — = :1 I ll IIl1 t til 1 •`arl ` ul lil' Ij K - K -2 K -1 C -1 C -2 "11CR" Mud Cross Riser above drill deck This number will vary from well to well 1.00' to 3.00' Drill Deck 13 518 6M Riser 86001133 135/85MX 3 1/8 5M EFO 19.00 III !if Ill III Spacer Spool 135/85M X 136/86M 1.95' 18001bs Ill I Ifl Ii! Crossover Spool 136/36M X116M 18001bs 2.83 Ill III Top of Wellhead II • • Williams Rig 404 BOP Test Procedure Hilrorp ,Ua.ka. Lt,' Attachment #1 Diagram B: Grayling Choke Manifold To Gas Buster All National type To Panic line 2 1/16 5M 1502 Union ball valves MI 4m ..... i l l ,, : -3.. ,I.,,: ,.., . ,,_,,, 25 1. , , l "' Chokes are 90 degrees off in drawing in order to show 1 detail : 1 : 1 r 3 I 1 4 1 r - - I I - , 11 1111 I 111 111 IS i1 - Swaco :I . I]: I — 7)45 III i i l, , , i ii e „1 , ;kiiiiii ,i, - _ III I 1 i I I ° ICI - 0..- From Bop Choke Line 2 1/16 5M Unibolt Flange Valve Type #1 National Ball Valve B3260, 3 1 /4" Ball port, 6000psi working pressure #2 National Ball Valve B3260, 3'/4" Ball port, 6000psi working pressure #3 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #4 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #5 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #6 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #7 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #8 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #9 National Ball Valve B3260, 3'/4" Ball port, 6000psi working pressure #10 National Ball Valve B1560, 1 ' /2" Ball port, 6000psi working pressure z WILLIAMS RIG #404 A ... FLUID FLOWDIAGRAM ... = NORMAL OPERATIONS CIRCULATING DOWN CASING, UP TUBING "REVERSE CIRCULATING" STANDPIPE PANIC LINE ❑ • 0 4 0 r -- _.. „PANIC 4� o f f r TRIPPER ,,/ HEAD 11-1-1 IIII O BGP — MANUAL AUTO VATIC CHOKE CHOKE C 0 la = 11 1?I` l I ?I : 0 : C 0.406 STACK I PUMP --41. X" �.. . PUMP C ` \ MANIFOLD `NCR VALVE ..)15 LP G AS SUCTION e USTEM \ LINE (• • -A FLUID TPNKPIT rt CO G Cu V1 H lD ' F' al O C. A C CD CD x - 4 M WILL LAMS RIG #404 FLUID F LOW DIAGRAM NORMAL OPERATIONS CIRCULATING DOWN TUBING, UP CASING ANNULAS 'THE LONG WAY" STANDPIPE PANIC LINE v • ❑ I I . e ( D9 C4 ■ % z 0 f c TRIP PEP. . BOP i HERD .•.. ` L P B t1 ANURL ❑� AUTO MATE. - O - C STACK C HOKE CHOKE MUD O I_I . I - - PUMP - ply Iii, PUMP „ C `\ • MANIFOLD , \-- HO! VALVE LP GAS i>16 SUCTION e USTEI . LINE /1 • D co g FLUID TANK/PIT cu Tr n --i Isi 3 o F'' (D 0 C. A C (ii .,, • • Grayling Platform 1 G -29RD Proposed 05/24/2013 Hilrnrp :tla.kn. 1.1.t wA Grayling 29RD Tubing hanger, CIW -DCB, 20 X13 3/8 X 9 5/8 X 4 11 X 4'A EUE 8rd lift and 1/2 4 Y2 TC -2 susp, w/ 4" type H BPV profile, 7" EN, 'A" non continuous control line BHTA, CIW, 41/16 5M Full Stainless Steel FE X Internal Acme knockup Valve, swab,WKM -C, _ ` 4 1/16 5M FE, HWO, arc o h a O Valve, Safety, WKM -M, T -26 4 1/16 5M FE, w/ 15" p®p 3 Safeco operator #te r , T -26 Trim Tee, stdd, 4 1/16 5M X 4 1/16 5M I O FF material ;.. O I. Valve, lower master, WKM -C, e 10 4 1/16 5M FE, HWO, T -26 -' o 0 O0O ) •. ,.� Adapter, CIW -FBB, 11 5M Stdd X 4 1/16 5M, prepped for 7" extended neck, no control line port Tubing head, CIW -DCB, Valve, CIW -FC, 2 1/16 5M FE, 13 5/8 5M X 11 5M, w/ 2- , HWO,AA 2 1/16 5M SSO, X bottom I �� I 4 prep w/ R seal 1'A VR profile i t l I I I I Test good 2/15/2012 ����� 250/2500psi Casing spool, CIW -WF, su ( I 21% 2MX135/85M, EtiE i. E. 0 , w/ 2- 2 1/16 5M EFO, I lli me 11111 1111111-1. PP bottom prep UN M C_ Test good 2/15/2012 � 250 /1000psi Casing head, CIW -WF, i 21'''% 2M X 20" SOW bottom, ltl 111 w/ 2- 2 1/16 2M EFO 11-111 � Ill i � ILI'll i 2 "LP ball valve ll Nor STATE OF ALASKA ALA OIL AND GAS CONSERVATION COM ION REPORT OF SUNDRY WELL OPERATIONS — 01 Aerations Abandon ❑ Repair Well 0 Plug Perforations ❑ Perforate El Other Performed: Alter Casing ❑ Pull Tubing 0 Stimulate - Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat. Shutdown❑ Stimulate - Other ❑ Re -enter Suspended WeII❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development ❑ Exploratory ❑ 192 -052 3. Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic Service 0 6. API Number: Anchorage, AK 99503 50- 733 - 20374 -01 -00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0017594 –* Trading Bay Unit / G -29RD 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): N/A McArthur River Field / Hemlock Oil and Middle Kenai Gas Pools 11. Present Well Condition Summary: Total Depth measured 13,538 feet Plugs measured None feet true vertical 9,803 feet Junk measured N/A feet Effective Depth measured 13,386 feet Packer measured 11,544 feet true vertical 9,736 feet true vertical 8,840 feet Casing Length Size MD TVD Burst Collapse Structural 324' 28" 324' 324' Conductor 911' 20" 911' 911' 1,530 psi 520 psi Surface 6,572' 13 -3/8" 6,572' 5,608' 3,090 psi 1,540 psi Production 10,078 9 -5/8" 10,078' 7,810' 6,870 psi 4,760 psi Liner 3,771' 7" 13,538' 9,803' 11,640 psi 10,760 psi Liner 1,753' 5" 13,431' 9,756' 8,290 psi 7,250 psi Perforation depth Measured depth See Schematic feet SCANNED JAN 2 8 2013 True Vertical depth See Schematic feet 3 -1/2" 9.2# L -80 11,625' (MD) 8,879' (TVD) Tubing (size, grade, measured and true vertical depth) 4 -1/2" 12.6# L -80 833' (MD) 833' (TVD) 11,544' (MD) Packers and SSSV (type, measured and true vertical depth) SAB Inj. Packer 8,840' (TVD) SSSV N/A 12. Stimulation or cement squeeze summary: RECEIVED Intervals treated (measured): N/A SEP 2 4 2012 Treatment descriptions including volumes used and final pressure: //'�+ 13. Representative Daily Average Production or Injection Data AOGCC Oil-Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: N/A N/A 0 0 0 Subsequent to operation: N/A N/A 0 0 0 14. Attachments: 15. Well Class after work: _ Copies of Logs and Surveys Run Exploratory❑ Development❑ Service IS Stratigraphic ❑ Daily Report of Well Operations x 16. Well Status after work: _ Oil ❑ Gas ❑ WDSPL❑ GSTOR ❑ WINJ IS 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: 312 -255 Contact Michael Dunn Printed Name Mich 1 Dun Title Sr. Reservior Engineer Signature Phone (907) 777 -8382 Date 9/24/2012 R3DMS SEP 2 5 2012 W. \ '3 � Form 10 -404 Revised 11/2011 `U� > � Submit Original Only e • • McArthur River Field, TBU 1 SCHEMATIC Well: G -29RD Hilcorp Alaska, IAA: Actual Completion: 4/30/02 CASING DETAIL RKB to TBG Hanger = 41.35' SIZE WT GRADE CONN TOP BOTTOM Note 28" Driven Surf 324 1 I I 20" 94 H -40 Surf 911 L 68 K -55 Surf 6,572' 1133--33//88:: " 3,080' DV Collar L , 9 -5/8" 47 N -80, 5 -95 Buttress Surf 10,078' 7" 32 P -110 Buttress 9,767' 13,538' 5" 15 L -80 Hyd 511 11,678' 13,431' Cement Scab Liner TUBING DETAIL 13 - 3/8" 1 4 -1/2" 12.6 L -80 SC BTC Surface 833' Kill String DV Collar 3 -1/2" 9.2 L -80 SC BTC 11,544' 11,625' JEWELRY DETAIL No. Depth Item 1 11,544' 3 - 1/2" x 7" SAB injection packer w /MOE Model "K" anchor in top of pkr. Partially Milled 2 11,589' 3 -1/2" X nipple, 2.813" ID 3 11,625' 3 -1/2" tubing tail with Hydrotrip sub 4 11,678' 5" x 7" ZXP liner top packer 5 13,386' 5" liner Float Collar PERFORATION DATA ZONE TOP(MD) BTM(MD) TOP(TVD) BTM(TVD) DATE G -1 11,790' 11,890' 8,960' 9,009' Perf 4/29/02 7 liner G -2 11,960' 11,990' 9,044' 9,059' Perf 4/29/02 top @ 9,767' 6-3 12,050' 12,065' 9,089' 9,097' Perf 4/29/02 9 -5/8" 6-4 12,085' 12,115' 9,107' 9,122' Perf 4/29/02 window G -4 12,125' 12,160' 9,127' 9,145' Perf 4/29/02 L 1 ' -. @ G -4 12,190' 12,200' 9,160' 9,165' Perf 4/29/02 10,078' G -5 12,250' 12,370' 9,191' 9,251' Perf 4/29/02 MB 2 G -5 12,385' 12,410' 9,259' 9,271' Perf 4/29/02 X 3 4 HB 1 12650 12,690' 9,393' 9,413' Perf 4/29/02 �, . HB-1 12,670' 12,680' 9,403' 9,408' 1992 Frac Stim. `0.s - -,,�.1 HB -3 12,940' 12,960' 9,534' 9,543' Perf 4/29/02 '. HB -3 13,010' 13,040' 9,567' 9,581' Perf 4/29/02 ", a; `i HB -3, 4 12,868' 13,215' 9,500' 9,661' Perf 92' - 7" 117: HB -4 13,190' 13,240' 9,650' 9,672' Perf 4/29/02 �e ' C TD = 13,538' MD/9803' TVD PBTD = 13,386' = 5" landing collar Max hole angle = 64 deg @ 13,300' 60+ deg from 11,400' to TD Revised 9.24.12 by TDF Hilcor p Alaska LLC • Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date G -29RD 50- 733 - 20374 -01 192 -052 7/27/12 8/24/12 Daily Operations: 07/28/2012 - Saturday Rig up slickline lubricator. Install BOP lubricator with slickline gauge 3.750" and pressure test. RIH with gauge to 100 ft. Rig down gauge. Make up tubing stop tagging scale at hanger and POOH. Make up gauge cutter to clean out scale and pump produced fluid to wash tubing clear. POOH with gauge and prepare to pump fluid down tubing. RIH with AE Stop and set at 61 feet. POOH to pick up packoff plug. RIH with positive packoff plug, set and sheared on top of Stop, POOH. Pick up holddown stop and place on top of plug, POOH. Pressure up on top of plug, plug appears to be moving, possible scale preventing AE Stop from fully locking into tubing. Continue to pressure up, plug not holding properly, pull hold down stop. RIH with GS latch and jar on plug, unable to pull free. Continue jarring for 1 hour and POOH. Pick up prong to shear Kobe knock plug. POOH with prong, pick up GS, latch and retrieve plug. Redress full of scale. Ran broaching tool until tubing clean. Rerun, plug and pressure up to 800 psi, increasing pressure in 100 psi increments, while beating down on plug to insure proper set in tubing. RIH with hold down stop and set on top of plug, pressure up to 1,000 psi. POOH with slickline and rig down wellhead equipmen. Begin nippling down tree. Plan to inspect and clean threads and if possible set BPV as secondary barrier. Remove valves from tree, pull tree free and raised to top of production deck. Inspect and clean threads in top of hanger. Prepare to install well head riser. Riser installed. Pick up BOP stack and install on riser. Torque all bolts and tightned the annular on top of the BOP stack. 07/29/2012 - Sunday Moving new manifold to position, continue hooking up lines and perform function test of all equipment prior to calling for witness on BOPE test. All surface equipment hooked up and pressure tested to 1,000 psi. Make up chart recorder and perform low pressure check of total system. Pressuring up to 3,000 psi the plug failed at 1,500 psi. Rigging up slickline to retrieve holdown stop, plug and btm stop. Pull hold down stop and check for damages, full of tubing scale. RIH with GS Pulling tool and recovered positive tubing plug, full of scale, rubber appears in good shape. Pull Bottom tubing stop, caked with tubing scale. Spoke to State BOPE Inspectors, indicated that we should continue with attempt to clean tubing and set a CIBP for BOPE test if unable to pressure test with tubing plug. Running broaching tools and pumping produced water to clean scale. Continue to broach tubing down to 200 feet below the hanger and pumping down hole to clean away scale. Rig down slickline tools and rack all equipment. Rig up e-line and make up CIBP. RIH, locate collar at 84 feet with CIBP at 90 feet, set plug, j iv indication of setting. Rig down e-line and prepare to test against CIBP. Check all valves, close blinds and begin filling tubing and lines. Took 5 bbls of produced water, pressure building slowly to 1,500 psi, pressure not building. Well is taking fluid. Stop pumps and recheck all lines for leaks. Check casing, riser, BOP stack and choke lines pump. No leaks. Contact State of Alaska to inform of failure to test, request instructions and permission to pull hanger with parted tubing and then set test plug in hanger assembly. Instructed to standby until a formal discussion can be conducted with both State of Alaska and the DOA. Moved equipment away from rig area. Completed the V -door, added all safety rails, and replaced caution tape. Prepared fishing tools to spear the tubing hanger and pull tubing once a final approval is provided from AOGCC and DOA. II Hilcor p Alaska LLC • Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date G -29RD 50- 733 - 20374 -01 192 -052 7/27/12 8/24/12 Daily Operations: 07/30/2012 - Monday Preparing tongs for 4 -1/2" tubing. Waiting on orders from State of Alaska. Instructed to install 4 -1 2" test 'oint and TIW into Variable rams for final test. Pump fluid and established rate at 1,500 psi, BOP's holding but fluid is being injected down hole (possible hole in tubing above the CIBP). Make up fishing assembly and BHA. RIH and sting into top of 4 ft pup joint below tubing hanger, work oil jar to warm up, set down weight and release lock pins. Pull up and engage jars, hanger released on first jar action. Pulling up thru BOPS. Remove BHA and lay down acc jars without breaking out. Lay down oil /bumper jars and racked, add lifting sub to top of spear and pulled out hanger assembly, broke 4 foot pup under hanger. Pull additional joint of 40 foot completion tubing, hole located above the collar. Pulling 40 joints of 4 -1/2" completion tubing and racking on work deck. Tubing is covered with scale. Currently have 16 joints on the deck. Out of hole with 26 joints of completion tubing, 1- 3 foot section of 27th joint, hanger and 4 ft pup. Blinds are closed. Ready to begin BOPE test. Make up crossover to 4 -1/2" test joint, pick up hanger test plug and set inside hanger, begin full BOPE test. 3 pass /fail on the BOPE test with accumulator still not functioning properly. Will discuss and address concerns. Notified AOGCC of upcoming BOPE test. Talking with Bob Noble and Jim Regg about getting a witness onsite. 07/31/2012 - Tuesday Rig crew pressure testing BOP stack, 2 -7/8" test joint in place to resemble workstring which we will use next for fishing operations. Blind rams and annular will also be re- tested while waiting on State of Alaska witness. Continue with testing of surface equipment. State waived witness of BOP test. Pressure test BOPE 200 psi low /3,000 psi high. Moving fishing tools to rig floor, retest the kill line valves while moving equipment into position. Remove jar assembly from the overshot and make up to run in hole with equipment. Tally 2 -7/8" workstring and swing to v -door for assembly and tripping in hole. Pick up workstring, using slickline jars and gauge to rabbit tubing, unable to use light weight rabbit due to gunk in pipe. RIH with workstring. Work overshot slowly going down hole only a couple of feet at a time to avoid bending in the top of fish and closing off the ID. Rotating the workstring with power swivel moving down hole marking tubing, picking up to check weights. Latch fish, remove swivel and rig up a -line. RIH with CCL locater, weight bars, spang jars and 2" gauge ring, @ 2,173 lost CCL signal. POOH and redress. RIH with same tool string, CCL working, tag up @ 9,618. POOH. Rig up TIW and pump hose, pumping down tubing with annulus closed. Rig up eline with same tool string, RIH, tag up at same depth of 9,618' work tool string attempt to sting into or work thru obstruction with no success. POOH with a -line. Rig up to pump while in hole at top of fish, start pump with produced water. Continue to work tool string, getting good friction bite, having to overpull with a -line. POOH with e-line and pick up LIB to tag obstruction. 08/01/2012 - Wednesday POOH with Impression Block, rerun with centralizers. No postive indication on LIB. Pick up centralizer with gauge ring and RIH to 4,800'. POOH, tools covered with sludge. Rig down e-line. Rig up slickline. Make up small od tool string (1.250" with 2" LIB) to tag obstruction. Impression indicates fill. Rig up with sample bailer and tag obstruction. Recovered scale and sludge. Rig up dump bailer to begin bailing thru if possible. Made multiple bailer runs to crossover at 9,618'. Recovering scale and sludge. Rig off slickline to pull up on completion tubing, pull 60K and tubing came free, carrying additional 28K over workstring. Rig up to POOH racking 2 -7/8" workstring and will laydown 4 -1/2" completion tubing. POOH with 2 -7/8" workstring and overshot. Pick up tongs and elevators and begin pulling, checking for holes, laying down and racking 4 -1/2" completion tubing on opposite deck. Continue POOH with fish. Continue to lay down tubing, 110 joints of 4 -1/2" completion string on board and ready for trip in after we pull the fish. Out of hole with fish 74 joints @ 2,970.85'. Redress overshot for collar on 4 -1/2" tubing string. • • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date G -29RD 50- 733 - 20374 -01 192 -052 7/27/12 8/24/12 Daily Operations: 08/02/2012 - Thursday Overshot redressed, remove extension and allow for short catch on fish. Pick up joint and make up overshot. Tally and swing four joints per lift to v -door, begin fishing operations. Swinging 4 joints per lift to rig v -door and RIH with 8.125" OD Overshot dressed with 5.125 grapple and 5.125 mill control packer. RIH with 20 joints, tally additional joints and swing to rig floor. Operations suspended due to high winds. Restart operations. Continue picking up tubing and swinging to rig V- door. RIH with overshot to top of fish. Need to run appx 100 joints before picking up swivel to tag fish. Pick up power swivel to rotate over and latch collar on 4.5" tubing. Tag top of fish, weight dropped off as though collar came off of the next joint of tubing. Hook up pumps and displaced tubing. Pump 85 bbls of produced water to displace tubing. Top of fish @ 4,041'. 08/03/2012 - Friday Tag top of fish at 4,041' latch onto collar of 4 -1/2" used completion tubing. Pump 100 bbls of produced water to clear workstring and flush tubing at fish. Try to engage collar with no success. RIH with eline and gauge ring to overshot, work slowly to go thru and enter tubing, collar locater engaged and locate first collar 4,081'. Continue down hole slowly and sat down at 4,121' indicating tools may be outside tubing. POOH, laying down new completion tubing /workstring. POOH with E -line and rack equipment, pump 50 bbls and prepare to POOH with workstring and overshot. OOH with overshot, recover 2 full joints of 4.5" completion tubing. Redress overshot for tubing only, prepare to RIH on 2 -7/8" PH -6 workstring. Overshot dressed, pick up overshot for tubing, jars and 4 drill collars, intensifiers and swing to rig floor. Remove swivel from derrick, and begin operations. RIH with 2 -7/8" workstring, 16 stands in the derrick, tally and swing 10 joints at a time to the V -door. Continue to RIH with overshot, fishing tools and workstring. Continue in hole with workstring, unbind bundles, layout and tally for use. Swing to V -door, make up and continue operations. Currently in hole with 100 joints. 08/04/2012 - Saturday Continue operations. RIH with single joint to fish, on top of fish @ 4,125', rotate over top and work down to latch. Prepare to relatch fish and POOH. POOH with work string and BHA. Pull up to overshot, fish in overshot with tubing below. Remove old completion tubing. Laydown 4 joints and continue to pull and Iaydown worn pipe. Redress overshot to grab tubing, make up to workstring and prepare to RIH to top of fish @ 4,362. RIH with overshot for 4.5 tubing with 138 joints of 2 -7/8" Ph6 workstring. On top of fish at 4,362' work over top of fish and pull up workstring weight, fish came free. Begin to POOH. At surface with overshot, remove joint of tubing and begin working to remove balance of fish by clamping and cutting while pumping fluid down backside to control any potential releases. Continue to remove fish. Out of hole with 4 full joints of completion tubing. Close Blinds and pump 400 bbls of produced fluid to clean out wellbore around fish. 08/05/2012 - Sunday Continue to flush casing with produced water. M/U overshot and first joint of workstring. RIH with overshot and workstring, stop 1 joint above fish at 4,411'. Pick last joint, latch fish, pull up slowly in stages to allow torque to work downhole. POOH with fish, break out joints to laydown 4.5" completion tubing. Remove fish from overshot, check grapple, if good, will rerun to top of fish @ 4,692'. On bottom with 151 joints of 2 -7/8" Ph6 work string, latch fish and pick up weight, came free with extra weight on indicator. POOH with workstring and overshot. OOH with workstring, overshot and fish. Redress overshot, prepare to run in hole and latch top of fish at 5,024'. M/U overshot to workstring and begin RIH. Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date G -29RD 50- 733 - 20374 -01 192 -052 7/27/12 8/24/12 Daily Operations: 08/06/2012 - Monday Continue to RIH with overshot to top of fish, tag, latch and pull up. Out of hole with workstring, rigging over to begin pulling overshot and laying down 4.5" tubing string. Out of hole with fish, recovered total of 21 joints of 4.5" tubing. Bottom of fish is box. Redress overshot to RIH and latch pin end of fish. Overshot ready, swing to rig floor, make up with workstring and RIH to top of fish. On bottom with overshot (5,945.5') work tubing slowly to allow torque to work down hole. Continue to work until tubing released, pick up and try to engage with overshot, unable to do so. POOH. Prepare rig for overshot, pull up to overshot, fish in slips. Fish is now a collar on bottom, laydown overshot, and joint of 4.5" tubing and prepare to clean out BOP's for test. M/U test subs, pull wear bushing, and change out two manual kill valves while waiting for State of Alaska inspector. 08/07/2012 - Tuesday Prepare for BOPE test with State inspector. IBOP leaking internally, second IBOP coming on helicopter. Pickup test plug to set in hanger, blew o -ring at 1,500 psi. Remove and replace o -ring, re -test, same results, plug is not seated in the hanger correctly. Pull test plug to check for damage, hammer marks on the plug, sent to welding shop to redress. Install new o- ring and re -run plug. Change needle valves on pressure line from platform. Remove flange at wellhead to visually inspect for leaks at the plug. Pressure test again. Chasing leaks in flanges, needle valves, crossovers, test plugs, check valves. State inspector is working closely with team. 08/08/12 - Wednesday Install 4.5" test joint and pressure test variable rams 200 psi low /3,000 psi high. Order equipment for super choke. Makeup overshot to fish 4 -1/2" collar. Replace existing jars with Bowen bumper sub, oil jars, 4 drill collars and accelarators. Pick up work string and begin RIH. On bottom with workstring and BHA. Pick up single, tag and latch fish, pull 92K, set in slips and rig up slickline unit. Make up 2" pump bailer to run in hole and check for obstruction in advance of eline run. Rig down slickline. Rig up eline equipment, make up tool string and prepare to RIH. RIH with CCL, and Split shot tool (1 -3/8" Od) Using Split Shot Tool, begin logging collars on btm at 9,459'. 08/09/12 - Thursday Wireline running Split shot tool for collars, logging on depth to make shot, continue to log in attempt to find correct collar. Made shot at 9,459'. POOH with a -line, pull up on workstring, pipe is not free. RIH with second split shot, unable to get past 7,546'. POOH, remove split shot, pick up gauge ring and jars. RIH to 7,546' attempt to work past, unable to do so. Attempt to make multiple logs at depth (7,250' - 7546') collars are not clearly visable on locator. Continue to log, review log, nothing clear, POOH with eline and rig off well. Rig off eline, pick up pipe from slips and begin working string allowing force to move downhole, work to 130K several times, weight dropped to 102K. Pull up hole, removed single joint, lay out, begin pulling doubles, racking to derrick. POOH with workstring, laydown accelerators, rack drill collars, lay down bumper /oil jars, pull overshot with fish to the floor. Pulling 4.5" completion tubing, breaking out, rack on v door 4 at a time, swing to opposite deck and stack, tally each layer. Isolate well with TIW. Continue operations, (placing tubing clamp under top collar of 4.5 tubing to prevent slipping), 40 joints out of hole. Pulling out of hole, clamping, breaking connection, laying down and swinging to stack. Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date G -29RD 50- 733 - 20374 -01 192 -052 7/27/12 8/24/12 Daily Operations: 08/10/12 - Friday Continue pulling fish out of hole. Split shot missed collar by 1 foot and was visible on 5th joint above the crossover. Redress overshot to latch top of 3.5" tubing. RIH with 8.125" Series 150 Overshot dressed for 3.5" tubing. RIH with BHA fishing assembly to top of fish. Pick up power swivel, pick up joint # 300 and latch fish. Set overshot and pull up to nuetral position. Weight dropped off additional 4K at overshot, tubing is parted, check measurement, and weight, appears to be fish. Remove power swivel, and prepare to pull out of hole. 08/11/12 - Saturday Out of hole with workstring, remove the acc jars, rack the drill pipe in derrick, remove the bumper and oil jar combo, pull overshot into derrick with 3.5" tubing. Remove overshot and 3.5" tubing fish. Redress and re -run overshot. Make up oil /bumper jars. On bottom with overshot & BHA. Tag fish, latch in and pull 10K over, pick up power swivel to attempt to rotate out of K -22 Anchor. Working power swivel putting turns into the packer in attempt to unscrew the K -22 anchor. Made 4 attempts putting 8 turns at btm, some turns are coming back but appears to be unscrewing the anchor, weight dropped off, tubing broken, pull out with additional weight. POOH with partial fish. Out of hole with workstring, laydown acc jar, rack drill collars, remove bumper /oil jars, and pull up to floor with overshot & 3 1/2" tubing. Clean up overshot and prepare for next run. Plan to use eline to gauge to btm and possible cut. If unable to do so, pick up wash pipe with outside cutter. 08/12/12 - Sunday RIH with overshot, stop 15 feet above fish, reverse circulate to clean well bore. Latch onto fish, rig up pump to bullhead into tubing. Eline rigging up on top of work string, test equipment. RIH with eline for gauge ring run, stop at 3,000'. POOH. RIH to 6,000', having problems getting downhole due to gunk and other buildup in the workstring. POOH to review tool string. Attempt to RIH with eline gauge ring using smaller tool string with 2" gauge, unable to get pass 6,000'. Rig down eline. Pick up heavy elevators, pull up to 150K (workstring + fish), work tubing several times then attempt to rotate out of K -22 anchor. Begin working jars at 120K several times, then move to 130K, continue to jar up on fish in attempt to shuck the tubing anchor. Work against fish with 140K jarring, made 3 attempts, fish came loose. Pull first joint, laid out, remove TIW, replace on second joint, hook up pumps to circulate 2 bottoms up prior to pulling out of hole. 08/13/12 - Monday Continue to remove tubing, pulling 3.5" tubing, hot work permitted to use cutter, cutting tubing off above each collar, due to poor condition of the completion string. Currently have 7 full joints on the deck and continue to pull out of hole with tubing. Recovered total of 10 joints of 3.5" completion tubing. Remove stub from overshot, redress and prepare for next run. Make up overshot to latch 3.5" tube, pickup BHA and workstring and begin preparation for RIH. RIH with BHA, overshot and workstring. On bottom with overshot, tag fill with first of 10 joints required to reach top of fish. Make up joint, reverse circulating fill, continue operation adding single joints. Continue washing out fill with reverse circulation, 4 joints in hole still circulating fill from annulus with power swivel rigged up. 6 joints in hole washing out fill and working overshot down toward top of fish at 10,136'. Joint # 10 washed to top of fish, latched fish using power swivel. Rig down power swivel, pick up pipe tongs, pull into neutral position, pull 2,000 overpull, rotating tubing 12 full turns. Holding weight under overshot, reverse tongs, prepare to POOH. Out of hole with BHA, begin laying down acc jars, drill collars and bumper /oiljars. • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date G -29RD 50- 733 - 20374 -01 192 -052 7/27/12 8/24/12 Daily Operations: 08/14/12 - Tuesday Remove overshot with full joint of tubing, begin breaking joints out and racking to opposite side. Recovered pup joint on last joint with K -22 Anchor latch in good condition with anchor slips intact. Conduct BOPE test 200 psi low / 3,000 psi high. Witness of test waived by Jim Regg, AOGCC. Remove the test plug and install the wear bushing. Torque up mill and inside extension for the packer plucker. Swing to V door and begin picking up the BHA. RIH with work string. Tally additional lengths of workstring to reach top of fish. 08/15/12 - Wednesday RIH with BHA, workstring while adding additional joints to reach top of packer at 11,540'. Hog's head installed, power swivel on, picking up singles and washing down hole to top of packer. Pick up total of 35 joints washing down thru 11,350 ft. Continue to clean out 7" casing and reverse circulating adding joints of workstring, tag top of packer with joint # 360, plus 167 feet of BHA. Pull up latched into the packer mill out extension. Begin milling operations. Mill on packer, recovering rubber at surface with metal shavings. Continue to mill packer washing over packer with rotary shoe, packer plucker and BHA. 08/16/12 - Thursday Continue milling and working on packer. Tally indicates top slips are cut and shoe is riding on top extrusion ring. PU 85 -90 k SO 60K Rot 72 -74K. Torque is not at the shoe. Attempt to beat down on fish and engage shoe, no progress less than 1/2 ". Reverse Circ bottoms up. Total milling from 11,500' - 11,501.5'. Hang off power swivel in derrick and POOH to check BHA. Burning shoe OD OK ID polished smooth 4 -1/8" inside top of shoe was 1 complete 7" pin casing lead thread. Returns evaluated in settling pit revealed rubber and mandrel curls. Lay Down BHA to PU and replace burning shoe, dump friction reducer in wellbore, laydown boot baskets and x- overs. New BHA total length 173.53. RIH with pipe in derrick 179 stands move 3 singles with Crane. 08/17/12 - Friday PU power swivel and wash down to top of fish. Torque has reduced to well under pipe specs, milling ahead and additional 3.5 ' for a total of +/ -5 feet. Circ. returns all iron evidence of packer clear. Pure asphaltine in returns minor shavings . Working 80K to 120K indications of parted casing. Packer is milled over completely and tailpipe is anchored /stuck possibly in heavy dehydrated Asphaltine. Plans to POOH recover current fishing assembly and RIH with overshot jarring assembly to recover packer and tailpipe cutting tail pipe with explosives if necessary. Rig service and circulate BU. Attempt to release Spear cannot pull up into upper parted pipe verify spear is released from packer with travel of 12'. Swivel height too high to work Burning shoe back into parted casing. Break off swivel hang in derrick, work free pipe from slack off 60K to 120K. Setting jars at 100K and continue to pull to 120K. String weight 80 K Jarring at 30K over and overpull to 40K ove. Lay Down Single and PU 18' and 1 2' Pup joint. PU Power swivel, work and jar pipe rotating , not rotating, pump on pump off all varing combinations. No metal /iron on returns light amounts of asphaltine balls dehydrated and dense in consistency. Well is neither taking or giving up fluid ciculating pressures attempted and maintained to 800 psi. No pressure increase when 5 -7/8" shoe pulled into casing collar. Contine working and jarring fishing BHA. Worked several times back down to lower fish can still net packer spear to enter top of packer. Estimated gap in casing +- 5 feet in lower assembly and wall thickness of collars jars and subs prohibit severing by conventional explosives. Researching options. • • Hilcorp Alaska LLC • Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date G -29RD 50- 733 - 20374 -01 192 -052 7/27/12 8/24/12 Daily Operations: 08/18/12 - Saturday Continue working the fish. Burning shoe worked into bottom of casing working 140 -150 K and continued movement up into shoe with 90K SW with some drag. Lay down swivel and single and prepare to POOH with Packer Picker assembly. POOH racking back work string in derrick. Change out tongs and rig up floor for BHA. POOH with BHA connections difficult to locate with parrafin coated BHA. All tools recovered scars unreadable until we can steam everything off. 08/19/12- Sunday PU 5 -3/4" 0/S with no grapple and internal tattle tail indicators. Watermelon mill 5- 15/16" OD. Pump out sub and Jarring assy. Total BHA length 162.36'. RIH with pipe from derrick 179 stands & liner top could be seen with watermelon mill. Water melon mill OD is 5- 15/16" w/o asphaltine coating. PU 3 singles from catwalk to clean out casing collar at 11,540'. Milling tight spot with watermelon mill. After making 3 -4 inches, torque increased then drop of pressure increase on pump pressure and undefined weight indicator activity when picking up 10'. To many parameter changes to risk continuing with milling ops. Circ bottoms up plus heavy asphaltine lay down single set back power swivel. POOH w/ 72 stands. Rig shut down for repairs. 08/20/12 - Monday Rig repair and troubleshoot. Mechanic arrived and verified well rig will need to be rewired during rig move. POOH with remainder pipe and BHA. Guide in empty overshot heavily scarred and cut tip broken off. Scarring indicates 0/S guide was through casing bottom and did the milling work. Watermelon mill slick OD with asphaltine packed between carbide cutting rings. Stand back DC's, PU 9 -5/8" casing, scraper, x -over and RIH with pipe out of derrick. Tag top of liner @ 9,767'. POOH, lay down heavily asphaltine coated scraper, PU tapered mill 5- 15/16" OD. Total BHA 168.47'. Install stripping head RIH. 08/21/12 - Tuesday RIH w/ pipe from derrick 170 stands. Rig up pump in sub and circ 3 BPM 800 -850 psi returns clean very little aspahltine. Rig down pump line. RIH with 10 stands, PU power Swivel and 1 single. Wash down to TOF 11, 544'. No restriction evident in bottom of parted casing. Stand back Power swivel, POOH, lay down BHA. Rig down Stripping head, retrieve swear bushing and install test plug. Test BOPs 250 psi low / 3,000 psi high. Jim Regg, AOGGG, waived witness of test. Pull test plug and reinstall wear bushing. PU Wavey Bottom Shoe, 2 Jts Wash Pipe with TCB internal Box Tap for packer retrieval. Pump out sub, bumper jars, Oil jars, 4 EA 4 -3/4 DC's accelerators. RIH with pipe from derrick. 08/22/12 - Wednesday RIH with 170 stands. Circ reverse 3 bpm clean returns. RIH w/ 9 stands and P/U power swivel with single. Wash ream cannot tell if alongside or over packer. Circulate hole, clean to analyze cuttings set back swivel. POOH with BHA. Shoe has external scarring and chipping on face indicating possible coring of bottom casing. BHA not packed off as badly as before. Analyze shoe and rebuld new 5 -1/2" shoe. RIH with modified shoe and existing BHA. • • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date G -29RD 50- 733 - 20374 -01 192 -052 7/27/12 8/24/12 Daily Operations: 08/23/12 - Thursday RIH P/U swivel and 1 single. Attempt to get in lower parted pipe and over packer with hillside carbide guide. Cut approx 60 degrees. Circulate bottoms up 2 times then circulate 150 bbls conventional with filtered bay water, displacing 7" liner with clean fluid for future camera runs. R/D Power Swivel prepare for equipment change and lay down of work string. POOH. L/D workstring and offload Power Swivel and other equipment for rig move. Break down BHA. Heavy dehydrated asphaltine on OD. Broke down fishing assembly beat skivers chewed up casing pin and cement out of wash pipe. OD of shoe scarred and shoe gouged from fish top. Clean up floor retrieve wear bushing open BOPs to check rams. 08/24/12 - Friday Moving equipment prepare for kill string. Function test BOP's. Install safety valve and test pipe rams 200 psi low / 3,000 psi high for 4.5" tubing. P/U 20 jts 4.5" production Kill string open ended no wireline re -entry guide total strap depth 832.7'. Land hanger. Install BPV. N/D BOP, Iaydown derrick, rig down all lines wrap up accumulator. N/U tree continue to tie up guy lines. Shell test tree. Retrieve BPV. • • Page 1 of 2 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Thursday, August 16, 2012 1:52 PM To: 'Mike Dunn'; Ferguson, Victoria L (DOA) I I — 6 c Cc: Tom Fouts - (C) Subject: RE: G -29RD Workover: PTD 192 -052 Sundry 312 -255 Request to set packer high and reduce MIT test pressure. Mike, No issues with cement in the liner... You have approval to move packer setting depth to 11500' and (290' above injection perfs) based on adequate bonding at the new setting depth:""" * Additionally, a test pressure of 2205 psi is approved for MIT of the IA after packer is set. Regards, Guy chwartz MAY 0 7 Z013 Senior Petroleum Engineer NN� AOGCC 793 -1226 (office) 444 -3433 (cell) From: Mike Dunn [mailto:mdunn @hilcorp.com] Sent: Thursday, August 16, 2012 12:41 PM To: Schwartz, Guy L (DOA); Ferguson, Victoria L (DOA) Cc: Tom Fouts - (C) Subject: G -29RD Workover: PTD 192 -052 Sundry 312 -255 Request to set packer high and reduce MIT test pressure. Guy and Victoria, Per your request below, attached is the supporting evidence to show that there is cement at 11500', where we would prefer to set the packer, which is 290' above the top injection perf. Also, we would like the MIT test pressure to be modified to 2205 psi which is .25 psi /ft times TVD of packer setting depth (8818' - see survey excerpt below). Our original procedure had stated a test pressure 2500 psi. Upon further review, this is a well that we would rather not subject the casing to a test pressure any more than we are required to. Regards, Mike Dunn 8/16/2012 • • Page 2 of 2 11400.3 8768.6 - 5513.23 2346.77 59.84 302.31 11425 8780.94 - 5531.3 2358.21 60.19 302.36 11450 8793.33 - 5549.62 2369.87 60.41 302.58 11475 8805.63 - 5567.95 2381.61 60.67 302.68 11500.2 8818.02 - 5586.4 2393.5 60.43 302.92 11525.3 8830.44 - 5604.68 2405.39 60.21 303.17 11550.1 8842.67 - 5622.74 2417.19 60.7 303.13 11575.2 8854.9 - 5641.11 2429.16 61.02 303.06 11600.1 8867.02 - 5659.34 2441.01 60.68 303 11625 8879.15 - 5677.57 2452.87 61.02 303.09 11650.1 8891.26 - 5695.98 2464.89 61.29 303.2 11675.4 8903.37 - 5714.59 2477.03 61.55 303.05 11700.1 8915.22 - 5732.72 2488.88 61.06 303.26 Mike, Assuming the 7" liner is fully cemented and bond looks good then we can grant the variance to 20 AAC 25.412 (b) requirements... Please verify the liner cement details and send me an email back. (Normally the variance is requested when the sundry is submitted so we can look at the bond log and cementing records. ) This is a fairly minor change but I still need to have you check on the confinement specifics.... The new packer must have good cement at the proposed setting depth also. Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Mike Dunn f mailto:mdunn@ hilcorp.com] Sent: Wednesday, August 15, 2012 10:17 AM To: Schwartz, Guy L (DOA) Subject: Permission to set packer more than 200' above top perf on injector Guy, Attached is the 10 -403 for G -29RD. We have started milling the packer at 11540'. We would like to set the new packer at 11500', which will be 290' above the top perf, rather than at 11600' as outlined in the procedure. We would rather not set the packer below where the old packer was milled, as it is possibly weak or could present problems going through it. Permission requested to set the packer more than 200' above the top perf. Please advise. Thanks, Mike Dunn 1 Senior Engineer Hilcorp Alaska, LLC Office: (907) 777 -8382 Mobile: (907) 351 -4191 8/16/2012 I 7 11 I I ,.VMUl.l, 11V• t y�� r TON MI. OR S FOOTAGE FORMA ou CORE ' (SHOW' WT. ON PUMP N0. PUMP N . ? METHOD; ROTAR BIT FUN RIN1 CORE. CORE RECOVERY/ RPM it S p ' FROM N lira S.P"tA • TINIER S.P.M P 'tF I I 5 i ('' 5 i DEPTH DEV. DIRECTION DEPTH DEV. DIRECTION DEPTH DEV. DIRECTION ■ DEVIATION RECORD r TIME LOG ELAPSED CODE N0. DETAILS OF OPERATIONS IN SEQUENCE AND REMARKS FROM TO TIME V V N T . J J� D A . 1 D I4 h nn :n0 D ;30 3lz- Id TT 3 (�i,T1 � ,, �nI e •2 � /il tv Pry � , ) 3 30 c'; V 1 1 . PlineC: 4 I W L INt°�' Ildt t"t* t Rot\ ,rf0OL " =i 0#I i #ot es q ` 11 ?'I ;5v 6%)& 3 / I RTH S1atu ' OP CilI every 51Ma. 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'''',1 ,‘ 1 ; 1 1 1 '4, , 4.,•••"‘I'lt-P-- 1.\ 3 i.•; ii I R'' ,1 1•-• ii`k.,•ri••••••••,....1 rAL.r .• %...! ! .„, , ; 1 . • \.:,,../ • . .. • 1 , . , , , • ; . . . = • • • 1... . „... •.. .. . .... i ' ' I ; :. ; • t • = • • ; • , , • , . . . _ . . .. .. • • • Page 1 of 2 • Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Monday, July 30, 2012 9:57 AM To: 'Mike Dunn'; Ferguson, Victoria L (DOA) Cc: Regg, James B (DOA); Paul Langley - (C); Chris Myers; Ferguson, Victoria L (DOR) Subject: RE: BOPE Test on G -29RD ( PTD 192 -052) Mike, As we discussed.. a rolling test ( to approx 1500 psi) with a joint of tubing or test joint is required before pulling the hanger. At that point once you have the tubing out of the way a full BOP can be done by setting a test plug in the wellhead. Guy Schwartz Senior Petroleum Engineer AOGCC SCANNED WIA\Ir 0 2 2013 793 -1226 (office) 444 -3433 (cell) From: Mike Dunn [mailto:mdunn @hilcorp.com] Sent: Monday, July 30, 2012 7:09 AM To: Schwartz, Guy L (DOA); Ferguson, Victoria L (DOA) Cc: Regg, James B (DOA); Paul Langley - (C); Chris Myers Subject: FW: BOPE Test on G -29RD Guy or Victoria and Jim, As Paul Langley describes, we have made every attempt to test the BOP against a plug, with no success. The combination of an eroded BPV profile, and rotten tubing, has left us no way to test BOPs. We would like to proceed with pulling the hanger and upper part of the tubing, so we can set a set a test plug. It is the same equipment used on G -05RD. No problems experienced the last 2 times of testing the stack. Please call my cell phone if you wish to discuss. The rig is currently on standby waiting on direction. Thanks, Mike Mike Dunn !Senior Engineer Hilcorp Alaska, LLC Office: (907) 777 -8382 Mobile: (907) 351 -4191 From: Regg, James B (DOA) [mailto:jim.regg @alaska.gov] Sent: Monday, July 30, 2012 12:03 AM To: Paul Langley - (C) Cc: Grimaldi, Louis R (DOA); Mike Dunn Subject: Re: BOPE Test You appear to have made a good faith effort to get a tubing plug set in G -29RD. Your plan makes sense fi "Paul Langley - (C)" <plangiey@hilcorp.com> wrote: 7/30/2012 • Page 2 of 2 w • Sir: We have made several unsuccessful attempts to set a plug in the G -29RD well on the Grayling Platform. 1. We anticipated there would be no way of successfully setting a BPV in the hanger as this well proved to have more scale buildup then the G -05, our last workover. 2. We utilized slick line services to broach heave scale and thick sludge while pumping down the well bore. A positive tubing plug was set on top of an AE tubing slip. We tested and remove the tree, install the BOP stack. We attempted to pre -test at low and high pressure and the plug then failed. 3. We then pulled the entire assembly and clean tubing ID again, reset and failed as well. Remove assembly and had crew scrap and flush tubing 4. Called for E -line crew with a permanent cast iron bridge plug and set at 90 feet, visible indication of Positive set. 5. Removed E -line equipment, and begin testing against the plug, once the pressure reached 1500 Psi the well began to take fluid. We checked for pressure leaks, none were encountered. Checked all valves, replaced gauges and rechecked, same results. It is my feeling that the tubing has developed a leak above the plugs and we are currently injecting into the formation. We shut off the pump and the pressure goes to 0 psi. Startup pumps and well takes 3 bbls, begins to pressure up and then takes fluid at 1500 Psi. Once I shut the pump the pressure again goes to 0 Psi. I am requesting your permission to discuss the following option: 1. Remove the hanger and pull up against the tubing. Well files indicated parted tubing at 1100 ft slickline measurement, if possible we could retrieve this portion of the tubing, once out of the hole close the blinds. 2. Pickup casing scraper and clean the casing down to 1000 feet , flush with produced water, then pick up a retrievable casing plug for shallow set, or a storm packer. Set and test. 3. While at this point we have two options, 1. Proceed with BOPE test and 2. Remove and replace the tubing hanger which we have plans to do later in the workover procedure ( do this now and replace the riser and BOP, complete a proper test with a BPV in place, remove the packer and return to the workover operations with new tested surface equipment. I would like your input, guidance and approval on this situation prior to making any other steps. Respectfu Ily Paul Langley WSM Grayling Platform Ph 776 - 6630 7/1/2012 • • ilz3 Cl[F LanS[KKA ' ,� u SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Mike Dunn Sr. Reservoir Engineer © S -.,. Hilcorp Alaska, LLC l 1 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: McArthur River Field, Hemlock & Middle Kenai Gas Pool, TBU G -29RD Sundry Number: 312 -255 Dear Mr. Dunn: 54.. iig ED JUL 8 201L 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, L I Cathy ' . Foerster Chair DATED this �If day of July, 2012. Encl. iiii:: f ri� STATE OF ALASKA JUL 13 2012 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well [411 «' Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate 6 • Pull Tubing 0 • Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Reperfarate/Recomplete 112 - 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Development ❑ Exploratory ❑ 192 -052 • 3. Address: Stratigraphic ❑ Service El . 6. API Numb 3800 Centerpoint Drive, STE 100, Anchorage, AK 99503 50- 733 - 20374-01 -00 . I 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 Trading Bay Unit G-29RD • 9. Property Designation (Lease Number): 10. Field / Pool(s): ADL0017594 • McArthur River Field / Hemlock Oil and Middle Kenai Gas Pools 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): 13,538 ' 9,803 • 13,449 9,763 none Casing Length Size MD TVD Burst Collapse Structural 324' 28" 324' 324 Conductor 911' 20" 911' 911' 1,530 psi 520 psi Surface 6,572' 13 -3/8" 6,572' 5,608' 3,090 psi 1,540 psi Production 8,935' 9 -5/8" 10,078' 7,810' 6,870 psi 4,760 psi Liner 3,771' 7" 13,538 9,803' 11,640 psi 10,760 psi Liner 1,753' 5" 13,431' 9,756' 8,290 psi 7,250 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 3 -1/2 ", 4 -1/2" 9.2# L80, 12.6# L -80 11,625', 9,618' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): SAB Injection Packer and N/A (SSV) Packer 11,540 (MD) 8,838 (TVD) 12. Attachments: Description Summary of Proposal el 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Development ❑ Service 0 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 7/17/2012 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: N/A WINJ El • GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Mike Dunn Printed Name MiKe Du Title Sr. Reservoir Engineer Signature / 2 4 4 Phone (907) 777 -8382 Date 7/11/2012 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: J' " 255 Plug Integrity ❑ BOP Test Mechanical Integrity Test i7 Location Clearance ❑ Other 0 ' "e ....7 C 7 5G f cd Ai Y G'7 1 f4 Subsequent Form Required: /0 --- 401- tt/ / APPROVED BY Approved by:,♦, i COMMISSIONER THE COMMISSION Date: 7 _ /4 �,r DMS JUL 17 101, . � ►„ in Duplicate '�t Form 10-40 Revised 1/2010 0R1G1N -/ 1 � � I Z- ,,lt • • Well Work Prognosis Well: G -29RD Hilcorp Alaska, LLC Application Date: 07/13/2012 Well Name: G -29RD API Number: 50- 733 - 20374 -01 Current Status: Active Water Injector Leg: Leg #4 (SW corner) Estimated Start Date: July 19, 2012 Rig: Williams Rig 404 Reg. Approval Req'd? 10 -403 Date 10 -403 submitted: July 13, 2012 Regulatory Contact: Tom Fouts 777 -8398 Permit to Drill Number: 192 -052 First Call Engineer: Mike Dunn (907) 777 -8382 (Office) (907) 351 -4191 (M) Second Call Engineer: Ted Kramer (907) 777 -8420 (0) (985) 867 -0665 (M) AFE Number: Budgeted Cost: Pressures: The well is a shut -in injector. The well has 0 psi on the tubing and will not hold a full column of seawater. The estimated bottom hole pressures are based on previous static surveys and recent fluid level shots. Current BHP: — 3,500 psi @ 9,324' TVD/12,515' MD .38 psi /ft., (7.2 ppg) at mid -pert of G &H Max. Expected BHP: — 3,500 psi @ 9,324' TVD .38 psi /ft. (Same zone re- perforated) Max. Possible SP: 0 psi Using 0.435psi /ft. SW gradient to surface Brief Well Summary G -29RD is currently a shut in water injector that has a bottom -hole location in the middle fault block of the Northwest feature. When injecting, it supports G -13 and G -28RD producers. The well was a producer until April 2002 when it was making about 2,000 bfpd at 95% watercut. The gas lift string was pulled and the well converted to injection and injected between 9,000 and 11,000 bwipd from 2002 to 2005. In May 2005 the well experienced communication between the tubing and casing. A temperature survey was run on June 26, 2005. After approximately one month of injection, a follow up survey was run on August 26, 2005. The surveys confirmed that all injected fluids were exiting at the perforations. Administrative approval was granted on September 23, 2005 to allow injection, with bi- annual temperature surveys run to confirm water was staying in zone. In September 2011, while attempting to run a temperature survey, the tubing was found - to be parted at 1,024'. The well has been shut -in ever since. The obiective of this workover is to repair the well. During the workover while the packer is removed, the current zones will be re- perforated with modern . perforating guns to improve injectivity. --- Notes Regarding Wellbore Condition • The tubing has no integrity; there is a full or partial part in the tubing at 1,024'. • Casing integrity is intact. There are no indications of communication behind the 9 -5/8" casing. Procedure: 1. Skid Williams Rig 404 over the G -29RD well slot. Raise mast. Prepare for wellwork operations. 2. Plumb FIW lines to circulate down the annulus and up the tubing, when the tubing is pulled out of the packer. 3. Notify AOGCC of pending BOPE test. Set BPV, ND tree, NU BOPE. Test all BOP equipment per AOGCC guidelines to 250 psi LOW and 3000 psi HIGH. Test Annular BOP to 250 psi LOW and 1500 psi HIGH. • • Well Work Prognosis Well: G -29RD Hilcorp Alaska, LLC Application Date: 07/13/2012 Record pressures, fill out the 10 -424 form and send to Jim Regg at AOGCC and Juanita Lovett with Hilcorp. 4. PU landing joint and make -up to tubing hanger. Tug on tubing to pull the hanger free and the upper portion of the parted tubing. 5. Pull hanger up to floor height. Install stripper rubber. Circulate at least 2 bottoms -up to adequately clean hole. 6. POOH with 1,000' of completion tubing. LD same, check for NORM. 7. PU overshot assembly on workstring and RIH and swallow tubing stub. Pull tension. 8. RU E -line and jet cut the tubing approximately 10' above the packer at 11,535'. Note loss of weight. If returns can be established, CBU at least 2 bottoms up. 9. MU overshot and jarring assembly and RIH. Jar and rotate K- anchor until it comes free of packer. POOH. 10. PU packer milling assembly. Mill packer using stripper rubber and reverse circulation method. If losses are low, continue with plan. If losses are too high to circulate fill and /or metal shavings, pump polymer /salt pills as necessary to reduce fluid losses. Circulate hole clean of metal shavings. Use magnets at surface to catch metallic debris. Pluck packer out of hole. 11. After milling and retrieving packer, PU a full gauge mill with open jets and a casing scraper clean out fill and scrape the casing down to PBD at 13,386'. Reverse circulate all fill out of hole. Displace hole with clean FIW from sand filters. POOH about 500' above top perf with mill. MU storm packer, RIH to 100'. Set same and release. POOH to change out tubing head. 12. ND BOP and install a new tubing head. NU BOP, test BOPs. RIH, pull storm packer. LD same. 13. MU Schlumberger TCP guns on workstring and RIH. RIH with E -line or memory GR tool on slickline. Position guns to perforate as follows, using the Hilcorp Digital Database Log (DDL) as the reference log. Proposed Perforations: Zone Top Bottom Feet G1 • 11,790 11,890 100 G2 11,940 11,950 10 G2 11,960 11,990 30 G3 12,050 12,065 15 G4 12,085 12,115 30 G4 12,125 12,160 35 G4 12,190 12,198 8 G5 12,250 12,370 120 G5 12,385 12,410 25 G7 • 12,544 12,590 46 HK1 12,650 12,700 50 HK3 -4 12,880 13,240 360 Total: 829' 14. When the guns detonate, the reduction of skin damage could cause the well to drink fluid until the fluid level finds the balance point between reservoir pressure and the column of fluid in the well. There is no need to circulate the hole, following the perforation event. After detonation, monitor • • Well Work Prognosis Well: G -29RD Hilcorp Alaska, LLC 14 Application Date: 07/13/2012 well by shooting a fluid level. It is OK to fill the hole periodically with clean FIW since this will be an injector. Do not pump polymer and /or salt to slow the fluid loss. Once the well is determined to be static, POOH. 15. POOH with guns. LD same. Confirm that all charges fired. 16. PU 4 -1/2" X 7" packer and 4 -1/2" tubing. RIH. Space out and set packer at +/- 11,600'. Land the Ow -I-- tubing hanger, and pressure up backside to confirm packer is set. Hold 2,500 psi for 30 minutes for ,3o`i the casing MIT test. If the pressure does not decline more than 250 psi in 30 minutes, the well has passed the Workover MIT. Provide Larry Greenstein with the pressure test results and the completed 10 -426 form for the MIT. 17. Set BPV. ND BOPE and NU tree. Test tree. 18. Turn well over to Production Supervision (TOPS) for re -start of injection. 19. Within 2 weeks of stable injection, schedule an Initial MIT with AOGCC. Provide the AOGCC 24 hour notice prior to the MIT test. All pressure test results and completed 10 -426 are to be provided to Larry Greenstein immediately following the test. II H • • Well Work Prognosis Well: G -29RD Hilcorp Alaska, LLC Application Date: 07/13/2012 As -built (Old) Wellbore Schematic CASING DETAIL RKB to TOG Hanger = 41.35' C GRADE CONN TOP BOTTOM Note 28" Driven Surf 324 20" 94 H- 0 Surf 911 133/8" 68 F- Surf 6 5 133,8" 3,080' C. + +/ Collar ill Parted Buttres 1 Tubing �' 4; N w. .:95 s Surf 10,0:8' Buttr Ps 7" - P -110 _ 9,767' 13,538' 32 5" 15 L i r H,: d 511 11,678' 13,431' erma Scab Liner 13 ?J'S ■ � DETAIL DV 4 1� "2" 12.6 L =0 Butt es S 9,618' xf 3 -1/2" 9. I -80 ^C:F,r' . '')WY U 4i 1 .77.' r to. 1 1 9,618' 3 -1/2" x4-1/2" crossover 2 11540' 3-1/2" x 7" SAB injection packer •,a'M0E Model "K" anchor in top of pkr 11.589' 3-1/2" X nipple. 2813" ID 4 11,625' 3-1/2" tubing tail with Hydrotrip sub 5 11,678' 5" x 7" D P liner top packer 6 13,386' 5' liner Float Collar F'EkF !R:=ATION DATA ZONE TOP(MD) BTM(M TOPfTVD) BTM(TVD) TIr. G-1 11,790' 11,890' 960' 9009' Perf • 4/29/02 7" liner G-2 11,550' 11,990' 9,044' 9059' Perf 4129/02 top @ 1 G-3 12,C150' 12,065' 9,089' 9097' Pert 4; 29/02 9,767 G-4 12035' 12,115' 9,107' 9 ,122' Pert4/29%02 - in .;.;• G4 12,12'5' 12160' 9.127' 9;145' F'ert4 - lilt A �' " " 2 b ,x G-4 12,190 i' 1? i r0' 3,160' 9165' F'erf 4 '02 10.076' G-5 12,250' 12,370' 9,191' 9251' Perf 4 /31/02 3 G5 12,385' 12,410' 9,259' 9271' Pert 4/31/02 ir , Mt HB-1 12650 12,690' 9,393' 9,413' Pert4/29/Ll2 A 5 HE -1 12,670' 12,680' 9,403' 9,408' 1992 Frac Stirn. i t HB-3 12,940' 12,960' 9,534' 9,543' Perf4/29JU2 HE 3 13, 0' 13,040' 9,567 9,581' Pert41�91tt2 HB 3, 4 12,868' 13,215' 9,500' 9,661' Pelf 92' - 7" He�4 13.190' 13,240' 9,650 9 Pelf 4/29/112 6 Note IF, run 9j6 ;l1 found impression of parted tubing at 1092 Ternp survey could not be run. Well shut -in. TO = 13,538' MD/9603' TVD PBTD = 13366' = 5" landing collar M a' hole angle = 64 de g r' 13300' 60+ deg from 11400' to TD Revised 7.10.12 by TDF ` • • Well Work Prognosis Well: G -29RD Hilcorp Alaska, LL( A pplication Date: 07/13/2012 Proposed (New) ) 0 Wellbore Schematic p ( RKB to TBG Hanger = 41.35' CASNG DETA! J - T GRADE ( TTOM Note 2S Driven Surf 2.:1 94 H-40 Surf 9:: - i _P-3 8 68 K -55 Surf 6,572 3 S 3,0S3' D',' Collar t u 9-5 S. 47 N-80, S-95 Buttress S 10,078' 7 32 P -110 Buttress 9,767 13,538' 5' :5 L-80 M511 11,678' 13,431' Cement Scac Liner 13-3/8' ■ III L-80 DETAIL Or Co a 4 ' 2 I :2.6 L -80 Imp BTC Surf ±9,618' 1 i JEWELRY DETAIL No. Depth Item 1 511,600' 4.1/2" 12.60L- 801BTtubing 2 +^ a 4 -1/2" x 7" SAB injection picker w/MOE Modell " anchor in top ofp Cr 3 *_12,640' 4 -1/2" X nipple,2.813" ID 4 _11,650' 4- 1 /2 " tubing WLEGwith tiztrarip sub PERFORATION DATA LONE TOP B DATE 7" liner 0 -1 ±11,790' ±11,890` Perf 4x29/02; Bunt Future top @ 9,767' '-' G -2 ±11,940' ±11,950' Perforate Future 9 -5/8" G -2 ±11,960' ±11,990' Perf 4/29/02, 8e e.,lP..a4e Future window G -3 _ *12,050' ±12,065' Perf 4/29/02; B, ped ,fate Future • ." 0-4 ±12,085' ±12,115' Perf 4/29/02;ltpr(A @te Future 10,078' 3 G-4 ±12,125' ±12,160' Perf 4/29/02; &p.petf-g!ate. Future 4 G-4 ±22,190' 512,198 a£AB..rf.9r-aSe Future -.-t� 0-4 12,190' 12,200' Perf 4/29/02 G-1 , G -5 512,250' 512,370' Perf 4/29/02; aepp Future G 2 G -5 *_12,385' 1 Pert 4/29/02; Rspezfa ate Future + 43.3 G G-7 ±12,544 +12,590' Perforate Future G HB - 212,650' *12,693' Perf 4/29/02; flepe,.O4#!dte, Future ` ...1 GI HB -: 12,670' 12,680' 1992 Frac t±,m,. - Fra-GY 1 H8 -3 12,940' 12 Perf 4/29/02 r ,� I. 4 r &'..4 H8 - 13,010' 13,040' Perf 4/29/02 ■15 He - 12,868' 13,215' Perf 92' -?" HB -3, 4 :23.SS2 s: 3,240 Perforate Future HB-4 13,190' 13,240' Perf 4/29/02 TO = 13,538' MD /9803' ND PBTD= 13386' = 5" landing collar Max hole angle = 64 deg @ 13300' 60* deg from 11400' to TD Created 711.12 by 7DF • • Well Work Prognosis Well: G -29RD I�Ornrlt , th.ka. C. Application Date: 07/13/2012 Williams Workover Rig • Grayling Platform • BOP 2012 IOC I {I Weatherford Rental BOP Width 4.16' 3 74' Weight 13,100# Shaffer 13 iii III ili ill Iii • Total BOP height above Shaffer LWS drill deck 13 5/8 5M LWS 13 5/8 5M 9.48' min dimensions 11.48' max Length 7.73' 0 — 3.00' Width across body 2.72' c Width across flanged outlets 4.00' Weight95001bs • 9 00' III III III III Mud Cross H i 1417T, t t 1 74 28501bs w/ valves r / Illal LIn nl IiI • Riser above drill deck III... This number will vary 1.111111111- from well to well 1.00' to 3.00' t Drill Deck 13 5/8 5M Riser 85001bs 15.00' qa � I � � y �I III ak�Ai«"E° 1 SIXONIMM III _ III Spacer Spool 135/85M X 135/85M 3,i 1. 95' 1800Ibe .: I II . " . III 'lea' -2/4 'h III III Crossover Spool 13 5/8 5M X 11 5M 18001bs 2.83' III III Top of Wellhead • • Page 1 of 1 Maunder, Thomas E (DOA) From: Greenstein, Larry P [Greensteinlp @chevron.com] Sent: Friday, October 14, 2011 7:31 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: Cole, David A; Martin, J. Hal; Lambert, Steve A; Ayer, Phil M; Ross, Gary D; Quick, Mike [ASRC]; Hallett, Trudi R. Subject: 2011 Third Quarter's LTSI Well Monitoring Report Attachments: Master Well List TIO Report 2011 10 01.xls Hi Tom & Jim, Here is the third quarter's report for the LTSI wells utilizing pressure monitoring in lieu of an MIT to determine any mechanical integrity problems. tcp-O The wells G -29RD, G -27, G -22 & G -5RD have been moved to this LTSI report as their downhole problems (like parted tubing) do not allow a temp survey to be run to the proper depth to confirm water entry into the perfs. As a result, they are all shut -in and will remain so for now. The An -17, An -29, Ba -16 & GPP 33 -14RD wells showed increases in the 13 3/8" annulus, but they all have leveled off lately. Ba -17, after an MIT, was used in August to disposed of some fluids collected during the well kill operations on Baker. It may be used again in October for fluids collected during a well abandonment operation. I have left this well on the LTSI well list because after this usage, the well will revert to being shut -in for the foreseeable future. All the pressures seen during the usage in August looked appropriate and the well appears to have maintained its mechanical integrity throughout the disposal operations. The general pattern of stable or slowly rising pressure trends continued this month for the Baker & Dillon wells on this list with the only other pressure anomaly related to the seasonal trend in pressures apparent in Ba -15RD. The well kill operations performed on the Dillon platform in August show up very clearly on the plots. Other than the noted issues, there doesn't appear to be any wells that show indications of any well integrity problems. Larry • 10/14/2011 Plot Pressure late vs Time - Well G -29RD • 8000 2000 -- _ f ft �• 7000 _,- J —9 5/8" 6000 1500 13 3/8" — — - _ w 20" 'Tubing •■••■Vot 0 -29 5000 v 7 J VI 0] N m 1000 4000 3000 500 - -._ -_ - ...._. -. ._ -- ._..__._ .- _..... __.... _...__ __._ ..___._ _-_-__.. __- 2000 1000 0 ,. _ _ �. ,... _- 0 63 7 O O M 0) N N r 75 rn o 0 0 0 0 0 0 Date 5/8" 13 3/8" 20" imfflegirollIMIP TIO Report 10/01/11 0 25 0 0 0 09/30/11 0 25 0 0 0 Data Sheet 09/29/11 s 0 25 0 0 0 09/28/11 0 25 0 0 0 09/27/11 { 0 25 0 0 0 G -29RD 09/26/11 F 0 25 0 0 0 09/25/11 L 0 25 0 0 0 09/24/11 0 25 0 0 0 INJECTION 09/23/11 0 25 0 0 0 09/22/11 0 25 0 0 0 09/21/11 0 25 0 0 0 Permit # 1920520 09/20/11 0 25 0 0 0 09/19/11 ? 0 20 0 0 0 09/18/11 0 20 0 0 0 API # 50- 733 - 20374 -01 09/17/11 0 20 0 0 0 09/16/11 ' 0 10 0 0 0 09/15/11 0 10 0 0 0 04/01/2011 to 10/01/2011 09/14/11 0 10 0 0 0 09/13/11 0 10 0 0 0 09/12/11 z 0 10 0 0 0 09/11/11 0 25 0 0 0 09/10/11 • 0 25 0 0 0 09/09/11 0 25 0 0 0 09/08/11 0 25 0 0 0 09/07/11 : 1740 25 0 1900 6335 09/06/11 1750 25 0 1900 8082 09/05/11 ' 1750 25 0 1900 8093 09/04/11 1700 25 0 1900 8104 09/03/11 •' -! 25 0 1900 8105 09/02/11 25 0 1900 8062 09/01/11 25 0 1900 7956 08/31/11 30 0 1900 7946 08/30/11 30 0 1900 7962 08/29/11 " 1740 30 0 1900 7988 08/28/11 1740 30 0 1900 8013 08/27/11 30 0 1900 8000 10/14/2011 8:46 AM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2011 10 01.xIs G -29RD Page l of l Maunder, Thomas E (DOA) From: Greenstein, Larry P [Greensteinlp @chevron.com] Sent: Thursday, October 13, 2011 9:14 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: Martin, J. Hal; Lambert, Steve A; Hallett, Trudi R. Subject: 2011 September's Waivered Injection Well Report Attachments: Master Well List TIO Report 2011 10 01.xls Hi Tom & Jim, Here is Septemb is month) report for all the active monitored injection wells. ,. t _ -®5D- I did move -29RD, G -22 & G -5RD out of this report and over to the LTSI report due to the inability to get a temp survey deep enough for a successful MIT. These wells have been shut -in and will remain so for now. These monitored wells, including the newly added wells, are responding as expected to ups and downs in injection volumes without any apparent pressure or rate anomalies observed. Bottom line, I don't see any indication that any of these wells are losing control of the injected fluids downhole. Larry r 1 , i 11/8/2011 Page 1 of Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Monday, September 12, 2011 9:05 AM To: 'Lambert, Steve A' Cc: Cole, David A; Agler, Brit G; Greenstein, Larry P; Brooks, Phoebe L (DOA) Subject: RE: G -29RD (PTD 192 -052; AIO 5.007) MIT Survey Steve, et al, was just looking at the pressure record as well and I agree that there isn't anything that jumps right out. Tom Maunder, PE AOGCC From: Lambert, Steve A [mailto:salambert@ chevron.com] Sent: Monday, September 12, 2011 9:02 AM To: Maunder, Thomas E (DOA) Cc: Cole, David A; Agler, Brit G; Greenstein, Larry P; Brooks, Phoebe L (DOA) Subject: RE: G -29RD (PTD 192 -052; AIO 5.007) MIT Survey Tom the last time we had wireline in well G -29RD was February 20, 2009 when we ran a successful MIT temperature survey. A 2" gauge ring was run to 11,575" at that time with no note of any restriction and the temperature survey was subsequently run to 11,600' with no note of any obstructions. As you can see from the attached plot, there are no obvious indications of a change in injectivity following the survey run in 2009. Steve Lambert Senior Advising Petroleum Engineer Chevron North America Exploration and Production S1 1 � 3800 Center Point Suite 100 Tel 907 263 7658 salambert @chevron. com om: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sen . u onday, September 12, 2011 7:58 AM To: Lambe , teve A Cc: Cole, David • , • • er, Brit G; Greenstein, Larry P; Brooks, Phoebe L (DOA) Subject: RE: G -29RD • ' 92 -052; AIO 5.007) MIT Survey Steve, et al, Was there anything noted in the well operate. _ hat would have indicated when the tubing might have parted? When was the last successful WL entry into the we Tom Maunder, PE AOGCC From: Lambert, Steve A [mailto:salambert@chevron.com] Sent: Monday, September 12, 2011 7:26 AM To: Maunder, Thomas E (DOA) Cc: Cole, David A; Agler, Brit G; Greenstein, Larry P; Brooks, Phoebe L (DOA) Subject: G -29RD (PTD 192 -052; AIO 5.007) MIT Survey While attempting to run an MIT temperature survey on Grayling injection well G -29RD (PTD 192 -052) on 9/12/2011 Page 1 of 1 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Monday, September 12, 2011 7:58 AM To: 'Lambert, Steve A' Cc: Cole, David A; Agler, Brit G; Greenstein, Larry P; Brooks, Phoebe L (DOA) Subject: RE: G -29RD (PTD 192 -052; AIO 5.007) MIT Survey Steve, et al, Was there anything noted in the well operations that would have indicated when the tubing might have parted? When was the last successful WL entry into the well? Tom Maunder, PE AOGCC From: Lambert, Steve A [mailto:salambert@chevron.com] Sent: Monday, September 12, 2011 7:26 AM To: Maunder, Thomas E (DOA) Cc: Cole, David A; Agler, Brit G; Greenstein, Larry P; Brooks, Phoebe L (DOA) Subject: G -29RD (PTD 192 -052; AIO 5.007) MIT Survey While attempting to run an MIT temperature survey on Grayling injection well G -29RD (PTD 192 -052) on Thursday September 8, 2011, parted tubing was discovered at 1,076'. The biennial temperature survey was required under Administrative Approval AIO 5.007 granted on September 23, 2005. The well was shut -in on September 8, 2011 and will remain shut -in until the tubing can be replaced. Steve Lambert Senior Advising Petroleum Engineer Chevron North America Exploration and Production 3800 Center Point Suite 100 Tel 907 263 7658 salambert@chevron.com 9/12/2011 g-29rd Pressure Observations 3000 14000 Hours •Tubing •9 5/8" 12000 2500 713 3/8' I - Rate 10000 2000 . 11° Ill e I 111 111,A • A Tiii i 7 Ir , . r •I' • ' i w 1 ,44e 01 001, 8000 1 2 = cu vl .... 6" 1500 ---- la Ce It T 6000 1000 . 500 4000 0 2000 1 n _ 0 i _ __111111,Ems...-- -- 1.1.11111.11.111 Al- 0 12/18/08 07/06/09 01/22/10 Time 08/10/10 02/26/11 09/14/11 Printed on 9/12/2011 at 9:03 AM g-29rd Pressure Data 2011 09 11.xlsx Plot Pr essure & Rate vs Time - Well G -29RD 2000 1k )-1111111101 �- 8000 7000 �9 5/8" 1500 -- -- - -- 13 3/8" -- - -- — - I 6000 _,-"- 20" - Tubing - Vol 6 -29 5000 E 3 v) N J 0 co N m a 1000 4000 3000 500 .._.__ 2000 1000 0 i - in 0 0 o rn 15 O M M M N N N O CO O O O O co Date 13 3/8" 20" Tubirilroi G -29 TIO Report 09/01/11 25 0 19 7956 08/31/11 1740 30 0 1900 7946 Data Sheet 08/30/11 '= 1740 30 0 1900 7962 08/29/11 1740 30 0 1900 7988 08/28/11 1740 30 0 1900 8013 G -29RD 08/27/11 1720 30 0 1900 8000 08/26/11 1720 30 0 1900 7990 08/25/11 1700 20 0 1900 7999 INJECTION 08/24/11 1700 20 0 1900 8002 08/23/11 1700 20 0 1900 8032 08/22/11 1700 20 0 1900 7923 Permit # 1920520 08/21/11 1700 20 0 1900 7934 08/20/11 1700 20 0 1900 7966 08/19/11 1700 20 0 1900 7980 API # 50- 733 - 20374 -01 08/18/11 1700 20 0 1900 7992 08/17/11 1700 20 0 1900 7969 08/16/11 1700 20 0 1900 7980 03/01/2011 to 09/01/2011 08/15/11 1695 32 0 1900 7955 08/14/11 1690 32 0 1900 7940 08/13/11 1695 32 0 1900 7992 08/12/11 1695 32 0 1900 8074 +_ 08/11/11 1695 32 0 1900 8050 gt'O y-+�0 + -∎ Nk \l OS1; w1 t orr 08/10/11 1675 32 0 1850 8008 �j, "� 08/09/11 1630 32 0 1825 7939 08/08/11 1600 32 0 1800 7639 08/07/11 1720 35 0 1950 0 08/06/11 1720 35 0 1950 0 08/05/11 1720 35 0 1950 3757 08/04/11 1720 35 0 1950 8080 08/03/11 1625 35 0 1800 8083 08/02/11 1625 35 0 1800 8169 08/01/11 1625 35 0 1800 4016 07/31/11 1710 38 0 1990 8080 07/30/11 1710 38 0 1990 8509 07/29/11 111A 35 0 1800 1074 07/28/11 Am 41 0 0 3401 9/12/2011 9:00 AM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2011 09 01.xIs G -29RD • • Plot Pressure & Rate vs Time - Well G -29RD 2000 1 ` , ■ _ I _ m 8000 _ 0. • - 9 5/8" 13 3/8" ---20" 7000 - Tubing - Vol G -29 1500 __ --. 6000 5000 ai 3 J In CO H CO QJ 0- 1000 4000 3000 500 2000 1 - 1000 0 .� 0 O o o _ rn rn ao a n a m N N Si Si N N Si 0 O N (N O O O O Date 13 3/8" 20" Tubiol G -2g! TIO Report 03/31/11 - 50 0 1 7797 03/30/11 + 1750 50 0 2000 7801 Data Sheet 03/29/11 1750 50 0 2000 7804 03/28/11 1790 50 0 2000 7946 03/27/11 1790 50 0 2000 8047 G -29RD 03/26/11 1790 50 0 2000 8006 03/25/11 1785 50 0 2000 8035 03/24/11 1785 50 0 2000 8007 INJECTION 03/23/11 ; 1800 50 0 2000 8076 03/22/11 1800 50 0 2000 8226 03/21/11 1760 50 0 2000 8212 Permit # 1920520 03/20/11 1820 50 0 2100 8753 03/19/11 .4 1820 50 0 2100 4348 03/18/11 1800 51 0 1980 3140 API # 50- 733 - 20374 -01 03/17/11 i 1800 51 0 1980 8108 03/16/11 1800 51 0 1980 8054 03/15/11 1800 51 0 1980 8063 09/29/2010 to 03/31/2011 03/14/11 1800 51 0 1980 7734 03/13/11 1800 51 0 1980 7756 03/12/11 1800 51 0 1980 8122 03/11/11 6820 53 0 1990 7190 03/10/11 1820 53 0 1980 8018 03/09/11 1820 52 0 1980 8033 03/08/11 k.` 1820 52 0 1980 8016 03/07/11 1 1800 50 0 2000 8027 03/06/11 1800 50 0 2000 8025 03/05/11 1800 50 0 2100 8036 03/04/11 ' 1800 50 0 2000 8008 03/03/11 1800 50 0 2100 8012 03/02/11 ,' 1800 50 0 2100 8009 03/01/11 1800 50 0 2100 8013 02/28/11 1820 52 0 2000 8009 02/27/11 1820 52 0 2000 7999 02/26/11 �- 1840 55 0 2000 8012 02/25/11 ' Ada 55 0 2000 8020 02/24/11 1.111 55 0 2000 8020 9/12/2011 9:01 AM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2011 03 31 (6).xls G -29RD • . Plot Pressure & Rate vs Time - Well G -29RD 2000 1 V l -.. V 'i ^ 8000 r 7000 9 5/8" 1500 13 3/8" — — _._ 6000 — 20" - Tubing Vol 5000 ai 3 N m E m - 1000 ._..__. 4000 3000 500 __ --- 2000 i ll 1 1000 O o O O O O O co O o <h o M N N O o O O O co O Date - . 13 3/8" 20" Tu ,r?"1"'" TIO Report 09/30/10 - 100 50 0 0 0 09/29/10 100 50 0 0 0 Data Sheet 09/28/10 100 50 0 0 0 09/27/10 90 50 0 0 0 09/26/10 90 50 0 0 0 G -29RD 09/25/10 100 50 0 0 0 09/24/10 100 50 0 0 0 09/23/10 120 50 0 0 0 INJECTION 09/22/10 120 50 0 0 0 09/21/10 120 50 0 0 0 09/20/10 120 50 0 0 0 Permit # 1920520 09/19/10 150 50 0 150 0 09/18/10 200 40 0 100 0 09/17/10 200 40 0 100 0 API # 50- 733 - 20374 -01 09/16/10 200 40 0 100 0 09/15/10 350 35 0 350 3585 09/14/10 _` 2040 88 0 2150 8456 04/01/2010 to 10/01/2010 09/13/10 2040 88 0 2150 8456 09/12/10 2040 88 0 2150 8434 09/11/10 2040 88 0 2150 8428 09/10/10 2040 75 0 2100 8465 09/09/10 ,. 2040 75 1 2100 8484 09/08/10 2040 75 0 2100 8470 09/07/10 `x 2000 85 0 2100 8427 09/06/10 <,x 2000 85 0 2100 8316 09/05/10 e. 2000 85 0 2100 8332 09/04/10 !: 2000 85 0 2100', 8334 09/03/10 <K- 2000 85 0 21001 8358 09/02/10 '+ 2000 85 0 2100 8364 09/01/10 ,..$ 2000 85 0 2100 8380 08/31/10 'ts 2000 85 0 2100 8420 08/30/10 ':' 2000 85 0 2100 8422 08/29/10 2000 85 0 2100 8648 08/28/10 1 85 0 2100 8261 08/27/10 18Q 115 0 2100 8071 08/26/10 115 0 2100 8288 9/12/2011 9:02 AM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2010 10 01 (4).xls G -29RD ~ • Page 1 of 1 Regg, James B(DOA) ~ i`~2- d~v From: Regg, James B (DOA) ~ ~~~ ~~~~ Sent: Thursday, July 16, 2009 10:00 AM l l To: Greenstein, Larry P Cc: Aubert, Winton G(DOA); Schwartz, Guy L(DOA) Subject: Mechanical Integrity Determinations - Grayling Wells During our phone conversation 7/15/2009, you requested clarification about timing of inechanical integrity determintations for several wells on TBU Grayling Platform. Temperature surveys for TBU G-29RD (PTD 192- 052; AIO 5.007) and G-11 (PTD 168-043; AIO 5.009) and were performed on 2/20/2009 and 7/8/2009 , respectively. You questioned if these temp surveys - performed up to 7 months early - can be used to satisfy the requirements of administrative approvals. Both surveys will be considered by the Commission as satisfying compliance with the administrative approvals; please note that testing early will not reset the due date for temperature surveys; next temperature surveys will be due as follows: TBU G-11 due 12/15/2011 TBU G-29RD due 9/23/2011 You also mentioned that the standard MIT (pressure test) for TBU G-14ARD (PTD 191-099) was due April 6, 2009 but platform production and injection has been SI due to Redoubt volcano eruptions. Delaying the MIT until the G-14ARD was put back on injection was discussed and agreed to previously (refer to June 12, 2009 email). You indicated that Union is assessing restarting Grayling production and injection in August - please notify us when injection recommences and to arrange for a witnessed MIT. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 , ~. ~ ~~'~'~~.:;' ~` r?(~ i~ `v,. ~r. wY.w~'' . ~ ~ ~.;; .~ ._ L.V ~iJ_= 7/16/2009 • ~ Page 1 ~~~~ Regg, James B (DOA) ~ lRZ-c~SZ-- From: Martin, J. Hal [Hal.Martin@chevron.com] Sent: Monday, February 23, 2009 4:22 PM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA); Greenstein, Larry P; Cole, David A; Lambert, Steve A Subject: Grayling G-29RD Waterflood Injector (Permit No. 192-052) Temp Survey Follow Up Flag: Follow up Flag Status: Orange Attachments: G-29 Static log 2-20-09.zip; G-29RD_MD_TempSurvey_2-20-09vs6-24-07and8-26-05.pdf; G-29RD_TVD_TempSurvey_2-20-09vs6-24-07and8-26-05.pdf; G- 29 RD_TVD_TempSunrey_2-20-09Shiftedvs6-24-07and8-26-05. pdf Tom, We ran a temp survey on Grayling Platform Well No. G-29RD (Permit No. 192-052) waterflood injector last Friday, 2/20/09. The well remains shut-in. Attached is the survey as well as scanned graphs of this survey along side the previous two surveys (8/26/05 and 6/24/07) on this well from a MD view, TVD view, and a view where the 2/20/09 survey is shifted to more closely overlay the other two. From my perspective, the answer appears to be that there is no injection of water in to any interval above the packer and all injected water is therefore going in to intervals approved for injection below the packer. Take a look and give me a call if you have any questions or want to discuss. If the AOGCC agrees and approves, then I would expect this temp survey to reset the 2- year clock for the next Admin Approval temp survey to 2/19/2011. Once the AOGCC approves, my current plan is to bring this well back on injection and increase the volume going in to the well such that the injection pressure is about 2500 psi for about a month or two and monitor the response we see on the G-15RD ESP producer it has supported. In the interim, we will be trying to figure out if there is a way we can reasonably expect to be able to determine where the excess water is going and also if there is a way we think we might be able to reduce it or shut it off. Let me know if you require anything else. Thanx, Hal Martin Optimization Engineer MidContinent/Alaska Business Unit Chevron North America Exploration and Production 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tel 907 263 7675 Fax 907 263 7847 hal. martin@chevron.com 9/16/2009 • • ~ 112-t~Sz Chevron Well: G-29RD Field: Grayling Date Pressure {psis) 0 500 1000 1500 2000 2500 3000 3500 4000 m Y .-. as .~ s a as 1 1 1 Temperature (Deg. F) 6-24-07 Pressure - Perfs 13-318 9-518 7 5 Tbg 6-24-07 Temp ~8-26-05 Temp 2-20-09 Temp 60 70 SO 90 100 110 120 130 140 Chevron Well: G-29RD Field: ~r~ylinrl Date 2-20-09 Temperature {Deg. F) 55 65 75 85 95 105 115 125 0 ... 01 ~... .C a a~ 1 - ---- -- - Perfs 13-3/8 9-518 7 5 Tbg 2-20-09 Temp 6-24-07 Temp ~8-26-05 Templ 70 80 90 100 110 120 130 140 8-26-05 and 6-24-07 Temperature (Deg. F) Chevron Well: G-29RD Field: Grayling Date f7 .- d t a d O so 70 6-24-07 Pressure - Perfs 5 Tbg so 9a 100 110 120 13o iao Temperature (Deg. F} 13-318 9-518 7 fi-24-07 Temp ~8-26-05 Temp 2-20-09 Temp Pressure (psis} 0 500 1000 1500 2000 2500 3000 3500 4000 ~ ~~'~~~ ~ ~ 2' ~~ P --~ ~ ~z.r ~-~v Pressure (psia) 0 500 1000 1500 2000 2500 3000 3500 4000 0 1000 i --- 2000 i - i 3000 I i 4000 I ~ - - - .~. ~ 5000 - ... 0 6000 7000 - --- 8000 - - 9000 10000 60 65 70 75 80 85 90 95 100 105 110 115 120 125 Temperature (Deg. F) -- - Perfs - 13-3/8 ° °- 9-5/8 7 5 Tbg Pooh Psia Pooh Temp Chevron Well: G-29 ~'~ Field: Grayling 02-20-2009 130 4000 120 3500 Going in Hole POOH Static Well Shut-In 110 3000 100 _ ~ 2500 -• ~ : v~ Gauge at depth ~ ~ ~ 11600' RKB 90 m 2000 N ~ N L 80 ~ Q- 1 500 ~ 70 1000 60 500 50 40 0 14 15 16 17 18 19 20 21 22 23 Time (hrs) Pressure Temperature • • Chevron Well: G-29 ,2) Field: Grayling Date 02-20-2009 0 500 1000 m Y .~ m m y- .-. L Pressure (psia) 1500 2000 2500 3000 3500 4000 0 1000 - - 2000 Pressure-Temperature Profile 1. RIH -POOH 11600' RKB ---- 2. Well Shut-in 3000 - 4000 - - - - -- - -- 5000 --- - 6000 --- - - - 7000 - -- -- -- 8000 - - F 9000 -- 10000 -- -- ,.~ - 11000 - - 12000 50 55 60 65 70 75 80 85 90 95 100 105 110 115 120 125 Temperature (Deg. F) - _ _ -_--- Pressure - Perfs --- 13-3/8 - °~-°° 9-5/8 7 Iii 5 Tbg POOH PSIA Temperature - -POOH F Chevron 0 1000 2000 3000 4000 Y 5000 .-. a~ sooo t a m 7000 sooo 9000 10000 11000 12000 W Fie ~~ ~~~z -u~ Z- Date 02-20-200! Pressure (psia) 500 1000 1500 2000 2500 3000 3500 4000 Pressure-Temperature Profile 1 Going in hole 06.07,09 Overlay M --- (. ~5 60 65 70 75 80 85 90 95 100 105 110 115 120 125 Temperature (Deg. F) Pressure 09 - Perfs 13-3/8 9-5/8 7 5 Tbg -- - - 07 pressure ~, 06 Press Temperature 09 07 temp 06 Temp ~ ~~zz,-c s Z Chevron ell: G-29 ~`:~ Field: Gra ing 02-20-2009 5000 ~ 6000 Q d 7000 8000 9000 10000 11000 12000 ~4- 60 65 70 75 80 85 90 95 100 105 110 115 1201 125 Temperature (Deg. F) - ~O- Pressure 13 3/8 9 5/8 7 5 tbg - Perfs - - {3 - -Temperature Pressure (psia) 1500 2000 2500 3000 3500 4000 Pressure-Temperature Profile I 1. Pulling out of hole from 1 1600 MD 2. Making stops 3. Well Shut-In RKB TVD Pressure Temp P-Grad T-Grad (feet) (feet) (psi) (Deg.F) (psilft) Deg.F/ft 41.2 41.2 0.52 64.36 2000.0 1999.6 396.89 76.78 0.2024 0.63 3999.4 3817.5 1200.14 76.78 0.4419 0.00 6000.7 5229.4 1827.39 83.25 0.4442 0.46 - - 8000.3 6631.2 2451.53 91.91 0.4452 0.62 10000.5 7997.6 3058.99 105.33 0.4446 0.98 11601.0 8867.4 3442.83 114.77 0.4413 1.09 \~ - '• ~ -- ~ \ - ~ ~ ~~ ~ '. ~ '~ ~ I ~. ~ - \ '. ~ --- ~~ ~~ ~, . ICtz -ajz Chevron Well: G-29~+'~ Field: Gravlu a Date 02-20-2009 Pressure (psia) 0 500 1000 1500 2000 2500 D H ..~ s d .~~ 1 3000 3500 4000 50 55 60 65 70 75 80 85 90 95 100 105 110 115 120 125 Temperature (Deg. F) Pressure - Perfs 13-3/8 9-5/8 7 5 Tbg Temperature • Regg, James B (DOA) From: Regg, James B (DOA) Sent: Wednesday, December 26, 2007 5:23 PM To: 'Greenstein, Larry P' Cc: Maunder, Thomas E (DOA) ;~ Subject: RE: Well with Questions on Determining the Anniversary Dates for Compliance Temp Surveys Larry -Each of the listed admin approvals did not establish a formal anniversary date for de#ermining when to perform compliance temperature surveys. There has been some confusion that has resulted. Based on what f have read below and our conversation earlier today, I believe using the effective date (signature date) of the administrative approvals is consistent with your request for nearly all wells accomplishes what you are after {efficiency). The wells you reference below are (with a due date for the next temp survey): Granite Pt State (Anna} 19 - AIO 6.008 {3/29/2005); next temp survey due 3/29/2009 Granite Pt State (Anna) 21 - AIO 6.009 (3/29/2005); next temp survey due 3/29/2009 TBU G-11 - AIO 5.009 (12115/05); next temp survey due 12115/2009 (yo=..~ suggested 9/2009) TBU G-22 - AIO 5.006 (9/14/2005); next temp survey due 9/14!2009 TBU G-23RD - AIO 5.004 (6/3012005); next temp survey due 6/30/2009 {you suggested 312009) TBU G-27 - AIO 5.003 (3/2912005); next temp survey due 3129/2009 TBU G-29RD - AIO 5.007 {9/23/2005}; next temp survey due 9/23/2009 TBU G-40 - AIO 5.002 {3129/2005}; next temp survey due 3/29/2009 TBU K-11 - A10 5.011 {216/06}; next temp survey due 2/6/2010 TBU K-24RD2 - A[O 5.010 (216/06}; next temp survey due 2/6/2010 There is nothing preventing Chevron from testing earlier {as you have proposed for 2 of these wells). This does not affect any admin approvals that have anniversary dates specifically listed in the conditions. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 ~~~ ~~~c ~ ~ ~oc7 From: Greenstein, Larry P [mailto:Greenstein{p@chevron.com] Sent: Wednesday, December 26, 2007 10:45 AM To: Regg, James 6 (DOA) Subject: Well with Questions on Determining the Anniversary Dates for Compliance Temp Surveys Thanks for the conversation on this anniversary date topic Jim. It gets real confusing for me to keep the different basis for the anniversary dates separate for each well. The wells in question are: An-19 - AA signed 3/29x`05 -last compliance temp survey 10!3f06. t1Vou!d like to slide 10108 temp survey to 3109 to get on AA anniversary date cycle. An-21 - AA signed 3/29/05 -last compliance temp survey 10/4.%06. Would like to slide 10!08 temp survey to 3!09 for the AA date reason. K-11 - AA signed 216!06 -last compliance temp survey 12;11/07 {ust sent to you). Would like to slide 12;09 temp survey to 2110 for the AA date reason. • i~z o ~~ 12/26/2007 ~- ---a- - ---- K-24RD2 - AA signed 216106 -last c~iance temp survey 12/21107 (wilt send t~ soon}. Would like to slide 12109 temp survey to 2110 for the AA date reason. The Grayling wells have some other things going on. We have wells with AA anniversary dates in every quarter. {sure would like to get the number of logging visits down to just twice a year instead of four times a year. Maybe slide G-23RD forward from June to March and G-11 forward from December to September. This way only two wells get off the AA anniversary date cycle and we'll have three wells due for temp surveys each visit. G-11 - AA signed 12/15;05 -last compliance temp survey 6/25107. Would like to slide to 6109 temp survey to 09/09 for efficiency. G-22 - AA signed 9114.'05 -fast compliance temp survey 4x26107. Would like to slide 4109 temp survey to 9109 for the AA date reason. G-23RD - AA signed 6!30105 -fast compliance temp survey 4!19x`07. Would like to slide 4t09 temp survey to 3/09 for efficiency. G-27 - AA signed 3129!05 -last compliance temp survey 9/21!06. Would {ike to slide 9108 temp survey to 3109 far the AA date reason. G-29RD - AA signed 9123105 -last compliance temp survey 6;24/07. Wauid Pike to slide 6109 temp survey to 9109 for AA date reason. G-40 - AA signed 3129f05 -last compliance temp survey 9/21106. Would Like to slide 9108 temp survey to 3109 for AA date reason. I hope there aren't any more hiding out there. Surely next year I'll find one or two, but for now this list looks like all of them. Thanks again for your consideration Jim. Call me if you want to discuss some more. Larry 263-7661 12/26/2007 ----~ 2-Year Temperature Survey Timing Requirements Granite Point Field and Trading Bay Unit Administrative Approvals for these wells did not include specific anniversary dates for determining when to perform compliance temperature surveys (alternate mechanical Background Info: integrity determinations in lieu of MITs}. Clarification was requested by Chevron (L. Greenstein; 907-263-7661) on 12/2612007. The following table summarizes admin approval info, anniversary date options, and the Commission's decision. Well PTD AA Anniversary Date AA Date Last Surve GP State An-19 168-006 6.008 3/29/2005 10/3/2006 GP State An-21 176-049 6.009 3/29/2005 10/4/2006 TBU G-11 168-043 5.009 12/15/2005 6/25/2007 TBU G-22 175-016 5.006 9/14/2005 4/26/2007 TBU G-23RD 179-014 5.004 6/30/2005 4/19/2007 TBU G-27 178-070 5.003 3/29/2005 9/21/2006 TBU G-29RD 192-052 5.007 9/23/2005 6/24/2007 TBU G-40 190-003 5.002 3/29/2005 9/20/2006 TBU K-11 168-083 5.011 2/6/2006 12/11/2007 TBU K-24RD2 201-141 5.010 2/6/2006 12/21/2007 GP State An Granite Point Field, Anna Platform TBU G Trading Bay Unit, Grayling Platform TBU K Trading Bay Unit, King Salmon Platform AA Administrative Approval (AIO 5 and AIO 6, Rule 9} Options Next Temp Survey Due, Based on AA Date1 AA Date2 Last Survey 3/29/2007 3/29/2009 10/3/2008 3/29/2007 3/29/2009 10/4/2008 12/15J2007 12/15/2009 6!25/2009 9/14/2007 9/14/2009 4/26/2009 6/30/2007 6/30/2009 4119/2009 3/29/2007 3/29/2009 9/21/2008 9!2312007 9!23!2009 6/24/2009 3/29/2007 3/29/2009 9/20/2008 2!6/2008 2/6/2010 12!11/2009 2/6/2008 2/6/2010 12/21 /2009 last update: 12/26/2007 Next Survey Due (Chevron Proposed) Next Survey Due (AOGCC) Which Option? 3/29/2009 3/29/2009 AA Date 3/29/2009 3/2912009 AA Date 9/30/2009 12/15/2009 AA Date 9/30/2009 9/14/2009 AA Date 3/30/2009 6/30/2009 AA Date 3/30/2009 3/29!2009 AA Date 9130!2009 9/23/2009 AA Date 3/30/2009 3/28/2009 AA Date 2/28/2010 2!6!2010 AA Date 2/28/2010 2/6/2010 AA Date • 2007/uly's Waivered Injection we.port Regg, James B (DOA) . Page 1 of2 From: Greenstein, Larry P [Greensteinlp@chevron.com] Sent: Thursday, August 09,200711 :29 AM To: Regg, James B (DOA); Maunder, Thomas E (DOA) Cc: Lambert, Steve A Subject: RE: 2007 July's Waivered Injection Well Report Jim, n 1 cohCt/D7 \Z-l1 \q~- D$J-. '( ~0Ù &~qR'þ Both wells have had some recent wireline work that might explain the pressure changes you noted. Steve Lambert provided the following summary: G-22- The casing pressure increased on July 13. This is the day we ran the injection survey and we opened the annulus to flow in an attempt to locate any tubing leaks. Since that time the tubing and casing have been tracking. It appears that gas in the annulus was blown off the well and now both strings are tracking. (We are still waiting on the log results.) G-29RD This well was surveyed on July 14 and 15. Once again the annulus was opened to flow during the test. 2 days later on 7/17 the casing pressure dropped to zero and has remained low. (I believe the pressure probably dropped at the time of the survey and was not recorded properly until 7/17.). The change in casing pressure is a result of having blown off the pressure on the annulus and the annulus has not repressured to date. The pressure gauge on the casing was changed on August 6 and the pressure is currently reading zero. We are awaiting the results of the survey to determine if the source of the tubing 1 casing communication can be determined. The one curiosity, is why didn't the annulus pressure in G 29RD pressure back up with the tbglcsg communication that necessitated the admin approval in the first place?? We even changed out the gauge to make sure the readings were accurate. We are very interested in what the recent injection surveys will show us about both these wells. Hope this helps. Larry From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Wednesday, August 08, 2007 10:08 AM To: Greenstein, Larry P; Maunder, Thomas E (DOA) Cc: Martin, J. Hal; Lambert, Steve A; KRAMER, TED E Subject: RE: 2007 July's Waivered Injection Well Report Larry - When you get a chance, a couple things to look at... SCANNED SEP 0 7 2007 G-29RD: Why the sudden drop in IA pressure? Seems uncharacteristic for this well with TxlA communication; IA has always tracked tubing pressure. G-22: Quick review of history indicates that there has normally been a 300-500 psi differential between T and IA; since 7/13/07 pressures have been equal; is communication getting worse? Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: Greenstein, Larry P [mailto:Greensteinlp@chevron.com] Sent: Wednesday, August 08,20079:17 AM 8/29/2007 2007 July's Waivered Injection We~port To: M~under, Thomas E (DOA); Regg,~es B (DOA) 'Cc: Martin, J. Hal; Lambert, Steve A; KRAMER, TED E Subject: 2007 July's Waivered Injection Well Report . Page 2 of2 Hi Tom & Jim, Here is July's monthly report for all the active monitored injection wells. The King (deaereator) and Steelhead (well) waterfloods are still down. As you can see, the A-8RD2 well has maintained some pressure isolation between the tubing and casing pressures. Possibly a slow equalization is occurring (trend shows -4#/day) and we would like to watch this for another month or so to confirm. There was a pressure spike on An-32RD in the middle of July. The well was already shut-in, so it seems odd to show this pressure. Talked with the operators and nobody had an explanation. Doesn't appear to be typos. With all the ups and downs of Anna injection lately, possibly the well got opened and then shut back in without any injection volumes measured. Just don't have an answer for this spike. The well settled right back down to normal pressures right after this 'event'. Lots of ups and downs, as usual, but nothing out of the expected changes in rates 1 pressures was recorded this last month. Bottom line, I don't see any indication of any of these wells losing control of the injected fluids downhole. Larry «Master Well List TIO Report 200707 31.xls» 8/29/2007 o 500 1000 1500 2000 2500 -9 5/8" 13 3/8" ,~ . . tq~· 07~ A 1líf 1\Ii(O 1 TBU_G-29RD_temp_survey_2007-0702.txt FW: G-29RD compliance Temperature surveyFrom: Lambert, Steve [salambert@chevron.com] Sent: Monday, July 02, 2007 4:32 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA) Cc: Greenstein, Larry P Subject: FW: G-29RD compliance Temperature survey Attachments: 6-24-07 survey.zip G-29RD Admin Approval Temperature Survey Jim, Tom well G-29RD (PTD 192-052) was granted Administrative Approval (AIO 5.007) on september 23,2005. AS required under the approval, a follow-up temperature survey was run on 6-24-07. The survey (see attached) is consistent with the survey run on 8-26-2005. The current survey confirms that all injected fluids are being contained within the zones of injection. please contact me if you have any questions concerning the survey. «6-24-07 survey.zip» sCANNE.D JUL 2 0 20m page 1 . m 5000 ~ 0::: - .... CI) .! 6000 - .c .... c. CI) 7000 C 10000 11000 12000ïi;- 70 . . o o 1000 Pressure (psia) 1500 2000 2500 3000 3500 4000 500 2000 I --------- ,- --- .-- ----1 -:----~-----~~---c~---! .j------ - - --~"-j 3000 4000 8000 9000 ! i ___~_.___..__m____+___--.--.m----'-. -------~~ -;- ", I \ - 1:······1 n_n_ __m____"_ .." -- --.. r .. -i· no pi-. - - -- - --- -" 80 90 100 110 120 130 140 Temperature (Deg. F) -----------~-----~~--- - ----------~--~--------.--- -----------~ --~~---- --~~-~------ _.__.._---------~ 7 - 5 - Tbg -6-24-07 Temp -8-26-05 Temp: -6-24-07 Pressure - Perfs - 13-3/8 -==-9-5/8 " ' ') ) @'e,'............" i !(id, ,",":""';j"" , ì~~~ r i )0">1\ I) i' ~ G~i i,'IOt) : ::=ïJ d::J ''"'':'';:-'';¡¡ : I !,'Lfi...; , I :¡ : ), i L:=J 1-; FRANK H. MURKOWSKI, GOVERNOR AI{ASIiA. OIL AND GAS CONSERVATION COMMISSION October 21, 2005 333 W. pH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)276-7542 Don Page Production Accounting Manager UNOCAL [Chevron] P.O. Box 196247 Anchorage, Alaska 99519 Re: Offshore Injection Volume Corrections ., Ö6ð-- \~f} ....~ &/à-c>\ SCI\~~ED ~O\l (.\ t !\}í\Y) Dear Mr. Page: In early May, a discrepancy between the official injection volume reported to the AOGCC and the Unocal internal volume for TBU well G-29RD was discovered~ In the case of this particular well, Unocal's volumes were nearly double those reported to the AOGCC. U nocal's preliminary findings revealed that the discrepancy was likely due to particular wells existing in both Unocal's production and injection databases. The double entry evidently occurs when a well is converted from a producer to an injector and the particular well is added to the injection well database, but is not removed from the production database. The preliminary finding indicated that it is likely that this "multiple entry" affects a number of wells in at least Trading Bay Unit and Granite Point Field. The most recent update we have on this matter was received August 24 (copy attached), however a final resolution date has not been identified. At this time, the magnitude of the necessary volume changes have not been communicated to the AOGCC. However it has been indicated that in some cases the volumes have been inaccurately reported for several years. Lately, Chevron production accounting personnel from California have contacted our Statistical Technicians regarding preparations for changes in the production reporting process. These conversations have indicated that beginning in 1 st Quarter 2006 Chevron's Houston office will be submitting the required reports. It is in our mutual interests to have this matter resolved as expeditiously as possible and in advance of any internal Unocal [Chevron] functional realignment. Don Page October 21, 2005 Page 2 of2 ) ) By copy of this letter, Unocal is directed to complete the determination of these volume corrections as well as any other production/ injection accounting problems and present them to the Commission not later than November 15, 2005. Please contact Steve McMains at 793-1241 or Tom Maunder at 793-1250 if further information is required. ø Daniel T. Seamount, J r. Commissioner cc: John Zager Vice President, Unocal Jdll-L.YVV ~V lVläY, L.VV.J ) ) Sûblect:, Jan~2000 tc:rMay, 2005 ....,.... .':" '..:.' . . ." . . .' . ..: ..' - . All Concerned Parties: Revision Water Injection AK10-406 for All Facilities Various Years 2000 to May, 2005 Revision Time Line: 1. Unocal to complete necessary corrections to the PRISM database. This portion is completed for all major errors. 2. Networks will be up dated to perform allocations properly. Will complete today -- August 19th, 2005 3. Facility Networks for each month for the various years committed to NETWORKS This will take some time as our allocation application requires that each month be run separately. 4. Preparing a test set of reports to check our internal & external reports against one another for accuracy 5. For injection revisions only, we propose to furnish an electronic file as we have in the past. However, instead of hard copies of the 10-406, we would submit an excel (text) file with the 10-406 data, which our database manager has been working on. a. Submit the test reports using the electronic file, text file, and hard copy. b. Request AOGCC to determine if the text file would be acceptable as a revise report. When the test set has been reviewed and any problems resolved, we will begin by doing the remainder of the Injection reports. We can better determine a completion date at that time. Thanks, Janet (Dormady Unocal Ala8ka Senior ,Production Clcrk 909 rrest 9th A l'enue .Anchor;lgc, AK 99501 Elnail: dormadyj(í?;unocal.com Phone: 907-263-7946 FA..X: 907 -263-7607 1 of 1 10/13/2005 3 :06 PM 10/13/2005 3 :20 PM 1 of 1 Larry A joint effort between engineering and production accounting will be required to resolve these discrepancies. As we discussed earlier today, Unocal recognizes that some incorrect water injection volumes have been reported to the state. We are investigating the cause and expect this will require revisions to be sent to the state. Torn, -------- Original Message -------- Subject: Waterflood volume issues Date: Tue, 10 May 2005 13:22:07 -0800 From: Greenstein, Larry P <greensteinlp@unocal.com> To: Thomas Maunder <t.om maunder@admin.state.ak.us::> CC: Cole, David A <'2L(~'()"rë@Ùrï'(:;'(~'a'I"':'''¿~''oñL~''~'''''''''LamEë'r't"~"''''''''S"t''eve A <salambE::rt@unocal. com>, Ha 1 Ma rt i n .~.:.~9.:F..~..~.~~.Þ.:.~~.~.!.~.?..~..9.:.~....:...S::.9.~~~.?.:.' Do 1 an , J e f f J .:~..?:.9..~..9.:.!.:Uj..~~~~~g.~:.~~.~...~..~~.~!~.?:.., Page, Dona 1 d A <dpa9E::@Unocal . com>, Dormady, Janet N <dorm.ady:) @unocal . com>, Whitacre, Dave S <whitacred@unocal.com> Further to the earlier messages. From a conversation with Larry, it appears that they have "a disconnect" when the injection volumes are transferred from engineering/operations to accounting. All the engineers use OFM which picks up the information from their "Prism" system. OFM, Prism and the actual well meter readings agree, however in the case of G-29RD "their" numbers are nearly double what we have in RBDMS. Apparently their greatest problem is with wells that are converted from producer to injector and is due to accounting's not changing the status of the well in their system. The well evidently exists in both databases and the program attempts to force allocate. From the preliminary work Unocal has done, corrections could be necessary at least for 4 years on some platforms. I will keep you all informed as I receive additional information. Tom Subjec~: [Fwd: Waterflood volume issues] From: Thomas Maunder <tom _ maunder@admin.state.ak.us> . . ..' . .....It"""'~ Date: Tue, 10 ~ay 2005 13:3.9:14 -08~0 ."'!I\/a,~:}:J0 To: Stev~ Davies <steve__davies@admln.state.ak.us>, Steve McMains . <steve _ mcmains@admin.state.ak.us>, John D Hartz <jack ~hartz@admin.state.ak. us>, Jane Williamson <Jane _ Williamson@admin.state.alcus>, Jim Regg <j im_regg@admin.state.alcus> ) ) !Fwd·:, Wa~erflood volume issues] . , " . [Fwd:..RE\Waterflood volume issues] ) Su bjec~: [F\vd: RE: Waterflood volume issues] From: Thomas Maunder <tom _ maunder@admin.state.ak.us> Date: Fri, 05 Aug 2005 11 :29:07 -0800 To: Steve McMains <steve,-mcmains@admin.state.ak.us> CC: Steve Davies <steve_davies@admin.state.ak.us> .,\(!1~"'ëJ'5'-r- Steves, FYI -------- Original Message -------- RE: Waterflood volume issues Fri, 05 Aug 2005 11:05:40 -0800 Greenstein, Larry P <greensteinlp@unocal.com> Thomas Maunder <tom maunderCi\adrnin. state. ak. us> Subject: Date: From: To: Tom, We are definitely getting close. Our production accounting folks have told me that they believe they will be done with this next week. They are in contact with Steve McMains about electronic vs hard copy revisions and this seems to be slowing their progress. Thank you for being so patient. Larry -----Original Message----- From: Thomas Maunder [¡~?:..~..~..~..<::.~..,:....t~.g,!!l-~.~~.~.ª~..!~.9.:.ª.~.~.!.~..~....§..~..~.~~.~...~...~~.~...:...\1..~] Sent: Thursday, August 04, 2005 2:54 PM To: Greenstein, Larry P Cc: McMains, Stephen E -AOGCC Subject: Re: Waterflood volume issues Larry, Any news on this matter. I realize that there are a lot of peri feral issues out there, but I'd really appreciate a status report on this work and an estimate of completion. Thanks in advance, Tom Maunder, PE AOGCC Greenstein, Larry P wrote, On 6/29/2005 9:13 AM: Thanks Tom. We'll get it to you as soon as we can put it together. ---------------------------------------------------------------------- * From: * Thoma s Ma unde r [~9.:..~}..!:.,.?..:...!::..S?.,r..[~l.~,~\1..9.:.ª.~.E,~,.~_'?.:~.~..9.:...~....§..!:..9.:.!:..~...:...~,~...~,..\1.,~] *Sent:* Wednesday, June 29, 2005 7:32 AM *To:* Greenstein, Larry P *Cc:* Dormady, Janet N¡ Dolan, Jeff J *Subject:* Re: Waterflood volume issues Larry, Jeff and Janet, I have an appreciation for the volume of work this task must entail. I was curious to see how it was progressing. Good luck to all. Tom Maunder Greenstein, Larry P wrote: We got Jeff Dolan involved also to get the timing of the revisions figured out. 1 of3 10/13/2005 3 :07 PM ,[Fwd': RE: Waterflood volume issues] )' I, . 20f3 ') ) Still working the issue and approaching the final solution to correcting all the en~'ors . Sorry this is taking so long. ..just goes slow. Larry -----Original Message----- From: Thoma s Ma unde r [:~:~~9.:..~..~.:~:..~?...:...!::g:r.~~~~.9.::~~!.:~.ª.~E.~~).9.:~~~~~~.~..~~...:.,..~~~.:~:...~~:~:..~...~...9.:.~...~..~:~.§?.] Sent: Tuesday, June 28, 2005 3:53 PM To: Greenstein, Larry P Subject: Re: Waterflood volume issues Hi Larry, Just a check up on the status of the "revision project". How goes the process?? Tom Maunder, PE AOGCC Greenstein, Larry P wrote: Janet Dormady is working on the issue. It looks like it goes back some time. We figured out the problem, now we just have to figure out the cleanest way to get a solution. It will be a lot of revisions. Larry -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Monday, June 06, 2005 4:00 PM To: Greenstein, Larry P Subject: Re: Waterflood volume issues Larry, How goes the resolution of the injection volumes?? Tom Maunder, PE AOGCC Greenstein, Larry P wrote: You got it Torn. -------------------------------------------------------------------- * From: * Thoma s Ma unde r [t!.1.<?:..~..~.~..S?...:,..~..9.,r.r.~~.9.:~?.:!.~.9..~E.~~.9..9.:~:0.,~..~_~...:....?,~,9...1::,..~....~...9.:,~..:...\~..?] *Sent:* Tuesday, May 10, 2005 1:47 PM *To:* Greenstein, Larry P *Cc:* Cole, David Ai Lambert, Steve Ai Hal Martini Dolan, Jeff Ji Page, Donald Ai Dormady, Janet N¡ Whitacre, Dave S¡ McMains, Stephen E 10/13/2005 3 :07 PM ~[FJiV&: rŒ: Waterflood volume issues] ~, .. ';" 3 of3 ) -AOGCC¡ Steve Davies *Subject:* Re: Waterflood volume issues Larry, et al: Thanks for the explanatory note. Good luck with chasing this gremlin down, I have no doubt you all will do it. As this matter proceeds to resolution, I suggest that any resubmission of production/injection data be accomplished only after an explanatory letter is sent to the Commission. I don't think these changes should be made piecemeal. I am suggesting this since it appears that there will be a number of changes and some sort of "notice or explanation" may need to be added to the AOGCC web site information but I will defer to Steve McMains on this matter since the production and injection databases are his "domain" . Please call or message with any comments/suggestions. Tom Maunder, PE AOGCC Greenstein, Larry P wrote: Tom, As we discussed earlier today, Unocal recognizes that some incorrect water injection volumes have been reported to the state. We are investigating the cause and expect this will require revisions to be sent to the state. A joint effort between engineering and production accounting will be required to resolve these discrepancies. Larry 10/13/20053:07 PM n ALA3SA OIL AI~TD GA,S CO1~T5ER~A1`IO1~T CO1~II~II3SIO~T ADMINISTRATIVE APPROVAL AIO 5.007 Mr. Steve Lambert Reservoir Engineer Unocal Alaska P.O. Box 196247 Anchorage, AK 99519-6247 333 W. T" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 RE: Trading Bay Unit G-29RD [aka Grayling 29RD] (PTD 192-052) Request for Administrative Approval AIO ~ Dear Mr. Lambert: By letter dated September 14, 2005, Unocal Alaska "("Unocal") requested that the Alaska Oil and Gas Conservation Commission ("AOGCC" or '`Commission") grant an administrative approval per Rule 9 of Area Injection Order ("AIO") 5, to continue water injection into the subject well without complete mechanical integrity. After review, the Commission hereby grants Unocal's request for administrative approval for water injec- tion in the subject well. AOGCC finds the following: 1. This well was originally reported to have experienced tubing x inner annulus ("T x IA") communication in May 2005 and was shut-in. 2. On May 25, 2005 Unocal applied by Sundry application to return the well to in- jection so that diagnostic logging could be performed in support of an administra- tive approval. 3. Following review of available information, Unocal's application was approved on June 6 subject to recording and submitting the daily injection rate and well pres- sure information and performing a subsequent temperature survey. 4. Actual injection did not begin until mid July. While injecting. Unocal has been recording daily injection rate and well pressures and has provided this information to the Commission. In support of this application, Unocal has submitted a base- line and subsequent temperature log. ~. Based upon analysis of the submitted logging information, there are no tempera- ture anomalies indicated. The rate/pressure information has not indicated any fur- therpressure integrity loss. 6. At this time, Unocal is not proposing to repair the well to restore full integrity. • FRANK H. MURKOWSKl, GOVERNOR Mr. Steve Lambert September 21, 2005 Page 2 of 2 7. An aquifer exemption is in effect for all aquifers lying directly below iVlcArthur River Field (Trading Bay Unit) [40 CFR 147.102(b)(2)(ii)]. Based on analysis of the submitted information, the Commission concludes that TBU G- 29RD exhibits rivo competent barriers to release of well pressure. Accordingly, the Commission believes that the well's condition does not compromise overall well integrity so as to threaten the environment or human safety. AOGCC's administrative approval to continue water injection in Trading Bay Unit G- 29RD [aka Grayling 29RD] is conditioned upon the following: 1. Injection is limited to WATER ONLY; 2. Unocal shall monitor and record wellhead pressures [T/I/O] (tubing/inner annu- lus/outer annulus) and injection rate daily and submit this information to the Commission monthly; 3. Unocal shall perform a temperature log every tw-o years to demonstrate continued production casing integrity; 4. Unocal shall immediately shut in the well and notify the AOGCC upon any meas- urable change in well outer annulus pressure or any change in the rate/pressure re- lationship for the TxIA; and ~. After well shut in, AOGCC approval shall be required to restart injection. 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 rehearing. A request for rehearing is consid- ered timely- if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Alaska this 23`d day of September, 2005. ,~alfn K. Norman Chairman RE: G-29RD Pressure Information e e Sub.iect: RE: G-29RD Pressure Information From: "Greenstein, Larry P" <grecnsleinlp@unoeal.com> Date: Mon, 19 Sep 2005 15:57:27 -0800 To: Thomas Maunder <tQrn _maundcr@admin.statc.ak.us> CC: "Lamhert, Steve A" <:salambert@lUlocaLeom> Be glad to Tom. Attached is the pressure plot for G-29RD. "\ \,s"~....o 5 if- Larry -----Original Message----- From: Thomas Maunder [ma~_.:!-_!:~_:.:t:_<?_rr~~?~I..J:.<.ier@ad~:h~. st~!~:_~_Js_::!:!:.§.] Sent: Monday, September 19, 2005 2:27 PM To: Larry Greenstein Cc: Steve Lambert Subject: G-29RD Pressure Information Larry, I have received the AA paperwork from Steve with regard to G-29RD. Do you have some pressure information for the well?? This information will add to the record for the AA. Steve notes that communication was reported in early May. Can you provide information back to end of 1st Q and maybe for entire calendar year if possible?? Thanks in advance, Tom Maunder, PE AOGCC Pressure Observations 2005 09 G-29RD Pressure Content-Description: Observations 200509 I8.xIs Content-Type: Content-Encoding: appIication/vnd.rns-exceI base64 SCANNED OCT 3 1 2005 1 of 1 9/20/20057:41 AM G-29RD Pressure Observations 4000 16000 ----CSGPRESS295ffi 3500 13 3/8 CSGPRESS5 20 -DAILY VOLUME 14000 3000 12000 2500 10000 ~ ~ ~ 2000 8000 ~ n. 1500 6000 1000 4000 o 11/09/04 2000 500 04/08/05 07/17/05 09/05/05 1 9/20/2005 at 7:41 AM Chart ) ) !@" t~ V.' /8\ ~ :1-[::2 : ~, ¡ I / ¡ \ \ I: i! '\f"\ ! ! ! ï ~ \ i II::=J ~"'I'':II II , (1))1 l i ;',iM \\1 i ¡ II L \ . lW I.: -~ \~\1 ~~ ~ !r~.1 i.'L,-21 ! JU!' i I i I ! I """,j I 'I II ;~~J U /M J.J.J \) )""'1. '.~ :U '\j Æ\ f II' ,r, -\ lJi \}~~ FRANK H. MURKOWSKI, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION 333 W. pH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Steve A. Lambert Reservoir Engineer Union Oil Company of California P.O. Box 196247 Anchorage, AlaskaCf1519 f\ "ÖGr' "'0-- Re: McArthur 0-29 RD Sundry Number: 305-136 SCANNED JUN 1 ~~ 20m) Dear Mr. Lambert: 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. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659-3607 (pager). 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 rehearing. A request for rehearing 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 'day or weekend. A person may not appeal a Commission decision to Superior ourt unless rehearing has been requested. ( ~ DATED this£ day of June, 2005 Enc!. r:Jì E· cO., P'I· '[."'"" "~...,, ) STATE OF ALASKA ~ ~1;G "\J~N ~ll ';O~ ALASKA OIL AND GAS CONSERVATION COMMISSION 1"15. . "Ii¡ APPLICATION FOR SUNDRY APPROVAL t~la$ka Oil & G~s ;,.<.;~ 20 AAC 25.280 Operational shutdown U Plug Perforations D Perforate New Pool D 4. Current Well Class: Abandon U Suspend U Alter casing D Repair well D Change approved program 0 Pull Tubing D 2. Operator Name: Union Oil Company of California 1. Type of Request: 3. Address: 7. KB Elevation (ft): 103'KB above MLW 8. Property Designation: ADL 17594 11. Total Depth MD (ft): 13538 Casing Structural Conductor Surface Intermediate Production P.O. Box 196247 Anchorage, Alaska 99519 Development Stratigraphic D D Perforate U Waiver U Stimulate D Time Extension D Re-enter Suspended Well D 5. Permit to Drill Number: Vb Exploratory D 95-52 V /CJJ.I15:kJ, -()1'<:6 Service 0 6. API Number: 50-733~~-01 dO ·5",-\ --0' JJt'V1,(ç. Other U 9. Well Name and Number: G-29 RD 10. Field/Pools(s): McArthur River Field Tyonek GlHemlock PRESENT WELL CONDITION SUMMARY 12. Attachments: Description Summary of Proposal 0 Detailed Operations Program D BOP Sketch D 14. Estimated Date for Commencing Operations: 16. Verbal Approval: Total Depth TVD (ft): 9803 Length Effective Depth MD (ft): 13449 Junk (measured): Effective Depth TVD (ft): 9763 Plugs (measured): none Size MD 911 6572 20" 94# H-40 133/8" 61-68# K-55 TVD Burst 8935 9 5/8" 47# N-80, Collapse 911 6572 911 5608 1530 psi 3090 psi 520 psi 1540 psi 10078 7810 9803 Tubing Grade: 9.2# L-80, 12.6# L-80 6870 psi 4750 psi Liner 3771 7" 32# P-11 0 13538 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: 13055-13075,12670-12680, 9586-9596,9402-9408,9498- 31/2,41/2 12868-13215,12647-12694 9662,9392-9415 Packers and SSSV Type: Date: 12460 psi 10760 psi Tubing MD (ft): 11625',9618' Packers and SSSV MD (ft): Pkr 11 ,540 13. Well Class after proposed work: Exploratory D Development D 15. Well Status after proposed work: 6/6/2004 Oil D Gas D Plugged D WAG D GINJ D WINJ 0 Service 0 Abandoned WDSPL D D Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Steve Lambert 263-7658 Printed Name Steve A. Lambert Title Reservoir Engineer Signature Phone 263-7658 Date COMMISSION USE ONLY 25-May-05 Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 30~-~ J 3-'- Plug Integrity D BOP Test D Mechanical Integrity Test D Location Clearance D n>--k.\o Ð/è: I"'()"'~~ ~è.\\ì ~~~~ Wlr---\\-"\ì. \ù.-.\-~~ <;~~e:.., \'\\Ð\+o '1ll~~.. Form 1 0-403 Revised 11/2004 APPROVED BY COMMISSIONER THE COMMISSION Date: fI~£ OF<IGINAL Submit in Duplicate Unocal Alaska Resources Unocal Corporation 909 West 9th Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNOCAL. RECE JUN {) 1 200§ ^~,ask~ m~ at G~5 AII'M~tunac~ Steve Lambert Reservoir Engineer May 25, 2005 Tom Maunder Alaska Oil and Gas Conservation Commission 333 W 7th Ave # 100 Anchorage, Alaska 99501-3539 RETURN TO INJECTOR GRAYLING PLATFORM WELL NO. 29 \~ \) ~09'-.AA MCARTHUR RIVER FIELD ¡d¡-ý~ 'v \ Dear Tom: Unocal is proposing to return well G-29 to injection. Enclosed is form 10-403. Well G-29 experienced pressure on the tubing casing annulus and was shut-in on May 7. The well is a critical component of the efforts to maintain productivity and improve recovery from the Tyonek "G" zone and Hemlock reservoirs. Following is the proposed procedure for bringing this well back on injection. 1) Obtain permission to inject. 2) Baseline temperature survey 3) Inject until the well has stabilized (approximately 1 month). 4) Follow-up temperature survey. 5) Obtain variance to inject. 6) Monitor well daily and repeat temperature surveys every two years. Please let me know if you require additional information. ~Ce~eIY. /\ \ ~ t;~ lj\c~ Steve Lambert Enclosure O:\OOE\OOEFields\TBU\Grayling\Wells\G-29\G-29 Return to Injection Letter May 05.doc Re: FW: G-29 RD Tbg-csg communication ) ) Subject: Re: FW: 0-29 RD Tbg-csg communication . From: Thomas Maunder <tom _ maunder@admin.state.ak.us> Date: Tue, 24 May 2005 09:59:35 -0800 To: "Lambert, Steve A" <salambert@unocal.com> CC: "Greenstein, Larry P" <greensteinlp@unocal.com>, Dave Cole <dcole@unocal.com> Steve, Temperature surveys are an option. You may also do a combo MIT using a plug in the tailpipe. Your choice. Whatever "method" you choose needs to demonstrate that fluids are contained. If the well has been SI since May 7, temperatures may have changed sufficiently to make the temperature log attractive. You are correct about the "process". I don't expect that turning your request around should be difficult. If the temperature survey is the way you want to go, you can go ahead and get you baseline pass(es) underway. Tom Maunder, PE AOGCC Lambert, Steve A wrote: Tom, Well G-29 is a critical injector and we would like to return it to service. As we outlined in the e-mail below, the well was shut-in on May 7 with communication between tubing and the casing annulus. We inspected the tree and it does not appear that the tree is the source of the communication. As we understand the procedure, we need to submit a sundry to allow an injection test with appropriate temperature surveys to confirm fluid is not moving outside the zone of interest. If the surveys confirm that the water is contained within the zone of interest, a request for administrative approval to return the well to full time injection status would be submitted. Please let us know if this is the proper procedure for reestablishing injection into this well. -----Original Message----- From: Lambert, Steve A Sent: Monday, May 09, 20059:13 AM To: Thomas Maunder Cc: Cole, David A; Greenstein, Larry P Subject: G-29 Tbg-csg communication G-29 developed communication between the tubing and casing annulus on Saturday May 7. The rates on Sunday were 9,423 BWPD with 2500 psi on the tubing and 2030 psi on the casing. The well is being shut-in this morning and we plan to have the tree inspected as the first step in returning this critical injector to service. ~,t. "" 0\- ç; \ \~~ cz¡ œ:S "('\.C)-\- .,.\-.a v.3 CJ.,.'i'.,(>-'l'A.,ð ~ <;,. ~~,i\C) ~ ~\ '\ G '.\.<::1 \-\~ (. RE:\~\oK'''~ -\-~ ~\\ -\-0 CY~~\O.-\\-o"--\o ~~'i:-~-\-~ ~\c..~~-\('Ÿ ~ \ \ \.. ~~ r\ ~ "-- \i'^.f:) ò<E ,~V\.....~, '\ J'- ~ -Ç- ~ ~ ~C9- ~ ~ ~ ~O~\o,~i'\.. O-\\O--\-E<:?~~':>~~S:. S~\~ ~\'S.<-l.os~ G.1"'-'1 N'ð-:¡Cio\~~ ()~.Ç\~~ "-> ~Yè_'fO.:ð -\-k v-::>rt \ \ ~~. 1. ~C1J""~~ ('J! ~ ~ro\'\Q l ¿ \.) t"\Ot.O-\ \ '> ~~~<=.o,.~ ~n 1fv¡ G. L (fc-aÇ- 1 of 1 6/6/2005 3:56 PM G -29RD Pressure Observations 14000 HRS_ON TBGPRESS ° 'CSGPRESS2 9 5/8 12000 CSGPRESS3 13 3/8 CSGPRESS5 20 --DAILY VOLUME 10000 nif 11111 8000 cn cn cu 6000 4000 • I 2000 0 _ 01/08/05 01/28/05 02/17/05 03/09/05 03/29/05 04/18/05 05/08/05 05/28/05 Date • Printed on 5/11/2005 at 8:55 AM Prism Chart Prism Chart RE: G-29 Tbg-csg communication ) ) Subject: RE: G-29 Tbg-csg communication From: "Greenstein, Larry P" <greensteinlp@unocal.com> Date: Mon, 09 May 2005 15:32:32 -0800 To: Thomas Maunder <tom_maunder@admin.state.ak.us> Understand Torn. There is definitely a disconnect. The number DO need to agree and after we dig a little deeper, I'll bet we can figure out where the errors carne from and get them corrected. I'Ll give you a call tomorrow and swing by for the tickets. Thanks Larry -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Monday, May 09, 2005 3:30 PM To: Greenstein, Larry P Subject: Re: G-29 Tbg-csg communication Larry, Didn't mean to cause work, but there does seem to be a disconnect here. We both want the numbers to agree reasonably. With regard to the tickets, just call when convenient. I have them here. Tom Greenstein, Larry P wrote: It will be a load of fun, Torn. It appears to be a big mess on some platforms and nothing or minor on others. Still trying to find the root causes. By the way, I need three tickets to the Friday night event. I can swing by when convenient and give you the money. Let me know when would be a good time. Thanks. Larry -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Monday, May 09, 2005 3:19 PM To: Greenstein, Larry P Subject: Re: G-29 Tbg-csg communication Larry, Got it OK. Looks like you all will be having some fun. Tom Greenstein, Larry P wrote: Sorry Torn, Our e-mail system is acting crazy. I'm not even sending these messages because I have more to write and all of a sudden you get it sent to you 10f4 5/11/2005 8:55 AM RE: G-29 Tbg-csg communication ') ') I somehow. We are looking into this. The Production Accounting group has some allocation errors that seem to be affecting some platforms and not others. Haven't figured out how pervasive it is. Definitely Grayling, Anna and Dolly show errors and Steelhead does not. Not looking good for the injection networks built into our reporting system. We'll get back with you as soon as we can with the problems on the volumes and how far back it goes. Revisions will be forthcoming. Again, sorry for the e-mail problems. Hopefully this one makes it through intact. Larry -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Monday, May 09 ,2..õ''ò'i5....'..3'...;..'õ'2......PM'..........'............'...'................................'....,..............,....................,....................,..,.... To: Greenstein, Larry P Subject: Re: G-29 Tbg-csg communication Hi Larry, Didn't see anything new on your message. Tom Greenstein, Larry P wrote: --------------------------------------------------------------------- *From:* Thomas Maunder [mailto:tom maunder@admin.state.ak.us] *Sent: * Monday, May 09, 2·'6..6'i5.......i2...~''3..3'-pivÏ........................................,·...........,.................,...,............,.,..,..,.....,...,.......,........... *To:* Greenstein, Larry P *Cc:* Lambert, Steve Ai Cole, David Ai Jim Regg *Subject:* Re: G-29 Tbg-csg communication I presume it same to assume the you all are looking into this. Greenstein, Larry P wrote: We have dicovered the same things here. -------------------------------------------------------------------- *From:* Thomas Maunder [mailto:to~_~~~~der@admin.state.ak.~) *Sent:* Monday, May 09, 2005 11:12 AM *To:* Greenstein, Larry P *Cc:* Lambert, Steve Ai Cole, David Ai Jim Regg *Subject:* Re: G-29 Tbg-csg communication Larry, Steve, et al: Larry, thanks for the information. It appears that the pressures don't look anomalous until this most recent event. I do have a question with regard to the rate. I pulled the injection reporting information from our database. The information is in 2 parts, G-zone 20f4 5/11/2005 8:55 AM RE: 0-29 Tbg-csg communication ) ) and Hemlock. According to our information for the first quarter (60 days in operation) the G-zone allocation was 1241 bpd and the Hemlock allocation was 3724 bpd for a total of 4966 bpd. daily rate of nearly 10000 for the report period. missing here. Tom Maunder, PE AOGCC Your plot shows a What are we Greenstein, Larry P wrote: Sure do Tom. It was looking pretty stable until just the last day. Hope this helps. Larry ------------------------------------------------------------------- *From:* Thomas Maunder [mailto:tom maunder@admin.state.ak.us] * S en t : * Monday, Ma y 09, '2'Õ..O'Š....'..9..~'·2'4..'...ÃM..'........,...,...,·..,..,...........·......,....·............,.........,...,.............,...............,...,.......,.........,.. *To:* Lambert, Steve A *Cc:* Cole, David Ai Greenstein, Larry Pi Jim Regg *Subject:* Re: G-29 Tbg-csg communication Steve, Thanks for the information. You note that the communication was noted on May 7. Why is the well only being SI this morning?? Is 9400 bpd the normal daily injection volume for G-29?? What are the present values for the pressures on the tubing, inner annulus and outer annulus?? Larry, do you have the ability to provide a chart of pressure/rate information for this well like you do for the "monthly report"?? If 3 of4 5/1112005 8:55 AM RE: G-29 Tbg-csg communication ) ') you can, please provide the information for the last 90 days. Tom Maunder, PE AOGCC Lambert, Steve A wrote: G-29 developed communication between the tubing and casing annulus on Saturday May 7. The rates on Sunday were 9,423 BWPD with 2500 psi on the tubing and 2030 psi on the casing. The well is being shut-in this morning and we plan to have the tree inspected as the first step in returning this critical injector to service. 40[4 5/11/2005 8:55 AM Re: G-29 Tbg-csg communication ) Subject: Re: G-29 Tbg-csg communication v From: Thomas Maunder <tom _ maunder@admin.state.akus> \ , ~ - 0 $ ~ Date: Mon, 09 May 200509:40:38 -0800 To: Thomas Maunder <tom_maunder@admin.state.akus> CC: "Lambert, Steve A" <salambert@unocal.com>, "Cole, David A" <dcole@unocal.com>, "Greenstein, Larry P" <greensteinlp@unocal.com>, Jim Regg <jim_regg@admin.state.akus> Steve, et al: I was just starting to pull what information I have on this well. You should note that TBU 0-29 "does not exist anymore". According to the records I have that well was P&Aed June 11, 1992. TBU G-29RD was initially completed July 17,1992 and was converted to injection service May 2,2002. Attention to what well "actually exists" is very important. Please call or message with any questions. Tom Maunder, PE AOGCC Thomas Maunder wrote: Steve, Thanks for the information. You note that the communication was noted on May 7. Why is the well only being SI this morning?? Is 9400 bpd the normal daily injection volume for G-29?? What are the present values for the pressures on the tubing, inner annulus and outer annulus?? Larry, do you have the ability to provide a chart of pressure/rate information for this well like you do for the "monthly report"?? If you can, please provide the information for the last 90 days. Tom Maunder, PE AOOCC Lambert, Steve A wrote: G-29 developed communication between the tubing and casing annulus on Saturday May 7. The rates on Sunday were 9,423 BWPD with 2500 psi on the tubing and 2030 psi on the casing. The well is being shut-in this morning and we plan to have the tree inspected as the first step in returning this critical injector to service. 5 {:n - 0;>- <,,'" L<-E:...,. S~ \ h \ "'\ c., ~ \n "'-.) 0 \-0 c..c" ~ wo \"'\~~~ c..\~û.~~-~SC-o.~\\~\' S\r-0-~ <:D~\>\«:.\,\(J,,- ~;.~ t--~ ~<:.Q\ \\!'Qr (~:cx)Q:~ 0\\ 'O\d ~~~'" ~ ~~\ ¿;~~~, O'"""'~,,~ \ ''\ \>\O-."cið \ '\ ~t \c ~ WC>-S, '0~~\ -, c;.0~<tc~ð ,",0\1::::; \~ '\" \\"'~~ (..ðt:ê.,\:>\ 1.""\~~'Z-O,,-~ ~\, \DC D<t~n~'\~<t~ \.\ '0œ(A. \ ~ \t:f:i)( o.\O-:JfC G ?~~ 1 of 1 5/9/2005 9:51 AM Trading Bay Unit Grayling Platform Well # G-29RD As run 4/30/02 CASING AND TUBING DETAIL SIZE WT GRADE CONN TOP 28" 1.125" wt Driven 0' 20" 94 H-40 0' 13-3/8" 68 K-55 0' 13-3/8" DV Collar 3080' 9-5/8" 47 N-80 & Buttress 0' S-95 7" 32 P-I10 Buttress 9767' ) UNOCAL8 ,. RKB to TBG Hanger = 41.35' L ~ L ~ )' BOTTOM 324' 911 ' 6572 ' 10078' (window) 13538' 5" 15 L-SO Hyd 511 11678' (cmtd scab liner) Tubing: 4-1/2" 12.6 L-80 Buttress 0' 3-1/2" 9.2 L-80 SC BTC 9618' 13431 ' 9618' 11625 ' JEWELRY ANDWELLBOREDETAIL NO. Depth Item 1 9618' 3-1/2" x 4-112" crossover 2 11540' 3-112" x 7" SAB injection packer wlMOE Model "K" anchor in top of pkr 3 11589' 3-112" X nipple, 2.813" ID 4 11625' 3-112" tubing tail with Hydrotrip sub Note: Slickline Run has not been made since 2.50" ball was used on 4/30/02 to set the packer. Ball was pressure-released thru Hydro- trip sub after packer was set. ID of Hydrotrip sub should be 2.781" after ball released. 7" liner top @ 9767' \ / 1 5 11678' 6 13386' 9-5/8" X window 2 ~ @ 10078' TOP 11790 3 11960 4 12050 ~ 5 12085 . . . ... 12125 12190 12250 12385 12650 L x ~ ~ 6 .. .. .. . .. .. .. .. .. .. .. . .. .. .. .. .... ...................... .. .. .. .. .. .. .. .. .. .. .. I .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. ,.... ·cr········ " TD = 13,538' MD/9803' TVD PBTD = 13386' = 5" landing col1ar Max, hole angle = 64 deg @ 13300' 60+ deg from 11400' to TD 12940 13010 13190 G-29RD WO 4-30-02 Schematic final .doc 05/02/02 5" x 7" ZXP liner top packer 5" liner Float Collar PERFORATION DATA BTM ZONE SPF 11890 G-l Perf 4/29/02 11990 G- 2 Perf 4/29/02 12065 G-3 Perf 4/29/02 12115 G-4 Perf 4/29/02 12160 G-4 Perf 4/29/02 12200 G-4 Perf 4/29/02 12370 G-5 Perf 4/29/02 12410 G-5 Perf 4/29/02 12690 HB-l HB-l Perf 4/29/02 12670'-12680' Frac Stirn in 1992 12647' -12694' perf in 1992 in 7" HB-3,4 12868'-13215' 1992 perfs in 7" 12960 HB-3 13040 HB-3 HB-3 Perf 4/29/02 Perf 4/29/02 13055-13075 Frac Stirn in 1992 13240 HB-4 Perf 4/29/02 DRAWN BY: TAB Summary by Month: Individual Well Injection / Disposal Well Name: TRADING BA Y UNIT G-29RD API: 50-733-20374-01-00 Permit to Drill: 1920520 Operator: UNION OIL CO OF CALIFORNIA Field/Pool: MCARTHUR RIVER, HEMLOCK OIL Sales Cd: 50 Acct Grp: 2 Final Status: I-OIL Current Status: 1 WINJ 2002 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth Wtr Inj Wtr Inj Wtr Inj Shut-In Wtr Inj Wtr Inj Wtr Inj Wtr Inj Days 29 30 13 0 21 31 30 31 Wtr 153,255 169,525 71,280 0 106,541 171,119 164,390 165,769 Gas 0 0 0 0 0 0 0 0 2002 Totals: Water 1,001,879 Gas 0 Cum Wtr 1,001,879 Cum Gas 0 2003 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj - Days 18 18 31 30 31 30 31 31 30 31 30 31 Wtr 89,697 89,300 171,644 147,481 143,556 138,176 140,897 133,977 140,363 138,929 120,795 136,018 Gas 0 0 0 0 0 0 0 0 0 0 0 0 2003 Totals: Water 1,590,833 Gas 0 Cum Wtr 2,592,712 Cum Gas 0 2004 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Days 31 29 28 30 31 29 30 29 16 17 30 25 Wtr 139,165 132,632 107,788 133,512 125,666 105,285 109,834 134,523 68,907 72,423 111,558 82,296 Gas 0 0 0 0 0 0 0 0 0 0 0 0 2004 Totals: Water 1,323,589 Gas 0 Cum Wtr 3,916,301 Cum Gas 0 2005 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth Wtr Inj Wtr Inj Wtr Inj Days 2 28 31 -~ Wtr 6,920 104,118 123,883 Gas 0 0 0 2005 Totals: Water 234,921 Gas 0 Cum Wtr 4,151,222 Cum Gas 0 ~~toO )\ \ 'b ~c; "'V )d,,\O-~ Monday, May 09, 2005 Page 1 Summary by Month: Individual Well Injection / Disposal Well Name: TRADING SA Y UNIT G-29RD API: 50-733-20374-01-00 Permit to Drill: 1920520 Operator: UNION OIL CO OF CALIFORNIA FieldlPool: MCARTHUR RIVER, MID KENAI G OIL Sales Cd: 50 Acct Grp: 2 Final Status: I-OIL Current Status: lWINJ 2002 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth Wtr Inj Wtr Inj Wtr Inj Shut-In Wtr Inj Wtr Inj Wtr Inj Wtr Inj Days 29 30 13 0 21 31 30 31 Wtr 51,085 56,508 23,760 0 35,514 57,040 54,796 55,256 Gas 0 0 0 0 0 0 0 0 2002 Totals: Water 333,959 Gas 0 Cum Wtr 333,959 Cum Gas 0 2003 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth Wtr (nj Wtr (nj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj -- Days 18 18 31 30 31 30 31 31 30 31 30 31 Wtr 29,899 29,767 57,215 49,160 47,852 46,058 46,965 44,659 46,788 46,309 40,265 45,339 Gas 0 0 0 0 0 0 0 0 0 0 0 0 2003 Totals: Water 530,276 Gas 0 Cum Wtr 864,235 Cum Gas 0 2004 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Wtr Inj Days 31 29 28 30 31 29 30 29 16 17 30 25 Wtr 46,388 44,210 35,929 44,504 41,889 35,095 36,611 44,841 22,969 24,141 37,186 27,432 Gas 0 0 0 0 0 0 0 0 0 0 0 0 2004 Totals: Water 441,195 Gas 0 Cum Wtr 1,305,430 Cum Gas 0 2005 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth Wtr (nj Wtr Inj Wtr Inj Days 2 28 31 '- Wtr 2,307 34,706 41,294 Gas 0 0 0 2005 Totals: Water 78,307 Gas 0 Cum Wtr 1,383,737 Cum Gas 0 \\S~ \)~~ \~~) \d~ \ G.'J~ ys.~~ r~ ~o-\-~~ \> ct'J0 ~\ Monday, May 09, 2005 Page 2 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO' Camille O. Taylor Chair THRU' Tom Maunder P.I. Supervisor FROM: Jeff Jones Petroleum Inspector NON- CONFIDENTIAL DATE: May 22, 2002 SUBJECT: Mechanical Integrity Tests Unocal/Grayling Well G-29RD ~ MRF / TBU Packer Depth Pretest Initial 15 Min. 30 Min. WellI G-29RD Type tnj. J S I T.V.D. I 8828 I Tubing J 2810 J 2810 i 2810 I 2810 P.T.D.! 1920520 Type testI P I Testpsil 2207 ICasing, i 300 .I 2250 I 2250 ! 2245 I P)F ! P' Notes: Pre-test pressures monitored 30 min. & stable Type INJ. Fluid Codes F '- FRESH WATER INJ. G - GAS INJ. S = SALT WATER INJ. N = NOT INJECTING Type Test M= Annulus Monitoring P= Standard Pressure Test R= Internal Radioactive Tracer Survey A= Temperature Anomaly Survey Interval I= Initial Test 4= Four Year Cycle V= Required by Variance W= Test during Workover D= Differential Temperature Test O= Other (describe in notes) Test's Details May 22, 2002: I traveled to Unocal's Cook Inlet Platform Grayling in the McArthur River Field to witness an MIT on water injection well G-29RD. Wayne Johnson was the Unocal representative in charge of testing and he performed the tests in a safe and proficient manner. The pre-test pressures were monitored for 30 minutes and found to be stable. The pressure test was then performed with the well passing the MIT. Summary: I witnessed a successful MIT on Unocal's water injection well G-29R'D in the McArthur River 'Field, TBU. M.I.T.'s performed' 1_ Number of Failures: O Attachments: none Total Time during tests' 2 hrs. cc: MIT report form 5/12/00 L.G. MIT TBU G-29RD 5-22-02 JJ.xls 5/29/02 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown: Stimulate: Plugging: Perforate: X Pull tubing: X Alter casing: X Repair well: Other: X Convert to injection 2. Name of Operator 5. Type of Well: 6. Datum elevation (DF or KB) Union Oil Company of California (UNOCAL) Development: RT 103' to MSL feet 3. Address Exploratory: 7. Unit or Property name Stratigraphic: P.O. Box 196247, Anchorage, Alaska Service: X Trading Bay Unit 4. LocalJon of well at surface Grayling Leg 3 Conductor No.1 8. Well number 1837' FSL, 1438' FEL, Sec 29, T9N, R13W, SM Grayling G-29RD At top of productive interval 9. Permit number/approval number 923', FNL, 1968' FEL, Sec 30, T9N, R13W,SM at 11790'MD/8950' TVD 92-52/302-112 At effective depth 10. APl number 128' FNL, 3114' FEL, Sec 32, T9N, R13W, SM at 13386' MD/9723' TVD 50-733-20374-01 At total depth 11. Field/Pool 9' FNL, 3190' FEL, Sec 30, T9N, R13W, SM at 13538' MD/9803' TVD McArthur River Field/Hemlock & G 12. Present well condition summary Total depth: measured 13538' feet Plugs (measured) true vertical 9803' feet Effective depth: measured 13386' feet Junk (measured) true vertical 9723' feet Casing Length Size Cemented Measured depth True vertical depth Structural 324' 28" Driven 324' 324' Conductor 911' 20" 1814 sx 911' 911' Surface 6572' 13-3/8" 4110 sx 6572' 5608' Intermediate 10078' window 9-5/8" 1575 sx 10178' 8048' Production Liner 3771' 7" 1162 sx 9767'- 13538' 7844'-9803' Inner Liner 1753' 5" 118 cuff 11678'-13431' 8895'-9743' Perforation depth: measured 11790'-11890', 11960'-11990', 12050'-12065', 12085'-12115', 12125'-12160', 12190'-12200', 12250'-12370', 12385'-12410', 12650'-12690', 12940'-12960', 13010'-13040', 13190'~13240' true vertical 8950'-9659' Tubing (size, grade, and measured depth) Single 4-1/2" 12.6 Ib/ft L-80 Butt x 3-1/2" 9.2# L-80 buttress at11625' Packers and SSSV (type and measured depth) Baker SAB packer at 11540' ?'~: .... -~-' '" i"i", ! ':! ~i:' ;..'ii i'., 13. Stimulation or cement squeeze summary ~..,' ,' ~: C~!'i?,:? i '. : : ; ".' ,' ~i.~' Intervals treated (measured) Treatment description including volumes used and final pressure ":' .~": d'~i -' 14. Representative Daily Averaqe Production or Injection Data OiI-BBL Gas-Mcr Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 4/13/02 95 51 2470 1320 psi 180 psi Subsequent to operation 5/4/02 6853 BWIPD 290 psi 3200 psi 15. Attachments: 16. Status of well classification as: Copies of Logs and Surveys run: Daily Report of Well Operations: X Oil: Gas: Suspended: Service: Water Injector 17. I hereby certify that the foregoing is true and correct to the best of my knowledge: Form 10-404 Rev 06/15/88 AFE #153665 SUBMIT IN DUPLICATE UNOCAL Grayling #G-29RD Workover to Convert to Inj Daily Summary 4/16/02 Move rig from G-7 to G-29RD.ND tree, NU BOPs. 4/17/02 Test BOPE. Engage tbg hgr and pull on tbg, RIH with jet cutter on E-line. Make 3-1/2" tbg cut at 12469' in mid-jt above packer. POOH and RD E-line. 4/18/02 POOH laying down 3-1/2" tbg and GLMs. 4/19/02 RIH with overshot while PU drill pipe. 4/20/02 Tag top of fish at 12481'. Worked over top of fish and engage grapple with overshot. Appeared to have released anchor while dressing top of tbg stub. POOH. 4/21/02 Recovered stub and tbg anchor. RIH with packer mill and PRT. Tag packer at 12499'. 4/22/02 Mill packer from 12499' to 12503'. Pushed packer downhole from 12503' to 12507', high torque. PU with 30-40K drag. POOH, no packer recovery. Dress PRT with 1/16" bead weld. RIH, tag fish at 12507'. Fish moved freely down to 12677'. 4/23/02 PU with 60K overpull. POOH, recovered packer and all of tailpipe (76' long fish). RIH with shoe and rolling dog assy, tag fill at 12684'. Wash and rotate to clean out fill from 12684' to 12836'. Pump hi-vis sweep. Short trip to check drag, 10k. Losses at 50 bph. Pump 45 bbl sized salt pill, squeezed into perfs at 1000 psi. Losses reduced to 0. 4/24/02 Washed down from 12842' to 12862', tagged CT bridge plug at 12862'. Mill 1 ft to 12863'. PU and wait 20 min for bridge plug to relax. RIH and BP had fallen. Tag at 13057'. Torque increased. Circ hi-vis sweep. Rotate to 13068' with 20 bph losses. Circ another hi-vis pill at 13068'. POOH, pulled tite at 10690', pumped pipe free. POOH, successfully had CT bridge plug in rolling dog. Test BOPE. 4/25/02 RIH with 6" mill cleanout assy. Wash and ream from 13068' to 13409' while pumping three hi-vis sweeps. 4/26/02 Short trip to top of 7" liner at 9700'. Trip back to bottom at 13409' with no fill. Pull to 12448' and pump polymer breaker. POOH with cleanout assy. Run 5" liner. 4/27/02 RIH with 1909' of 5" liner. Tagged bottom at 13431'. Circ at 5.5 bpm, some gassing at surface, and pipe sticking. Reduce rate and clean up well at 3.7 bpm, regain reciprocation. Pump 21 bbls of 15.8 ppg cmt and displace with clean 3% KCL. Bump plug, set hanger with 3000 psi. Rotate to release running tool. PU 8' and set ZXP packer with 45K down weight. Test annulus to 2200 psi. PU and attempt to reverse circ, drill string plugged after 5 bbls of reversing. Circ down drill pipe, cir¢ hole clean with no sign of cement to surface. Daily Summary for G-29RD WO.doc 1 5/8/2002 UNOCAL Grayling #G-29RD Workover to Convert to Inj Daily Summary 4/28/02 Test casing and ZXP packer to 2200 psi for 30 min, OK. Reverse circ well to clean 3% KCL at 4 bpm. POOH with drill pipe and liner running tool. 4/29/02 Run TCP guns, close Fas-Fill valve with 4650' of dry pipe for 1200 psi underbalance. RIH with guns to depth. RU Schlumberger, correlate GR to open hole log and place guns on depth. RD Schlumberger. Set packer and pressure annulus to 2250 psi to fire guns. Perf intervals = 11790'- 11890' G-1 11960'-11990' G-2 12050'-12065' G-3 12085'-12115' G-4 12125'-12160' G-4 12190'-12200' G-4 12250'- 12370' G-5 12385'- 12410' G-5 12650'-12690' HB-1 12940'-12960' HB-3 13010'-13040' HB-3 13190'-13240' HB-4 Reverse circ two DP volumes. Pull 10 stands, circ hole clean. 4/30/02 POOH with guns. All shots fired. RIH with 4-1/2" x 3-1/2" completion including SAB-3 injection packer. 5/1/O2 Reverse circ corrosion inhibited packer fluid into annulus. Drop 2.5" ball and set packer with 2500 psi tbg pressure. Pressure test packer annulus to 2250 psi. Attempt to shear out ball but ball already sheared, inject down tbg at 5 bpm and 3350 psi. Retest annulus to 2250 psi, OK. ND BOPE. 5/2/02 NU tree. Perform MIT on annulus to 2250 psi for 30 min. Release rig for move from G-29RD to G-12RD. Daily Summary for G-29RD WO.doc 2 5/8/2002 UNOCAL RKB to TBG Hanger = 41.35' 7" liner top @ 9767' 5 TD = 13,538' MD/9803' TVD PBTD = 13386' = 5" landing collar Max hole angle = 64 deg @ 13300' 60+ deg from 11400' to TD G-29RD WO 4-30-02 Schematic final .doc 9-5/8" window @ 10078' 05/02/02 Trading Bay Unit Grayling Platform Well # G-29RD As run 4/30/02 CASING AND TUBING DETAIL SIZE WT GRADE CONN TOP BOTTOM 28" 1.125" wt Driven 0' 324' 20" 94 H-40 - 0' 911' 13-3/8" 68 K-55 - 0' 6572' 13-3/8" DV Collar 3080' 9-5/8" 47 N-80 & Buttress 0' 10078' S-95 (window) 7" 32 P-110 Buttress 9767' 13538' 5" 15 L-80 Hyd 511 11678' 13431' (cmtd scab liner) Tubing: 4-1/2" 12.6 L-80 Buttress 0' 9618' 3-1/2" 9.2 L-80 SC BTC 9618' 11625' JEWELRY AND WELLBORE DETAIL NO. Depth Item 1 9618' 3-1/2" x 4-1/2" crossover 2 11540' 3-1/2" x 7" SAB injection packer w/MOE Model "K" anchor in top of pkr 3 11589' 3-1/2" X nipple, 2.813" ID 4 11625' 3-1/2" tubing tail with Hydrotrip sub Note: Slickline Run has not been made since 2.50" ball was used on 4/30/02 to set the packer. Ball was pressure-released thru Hydro- trip sub after packer was set. ID of Hydrotrip sub should be 2.781" after ball released. 5 11678' 6 13386' 5" x 7" ZXP liner top packer 5" liner Float Collar PERFORATION DATA TOP BTM ZONE SPF 11790 11890 G- 1 Perf 4/29/02 11960 11990 G-2 Perf 4/29/02 12050 12065 G-3 Perf 4/29/02 12085 12115 G-4 Perf 4/29/02 12125 12160 G-4 Perf 4/29/02 12190 12200 G-4 Perf 4/29/02 12250 12370 G-5 Perf 4/29/02 12385 12410 G-5 Perf 4/29/02 12650 12690 ~-1 ~-1 Perf 4/29/02 12670'-12680' Frac Stim in 1992 12647'-12694' perf in 1992 in 7" 12940 12960 HB-3 13010 13040 HB-3 HB-3 12868'-13215' 1992 perfs in 7" Perf 4/29/02 Perf 4/29/02 13055-13075 Frac Stim in 1992 13190 13240 HB-4 Perf 4/29/02 DRAWN BY: TAB STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test E-Mail to; Tom_Maunder@admin.state.ak.us and Bob_Fleckenstein@admin.state.ak,us OPERATOR: Unocal FIELD / UNIT / PAD: McAr~hur River Field/?BU/Gray/ing Platform DATE: May 2, 2002 'iiiiiiiiii iNUi'".MBE'.R, ili::i::i::iii::iiii~BGiii iiiiii?:ii ::iiiii!iiiiii~..Y..P::Ei il ii::P.~O~ERi :: ::?: :: :: :: :: ::::::::::::::::::::::::: ::!::!::?:i::i:: iiii::iii![! ii ?:iiiiiREQ::i::i! i ::i::ili,,T..B.".Giiiili:: i :: i ..T..'i::MiEiiiili i !ii~li'.~Eiiiiii i ! ii.:T.:il~Ei!ill i iiii::iiii i il ili i i il iiiiii::?:i::ili:~EEE.'i::iiiii::iiiiili::i::EE[L!.,liD ii iTi.¥,EL:: iliii ..F. EUIE)i i iii:: iMOiiii ii iSiiZ.'E::/. ~TiL:GRA.:'DEi :SIZEi ::::~RE'.S, S i ~iiPRE. S$i::liii::C.:,SGi:i ~i:i¢~.Giii:: ii:: i~SGill :i i~IME:: :: :: ::i:: ::::il PTD: 92-52 S P S 8,828 9-5~8"~47fi~N-80 4ol/2" 0 0 0 0 15:00 P ,, Well #: G-29RD 11,540 2207 0 2,240 2,240 2,240 COMMENTS: COMMENTS: COMMENTS: COMMENTS: COMMENTS: TBG. INJ. FLUID CODES F = FRESH WATER INJ. G = GAS I NJ. S = SALT WATER INJ. N = NOT INJECTING TEST TYPE: M = ANNULUS MONITORING P = STD ANNULUS PRESSURE TEST R = INTERNAL RAD. TRACER SURVEY A = TEMPERATURE ANOMALY TEST D = DIFFERENTIAL TEMPERATURE TEST ANNULAR FLUID: DIESEL GLYCOL SALT WATER DRILLING MUD OTHER P.P.G. Grad. 8.5 0.44 WELL TEST: Initial X 4 - Year Workover X Other Distribution: orig- Well File OPERATOR REP SIGNATURE: c - Qperator c- [~j~c~revised by L.Q. 8/6/00 c- Trip Rpt File c- Inspector Shane Hauck , AOGCC REP SIGNATURE: G-29MITform 5-2-02 corrected.xls None 5/7/2OO2 05'OZ-ZOOZ . FRO~- T-514 o. P.OOS/O05 ! · STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon: Suspend: Operation shutdown: Re-enter suspended well: Alter casing: Repair well: Plugging: Time extension: Stimulate: Change approved program: Pull tubing: X Variance: Perforate: X Other: X convert to injector 2. Name of Operator 5. Type of well: 6. Datum elevation (DF or KB) Union Oil Company of California (UNOCAL) Development: X 103' RKB above MSL feet 3. Address Exploratory: 7. Unit or Property name P. O. Box 196247 Stratigraphic: Anchorage, AK 99519-6247 Service: Trading Bay Unit 4. Location of well at surface 8. Well number 1837' FSL & 1438' FEL of Sec. 29, T9N, R13W, SEWARD Grayling G-29RD At top of productive interval- Top Hemlock 12,647' MD/9391' TVD ~. Permit number 491' FNL & 2561' FEL of Sec. 30, T9N, R13W, SEWARD 92-52 At effective depth 13449' MD/9763' TVD 10. APl number 59' FNL & 3130' FEL of Sec. 30, T9N, R13W, SEWARD 50- 733-20374-01 At total depth 13538' MD/9803' TVD i 1. Field/Pool 9' FNL & 3190' FEL of Sec.30, T9N, R13W, SEWARD McArthur River/Her~m~' :~m~j~r~ 12. Present well condition summary Total depth: measured 13538' feet Plugs (measured) Baker coil tbg conveyed bridge plug @ 12840' true vertical 9803' feet Effective depth: measured 13449' feet Junk (measured)'"--'--" ,~ ~,u~~ Alar~ 0il ~' Gas P'~s, true vertical 9763' feet ~nchor~e Casing Length Size Cemented Measured depth True vertical depth Structural 324' 28" Driven 324' 324' Conductor 911' 20" 1814 sx 911' 911' Surface 6572' 13-3/8" 4110 sx 6572' 5608' Intermediate Production 10078' window 9-5/8" 1575 sx 10078' 8048' Liner 3771' 7" 1162 sx 9767'- 13538' 7844'-9803' Perforation depbh: measu red 12647'-13694', 12868'- 13215' true vertical 9392'-9415', 9498'-9662' Tubing (size, grade, and measured depth) 3-1/2", 9.2#, N-80 @ 12575' Packers and SSSV (type and measured depth) Baker "3-H" pkr @ 12499' Baker TRSSSV @ 296' 13. Attachments Description summary of proposal: x Detailed operations program: BOP sketch: x 14. Estimated date for commencing operation 15. Status of well classification as: 4/15/2OO2 16. If proposal well verbally approved: Oil: X Gas: Suspended: Name of approver Date approved Service: 17. I hereby ~he ~oregoing/~'~ ¢ '"~ is true and correct to the best of my knowledge. Si~e~; _ __ , ~ ~,~ 'F~ r Dan Williamson Title: Drilling Manager Date: ! FOR COMMISSION USE ONLY Conditions of approval: Notify representative may witness 3(~(~ ~ ~'t ~"%¢-~:~'~¢.s-~:~- ~ Approval .. Plug integrity COP Test _~ Location clearance , Mechanical Integrity Test Subsequent form required 10- OriginalvSigned Oechsli By Approved by order of the Commissioner Camm. Commissioner Date AFE # 153665 Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE UNOCAL RKB to TBG Hanger = 41.35' 7" liner top @ 9767' TD = 13,538' MD/9803' TVD PBTD = 13449' 9-5/8" window @ 10078 SIZE WT Trading Bay Unit Grayling Platform Well # G-29RD As completed 7/16/92 CASING AND TUBING DETAIL GRADE CONN TOP BOTTOM 28" 1.125" wt 20" 94 H-40 13-3/8" 68 K-55 13-3/8" DV Collar 9-5/8" 47 N-80 & S-95 7" 32 P-110 Tubing: 3-1/2" 9.2 L-80 Driven - - Buttress Buttress SC BTC , 0' 0' 3080' 0' 9767' 324' 911' 6572' 10078' (window) 13538' 12575' Gas Lift Mandrels: 1 2316' 3-1/2" Camco GLM 2 3110' 3-1/2" Camco GLM 3 4126' 3-1/2" Camco GLM 4 4982' 3-1/2" Camco GLM 5 5805' 3-1/2" Camco GLM 6 6684' 3-1/2" Camco GLM 7 7507' 3-1/2" Camco GLM 8 8397' 3-1/2" Camco GLM 9 9255' 3-1/2" Camco GLM 10 10175' 3-1/2" Camco GLM 11 11281' 3-1/2" Camco GLM 12 12424' 3-1/2" SFO-2 GLM with Orifice valve and RK latch JEWELRY AND WELLBORE DETAIL NO. Depth Item 1 296' 2 12462' 3 12497' 4 12499' 5 12541' 6 12575' 7 12840' TOP 12647 12670 Baker Self Equalizing TRSSSV (flapper) 3-1/2" Baker 'CMU' Sliding Sleeve Baker 'CH' Anchor Tubing Seal Nipple Baker '3-H' Production Packer (mill out extension @ 12504') Baker 'X' Landing Nipple Baker Shear Out Ball Seat Sub Baker Coil Tubing conveyed bridge plug w/ no sand on top. PERFORATION DATA BTM ZONE SPF 12694 HB-1 8 12680 HB-1 8 12868 13055 13215 HB-3/4 8 13075 HB-3/4 8 G-29RD vl Schematic.doc 03/13/02 DRAWN BY: LWB UNOCAL ) 7" liner top @ 9767' RKB to TBG Hanger = 41.35' TD = 13,538' MD/9803' TVD PBTD - 13449' 9-5/8" window @ 10078' SIZE WT Trading Bay Unit Grayling Platform Well # G-29RD Proposed 4/02 Workover CASING AND TUBING DETAIL GRADE CONN TOP BOTTOM 28" 1.125" wt 20" 94 H-40 13-3/8" 68 K-55 13-3/8" DV Collar 9-5/8" 47 N-80 & S-95 7" 32 P-il0 5" 15 L-80 Tubing: 4-1/2" 12.6 L-80 3-1/2" 9.2 L-80 Driven 0' 0' 0' 3O80' Buttress 0' Buttress 9767' 11700' (Proposed cmtd scab liner) 324' 911' 6572' 10078' (window) 13538' Buttress 0' 9700' SC BTC 9700' 11700' JEWELRY AND WELLBORE DETAIL NO. Depth 1 9700' 2 11670' 3 12715' 5 13175' Item 3-1/2" x 4-1/2" crossover 3-1/2" X nipple 3-1/2" tubing seals, 15' long 4-1/2" x 7" ZXP liner top packer with 4.00" ID x 15' long seal bore 4-1/2" liner Float Collar PERFORATION DATA TOP BTM ZONE SPF 11790 11890 G-1 Proposed 11960 11990 G-2 Proposed 12050 12070 G-3 Proposed 12085 12115 G-4 Proposed 12125 12160 G-4 Proposed 12190 12200 G-4 Proposed 12250 12370 (3-5 Proposed 12385 12410 G-5 Proposed 12647 12694 HB-1 Proposed Reperf 12670 12680 HB-1 Not reperfed 12868 13215 HB-3/4 Proposed Reperf 13055 13075 HB-3/4 Proposed Reperf G-29RD Proposed WO 4-02 Schematic.doc 04/02/02 DRAWN BY: LWB UNOCAL Workover Discussion Grayling #G-29RD Workover Procedure AOGCC for 403 4/2/02 Objective: The primary objective of the G-29RD workover is to convert the well from a Hemlock producer to a G zone/Hemlock injector. This will require removing the existing packer just above the Hemlock perfs in order to add G- zone injection intervals. There is also a CT-set bridge plug between HB-1 and HB-3/4 perfs currently in the well which will be cleaned out during the proposed workover. There is a suspected severe hole in the 7" liner which if confirmed, will be repaired by installing a cemented 5" inner liner. All of the G-zone and Hemlock perfs will then be performed by the rig with TCP guns. A single 4-1/2" x 3-1/2" tubing string will be run with an injection packer. A summary of the work plan is as follows: 1. Just prior to finishing G-7 workover, shut-in G-29RD gas lift, fill annulus and tubing with 3% KCL. 2. Set tubing plug just below hanger because BPV profile threads are washed out. 3. Move rig after G-7 workover is completed. 4. ND tree, NU and test BOPs to 250/3000 psi against tubing plug. 5. Pull tbg plug. 6. RU APRS, run jet cutter to cut tubing above packer at 12499'. 7. Pull and lay down the 3-1/2" tubing and GLMs. 8. PU DP and RIH with overshot. Engage 3-1/2" tbg stub and rotate "CH" anchor out of top of Baker "3-H" packer. POOH with stub and anchor. 9. RIH with packer mill and retrieving tool. 10. Mill Baker 3-H packer with MOE at 12499'. POOH with packer and tail pipe. 11. RIH with 6" mill and clean out 7" liner down to CT bridge plug at 12840'. 12. Mill up bridge plug and continue on cleaning out to 13175' if possible (100' above lowest perf). 13. Circ hole clean and POOH. 14. Run csg scraper to 11700'. 15. Run retrievable test packer and set at 11700'. Pressure test csg to 2250 psi. Pull packer. 16. Runand cement a 5" liner from appx 11700' to PBTD of 13175'. 17. Set liner top packer with seal bore receptacle in liner hanger below liner top packer. Appx liner top packer depth = 11700' MD/8906' TVD. 18. Run Halliburton TCP guns to shoot new G-zone intervals 11790' - 12410' and reperf Hemlock intervals 12647'-13075'. Correlate guns with Schlumberger E-line. Shoot guns underbalanced and then kill well before pulling guns. 19. Run 4-1/2" x 3-1/2" injection tubing and stab into seal bore at top of 5" liner. 20. Pressure test annulus and liner top packer to 2250 psi (.25x8896' TVD = 2227 psi for MIT). 21. Release rig. Tim Billingsley Unocal Drilling Engineer 263-7659 Proc G-29RD AOGCC ver 2.doc 1 4/2/2002 UNOCAL Grayling #G-29RD Workover Procedure AOGCC for 403 4/2/02 G-29RD: Existinq Cement Top of 7" Liner In 1992, G-29 was redrilled as G-29RD. A 7" liner was run and cemented with 235 bbls or 1162 sx of cement. There were 30 bbls of cement reversed off the top of the liner at 9767'. On 7/8/92, a Atlas cement bond log was run. The top of good cement bond on the log was at 10800' MD or approximately 1000' MD above the highest proposed G-zone injection perfs at 11790'. This demonstrates sufficient isolation to for the proposed conversion to injection and for the proposed addition of G zone perfs. G-26RD Proposed 5" Inner Liner There is a suspected large hole in the existing 7" liner in the existing Hemlock Lower Bench 1 perfs, 12670'-12680'. This could result in a thief injection zone if no remedial action is taken during the proposed workover. A cemented 5" liner is proposed to isolate the potential thief zone. All zones will be perforated through both the 5" and 7" liners during the workover with TCP guns except the potential thief zone at 12670' to 12680'. The proposed cement volume is as follows: 5" shoe track = 80' x .024 bbl/ft = 1.9 bbls 13175'-11700'=1475' x .0118 bbl/ft for 5" x 7" 32# = 17.4 bbl Total cmt = 1.9 + 17.4 = 19.3 bbls x 1.19 cuft/sk (15.8 ppg): 91 sx Unocal proposes to not run a cement bond-log on the 5 liner cement job because the existing 7" CBL indicates there will be sufficient cement isolation to prevent injection water from channelling up the hole. G-29RD Estimated Reservoir Pressure Proposed G-zone = 2730 psi based on K-18RD PBU on 8/1/01 = 6.1 ppg EMW at 8640' TVD Hemlock Reperfs = 3519 psi based on K-1RD 12/00 info = 7.2 ppg EMW at 9392' TVD The above reservoir pressures indicate maximum anticipated shut-in surface pressure should not exceed: 3519 psi - 0.1 psi/ft gas grad x 9392' TVD = 2580 psi Therefore, a 3000 psi BOP test should be sufficient. Tim Billingsley Unocal Drilling Engineer 263-7659 Proc G-29RD AOGCC ver 2.doc 2 4/2/2002 3" KILL IdNE: WITH TWO 3" ~M VALVES [:i ' ;i';'. ;!;" KILL LINE: FROMMUD PMP ,~ C--~EN'r UNIT L I , NIPPL~ i i L i i i i i i 3-5/8" 5000 Psi ANNULAR ~t_ . · , · FLOWLIN£ 13-S/~I,, 5M FLAN(;£ .......... DOUBLE GATE BUNO RAMS .. l .... ! ~" CHOKE LINE WITH ONE: RENOTE: ~ 1 ~I~UA/... ,l." 5M VALVE i 13-5/8" sH FLANOE SINGLE GATE 1c~-5/8" 5M FLANC:;E CAMERON 5M SPOOL ,,. I GRAYLING PLATFORM UNION OIL COMPANY OF' CALIFORNIAa UNOCAL) · '-i~RAWN: OA¢ A,°P'O: 658 SCALE:: NONE: ." _ i TO GA~ BUSTER · / AUTOMATIC CHOKE TO O~R,R~CK VENT F'ROU CHOKE UNE TO WELL CLEAN TANK 3-1/8" AUTO~,TIC CHOKE UNION VALVE~ UPSTREAM OF CHOKES ARE I0,000 PS1 C, ATE TYPE VALVES OOWNSTREAM OF CHOKES ARE §,000 PSI GATE TYPE CHOKE MANIFOLD GRAYLING PLATFORM OIL COMPANY OF' CALIFORNIA (dba UNOCAL) THE MATERIAL UNDER THIS COVER HAS BEEN MICROFILMED ON OR BEFORE NOVEMBER 13, 2000 P M C:LORBMFILM.DOC L A T TE R IA'L U H-.~tS --.M A R E W N D E R K E R Unocal Energy Resour, ~ivision Unocal Corporation 909 West 9th Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 263-7809/276-7600 Facsimile 263-7874 UNO ..AL March 19, 1996 Martin T. Morell Cook Inlet Onshore/ T.B.U. Asset Group Mr. Dave Johnston, Commissioner Alaska Oil & Gas Conservation Comm. 3001 Porcupine Drive Anchorage, Ak. 99501-3192 Re: Grayling Platform Well, G-29RD APl Number 50-733-20374-01 On July 5, 1993 operations were terminated after failing in two attempts to set a sand plug from 13,449' to 12,820'. A Baker inflatable bridge plug was set at 12,840' C TM with sand dumped on top. However, the presence of sand above the bridge plug could not be detected and sand was later produced to the surface when the well was put back in production. G. Russell Schmidt Drilling Manager '-' STATE OF ALASKA -'-' ALASKA OIL AND GAS CONSERVATION COIvlMISSION REPORT OF SUNDRY WELL OPERATIONS !1. Operations performed: 2. Name of Operator Operation shutdown Stimulate Plugging Pull tubing Afte~ casing m "-~epair well UNION OIL COMPANY OF CALIFORNIA (UNOCAL) 3. Address P.O. BOX 196247 ANCHORAGE, AK 99519 - 6247 Location of well at surface Leg 4, Cond. 18 1837' FSL &1438' FEL, Sec. 29, R9N, R13W, SM At top of productive interval 491' FNL and 2561' FEL, Sec 30, T9N, R13W, SM At effective depth 13538' MD (9803' I'VD) At total depth 13538' MD (9803' TVD) Perforate X Sand Pull tubing Other X Plug 5. Type of Well: Development x Exploratory Stratigraphic Service ORIGINAL 6. Datum elevation (DF or KB) 103' KB above MLLW feet 7. Unit or Property name Trading Bay Unit 8. Well number G-29RD 9. Permit number 92-52/93-153 10. APl number 50-733-20374-01 11. Field/Pool McArthur River/Hemlock 12. Present well condition summary Total depth: measured true vertical 13,538 feet Plugs (measured) 9,803 feet Inflatable Bridge Plug @ 12,840' Effective depth: measured 13,449 feet Junk (measured) true vertical 9,753 feet Casing Length Size Cemented Measured depth True vertical depth Structural 324' 28" Driven 324' 324' Conductor 911' 20" 1814 sx 911' 911' Surface Intermediate 6572' 13-3/8" 4110 sx 6572' 5608' Production 10,078' 9-5/8" 1575 sx 10,078' window Liner 3771' 7" 1162 sx 13,538' 9803' Perforation depth: measured 13,055'-13,075'; 12,670'-12,680'; 12,868'-13,215'; 12,647'-12,694' true vertical 9586'-9596'; 9402'-9408'; 9498'-9662'; 9392'-9415' Tubing (size, grade, and measured depth) 3-1/2", 9.2# L-80 Buttress @ 12,575' Packers and SSSV (type and measured depth) 13. Stimulation or cement squeeze summary Intervals treated (measured) Baker 7" 3-H, Prop pkr @ 12,497'/Baker Tag Ret Self-Equa~ E C E i VE Flapper ~ 296' SSSV MAR 211996 14. Treatment description including volumes used and final pressure Alaska 0il & Gas Cons. C0mr Representative Daily Average Production or Injection Data Anchorage OiI-Bbl Gas-Mcf Water-Bbl Casing Data Tubing Pressure Prior to well operation 201 288 2516 1185 180 Subsequent to operation 215 376 2435 1190 80 15. Attachments 16. Status of well classification as: Copies of Logs and Surveys run Daily Report of Well Operations ~ ~ Oil X Gas Suspended Service 17. I hereby certify that the for~p~ true;er/iii c(~r~ t° t/~est of my knowledge. Signed G. Russell Schmidt ~e Drilling Manager Date Form 10-404 Rev 06/15/88 ¢ ~'" ' ' SUBMIT IN DUPLICATE lission Memorandum UNOCAL ) Suly 19, 1993 To: G-29RD Well File From: Greg Stephenson, Summer Engineer Re: Job Summary 'RECEIVED MAR 2 1 1996 Alaska 0il & Gas Cons. Commission Anchorage/ . llist0rv At the time G-29RD was completed, offsets which were completed in Benches 1, 3, and 4 were producing an average of 475 BOPD at 53% water cut. Offsets that produced out of the lower benches produced cuts in excess of 80°,4. Production profiles seemed to confirm that the majority of water production for the region was coming from the lower benches. In addition, 3-D seismic interpretation showed a fault which appeared to be acting as a permeability barrier between this area and the remainder of the Northwest Feature. This seemed to provide an explanation for the anomolously low water cuts in the upper benches. It was for these reasons that G-29RD was completed as a Bench 1,3, and 4 producer. Based on the available evidence, the Reservoir team conservatively anticipated a production of 480 BOPD with a water cut of 60-70%. Much to everyone's surprise, this well yielded an initial production of 275 BOPD with a 92% water cut. It was speculated that this phenomenon could be due to either a split in the casing a part in the casing, or vertical fracturing of the reservoir. Two attempts were made to profile the well. During the first attempt the tool was unable to get past a casing restriction, and the profile was unsuccessful. Afterwards, an attempt was made to jet out the the restriction with coiled tubing. Unfortunately, this clean-out attempt was also unsuccessful. For, when an additional attempt was made to mn a production profile, it was only marginally effective. Although the profiling tool could not enter the lower benches to measure flow distribution, it did seem to confirm that the majority of oil production was coming from HB 1 while the lower benches were producing most of the water. ,,Procedure Based on the available survey data, we opted to shut off flow from HB3 and :HB4 in order to improve the water cut of the well. Because we were not satisfied with the quality of the production survey that had been run, we were not willing to permanently abandon the lower intervals. This is why we opted to use the sandback procedure. In theory, this procedure, which involves 'laying out' a sand plug with coiled tubing, allows one to "semi-permanently" abandon a given interval at a lower cost than setting a bridge plug. We modeled our procedure for setting the sand plug after the one described in M.J. Chambers' paper, 'Laying Sand Plugs With Coiled Tubing' (SPE 25496). One of the key principles of this paper is that when laying sand plugs in highly-deviated holes, there is a tendency toward the occurence of two specific phenomena. The first is 'duning'. Duning is the phenomenon in which the sand is 'strung out' and actually forms sand dunes along the wall of the casing, rather than compacting in the form of a plug. The second phenomenon discussed was 'bridging'. 'Bridging' is when the sand fails to fully compact and actually bridges off inside the casing, forming gaps in the plug itself. Both of these FORM 1-0C03 (REV. 8-85) PRINTED IN U,S.A. phenomena can.yield a false tag. This is why a special technique is required to lay a sand plug effectively in highly-deviated wells. In addition to the tendencies described above, we had several concerns of our own. Specifically, we were concerned with the rheological properties of our carrying fluid. In order to prevent the sand from bridging off or simply falling out of solution inside the coiled tubing, we wanted our fluid to have a considerable carrying capacity. At the same time, because the coiled tubing available to us had a small inside diameter, we were extremely concerned about pressure drops due to friction. It is for this reason, that we desired a fluid that was "slick~ yet could maintain viscosity at low velocities. Furthermore, in order to obtain a *hard" tag, we wanted the sand to fall out of solution after leaving the coiled tubing nozzle. Because of these concerns, we chose an XCD polymer as our carrying fluid. This polymer has the advantage of being able to keep great quantities of material in suspension at low velocities and, by virtue of its shear-thinning properties, reducing observed surface pressures by 25-30%. In order to allow the sand to fall out of solution as we desired, we added a lithium hypochlorite breaker directly to the XCD polymer solution. This agent is designed to break the polymer in the presence of a high temperature (specifically, bottom-hole temperature). Indeed, on-the-fly testing confirmed that at 150°F, our gel broke within five minutes, while at room temperature, the polymer broke in 1-2 hours. In order to deal effectively with the problems associated with "bridging" and "duning", we designed our sand placement program to occur in 2-3 stages. The procedure went as follows. In the first stage, we were to calculate and pump 80% of the sand necessary to 1ill the desired interval. After pumping this quantity of sand, we were to tag the sand top with coiled tubing. If the tag was higher than the calculated sand top, we would assume that bridging was occurring and would "fluff~ the sand with the coiled tubing, then wait for the sand to settle. If we encountered a tag that was lower than anticipated, we would assume that duning was occurring and we would wash down any sand that was strung up the hole. We would repeat the tagging process until a consistent tag was obtained. Once we felt confident that we had a reliable tag, we would begin the second stage. In the second stage we were to pump the remainder of the sand necessary to fill the desired interval, and repeat the tagging procedure described above. In the event that the sand top was at a different height than was anticipated, we would use a third stage for fine-tuning. After we obtained our initial design for the program, we found the need to make some amendments to it. After considerable thought and consideration, we came to the conclusion that we needed an additional barrier to block the flow of water through the plug. In order to provide a more effective permeability barrier, we opted to lay a CaCO3 pill on top of the sand plug. To do this, we had to resize the sand plug in order to accommodate our desired quantity of CaCO3. One advantage of the CaCO3, however, is that it eliminated the need for the third "fine-tuning" stage. We could simply resize the CaCO3 pill to "fill in the gaps". Unfortunately, this process worked better in theory than in practice. When we were designing the first stage of this process, we were concerned about getting sand up in the tubing tail and possibly sticking the coiled tubing. Therefore, we designed the first stage to take up 70% of the desired height in the casing, rather than the prescn~oed 80%. In theory, we should have gained seventy-two feet of height in the liner. Much to our surprise, however, we only gained three feet of fill-up. We then attempted to wash down any poss~le dunes. After all of our efforts to improve our tagged depth, we never managed to gain more than three feet of fill-up. Therefore, we assumed that for some reason, the formation was taking the sand. We knew that the well had been fracture- stimulated in the past, and it was plausible that there could have been some voidage in the reservoir itself. Therefore, we pumped another pill identical to the first one, in hopes that we would finally gain some height in the liner. Again, the tag was the same as before. At this point, we felt that it was no longer cost effective to attempt a sandback in this well. So, we set an inflatable bridge plug for temporary abandonment of the zone. As is the practice with setting bridge plugs, we decided to lay sand on top of the plug to both protect the fishing neck and increase the effective differential pressure rating of the bridge plug. Although we obtained a firm setting of the plug (we placed 6000~ on it), we never could detect the presence of the sand we put on top of it. As was the case with the sandback procedure, it was as if the sand had disappeared. Later, when the well was put back on production, virtually aH of the sand was produced to surface. We have reason to suspect that the sand's disappearance could be attributed to split casing. As I mentioned previously, split casing was considered as a possible explanation for the anomalously high water cut experienced upon completion. Furthermore, in order to produce the sand that we placed above the bridge plug, there would have to be some form of pressure differential at the point where the sand was set. The nearest perforations, however were some 170 feet above the point where the bridge plug was set. This would seem to support the split casing theory. One strike against this theory, however, is the fact that the well was completed with P-110 casing. Under normal conditions, it is highly unlikely that this grade of pipe would develop a split. It is also important to note that while we tagged fill very near the previous coiled tubing clean-out depth (12,920'), there are no guarantees that the wellbore was completely bridged off at this point. In other words, it is possible that sand could have fallen below this blockage. However, it seems highly unlikely that there would be enough of a void below this depth to accept the volumes of sand that we put away. Discussion If the failure of this attempt to lay a sand plug is indeed attributable to a split in the casing, this may in fact be good news. This is because, we would, for the first time have an explanation for the unexpectedly high water cut that this well has encountered since its completion one year ago. We could then opt to either work-over the well with a 5" liner or redrill the well. We are currently exploring the possibility of running a Magnelog~ in conjunction with a spinner survey to determine conclusively whether this is indeed the case. REC[IV[D PERMIT DATA AOGCC Individual Well Geological Materials Inventory T DATA_PLUS Page' Date' 06/13/94 RUN DATE_RECVD 92-052 SURVEY 92-052 BHCA/GR 92-052 BHCA/GR 92-052 DIFL/GR 92-052 DiFL/GR 92-052 MUD 92-052 SBT/GR/CCL 92-052 SBT/GR/CCL 92-052 407 92-052 DAILY WELL OP 92-052 SURVEY 92-052 SURVEY 92-052 DRY DITCH 92-052 5328 D GYRO L 9720-13529 L 9720-13529 L 9720-13529 L 9720-13529 L 10095-13538 L 10000-12547 L 9750-13416 R COMP DATE: 07/17/92 R 06/10/92-07/17/92 R 0-13438, FINDER R 0-13438, FINDER GYRO S 10090-13538, SS#846 T 9731-13571, OH-DIFL/AC 07/14/92 07/14/92 07/14/92 07/14/92 07/14/92 07/14/92 07/14/92 07/14/92 10/05/92 10/05/92 07/14/92 07/14/92 07/14/92 07/14/92 Are dry ditch samples required? Was the well cored? yes ~Ana!ysis & description received? Are well tests required . Received? yes _ Well is in compliance Initial COMMENTS yes ~ And received? ~ yes ~ , ~"'~ STATE OF ALASKA ALA' . OIL AND GAS CONSERVATION COMIV, ON APPLICATION FOR SUNDRY API-'ROVALS 1. Type of request: Abandon __ Suspend __ Operations shutdown __ Re-enter suepended well__ Alter casing Repair well Plugging Time extension Stimulate Change appCed program -- Pull tubing -- Varianoe Perorate Othe---rX 2. Name of Operator -- 15. T~e of Well: -- 6.-~'atum elev~3n (DF or KB~ UNION OIL COMPANY OF CN. IFORNIA (UNOCAL) I Exploratory __ 103 RKB above MLLW f~et 3. Address I 8tratigraphic __ 7. Unit or Property name P.O. BOX 196247 ANCHORAGE, AK 9951 9 I Sense __ TRADING BAY UNIT 4. Location of well at surface LEG #4 CONDUCTOR #18, GRAYLING PLATFORM 1837' FSL & 1438' FEL, Sec. 29, R9N, R13W, SM At top of productive interval Top Hemlock 12,647' MD (9391' '1~)E 491' FNL and 2561' FEL, Sec 30, T9N, R13W, SM CE~VED At effective depth 13538' MD (9803' '[VD) At total depth 13538' MD (9803' 'fVD) 12. Present well condition summary Total depth: measured true vertical 13,538' 9,803' feet Plug~~ed) feet 8. Well number G-29RD 9. Permit number 92-52 10. APl number~., 50_733 ~~~ 1 ~1~S13~i~4~ 11. Field/Pool )f~ MCARTHUR RIVER/HEMLOCK Effective depth: measured true vertical 13,449' 9,753' feet Junk (measured) feet Casing Structural Conductor Surface Intermediate Production Liner Length 324' 911' 6572' 10,078' 3771' Perforation depth: measured Size Cemented Measured depth True vertical depth 28" Driven 324' 324' 20" 1814 sx 911' 911' 13-3/8" 4110 sx 6572' 9-5/8" 1575 sx 10,078' window 7" 1162 sx 13,538' 13,055'-13,075' 12,670'-12,680' 12,868'-13,215' 12,647'-12,694' 5608' 9803' true vertical 9586'-9596' 9402'-9408' 9498'-9662' 9392'-9415' Tubing (size, grade, and measured depU3) 3-1/2", 9.2#, L-80 Buttress @ 12,575' Packers and SSSV (type and measured depth) Baker 7" 3-H, Prop pkr @ 12,497'/Baker Tag Ret Self-Equality Flapper @ 296' SSSV 13. Attachments Description summary of proposal_ _ Detailed operations programX__ BOP sketch X_ 14. Estimated date for commencing operation 15. 16. If proposal was verbally approved / Oil X_ Gas Name of approver Date approved Service 17. I herel~e~for~n~~e and correct to the best of my knowledge. Signed G. Russell Schmidt Title Drilling Manager FOR COMMISSION USE ONLY Status of well classification as: __ Suspended Date June8~ 1993 Conditions of approval: Notify Commission so representaUv~ may witness Plug Integrity __ BOP Test Location clearance Mechanical Integrity Test__ Subsequent form required 10- Z/t3 z./ Approved by the order of the Commission Original S~gned By David W. johnston JApproval No¢ ~'- / i-..~-- Copy Returned Commissioner Form 10-403 Rev 06/15/88 Date ~'//~'//'~' } SUBMIT IN TRIPLICATE ~, 1 28' @ 324' 20' @911' 13-3/8' @ 6572' LINER TOP @ 9767' 9-5/8' WINDOW @ 10078' KB (g) 0.0' TBG HGR (TOP) (~ 41.35' TUBING DETAIL: 3-1/2', 9.2#, L-80 BUTTRESS TUBING ~, NACESERVICE EQUIPMENT 1) BAKER TUBING RETRIEVABLE SSSV (SELF EQUALIZING FLAPPER) @ 296' ~ 2) GAS LIFT MANDRELS AS FOLLOWS' GLM #1 @ 2316' GLM GLM GLM GLM GLM GLM GLM GLM GLM GLM GLM #2@3110' #3 @ 4126' #4 @ 4982' #5 @ 5805' #6 @ 6684' #7 @ 7507' #8 (~ 8397' #9 @ 9255' #10@10175' #11 (g) 11281' #12 (~ 12424' 3) BAKER 'CMU' SUDING SLEEVE AT 12462' 4) BAKER '3-H' PROD PACKER (g) 12499' 'CH' ANCHOR TUBING SEAL NIPPLE AT 12497' MILLOUT EXTENSION AT 12504' 5) BAKER 'X' LANDING NIPPLE AT 12541' 6) BAKER RE-ENTRY GUIDE AT 12575' PERFORATED INTERVALS: HB-1: 12647' - 12694' I D~ 12670' - 12680' HB-3/4:12868' - 13215' 7' P-110 13055' - 13075' FI:lac STIM @ 13538' 13449' ET FRAC STIM WELL TBUS G-29RD IDRAWN: DAC COMPLETION (JULY 16, 1992) SCALE:NONE 0~(~ ~ DATE: 8-06-92 UNION OIL OOMPANY OF OALIFORNIA (dba UN E I V _ D J UN 1 4 !993 ,~,laska Oil & Gas Cons. Commissio~ Anchorage General Work Procedure Coil Tubing Sandback G-29RD 1. RU & test 1-1/2" coil tubing unit (maximum depth 13,200'). . . , RIH w/bull nose & tubing tail Iocator. Locate tubing tail and tag fill. Note: Drag problems recorded on previous coil tubing clean out attempt (9/92). Mix and pump 80% of calculated sand plug slurry to fill to 12,820'. Tag sand & mix remainder of sand necessary to tag sand at 12,820'. RD & move to next well. E-line tag to follow to verify top of sand. R EIVED J UN '/4 399;~ Ataska Oi~ & (~as Cons. Comrnissio~ Anchorage TUE ,RCTlC -~ECOIL Arctic Recoil, Inc. (907) 283-1980 P.O. BOX 2595 Kenai, Alaska 99611 __ I .. _ il j.I ,.I t.J ~ 1 4 199J ,Alaska Oil & Gas Cons. Commissio~ Anchorage WELL STATE OF ALASKA ~.~ ~ ALA~'~-'~'OIL AND GAS CONSERVATION CO'-"SSION COMPLETi JN OR RECOMPLETION ,,EPORT AND LOGf 1. Status of Well Classitication of Service Well OIL ~ GAS D SUSPENDED D ABANDONEDD SERVICE D 2. Name of Operator 7. Permit Number Union Oil Company of California (UNOCAL) 92-52 3. Address 8. APl Number P. O. Box 196247, Anchore~le, Alaska 99519 50-733-20374-01 4. Location of well at surface Leg #4, Conductor #18, Grayling Platform 9. Unit or Lease Name 1837' FSL and 1438' FEL Section 29, T9N, R13W, S.M.~..~_~ ~ ~' Trading Bay Unit At Top Producing Intewal Top Hemlock:. 12647' MD ( 9391' TVD ~. [;,~.d~.% [.i:: I t0N ~ 491' FNLand 2561' FEL, Section 30, T9N, R13W, S.M. ~ £}A'I-~ t i ~---~'/~-~~a~l~~ G-29 Redrill 9' FNL and 3190' FEE Section 30, T9N, R13W, S.M. ~ 'V~tFI~rJ i McArthur River Field 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Sen~ No. Hemlock 103' RKB above MLLW ADL 17594 12. Date Spudded 13. Date T.D. Reached 114. Date Comp., Susp. or Aband. 115. Water Depth, if offshore [ 16: No. of Completions June 10, 1992 July 1, 1992 July 17, 1992 125 Feet MSL One (1} 17. Total Depth (MD +TVD) 18. Plug Back Depth (MD+'I'VD)t 19. Diroctioral Surve~ 120. ~j~pth whore SSSV set [21. Thickness of Permafrost 13538' MD/9803' TVD 13449' MD/9763' TVD lYES [~ NO U feet MD N/A 22. Type Electric or Other Logs Run BHC-AI_/DIFL/GR/SP; SBT/VDL/GR/CCL 23. CASING, UNER AND CEMENTING RECORD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" 94# H-40 Surface 911' 25' 1814 sxs 13-3/8' 61 # & 68# K-55 Surface 6572' 17.5' 4110 sxs 9-5/8' 47# N--80 Surface 10078' (window) 12.25' 1575 sxs 7' liner 32# P-- 110 9767' 13538' 8.5' 1162 sxs 24. Perforations open to Production (MD+TVD of Top and Bottom and 25. TUBING RECORD intmval, si~e and number) SIZE I DEPTHS~ ~o)tPACKER SET 12647' - 12694' MD 9392' - 9415' I'VD 3.5", 9.2#, N-80 12575' 12499' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 12868' - 13215' MD 9498' - 9662' TVD DEPTH INTERVAL (MD) 1 AMOUNT& KIND OF MATERIAL USED' 13055' - 13075' Frac w/20700# 16-20 Resin Coated Carbolite 12670' - 12680' Frae w/18000# 16-20. Reein Coated Carbolite 27 PRODUCTION TEST Date First Production i Method of Operation (Flowing, gas lilt, etc.) July 18~ 1992! 3228 ~lross/381 netr 88.2% cut ( gasliff ) Date of Test Hours Tested PRODUCTION FOF OIL-BBL GAS-MCF WATER-BBL CHOKE sIZE I GAS--OIL RATIO TEST PERIOD Flow Tubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (corr) Press. 24--HOUR RATE 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chip& None Alasi(a Oil & Gas Cons. Commission Anch0rag0 Form 10-407 rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate GEOLOGIC MAFt(EF~ FOI:IlVlATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VEl=Fr. DEPTH GOF[ and time of each phase. Top 'G' Zone 11180' MD -8513' ss None Top Hemlock 12647' MD. ,~ ~ ~ ~'~928(7 ss 31. LISTOF ATTACHME3~I'S 32. I hereby certify that the foregoing is ~'ue and correct to the best of my knowledge INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and Icg on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervalsfor only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental recordsfor this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate 'none". I 28' @ 324' 20'@ 911' 13-3/8' @ 6572' LINER TOP 9767' 9-5/8' WIN DOW @ 10078' 7' P-110 @ 13538' KB @ 0.0' -I'BG HGR (TOP) @ 41.35' 1344g' ETDt TUBING DETAIL: 3-1/2', 9.2#, L-80 BUTTRESS TUBING x,,, NACE SERVICE EQUIPMENT 1) BAKER TUBING RETRIEVABLE SSSV (SELF EQUALIZING FLAPPER) @ 296' ~,, 2) GAS LIFT MANDRELS AS FOLLOWS: GLM #1 @ 2316' GLM GLM GLM GLM GLM GLM GLM GLM GLM GLM GLM #2@3110' #3 @ 4126' #4 @ 4982' #5 @ 5805' #6 @ 6684' #7 @ 7507' #8 @ 8397' #9 @ 9255' #10 @ 10175' #11 @ 11281' #12 @ 12424' 3) BAKER "CMU" SLIDING SLEEVE AT 12462' 4) BAKER '3-H" PROD PACKER @ 12499' 'CH' ANCHOR TUBING SEAL NIPPLE AT 12497' MILLOUT EXTENSION AT 12504' 5) BAKER "X" LANDING NIPPLE AT 12541' 6) BAKER RE-ENTRY GUIDE AT 12575' PERFORATED INTERVALS: HB-I: 12647' - 12694' 12670' - 12680' HB-3/4: 12868' - 13215' 13055' - 13075' FRAC STIM FRAC STIM WELL TBUS G-29RD COMPLETION (JULY 16, 1992) UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) K EE DRAWN: DAC SCALE: NONE DATE: 8-06-92 UNOCAL TUBULAR DETAIL WELL ~lt: G-29 RD GRAYLING PLATFORM PAGE 1 0£ DATE: Ju~ o~, 1992 AFE NO.: STRING: 7' 321, P-llO, BlffTRESS CASING FOREMAN: 1 1 HOWCO FLOAT SHOE 1.3 13536.7 13538 JT#1 1 JOINT 7" 32#, P-Il0, BLrlW. CASING (w/ CENTRALIZER IN MIDDLE) 6.094 44.83 13491.87 13536.7 2 1 HOWCO FLOAT COLLAR 1 13490.87 13491.87 JT#2 1 JOINT 7" 32#, P-Il0, BuTr. CASING (w/ CENTRALIZER INMIDDLE) 6.094 41.09 13449.78 13490.87 3 1 TIW LANDING COLLAR 1 13448.78 13449.78 yr#3-? 5 JOINTS 7" 32#, P-Il0, BUTt. CASING (w/ CENTRALIZER ON EA. JT.) 6.094 209.04 13239.74 13448.78 4 1 7" 32#, P-110, BU'IWRESS PUP JOINT 6.094 21.9 13217.84 13239.74 #s-19 12 JOINTS 7" 32#, P-110, BIJIW. CASING (w/ CENTRALIZER ON EA. JT.) 6.094 513.87 12703.97 13217.84 5 1 7" 32#, P-Il0, BLYIWRESS PUP JOINT 6.094 21.82 12682.15 12703.97 #2o-z$ 6 JOINTS 7" 32#, P-Il0, BUIW. CASING (w/ CENTRALIZER ON EA. JT.) 6.094 254.3 12427.85 12682.15 #2~-77 52 JTS 7" 32#, P-Il0, BUTF. CASING (CENTRALIZERS EVERY OTHER JT) 6.094 225626 10171.59 12427.85 #78-?9 2 JOINTS 7" 32#, P-Il0, BUTrRESS CASING (NO CENTRALIZERS) 6.094 84.3 10087.29 10171.59 #8o-a$ 6 JOINTS 7" 32#, P-Il0, BUTF. CASING (w/ CENTRALIZER ON EA. JT.) 6.094 262.41 982438 10087.29 JT#86 1 JOINTS 7" 32#, P-Il0, BLTIWRESS CASING (NO CENTRALIZERS) 6.094 42.53 978235 982438 6 1 TIW 7" LINER HANGER/PACKER-MODEL DTH-S SINGLE CONE 15.23 9767.12 978235 HYDRO-HANGER/HD-6 "S" PACKER 9767.12 0 0 0 0 0 0 01 01 0! 0[ 01 0 0 0 0 0 0 0 0 0 0 0 0 0 ! nchora~o 0 UNOCAL TUBULAR DETAIL WELL/~: G--29RD GRAYLING PLATFORM PAGE 1 0£ I DATE: JULY 16, 1992 AFE NO.: 321403 STRING: SINGLE STRING; 3-1/2' 9.21 N-80 SC BLITTRESS FOREMAN: DON B YRNE WL REG/SO S 0.95 12573.65 12574.6 1 JOINT 3-1/2", 9.2#, N-80, SC BUTTRESS TUBING 31.5 12542.15 12573.65 BAKER 'riX" LANDING NIPPLE 1.25 12540.9 12542.15 1 JOINT3-1f2", 9.2#, N-80, SC BUTrRESSTUBING 31.02 12509.88 12540.9 CROSS OVER 0.63 12509.25 12509.88 MILL OUT EXTENTION 5.51 12503.74 1250925 BAKER 3-H HYDRO SET PRODUCTION PACKER 4.79 12498.95 12503.74 BAKER CH ANCHORTUBING SEAL NIPPLE 1.49 12497.46 12498.95 1 JOINT3-1/2", 9.2#, N-80, SC BLrlTRESSTUBING 31.5 12465.96 12497.46 BAKER CMU SLIDING SLEEVE 3.88 12462.08 12465.96 1 JOINT3-1/2", 9.2#, N-80, SC BLrrrRESSTUBING 31.78 12430.3 12462.08 1 1 GAS LIFT MANDREL #12 6.5 12423.8 12430.3 36 JOINTS3-1/2", 9.2#, N-80, SCBLrUrRESSTUBING (#5-#40) 1135.9 11287.9 12423.8 2 1 GAS LIFT MANDREL #11 6.5 11281.4 11287.9 35 JOINTS3-1/2", 9.2#, N-80, SC BUTrRESS TUBING (#41- #75) 1099.69 10181.71 11281.4 3 1 GAS LIFT MANDREL #10 6.5 10175.21 10181.71 29 JOINTS3-1/2", 9.2#, N-80, SCBI. rlTRESSTUBING (#76- #104) 913.56 9261.65 1017521 4 1 GAS LIFT MANDREL g9 6.5 9255.15 926135 27 JOINTS 3-1/2", 9.2#, N-80, SCBLrrFRESS TUBING (#105 - #131) 852.07 8403~08 9255.15 5 1 GAS LIFT MANDREL #8 6.5 8396.58 8403.08 28 JOINTS3-1/2", 92#, N-80, SC BUTTRESS TUBING (#132- #159) 883.14 7513.44 8396.58 6 1 !GAS LIFT MANDREL #7 6.5 7506~4 7513.44 26 JOINTS3-1/2", 9.2#, N-80, SC BLrTTRESS TUBING (#160- #185) 815.97 6690.97 7506.94 7 1 GAS LIFT MANDREL #6 6.5 6684A7 6690.97 28 JOINTS3-1/2", 9.2#, N-80, SC BLFI'rRESS TUBING (#186- #213) 873.4 5811~}7 6684A7 8 1 GAS LIFT MANDREL #5 6.5 5804.57 5811~)7 26 JOINTS3-1/2", 9.2#, N-80, SC BI_rFrRESSTUBING (#214- ~g239) 815.81 4968.76 5804.57 9 1 GAS LIFT MANDREL #4 6.5 496226 4968.76 27 JOINTS 3-1/2", 9.2#, N-80, SCBUTrRESS TUBING (#240 - #266) 849.98 413228 496226 10 1 GAS LIFT MANDREL #3 6.5 4125.78 413228 32 JOINTS3-1/2", 9.2#, N-80, SC BUTrRESS TUBING (#267- g298) 1009.05 3116.73 4125.78 11 1 GAS LIFI' MANDREL #2 6.5 311023 3116.73 25 JOINTS3-1/2", 9.2#, N-80, SCBUTrRESSTUBING (#299- #323) 787.37 232236 311023 12 1 GAS LIFT MANDREL #1 6.5 231636 232236 64 JOINTS 3-1/2", 9.2#, N-80, SCBUTFRESS TUBING (#324 - #387) 2008.51 307.85 231636 1 i PUP JOINT; 3-1/2" 9.2# N-80 BUUFRESS w/3-7/8" OD COUPLING 3-7/8" 4.16 303.69 307.85 , S CSSSV 7.48 296.21 3(13.69 1 PUP JOINT; 3-1/2" 92,# N-80 BUTTRESS w/3-7/8" OD COUPLING 3-7/8" 4.14 292.07 296~11 8 JOINTS3-1/2", 9.2#, N-80, SC BUTrRESS TUBING (#388- #~95)_ ........ I,~ 249.9 42.17 292.07 CIW 11",5000# DCBHANGER ~ ? (' ' [ V ~ L} 0.82 41.35 42.17 RKB ELEVATION 41.35 0 41.35 UP WEIGHT; 132K ...... icelf~ll 0 DOWN WEIGHT;82K b~l~i(a [.)il ~.,, ~a~ (~i3,:lu 0 JI... IL. ,Iii l ~,_* I ItJl G-29 REDRILL 12728'/10536' ETD DaY 1 (6/10/92) 13-3/8" @ 6572' 9-5/8" C @ 12728' COMMENCE OPERATIONS @ 0100 HRS 6/10/92. NU FLOWLINES. NU BOP AND TEST. PU 5" DRILL PIPE AND 9-5/8" CSG SCRAPER, RIH. DISPLACE HOLE W/FIW. POH TO 9912'. PT 9-5/8" CSG TO 3000 PSI. RIG UP ATLAS WL FOR SQZ HOLES. TEST LUBRICATOR. RIH W/PERF GUNS. ATTEMPT TO CORRELATE GUN-CCL/GR FAILED. POH, CHANGE WL TOOLS. RIH. CLOSE ANNULAR & PERF'D SQZ HOLES F/10140'-10145'. POH W/WL. G-29 REDRILL 12728 '/10086' ETD DaY 2 (6/11/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 12728' CONT'D POOH W/SQZ GUNS. POOH W/D.P. RIH AND SET A CMT RETAINER AT 10,114' WLM. SQZ'D PERFS AT 10,140'-10,145' WITH 350 SXS OF "G" CEMENT. CIP AT 0930 HRS. POOH W/D.P. RAN CBL LOG F/10,114'-9500', TOC @ 9640'. G-29 REDRILL 12728'/10087' ETD DaY 3-5 (6/12-14/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 12728' RIH W/WHIPSTOCK PKR, CORRELATED W/WIRELINE, SET PKR AT 10,086'. POOH. RIH W/GYRO AND ATTEMPTED TO CORRELATE, DID NOT ENTER PKR KEY SLOT. SECOND ATTEMPT, SAME RESULT. MODIFIED CENTRALIZERS ON GYRO TOOL, DID NOT ENTER KEY SLOT. MODIFIED TOOL AND ORIENTED PKR. RIH W/WHIPSTOCK AND LATCHED INTO PKR AT .10,086'. CHANGED OVER TO MUD AND MILLED 18" STARTING WINDOW. POOH. MILLED WINDOW F/10,080'-10,083'. POOH. PIN CONNECTION PARTED LEAVING WINDOW MILL AND WATERMELON MILL IN HOLE. RIH, ENGAGED AND RECOVERED FISH. RIH AND MILLED WINDOW F/10,083'-10,087'. BOX CONNECTION PARTED LEAVING WINDOW MILL IN HOLE. RIH, ENGAGED FISH. G-29 REDRILL 12728'/10087' ETD DaY 6 (6/15/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 12728' POOH W/FISH. RIH W/CONCAVE MILL. MILLED F/10,087'-10,090. WINDOW OPEN. POOH. RIH W/CONCAVE MILL AND WATERMELON MILL. POLISHEDAND SMOOTHED WINDOW. DRILLED TO 10,095'. PERFORMED L.O.T. G-29 REDRILL 10246 '/156 ' DaY 7 (6/16/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 12728' POOH. RIH W/8-1/2" BIT ON A STEERABLE MOTOR ASSEMBLY. DRILLED 8-1/2" HOLE FROM 10,095'-10,246'. G-29 REDRILL 10588 '/342 ' DAY 8 (6/17/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' DRILLED 8-1/2" HOLE FROM 10,246'-10,588'. TESTED BOPE, OK. RIH W/ROTARY ASSEMBLY. CIRC. POOH. G-29 REDRILL 11108 '/520 ' DaY 9 (6/18/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' DRILLED 8-1/2" HOLE FROM 10,588'-10,826'. PUMPED A HI VIS SWEEP-RECOVERED CUTTINGS. MADE A WIPER TRIP-TIGHT F/10594'- 10248' @ INTERVALS. DRLD F/10826'-11108'. R'ECEIVED Ak~ska Oil & C,~.:; Oe~-~s, (;ommissio~ G-29 REDRILL 11108'/520' DaY 10-12 (6/19-21/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI TRIP FOR BHA CHANGE. M/U A "BUILDING" ASSY & RIH TO 11108' (SLIP & CUT DRLG LINE). DRLD 8-1/2" HOLE F/11108'-11256'. WIPER TRIP-TIGHT F/11083'-11021'. DRLD F/11256'-11433'. TRIP FOR BHA CHANGE. M/U A "HOLDING" ASSY & RIH TO 11433'. DRLD F/11433'-11600'. WIPER TRIP-TIGHT @ 11422'. DRLD F/11600'- 11734'. WIPER TRIP-NO TIGHT HOLE. DRLD F/11734'-11849'. TRIP FOR BIT-LEFT 3 CONES IN HOLE. RIH W/CONCAVE JUNK MILL- TIGHT HOLE @ 10407' & 10820'. G-29 REDRILL 11849'/0' DaY 13 (6/22/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI MILLED ON CONES @ 11849' W/CONCAVE JUNK MILL. TRIP TO CHECK MILL. RIH & MILL ON CONES @ 11849' W/BLADED JUNK MILL. TRIP TO CHECK MILL. RIH W/MILLED TOOTH BIT. G-29 REDRILL 12039'/190' DaY 14 (6/23/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI CONT RIH W/MILLED TOOTH BIT. DRLD F/11849' TO 11852' IN 3 HRS. TRIPPED TO CHECK BIT-3/16" UNDERGAUGE W/SEVERE CUTTER WEAR. M/U INSERT BIT & RIH TO 11843'. REAMED TO 11852'. DRLD 8-1/2" HOLE F/11852' TO 12033'. WIPER TRIP TO 11523'. DRLD F/12033' TO 12039'. G-29 REDRILL 12339'/219' DaY 15 (6/24/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI DRLD 8-1/2" HOLE F/12039'-12189'. WIPER TRIP TO 11714'. DRLD F/12189'-12339'. TRIP FOR BIT. PERFORM WEEKLY BOPE TEST. M/U NEW BIT & RIH TO 1439'. SLIP & CUT DRILL LINE. ECEIVED G-29 REDRILL 12562'/223' DaY 16 (6/25/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI FINISHED SLIP & CUT DRILLING LINE. RIH TO 12,339'. DRLD 8- 1/2" HOLE F/12,339' TO 12,537'. WIPER TRIP TO 12,072'. DRLD 8-1/2" HOLE FROM 12,537' TO 12,562'. G-29 REDRILL 13326'/764' DaY 17-19 (6/26-28/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI DRILL 8-1/2" HOLE FROM 12,562' TO 12,735'. WIPER TRIP TO 12,165'. DRILL 8-1/2" HOLE FROM 12,735' TO 12,806'. TRIP FOR BIT. DRILL 8-1/2" HOLE FROM 12,806' TO 12,963'. TRIP FOR BIT. DRILL 8-1/2" HOLE FROM 12,963' TO 13,231'. WIPER TRIP TO 12,352'. DRILL 8-1/2" HOLE FROM 13,231' TO 13,299'. TRIP FOR BIT. DRILL 8-1/2" HOLE FROM 13,299' TO 13,326'. G-29 REDRILL 13538'/212' DaY 20 (6/29/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI DRILL 8-1/2" HOLE FROM 13,326' TO 13,538' (TD). WIPER TRIP TO 10,078' (9-5/8" WINDOW). CIRCULATE AND CONDITION HOLE FOR LOGS. TRIP FOR LOGS. LOG HOLE. G-29 REDRILL 13538' DaY 21 (6/30/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI LOG HOLE WITH RUN #1. RIH WITH RUN #2. STOP @ 13,106' WLM. LOG HOLE. STUCK AT 12,860' WLM RIG/UP AND STRIP/OVER WITH 5" DP. RECEIVED G-29 REDRILL 13538' DaY 22 (7/01/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI RIH AND STRIP/OVER W.L. WITH 5" DP. W.L. PARTED AT 11,995' WLM POOH WITH W.L. RIH WITH ROPE SPEAR ON 5" D.P. TO 12,754'. CATCH W.L. POOH. RECOVERED ALL W.L. TO CABLE HEAD. G-29 REDRILL 13538' DaY 23-26 (7/02-05/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI RIH WITH FISHING ASSY ON 5" DP. FISH F/12,970' TO 13,510'. NO RECOVERY. RUN W.L. GAMMA RAY THRU D.P. & LOCATE SOURCE AT 12,851'. POOH TO 12,804'. FISH TO 12,845'. NO RECOVERY. POOH. JUNK FROM WHIPSTOCK-WINDOW IN FISHING TOOL GUIDE. RIH WITH FISHING ASSYUNABLE TO WORK THRU WINDOW. POOH. RIH WITH MILLING ASSY AND MILL AND PRESS WINDOW. POOH. RIH WITH FISHING ASSY WITH BOWEN KNUCKLE JOINT TO WINDOW. RIH. UNABLE BREAK CIRCULATION. POOH TO WINDOW AND ATTEMPT TO RETRIEVE, KNUCKLE JOINT PLUG WITH SLICK LINE. UNABLE TO LATCH INTO PLUG & RETRIEVE. GAINED CIRCULATION. RIH TO 12,792' FISH FROM 12,800' TO 12,954'. RUN W.L. GAMMA-RAY THRU D.P. INDICIATED SOURCE HAD MOVED DOWN HOLE. CHASE FISH TO 13,503'. ENGAGED & CATCH FISH. POOH. RECOVER FISH IN IT'S ENTIRETY. SOURCES INTACT. RIH WITH DRILLING BHA TO 13,538'. NO FILL. CIRCULATE AND CONDITION HOLE F/PIPE. POOH. R/U AND RUN 7" LINER. G-29 REDRILL 13538' DaY 27 (7/06/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI RIH W/7" LINER ON 5" DP TO 13538' (TOL @ 9767'). R/U SURFACE CMT LINES. CMT LINER W/235 BBLS (1162 SXS) "G" CMT W/ADDITIVES. CIP @ 1450 HRS. SET LINER HANGER & LINER TOP PKR. RELEASED F/HANGER & REV OUT 30 BBLS EXCESS CMT. POH. LAID DN EXCESS PIPE IN DERRICK. ,RECEIVED Gas Cei'!s. Corm't~.issio~ A,,]~horag~ G-29 REDRILL 13538'/13449'ETD DaY 28 (7/07/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI TEST BOPE. STRING BLOCKS BACK TO 8 LINES. MADE UP 6" CLEAN OUT ASSY & RIH PICKING UP 3-1/2" DP. TAGGED CMT @ 13351' & C/O TO LANDING COLLAR @ 13449'. TESTED CASING TO 3000 PSI FOR 30 MIN. TRIP FOR CASED HOLE LOGS. G-29 REDRILL 13538'/13449'ETD DaY 29 (7/08/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI CONT POH. R/U ATLAS WL & RAN SBT/VDL/GR/CCL F/13400' TO 9767' (LINER TOP). RAN GYRO SURVEY F/13,438' TO SURFACE. RIH & SET RTTS PKR @ 9734' W/MULTI SERVICE VALVE @ 6777'. PERFORMED A DRAWDOWN TEST (1000 PSI WATER CUSHION) ON THE LINER LAP-DRY TEST. G-29 REDRILL 13538'/13449'ETD DaY 30 (7/09/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI POH W/RTTS PKR. RIH W/TANDEM CSG SCRAPERS TO 13443'. CHANGE OVER TO 3% KCL/FIW. CIRC & FILTER FLUID. TRIP FOR WL PERF GUNS. G-29 REDRILL 13538 '/13449 'ETD DaY 31-33 (7/10-12/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI RIGGED UP ATLAS WIRELINE. PERFORATE HEMLOCK HB-3/4 FROM 13055'-13075' AT 8 HPF. RIH WITH FRAC ASSEMBLY AND SET RTTS PACKER AT 12716' WITH TAIL AT 12750'. RIGGED UP AND TESTED SURFACE LINES TO 10,000 PSI. PERFORMED DATA FRAC. PUMPED FRAC JOB AT 15 BPM AS FOLLOWS: 500 BBL PAD; 18 BBL 4 PPA; 35 BBL 8 PPA; 63 BBL 12 PPA; AND 160 BBL DISPLACEMENT (16-20 RESIN COATED CARBOLITE). SANDED OUT WITH 27 BBL OF 12 PPA OUTSIDE THE PERFS. REVERSED OUT EXCESS SLURRY. FILTERED BRINE. POH WITH FRAC ASSEMBLY. RIGGED UP ATLAS WIRELINE. RIH WITH A DRILLABLE BRIDGE PLUG & HUNG UP AT 11327'. SET THE PLUG TO RELEASE THE RUNNING TOOL. RIH & DRILLED UP THE PLUG AT 11327'. PUSHED THE JUNK TO 12838'. FILTER FLUID. SET DRILLABLE BRIDGE PLUG AT 12765' ON DRILL PIPE TO ISOLATE HB- 3/4 PERFS. RIGGED UP ATLAS WIRELINE. RELOGGED INTERVALS FROM 12750'-12250' AND 10500'-10000' WITH SBT/VDL/GR/CCL. PERFORATED HEMLOCK HB-1 FROM 12670'-12680' AT 8 HPF. RIH WITH FRAC ASSEMBLY. G-29 REDRILL 13538'/13449' DaY 34 (7/13/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI CONT RIH WITH FRAC ASSEMBLY AND SET RTTS PACKER AT 12312' WITH TAIL AT 12346'. RIGGED UP AND TESTED SURFACE LINES TO 10000 PSI. PERFORMED A 150 BBL INJECTIVITY TEST WITH 3% KCL/FIW AT 15 BPM. PUMPED FRAC JOB IN TO HB-1 AT 15 BPM AS FOLLOWS: 350 BBL PAD; 19 BBL 4 PPA; 28 BBL 8 PPA; 57 BBL 12 PPA; AND 142 BBL DISPLACEMENT (16-20 RESIN COATED CARBOLITE). SANDED OUT WITH 3 BBL OF 12 PPA OUTSIDE THE PERFS. REVERSED OUT EXCESS SLURRY. TRIP FOR CLEAN OUT ASSEMBLY. PERFORMED WEEKLY BOPE TEST. RIH WITH CLEAN OUT ASSEMBLY AND TAGGED SAND AT 12444'. CLEANED OUT TO 12734'. G-29 REDRILL 13538'/13449'ETD DaY 35 (7/14/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI CONTINUED CLEAN OUT TO 12765'. DRILLED THE RETAINER AT 12765'. CONTINUED CLEANOUT TO 13449' ETD. CIRCULATED AND FILTERED FLUID. TRIPPED FOR TUBING CONVEYED PERFORATING ASSEMBLY. G-29 REDRILL 13538 '/13449 ' DaY 36 (7/15/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI COMPLETED TRIP OUT. PICKED UP AND RIH WITH TUBING CONVEYED PERFORATING ASSEMLBY. RIGGED UP ATLAS WIRELINE AND RAN GR CORRELATION LOG. SET PACKER AND RAN CONFIRMATION LOG. PERFORATED HEMLOCK AT 8 HPF WITH 4-5/8" 25 GRAM DEEP PENETRATING CHARGES AS FOLLOWS: HB-1 12647'-12694'; HB-3/4 12868'-13215'. REVERSED WELL CLEAN-HOLE TAKING 30 BPH. POH W/TCP GUN ASSEMBLY. G-29 REDRILL 13538'/13449' DaY 37 (7/16/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI RIGGED UP TO RUN COMPLETION. RUN 3-1/2" SINGLE GAS LIFT COMPLETION (HYDROTESTING TO 5000 PSI). G-29 REDRILL 13538'/13449' DaY 38 (7/17/92) 13-3/8" WINDOW @ 6572' 9-5/8" C @ 10078' 478 PSI LANDED COMPLETION WITH THE PERMANENT PACKER AT 12499'. PACKED OFF AND TESTED THE TUBING HANGER. DROPPED THE SETTING BALL AND PRESSURED UP THE TUBING TO SET THE PACKER. SHEARED OUT THE SETTING BALL AND TESTED THE PACKER. SET BACK PRESSURE VALVE AND NIPPLE DOWN BOPE. INSTALLED AND TESTED PRODUCTION TREE. PREPARED TO SKID RIG TO TBUS G-15 WORKOVER. RELEASED RIG AT 2400 HRS ON 7/17/92. R[CEIV[D Alaska Oil & G~,.'.~ Cons. Commission STATE OF ALASKA A~' \ OIL AND GAS CONSERVATION APPLICA I'ION FOR SUNDRY APi-'ROVALS 1. Type of request: Abandon __ Suspend Alter casing __ Repair well Change approved program __ 2. Name of Operator I Union Oil of California (UNOCAL) I Development X Exploratory __ 3. Address Stmfigraphio __ P. O. Box 196247, Anchorage, Alaska 99519 Sen~ce 4. Location ofwell at surface Leg #4, Conductor #18, Grayling Platform 1837' FSL and 1438' FEL, Section 29, T9N, R13W, S.M. At top of productive interval Top Hemlock: 12647' MD (9391' TVD) 491' FNL and 2561' FEL, Section 30, T9N, R13W, S.M. At effective depth 13449' MD (9763' TVD) 59' FNL and 3130' FEL, Section 30, T9N, R13W, S.M. At total depth 13538' MD (9803' TVD) 9' FNL and 3190' FEL, Section 30, T9N, R13W, S.M. Operations shutdown __ Re-enter suspended well__ Plugging __ Time extension Stimulate Pulltubing Variance Perforate OtherX Coiled Tubing 5. Ty'--~e of Well: -- 6.-~'atum eleva-~on (DF or KB) 103' RKB above MLEW feet 7. Unit or Property name Trading Bay Unit 8. Well number G- 29 Redrill 9. Permit number 92-52 10. APl number 50-733-20374-01 11. Field/Pool McArthur River/Hemlock 12. Present well conclition summary Total depth: measured true vertical 13538' feet Plugs (measured) 9803' feet Effective depth: measured 13449' true vertical 9763' feet Junk (measured) feet Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length Size Cemented 911' 6572' 20" 1814 sxs 13-3/8" 4110 sxs 10078' (window) 9-5/8" 3771' 7" measured 12647' - 12694'; true vertical RECEIVED =",laska Oil & Gas Cons. L;ol-nmissio[~ Metered depth Anchora~ue ven~a dep~ 911' v~'~ "~,~ 911' 6572' 56~' 1575 sxs 10078' 8048' 1162 sxs 9767' - 13538' 7844' - 9803' 12868' - 13215' 9392' - 9415'; 9498' - 9662' Tubing (size, grade, and measured depth) Single 3-1/2", 9.2#, N-80, Buttress with tubing tail at 12575' MD Packers and SSSV (type and measured depth) Baker "3-H" Hydroset Prod Pkr at 12499' MD, Baker SSSV (Tbg Retrievable) at 296' MD 13. Attachments Description summary of proposal X__ Detailed operations program__ BOP sketch X__ 14. Estimated date f~ commencing operation ~15. Status of well classification as: August 10, 1992 16. If proposal was verbally approved Oil X Gas __ Name of approver Date approved Service Suspended 17. I hereby certify that the foregoing is true and .(~rrect to the best of my knowledge, Signed Gary S. Bush (~~ ~, ~:)~~ Regional Drilling Manager (~ ~-~ FOR COMMISSION USE ONLY Conditions o[ approval: Noah/Coha~nission so representative may witness Plug Integrity ~ BOP Test Location clearance Mechanical Integrity Test~ S-'~bsequent form required 1'-~'- ~ O L~ Approved by the order of the Commission Original Signed Ely David W. Johnston Date August 6, 1992 IApproval Nr~ _ .. ~,pproved Copy / Returned Commissioner Date ~'/JO / C~ 2. SUBMIT I1~ TRIi~LICATE Form 10-403 Rev 06/15/88 COILED TUBING CLEANOUT PROCEDURE TBUS G-29RD 1) Skid Rig #55 over TBUS G-29RD, Leg #4, Conductor #18. 2) MIRU 1-1/2" coiled tubing unit. 3) Install and test BOPE to 5000 PSI. 4) Lock open the Baker tubing retrievable subsurface safety valve by insuring that the control line pressure cannot be bled off. 5) Run in with a wash nozzle on coiled tubing and tag fill (Fill tagged with wireline at 12846' WLM). 6) Cleanout fill to 13449' ETD. a) Use 3% KCL/XCD Sweeps as needed to clean the hole. b) Use gas lift to help move solids in the tubing. 7) Pull to the tubing tail and circulate while waiting on fill to settle. Run in and tag for fill. Trip out. 8) Rig up wireline. Run production profile logs. 9) Run a "thru tubing" inflatable bridge plug on coiled tubing and set the plug in the liner above the water producing zone, as determined from the profile log. Trip. 10) Production test the well to determine if the water has been shutoff. 11) Once the water has been shut off by proper placement of the inflatable bridge plug. Lay a cement plug on top to complete the isolation.~'%.[~,.EI[~ i7~ (' ~\/ E~J~":' 12) Rig down coiled tubing unit and return well to production. ,' ....... "' "Co,i°. ,.~,~,slo.~ Oii &,~ao ""-" Arlchorage NOT~.: Anticipated SIBHP is 3950 PSI at 9450' TVD. The workover fluid will be 3% KCL/FIW with NACL as required for well control. UNOCAL TUBULAR DETAIL ~ :~lt; 0--29 RD GRAYLING PLATFORM PAGE 1 01' 1 DATE: Jt~ Y 16, 1992 AFE NO.: .521403 STRING: SINGLE SI'RING; 3--1/2" 9.2# N--80 SC BUTTRESS FOREMAN: DON B YRNE WL REG/SO S 0.95 12573.65 12574.6 1 JOINT3-1/2", 9.2#, N-80, SC B~ESSTUBING 31.5 12542.15 12573.65 BAKER '~X' LANDING NIPPLE 1.25 12540.9 12542.15 1 JOINT 3-1f2", 9.2#, N-80, SC BLrITRESS TUBING 31.02 12509.88 12540.9 CROSS OVER 0.63 12509.25 12509.88 MILL OUT EXTENTION 5.51 12503.74 12509.25 BAKER 3-H HYDRO SET PRODUCTION PACKER 4.79 12498.95 12503.74 BAKER CH ANCHORTUBING SEAL NIPPLE 1.49 12497.46 12498.95 1 JOINT 3- lf2", 9.2#, N-80, SC BLrITRESS TUBING 31.5 12465.96 12497.46 BAKER CMU SLIDING SLEEVE 3.88 12462.08 12465.96 1 JOINT 3-1/2", 9.2#, N-80, SC B~ESS TUBING 31.78 12430.3 12462.08 1 1 GAS LIFT MANDREL #12 6.5 12423.8 12430.3 36 JOINTS3-1/2", 9.2#, N-80, SCB~ESSTUBING (#5-#40) 1135.9 11287.9 12423.8 2 1 GAS LIFF MANDREL #11 6.5 11281.4 11287.9 35 JOINTS3-1/2", 9.2#, N-80, SCBUTTRESSTUBING (#41- #75) 1099.69 10181.71 11281.4 3 1 GAS LIFT MANDREL #10 6.5 10175.21 10181.71 29 JOINTS3-1/2", 9.2#, N-80, SCBLrI~RESSTUBING (#76- #104) 913.56 9261.65 10175.21 4 1 GAS LIFT MANDREL g9 6.5 9255.15 9261.65 27 JOINTS 3-1/2", 9.2#, N-80, SC B~ESS TUBING (#105 - #131) 852.07 8403.08 9255.15 5 1 GAS LIFt MANDREL #8 6.5 8396.58 8403.08 28 JOINTS3-1/2", 9.2#, N-80, SC BUTrRESS TUBING (#132- #159) 883.14 7513.44 8396.58 6 1 GAS LIFT MANDREL/g7 6.5 7506.94 7513.44 26 JOINTS3-1/2", 9.2#, N-80, SC BUTrRESS TUBING (#160- #185) 815.97 6690.97 7506.94 7 1 GAS LIFT MANDREL #6 6.5 6684A7 6690.97 28 JOINTS3-1/2", 9.2#, N-80, SC BUTrRESS TUBING (#186-g213) 873.4 5811.07 6684A7 8 1 GAS LIFT MANDREL #5 6.5 5804.57 5811.07 26 JOINTS3-1/2", 9.2#, N-80, SCBUTTRESSTUBING (#214- ~239) 815.81 4988.76 580437 9 1 GAS LIl:rr MANDREL #4 6.5 408226 4f~8.76 27 JOINTS 3-1/2", 9.2#, N-80, SC BUTTRESS TUBING (#240 - ~g266) 849.98 4132.28 498226 10 1 GAS LIFT MANDREL #3 6.5 4125.78 413228 32 JOINTS3-1/2", 9.2#, N-80, SC BUTI~ESS TUBING (#267- ~g2~) 1009.05 3116.73 4125.78 11 1 GAS LIFT MANDREL ~/2 6.5 3110.23 3116.73 25 JOINTS3-1/2", 9.2#, N-80, SCBWITRESSTUBIN~3 (#299-#323) 787.37 2322.86 3110.23 12 1 GAS LIFT MANDREL #1 6.5 231636 2322.86 64 JOINTS3-1/2", 9.2#, N-80, SCBI. YITRESSTUBING (#324- #387) 2008.51 307.85 2316..36 1 PUP JOINT; 3-1/2" 9.2# N-80 BUITRESS w/3-7/8" OD COUPLING 3-7/8" 4.16 303.69 307.85 SCSSSV 7.48 296.21 303.69 1 PUP JOINT; 3-1/2" 9.2# N-80 BUI~RESS w/3-7/8" OD COUPLING 3-7/8" 4.14 292.07 296.21 8 JOINTS3-1/2", 9.2#, N-80, SC B~ESS TUBING (#388- #395) 249.9 42.17 292.07 CIW 11", 5000# DCB HANGER i~ ~ (i ~ i ~ ~'~ ~k 0.82 41.35 42.17 RKB ELEVATION '' ~ ~ ' L~ ] V l, L/ 41.35 0 41.35 0 UP WEIGHT; 132K :"~ ~g '~''~ .... ~ ~ ~'' ~'' ' 0 DOWN WEIOHT;82K ~:.~,c~ .Wc~ OJi ° ~"~'~ f~:"'~ ~-'~ ..:.~.'~.~,'..'~ i:~ 0 1 28' @ 324' 20'@ 911' 13-3/8' @ 6572' LINER TOP @ 9767' 9-5/8' WIN DOW @ 10078' KB @ 0.0' TBG HGR (TOP) @ 41.35' TUBING DETAIL: 3-1/2", 9.2#, L-80 BUTTRESS TUBING , NACE SERVICE EQUIPMENT 1) BAKER TUBING RETRIEVABLE SSSV (SELF EQUALIZING FLAPPER) @ 296' 2) GAS LIFT MANDRELS AS FOLLOWS' GLM #1 @ 2316' GLM #2 @ 311 O' GLM #3 @ 4126' GLM #4 @ 4982' GLM #5 @ 58O5' GLM #6 @ 6684' GLM GLM GLM GLM GLM GLM #7 @ 7507' '?'t/~t'k~ £L"i ~ ,.. #8 @ 8397' #9 ~ 9255' Anchorage, · ~0 ~ ~0~75' · 11 ~ 11281' · 12 ~ 12424' 3) BAKER 'CMU' SLIDING SLE~E AT 12~2' 4) BAKER '3-H" PROD PACKER ~ 12499' "CH' ANCHOR TUBING S~L NIPPLE AT 12497' MILLOUT ~ENSION AT 12504' 5) BAKER ~ ~NDING NIPPLE AT 12541' 6) BAKER RE-ENTRY GUIDE AT 12575' 7' P-110 @ 13538' ~13449' ETD PERFORATED INTERVALS: HB-1: 12647' - 12694' 12670' - 12680' HB-3/4: 12868' - 13215' 13055' - 13075' FRAC STIM FRAC STIM WELL TBUS G-29RD COMPLETION (JULY 16, 1992) UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) DRAWN: DAC SCALE: NONE DATE: 8-06-92 TEXAS TOOLS OGT. ~4 TUBING STRIPPER/PA K~_ R I $,000 psi Working Pressure ~ ~ H:S. Service ~...L 1.00'Series DS322~. 1.2~!~erJes DS323 Telex: 79090S TX TOOLS. HOU phone: (71'3) 6206 AOGCC GEOLOGICAL MATERIALS iNVENTORY LiST PERMIT # , /~_~ - ~,4-~,~ WELL NAME COMPLETION DATE 7 ," /,,~' j ?.~'-- CO. CONTACT Check off or i'ist dat'~ a~' it'iS reccivcd.*list received date fo~ 407. if not rc~ircd list a's core. i.,c~is "i ~ore ;~alysi; ~j d~i~ch ~ntc~als ~ "'digital data ,,'~ ........ :'",',,,',,,',1 ' ', ....... I ~, ~, ,, "' ,',I"~~ ~ ' I ...... ~ .......~ ................ ............. ! ................. ! .......~ ........ ...... NO. [t~ thc neareot,~oot} .... [inchll OO'} ,, ,,,, i01 .... Unocal North America~-~;i & Gas Division Unocal Corporation 909 West 9th Avenue, P.c .ox 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNO .AL R. C. Warthen Regional Manager Development Geology & Geophysics Alaska Region DOCUMENT TRANSMITrAL July 14, 1992 HAND DELIVERED TO: Larry Grant FROM: Kirk Kiloh 3001 Porcupine Drive Anchorage AK 99501 ALASKA OIL & GAS CONSERVATION COMMISSION P O Box 196247 Anchorage &K 99519-6247 ALASKA REGION Transmitting as Follows: Trading Bay 'Unit, McArthur River Field, G-29RD well \ 1 blueline and 1 sepia as follows: egmentedBond log, Gamma Ray - CCL log, run 1 gmented Bond log, Gamma Ray- CCL log, run .,2 ,~Dual Induction Focused log, Gamma Ray 2" and 5 '/BHC Acoustilog, Gamma Ray - 2" and 5",/~ '/~Mud log ,~ v/1 DIFL/AC/SP/GR tape and listing ,/ v/G~o Survey with disk ,/ 2 boxes of dry samples 10,090-12,330' ,/ 12,330-13,538' / 4~ PLEASE ACKNOWLEDGE RECEIPT OF THIS DOCUMENT TRANSMITTAL BY SIGNING AND RETURNING ONE COPY. THANK YOU. DATED: JUL 1 4 1992 Alaska 0il & Gas Cons. Commission Anchorage MEMORA E AND GAS TO: Lonnie C Sm~ CommissioneP DATE: FILE NO: June 26, 1992 lg626-3.doc THRU: FROM: Blair WOndzell e/~ SUBJECT: P. I. Supervisor Louis R Grimaldi Petr Inspector BOP Test Unocal Rig 55 Permit No. 92-52 Grayling G-29 AP Wednesday, June 17. 1992 I travelled to Unocal's Grayling Platform to witness the weekly BOP test on their rig, which is Presently performing a redrill on Well G-29. The test went well with one failure, that being a floor safety valve. A new one was brought from town and tested ok. Ali. else appeared good and the rig resumed operations. The rig and associated equipment appeared to be well maintained. In sugarY, I witnessed a good BOP test on Unocal's Graylinq Rig 55 with one failure, the floor safety valve. Attachment 02-00lA (Rev. 6/89) 20/ll/MEMO1.PM3 OPERATION: Drlg ~ Wkvr Operator C) X90 4 - Drlg contrctr xPO 0 ~-_. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION BOP Test Report TEST: Initial Rep Weekly / Other Rig phone # 77~ csg set Location (general Housekeeping (.geyneral Rsrve pi t/":/~C' MUD SYSTEMS: Trip tank Pit gauge Well sign Rig Gas detectors BOPE STACK: Test Pressure Annul ar preventer Pipe rams Blind rams Choke'line valves HCR Valve Kill ltne valves Check valve ACCUMULATOR SYSTEM: Full charge pressure Press after closure Pump inet clos press 200 psig Full charge press attained Controls: Master 'Remote ~? O (~[~) psig / ~/~ C~ psig -------' min ~"-~-- sec ~ ~ sec ~.~ min ~ psig ~--~ 0 _ . ~Blind switch cover KELLY AND FLOOR SAFETY VALVES Upper Kelly ~ Test Lower Kelly ~ Test Ball type F Test Inside BOP / Test Choke manifold ~/ Test Number valves Number fl anges Adjustable chokes / Hydraulically operated choke pressure ~-~ pressure _ pressure pressure TEST RESULTS: Failures / Test time~ : H~': hrs Repair or replacement of failed equipment to be made within __ days. Notify the Inspector, and follow with written/FAXed [276-7542] verification to Commission office. Remarks: Distribution: orig - AOCCC C - Operator c - Supervisor C.004 (rev 03/92) STATE WITN,ES~EOUIRED? J yes yx no J 24-HR NOTICE//G~'VEN2 j yes ~ no j Waived by: Witnessed b~~ ALASKA OIL AND GAS CONSERVATION COMMISSION May 14, 1992 WALTER J, HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 80.63 Re: The application of Union Oil Company of California, operator of the Trading Bay Unit (TBU), to drill, complete and produce the TBU G-29 Redrill (RD) well. Mr. Gary S. Bush Regional Drilling Manager UNOCAL Corp. P. O. Box 190247 Anchorage, Ak 99502-0247 Dear Mr. Bush: Your application of May 12, 1992 for a permit to drill the TBU G-29 RD indicates that the drilling and completion of the TBU G-29 RD well will provide additional oil recovery from the Hemlock Oil Pool. The Alaska Oil and Gas Conservation Commission hereby authorizes the drilling and completion of the TBU G-29 RD well pursuant to Rule 5 of Conservation Order No. 80. Sincerely, Russell A. Douglass Commissioner BY ORDER OF THE COMMISSION ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 May 19, 1992 Gary S. Bush Regional Drilling Manager . UNOCAL P O BOX 196247 Anchorage, AK 99519 Re: Trading Bay Unit G-29 RD UNOCAL Permit No: 92-52 Sur. Loc. 1837'FSL & 1438'FEL, Sec. 29, T9N, R13W, SM 'Btmhole Loc. 46'FSL & 3314'FEL, Sec. 19, T9N, R13W,.SM Dear Mr. Bush: Enclosed is the approved application for permit to redrill the above referenced well. The permit to redrill does not exempt you from obtaining additional permits ~equired by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given by contacting the Commission at 279-1433. David W. ~ohnston~ , Chairman ' BY ORDER OF T~E COMMISSION dlf/Enclosures Department of Fish & Game, Habitat Section w/° encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA -- ALASK,~ ~IL AND GAS CONSERVATION CO fISSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work Drill ~] Redrill F~ 1 lb. Type of well Exploratory F'J Stratigraphic Test F~ Development Oil Re-Entry F~ Deepen ~I Service [-1 Development Gas F'] Single zone~ Multiple Zone ~ 2. Name o~ Operator 5. Datum Elevation (DF or KB) 10. Field and Pool (UNOCAL) Union Oil Company of California 103' RKB above MSL McArthur River Field 3. Address 6. Property Designation Hemlock P.O. Box 196247, Anchorage, AK99519 ADL 17594 4. Location of well at sur~ce: Conductor #18, Leg ~ 7. Unit or property name 11. Type Bond (SE~ ~nAcc25.0~ 1837' FSL & 1438' F,~L, Sec 29, T9N, R13W, S.M. Trading Bay Unit United Pac. Ins. Co. At top of productive interval: 12549' MD / 9350' TVD 8. Well number Number U62-9269 500' FNL & 2500' FEL, Sec 30, T9N, R13W, S.M. G-29 Reclrill At total depth: 13700' MD / 9950' TVD 9. Approximate spud date Amount $200,000 46' FSL & 3314' FEL, Sec 19, 'r9N, R13W, S.M. May 1992 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD,~WO) property line 500' atTop Hemlock 1500' (G-13) 17299 Acres ( Hemlock ) 13700' ! 9950' 16. To be completed for deviated wells 17. Anticipated Pressure(s, ~n AAC 25.oa5 (~(~) Kickoff Depth 10000' MD Maximum holean§le 59 DEC Maximum surface 846 psic~ At total depth ¢VO) 4158 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cema nt Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 8-1/2" 7" 29# N-80 Butt. 4000' 9700' 7974' 13700' 9950' 585 sxs (672 cu ft) , , 19. To be completed for Redrill, Re-entry, and Deepen Operations Present well condition summary Total depth: measured 12733' feet Plugs (measured): Retainer at 11328' MD (8880' '[VD) true vertical 9930' feet S q ueezed ~l~tl~ ~J~"~'~~ a ~ i.. ~,.,, i../v i.., i,.,. Effective depth: measured 11328' feet Junk (measured): true vertical 8880' feet MAY 1 1992 Casing Length Size Cemented Measured.d, epth Tr~(~ns.e ve ~ Structural ~as~a Oil & Gas Conductor ~ch0rage Surface 911' 18" 1814 sxs 911' 911' Intermediate 6572' 13-3/8" 6414 sxs 6572' 5608' Production 12728' 9-5/8" 750 sx 12728' 9926' Liner Perforation depth: measured 11680'- 11664'; 11990' - 11994'; 12118' - 12122'; 12180' - 12184'; 12360' - 12364' Each perf interval was isolated by cmt retainer and sqzd w/ "G" cmt true vertical 9129'- 9133'; 9355'- 9359'; 9448'- 9452'; 9495'- 9499'; 9632'- 9636' 20. Attachments: Filing fee ~ Property plat ~ BOP Sketch~ Dive,er Sketch ~ Drilling program ~ Drilling fluid program ~ Time vs depth plot ~ Refraction analysis [-'] Seabed report r~ 20 AAC 25.050 requirements r"] 21. i hereby certify~hat the foregoing is true and correct to the best of my knowledge ~ Signed Ga~~~. ~.~, Title Regional Drilling Manager Date ' Commission Use Only Permit Number '" [APl number I Ap~q~..._~l ~dat_.e.Is . coverletter ~.2.. - ,.~, ~ J 50-~.~_~ - .7..o..~ .7 ~-- o /I ,,.~ / / _~'.~I for other requirements Conditions of approval Samples required r--] Yes~ No Mud log required ~ Yes~[ No Hydrogen sulfide measures ~ Yesj,,~ No Directional survey required ~ Yes [~ No Required workin~.,._~essureforB~lJB_F,~..,~..M; [~ 3M; F'] 5M; r-1 1OM; F~ 15M by the order of // Approved . Commissioner the commission Dat~. I 3M; ~ 5M; r-1 Form 10-401 Rev. 12-1-85g ~ SubnT tin triplicate Unocal North Americ¢ -' Oil & Gas Division Unocal Corporation P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL Robert T. Anderson Manager, Lands Alaska Region May 12, 1992 Mr. Russell Douglass Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 TRADING BAY UNIT STATE OF ALASKA Permit to Drill Well: G-29 Redrill Dear Mr. Douglass' Union Oil Company of California, as operator of the Trading Bay Unit, hereby requests approval to drill, complete, and produce Trading BayUnit State well G-29 Redrill in the McArthur River Field "Hemlock Zone" pursuant to Rule 5, Conservation Order No. 80. The proposed completion of this well will result in additional recovery of Hemlock Production. In accordance with AOGCC Regulation 20 AAC 25.005 (Permit to Drill), enclosed please find check number 11192 in the amount of $100.00 payable to the State of Alaska, Department of Revenue to cover the permit fee for the above referenced well. Aisc enclosed is form 10-401 in triplicate, covering the subject permit for your approval. Your approval of this request will be appreciated. Should you have any quel i 11 " E&¥ E contact the undersigned at 263-7602. MAY 1 ) 199~ Ve.ry truly yours, Alaska 0ii & ~as Cons. Kevin A. Tabler Land Administration Manager TRADING B~Y UNIT TBUS G-29 REDRILL DRILLING PROCEDURE 1. Skid Rig #55 over TBUS G-29, Conductor 18, LEG #4. 2. Nipple up and test BOPE to 3000 psi. 3. Run bit and scraper in 9-5/8" casing to 11328' ETD. 4. Shoot squeeze holes from 10065' to 10069'. Set a cement retainer at 10055'. Squeeze with 250 sxs cement to complete the abandonment of the original hole. 5. Shoot squeeze hole from 9950' to 9954'. set a cement retainer at 9925'. Squeeze for casing stabilization with 250 sxs cement. Drill out to 10055' (cement retainer). 6. Set casing whipstock and mill window at 10000'. 7. Drill 10' of new formation and run leak off test. Squeeze, if necessary. 8. Redrill from 10000' to 13700' TD (8-1/2 hole). 9. Run logs. 10. Run and cement 7" liner. 11. Clean out, run cased hole logs and change over. 12. TCP perforate HB-3 and HB-4. 13. Fracture stimulate. 14. TCP perforate HB-1 and HB-2. 15. Fracture stimulate. 16. Clean out run to ETD. Set permanent production packer. 17. Run single 3-1/2" gaslift completion. RECEIVED UAY 1 199 Alaska Oil ,& Gas Cons. Comm~ssiO~ Anchorage TI~,D~NG B~Y UNIT TBUS G-29 REDRILL ANTICIPATED PRESSURES: MAXIMUM SURFACE PRESSURE CALCULATION FOR 8-1/2" HOLE MUD WEIGHT 9-5/8" CASING SHOE DEPTH 9-5/8" CASING SHOE FRAC GRADIENT TD OF 7" CASING POINT PORE PRESSURE GRADIENT GAS GRADIENT 9.6 PCF = 0.500 PSI/FT 10000' MD / 7992' TVD 0.90 PSI/FT 13700'MD / 9950' TVD 0.460 PSI/FT 0.0 PSI/FT ASSUME THAT 25% OF THE WELLBORE IS DISPLACED DURING A GAS KICK ( HOLE FILLED WITH 75% MUD AND 25% GAS ). MAXIMUM SURFACE PRESSURE = BHP - MUD/GAS HYDROSTATIC PRESSURE MSP = BHP - (3/4 MUD + 1/4 GAS) MSP =( 9950 FT * .460 psi/ft) -((.75 ( 9950 FT * .500 PSI/FT )) + ( .25 ( 9950 FT * 0 PSI/FT ))) MSP = 846 PSI THE GREATEST HYDROSTATIC PRESSURE AT THE 9-5/8" SHOE (HPsh) IS WHEN THE GAS BUBBLE REACHES THE SHOE, IF A CONSTANT BHP IS APPLIED. A CONSERVATIVE ESTIMATE WOULD BE THE MAXIMUM SURFACE PRESSURE (MSP) PLUS THE HYDROSTATIC PRESSURE AT THAT CASING DEPTH (HPcsg). HPsh = MSP + HPcsg + ( . oo RECEIVED 4842 PSI FPSh = FRAC GRAD * TVDshoe FPsh = 0.90 PSI/FT * 7992 FT = 7193 PSI MAY 1 199 Olt .& Gas Cons. t.;ommi$$io" o orago. HPsh = 4842 PSI IS LESS THAN THE FRACTURE PRESSURE AT THE 9-5/8" SHOE, FPsh = 7193 PSI AND THEREFORE ADEQUATE TO HANDLE THE WELL KICK. THIS SCENARIO IS CONSIDERED EXTREMELY CONSERVATIVE, SINCE A 316 BBL GAIN IS REQUIRED TO DISPLACE 25 PERCENT (VERTICAL) OF THE WELL BORE FROM AN ENTRY AT TD. TI~,.DING BAY UNIT TBUS G-29 REDRILL MUD PROGRAM ABANDONMENT AND 9-5/8" WINDOW MILLING RECOMMENDED PROPERTIES MUD WEIGHT FUNNEL VISCOSITY PLASTIC VISCOSITY YIELD POINT PH 8.8 TO 9.3 PPG 60 TO 150 SEC/QT 10 TO 15 CP 15 TO 25 #/100 SQ FT 9 TO 10 8-1/2" HOLE SECTION I 7" CASING 10000' TO 13700' MD ( 7992' TO 9950' TVD ) ( GENERIC MUD #2 ) RECOMMENDED PROPERTIES MUD WEIGHT FUNNEL VISCOSITY PLASTIC VISCOSITY YIELD POINT PH API FLUID LOSS HPHT @ 200 SOLIDS 9.0 TO 9.6 PCF 45 TO 55 SEC/QT 12 TO 20 CP 8 TO 16 #/100 SQ FT 8.5 TO 9.5 4 TO 6 CC 15 TO 18 CC 5 TO 8 PERCENT RECEIVED o EFFECT OF AXIAL TENSION ON COLLAPSE FOR LONE STAR STEEL CO. CASING Collapse ~esistance tn tension X (Collapse pressure rati~lg) Burst Pressure ~ ~P +. Depth ( Hyd. Gr. II --,5) BF (Bouyancy Fac'tot) = 1.oo- (o.o1~3 x ~ua wt. z) Calculations: TENSION LOAD AXIAL LOAD FACTOR,XI~= BODY YIELD STRENGTH WELL TBUS C-29 REDRiLL CflSING STRING 7" LINER CASING AND IUBIN$ DESIGN FIELD MCARTHUR RIVER FIELD BOROUGH.. GRAYLING PLATFORM STATE ALASKA DAlE ~,~Y 10, 1992 DESIGN BY D.A. CHUDANOV 1. I.~]D WT. I #/q: tlYD GR. I psi/ft. HUD WT. II #/q. HYD. GR. II psi/rt. M.S.P. pst. ASSUMPTIONS: 0.50 psi/fL gradient on outside, void on inside for collapse 0'.50 psi/ft gradient on inside, void on outside for burst WEIGHT IENSIBN MINIMUM COLLAPSE COLLAPSE W/ BF ,. -top or SIRENGTIt PRESS. ~ RESIST. INTERVAL , DESCRIPTION W/O BF '~ section 1ENSION bottom tension CASING SIZE Bottom Top LENGTH Wt. Grade lhread lbs lbs' 1000 lbs lDF ___psi ps1 9950' 7777~ TVD ].. 7" liner 13700' 9700 4000' 29# P-110 BUTTRESS 1!6,000 116,000 955 8.2 4975 8510 INlERNAL BURST MINIMUM PRESSURE YIELD CDF pst pst BDF 1.7 4975 11220 2.3 28' @ 324' 20' @ 911' 13-3/8' @ 6572' ,/ CMT RET @ 11328' DRILL PIPE FISH c~ 11401' MD CMT RET @ 11655' CMT RET @ 11960' CMT RET @ 12085' CMT RET @ 12165' CMT RET @ 12330' 9-5/8' @ 12728' KB @ 0.0' --~59QZD WI CU ,F--l'....p SQZD W! 552 CU FT CMT -- SQZD W/552 -- CU FT CMT -- SQZD W/115 CU FT CM'r SQZD W/328 CU FT CMT SQZD W/282 CU FT CMT -. COLLAPSED CASING AT 11395' MD ( MILLED HOLE IN CASING F/11398' TO 1141 O' MD ) SQZ PERFS F/11680' - 11684' MD SQZ PERFS F/11990' - 11994' MD SQZ PERFS F/12118' - 12122' MD SQZ PERFS F/12180' - 12184' MD SQZ PERFS F/12360'- 12364' MD WELL TBUS G-29 ORIGINAL HOLE EXISTING CONDITION ( APRIL 8, 1985 ) UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) DRAWN: DAO SCALE: NONE I 28" @ 324' 20' @ 911' 13-3/8" @ 6572' KB @ 0.0' TUBING DETAIL: 3-1/2', 9.2#, L-80 TUBING LINER TOP @ 9700' 9-5/8" WI N DOW @ lOOOO' 1) SUBSURFACE SAFETY VALVE 2) GAS LIFT MANDRELS 3) 'XA' SLIDING SLEEVE 4) PERMANENT PKR @ 12400' 5) "X' LANDING NIPPLE 6) RE-ENTRY GUIDE PERFORATED INTERVALS: 7' P-110 @ 13700' HB-1 HB-2 ~ HB-3 HB-4 FRAC STIMULATED ( TVVO STAGES ) WELL TBUS G-29RD PROPOSED COMPLETION UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) DRAWN' DAC SCALE: NONE DATE: 3-06-92 I p c iVFO ~A¥ 1 ~ ~992 Alaska Oil & Gas Cons. (;ommiss'toa '_.Anchorage BELL NIPPLE ] FLOWLINE 13-5/8' 3000 PSI ANNULAR 3' KILL LINE WITH TWO 2' 5M VALVES KILL LINE FROM MUD PMP & CEMENT UNIT m PIPE RAMS BLIND RAMS t I PIPE RAMS , ,] I 13-5/8' 5M FLANGE DOUBLE GATE 5M I 13-5/8' 5M FLANGE J 4' CHOKE LINE WITH ONE REMOTE & 1 MANUAL 4' 5M VALVE ',i[;' :~[,;' I CONNECTED TO CHOKE MANIFOLD (SEE MANIFOLD DRAWING) 13-5/8' 5M FLANGE SINGLE GATE 5M 13-5/8' 5M FLANGE RISER I I 13-5/8" BOPE 5M STACK GRAYLING PLATFORM UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) 1 O' 5M x 13-5/8' 5M ADAPTER CAMERON 5M SPOOL RECEIVED r,~ AY 1 ;~ 1992 Alaska Oil & Gas Cons. Comm~ssiol ~~DAC APP'D: GSB SCALE: NONE DATE: 11-23-91 TO GAS BUSTER /\ 4- 1,/16" 3-1/8" TO DERRICK VENT I I ! ;3-1/8" TO WELL CLEAN TANK /\ 4-1/16" `3-1/8" 3--1/16" 4--1/16" AUTOMATIC CHOKE .3-1/16" .3- 1/16" /~ ,3- 1/16" ,3-- 1/16" / FROM CHOKE LINE AUTOMATIC CHOKE RECEIVE£ MAY 1 ~ 199~ Alaska 0it .& Gas Cons. Goml VALVES UPSTREAM OF CHOKES ARE 10,000 PSI GATE TYPE VALVES DOWNSTREAM OF CHOKES ARE 5,000 PSI GATE TYPE CHOKE MANIFOLD GRAYLING PLATFORM UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) DRAWN' DAC APP'D: GSB SCALE: NONE DATE: 11/26/89 MIXING PIT 4O BBLS MIXING PIT IS A ONE LEVEL BELOW THE ACTIVE SYSTEM 185 BBLS VOLUME PIT TRIP TANK 45 BBLS 185 BBLS SUCTION PIT 125 BBLS DEGASSER 67 BBLS DESILTER 240 BBLS SHAKER SHAKER i i CENTRIFUGE RESERVE PIT 475 BBLS NOTE: THE SYSTEM WILL BE EQUIPPED WiTH A DRILLING PIT LEVEL INDICATOR WITH AUDIO & VISUAL WARNING DEVICES. EQUIPMENT LIST 1) RESERVE PIT 2) DEGASSER 3) (2) SHAKERS 4) PIT LEVEL INDICATOR (VISUAL & AUDIO) 5) FLUID FLOW SENSOR 6) TRIP TANK 7) PIT AGITATORS 8) DESILTER 9) CENTRIFUGE O) MIXING PIT UNOCAL GRAYLING MUD PIT SCHEMATIC DRAWN BY: DAC APP'D: GSB SCALE: NONE DATE: 11-30-89 GREAT LAND DIRECTIONAL DRILLING, INC. Corporate Office 1111 East 80th Avenue Anchorage, AK 99518 (907) 349-4511 Fax 349-2487 DIRECTIONAL WELL PLAN for UNOCAL CORPORATION Well ......... : G-29 RD (P4) Prepared ..... : 03/12/92 Field ........ : McARTHUR RIVER TBU Section at...: 304.90 Computation..: RADIUS OF CURVATURE KB elevation.: 103.00 ft LOCATIONS LEGAL DESCRIPTION X ASP ZONE 4 Y Surface ...... : 1836 FSL 1481 FEL S29 T09N R13W SM 212201.28 2502386.45 Tie-in ....... : 1712 FNL 721 FEL S30 T09N R13W SM 207722.52 2504230.13 Target.A ..... : 500 FNL 2500 FEL S30 T09N R13W SM 205971.44 2505485.96 BHL .......... : 46 FSL 3314 FEL S19 T09N R13W SM 205169.63 2506052.81 PROPOSED WELL PROFILE STATION IDENTIFICATION TIE-IN END BUILD & TURN TARGET TD MEAS INCLN VERT-DEPTHS SECT DIRECTION REL-COORDINATES DL/ DEPTH ANGLE BKB SUB-S DIST 10000 49.47 7992 7889 4701 10100 51.56 8056 7953 4778 10200 53.67 8117 8014 4857 10300 55.81 8174 8071 4938 10400 57.96 8229 8126 5022 AZIMUTH FROM-WELLHEAD 100 310.70 1732 N 4523 W <TIE 308.92 1782 N 4582 W 2.4 307.24 1831 N 4645 W 2.4 305.65 1879 N 4711 W 2.4 304.14 1927 N 4779 W 2.4 10428 58.57 8244 8141 5046 12549 58.57 9350 9247 6856 13700 58.57 9950 9847 7837 303.73 1940 N 4799 W 2.4 303.73 2945 N 6304 W 0.0 303.73 3490 N 7121 W 0.0 ~.Oil .& Gas rOons' ~'°'"~"'~s$~°~ L,,~IOCAL CORPORA~ ~ON ttarlcer Iden~ ! f !ca~ ~on ~) TZE-TN El) END BUILD G TURN C} TARGET D} TO ltd BKB SECTN INCLN lO000 7992 470i 49.47 i0428 8244 5046 58.57 12549 9350 6856 58.57 t3"/00 9950 7837 58.57 G-;~9 RD IP4) VERTICIL SECTION VIEN Sect ion at: 304.90 TVD Scale.: ! inch = 500 feet Oep Scale.: ! inch = 500 feet Dralvn ..... : 03/t2/92 ANGLE.5B.57 DEGREES ..... 4500 4750 5000'5250 5500 5750 6000 6250 6500 6750 7000 7250 7500 7750 BO00 Section De --UNOCAL CORI ORA-i-ION #arker Identification #D N/S Al TIE-IN tO000 t732 H 4523 PJ ~ BUILD G TURN i0426 t940 N 4799 CJ TARGET t2549 2945 N 6304 DJ TD 13700 3490 N 7~2! Sreat Land D~rect~ona] ZTc~]l~n9 6-29 RD (P4) PLAN VZEH i ii iii il ~LOSURE · 7930 ft at Azimuth 296.ii DECLINATION.' 23.i7 E SCALE ....... : I inch = iO00 ~eet DRANN · 03/12/92 REDRZLL B500 BO00 7500 7000 6500 6000 5500 5000 4500 4000 3500 3000 2500 2000 iO00 500 0 500 <- NEST · EAST -> GREAT LAND IRECTIONAL D LLING INC. Close Approach Analysis w~, G-29 Redrill .~d McAurthur River co~...~ UNOCAL Corporation AFE# ATTENTION Don Chudanov o.t, March 12, 1992 WELL CROSSINGS Crossing Well TVD TVD Distance Above/Below NONE i WELLS WITHIN 100 FEET OF PROPOSED WELL Close Approach Distance Range with well TVD G-29 100 8290 7992 - 8290 W.ll~ Comld~ed fo~ ~hi~ W~l. Con.ld~ed fo~ thi~ , G-OIRD D G-19 G G-40 D G-20 G G-O1 G G-21 G G-O2 G G-22 G G-O2RD G G-23 G G-03 G G-24 G G.O3RD1 G G-26 G G-O3RD2 G G-26 G G-04 G G-27 G G-O4RD G G-28 G GO6 G G-29 G G-O6 G G-30 G G-O6RD G G-31 G G-O7 G G-32 G G-08 G G-33 G G-O8RD G G-34 G G-O9 G G-34RD G G-lO G G-3S G G-lORD G G-36DPN G G-11 G M-1 G G-12 G M-2 G G-12RD G M-3 G G-13 G M-4 D G-14 G M-6 G G-14A G M-13 G G-14A RD P M-14 G G-16 G M-16 G G-16 G M-26 G G-17 G M-27 G G-17RD G M-28 G G-18 G M-29 G G-18DRN G Survey Status: P = Planned D = MWD G =Gyro Survey COMMENTS The profile for G-29 RD was computed from parameters provided by Unocal Corporation. This profile consists of a KOP of 10000' MD building and turning left to an inclination of 58.57°, and a direction of 303.73°. The build and turn is completed by 10428' MD, and held to the target at 12549' MD or 9350' TVD, and finally the TD of 13700' MD or 9950' TVD. The profiles for all other wells in the Grayling Platform area were computed from directional gyro surveys supplied by Unocal Corporation, and or Marathon Oil Company. As shown above the proposed profile for G-29 RD will not encounter any well crossings, and the only close approaching well to G-29 RD is the parent well G-29 from the KOP to a TVD of 8290. ANALYSIS BY: CHECKED BY: D. Th/d~nlpson ~ ~ Alaska 0il & Bas oons. but-~f~issio~ An horag CHECK LIST FOR NEW WELL PERMITS ITEM APRROVE DATE (1) Fee ...... [2 thru 8] (3) Admin [.~)(. ~..~ [g thru 13] : [lo cns [14 thru 22] (5) BOPE [23 thru 28] le 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. Is permit fee attached ............................................... Is well to be located in a defined pool .............................. Is well located proper distance from property 1 ine ................... Is well located proper distance from other wells ..................... Is sufficient undedicated acreage available in this pool ............. Is well to be deviated & is we!lbore plat included ................... Is operator the only affected party .................................. Can permit be approved before 15-day wait ............................ Does operator have a bond in force ................................... ../~ Is a conservation order needed ....................................... I s admi n i st rat i ve approval needed .................................... /~ Is 1 ease n~nber appropriate ..................... · . . Does well have a unique name & nLmber ................................ ]/~ Is conductor string provided ......................................... Will surface casing protect all zones reasonably expected to serve as an underground source of drinking water .................. Is enough cement used to circulate on conductor & surface ............ Will cement tie in surface & intermediate or production strings ...... Wil 1 cement cover al 1 known productive horizons ..................... Will all casing give adequate safety in collapse, tension, and burst. Is well to be kicked off from an existing wellbore ................... Is old wellbore abandonment procedure included on Is adequate wel l bore separation proposed .......... Is a diverter system required ..................... Is drilling fluid program schematic & list of equi Are necessary diagrams & descriptions of diverter Does BOPE have sufficient pressure rating -- test Does choke manifold comply w/API RP-53 (May 84)... Is presence of H2S gas probable ................... 10-403 ............. ,~r Lease & We l 1 ~,/~4~/-- / 7~G-- ? ?' ~-~/_-// / , ,~,, eeee~eeeeeeeeeeeeee ~ (6) Other /t4'~C .~.~///~Z~ 29. [29 thru 31] 30. 31. (7) Contact /4/~//~, 32. [32] (8) Addl ~~~~.~ 33. FOR EXPLORATORY & STRATIGRAPHIC WELLS: Are data presented on potential overpressure zones ................... Are seismic analysis data presented on shallow gas zones ............. If offshore loc, are survey results of seabed conditions presented... Name and phone number of contact to supply weekly progress data ...... Additional requirements ............................................. /, / / g "t'Z ~O geology' DWJ~ rev 04/92 joi6.011 engineering: . .- MTM,~ LCS jH.~Z_/~_j~ -'~ INITIAL GEOL UNIT ON/OFF POOL CLASS STATUS AREA ~ SHORE 520 1.20 Additional remarks' Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information, of this nature is accumulated at the end of the file under APPENDIXi ,. No special'effort has been made to chronologically organize this category of information. ORIGINAL Scientific D~'.ill~r,g ]~,%~r.~iional, Inc. 3511 Yes~uind Drive Rnchora~e, P, laska 9951G Finder Survey ~or tINOCRL Corpora%ion P.O. Box 190247 R~f~'rage, Rla~ka S9519-OZd7 Well Number Si~e Location : G-Z9 RD : 'FBU, Mc(IRTHUR RIVER FIELD : KEN'RI PENINSULR BOROUGII COOK INLET, RLASKR RECEIVED JUL 1 4 1992 Alaska 0il & Gas Cons. Commission Anchorage Job ~Jmber : ¢SF$O7920ZZ Lat ~ 'lude : ~,, 838 Survey Oa~e(s/ o~ ~L-BZ S.D.I. personnel C~lcula~ion Me~hod : Radis oT Curvature Survey ~pth Zero Proposal Direction : Depth Unit ~B ~o MSL ' hi ] az J mu%h~ r-e{e~',er;ced 'to true north. Survey run in B-S/B" cc~ing ond 7" liner. I IIC 0FI/NED -- SCIENTIFIC DR1L LI N'~ Lg~OCRL Cor'pora~ ion G-29 RD Mca~ured Vertical Vert. De~,th Dcptl~ C~ect ion Inc Dec] 0.0 0.~0 0.0 100.0 100.00 0.2 ZO1.0 201.0~ -0.~ Z99. ~ 7. BB. 'dO -0. S 499.9 4BB. 8S 2.1 Survey Azimuth Oeg 1100.1 1099.80 4.7 t2~.0 1t99.69 4.6 13~Y"~.l IZBg.?8 4.4 14~0.0 1399.67 4.Z 1500.0 1499.GG 3.9 page 1 1G~. 3 15~9 . 9,.'S 3.6 1700.1 1699.74 3. Z 1799.9 1'799.S4 2.G 1899.9 1899.53 Z.0 t999.9 t999.53 1.4. Dato : 08-JUL-9Z 28449.8 ?099.41~ 0.9 Z20~.0 :Z199.GZ 0.4 Z299.8 2299.3G Z.g Z"J99.8 7.399. t0 0.6 2499.8 2498.58 17.Z Coor',Jina ~es La~ it~,de Del:,ar~ure 2699.8 2169S.99 44.S 28~. 1 Z793.68 64.0 ZBZS. Z 2817. gS G9. S 850.3 2O42.1 3 75.2 ZS"ZS. 1 Z8GS.9? 81.1 0.0~ 0.0~ 0.0~4 0.00E 0.46 181 .G9 0. ~ON O. ZSW 0.42 IS9.70 0.7GS 0.13W 0.10 Z12.89 1.18S 0.18W 2.05 1G.87 0.09S 2.S4W 1.88 19.:~3 3.17N 1 . 48W 1.83 gl .99 6.70N 0.33W 1.61 Z8.~Z 8.92N 0.95E 1.SS Z7.25 I1.3GN 2.Z3F I . 36 29.90 t 3.59N .3.45E 302S.1 ~(J08.34 121.4 '30~0.1 3031.79 129.0 5075.Z 3055.09 13G.8 31~.1 30'/8.1G 144.~ 1.01 3S.83 1S.3ZN 4.S?E 0.86 43.26 1G.SSN S.61E 0.80 39.8S 17.GGN 6.S7E 0.74 -45.39 18.6SN 7.48E 0.77 48.03 19.SGN 8.43E 0.70 0.69 0.6Z 0. S? 0.61 0.70 (~. 87 3.01 5.1Z 6. S5 -48.41 20.41N 9.3fiE S9.12 ZI.13N 10.3'?E Gg.S? Z1.G8N II.37E 75.63 ZZ.OSN IZ.3~E 74.87 ZZ.3ZN 13..~3E 82.S'? Z2.4SN 14.02E 254.'77 gt .84N 14.14E 2BG. 18 Z 1 . 29N 10.82E ZG9.05 20.99N 3. '/4E 27:4.3'/ 71 · 21N 6. 431,,.I 2'73.57 2$.IZN 58.02W 2?2.80 24.38N 60.GGW ZTZ.TG Z4.GgN 67.08W 272.80 £S.02N 73.78W 2'72.89 2S.:~GN RO.G3W 272.77 ZS.71N 87.7SW Z'72.78 26.07N 9S. 18W Z72.GG 2G.44N 102.90W 272.S0 Z6.80N 110.88W 277.47 Z'/.1SN 119.11W 272.86 ZT.SGN tgT.GBW 277.99 28.01N 136.54W 273. tG 28.5~N 14S.G8W 273.~"~ 29.02N 155.03W 1 I.G7 14.4C lS.ZZ 15.78 16.31 16.99 17.GZ 18.Z5 18.88 19.75 20.43 21.07 21.75 22.43 D-leg 0.00 0.46 0.17 0.38 1 . 07 0.19 0.10 0.29 0.0? 0.20 0.37 0.19 0.08 0. t0 0.04 0.07 0.13 0.08 0.14 0.04 0.41 1.07 2, 1'/ 2.12 I. 49 Z. S6 Z .79 5.0'3 2.Z3 Z.14 Z .73 2.52 Z.S1 Z. SZ 3.4.9 Z. '77 Z. 5'/ z. 2, SCIENIIFIC DRILL1NG UNOCAL Corpora ~ ion G-?9 RD Medsured VerLical Verk. 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Z G370.18 2926.4 46.16 297.21 2944.4 46.16 297.36 2962.3 46.23 297.49 2980.3 46. i)0 ~97.44 2998.3 48,37 297.45 708.75N 3048.71W 0.75 717.09N 3064.86W 0.51 725.41N 3080.88W 0.40 73J.'?4N 309G,90W 0,32 74Z.07N 311Z.BSW 0.29 7G[~. 1 G;587,41 ?G75, 1 6484. ?Z 7700, 1 G4Z Z . 03 772 S, Z 64 39.49 ?'/Se. z~ G4S?. ~S ~lG, l 4G.05 29'7.49 3034,0 46.29 297.50 5052.0 46.09 29'7.57 3069.9 45,74 297.93 308'7.9 45.94 ~9'7.81 750, 3GN 3128,90W 1 . 29 7SS,GDN 3144,90W 0,96 767,03N 3160.90W 0, 8 3 7"75.42 N 3176,8SW 1 . 73 '783.8tlN 3192.83W 0.86 7775.4 6474,34- "/R00.4 6491 · S3 782 S. 0 6508,51 7050.3 GSZG, ~Z)S 7875.4 GS4 3.48 310,'5,8 46,56 297.36 ~123.9 46.53 Z97.39 3141.6 46, 18 Z97.83 3t59.7 46.03 29'7.94 3177.? 45.99 298.14 792.24N 3208.84W 2.80 884).58N 3224.96W 0.16 808.83N 3240.73W 1.92 81'7.~::;N 3256,84W 0.67 8ZS.8SN 3Z72.78W 0.59 7925.1 6578. IB "/9F~)..~ 6595.90 7975, Z GG 1 3.60 3195.4 45.91 ZR8.11 3713.1 45,22 298,47 32 J0.8 44,82 Z98.G1 3Z48.4 45.05 298.64 8J4.ZSN 5288.50W 0.34 842.68N 3304.16W 7.96 BSI.IGN 5319,76W 1.64 859.62N 3335.ZGW 0.92 SCIENTIFIC DRILI. ING p~ge 7 I'nrun Survey IJNOCBL Corporation G-29 RD Da%e : 08-JUL-BZ Moctsured Ver tical Ver't. Dept. h Dep'th Sect ion 8000.0 G831,03 3795.9 8025. I C~18.55 ~Z8~.8 ~0,2 BGGG. 09 3~01.7 8075.2 6683.67 3319.4 8100.1 6701.30 3338.9 Inc Azimuth Coordinates Oeg Oeg La~i%ude Deportur. e 45.83 298.27 888.02N 3350.78W 45.86 298.04 876.SIN J366.61W 45.44 298.26 884.97N 3382.44W 45.24 298.33 893.40N 3J98.10W 44.58 298.71 901.80N 3413.54W D-leg 2.S'? 1.13 1.79 0.83 2.86 81ZB. I 8719.07 5354.4- 8150.1 6736.73 3372.0 8175.1 8754. Z2 3389.8 8200.3 8771 . 69 3407.9 8X Z 5.0 6788.89 342 S. S 44.04 298.93 45.24 298.68 443.~ 298.39 46.Z3 298.87 45.45 384).12 910.28N 2MZS.BSW 918.80N 3444.45W 9Z7.33N 3480.1SW 938.04N 347~.09W 944.7GN 3491 ~ SZ W 1.Zl 1.75 3.15 1 4.81 8250. I 682~;.83 34,43.3 8275. I 6824.48 34.60.8 83~K4.2 684 Z. 39 3478.4 8325.2 GO~.~ 3496.1 835(~. 1 6877.39 3513.9 44.82 302.01 44..24 303.'72 44.78 304.41 45. GS 304..:~0 45.78 3~'I. 4 G 8375.Z GR94.92 3531 8400.1 8912.35 3549 8425.3 6930.03 35G7 8450.0 8947.49 3585 8¢75.3 8965.47 3602 · 9 4S.GS 3(~-l.18 · 7 45.48 304.16 · G 45.39 304..t2 .1 44.88 304.81 .9 44.72 3~)4.72 I~5.48N J5-80.19W 0.91 1013.47N 3594.90W 0.60 t0Z3.57N 5609.75U 0.58 1033.48N 3824.14W 3.20 1~43.83N JGJ8.7GW 0.29 85(~.2 8983.12 3GZO.S OSZS.Z ?-4N~X~.'73 3838.2 8SSO.Z 7818.22 3GSG. 1 8575.4 7035.77 J874.2 8808.1 7~2.93 3691.9 45.04 304.89 45.38 384.82 45.80 304.6F; 45.96 304.87 4G.03 305.24 1053.83N 3853, 20W 1.29 1083.72N 3687.79W I , 38 1073.87N 3807.49W 1 · 88 1084. '1GN i:~697.3'ZW 0.84 1094.34N 3?11,93W 1.88 8625.4 7q~'70.45 3710.2 8850. Z 708'7.50 3728.2 88?5.4 7184. GS 3748. G 8788.3 7121.48 3785.0 8725.1 71 38.Z1 3783.3 4G.~0 305.39 46.81 305.3'7 47.43 SOS.GG 47.49 305.74 47.70 Jk,~S.21 1 t0,1..8DN JTZG. 8ZW 1.1S I 11S. 32 N 3741 · 584.J Z. 08 11ZG. 04N 3758. S3W Z. GO 1138.75N 3771.43W 0.34 1147.51N b"70G. 2SU 1.83 8750.Z 7155.08 3801.8 8775.0 7171 . 62 58Z0.3 88~.0 7188.08 3839.1 8~425.S 7204.75 3058.4 8850.2 7221.01 3878,9 47.83 308.38 48.49 308.28 49.19 306.25 49.13 308.19 48.54 306.37 llSO.S1N 3801.Z3W 0. G8 ttG'9.4SN 3OlG. IZW 2.68 1180.58N 3831.30W 2.80 I191.98N 384G.88W 0. Z9 1202.98N 3881.85W 2.45 88'~S. 1 723'7.58 38Y5.5 8988.2 7754.39 3914.1 8.g.2 S. 0 7.271.01 3932 .S 8950.Z 7287.93 3951.Z 48.03 J86.77 47.87 308.84 47.97 3~;. 88 47.71 307.17 1Z14.0SN 38'78.78W 2.57 IZZS.Z2N 3891.70W 0.67 IZ3G.ZGN ~908.43W 0.41 1747.50N 39Z1.35W 1.38 SCIENTIFIC DRIL).ING Inrun UNOCAL Cor'pora~ion G-29 RD [.lea~ured Vortical Ver 4. Inc Dep%l", Deptl'~ Sect ioTI Deg 8975.4 7304.99 3969.7 47.04 9~.3 73ZZ.OZ 3987,8 46.69 9~25.~ 7339.14 4~5.9 46.42 9~. 3 7356.~ ~24.~ 46.05 9875.8 7373.65 4~1.7 45.98 910~).0 7J91.0I 4059.7 9125,4 7408.60 4078.0 9150.0 74ZS.74 4095.6 9175.Z 744 3.38 4113.5 9200.0 7460.59 4131.3 Survoy 92ZS. 1 7477.90 4149.S 9ZS0.3 7495.22 4167.7 9275.0 751Z.18 4185.7 930~.S 7529.71 4204.1 9325.1 ?S4G.6Z 4221.9 paoe O 9550. Z '7563.83 4'Z40.2 9375.4 7581.09 4758.5 94(~0.2 7598.~9 4276, S 945~.6 763Z,47 4~13.2 Date : 08-JUL-92 9475,3 7649.ZZ 4331.3 'J~. 1 7F;GG.00 4349.5 9575.3 7682,99 43G8.0 9550.1 7699,69 4386.3 9575,3 7?IG,GG 4404.8 ¢~z imu th Coo,"d i naxos De[~ ' ~.a,i tud~ Dcpar'ture 307.07 1258.60N 3936.13W 307.04 1ZG9. G4N 5950. G3W 307. ~ 1 ~80. S3N 3965.07W 307.03 1291.44N ~79. S4W 307.16 1302. I~N ~99~.71W 96~. 3 7733.40 442 3.3 9625. I 7749.04 4441.8 9 GSO. 1 7"766.3 t 4460. S 9675,4 7'~83.03 4479.4 970~. 4 7799.8~ 4498.0 46.07 307.23 1313.04N ,¢008.05W 46.30 307,11 13Z4.11N 4022.65W 45.37 308.07 1334.87N 403G.GJW ~S.78 307.97 1345.96N 4050.81W 46.31 307.70 t3SG.91N 4064.91U 9725.3 7816.23 4516.S 9750.0 7832.67 4534.9 9775.1 7849.24 4553.G 906~0, I 7865,72; 457Z, 3 9825.0 7882.19 4590.9 4G.S? 307.54 13GO.O1N 4079.31W 46,64 J07.SZ 1379.16N 4093.83W 4G.G~ 307.96 1390.15N 4108.03W 4G.C~8 308.11 I~OI.SGN 412Z.G1W 46.64 308.11 1412.58N 4136,67W 4G. 76 46.02 46.63 47.02 -47.27 47.33 47. 47.71 47.6Z 47.70 'J0,8.Z9 308,44 508.60 308.G3 308.82 308.66 309.t9 309.01 3,09.39 309.26 308.99 308,79 308,98 309,00 309.44 309.53 ~09.Z4 30~.Zg 309.GS 309.80 48.Z3 48.75 48.82 48.46 48.32 48.06 48.47 48.91 48. S3 48.75 9050.1 7898.72 4609.7 48.87 ~09.74 9875.1 7915.17 4G2~.4 48.82 309.97 9900.0 7951.57 4847.1 48.78 510.14 9925.1 7948.15 4GGS.O 48.57 310.33 14Z3.88N 4151.02W 1435.28N 4165.43W 1446.52N 4179.SSW 1457.99N 4193.91W 14G9,SSN 4208.3ZW 1480.91N 4222.48W 1492.38N 4236.69W 1S~4.1ZN 4251.14W ISIS.TIN 4~65.34W 1SZT.S1N 4Z?9.?SW 1539.25N 4294. IGW 1550.89 N 4 308. G 1 W t562. '7ON 4323. ZSW 1574. G4N 4330.01W 1S8G. 4GN 4352.49W 1598.ZGN 43GG.01W 1609.9GN 4381.06W 1621,88N 4395.GGW 1633.8ZN 4.410.1'7W 1G4S.7GN 4474.SSW 1GST. 8SN 4439,07W 1GGB. ¢j 1N 44 53,5ZW t G.81 · 9GN 4.467, 8GW 1694.14N 4482.7SW D-lsg / Z. 67 I .41 1.0~ l 0.47 0.41 0,97 4.70 1. GL 2.28 0.96 0.48 1.30 0.67 0.57 0.71 0.50 0.90 I .55 1.13 0. S4 1. '75 0.97 1.19 0. S0 Z.Z7 Z.18 0.64 I .4Z 1.43 1.08 1.88 1.75 7.04~ 0.99 0,S1 0.72 0.54 1.01 SCIENTIFIC DRIt. L]NG I Ai"un UNOCRL Corpora-~ ion G-29 RD Hma~ured Verkical Verk. Dep~l ~ Depth Sect ~ on Inc Oeg Survey Rz i,,u~ h 9950.1 7984.66 48O4.4 48.73 310.40 :t975.3 7981.21 4.703.3 49.19 310.31 1~.1 7997.37 4722.0 49.47 310.23 1~25. I ~l~13.61 4740.9 49.50 310.~6 l~S~.~ 8029.81 4759.7 49.35 31~. 33 ~Z~75.2 8046. ZG 4778,7 101~,.0 8087.05 4797.7 t~IZS.Z 8~77. SI 4817.5 50.~ 8092.47 4837.3 1~175.1 8107.38 4057.4 49.13 SI .78 S2.Sl S3.32 $3.89 10200.0 8121.91 4877.8 S4.59 10225.1 8136.35 4898.1 5S.ZO 10250.1 8150.45 4918.8 SG. 10 102'/S.1 8184.23 49:~9.6 ST.O~ 103(//g. 1 817'~. ?8 4 9 ~0. G 57.38 10325.1 8191.07 4981.8 10350. Z 8204.34 5(~3,0 1 ~375.2 8Z 17.67 S~Z4..Z 104~.1 82 30.99 5045.2 lg~I.Z-S.O 8244.34 SOGB. 1 S8, 38 57.78 S7. ?9 S7. S? S7,85 10450.1 8257.70 S087.4 SU.03 10475,2 8270.93 SI~Z~8.G 58.34 lOUO&.$ 8283.89 S129.9 S8.93 tOSZS. 1 8296.71 StSI.3 59,30 10550,1 83~J.4Z 5172.7 59.50 I~S'?S.Z 8322,26 S194.Z S8,97 106¢/~.I 8335.10 S215.5 S8.98 I~ZS.Z 8347.98 5237.0 59.26 10G50.2 8380.72 S258.4 59.49 1057S.3 8~73.4G 5280.0 59.47 107~K~, 0 8380.12 S301. t S8.89 t0725.1 8:$99.1'7 ,5322,5 S8.47 lO?~a.3 8412.50 534 3.8 57.63 107"7S.4 R425.94 S3GS.~ ST.GS 1080~.1 8439,13 5385.8 57.79 10025.1 8452.42 S408.9 108S0.0 84.85.70 5420.0 10875.2 8479.32 5449.1 10900.0 8492.83 S4. G9.9 S7.97 S7.55 SG. 87 310.67 389.05 307.40 306.67 3 (~'J,. 72 JO4.60 307.. 92 301. 301. O1 3(¥g. 79 384~. 55 3(~.54 3~23~.42 299.89 298.72 298.89 299.58 299.82 299.'71 299.45 299.4.4 299.59 299,80 300,12 299.91 299.09 299.94 ~99.97 299.92 page. 9 Da't, e : 08- JUL - 92 Coordina~o~ D-leg Lai, i~ude Ocpartur¢ / 1708.29N 4498.55W 0.67 1718.80N 4511.03W 1.84 1730.76N 4525.38W 1.16 1743.01N 4539.91W 0.53 17SG.Z?N 4SE,4,3BW 1.07 1'767,6ZN 4568.87W 1.34 1'779,87N 4583.55W 11.81 l'7.clZ. Z8N 4599.10W 4. I 1 1R¢~4.40N 4G14.74W 1818.56N 48:~0.87W 3.26 1828.50N 4647.18W 4.18 1840.32N 4663.97W 4.39 1851.79N 4681.12W 8.61 1882.88N 4698,79W 6,44 1873.75N 4716.7'?W 1.84 1884.83N 4.'734.94W 4.07 1895.51N 4753.25W 2.44 19~Z~S.28N 4771.48W 0.31 1916.g7N 47~9.57W 1.09 1927.88N 480'?.88W 0.59 1938.50N 487~.95W 1.S'? 1949.31N 4844.33W 1.30 1959.99N 4887.7ZW 2.99 1970.50N d881.43W 4.40 198~.84N 490~.3ZW 0.49 1991.34N 4919.I$~ 3.71 Z001.9IN 493'7.29W 0.83 Z01Z.60N 4958.39W 1.ZS 2023.27N 4975.10W 1.28 Z033.QSN 4.993.9ZW 0.08 2844.3eN 5012.38W Z,41 Z054.93N 5831.0lY 1.82 Z085. GON 5049,54 W 3. SO 2~76. Z4N R067.88W 0. I 6 2086, GON 5085.9GW O. 81 ZO97.23N Sl SM.. 3ZW 0.73 2107.'/3N 51ZZ.S?W I.ED Z118.3ZN 5140.9SW t .95 Z I 2 8.70N S 158. BGW O. 79 SCIENTIFYC DRII.I, ING UNOCRL Corporabion G-29 RI) ,Measured Vertical Ver~. Del..~t, h DcF,~h Sect ion I ~]C Survey Rzimu~h Deg 10025.? 8506.64 5420.8 56.72 799.94 10950.3 8520.78 5511,8 56.89 299.94 i09'/5.1 8634.01 5532.5 SB.40 300.04 118~.0 0547.89 5553.1 SS.89 300.23 11025.1 8562.05 5573.8 S5,42 3844.45 11050.2 QSTG,3S 5594.4 55.08 $00. G7 11075,2 8590.68 5G14.9 SS.O1 300.78 II100.1 8605.03 S635,2 S4,60 $01.10 lllZS.O 8619.53 SGSS.4 S4.1G 301.42 lllSO. Z 8634.20 SG?S,B S4.GS 301.53 11175,2 8648.54 5698.4 S5.32 301.54 11200.1 8662.50 S716.9 S$,03 301.59 11725.1 8676,45 5737.7 SG.S? 301.83 11250.0 8690.14 S?S8.S S6,72 301.94 11275.0 8?03.74 S??B.4 S7.41 302.01 t3041.2 8717.18 S8~.7 325.1 8730.24 S021.9 1350.1 8'743. I4 S843.3 375.1 8755,87 5864.8 400. j 8768. SB 5886.6 S8.~ S8.67 59.19 S9.SB Sfl.84 114ZS.0 8'780.9.t 5900.0 t1450.0 8793.3t $929.7 11475.0 8805.81 sgsI.S 11F~O,Z 8818.~0 597.3.4 11525.3 8830.43 5995.2 60.19 ;50.41 80.67 60.43 BO. Zl ttSSO. 1 0842.66 G01B.B 11575.2 88E-~..88 G~38.7 !1600,1 8867.01 B~60,4 IIG2S.O 8879.14 608~.2 I1GSO. 1 8891.24 6104.2 60. 'TFj 61.02 60.68 61.02 61.29 116'75,4 8903.36 G126,4 I178~).1 891-S.2! B148.0 11725,0 8927.47 6169.7 1t750.0 89J9.95 8191.4 11775.0 8952.25 8213.1 61. 61.06 59.93 60.18 60. BB '.302.06 307.04 302.27 307.2 G 302.31 302.36 30Z.SB 302.68 302.92 383.17 303.13 303.06 ~03.00 303.09 303.20 303.0S 303.26 303, S? 303.77 302). 72 1 t 8(7X~. 4 09E14.,S 1 6;235.3 ilO. 83 303. RG 11825.1 8878.77 F;2SG,8 60.10 304.15 11050,0 8989.tG 6278.4 80,15 3814,1'! 11875.0 9001,57 8300. I ~0.37. 304.0~i par. jc 10 Date : OB-JUL-g2 Coor~tinaios D- 1 Lat itudm F)el.,ar. ture / 1 ~.~+' t. 2139.22N 5177.24W 0.B0 2149.71N 5105.44W 0.68 Z1GO.O~N S213.38W 2.~ 2170.44N SZ31,7GW 2.1-4 218~.91N SZ49.15W 2.01 Z191 . 39N SZGG. 91W I .53 ZZO1 .BGN SZ84.SZW 0.45 ZZ1Z. 33N S)]Ol .97W I . 95 2272.83N S319.28W Z.OS 2233.53N S336,75W 1.98 2244.74N S354.2~ Z.G8 ZZS5.~N S571.72W 2.BG ?265.B3N S389.42W 2.30 2276.9ZN S407.08W 0.71 2288.03N S424.88W 2.77 2299.33N 54.42.94W 2.66 Z310. SON 5460.91W 2.37 2321.98N S479.04U 2.22 2333.47N 549'1.24W l.GO 2345,09N SS15.63W 1.01 2356.53N S533.71W 1.43 ZJG8.19N 5552.03W 1.17 2379.93N S570.36W 1.10 2391.82N SSB8,81W l.ZG 7403.'?1N SGO"?.OBW 1.23 Z41S.StN SGZS. 1SW 1.98 2427.48N SB43.S2W 1,30 2439.35N SGGI.?S~ 1.38 2451.19N 56'/9,98W 1.40 24G3.Z1N SBYB.JBW 1.14 2475.3SN S'71G. 99W 1. IS 248'7. ZON S755.1.)W Z. 1Z 2499.13N 5763.22W 4.67 2511.14N 5771 .ZSW 1.ZZ ZS2 3. Z4N 5'789 . 35kI Z. BS .2535. STN S807.79W 0. S3 2547.80N S825.G1W 2.82 2559.73N S84'5.48W 0.14 ZS'il .90N SBG1.4SW 0.78 $CYENlIFIC DRILLING IIlt'" U ri UNOCAL Corpor'a'~ ion 6-2'9 RD Measured V~r ~ioal Ver~. Oep%h D~ptl', Sec% ior, Survey Azimuth 1900,1 9014,03 R321,9 60, 19 304,17 19ZS. t 902G,92 62M3,C S9.,OG Z~4,29 195~.1 9~39.~5 6365.2 S~.98 ~.28 1975.~ 9~91.72 6387.8 59.66 3~.3~ lZS~.S 98~.43 ~88.7 59.72 3~4.23 12025.2 9078.9Z ~JO. I SW.SJ 504.43 12090.2 9089.57 6451.6 S9.70 304.34 12075.0 9102.08 8473.0 59.70 304.33 121~4).Z 9114.83 8494.8 59.S0 304.38 12129.4 9127.8~Y) SSlJS. S S9.62 12150.2 9140.11 653'7.9 59.78 1Zt?S.O 9152.64 GS59.3 59.54 12200.1 9165.42 GE,80.9 59.22 122ZS. I 9178.21 6602.4 S9.ZS 12250.2 9190.90 GGZS.0 59.93 2279.1 9203.52 GG4S.S 60.05 3(~. 2 97 IG. 15 GGP,7.2 59.57 t2:~ZS.0 9228.89 GISf3O.G S9.87 358.1 9241.32 671~.3 59.89 375.3 9253.92 8'7~2.1 6~. t 1 124~(~. 1 926fi.30 6753.8 S9.99 124ZS. I 9278.89 8775.2 S9.76 12490.3 9291.SG 6798.9 S0.~4 12479,2 93~A4,16 68t8,4 S9,59 1258'~.2 9316.86 6839.9 59.35 1ZS25.1 9329.59 6861.3 S9.38 12950.2' 9342.28 6882.9 SQ. 63 IZ575.1 9354.8'7 6904.4 $9,63 126~.3 9367.65 6926.1 59.41 IZtSZS. 1 9380.31 t3947.4 59.20 12690.3 9393.12 8969.1 S9.'70 12675.~ 94.09.89 6990.7 G0.18 12700.0 9417.93 7012.1 60.19 1Z725.2 90J0.41 70~1.0 12750.2 9442.99 7055.8 80.74 304.35 304.4~g 304.81 304.8Z 304.72 504.81 304.96 3~.10 305.23 ~S.41 pagm 11 Da%e : 08-JUL-g? Coordinates D-leg l.mi. i~ude Dcpartur. e / 1~1'% ZS84.1ZN S879.49W 0.65 2996.29N S897.40W 1.59 Z68R.47N S919.28W 0.49 ZSZO.TSN S933.28W 1.27 7633.(~ SO51.ZGW 0.34 ZGSS.O1N 5988.85~ 1.04 2657.19N S988.GSW 0.75 2669.27N ~004.35W 0.~ ?G81.S3N ~022.TaW 0.80 269~.80N 6040.21W 0.48 7705.88N 605'?.89W O.GG 2717.98N B079.SSU 1.07 2730.ZZN 6093.34W 1.35 2742.48N 6111."JS~Y 0.73 2754.78N 612R.74W 1.17 2787.05N 6148.47W 2.11 2779.4GN 6164.22W 1.98 ZTBl.74N 6181.74W 0.63 2804.23N 8199.47W 0.98 2816.84N 6217.ZTW 1.07 30E,. 42 2829.3¢~ 8234 .TBW 0.49 309. S7 2841 .SSN F;2~2 . JBU 1.05 3~.71 2854 .S3N 6270.07W 0.88 305. 'l~ 28~7.0TN 8~87. SZW O. Z 1 305.76 2879. G4N 6305. ~W 0. B 8 509. U7 2892.18N B.-SZ Z . 37W O. 40 305.95 7904.8GN P_,339 . 89W 1 . 83 309.09 2917.47N EJAST. ZSW 0.21 306.17 2930. Z4N 63'/4.8SW 1.79 308.20 .2942 . ~3N Gig?. ~W O. 89 306.17 2995. G4N 6409 . 58W. 1.99 388.05 ZRG8.40N 84Z7. OGW 1.96 30~.23 2981.04N 6444.3GW O,G4 iL'~G. 33 2993.99N G4G2.O1W 1.01 30G. 38 3~E';. 90N 8479. SSW I . 24 1 ~77S. 1 9454.8¢ 70'77. S B~. 82. ..'lOG. 4.'? 128~).2 Et4G'?.OZ 7099.4 Gl. 10 3~,,.G4 12829.2 90"79,08 7121.3 Gl.ZZ 306.84 17850.0 9491.01 7143.0 61,30 306.74 3019.80N 8497.00W 0.50 3032.87N 85 ! 4. GTW 1. ZG 3049.9 3N GSJ2. ZSW 0.48 3098.9 3N E;549.6DW 0.4 8 SCIENTIFIC DR1L[ ING I nrun Survey UNOCAL Co-rp~'rat ion G-29 RO M.oasured Vertical Ver~. Depth Depth Sect ion Inc Rzimu%h DeW 12875.0 S503.80 7184.B 1Zg08. Z El515.05 7t07.8 lZB?.S.l ElSZG.87 '?ZOO.9 12OF~.Z 98:58.78 7Z'31.0 81.38 30G.78 $1.55 :50fi.$8 G1.72 308.75 81.77 :508.85 61.90 3~G.87 3~.A~8.4 D56Z. 38 '7275. 38Z5. ! El573.El6 72El7. :50'/S. 1 95B7.14 7:541. 00. I EIG~8.i5~ '?383. 82.10 307.03 G?-. OEl :507.10 8Z.46 ~07.Z4 62.47 307.Z8 t31gS.~ gSZCa. 05 7385.5 13158.1 .98:51.52 7487.7 13175.0 El~42.8G 7428. El 152~.~.0 9G54.1Et 748Z. 1 13225.1 8GG5.47 7474.5 G2.77:587.51 S2.8"? 387. GO SZ.gS 3Ca7.51 B3.13 J87.Sr~ 1 L4Z 50. I Et 67G. S~A 74918.8 1:5275.? 988'?.74 75t9.3 13:525.0 B'/8B.G5 75G3.B t 335~. 1 ~'/gO.8~ 758G. 4 iSA. ISZ .307.45 83.1SO 307.51 G3.87 307.72 ~4.18 307.72 84.1 I 507.80 3:575.1 91731.57 7688..g 34~. 1 9742.38 '7831.3 3475.Z ~753.Z9 7E153.~ .~438,B $759.Z3 7ISGS.8 84.08 308.13 G4.52 ~08.01 8:5.84 387.93 G3.61 307.90 page 1Z Oa%e : 08-JUL-g2 Coordinates D-leg Ls%ilude Oepsrture /I~{'i 307Z.OSN GGGT.ZSW 8.24 $gtSS.gON GS8S.~W 0,79 3098.38N EGOZ.SGW 8.7:5 3111.G3N GSZO. 2$~ 0.43 3124.80N BS3'?.83W 0.52 3138-ZJN G$SS.G8W 0.97 3151.38N $G'?:5.18U 0.25 3164.75N 6690.7~U 1.56 3178.17N 6708.37W 0.14 31~1.84N IS7ZG.O1W 1.06 3205.1 ON B'74 3. SBU 0.40 3ZI8.71N 6761 .Z8W 8.51 :52 3~. 2 3N G'778 . 8GW 0.4 G ~g4s. 79N 67~6. S3W O. 72 3ZSB.4SN 6814.3ZW 1.4& 3Z'73.87N GOJZ.OSU O. ISS :SZ8G.7GN B849.93W 0.33 33~0.34N GHG7.SSW 1.~0 3314.0BN 6805.33W 1.24 3327.BZN 6903.18W 0.48 Hole I. oca%Jon: Meo~ured O~pih = 1:5438.6 Hori~. Displ. = "7741.:515 Closure Oir. : Z95.B63 Scientific Drilling UNOCAL Corp G-29 RD, Grayling Platform Finder gyro survey of 8 July 1992 MD Incl Azimuth 0.00 0.00 0.00 100.00 0.46 181.69 201.00 0.42 159.70 299.30 0o10 212.89 499.90 2.05 16.87 599.90 1.88 19.33 700.00 1.83 21.99 800.20 1.61 28.42 900.10 1.55 27.25 1000.20 1.36 29.90 1100.10 1.01 35.83 1200.00 0.86 43.26 1300.10 0.80 39.85 1400.00 0.74 45.39 1500.00 0.77 48.03 1600.30 0.70 48.41 1700.10 0.69 59.12 1799.90 0.62 62.57 1899.90 0.57 75.63 1999.90 0.61 74.87 2099.80 0.20 82.57 2200.00 0.87 254.77 2299.80 3.01 266.18 2399.80 5.12 269.05 2499.80 6.55 273.37 2699.80 11.67 273.57 2800.10 14.46 272.80 2825.20 15.22 272.76 2850.30 15.78 272.80 2875.10 16.31 272.89 2900.00 16.99 272.77 2925.00 17.62 272.78 2950.10 18.25 272.66 2975.20 18.88 272.50 3000.10 19.75 272.47 3025.10 20.43 272.86 3050.10 21.07 272.99 3075.20 21.75 273.16 3100.10 22.43 273.30 3125.00 23.06 273.66 3150.20 24.00 274.13 3175.20 24.56 274.30 3200.10 25.23 274.37 3225.20 25.70 274.07 3250.40 26.33 274.14 3275.20 26.98 274.36 3300.20 27.61 274.19 3325.10 28.22 274.16 3350.00 28.88 274.24 3375.00 29.51 274.11 3400.10 30.09 274.12 3425.20 30.70 274.13 ORIGINAL RECEIVED JUL 1 4 1992 Alaska 0il & Gas Cons. Commission Anchorage 3450.10 3475.20 3500.20 3525.10 3550.00 3575.00 3600.00 3625.30 3650.20 3675.30 3700.40 3725.10 3750.00 3775.10 3800.20 3825.00 3850.10 3875.10 3900.20 3925.30 3950.10 3975.10 4000.20 4025.10 4050.20 4075.00 4100.20 4125.10 4150.20 4175.10 4200.20 4225.10 4250.30 4275.40 4300.20 4325.30 4350.10 4375.00 4400.20 4425.10 4450.20 4475.40 4500.00 4525.10 4550.30 4575.10 4600.10 4625.30 4650.00 4675.30 4700.20 4725.10 4750.10 4775.20 4800.10 4825.00 4850.10 4875.20 4900.20 4925.30 31.34 31.84 32.63 33.19 33.74 34.30 34.95 35.67 36.29 36.77 37.39 38.09 38.82 39.71 40.58 41.36 42.31 43.12 43.92 44.81 45.40 46.19 47.11 47.38 47.57 47.43 47.40 47.46 47.63 47.81 47.86 47.41 47.78 47.72 47.74 47.88 47.88 47.77 47.52 47.03 47.03 47.18 47.50 47.52 47.33 47.21 47.36 47.48 47.37 47.12 46.60 45.48 44.13 43.12 42.87 42.85 42.89 42.92 42.83 42.74 274.27 274.32 274.28 274.26 274.46 274.47 274.36 274.32 274.21 273.97 273.86 273.65 273.39 273.28 273.02 272.83 272.65 272.49 272.39 272.26 272.30 272.38 272.32 272.30 272.25 272.40 272.55 272.66 272.68 272.76 272.77 272.88 273.05 273.08 273.13 273.18 273.28 273.38 273.50 273.50 273.44 273.24 273.00 273.10 273.28 273.46 273.58 273.64 273.79 274.39 275.55 277.27 279.11 280.67 281.87 283.05 283.76 284.25 284.41 284.27 4950.30 4975.20 5000.60 5025.20 5050.20 5075.20 5100.30 5125.30 5150.10 5175.10 5200.20 5225.10 5250.20 5275.60 5300.10 5325.20 5350.40 5375.10 5400.20 5425.10 5450.30 5475.20 5500.10 5525.10 5550.20 5575.10 5600.20 5625.30 5650.40 5675.30 5700.50 5725.40 5750.30 5775.10 5800.50 5825.10 5850.20 5875.00 5900.20 5925.10 5950.40 5975.40 6000.40 6025.00 6050.10 6075.20 6100.30 6125.10 6150.30 6175.10 6200.10 6225.20 6250.00 6275.00 6300.10 6325.20 6350.00 6375.10 6400.20 6425.10 42.61 42.55 42.52 42.56 42.53 42.53 42.54 42.31 42.17 42.12 41.83 41.88 42.01 42.00 41.95 42.10 42.50 42.86 43.02 43.51 43.41 43.42 43.70 43.98 44.20 44.34 44.42 44.41 44.55 44.72 44.80 45.07 45.33 45.52 45.78 46.01 46.31 46.38 46.50 46.57 46.63 46.93 47.18 47.47 47.54 47.58 47.36 47.29 47.05 46.75 46.37 46.03 45.75 45.29 45.20 45.11 44.93 44.83 44.96 44.82 284.36 284.37 284.45 284.57 284.63 284.69 284.66 284.73 285.00 285.35 285.35 285.40 285.45 285.67 285.75 285.89 286.00 286.24 286.62 286.85 286.73 286.31 285.95 285.97 286.14 286.22 286.54 286.52 286.62 286.52 286.42 285.99 285.79 285.95 286.27 286.38 286.70 286.68 286.89 286.86 287.08 287.27 287.52 287.56 287.69 287.67 287.50 287.44 287.38 287.55 287.59 287.90 287.85 287.40 287.54 287.74 287.83 287.54 287.46 287.30 6450.20 6475.10 6500.40 6525.20 6550.20 6575.30 6600.40 6625.30 6650.50 6675.20 6700.50 6725.10 6750.00 6775.20 6800.10 6825.10 6850.20 6875.20 6900.00 6925.40 6950.20 6975.00 7000.10 7025.30 7050.5O 7075.20 7100.00 7125.20 7150.10 7175.20 7200.10 7225.20 7250.30 7275.00 7300.20 7325.10 7350.00 7375.20 7400.20 7425.20 7450.10 7475.00 7500.20 7525.00 7550.20 7575.20 7600.20 7625.20 7650.10 7675.10 7700.10 7725.20 7750.40 7775.40 7800.40 7825.00 7850.30 7875.40 7900.20 7925.10 44.41 44.17 44.05 44.41 44.30 43.26 43.26 43.67 44.22 44.04 43.41 43.01 43.58 44.06 44.21 44.85 45.00 45.86 46.18 46.58 47.20 47.00 46.45 45.12 44.61 44.12 44.05 44.50 45.07 44.83 44.52 45.00 45.21 45.67 46.10 45.98 45.56 45.53 45.73 45.98 46.43 46.32 46.34 46.16 46.16 46.23 46.30 46.37 46.05 46.29 46.09 45.74 45.94 46.56 46.53 46.18 46.03 45.99 45.91 45.22 287.03 287.13 287.08 287.33 287.71 288.13 288.26 288.44 288.24 288.49 288.74 289.01 288.90 288.97 288.96 289.29 288.77 288.78 289.16 289.63 289.50 289.82 291.07 292.84 294.59 295.41 295.83 295.75 295.23 295.39 296.14 296.23 295.96 296.27 295.79 296.15 296.56 296.67 296.96 297.11 297.14 297.22 297.14 297.21 297.39 297.49 297.44 297.45 297.49 297.50 297.57 297.93 297.81 297.36 297.39 297.83 297.94 298.14 298.11 298.47 7950.20 7975.20 8000.00 8025.10 8050.20 8075.20 8100.10 8125.10 8150.10 8175.10 8200.30 8225.00 8250.10 8275.10 8300.20 8325.20 8350.10 8375.20 8400.10 8425.30 8450.00 8475.30 8500.20 8525.20 8550.20 8575.40 8600.10 8625.40 8650.20 8675.40 8700.30 8725.10 8750.20 8775.00 8800.00 8825.50 8850.20 8875.10 8900.20 8925.00 8950.20 8975.40 9000.30 9025.20 9050.30 9075.00 9100.00 9125.40 9150.00 9175.20 9200.00 9225.10 9250.30 9275.00 9300.50 9325.10 9350.20 9375.40 9400.20 9425.40 44.82 45.05 45.63 45.86 45.44 45.24 44.58 44.84 45.24 46.00 46.23 45.45 44.62 44.24 44.76 45.65 45.76 45.65 45.48 45.39 44.68 44.72 45.04 45.38 45.80 45.96 46.03 46.30 46.81 47.43 47.49 47.70 47.83 48.49 49.19 49.13 48.54 48.03 47.87 47.97 47.71 47.04 46.69 46.42 46.05 45.98 46.07 46.30 45.37 45.78 46.31 46.52 46.64 46.63 46.50 46.64 46.76 46.82 46.63 47.02 298.61 298.64 298.27 298.04 298.26 298.33 298.71 298.93 298.68 298.39 298.87 300.12 302.01 303.72 304.41 304.30 304.46 304.18 304.16 304.32 304.81 304.72 304.69 304.62 304.66 304.67 305.24 305.39 305.37 305.66 305.74 306.21 306.36 306.26 306.25 306.19 306.37 306.77 306.84 306.86 307.17 307.07 307.04 307.00 307.03 307.16 307.23 307.11 308.07 307.97 307.70 307.54 307.52 307.96 308.11 308.11 308.29 308.44 308.60 308.63 9450.60 9475.30 9500.10 9525.30 9550.10 9575.30 9600.30 9625.10 9650.10 9675.40 9700.40 9725.30 9750.00 9775.10 9800.10 9825.00 9850.10 9875.10 9900.00 9925.10 9950.10 9975.30 10000.10 10025.10 10050.00 10075.20 10100.00 10125.20 10150.00 10175.10 10200.00 10225.10 10250.10 10275.10 10300.10 10325.10 10350.20 10375.20 10400.10 10425.00 10450.10 10475.20 10500.10 10525.10 10550.10 10575.20 10600.10 10625.20 10650.20 10675.30 10700.00 10725.10 10750.30 10775.40 10800.10 10825.10 10850.00 10875.20 10900.00 10925.20 47.27 47.33 47.52 47.71 47.62 47.70 48.23 48.75 48.82 48.46 48.32 48.06 48.47 48.91 48.53 48.75 48.87 48.82 48.78 48.57 48.73 49.19 49.47 49.50 49.35 49.13 51.78 52.51 53.32 53.89 54.59 55.20 56.10 57.00 57.38 58.38 57.78 57.79 57.52 57.65 58.03 58.34 58.93 59.38 59.50 58.97 58.96 59.26 59.49 59.47 58.89 58.47 57.63 57.65 57.79 57.97 57.55 57.06 56.87 56.72 308.82 308.66 309.19 309.01 309.39 309.26 308.99 308.79 308.98 309.00 309.44 309.53 309.24 309.22 309.65 309.80 309.74 309.97 310.14 310.33 310.40 310.31 310.23 310.06 310.33 310.67 309.05 308.12 307.40 306.67 305.72 304.60 302.92 301.32 301.01 300.79 300.64 300.55 300.58 300.66 300.54 300.42 299.89 298.72 298.69 299.58 299.82 299.71 299.45 299.44 299.59 299.80 300.12 300.08 299.91 299.89 299.94 299.97 299.92 299.94 10950.30 10975.10 11000.00 11025.10 11050.20 11075.20 11100.10 11125.00 11150.20 11175.20 11200.10 11225.10 11250.00 11275.00 11300.20 11325.10 11350.10 11375.10 11400.30 11425.00 11450.00 11475.00 11500.20 11525.30 11550.10 11575.20 11600.10 11625.00 11650.10 11675.40 11700.10 11725.00 11750.00 11775.00 11800.40 11825.10 11850.00 11875.00 11900.10 11925.10 11950.10 11975.30 12000.50 12025.20 12050.20 12075.00 12100.20 12125.40 12150.20 12175.00 12200.10 12225.10 12250.20 12275.10 12300.20 12325.00 12350.10 12375.30 12400.10 12425.10 56.89 56.40 55.89 55.42 55.08 55.01 54.60 54.16 54.65 55.32 56.03 56.57 56.72 57.41 58.08 58.67 59.19 59.59 59.84 60.19 60.41 60.67 60.43 60.21 60.70 61.02 60.68 61.02 61.29 61.55 61.06 59.93 60.18 60.89 60.83 60.18 60.15 60.32 60.19 59.86 59.98 59.66 59.72 59.53 59.70 59.70 59.50 59.62 59.78 59.54 59.22 59.25 59.53 60.05 59.57 59.67 59.89 60.11 59.99 59.76 299.94 300.04 300.23 300.45 300.67 300.78 301.10 301.42 301.53 301.54 301.59 301.83 301.94 302.01 302.06 302.04 302.27 302.26 302.31 302.36 302.58 302.68 302.92 303.17 303.13 303.06 303.00 303.09 303.20 303.05 303.26 303.57 303.77 303.72 303.86 304.15 304.17 304.06 304.17 304.25 304.28 304.30 304.23 304.43 304.34 304.33 304.36 304.36 304.35 304.48 304.61 304.82 304.72 304.81 304.96 305.10 305.23 305.41 305.42 305.57 12450. 12475. 12500. 12525 · 12550 · 12575. 12600. 12625. 12650. 12675. 12700. 12725. 12750. 12775. 12800. 12825. 12850. 12875. 12900. 12925. 12950. 12975. 13000. 13025. 13050. 13075. 13100. 13125. 13150 · 13175. 13200. 13225. 13250. 13275. 13300. 13325. 13350 · 13375. 13400 · 13425. 13438. 30 20 20 10 2O 10 30 10 30 30 O0 20 20 10 20 20 O0 O0 20 10 20 10 40 10 10 10 10 O0 10 O0 O0 10 10 20 O0 O0 10 10 10 20 60 59 59 59 59 59 59 59 59 59 60 60 60 60 60 61 61 61 61 61 61 61 61 62 62 62 62 62 62 62 62 63 63 63 63 63 64 64 64 64 63 63 .64 .59 .35 .38 .63 .63 .41 .20 .70 .18 .19 .43 .74 .82 .10 .22 .30 .36 .55 .72 .77 .90 .10 .09 .46 .47 .70 .77 .87 .95 .13 .48 .62 .68 .87 .18 .11 .08 .52 .84 .61 305.71 305.70 305.76 305.87 305.95 305.89 306.17 306.20 306.17 306.05 306.23 306.33 306.36 306.47 306.64 306.64 306.74 306.75 306.68 306.75 306.86 306.87 307.03 307.10 307.24 307.28 307.43 307.51 307.60 307.51 307.50 307.54 307.45 307.51 307.72 307.72 307.80 308.13 308.01 307.93 307.90 Tape Subfile 2 is type: LIS **** FILE HEADER **** CN WN FN COUN STAT : UNOCAL CORRPORATION : G-29RD : MCARTHUR RIVER FIELD : KENAI : ALASKA LIS COMMENT RECORD (s) : MAIN PASS. * FORMAT RECORD (TYPE# 64) ONE DEPTH PER FRAME Tape depth ID: F 17 Curves: Name Tool Code Samples Units API API API API Log Crv Crv Size Length Typ Typ Cls Mod 1 AC AC 68 1 US/F 4 2 ACQ AC 68 1 4 3 CAL CAL 68 1 IN 4 4 CHT 68 1 LB 4 5 CILD DIFL 68 1 MMHO 4 6 GR GR 68 1 GAPI 4 7 RFOC DIFL 68 1 OHMM 4 8 RILD DIFL 68 1 OHMM 4 9 RILM DIFL 68 1 OHMM 4 10 SP DIFL 68 1 MV 4 11 SPD 68 1 F/MN 4 12 TlR1 AC 68 1 US 4 13 TlR2 AC 68 1 US 4 14 T2R1 AC 68 1 US 4 15 T2R2 AC 68 1 US 4 16 TEMP TEMP 68 1 DEG 4 17 TTEN 68 1 LB 4 4 48 852 89 1 4 81 285 47 0 4 30 085 93 6 4 94 017 77 6 4 34 704 23 6 4 21 990 60 6 4 27 515 24 6 4 04 903 06 0 4 06 213 78 0 4 53 419 67 0 4 59 553 77 6 4 81 285 47 0 4 81 285 47 0 4 81 285 47 0 4 81 285 47 0 4 06 033 97 0 4 94 017 77 6 * DATA RECORD (TYPE# 0) 1014 BYTES * Total Data Records: 1098 / Tape File Start Depth = 13571.000000 / Tape File End Depth = 9731.000000' Tape File Level Spacing = 0.250000 Tape File Depth Units = Feet **** FILE TRAILER **** LIS representation code decoding summary: Rep Code: 68 276499 datums Tape Subfile: 2 1103 records... Minimum record length: 62 bytes Maximum record length: 1014 bytes 68 RECEIVED JUL 1 4 1992 Alaska Oil 8, GaS Cons. commi~]~J AnChOrage Tape Subfile 3 is type: LIS **** FILE HEADER **** CN WN FN COUN STAT : UNOCAL CORRPORATION : G-29RD : MCARTHUR RIVER FIELD : KENAI : ALASKA LIS COMMENT RECORD(s): REPEAT PASS. * FORMAT RECORD (TYPE# 64) ONE DEPTH PER FRAME Tape depth ID: F 17 Curves: Name Tool Code Samples Units API API API API Log Crv Crv Size Length Typ Typ Cls Mod 1 AC AC 68 1 US/F 4 2 ACQ AC 68 1 4 3 CAL CAL 68 1 IN 4 4 CHT 68 1 LB 4 5 CILD DIFL 68 1 MMHO 4 6 GR GR 68 1 GAPI 4 7 RFOC DIFL 68 1 OHMM 4 8 RILD DIFL 68 1 OHMM 4 9 RILM DIFL 68 1 OHMM 4 10 SP DIFL 68 1 MV 4 11 SPD 68 1 F/MN 4 12 TlR1 AC 68 1 US 4 13 TlR2 AC 68 1 US 4 14 T2R1 AC 68 1 US 4 15 T2R2 AC 68 1 US 4 16 TEMP TEMP 68 1 DEG 4 17 TTEN 68 1 LB 4 4 48 852 89 1 4 81 285 47 0 4 30 085 93 6 4 94 017 77 6 4 34 704 23 6 4 21 990 60 6 4 27 515 24 6 4 04 903 06 0 4 06 213 78 0 4 53 419 67 0 4 59 553 77 6 4 81 285 47 0 4 81 285 47 0 4 81 285 47 0 4 81 285 47 0 4 06 033 97 0 4 94 017 77 6 * DATA RECORD (TYPE# 0) 1014 BYTES Total Data Records: 113 Tape File Start Depth = 13565.000000 Tape File End Depth = 13173.000000 Tape File Level Spacing = 0.250000 Tape File Depth Units = Feet 68 **** FILE TRAILER **** LIS representation code decoding summary: Rep Code: 68 28243 datums Tape Subfile: 3 118 records... Minimum record length: 62 bytes Maximum record length: 1014 bytes Tape Subfile 4 is type: LIS **** TAPE TRAILER **** 92/ 7/10 01 **** REEL TRAILER **** 92/ 7/10 01 Tape Subfile: 4 2 records... Minimum record length: 132 bytes Maximum record length: 132 bytes End of execution: Fri 10 JLY 92 2:12a Elapsed execution time = 1 minute , 5.7 seconds. SYSTEM RETURN CODE = 0
