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196-090
!IT'D IR'6 -010 • Loepp, Victoria T (DOA) From: Loepp,Victoria T(DOA) Sent: Thursday, May 10, 2018 2:47 PM To: 'Simek,Jill' Subject: KRU 2M-09A (PTD 196-090; Sundry 318-054) P&A Procedure Changes Jill, The changes outlined below are approved. Please include this approval with the approved sundry. Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska ��M� � ,��� 5 �r)' Oil&Gas Conservation Commission M 333 W.7th Ave Anchorage,AK 99501 Work: (907)793-1247 Victoria.Loeppac 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 Victoria Loepp at(907)793-1247 or Victoria.Loepp@alaska.gov From:Simek,Jill<Jill.Simek@conocophillips.com> Sent:Thursday, May 10,2018 2:41 PM To: Loepp,Victoria T(DOA)<victoria.loepp@alaska.gov> Subject:2M-09A P&A Procedure Changes(PTD#196-090;Sundry#318-054) Victoria, Per our discussion,ConocoPhillips would like to make the following changes to the P&A procedure on 2M-09A(PTD:196- 090): Delete steps for cement dump bailer runs to place cement for Plug#1 Delete steps to circulate kill weight fluid from Plug#1 TOC to 4,661ft KB Delete steps to set cast iron bridge plug at 4,690ft KB. Add steps to place cement with coiled tubing from 9,017ft KB to 4,680ft KB(Plug#1) Add steps to tag and pressure test top of cement of Plug#1 Proceed with Plug#2 as outlined in original procedure (attached). Detailed steps to be added are below. Please advise if this is an acceptable change to the procedure. Thanks -Jill 1 • • Procedure: Coiled Tubing/Cementing Objective: Plug#1 — Place cement from XX Plug to 4,680ft KB. Cement Volume Calculations: • 4 '/z" liner from plug to liner top: (0.01522 bbl/ft) * (9,017ft-4,716ft) = 65.5 bbls • 3 'h" tubing from liner top to 4,680ft KB: (0.008696 bbl/ft) * (4,716ft—4,680ft) = 0.3 bbls • 3 '/z" x 7" annulus from packer to open gas lift mandrel: (0.02636 bbl/ft) * (4,716ft—4,631ft) = 2.2 bblS • Total = 65.5+ 0.3 + 2.2 = 68 bbls 1. Ensure an approved sundry has been received from AOGCC. 2. Contact Halliburton a week before the scheduled P&A date, to allow adequate time for pilot testing of the P&A cement design. (Wesley Miller/ Ed Jans 907 670-5827). The job is designed for 68 bbls of 15.8# Class "G" cement (includes 2.2 bbls "excess" to account for cement losses through tubing cut and/or open gas lift mandrel). 3. Conduct Safety Meeting and Identify Hazards. Inspect wellhead and pad condition to identify any pre-existing conditions. 4. RU Coil Tubing Unit and Cementers. Pressure test surface equipment as required. 5. Reference 12/2/2015 schematic and tubing details for depth correlation. 6. RIH with coil tubing and tag plug at 9,017ft KB. a. Pump 10 bbls fresh water spacer b. Pump 68 bbls of 15.8 ppg Class"G" Cement c. Pump 10 bbls fresh water spacer behind d. With approximately 50ft of cement out of the nozzle, begin to pull out of hole, laying in, cement, taking returns up the coil tubing backside. e. Pump and pull to 4,680ft KB. f. POOH above TOC g. Circulate CTU clean. 7. Wash up surface equipment. 8. RDMO. Slickline/Little Red Objective: State witnessed tag of TOC, CMIT-TxIA, DDT-TxIA, confirm circulation 1. WOC per UCA data (minimum 24 hours). Notify the AOGCC Inspector of the timing of the cement plug tag (submit AOGCC Test Witness Notification Form 24hrs in advance of witness). 2. Conduct Safety Meeting and Identify Hazards. Inspect wellhead and pad condition to identify any pre-existing conditions. 3. RU Slickline and PT surface equipment as required. 4. RIH and tag TOC at approximately 4,680ft KB. Record results. TAG MUST BE AOGCC WITNESSED. 5. RU LRS and PT surface equipment as required. 6. Perform CMIT-TxIA to 1,500 psi. Record Results. PRESSURE TEST MUST BE AOGCC WITNESSED. 7. Perform DDT-T. Record Results. 2 8. Pump 20 bbls diesrough tubing cut to ensure adequate ilk for cementing (+/- 2 bpm <= 2,000psi). 9. Report issues and results to Well Integrity Engineer. 10. Shut in well, RDMO. Jill Simek ConocoPhillips Alaska Staff Well Integrity Engineer 700 G Street, ATO 1854, Anchorage, AK 99501 Phone: 907-263-4131 I Cell: 907-980-7503 • 3 THE STATE °fALASKA GOVERNOR BILL WALKER Jill Simek Staff Well Integrity Engineer ConocoPhillips Alaska, Inc. P.O Box 100360 Anchorage, AK 99510 Alaska Oil and Gas Conservation Commission Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2M -09A Permit to Drill Number: 196-090 Sundry Number: 318-054 Dear Ms. Simek: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov 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, Z��' Hollis S. French k Chair DATED this G� day of February, 2018. RBDMS L,<,FES 2 7 208 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED FEB 0 9 2 13 AOA C 1. Type of Request: Abandon Plug Perforations It Fracture Stimulate ❑ Repair Well ❑ Operations shutdown Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Reenter Susp Well ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhilli S Alaska Inc. Exploratory ❑ Development ❑ Stratigraphic ❑ Service ❑, -- 196-090 3. Address: 6. API Number: P. 0. Box 100360, Anchorage, Alaska 99510 50-103-20177-01 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 O KRU 2M -09A 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL 25589 1 Kuparuk River Field / Kuparuk River Oil Pool it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9,405' 6,299' 9405 6299 Opal ,1-,401? 9017 NONE Casing Length Size MD TVD Burst Collapse Conductor 78' 16" 121' 121' Surface 4,264' 95/8 4,306' 2,775' Production 4,961' 7" 5,000' 3,051' Liner 4,685' 41/2 9,402' 6,297' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 90849096, 9104-9133, 9149- 6034-6043, 6050-6074, 6087- 1 3.500" L-80 4,719' 9214 ' 6140 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): PACKER = BAKER ZXP PACKER 4717 MD and 2936 TVD 12. Attachments: Proposal Summary 0 Wellbore schematic 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑ Service 0 , 14. Estimated Date for 3/1/2018 15. Well Status after proposed work: Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: 0 GINJ El Op Shutdown ❑ Abandoned 0 . 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Jill Simek Contact Name: Jill Simek Authorized Title: Staff Well Integrity Engineer Contact Email: Jill.Simek@cop.com Contact Phone: (907) 263-4131 Authorized Signature: Date: COMMISSION' USE ONLY Conditions of approval: NbWyCommission so that a representative may witness Sundry Number 313- O Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: i / 0 '7 RP DMi CJ � L FrP i 7 :C18 V APPROVED BY Approved by: COMMISSIONER THE COMMISSION 2- 1; Date: Ile, Submit Form and Form 10-403 Revised 4/2017 Approved application la valid Or 12 months from the date of approval. Attachments in Duplicate ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Commissioner, State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7' Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: 8 February 2018 ConocoPhillips Alaska, Inc. hereby applies for an Application for Sundry Approval to Plug and Abandon Kuparuk Injector 2M -09A (PTD#: 196-090). 2M -09A is a produced water injector drilled in 1996. In September 2012, Coiled Tubing encountered heavy weight pulls and was unable to complete a fill clean out. A subsequent gyro showed helical buckling and probable casing damage through the entire permafrost, with most severe damage shown from 150' to 800' KB. In June 2015, 2.78" and 2.68" Wireline Retrievable Plug drifts set down at 772' SLM. In October 2015, the well was secured with a 2.31" XX plug at 9,017' KB and tubing was cut at 4,661' KB in anticipation of a rig workover. However, the repair was deemed uneconomical and the resources were captured by other development projects. Thewe has s no future utility and represents unacceptable risk. 2M -09A is completed with 9-5/8" surface casing, 7" production casing, 3 %z" tubing, and a Baker ZXP packer set at 4,716.7' KB. A sidetrack was drilled through the `A' window at 4,980 to 4,990' KB and a 4'/2 " liner was run to 9,402.0' KB. Per this procedure, P&A steps will be performed to place a cement plug on the existing WRP to isolate perforations �P frompe wellbore (Plug#1). Kill weight fluid will be placed above the cement plug to the open gas lift mandrel at 4,6KB and a cast iron bridge plug will be set at approximately 4,690' KB. A second cement plug (Plug 42) will be pumped, fullbore, to bring cement to approximately 1,800' KB in the tubing and tubing x production casing annulus (IA). Tubing and production casing will then be perforated above Plug #2 and a third cement plug (Plug #3) will be pumped to bring cement to surface in the tubing, IA, and production casing x surface casing annulus (OA). The well will then be excavated 4 feet below original ground level, wellhead and cellar removed, and site backfilled with gravel/fill to ground level. Due to the subsidence related tubing restrictions from 150' to 800' KB and the tubing cut at 4,661' KB, it is not recommended to pull the WRP, as the risk of sticking the plug is high. Should the plug become stuck, the P&A operation may be compromised and the well would be left in an unsecured state. ConocoPhillips thereby requests a variance from the AOGCC well plugging requirements as specified in 20 AAC 25.112 (c)(1)(E): "if the perforations are isolated from open hole below, a mechanical bridge plug set no more than 50 feet above the top of the perforated interval, and either a minimum of 75 feet of cement placed on top of the plug by the ✓ displacement method or a minimum of 25 feet of cement placed on top of the plug with a dump bailer; X!( P 1-47 The WRP is s6t at 9,017' KB' KB, 67 feet above the perforations. ConocoPhillips proposes to place 25 feet of cement on this existing WRP, to isolate the formation from the wellbore. Please refer to the attached procedure for more details. If you have any questions or require any further information, please contact me at 263-4131. Sincerely, Jill Simek Well Integrity Engineer CPAI Drilling and Wells coo? s,rb� ConocoPhillips 2M-O9A P&A Permit to Drill #: 196-090 P&A operations will be performed to place a cement plug on the existing WRP to isolate perforations from the wellbore wellbore (Plug#1). Kill weight fluid will be placed above the cement plug to the open gas lift mandrel at 4,661' KB and a cast iron bridge plug will be set at approximately 4,690' KB. A second cement plug (Plug #2) will be pumped, fullbore, to bring cement to approximately 1,800' KB in the tubing and tubing x production casing annulus (IA). Tubing and production casing will then be perforated above Plug #2 and a third cement plug (Plug #3) will be pumped to bring cement to surface in the tubing, IA, and production casing x surface casing annulus (OA). The well will then be excavated 4 feet below original ground level, wellhead and cellar removed, and site backfilled with gravel/fill to ground level. ✓ Procedure: Slickline Objective: Plug #1 — Place 35 linear feet of cement on plug with cement bailer Cement Volume Calculations: • 4-1/2" liner, 25 linear feet, plus 10 feet excess = (0.015218 bbl/ft)' 35ft = 0.5 bbis 1. Ensure an approved sundry has been received from AOGCC. 2. Conduct Safety Meeting and Identify Hazards. Inspect wellhead and pad condition to identify any pre-existing conditions. 2, 3. RU Slickline and PT surface equipment as required. 4. Drift for cement dump bailer to 9,017.Oft KB. s (:-I 3P 5. With cement dump bailer, place 35ft cement on top of XX Plug set at 9,017.0ft KB. Expected cement top will be 8,982ft KB. m v. 7_5'V4✓ 6. RDMO Slickline/Little Red Objective: Tag Top of Cement, circulate KWF KWF Volume from Plug to Tubing Cut: • 41/2" liner from cement plug to liner top: (0.01522 bbl/ft) ` (8,982ft - 4,716.7ft) _ 64.9 bbls • 3'/2 " tubing from tail to open gas lift mandrel: (0.008696 bbl/ft)' (4,719.2ft — 4,631.1ft) = 0.8 bbls • 3'/2' x 7" annulus from packer to open gas lift mandrel: (0.02636 bbl/ft) (4,716.7ft — 4,631.1ft) = 2.3 bbls Excess: 2.0 bbls Total = 64.9 + 0.8 + 2.3 + 2.0 = 70 bbls 1. WOC per UCA data (minimum 24 hours). Notify the AOGCC Inspector of the timing of the cement plug tag (submit AOGCC Test Witness Notification Form 24hrs in advance of witness). JS 2. Conduct Safety Meeting and Identify Hazards. Inspect wellhead and pad condition to identify any pre-existing conditions. 3. RU Slickline and PT surface equipment as required. 4. RIH and tag TOC at approximately 8,982ft KB. Record results. TAG MUST BE AOGCC WITNESSE-D. 5. If TOC is found deeper than 8,992ft KB (25ft above plug), STOP, RIG DOWN, CALL JILL SIMEK @ 907-980-7503. 6. RU LRS and PT surface equipment as required. 7. Pump 45 bbls of 0.5% Baker CRW 132 corrosion inhibited 9.8# brine down tubing, taking returns from the IA. . fhb 8. Shut in well. RDMO. 9. Leave well shut in for 24 hours to allow for fluid swap. 10. RU LRS and PT surface equipment as required. 11. Pump additional 25 bbls of 0.5% Baker CRW 132 corrosion inhibited 9.8# brine down tubing, taking returns from the IA. 12. Shut in well, RDMO. E -line / Little Red Set CIBP below tubing cut, establish circulation. � 112z'Ct6F 1. Leave well shut in for 24 hours to allow for fluid swap. 2. Conduct Safety Meeting and Identify Hazards. Inspect wellhead and pad condition to identify any pre-existing conditions. 3. RU a -line and PT surface equipment as required. 4. RIH and set CIBP at 4,690ft KB. 5. Pump diesel down tubing to confirm circulation to IA (+/- 2 bpm <= 2,000psi). 6. RDMO Pumping Services: b Objective: Plug #2 -Fill the wellbore with cement from open gas lift mandrel -T (4,631ft KB) to base of permafrost (1,800ft KB). We will be circulating cement down the 3 %" tubing and up the 7" x 3'/2" annulus. Cement Volume Calculations: • Volume in 3'/2" x 7" annulus: (4,631ft - 1,800ft) x 0.02636 bbl/ft = 74.6 bbl • Volume inside 3'/z' tubing: (4,631ft - 1,800ft) x 0.008696 bbl/ft = 22.9 bbl • Total volume: 74.6 + 22.9 = 97.5 bbl • Displacement volume: (1,800ft KB) * (0.008696 bbl/ft) - 3 bbl spacer = 12.7 bbl )S 1. Contact Schlumberger a week before the scheduled P&A date, to allow adequate time for pilot testing of the P&A cement design. (Charles Hacker / Stephen Higgins 907 659-6121). The job is designed for 97.5 bbls of 15.8# Class "G cement. 2. Conduct Safety Meeting and Identify Hazards. Inspect wellhead and pad condition to identify any pre-existing conditions. 3. Ensure a 5" foam ball is loaded into the tree prior to the cement job. 4. RU cementers. Ensure to rig up a cement clean up line using an isolation valve and "T" connection off the tree. 5. Ensure that hardline is rigged up to pump down the tubing and take returns to a tank from the 3'/�' x 7" (IA) annulus. Also ensure that there is a way to pump down the IA in case the tubing pressures up. 6. PT surface equipment as required 7. Establish circulation with diesel. h 8. Pump 2 bbls fresh water spacer 9. Pump 97.5 bbls of 15.8 ppg Class "G" cement. 10. Drop 5" Foam Ball 11. Pump 3 bbls fresh water spacer. 12. Displace with 12.7 bbls diesel to leave Top of Cement in tubing and IA at 1,800ft KB. Do not overdisplace. 13. Shut down pumps and close in Tubing and IA. 14. Wash up cement pumps and clean up surface lines. 15. RDMO Slickline / DHD Objective: Tag TOC, CMIT-TxIA, DDT-TxIA 1. WOC per UCA data (minimum 24 hours). 2. Conduct Safety Meeting and Identify Hazards. to identify any pre-existing conditions. 3. RU Slickline and PT Equipment as required. 4. RIH and tag TOC @ approximately 1,800ft KB. to Well Integrity Engineer. Inspect wellhead and pad condition 5. Perform CMIT-TxIA to 1,500 psi. Record results. 6. Perform DDT on Tubina and IA. Record results. Record results and report tag depth 7. Report issues & results to Well Integrity Engineer. 8. RDMO E -line / Little Red Log CBL and perforate 3'/]" tubing and 7" production casing to establish circulation for surface cement plug. 1. Conduct Safety Meeting and Identify Hazards. Inspect wellhead and pad condition to identify any pre-existing conditions. 2. RU e -line and PT surface equipment as required. JS ocy7 {3Vr 3. Log CBL to determine TOC in IA. 4. DISCUSS CBL RESULTS WITH WELL INTEGRITY ENGINEER TO CONFIRM REQUIRED PUNCH DEPTH 5. RIH with dual -string perforating gun (5ft x 2" Powerflow downloaded to 1spf, zero degree phased), referencing 12/2/2015 schematic and tubing details for depth correlation. 6. Punch at depth determined by TOC tag and CBL log, TO BE CONFIRMED BY WELL INTEGRITY ENGINEER. Orient perforating gun to shoot high side of tubing. 7. Pump diesel down tubing to confirm circulation to both IA and OA (+/- 2 bpm <_ 2,OOOpsi). Ensure fresh diesel is circulated into OA to fully displace unknown annulus fluid. 8. If 2 bpm circ. rate is not achievable, RIH with a second perforating gun and perforate 32' above the previous holes. 9. RDMO Pumping Services: Objective: Plug #3 - Fill the wellbore with cement from perforating depth (-1,800' MD) to surface. We will be circulating cement down the 3 %" tubing and up the 9 5/8" x 7" annulus as well as up the 7" x 3 %" annulus. Cement Volume Calculations: • Volume in 3'/z" x 7" annulus: (1,800ft - Oft) x 0.02636 bbl/ft = 47.4 bbl • Volume in 7" x 9 5/8" annulus: (1,800ft - Oft) x 0.02561 bbl/ft = 46.1 bbl • Volume inside 3'/2' tubing: (1,800ft - Oft) x 0.008696 bbl/ft = 15.7 bbl • Excess: 20 bbl k� • Total volume: 47.4 + 46.1 + 15.7 + 20 = 129.2 bbl 1. Contact Schlumberger a week before the scheduled P&A date, to allow adequate time for pilot testing of the P&A cement design. (Charles Hacker / Stephen Higgins 907 659-6121). The job is designed for 129.2 bbls of ArcticSet 1 (AS1) cement. 2. Conduct Safety Meeting and Identify Hazards. Inspect wellhead and pad condition to identify any pre-existing conditions. 3. RU SLB Cement Equipment and PT surface lines as required. Ensure that hardline is rigged up to pump down the tubing and take returns to a tank from both the 9 5/8" x 7" (OA) and 7" x 3'/z" (IA) annuli independently. Also, ensure that there is a way to pump down the IA or OA in case the tubing pressures up. Rig up line to flush all surface lines of cement post -job. 4. Close the OA, open the IA, and pump 20 bbls of diesel down the tubing, taking returns to tank from the IA to confirm circulation. 5. Close the IA, open the OA, and pump 20 bbls of diesel down the tubing, taking returns to tank from the OA to confirm circulation. 6. After circulation to IA and OA is confirmed, batch up AS1. 7. Line up to pump cement down the tubing, taking returns from the OA. 8. Follow Pump Schedule below: i. 5 bbls fresh water spacer ahead ii. 129.2 bbls of AS1 (cement to surface in TWO, including 20 bbls excess) JS MM 9. After approximately 61.8 bbls of cement is pumped away, expect to see OA cement returns. Utilize mud balance to confirm good AS1 cement to surface coming from the OA. Pump contingency cement if needed to obtain good cement to surface. 10. With good OA cement to surface, open the IA, close the OA, and line up to take IA returns to tanks. This step must be performed efficiently as AS1 is thixotropic and will develop gel strength quickly when static. 11. After approximately 47.4 bbls of cement is pumped away, expect to see IA cement returns. Utilize mud balance to confirm good AS1 cement to surface coming from the OA. Pump contingency cement if needed to obtain good cement to surface. 12. After good OA and IA cement is seen at surface, shut down pumps and close in the IA and OA valves. 13. Close in the master valve, open the cement clean up line, and circulate to tanks to wash up tree and surface equipment. 14. RDMO Objective: DDT 1. WOC for 48 hr or until field blend compressive strength. 2. RU DHD and PT equipment. 3. Perform drawdown test on tubing, Wellhead Excavation / Final P&A: Js UCA chart shows cement developed 1,500 psi IA, and OA. 1. Determine top of cement in tubing and annuli; perform cement top up job. 2. Notify the AOGCC Inspector of timing for surface plug witness and marker plate installation (submit AOGCC Test Witness Notification Form 24hrs in advance of witness). 3. Remove the Well House (if still installed). 4. Bleed off TWO to ensure all pressure is bled off the system. 5. Remove the tree, in preparation for the excavation and casing cut. 6. If shallow thaw conditions are found, have shoring box installed during the excavation activity to prevent lose ground from falling into the excavation. 7. Cut off the wellhead and all casing strings at 4 feet below original ground level. 8. Perform Top Job and verify that cement is at surface in all strings. AOGCC witness and photo document required. 9. Send the casing head w/ stub to materials shop. Photo document. 10. Weld %" thick cover plate (16" O.D.) over all casing strings with the following information bead welded into the top. Photo document. AOGCC Witness Required. ConocoPhillips 2M -09A PTD # 196-090 API # 50-103-20177-01 11. Remove Cellar. Back fill cellar with gravel/fill as needed. Back fill remaining hole to ground level. 12. Obtain site clearance approval from AOGCC. RDMO. 13. Report the Final P&A has been completed to the AOGCC, and any other agencies required. Photo document final location condition after all work is completed. Js Schematic: js P&A Diagram: 1s 2M -09A P&A PTD #: 196-090 IL'.e' 62.54 MdL ChTpIiKJpi 121' K6 Ga', T's NIj01e a 514'<e Sae c0# -Bo :,e Ca:rg 04.sr GGLu:. Farr a 4,e5.1 r Ke Camra w wpoka 4.676.e Ke Cat T nhg a 4,ef.1 A ::e Wer Lx v 4, 4,7167 KS 3-1' 9 3FLIC "Nnrg a 4,71>i" M5 Eae -WC _M HTger a ea ff.5R 0 e,'5-.7 K5 :68:90 FiDWMI. �asng s,ox �:E C4MM N PP,* MIR Pott' 0 9.D17 0' K5 Pen: 9,DBW9,DS6 Ke 9ALW9,137 KP 9.:49-9,214 KE 4 V 126E L -5D L^MS ® 4,4C7 K9 Mt.O.�uet i W_mai�pV.,em?n Pini: TOG 6. 1.8.,:'KS 3,8Rvam5 rl KViF1e Asset' K5 58c am.V J: ^201:018 Rixse, Melvin G (DOA) From: Rixse, Melvin G (DOA) Sent: Friday, February 23, 2018 11:40 AM To: 'Simek, Jill' Cc: Schwartz, Guy L (DOA) Subject: RE: [EXTERNAL]Sundry318-054 KRU 2M -09A P&A Jill, We will proceed with the Sundry approval for the P&A of 2M -09A. Just to clarify, we hope you are able isolate the 4-1/2" liner with a plug just below the cut at 4661' MD before cementing tubing and the IA. If you cannot, please contact Guy or myself to discuss your plan forward. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell melvin.rixse@alaska.gov cc. Guy Schwartz From: Simek, Jill [mailto:Jill.Simek@conocophillips.com] Sent: Thursday, February 22, 2018 3:30 PM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Cc: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: RE: [EXTERNAL]Sundry 318-054 KRU 2M -09A P&A '5 Jov Mel, Thanks for talking through these steps. Per our telephone discussion, if we can't get deep enough to tag Plug## with the standard CIBP drift, we will reattempt with a slim or inflatable plug drift. We would also look at broaching options to open up the obstruction. If still unsuccessful, we would ask the state for permission to change the plug set depth, adding Kill Weight Fluid in the tubing and annulus between planned and revised set depths. Let me know if this plan is acceptable. Thanks! Jill From: Rixse, Melvin G (DOA) [mailto:melvin.rixse@alaska.eov] Sent: Thursday, February 22, 2018 2:53 PM To: Simek, Jill <JiII.Simek@conocophillips.com> Cc: Schwartz, Guy L (DOA) <Ruv.schwartz@alaska.Rov> Subject: RE: [EXTERNAL]Sundry 318-054 KRU 2M -09A P&A Jill, I want to do our best to get the CIBP (or similar plug) into the stub, so below the cut at 4661' MD. Really anywhere in that 30' should be okay. If we cannot get a CIBP below the cut, could we at least consider the possibility of an inflatable run into the stub? Let me know what you think. You can call me if email is getting too tenuous. I am fine with the pressure test at the CIBP drift. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell melvin.rixse@alaska.gov cc. Guy From: Simek, Jill [mailto:lill.Simek@conocophillips.com] Sent: Thursday, February 22, 2018 1:44 PM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Cc: Schwartz, Guy L (DOA) <guy.schwa rtz@alaska.gov> Subject: RE: [EXTERNAL]Sundry 318-054 KRU 2M -09A P&A Mel, 1 will add steps to include charted pressure test and CIBP drift. I think it would be best to drift when we tag plug#1, after the cement dump bailer runs. This gets me thinking of contingencies: if we are unable to drift/tag plug#1 (ie if cement stringers are left during bailing step), would the AOGCC allow us to set the CIBP higher than the planed 4,690ft? Thanks, Jill Simek ConocoPhillips Alaska Staff Well Integrity Engineer 700 G Street, ATO 1854, Anchorage, AK 99501 Phone: 907-263-41311 Cell: 907-980-7503 From: Rixse, Melvin G (DOA)[mailto:melvin.rixse@alaska.gov] Sent: Wednesday, February 21, 2018 4:32 PM To: Simek, Jill <JiILSimek@conocophillips.com> Cc: Schwartz, Guy L (DOA) <guv.schwartz@alaska.gov> Subject: [EXTERNAL]Sundry 318-054 KRU 2M -09A P&A Hi Jill, am reviewing the Application for Sundry Approval for the P&A program for 2M -09A. I appreciate the detailed work description you have provided. I have a request: Please provide a charted pressure test (30 minutes @ 1500 psi) of the wellbore (around step #6) against bailed cement set on the CIBP @ 9017' MD. Also, A question: Will the CIBP (@4690' MD) need to be drifted to 3-1/2" ID? Can you do this when you drift for the bailer or should it be done just before setting the bridge plug? Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell melvin.rixse@alaska.gov cc. Guy Schwartz 111 • ‘01G- ogo 26W S . WELL LOG TRANSMITTAL I� DATA LOGGED /0/2011 PROACTIVE DIAGNOSTIC SERVICES, INC. RECEIVEDM.K.BENDER JUL 132017 To: AOGCC AOGCC Makana Bender 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 (907) 793-1225 RE : Cased Hole/Open Hole/Mechanical Logs and/or Tubing Inspection(Caliper/MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the attention of: ProActive Diagnostic Services, Inc. Attn: Ryan C. Rupe 130 West International Airport Road Suite C Anchorage, AK 99518 Fax: (907) 245-8952 SCANNED AUG Q 3 201 7, 1) Caliper Report 1gJun-17 2M-09A 1 Report /CD 50-103-20177-01 2) Caliper Report 13-Jun-17 .1E-15A 1 Report /CD 50-029-20769-01 Signed : /'22.4ta4Z4Jt..d ,5 o_ellvireetDate : Print Name: PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W.INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAx: (907)245-8952 E-MAIL: PDSANCHORAGE(DMEMORYLOG.COM WEBSITE:WWW.MEMORYLOG.COM a Wchives\MasterTemplateRes\Templates\Distribution\TransmittalSheets\ConocoPhillips_Transmit.docx koiG -ogo ECEIVED 271C3S ( 1110 JUL 13 2017 Memory Multi-Finger Caliper tilt AOGCC Log Results Summary Company: ConocoPhillips Alaska, Inc. Well: 2M-09A Log Date: June 12, 2017 Field: Kuparuk Log No.: 14256 State: Alaska Run No.: 3 API No. 50-103-20177-01 Pipe Description: 3.5 inch 9.3 lb. L-80 EUE 8RD MOD Top Log Interval: Surface Pipe Use: Tubing Bottom Log Interval: 4,735 Ft. (MD) Inspection Type : Corrosive and Mechanical Damage Inspection COMMENTS : This caliper data is tied into the top of GLM 5 at 4,631 feet(Driller's Depth). This log was run to assess the condition of the tubing with respect to internal corrosive and mechanical damage. The caliper recordings indicate an apparent chemical cut at-4,661 feet where the caliper recorded a maximum wall penetration of 54%wall thickness. A 3-D log plot of the caliper recordings across the interval of apparent chemical cut is included in this report. The caliper recordings indicate the 3.5 inch tubing logged appears to be in good to poor condition, with wall penetrations ranging from 20%to 57%wall thickness in 45 of the 155 joints logged. Recorded damage appears as isolated pitting and a line of pits. No significant areas of cross-sectional wall loss are recorded throughout the tubing logged. Deposits restrict the I.D. to 2.78 inches in joint 128 (4,110 ft). No other significant I.D. restrictions are recorded throughout the tubing logged. A graph illustrating minimum recorded diameters on a joint-by-joint basis across the tubing logged is included in this report. The caliper recordings indicate helical buckling throughout the interval of 3.5 inch tubing logged. A 3-D log plot overlay of the centered and un-centered caliper recordings across the interval of tubing logged is included in this report. This is the third time a PDS caliper has been run in this well and the 3.5 inch tubing has been logged. A comparison of the current and previous log (October 13, 2009) indicates an increase in corrosive damage during the time between logs. A graph illustrating the difference in maximum recorded wall penetrations on a joint-by-joint basis between logs is included in this report. MAXIMUM RECORDED WALL PENETRATIONS : D,,scotion Perc,ent dJ_-1i1 Penetration ifW.rr Line of Pits 57 144 4,614 Ft. (MD) Line of Pits 54 145 4,661 Ft. (MD) Line of Pits 48 143 4,577 Ft. (MD) Line of Pits 45 129 4,149 Ft. (MD) Line of Pits 42 142 4,557 Ft. (MD) MAXIMUM RECORDED CROSS-SECTIONAL METAL LOSS: No significant areas of cross-sectional wall loss(> 8%)are recorded throughout the tubing logged. ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 Phone: (281) 431-7100 or (888) 565-9085 Fax: (281) 431-7125 E-mail: PDSAnalysis@memorylog.com Prudhoe Bay Field Office Phone: (907) 659-2307 Fax: (907) 659-2314 �� �� `� MAXIMUM RECORDED ID RESTRICTIONS : oem'ipunn min|mmnRauo,Veuo/ameter Jomt oepm Deposits 2.78 inches 128 4,110 Ft. (MD) No other significant I.D. restrictions are recorded throughout the tubing logged. C. Goerdt C. Waldrop J. Condio p/emconmemr(s) xna|voKy) mxtnomn(es) ProActive Diagnostic Services, Inc. / P.O Box 1369, Stafford, TX 77497 Phone: (281) 431-7100 or (888) 565'8085 Fax: (281) 431'7125 E-mail: PDSAna|ysis@/momory|ogzom • • PDS Multifinger Caliper 3D Log Plot Company : ConocoPhillips Alaska, Inc. Field : Kuparuk Well : 2M-09A Date : June 12, 2017 Description : Detail of Caliper Recordings Across Apparent Chemical Cut in 3.5 Inch Tubing. Comments Depth Nominal I.D. 3-D Log Image Map i1ft:240ft 2.5 inches 3.5 0° 0° 90° 180° 270° 0° Maximum I.D. I 2.5 inches 3.5 Minimum I.D. I I 2.5 inches 3.5 .+wv - is Joint 144 Line of Pits 4610 57%Wall Penetration 4620 Pup Joint .. • 4630 GLM1 1 11111111111 — 4640 ' Pup Joint . "Apparent Chemical Joint 145 4650 Cut (-4,661') Apparent . ChemicalCut • 4660 • (-4,661') V 1,- 54%Wall ii z. Penetration 4670 / Camco W-1 k X.M Mx ti: .3- \ Nipple 4680 #, 4690 {. Joint 146 4700 4710 Locator Joint 147 470n Minimum I.D. I 2.5 inches 3.5 Maximum I.D. 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"fir. _ ' 'I 4550 T , , . f__ _ 7::__._. .....,. ., - .._-• . .. .. .....••' •�r -r-- �::.. •• m µ4600 �" -- krttJtrtrttt — -- ...".... a .:::„...„. - ...,.., _ . ,..... ....,....,,,,,,, . , div:T.. - V:............,..., : 4650 - - ... „-,„ --, i „.1 ..• ......... ..... .•............ m 4 41 '" 4700 / ..- , • ttt • Minimum Radius 1.25 inches 1.75 Maximum Radius 1.25 inches 1.75 Minimum I.D. I I 2.5 inches 3.5 Maximum I.D. I I 2.5 inches 3.5 Nominal I.D. Depth 3-D Log(Un-Centered) Image Map(Un-Centered) 3-D Log(Centered) Image Map(Centered) �2.5 3.5 1:600 0° 0° 90° 180° 270° 0° 0° 0° 90° 180°270° 0° • 0 Maximum Recorded Penetration IR5 Comparison To Previous Well: 2M-09A Survey Date: June 12,2017 Field: Kuparuk Previous Date: October 13, 2009 Company: ConocoPhillips Alaska, Inc. Tool Type: UW MFC 24 No.211387 Country: USA Tubing: 3.5"9.3 lb L-80 EUE 8RD MOD Overlay Difference Maximum Recorded Penetration(mils) Difference in Maximum Penetration(mils) 0 50 100 150 200 250 -200 -100 0 100 200 0.1 —_ 0.1 -- Y_ 77 7--_,a1-- J� _ 14.3_ 14.3g. ,--- 24-,--=–_---- 24= 34 34 44r= 44;.--= } 54 54 d 64 d 64E. E 5 r Z 74~! Z 74-J- Z .6.cc 84 84 r 94 J! 94 104_ 104 D------:: 114 1141 124 ` 124= 134 134 144= 144-,.- GL M rGLM I -26 -13 0 13 26 •June 12,2017 •October 13,2009 Approximate Corrosion Rate(mpy) Corrosion Rate(mpy) Top 10 Jts. Overall Average 9 2 Median 9 1 • • Correlation of Recorded Damage to Borehole Profile • Pipe 1 3.5 in (31.9'-4,734.8') Well: 2M-09A Field: Kuparuk Company: ConocoPhillips Alaska,Inc. Country: USA Survey Date: June 12,2017 ■ Approx.Tool Deviation ■ Approx. Borehole Profile 1 35 10 343 20 672 30 990 40 1,307 50 ♦ 1,623 60 1,940 70 2,256 E c z 80 2,571 L iv — 90 2,889 100 3,205 110 3,522 120 3,839 130 4,153 140 4,468 GLM 1 147 4,716 0 50 100 Damage Profile(%wall)/Tool Deviation (degrees) Bottom of Survey=1 47 • Minimum Diameter Profile Well: 2M-09A Survey Date: June 12,2017 Field: Kuparuk Tool Type: UW MFC 24 No.211387 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 inches Country: USA Tubing I.D.: 2.992 inches Minimum Measured Diameters(in.) 1.75 2 2.25 2.5 2.75 0.1 - -32 � I 248 I - 14.3 ■ 508 241 799 34 1,116 44 1,433 54 -- 1,750 64 2,067cv ' Z 74 2,382 c s a 84 2,698 94 3,016 104 3,332 114 3,649 124 ` 3,964 134 4,278 144- - 4594 • S PDS Report Overview 4- ►„ Body Region Analysis Well: 2M-09A Survey Date: June 12,2017 Field: Kuparuk Tool Type: UW MFC 24 No.211387 Company: ConocoPhillips Alaska,Inc. Tool Size: 1.69 inches Country: USA No. of Fingers: 24 Pipe 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Analyst: C.Waldrop Pipe Nom.OD Weight Grade&Thread Nom.ID Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD 2.992 in. 32 ft. 4,735 ft. Penetration(%wall) Damage Profile(%wall) 150 Penetration body Metal loss body 0 50 100 0.1 100 50 - 0 44 0 to 20 to 40 to over 20% 40% 85% 85% Number of joints analyzed(total= 155) 109 40 6 0 i Damage Configuration(body) 100 -- 80 94 60 40 20 0 Isolated General Line Other Hole/ Pitting Corrosion Corrosion Damage Pos.Hole GLM 1 (9:00) 144 Number of joints damaged(total= 125) 33 0 91 1 0 Bottom of Survey= 147 • • illi PDS Report Joint Tabulation Sheet Well: 2M-09A Survey Date: June 12,2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 32 ft. 4,735 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 0.1 32 0 0.02 8 2 2.89 Pup Lt. Deposits. 1 35 0 0.03 11 3 2.92 Lt.Deposits. ■ 1.1 65 0 0.04 14 3 2.93 Pup Lt. Deposits. 1.2 73 0 0.02 8 4 2.93 Pup Lt. Deposits. 1.3 79 0 0.04 16 3 2.90 Pup Shallow Line of Pits.Lt. Deposits. 2 89 0 0.03 10 3 2.92 Lt.Deposits. 3 121 0 0.03 11 3 2.93 Lt.Deposits. 4 153 0 0.03 10 3 2.93 Lt.Deposits. 5 184 0 0.04 16 3 2.92 Shallow Line of Pits.Lt. Deposits. ■ 6 216 0 0.04 17 3 2.91 Shallow Line of Pits.Lt. Deposits. ■ 7 248 0 0.04 16 4 2.92 Shallow Line of Pits.Lt. Deposits. 8 279 0 0.05 19 4 2.90 Shallow Pitting. Lt Deposits. ■ 9 311 0 0.04 15 3 2.93 Shallow Line of Pits.Lt. Deposits. ■ 10 343 0 0.04 17 5 2.92 Shallow Line of Pits.Lt. Deposits. a 11 374 0 0.04 15 4 2.91 Shallow Pitting. Lt Deposits. 12 406 0 0.05 19 4 2.93 Shallow Line of Pits.Lt. Deposits. a 13 438 0 0.06 22 4 2.90 Line of Pits. Lt.Deposits. ■ 14 469 0 0.07 26 4 2.92 Line of Pits. Lt.Deposits. ■ 14.1 501 0 0.03 13 4 2.90 Pup Lt. Deposits. 14.2 507 0 0 0 0 2.79 CAMCO DS NIPPLE 14.3 508 0 0.02 7 2 2.97 Pup 15 514 0 0.04 16 4 2.93 Shallow Line of Pits.Lt. Deposits. 16 546 0 0.05 19 4 2.91 Shallow Line of Pits.Lt. Deposits. ■ 17 578 0 0.06 23 6 2.93 Line Corrosion. ■ 18 608 0 0.06 24 5 2.92 Line of Pits. Lt.Deposits. ■ 19 640 0 0.05 . 18 4 2.92 Shallow Pitting. Lt Deposits. 20 672 0 0.05 20 4 2.93 Line of Pits. 21 704 0 0.05 18 6 2.92 Shallow Line of Pits.Lt. Deposits. ■ 22 736 0 0.04 16 4 2.93 Shallow Line of Pits.Lt. Deposits. 23 767 0 0.06 23 5 2.93 Line Corrosion. Lt.Deposits. a 24 799 0 0.05 19 4 2.92 Shallow Pitting. Lt Deposits. 25 830 0 0.06 24 4 2.92 Line of Pits. Lt.Deposits. 26 862 0.07 0.07 26 4 2.93 Isolated Pitting. Lt. Deposits. 27 894 0 0.07 28 5 2.93 Line of Pits. Lt.Deposits. 28 926 0 0.08 31 4 2.92 Isolated Pitting. Lt.Deposits. 29 958 0 0.07 26 4 2.92 Line of Pits. Lt.Deposits. 30 990 0 0.07 26 4 2.92 Line of Pits. Lt.Deposits. 31 1021 0 0.07 28 3 2.92 Isolated Pitting. Lt.Deposits. 32 1053 0 0.06 24 5 2.91 Isolated Pitting. Lt.Deposits. u 33 1085 0 0.06 22 6 2.93 Line of Pits. Lt.Deposits. a 34 1116 0 0.06 24 4 2.92 Isolated Pitting. Lt.Deposits. 35 1148 0.04 0.08 32 5 2.92 Line of Pits. Lt.Deposits. ■ 36 1180 0 0.07 28 4 2.91 Line of Pits. Lt.Deposits. 37 1212 0 0.06 24 4 2.93 Isolated Pitting. Lt.Deposits. ■ 38 1244 0 0.08 . 32 4 2.93 Line of Pits. Lt.Deposits. 39 1275 0 0.05 19 4 2.93 Shallow Line of Pits.Lt. Deposits. 40 1307 0 0.09 34 3 2.92 Line of Pits. Lt.Deposits. ■ 41 1339 0 0.07 29 5 2.94 Line of Pits. ■ 42 1371 0 0.06 25 5 2.92 Line of Pits. Lt.Deposits. ■ 43 1402 0 0.04 17 4 2.91 Shallow Line of Pits.Lt. Deposits. IPenetration Body Metal Loss Body Page 1 • • Ca PDS Report Joint Tabulation Sheet Well: 2M-09A Survey Date: June 12,2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 32 ft. 4,735 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 44 1433 0 0.05 19 3 2.92 Shallow Pitting. Lt Deposits. ■ 45 1465 0 0.05 20 3 2.92 Line of Pits. Lt.Deposits. ■ 46 1497 0 0.04 17 4 2.92 Shallow Line of Pits.Lt. Deposits. ■ 47 1529 0 0.04 16 4 2.94 Shallow Line of Pits. ■ 48 1560 0 0.03 12 2 2.91 Lt.Deposits. ■ 49 1592 0 0.05 20 3 2.93 Isolated Pitting. Lt.Deposits. ■ 50 1623 0 0.04 15 2 2.92 Shallow Pitting. Lt Deposits. • 51 1655 0 0.04 16 3 2.93 Shallow Pitting. ■ 52 1687 0 0.03 13 3 2.92 Lt.Deposits. ■ 53 1718 0 0.03 12 3 2.93 Lt.Deposits. ■ 54 1750 0 0.04 14 4 2.93 Lt.Deposits. ■ 55 1782 0 0.05 20 6 2.92 Line of Pits. Lt.Deposits. ■ 56 1813 0 0.05 18 6 2.92 Shallow Line of Pits.Lt. Deposits. ■ 57 1845 0 0.05 21 4 2.92 Isolated Pitting. Lt.Deposits. ■ 58 1877 0 0.04 15 3 2.92 Shallow Pitting. Lt Deposits. ■ 59 1909 0 0.04 17 4 2.93 Shallow Line of Pits.Lt. Deposits. ■ 60 1940 0 0.03 13 2 2.92 Lt.Deposits. ■ 61 1972 0 0.04 17 4 2.91 Shallow Line of Pits.Lt. Deposits. ■ 62 2004 0 0.04 14 3 2.91 Lt.Deposits. ■ 63 2035 0 0.03 13 3 2.92 Lt.Deposits. ■ 64 2067 0 0.04 16 3 2.92 Shallow Line of Pits.Lt. Deposits. ■ 65 2097 0 0.05 19 4 2.91 Shallow Line of Pits.Lt. Deposits. ■ 66 2129 0 0.04 15 3 2.93 Shallow Line of Pits.Lt. Deposits. ■ 67 2161 0 0.04 14 2 2.93 Lt.Deposits. ■ 68 2192 0 0.05 20 5 2.92 Line of Pits. Lt.Deposits. ■ 69 2224 0 0.05 19 4 2.93 Shallow Line of Pits.Lt. Deposits. ■ 70 2256 0 0.06 22 7 2.92 Line Corrosion. Lt.Deposits. 1 71 2288 0 0.05 18 2 2.93 Shallow Pitting. Lt Deposits. ■ 72 2319 0 0.03 13 3 2.92 Lt.Deposits. ■ 73 2351 0 0.04 14 3 2.91 Lt.Deposits. ■ 74 2382 0 0.04 17 4 2.91 Shallow Line of Pits.Lt. Deposits. ■ 75 2414 0 0.04 17 4 2.93 Shallow Line Corrosion. Lt. Deposits. ■ 76 2446 0 0.05 19 3 2.92 Shallow Line of Pits.Lt. Deposits. ■ 77 2477 0 0.04 14 3 2.92 Lt.Deposits. ■ 78 2508 0 0.04 17 4 2.92 Shallow Line of Pits.Lt. Deposits. ■ 79 2539 0 0.05 19 4 2.92 Shallow Line Corrosion. Lt. Deposits. ■ 80 2571 0 0.04 17 4 2.91 Shallow Line Corrosion. Lt. Deposits. ■ 81 2602 0 0.04 16 4 2.93 Shallow Line of Pits.Lt. Deposits. ■ 82 2634 0 0.05 20 4 2.91 Isolated Pitting. Lt.Deposits. ■ 83 2666 0 0.05 18 4 2.91 Shallow Line Corrosion. Lt. Deposits. ■ 84 2698 0 0.05 20 3 2.92 Line of Pits. Lt.Deposits. a 85 2729 0 0.03 13 4 2.91 Lt.Deposits. ■ 86 2761 0 0.04 15 3 2.93 Shallow Line of Pits.Lt. Deposits. ■ 87 2793 0 0.05 18 4 2.91 Shallow Line of Pits.Lt. Deposits. ■ 88 2825 0 0.05 19 4 2.92 Shallow Line of Pits.Lt. Deposits. a 89 2857 0 0.05 18 4 2.92 Shallow Line of Pits.Lt. Deposits. ■ 90 2889 0 0.05 19 2 2.92 Shallow Line of Pits.Lt. Deposits. ■ 91 2920 0 0.05 18 4 2.92 Shallow Line of Pits.Lt. Deposits. ■ 92 2952 0 0.04 16 4 2.93 Shallow Pitting. Lt Deposits. ■ 93 2984 0 0.04 15 3 2.92 Shallow Line of Pits.Lt. Deposits. IPenetration Body Metal Loss Body Page 2 • • Nil PDS Report Joint Tabulation Sheet Well: 2M-09A Survey Date: June 12,2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 32 ft. 4,735 ft. Joint Jt. Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 94 3016 0 0.04 14 3 2.93 Lt.Deposits. ■ 95 3048 0 0.05 18 3 2.92 Shallow Line of Pits.Lt. Deposits. ■ 96 3078 0 0.04 17 4 2.92 Shallow Line of Pits.Lt. Deposits. ■ 97 3110 0 0.05 21 3 2.92 Line of Pits. Lt.Deposits. ■ 98 3142 0 0.05 18 2 2.91 Shallow Line of Pits.Lt. Deposits. ■ 99 3173 0 0.05 21 4 2.92 Isolated Pitting. Lt.Deposits. ■ 100 3205 0 0.04 16 3 2.91 Shallow Line of Pits.Lt. Deposits. ■ 101 3237 0 0.05 18 3 2.92 Shallow Line Corrosion. Lt. Deposits. ■ 102 3269 0 0.07 26 4 2.93 Line of Pits. Lt.Deposits. ■ 103 3301 0 0.04 17 3 2.92 Shallow Pitting. Lt Deposits. ■ 104 3332 0 0.04 17 4 2.90 Shallow Line of Pits.Lt. Deposits. ■ 105 3364 0 0.05 18 2 2.93 Shallow Line of Pits.Lt. Deposits. ■ 106 3396 0 0.05 . 19 4 2.91 Shallow Pitting. Lt Deposits. ■ 107 3427 0 0.05 18 3 2.92 Shallow Line of Pits.Lt. Deposits. ■ 108 3459 0 0.06 22 4 2.92 Line of Pits. Lt.Deposits. ■ 109 3491 0 0.05 18 4 2.92 Shallow Line of Pits.Lt. Deposits. ■ 110 3522 0 0.05 19 4 2.93 Shallow Line of Pits.Lt. Deposits. ■ 111 3554 0 0.05 20 3 2.92 Line of Pits. Lt.Deposits. ■ 112 3586 0 0.04 17 3 2.91 Shallow Line of Pits.Lt. Deposits. ■ 113 3618 0 0.04 16 3 2.92 Shallow Line of Pits.Lt. Deposits. ■ 114 3649 0 0.05 18 5 2.93 Shallow Line of Pits.Lt. Deposits. ■ 115 3681 0 0.03 11 2 2.91 Lt.Deposits. ■ 116 3712 0 0.04 16 7 2.92 Shallow Pitting. Lt Deposits. r 117 3744 0 0.03 13 4 2.92 Lt.Deposits. ■ 118 3776 0 0.03 13 3 2.90 Lt.Deposits. ■ 119 3807 0 0.05 19 3 2.89 Shallow Line of Pits.Lt. Deposits. ■ 120 3839 0 0.05 21 4 2.90 Line Corrosion. Lt.Deposits. ■ 121 3870 0 0.03 13 2 2.90 Lt.Deposits. ■ 122 3901 0 0.03 12 2 2.90 Lt.Deposits. ■ 123 3933 0 0.03 11 2 2.90 Lt.Deposits. ■ 124 3964 0 0.04 15 3 2.90 Shallow Line of Pits.Lt. Deposits. ■ 125 3996 0 0.03 13 2 2.91 Lt.Deposits. ■ 126 4027 0 0.04 15 3 2.90 Shallow Pitting. Lt Deposits. ■ 127 4058 0 0.04 15 7 2.91 Shallow Pitting. Lt Deposits. 1 128 4090 0 0.05 19 6 2.78 Shallow Pitting. Deposits. ■ 129 4122 0 0.11 45 3 2.91 Line of Pits. Lt.Deposits. ■ 130 4153 0 0.04 15 5 2.88 Shallow Pitting. Lt Deposits. ■ 131 4184 0 0.04 17 5 2.91 Shallow Pitting. Lt Deposits. ■ 132 4215 0 0.04 16 7 2.90 Shallow Line of Pits.Lt. Deposits. a 133 4247 0 0.06 22 4 2.90 Line Corrosion. Lt.Deposits. ■ 134 4278 0 0.04 17 7 2.90 Shallow Line of Pits.Lt. Deposits. 1 135 4310 0 0.05 19 4 2.89 Shallow Pitting. Lt Deposits. ■ 136 4341 0 0.05 19 7 2.90 Shallow Pitting. Lt Deposits. a 137 4373 0 0.09 35 5 2.90 Isolated Pitting. Lt.Deposits. ■ 138 4404 0 0.05 19 7 2.90 Shallow Line of Pits.Lt. Deposits. a 139 4436 0 0.04 16 7 2.90 Shallow Line of Pits.Lt. Deposits. r 140 4468 0 0.05 21 4 2.90 Line of Pits. Lt.Deposits. ■ 141 4499 0 0.11 42 4 2.91 Line of Pits. Lt.Deposits. ■ 142 4530 0 0.11 42 7 2.91 Isolated Pitting. Lt. Deposits. i 143 4562 0 0.12 48 6 2.90 Line of Pits. Lt.Deposits. IPenetration Body Metal Loss Body Page 3 • • VS, PDS Report Joint Tabulation Sheet Well: 2M-09A Survey Date: June 12,2017 Field: Kuparuk Analyst: C.Waldrop Company: ConocoPhillips Alaska,Inc. Pipe Description Nom. ID Body Wall Top Depth Bottom Depth 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Tubing 2.992 in. 0.254 in. 32 ft. 4,735 ft. Joint Jt.Depth Pen. Pen. Pen. Metal Min. Damage Profile No. (Ft.) Upset Body % Loss I.D. Comments (%wall) (in.) (in.) % (in.) 0 50 100 144 4594 0 0.15 57 6 2.87 Line of Pits. Lt.Deposits. Flimi 144.1 4625 0.04 0.04 17 6 2.90 Pup Shallow Pitting. Lt.Deposits. 144.2 4631 0 0 0 0 2.64 GLM 1 (LATCH @ 9:00) 144.3 4639 0 0.04 17 5 2.90 Pup Shallow Line of Pits.Lt. Deposits. Pillimill 145 4646 0 0.14 54 7 2.84 Apparent Chemical Cut. Lt Deposits. 145.1 4677 0 0 0 0 2.78 CAMCO W-1 NIPPLE 146 4679 0 0.05 19 4 2.89 Shallow Line of Pits.Lt. Deposits. Fs 146.1 4710 0 0 0 0 2.92 BAKER LOCATOR 147 4716 0 0.03 13 5 2.90 Lt.Deposits. r Penetration Body Metal Loss Body Page 4 • • PDS Report Cross Sections Cif 0. Well: 2M-09A Survey Date: June 12,2017 Field: Kuparuk Tool Type: UW MFC 24 No.211387 Company: ConocoPhillips Alaska,Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Analyst: C.Waldrop Cross Section for Joint 144 at depth 4,614.426 ft. Tool speed=50 Nominal ID=2.992 Nominal OD=3.5 Remaining wall area=94% Tool deviation=68° 1 Finger= 7 Penetration=0.145 in. Line of Pits 0.15 in.=57%Wall Penetration HIGH SIDE=UP • • PDS Report Cross Sections Well: 2M-09A Survey Date: June 12,2017 Field: Kuparuk Tool Type: UW MFC 24 No.211387 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Analyst: C.Waldrop Cross Section for Joint 145 at depth 4,660.966 ft. Tool speed=49 Nominal ID=2.992 Nominal OD=3.5 Remaining wall area=89% Tool deviation=64° '. N 1 of Finger= 14 Penetration=0.136 in. Apparent Chemical Cut 0.14 in.= 54%Wall Penetration HIGH SIDE= UP • • (14/.. PDS Report Cross Sections Well: 2M-09A Survey Date: June 12,2017 Field: Kuparuk Tool Type: UW MFC 24 No.211387 Company: ConocoPhillips Alaska,Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 3.5 in. 9.3 ppf L-80 EUE 8RD MOD Analyst: C.Waldrop Cross Section for Joint 128 at depth 4,110.479 ft. Tool speed=50 Nominal ID=2.992 Nominal OD=3.5 Remaining wall area=98% Tool deviation=70° i 1 I Minimum I.D.=2.783 in. Deposits Minimum I.D.=2.78 in. HIGH SIDE=UP • • KUP INJ 2M-09A C011000PtililpS611Welt Attributes MD TO — ww.m....0,P,..,00 0,00,1 Mao. 1,00000•1 SUM. Ire'in Angle &,resKai 00 Dim 110,81, Alaska,Ira. 5,21:320,--2. ..JP!.."L.,011Vf..0..),44T ,,,,u 69 17 4123t1 9.IC6 0 -• CodaIS(14:4,4 DM mecum.% Rite Min 040 -Me 111416.••15•16 777V ',L.,996 43 al 6,201992 /400.000.01 Owe,MPS) Sod DON AnnotamoI MOO By " 45173g G., 'a 01 .10•C 2 12,'2T-.2C 15 4e,.6.3sor '7,17 I_env:, GLV= '.. 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I:52.-37 '.2,77 II Liner Detaibi 010000.0 lb oo lest Us(7V0104/411. teows41 in dame= Coo Orb 4 1.5 r :6..345 5 55 52 PAA.:KER EAXER.e.-0T.I-AL-0.ER AA.,...,116-15ACK.0'LtEVE& 4 47.4...."10000uCTC0,4.5 C..i.2, --....." ., ' LOCATOA I 4 7321 7 HANGE r '4 2 341 5SA 4,73-2' t.'.044 0 63, .-6404,Gell 66 i 1=e, A6111 itAC J144R R 4 43- 13A),EA atke 4 a00 raPPui 6,34 %Cie- 179 2 36 45 kocatE C.AMCO 006 NIPPLE sr AVA 3 613-%Wu 6,15 2 313 I 1901B1..00K se 01)0 2.313B artorks s vA. ENTRY otiOa 100110/000rory0kion 100 004)I 2rD 6.1 1 Toe 4 (11,4.1? d lot 00010 AKA,,3,1 :ISO!04434n 3, f7"1:06, ,1144.A.441:060104.44_ , I 7.0 TO.101 11.0.111001%A Tubing Strings t.dt.qa Deoo00110-1 13-00.0 v a 140 any r,..0,001 1 001 0000. B ot D000,Ria i 4w1 mot, ona. hop conn•obon 2 1 2 Z.992 3-z L-' l2 9.36 5. 9 5.2 -6.2- E.,..1E6F33A-20 Completion Details hlanilnat le TOO 0410, 1100(7VO:OW" Toolot e, il..1044 Coo, 100 31.4 374 11.40 1153 22 44,60_E 0A 0 D. Ne/>0,6 224 HANGER 7 ` F,AC GEN IV 7HA JEING NGER 0A30 , 2 375 2.3.12 ... 4 676 6 2,434 2 63.36 .421=0„,6 0-444001N-1/3120,-E Z 312 ',, 1 1 '-- - ,7J, 42 -1'2", T--,. -....-E,_C',...4'.7m 1 Z 19.4 Other in Hole Wire/me retrievable plugs,valves,pumps,frSh,etc.) det LIFT 4 aro 1— * '‘',.e avna Top tr. I00,49101 (TEM Os 4 to."7 2.1.It' to.', c L)TTL71:314410 C"ENIC,...1.JT f,;79 5 36.04 =•...JCa • t.....e, Coen au,Da0, NO•,101 0441 T1.10000 4 1MP,o If P erf or a tions&Slots Rwri Dont Top ITVOI 000(190)— 010010 II TWOT2104 0 Si"""Qb 0 2 61135 7 °In* 4 C--4 A.5 -.1.6- , 1093 15 22 Pert? 2 e7.-ra:.1.Z arg 09A prta6e,00erl 11.1 leg °COIF 019.71505 • . v t.. . 2 375-4c,'Etc leg . - . prii416.°Merl 10.3 16.9 ...DCAtoit 4 P14,3 . * CCW F -39.1 0106 •..........- 9.49 921:42 5,04e-- 6.40 1 4..3.31,-05-4 7 1=1991 ' 4 C .5E40 2 374.,..C_.136 sag D11050,00001 16-Deg iii I OCVV F 'lir 12,K16 Mandrel Inserts 41 is ... on TOO MIDI N 6....To0"7: OOKIII1Vat. USA Pot)Ulm 0110 Oka MIMI 0110100W A.0110064000. 00100,ACTKM VOW WV 011101 COO 0 • '' 1,-,2 I 1 Notes:General&Safety 5,14 1936 362006 11'11 3012 MOO 14000 00 11o/ Ian 402Tieowel Tee,,,Der,Acer i.a4u.E0 a‘,...:2 :.;',..,:::_Ir''......,c17:, f a 179. ") OVER VOTE 166kVE3660110.E.L 01-1ALLOW aackEa•.v.0.0.6a pcjEcTION chity-^ 410-TE Irerf7.36114.0466 a A161.3.1-06114,...311c9 2 PIO POO,ONO Cam 11/13,101S ate 5,.2e 2 011 III ,.24.2 '0 14 171.E...410.a.$000'3110 VVFL r0120S 17a72.271 a .40TE miners'01.4C,U001 $1,602 0 0, 0 1 1,00 1.0 tattala*404 044 000 0 +010111 V*DI 0-111.10 0-- 0,010F 11 1000.0,214 • ‘gC0 �-o� • • 2co4o 1 WELL LOG TRANSMITTAL DATA LOGGED tO/1_1/2015 M.K.BENDER To: Alaska Oil and Gas Conservation Comm. October 23, 2015 Attn.: Makana Bender 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RECEIVED OCT 2 82+01+5 RE: Multi Finger Caliper(MFC)/Water Flow Log with TMD3D: 2M-09A AOGCC Run Date: 9/20/2015 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Fanny Sari, Halliburton Wireline &Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 FRS_ANC@halliburton.com 2M-09A Digital Data(LAS), Digital Log file, Casing Inspection Report, 3D Viewer 1 CD Rom 50-103-20177-01 Water Flow Log with TMD3D 1 Color Log 50-103-20177-01 sCAtitiEa PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline & Perforating Attn: Fanny Sari 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-275-2605 Fax: 907-273-3535 FRS_ANC@halliburton.com Date: Signed: M,40.4,1) � ,t • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: DATE: Friday,October 09,2015 Jim Regg P.I.Supervisor �Q(( I 91,`5 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2M-09A FROM: Jeff Jones KUPARUK RIV UNIT 2M-09A Petroleum Inspector Src: Inspector Reviewed By:T P.I.Supry J NON-CONFIDENTIAL Comm Well Name KUPARUK RIV UNIT 2M-09A API Well Number 50-103-20177-01-00 Inspector Name: Jeff Jones Permit Number: 196-090-0 Inspection Date: 9/25/2015 Insp Num: mitJJ150928083218 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 2M 09A , IType Inj W TVD 2936 - Tubing 2500 _ 2500 . 2500 - 2500 - PTD 1960900 - Type Test SPT Test psi 1500 - IA 1 610 1800 - 1740 - 1720 - ------------------- ---- Interval REQVAR P/F P OA 1 370 380 - 380 - 380 . Notes: MITIA per AIO 2B.004;0.8 BBLS diesel pumped, 1 well inspected,no exceptions noted. SCANNED ! - Friday,October 09,2015 Page 1 of 1 • • Wallace, Chris D (DOA) From: NSK Problem Well Supv <n1617@conocophillips.com> Sent: Monday, September 28, 2015 3:00 PM To: Wallace, Chris D (DOA) Subject: 2M-09 Water flow log and caliper in place of MIT-T .M-Col A en) 11 ( p'10o Chris- This is email is to serve as notification that the water flow log and caliper have been run on 2M-09 as required by A10 26.004. Below is a copy of the summary from each job for reference until the processed logs are received. PERFORM WATER FLOW LOG TO CONFIRM THAT THERE IS NO OUT OF ZONE INJECTION. LOGGED IMPULSE TESTS AT 9074, 9064, 9054, 9034, 8984, 8584, 8084, 7584, 7084, 6584, 6084, 5584, 5084,AND 4584'. NO TESTS INDICATE ANY UP FLOW. PROBLEM AREA FROM 790'TO 860', UNABLE TO DRIFT WITH 50' RIGID TOOL STRING, BROKE STRING DOWN TO LONGEST RIGID PIECE OF 25'. LOG CORRELATED TO SLB CEMENT BOND LOG DATED 03 NOV 1992. READY FOR E-LINE CALIPER LOG 24 ARM CALIPER SURVEY FROM 9100'TO SURFACE. DATA SENT TO ANCHORAGE FOR FURTHER PROCESSING. WELL BOL AND TURNED OVER TO DSO.JOB COMPLETE. Please contact myself or Jan Byrne with any questions or concerns. Dusty Freeborn /Jan Byrne Problem Wells Supervisor ConocoPhillips Alaska, Inc. Office phone: (907) 659-7126 Cell phone: (907) 943-0450 WELLS TEAM ConocoPhillips SCANNED AUG 1 12016 Pages NOT Scanned in this Well History File XHVZE This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. i c/~"-O~'~File Number of Well History File PAGES TO DELETE Complete RESCAN [] Color items - Pages: Grayscale, halftones, pictures, graphs, charts- Pages: Poor Quality Original- Pages: [] Other- Pages: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED [] Logs of various kinds [] Other COMMENTS: Scanned by: Bevedy~Vincent Nathan Lowell [] TO RE-SCAN Notes: Re-Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: Isl • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission ( DATE: Friday, November 04, 2011 TO: Jim Re 1 f P.I. Supeer isor t SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2M -09A FROM: J eff Jones KUPARUK RIV UNIT 2M -09A Petroleum Inspector Src: Inspector Reviewed By: P.I. Supry J NON Comm Comm Well Name: KUPARUK RIV UNIT 2M -09A API Well Number: 50- 103 - 20177 -01 -00 Inspector Name: JeffJones Insp Num: mitJJ111103162451 Permit Number: 196 - 090 - Inspection Date: 10/29/2011 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well ! 2M -09A • Type Inj. W TVD 2936 IA 534 3220 , 3175 3176 - P.T.D 1960900 TypeTest SPT Test psi 1500 . OA 300 380 380 380 - Interval 1 Q P/F P Tubing 2650 2650 2650 2650 , Notes: 1.5 BBLS diesel pumped. 1 well inspected; no exceptions noted. AIO 2B.004 Friday, November 04, 2011 Page 1 of I • • Page 1 of 1 Regg, James B (DOA) P m l �!�- oqo From: NSK Problem Well Supv [n1617 @conocophillips.com] Wefl Sent: Tuesday, November 01, 2011 10:48 AM I ' To: Regg, James B (DOA); Maunder, Thomas E (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Subject: Witnessed MIT's performed in KRU Attachments: MIT KRU 2M -09A 10- 29- 11.xls; MIT KRU 1Q -02B 10- 25- 11.xis; MIT KRU 2F- 0410- 25- 11.xls; MIT KRU 2M -09A 10- 28- 11.xis; MIT CRU CD4 -209 10- 30- 11.xis Tom, Jim Attached are the forms for the witnessed MIT's that were recently performed: 1 Q -02B: Performed on 10/25/11 post tubing patch installation 2F -04: Performed on 10/25/11 for upcoming AA submission 2M -09A: Performed on 10/28/11 & 10/29/11. The test on the 28th was non - witnessed and the test on the 29th was a witnessed re -test due to scheduling conflicts. The rest of the AA compliance testing on this well has been completed also and will be submitted as soon as the final processing of the logs and reports are complete. CD4 -209: Performed on 10/30/11 as per AIO 28.003 Please let me know if you have any questions. Brent Rogers / Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659 -7224 ; - _ -, ! , . . Pager (907) 659 -7000 pgr. 909 11/4/2011 1 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.reaciaalaska.00v; doa. aoacc.prudhoe.bavtaDalaska.aov; phoebe.brooks(caalaska.00v; tom.maunder(tDalaska.aov OPERATOR: ConocoPhillips Alaska Inc. FIELD / UNIT 1 PAD: Kuparuk / KRU / 2M ( c?", ( t((4-14 DATE: 10/28/11 OPERATOR REP: Ives / Bybee AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 2M -09A - Type Inj. W TVD / 2,936' Tubing 2,675 2,675 2,675 2,675 Interval V P.T.D. 1960900 ' Type test P Test psi ' 1500 Casing 500 3,200 3,095 3,050 P/F P ' Notes: Test as per AIO 26.004 (amended) OA 300 430 430 430 Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F • Notes: OA Well Type lnj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey T = Test during Workover W = Water D = Differential Temperature Test 0 = Other (describe in notes) Form 10 -426 (Revised 06/2010) MIT KRU 2M - 09A 10 28 11.xls Page 1 of Z • Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Tuesday, October 25, 2011 2:28 PM To: 'NSK Problem Well Supv' Cc: Regg, James B (DOA); DOA AOGCC Prudhoe Bay Subject: RE: 2M -09A (PTD 196 -090) Update on delay in compliance testing Brent, It is acceptable to delay and keep the well in service. Keep us advised. Tom Maunder, PE AOGCC From: NSK Problem Well Supv [ mailto :n1617 @conocophillips.com] Sent: Tuesday, October 25, 2011 2:26 PM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; NSK Problem Well Supv Subject: 2M -09A (PTD 196 -090) Update on delay in compliance testing Tom, We attempted to perform the required MITIA today on 2M -09A. There is currently a rig move blocking the road that will delay the testing. The North Slope weather is deteriorating due to high winds. After discussion with the North Slope inspector, ConocoPhillips would like to delay the MITIA for today and reschedule within the next couple of days depending upon the weather. Also as an update, the well work was able to get completed and the WFL was performed on 10/24/11. Please let me know if this is acceptable. Brent Rogers / Kelly Lyons Problem Wells Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659 -7224 Pager (907) 659 -7000 pgr. 909 , > ? 1 E `j From: NSK Problem Well Supv Sent: Sunday, October 23, 2011 10:41 AM To: Maunder, Thomas E (DOA); 'Regg, James B (DOA)' Cc: Schwartz, Guy L (DOA); NSK Problem Well Supv; Hazen, Mike C; Condio, John W; DOA AOGCC Prudhoe Bay Subject: 2M -09A (PTD 196 -090) Possible delay in compliance testing Tom, Jim Kuparuk water injector 2M -09A (PTD 196 -090) is due for its' 2 year compliance testing by 10/26/11 as per AIO 2B.004 amended. The caliper was completed on 10/21/11 and the plan was to perform the WFL on the next day. There were some problems getting the tools in and out of the well during the caliper due to suspected schmoo or asphaltenes. Further steps with Slickline such as brush and flush in attempts to clean up the tubing are being scheduled to aid in the WFL. This may create a delay in completing the compliance testing prior to the due date. The MITIA has been tentatively scheduled with the North Slope inspectors for Tuesday 10/25/11 so the WFL would be the only test that may be delayed. Once all of the testing has been completed, the results will be submitted all together. Please let me know if you have any questions. 10/25/2011 • • 9 ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510 -0360 " b June 30, 2011` tai' Commissioner Dan Seamount i L D 8 20 .1 v. • Alaska Oil and Gas Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 _D Q 6 Commissioner Dan Seamount: arm - Q ( Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of these wells was found to have a void in the conductor. These voids were filled with cement and corrosion inhibitor, engineered to prevent water from entering the annular space. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place and meets the requirements of form 10 -404, Report of Sundry Operations. The cement was pumped on 5/23, 2011. The corrosion inhibitor /sealant was pumped 6/22, 6/24, 6/25, 6/26, and 6/27, 2011. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call MJ Loveland or Martin Walters at 907 - 659 -7043, if you have any questions. Sincerely, MJ Lo land ConocoPhillips Well Integrity Projects Supervisor • • ConocoPhillips Alaska Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top -off Report of Sundry Operations (10 -404) Kuparuk Field Date 6130111 2F,2M,2N,2T,2X,2Z,3B,3O PAD Corrosion Initial top of Vol. of cement Final top of Cement top off Corrosion inhibitor/ Well Name API # PTD # cement _ pumped cement date inhibitor sealant date ft bbls ft gal 2F -19 50029227280000 1962010 8" _ N/A 23" N/A 13 6/25/2011 4 2M-09A 50103201770100 1960900 = SF - N/A 18" N/A 3.5 6/26/2011 2M -14 50103201730000 1920630 SF N/A 19" N/A 3.5 6/26/2011 2M -17 50103201500000 1910180 SF N/A 19" N/A 3.5 6/26/2011 2M -26 50103201720000 1920550 SF N/A 21" N/A 3.5 6/26/2011 2N -316 50103203420000 _ 2000900 SF N/A 18" N/A 4 6/27/2011 2N -318A 50103203430100 2090220 _ 10" N/A 27" _ N/A 7 6/27/2011 2T-40 50103205280000 2060400 2' N/A 2' _ N/A 6 6/26/2011 2T -202 50103202540000 1980370 6" N/A 20" N/A _ 9 6/26/2011 2X -07 50029209910000 1831130 SF N/A 21" N/A 2 6/25/2011 2X -08 50029209920000 1831140 SF N/A 21" _ N/A _ 2.5 6/25/2011 2Z -02 50029209600000 1830800 , 18" N/A 18" _ N/A 2.6 6/24/2011 3B -01 50029213180000 1850560 _ SF 1.50 17" _ 5/23/2011 6 6/22/2011 30 -12 50029218040000 1880410 2 SF N/A 22" N/A 1.7 6/22/2011 Page 1 of 2 C~ Maunder, Thomas E (DOA) From: NSK Well Integrity Proj [N1878@conocophillips.com] ___ _ _._. _ Sent: Tuesday, August 31, 2010 3:07 PM To: Maunder, Thomas E (DOA) Subject: RE: 2M-09 PTD 196-090 Schmoo. You are right. `;~k.:'~, ....- - mj From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Tuesday, August 31, 2010 2:16 PM To: NSK Well Integrity Proj Subject: RE: 2M-09 PTD 196-090 Thanks MJ. I've heard of Smoo or is it Schmoo, but didn't realize this was it. Tom From: NSK Well Integrity Proj [mailto:N1878@conocophillips.com] Sent: Tuesday, August 31, 2010 2:14 PM To: Maunder, Thomas E (DOA) Cc: NSK Problem Well Supv Subject: RE: 2M-09 PTD 196-090 Tom, Yes, It is common in our MI wells, we call it Smoo and treat it with "Smoo Be Gone" . It is an organic material from PWI that dries out with MI injection. The larger issue with this well is the lack of infectivity for MI. It is not a good candidate hence the withdrawal of the proposal. Let me know if you'd like more details. MJ Loveland From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Tuesday, August 31, 2010 12:01 PM To: NSK Well Integrity Proj Cc: Gauer, Jenn L; CPF2 Prod Engrs; NSK Problem Well Supv Subject: RE: 2M-09 PTD 196-090 Hi Perry, Catching up on messages ... Is encountering this residue common? I believe I've heard of such before. How common is such encounter in CPAI's operations? Thanks in advance, Tom Maunder, PE AOGCC From: NSK Well Integrity Proj [mailto:N1878@conocophillips.com] Sent: Tuesday, August 17, 2010 9:17 PM To: Maunder, Thomas E (DOA) Cc: Gauer, Jenn L; CPF2 Prod Engrs; NSK Problem Well Supv Subject: 2M-09 PTD 196-090 9/1/2010 Page 2 of 2 • Tom, On 6113/10 we attempted to pertorm a memory (PROF on 2M-09 while on MI injection. Slickline struggled to get tools down the wellbore and were unable to reach the target depth of 9240' md. Pressure and temperature data were recovered from the tool. However, both spinners were obstructed with wellbore residue of a tarry asphaultene like nature. The well was WAG'd back to water 7/1/10. On 7/23/10 slickline brushed and flushed the tubing. On 8/6/10 operations converted the well back to gas injection but it failed to take gas. The well was converted back to water injection 8/16/10 and will remain on water. We have decided to not pursue an AA for WAG injection in 2M-09. We appreciate the opportunity to attempt to get gas into this pattern for added FOR but don't believe it is feasible at this time. Let me know if you have any questions or if more is needed to close out our original request. Sincerely Perry Klein Well Integrity Projects 907-659-7043 9/1/2010 • • Page 1 of 1 Maunder, Thomas E (DOA) From: NSK Well Integrity Proj [N1878@conocophillips.com] Sent: Tuesday, August 17, 2010 9:17 PM To: Maunder, Thomas E (DOA) Cc: Gauer, Jenn L; CPF2 Prod Engrs; NSK Problem Well Supv Subject: 2M-09 PTD 196-090 Tom, On 6/13/10 we attempted to perform a memory (PROF on 2M-09 while on MI injection. Slickline struggled to get tools down the wellbore and were unable to reach the target depth of 9240' md. Pressure and temperature data were recovered from the tool. However, both spinners were obstructed with wellbore residue of a tarry asphaultene like nature. The well was WAG'd back to water 7/1/10. On 7/23/10 slickline brushed and flushed the tubing. On 8/6/10 operations converted the well back to gas injection but it failed to take gas. The well was converted back to water injection 8/16/10 and will remain on water. We have decided to not pursue an AA for WAG injection in 2M-09. We appreciate the opportunity to attempt to get gas into this pattern for added FOR but don't believe it is feasible at this time. Let me know if you have any questions or if more is needed to close out our original request. Sincerely Perry Klein Well Integrity Projects 907-659-7043 ~. ~.;~ ; , i-; st ~~~_ ~ ~ t 8/31/2010 Page 1 of 1 Maunder, Thomas E (DOA) From: NSK Well Integrity Proj [N1878@conocophillips.com] Sent: Sunday, April 25, 2010 5:55 AM To: Maunder, Thomas E (DOA) Cc: Schwartz, Guy L (DOA); Regg, James B (DOA); NSK Problem Well Supv; CPF2 Prod Engrs; Gauer, Jenn L Subject: 2M-09 WAG Injector PTD # 196-090 Notice of WAG to MI Tom, 2M-09 was converted to MI injection 4-22-10. The T/I/O = 3611/440/160 psi. The well is currently taking 843 MCF miscible injectant. The plan forward is to perform a memory IPROF in approximately two weeks followed by an water flow log once the MI slug is complete and the well has been retuned to PWI. Please let me know if you have any questions. Sincerely, Well Integrity Project Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7043 Cell Phone (907) 943-1244 Voice Pager 659-7000 x937 8/31/2010 • • Page 1 of 5 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Thursday, April 01, 2010 9:58 AM To: NSK Problem Well Supv Cc: Versteeg, Joseph R; NSK Well Integrity Proj Subject: RE: 2M-09A (PTD 196-090) Thanks Martin. I presume the baseline "gas" log has been accomplished. Keep us informed. Tom Maunder, PE AOGCC From: NSK Problem Well Supv [mailto:n1617@conocophillips.com] Sent: Thursday, April O1, 2010 9:27 AM To: Maunder, Thomas E (DOA) Cc: Versteeg, Joseph R; NSK Well Integrity Proj; NSK Problem Well Supv Subject: 2M-09A (PTD 196-090) Tom, CPAI plans to add 2M-09A to the WAG schedule on Monday, April 5, 2010. This should allow for the well to be placed on MI injection within the next 3 weeks. Martin From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Tuesday, March 23, 2010 11:54 AM To: NSK Problem Well Supv Subject: RE: 2M-09A (PTD 196-090) Brent or Martin, I was wondering what the present status of the MI injection into 2M-09A might be? Thanks in advance, Tom Maunder, PE AOGCC From: NSK Problem Well Supv [mailto:n1617@conocophillips.com] Sent: Thursday, February 18, 2010 8:52 AM To: Maunder, Thomas E (DOA) Subject: RE: 2M-09A (PTD 196-090) Tom, Perry will be in today. We will get the test going and give you an update. Brent Rogers/Martin Walters Problem Wells Supervisor ConocoPhillips Alaska, Inc. 8/31/2010 • ~ Page 2 of 5 Desk Phone (907) 659-7224 Pager (907) 659-7000 pgr. 909 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Thursday, February 18, 2010 8:50 AM To: NSK Problem Well Supv Cc: NSK Well Integrity Proj Subject: FW: 2M-09A (PTD 196-090) Hi Brent, I got a bounce back from MJ's box. Tom From: Maunder, Thomas E (DOA) Sent: Thursday, February 18, 2010 8:48 AM To: 'NSK Well Integrity Proj' Cc: Regg, James B (DOA); Schwartz, Guy L (DOA); NSK Problem Well Supv Subject: RE: 2M-09A (PTD 196-090) MJ, et al, Based on the file review, I am not aware of any further requirements prior to beginning the MI slug. Keep us advised as the work proceeds. Tom Maunder, PE AOGCC From: NSK Well Integrity Proj [mailto:N1878@conocophillips.com] Sent: Wednesday, February 10, 2010 1:12 PM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA); Schwartz, Guy L (DOA); NSK Problem Well Supv; NSK Well Integrity Proj Subject: FW: 2M-09A (PTD 196-090) Tom, We are ready for the MI gas slug in 2M-09A (PTD 196-090) and I wanted to confirm that we have approval from the Commission for the test. During the MI slug CoP will run a Memory spinner and then follow up with another sigma log after it is back on water to ensure in zone injection. Pending the results we will request a modification of the AA to allow MI as one of the injection fluids. Please advise. MJ Loveland Well Integrity Project Supervisor ConocoPhillips Alaska, Inc. Office (907) 659-7043 Cell (907) 943-1687 From: NSK Well Integrity Proj Sent: Monday, November 16, 2009 3:38 PM To: 'Maunder, Thomas E (DOA)' 8/31/2010 • • Page 3 of 5 Cc: NSK Problem Well Supv; Regg, James B (DOA); 'Schwartz, Guy L (DOA)'; NSK Well Integrity Proj Subject: RE: 2M-09A (PTD 196-090) Tom, Both Brent and Martin are off slope. Per your questions below. 1. PDS files should be viewable from Adobe or the viewer is a free down load available from the HES website. 2. We are not planning on repeating the MITIA, the last MITIA was 10/26/09 witnessed by John Crisp. We do not internally require a higher test pressure and the AOGCC required test pressure was met on the above test 3. We will complete a sigma baseline before and after a 10-12 MI cycle looking for gas migration. I suspect the base line sigma log will be run the beginning of December, followed by a 10-12 week MI cycle, then 7-10 days of water injection, then the follow up sigma log. Please let me know if you have any questions. Regards MJ Loveland Well Integrity Project Supervisor ConocoPhillips Alaska, Inc. Office (907) 659-7043 Cell (907) 943-1687 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@Alaska.gov] Sent: Monday, November 16, 2009 3:13 PM To: NSK Problem Well Supv Cc: Regg, James B (DOA); Schwartz, Guy L (DOA); DOA AOGCC Prudhoe Bay; NSK Well Integrity Proj Subject: RE: 2M-09A (PTD 196-090) Brent or Martin, What is the status on the 2M-09A assessment? Thanks in advance, Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) Sent: Wednesday, October 28, 2009 10:43 AM To: 'NSK Problem Well Supv' Cc: Regg, James B (DOA); Schwartz, Guy L (DOA); DOA AOGCC Prudhoe Bay; NSK Well Integrity Proj Subject: RE: 2M-09A (PTD 196-090) Brent, Following up on our conversation and this message trail ... 1. Regarding an electronic copy, with your change in service providers we don't have a viewer to electronically look at their logs. Pieces would have to be converted to pdf. 2. You indicated that the MI request and routine compliance testing timing aligned to be more or less simultaneous. The accomplished MIT does demonstrate the integrity of the casing above the packer, however it 8/31 /2010 • ~ Page 4 of 5 is likely that the surface pressure with MI would be considerably greater than 1500 psi. You indicated that internally it would be required to test the IA to about 3000 psi prior to starting MI. When that test is accomplished, please contact the Inspectors regarding witness and supply the testing form per usual. 3. Provided the 3000 psi MIT is accomplished successfully and based on your assessment of the WFL diagnostic information gathered, it is acceptable for CPAI to move forward with Sigma log and initiation of the MI injection. How long of an initial MI injection period is planned before the follow up Sigma log will be run? I look forward to your reply. Tom Maunder, PE AOGCC From: NSK Problem Well Supv [mailto:n1617@conocophillips.com] Sent: Tuesday, October 27, 2009 2:37 PM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA); Schwartz, Guy L (DOA); Fleckenstein, Robert J (DOA); DOA AOGCC Prudhoe Bay; NSK Problem Well Supv; NSK Well Integrity Proj Subject: RE: 2M-09A (PTD 196-090) Completed AA compliance testing Tom, I do not have an electronic copy of the log to send you. I believe you will get your copy through the normal distribution. The time line for the gas injection has not been set yet as we were waiting for approval from the AOGCC for planning. Once approval is given, the Sigma reservoir log will be scheduled and the test cycle on gas will begin. Please let me know if you have any further questions. Brent Rogers/Martin Walters Problem Wells Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7224 Pager (907) 659-7000 pgr. 909 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Tuesday, October 27, 2009 1:44 PM To: NSK Problem Well Supv Cc: Regg, James B (DOA); Schwartz, Guy L (DOA); Fleckenstein, Robert J (DOA); DOA AOGCC Prudhoe Bay Subject: RE: 2M-09A (PTD 196-090) Completed AA compliance testing Brent, Do you have an electronic copy of the log that can be sent? I have looked at the records for 1A-04A. The situation of 2M-09A seems similar. It appears that integrity has been demonstrated. What schedule is planned for the initial MI injection? Has the baseline "gas" log been run? Tom Maunder, PE AOGCC From: NSK Problem Well Supv [mailto:n1617@conocophillips.com] Sent: Tuesday, October 27, 2009 10:35 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA); Schwartz, Guy L (DOA); Fleckenstein, Robert J (DOA); DOA AOGCC Prudhoe Bay Cc: NSK Problem Well Supv Subject: 2M-09A (PTD 196-090) Completed AA compliance testing Tom, Jim, Guy, Bob 8/31/2010 • • Page 5 of 5 The compliance testing for AIO 26.004 (amended) has been completed on Kuparuk water injector 2M-09A (PTD 196-090). The caliper log was completed on 10/13/09. Below is a summary from the IPROF and the WFL confirming zonal isolation. Also attached is the witnessed MITIA form that was performed on 10/26/09. 10/20/09: PERFORMED INJECTION PROFILE. RATE = 1100 BPD, 2419 PRESSURE, AT 129 DEGREES A/C SPLITS: CSANDS = 0%, A-4 SANDS = 75%, A-3 SANDS = 25% THERE WEREN'T ANY LEAKS OBSERVED AT TIME OF LOG AND CROSSFLOW WAS NOT OBSERVED. 10/25/09: PERFORMED SPECTRA FLOW /WATER FLOW LOG FROM TOP OF PERFS AT 9084' UP TO PACKER AT 4717'. NO LEAKS FOUND IN LINER AND NO UPFLOW DETECTED BEHIND LINER WITH THE WELL INJECTING AT 1800 BPD AT 2600 PSI. Please let me know if you have any questions. Brent Rogers/Martin Walters Problem Wells Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907) 659-7224 Pager (907) 659-7000 pgr. 909 8/31/2010 • • WELL LOG TRANSMITTAL To: Alaska Oil and Gas Conservation Comm. Attn.: Christine Mahnken 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: TDML.Sigma Log: 2M-09A Run Date: 12/31/2009 May 14, 2010 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Rafael Barreto, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 2M-09A Digital Data in LAS format,. Digital Log Image file 50-103-20177-01 TMDL Sigma Log 50-103-20177-01 .u 1 CD Rom 1 Color Log PLEASE ACKNOWLEDGE RECEII'T BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline & Perforating Attn: Rafael Barreto 6900 Arctic Blvd. ~ ~. ~ Anchorage, Alaska 99518 Office: 907-273-3527 Fax:907-273-3535 .. ~,, rafael barretq> ~~~ ~ ~=~~,. Date: .: ~ . w ~:~ /~~ -p4 b ~(v~"~ Signed: ~ MEMORANDUM To: Jim Regg ~~' (i((Z c~ t~ j P.I. Supervisor FROM: JCr C"~ I S~' Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Friday, October 30, 2009 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2M-09A KUPARUK RIV UNIT 2M-09A Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv l~~ Comm Well Name: KUPARUK RIV UNIT 2M-09A API Well Number: 50-]03-20177-O1-00 Inspector Name: JCr Insp Num: mitJCr091029135054 P ermit Number: .196-090-0 Inspection Date: 10/26/2009 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. - Well 2M-09A ~,lypelnJ.TW TVD 1960900 ~ SPT ~ p,T~ TypeTest ~ Test psi ~ - ~. Interval xEQvAx P/F P `~ 2936 '~ IA 1500 OA -~. Tubing _ 1140 2020` -- 500 600 i --r-- 26so ~ 26so 1990 i 1990T - 600 600 , ~ _ - ~ 26so z6so ~ _ _ Notes: 1 bbl pumped for test. Friday, October 30, 2009 Page 1 of 1 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:jim.regg~alaska.gov; tom.maunder~alaska.gov;bob.fleclcenstein~alaska.gov;doa.aogcc.prudtme.bay~alaska.gov Email to:guy.schwartz~alaska.gov OPERATOR: ConocoPhillips Alaska Inc. FIELD /UNIT /PAD: Kuparuk /KRU / 2M DATE: 1026/09 OPERATOR REP: Colee /Phillips - AES AOGCC REP: John Cusp Packer Pretest Initial 15 Min. 30 Min. We11 2M-09A T In'. W TVD 2,936' T 2,650 2,650 2,~0 2,650 Interval V P.T.D. 1960900 T test P Test 1500 1,140 2,020 1,990 1,990 P/F P Notes: Test per AIO 26.004 (amended) OA 500 600 600 600 Well T Iri . TVD Tubi Interval P.T.D. T test Test Casi P/F Notes: OA Well T In'. N TVD T Interval P.T.D. T best P Test Cali P/F Notes: OA Well T In'. TVD Tu ' Interval P.T.D. T test Test P/F Notes: OA Well T In'. TVD Tubi Interval P.T.D. T test Test Casi P/F Notes: OA TYPE INJ Codes D =Drilling Waste G=Gas I =Industrial Wastewater N =Not Injecting W =Water TYPE TEST Codes M = Annukrs Monitoring P = Stan~rd Pressure Test R = Intemal Radioactive Tracer Survey A =Temperature Anomaly Survey D = DilfererNral Temperature Test INTERVAL Codes I =Initial Test 4 =Four Year Cycle V =Required by Variance T =Test during Workover O = Oft-er (describe in notes) MIT Report Form BFL 11/27/07 MIT KRU 2M-09A 10-26-09.x15 Page 1 of 1 Maunder, Thomas E (DOA) From: NSK Well Integrity Proj [N1878@conocophillips.com] Sent: Monday, October 19, 2009 4:29 PM To: Regg, James B (DOA); Schwartz, Guy L (DOA); Maunder, Thomas E (DOA) Subject: FW: 2M-09A (PTD 196-090 AA AIO 2B-004) Attachments: 2 M-09A. pdf A schematic is attached for your reference From: NSK Well Integrity Proj Sent: Monday, October 19, 2009 4:28 PM To: Regg, James B (DOA); Schwartz, Guy L (DOA); 'Maunder, Thomas E (DOA)' Cc: NSK Problem Well Supv; NSK Well Integrity Proj; Versteeg, Joseph R Subject: 2M-09A (PTD 196-090 AA AIO 2B-004) Jim/Guy/Tom The ConocoPhillips Reservoir and Development groups in town have requested that I contact the Commission and request a modification of AA AIO 2B.004 for well 2M-09A (PTD 196-090) to allow MI gas injection. This well is similar to 1A-04A 04A (PTD 200-194) where the AA was just modified for the same reason. The well, 2M-09A, does not have any known integrity issues, however does have an active AA because it does not meet the requirements of 20 AAC 25.314 (b) as the packer is greater than 200' above the perforations. Since the purpose of the requirement is to ensure that the injection string can be monitored throughout its length for possible leakage, ConocoPhillips proposes the current integrity testing of a 2 year MITIA and 2 Year waterflow/caliper log will suffice to continue confirm long term well bore integrity. Similar to 1A-04A, if approved by the Commission, ConocoPhillips will run a Sigma reservoir tool before and after a short MI cycle to prove that the gas is staying in zone. Pending the results of the Sigma log and MI cycle, we would apply for a modification of AA AIO 26-004 to allow MI. Please advise if this proposal is acceptable and if a test MI cycle is allowed. Regards MJ Loveland Well Integrity Project Supervisor ConocoPhillips Alaska, Inc. Office (907) 659-7043 Cell (907) 943-1687 8/31/2010 r~ NIP (514-5 OD:3.5 TUBI (0~7 OD:3.5 ID:2.9 Gas 3ndrel/Dun vah (4631-4f OD:5.E PRA CAS (OAS OD:7.( wt:2s (46771 OD:3.! (4717-4 OD:6. SPACE (4718-4 OD:3. (a71 s~ OD:3. (9017-9 OD:S. LI (4717-5 OD:4. Wt:1: (9084 f (9104-4 (9149= ConocoPhillips Alaska, Inc. ~KRU 2M-09A 2M-09A API: 501032017701 Well T INJ An le TS: 36 d 9084 SSSV Type: NIPPLE Orig Com etion: 6/14/1996 Angle @ TD: 33 deg @9405 Annular Fluid: Last W/O: Rev Reason: RKB TAG Reference L Ref L Date: Last U ate: 11/26/2007 15, Do) Last Ta : 9292 TD: 9405 ftKB NG Last Ta Date: 11/25/2007 Max Hole An le: 69 d 4124 oo; Casin Strin -CONDUCTOR 92) Descri tlon Size To Bottom ND Wt Grade Thread CONDUCTOR 16.000 0 121 121 62.50 H-40 Casin Strin -SURFACE Descri lion Size To Bottom ND Wt Grade Thread SUR. CASING 9.625 0 4306 2775 40.00 L-80 Casin Strin -PRODUCTION Abandoned Ori final Wellbore~ Sidetrack Kick Off 4980' Descri lion Size To Bottom ND Wt Grade Thread Lift PROD. CASING 7.000 0 4980 3043 26.00 L-80 my Casin Strin -LINER re 1 ^ Descri lion Size To Bottom ND 1Mt Grade Thread 32' 63) LINER 4.500 4717 9402 6297 12.60 L-80 - TUBING i T bi S ~D. NG tr n - u n Size To Bottom TVD Wt Grade Thread Leo, 00 3.500 0 4719 2937 9.30 L-80 EUE 8RD MOD i , oo> Pertorations Summa Interval TVD Zone Status Ft SPF Date T e Comment 9084 - 9096 6036 - 6046 C-4,A-5 12 3 7/10/1996 IPERF 2 1/8" HC, 180 deg. phase; oriented 165 deg. CCW F/ Hi h Si NIP .7a' .00) 9104 - 9133 6052 - 6076 A-4 29 3 7/10/1996 IPERF 2 1/8" HC, 180 deg. phase; oriented 165 deg. CCW F/ Hi h Si 9149 - 9214 6089 - 6142 A-3 65 4 7/10/1996 IPERF 2 1/8" HC, 180 deg. phase; oriented 165 deg. CCW F/ Hi h Si Gas Lift MandrelsNalves St MD ND Man Mfr Man Type V Mfr V Type V OD Latch Port TRO Date Run Vlv Cmnt 1 4631 2901 Camco MMM DMY 1.5 RK 0.000 0 6/14/1996 rKe Other lu s e ui .etc. -JEWELRY 151) De th ND T e Descri lion ID cur 514 513 NIP Camco'DS' Ni a NO GO 2.812 719, soD) 4677 2919 NIP Camco'W-1' 2.812 TTL 4717 2936 PKR Baker 'ZXP' w/ 7.39' C2 Tie Back Sieeve 4.438 /20, i0o) 4718 2936 SPACE OUT 2.992 4719 2937 TTL 2.992 9017 5981 NIP Camco 5" X 3.813" DB5 Nipple w/3.81 maxi big bore lock w/Otis 2.313" X rofile & WL ent uide 2.313 Gener al Notes Date Note NIP -- 2/6/2006 NOTE: WAIVERED WELL: SHALLOW PACKER **WATER INJECTION ONLY** D18, DDO) VER - 402, 500, !.60) Perf 096) Pert 133) Pert 1214) - - ELL LOG TRANSMITTAL To: Alaska Oil and Gas Conservation Comm. Attn.: Christine Mahnken 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: Water Flow Log: 2M-09A Run Date: 10/2/2009 • November 13, 2009 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention o£ Rafael Barreto, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 2M-09A Digital Data in LAS format, Digital Log Image file, Interpretation Report 1 CD Rom 50-103-20177-O1 Spectra Flow Log 50-103-20177-01 1 Color Log PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline & Perforating Attn: Rafael Barreto 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-273-3527 Fay: 907-273-3535 rafael.ban~eto~~11al1iburton.coin ~J~~C c~~ ~ b~ ~ ~' ~~ Date: Signed: PROACTIVE DIAgNOSTIC SERVICES INC. To: AOGCC Christine Mahnken 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 (907j 659-5102 RE : Cased Hole/Open Hole/Mechanical Logs and/or Tubing Inspection(Caliper/ MTT) The technical data listed below is being submitted herewith. Please acknowledge receipt by returning a signed copy of this transmittal letter to the following ProActive Diagnostic Services, Inc. Attn: Robert A. Richey 130 West International Airport Road ~,~~ ~ ~ ~ ~ ~ X009 Suite C Anchorage, AK 99518 Fax. (907J 2458952 1/~,~LL L.~iC T~.4fifSli~/T~T~L 1 j Caliper Report 13.Oct-09 2M-09A 1 Report / EDE 50-103-20177-01 2j vac l~i~ -~~o ~~~a Signed Print Name: Date PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AK 99518 PHONE: (907)245-8951 FAX: (907)245-88952 E-MAIL ;: :i ; ; '' [ -: ~) ' . r` I WEBSITE : ' ' °,5 C:\DocutnenG and Settings\Owner~Desf.'toplTzattismit_Conoco.docx • ~ Memory Multi~-Finger Caliper s ~og Results Summary Company_ ConocoPhillips Alaska, lnc. Well: 2M-09A Log Date: October 13, 2009 Field: Kuparuk Log No. : 10599 State: Alaska Run No.: 2 API No.: 50-103-20177-01 Pipe9 Desc.: 3.5" 9.3 Ib. L-80 EUE 8RD MOD Top Log Intvl1.: 5urtace Pipe1 Use: Tubing Bot. Log Intvl1.: 4,740 Ft. (MD) Pipe2 Desc.: 4.5" 12.6 Ib. L-80 Top Log Intvl2.: 4,740 Ft. (MD) Pipe2 Use: Liner Bot. Log Intvl2.: 9,093 Ft. (MD} Inspection Type : Corrosive 8 A~echanical Damage Inspection ~ COMMENTS : ~ This caliper data is tied into the Camco UB5 Nipple @ 9,01T' (Driller's Depth). This log was run to assess the condition of the tubing and liner with respect ta corrosive and mechanical damage. The caliper recordings indicate the 3.5" tubing is in good to fair condition, with a maximum wall ' penetration of 28% recorded at an isolated pit in joint 27 (913'). Record~d damage appeats as isolated pitting and shallow corrosion. No significant areas of cross-sectiona( wafl loss qr I.D. restrietions are recorded. The caliper recordings indicate slight buckling throughout the 3.5" tubing. ~ The caliper recordings indicate the 4.5" liner logged is in good to poor condition with respect to corrosive artd meehanical damage, w~h a maximum recorded watl penetration of 43°/a recorded in an area of corrosian in jnint 92 (7,479'). Recorded damage appears as general corrosion throughout the liner logged and isoiated pitting. No significant areas of cross-sectional wall loss are recorded throughout the liner logged. Deposits ' restrict fihe I.D. to 2.74" in joint 146 (9,085'). A graph illustrating minimum recorded diameters on a joint-by- joint basis of the 4.5" liner lagged is included in this repart. The caliper recordings indicate bends in the 4.5" tiner logged from --8,57Q' to ~8,578', end -9,08~' to ~9,088", ' restricting the I.D. to 3.65" in joint 129 (8,576'). The caliper recordings also indicate buckling ftam -5,000' to -5,050', ~5,160' to ~5,270', -6,79d', -7,120', and ~9,050'. This is the second time a PDS caliper has been run in this well and tfie tubing and liner have been logged. A ' Companson of the current ahd previous log (September 28, 2007) indicates a slight increase in corrosive damage in the 3.5" tubing and an increase in corrosive damage in the 4.5" liner logged during the time between togs. Gr~phs illustrating the difference in maximum recorded penetrations on a joint-by joint basis ~ between the curren# and previous log of the 3.5" tubing and 4.5" liner logged are included in this report. 3.5" TUBING - MAXIMUM RECORDED WALL PENETRAl10NS: Isolated pitting ( 28%j Jt. 2~ @ 913 Ft. (MD} --- Isolated pitting ( 28%) Jt. 26 ~ 886 Ft. (MD) Iso{ated pitting ( 28%) Jt. ~40 @ 1,303 Ft. (MD) Isolated pitting ( 24%) Jt. 28 ~ 944 Ft. (MD) Isolated pitting ( 24%) Jt. 36 ~ 1,203 Ft. (MD) 3.5" TUBING - MAXIMUM RECOf~DED CROSS~SECTIQNAL ME~~~~,~{~~;~ ;~i~ ,1 ~~ ~~ ~~Q~ No significant areas of cross-se~fional wall loss (> 9%) ere recorded. ProActive Diagnostic Services, Inc. / P.O. Box 1369, Stafford, TX 77497 Phone: (281) or (88S) 565-9085 Fax: (281) 565-1369 E-mail: PDS@memorylog.com Prudhoe Bay Field Office Phone: (907} b59-2307 Fax: (907) 659-2314 V s c !q ~o ~ ~q 6 l'~ `~ d ~ • ~ I', , 3.5" TUBING - MAXIMUM RECORDED ID RESTRICTIONS: _ No signiflcant I.D. restrictions are recorded. 4.5" LINER - MAXIMUM RECORDED WALL PENETRATIt}NS: ~ Corrosion ( 43%) Jt. 92 ~ 7,479 Ft. (MD) Corrosion ( 42%) Jt. 97 ~ 7,618 Ft. (MD) Corrosion ( 39%) Jt. 102 ~ 7,760 Ft. (MD) Corrosion ( 39%) Jt. 145 ~ 9,077 Ft. (MD) ~ Corrosion ( 37°r6) Jt. 86 ~ 7,278 Ft. (Mp) 4.5" LINER - MAXIMUM RECORDED CROSS-SECTiONAL METAL ~OSS: ', No significant areas of cross,sectional wall loss (> 13%) are recorded throu ho ut the liner lo ed g gg . 4.5" LINER - MAXIMUM RECORDED ID RESTRICTIONS: ~ beposits Minimum I.D. = 2.74" Jt. 146 ~ 9,Q85 Ft. (MD) Bend Minimum I.D. = 3.65" Jt. 129 @ 8,576 ~t. (MD) Deposits Minimum I.D. = 3.65" Jt. 63 @ 6,587 Ft. (MD) ~ Deposits Minimum I.D. = 3.68" Jt. 23 ~ 5,495 Ft. (MD) ' Deposits Minimum I.D. = 3.71" Jt. 39 c~ 5,884 Ft. (MD) ~ ~ ', ~ Field Engineer. G. Etherton Analyst: C. Wa/drop Witness: C. Fitzpatrick ProAetive Diagnostic Services, Inc. J P.O. Box i369, Staffora, TX 77497 Phone: (281) or {888) 5b5-9085 Fax: {Z81) 565-1369 E-mail: PDS@memorylog.com Prudhoe Bay Field ~ffice Phone: (907) 659-2307 Fax: (94?} 659-231.4 II 1 ~ i ~ ~ Correlation of Recorded Damage to Borehole Profile , Pipe 1 3.5 in (22.3' - 4740.8') Well: 2M-09A Pipe 2 4.5 in (4740.8' - 9083.9') Field: Kuparuk Company: ConocoPhillips Alaska, Inc. Country: USA Survey Date: October 13, 2009 ^ Approx. Tool Deviation ^ Approx. Borehole Profile 1 26 82 ~ 1615 2407 3199 3990 GLM 1 4741 ~ ~ 5455 ~ c 6197 Q v ~ 6944 7694 8445 146 9084 0 50 100 Damage Profile (% wall) / Tool Deviation (degrees) Bottom of Survey = 146 25 ~ ~ Y. 50 75 ~. 100 125 1 ~ 25 E ~ Z ~ c O -` ~~ , ..,., 100 ~ ~ 125 ~ \J c Maximum Recorded Penetration ~-1. J.; Comparison To Previous Weli: 2M-09A Survey Date: October 13, 2009 Field: Kuparuk Prev. Date: September 28, 2007 Company. ConocoPhillips Alaska, Inc. Tool: UW MFC 24 No. 212330 COU~Uy: USA Tubing: 3.s 9.3 Ib L~0 EUE 8RD MOU C7VP~IaV 0 5 Max. Re 0 1 c. Pen. ( 00 1 mils) 50 2 00 25 0 0.1 7 14.3 24 34 44 54 64 E~ 74 Z S 84 - 94 104 114 124 134 144 ^October 13, 2009 ^September 28, 2007 Difference Diff. in Max. Pen. (mis) -50 -25 0 2 5 5 0 ' ~ - i ~ - E ~ 143 2d _.. 1 i ~ ~ 34 ~ I I ~ i 59-' ~ 64 __ _- - -- ~ i ~ 74 Z ~ ~ b 84 ~ 94 i i I ~ 104 I I i 114 j 124 I 134 I I ~ 144 -24 -12 0 1 2 2 4 Approx. Corrosion Rate (mp y) ~ ~ PDS Report Overview 1 ~~ Body Region Analysis Well: 2M-09A Survey Date: October 13, 2009 Field: Kuparuk Tool Type: UW MFC 24 No. 212330 Company: ConocoPhillips Alaska, Inc. Tool Sir_e: 1.69 Country: USA No. of fingers: 24 Anal st: C. Waldro Tubing: Nom.OD Weight Grade & lliread Norn.ID Nom. Upset Upper len. Lower len. 3.5 i~s 9.3 f L-80 EUE 8RD MOD 2.992 ins 3.5 ins 6.0 ins 6.0 ins Penetration and Metal Loss (9'o wall) ~ penetration body ,,>::.- metal loss body 150 100 50 ~ 0 to 1 to 10 to 1% 10% 20% 20 to 40 to over 40% 85% 85% Number of'oints anal se d total = 156 pene loss . 0 21 124 51 105 0 11 0 0 0 0 0 Damage Configuration ( body ) 150 100 SO 0 ~ isolated generaJ Ifne nr~ hole / poss pitting corrosion cormsion corrosion i61e hole Number of ~oints dama ed total = 111 101 10 0 0 0 Damage Profile (% wall) ~ penetration body ;~,y metal loss body 0 50 100 n GLM 1 Bottorn of Survey = 147.1 Analysis Overview page 2 ~ ~ PDS REPORT JOINT TABULATION SHEET Pipe: 3.5 in 93 ppf I_-80 EUE 8RD MOD Well: 2M-09A Body Wall: 0.254 in Field: Kuparuk Upset Wall: 0.254 in Company: ConocoPhillips Alaska, Inc Nominal I.D.: 2.992 in Country: USA Survey Date: October 13, 2009 )oint No. Jt. Depth (Ft.) Pc~n. ~ lE~s~~t 41n~.) Pen. Body (Ins.) Pen. °io ~1c~tal I c~ss `i~ Min. I.D. (Ins.) Comments Damage Profile (%wall) 0 50 100 .1 22 ii 0.01 ~ U 2.94 PUP 1 26 U 0.01 ~1 I 2. 3 Sli ht bucklin . 1.1 59 t~ 0.03 11 -l 2.92 PUP 1.2 66 O 0.01 4 2.95 PUN 1.3 72 ~1 0.01 0 2.91 PUP 2 81 l~ 0.02 i I 2.94 3 114 t1 0.01 6 I 2.93 4 146 i i 0.02 7 1 '1.94 Sli ht bucklin . 5 177 ~~ 0.03 10 I 2.94 6 209 U 0.02 9 ~~ 2.93 7 241 (~ 0.01 4 ? 2.92 8 272 (~ 0.03 12 1 '1.92 9 304 U 0.02 9 I .93 Sli h bucldin . 0 336 U 0.0 1" ? 2.94 11 367 U 0.04 1 S I 2.92 Shallow ~ittin . 12 399 u 0.04 15 2.93 Shallow ittin . 13 431 U O.D6 22 2.93 Isolated ittin . Lt De osits. 14 463 l~ .05 ZU ~> 2.92 Isolated 'ttin . 14.1 495 c~ 0.03 12 2.92 PUP 14.2 501 t~ 0 il ~) 2.81 Ca nco DS-Ni le No Go 143 502 (1 0.01 (i 1 2 98 PUP 15 508 t? 0.03 12 -3 2.93 Sli ht bucklin . 16 539 i) .04 lt3 t~ 2.92 Shallow ittin . 17 571 U 0.05 20 i 2.94 Shallow corrosion. 18 602 ~? 0.03 Li i~ 2.93 Shallow ittin . 19 633 t~ 0.05 20 ~l 292 Isolated ittin . 20 665 ~~ 0.03 1 1 !~ 2.93 21 697 U 0.03 11 ~ 2.93 Sli ht bucklin . 22 729 U 0.03 ~ 3 5 2.94 Shallow ittin . 23 760 l1 0.05 18 4 2.93 Shallow ittin . 4 791 U .05 ~' 1 t3 2.93 Isolated ittin . 25 823 U 0.05 18 a 2.93 Shallow ittin . 26 855 l1 0.07 Zt3 ~ 2.94 lsolated ittin . 27 887 U 0.07 ~~8 5 2.94 Isolated itt~in . 28 918 O 0.06 1d ~3 2.93 Isolated ittin . ~ 29 950 l) 0.05 2l1 i 2.93 Corrosion. Sli ht bucklin . 30 982 U 0.05 11 _' 2.93 Isolated ittin . 31 1014 l) 0.05 Zi) 2.93 Isolated itfin . 32 1045 ~) 0.05 ZU -t ,94 C rrosion. 33 7077 t) 0.04 18 t, 2.94 Shallow corrosion. 34 1 09 U 0.05 ~l) 2.93 Isolated ittin . 35 1140 U 0.06 13 - 2.94 Isolated ittin . 36 1172 U 0.06 ~4 ~ 2.93 Isolated ittin . 37 1204 ~~ 0.05 I~) ~ 2.94 Shallow ittin . 38 1236 t~ 0.05 1~) '~ 2.93 hallow corr sion. 39 1268 U 0.04 1(i ~ 2.94 Shallow ittin . Sli ht bucklin . 40 1300 O 0.07 1t3 2.93 Isol~ ted iltin . 41 1331 U 0.05 2U i 2.94 Shallow ittin . 42 1363 u 0.04 1(i ') 2.93 Shallow ittin . 43 1394 t7 0.04 14 ~~ Z.93 Shallow ittin . PeneUation Body ~ Metal Loss Body Page 1 • ~ PDS REPORT JOINT TABULATION SHEET Pipe: 3.5 in 9.3 ppf L-80 EUE 8RD MOD Well: 2M-09A Body Wall: 0.254 in Field: Kuparuk Upset Wall: 0.254 in Company: ConocoPhillips Alaska, Inc. Nominal I.D.: 2.992 in Country: USA Survey Date: October 13, 2009 )oint No. )t. Depth (Ft.) I'~~n. l lF~cc~i (In~.) Pen. Body (Ins.) Nen. % ~1c~t,~l I oss °~~ Min. I.D. (Ins.) Comments Damage Profile (%wall) 0 50 100 44 1426 ~~ 0.03 11 -! . 2 45 1457 i~ 0.03 l t -} 2.92 Shallow ittin . 46 14F39 U 0.03 I1 i .93 47 1521 ~~ 0.04 I ~ S 2.93 Shallow ittin . 48 1552 u 0.03 l li I 2.93 Sli ht BucMin . 49 1584 t) .06 ~'-1 -~ 2.93 Isolated ittin . 50 1615 ~~ 0.04 I~ 2.91 Shallow ittin . 51 1647 t i 0.04 1 5 1 .93 Shallow ittin . 5 1679 U 0.03 I~ ~ .93 53 17 0 i~ 0.02 ~) I 2.93 4 1742 t) OA2 £3 2.93 Sli ht cklin . 55 1774 ti . 3 l i i 2.93 Shallow ittin . 56 1805 u 0.03 12 7 2.91 57 1837 c~ 0.04 14 I 2.93 Shall w ittin . 58 1869 u 0.03 11 1 .93 59 1901 t~ .02 ~~ 5 2.93 6 1933 U 0.03 l i I 2.92 Shallow ittin . 61 1964 U 0.02 ti d 2.91 62 1996 ~~ 0.02 ~) 1 2.93 S i ht buc i. 63 2028 ~~ 0.03 11 -l .93 64 2060 ~ ~ 0.03 I ~ ~ -4 .93 65 2089 i 1 Qp3 I~ 2.93 66 2122 ~~ 0 03 1 1 ' 2.93 67 2153 U 0.03 1 i ? 2.93 Shallow ittin . 2185 i~ 0. 4 I-1 ' 2.93 Shallow ittin . 69 2217 U 0.04 I-1 2.93 Shallow corrosion. Lt. De osits. 70 2 49 u 0.04 I-1 ~ 2.91 Shallow ittin . 71 2281 t~ 0.03 1 1 ~ 2.94 Sli ht bucklin . 7 2312 (~ 0.0 ~) -~ 2.93 73 2344 t) 0.04 14 ~ 2.93 Shallow ittin . 74 2375 U 0.04 14 5 2.91 ha low it ~n . 75 2407 l~ 0.03 13 -1 2.91 Shallow ittin . 76 2439 u 0.03 1~~ .92 77 2470 1) 0.03 1 1 -i .91 Sli ht bucklin . 78 2501 tt 0.04 lE~ ' 2.92 Shallow ittin . 79 2533 I) 0.03 11 -1 2.91 80 2564 U 0.03 1 ~ .93 Shallow ittin . 81 2596 ~~ 0.04 l~ ~1 2.90 Shallow ittin . 2 2628 U 0.04 I(, -I 2.93 hallow ittin . Lt. De its. II3 2659 U 0.04 14 I 2.92 Shallow ~ittin . 84 2691 U 0. 4 17 ' 29 Shallow ittin . 85 2723 ~1 0.03 I:~ _' 2.93 Shallow ittin . Sli htbucklin . 86 755 U 0.04 1 5 ~ 2.90 Shallow ittin . t. De sits. 87 787 ~1 0.05 I t5 -l 2.91 Shallow ittin . 88 81 U .04 15 ~ .90 S allow i tin . Lt. e si . 89 2850 ~1 0.04 15 t, 2.92 Shallow ittin . 90 2882 ~~ 0. 3 13 t 2.92 Shal~ow ittin . 91 2913 ~~ 0.03 13 2.93 Shallow ittin . 92 2 45 U 0.03 1 3 ~~ 2. 2 Sh Ilow 'ttin . Sli bucMin . 93 2977 u 0.03 11 I 2.92 ~ Penetration Body Metal Loss Body Page 2 ~ ~ PDS REPORT JOINT TABULATION SHEEf Pipe: 3.5 in 9.3 ppf L-80 EUE SRD MOD Well: 2M-09A Body Wall: 0.254 in Field: Kuparuk Upset Wall: 0.254 in Company: ConocoPhillips Alaska, Inc. Nominal I.D.: 2.992 in Country: USA Survey Date: October 13, 2009 Joi~t No. Jt. Depth (Ft.) I'~~n. t lEnc~t (In..) Pen. Body (InsJ f'c~n. % Vlc~t,~l I c>ss `~~~ Min. I.D. (Ins.) Comments Damage Profile (% wall) 0 50 100 94 3009 ~~ 0.04 14 2 2.87 Shallow cor osi n. Lt. De osits. 95 3041 ~1 0.04 14 i 2.91 Shallow it ~n . 96 3072 ~1 0.03 1;> ; 2.92 Shallow _ittin . 7 3103 ~) 0.04 14 h 2.90 Shallow ~itUn . 98 3135 i~ 0.04 I-~ I 2.97 Shallow ittin . 99 3167 ~~ 0.03 ls ~~ .91 Shallow ittin . 100 3 9 ~~ .04 1, 2.90 Shallow it ~n . Sli ht bucklin . 101 3230 ~ i 0.04 I' c 2.E3 Shallow corrosion. Lt. De osits. 102 3262 ~1 0.04 14 ~ .91 Shallow itti 103 3294 U 0.04 1' ? 2.91 Shallow c.orros'on. Lt. osits. 104 3325 l~ 0.04 15 _' 2.89 Shallow ittin . Lt. De sits. 105 3 357 l~ 0.04 I-1 2.90 Shallow ittin . 106 389 u 0.03 _' 2.93 Sli ht bucklin . 107 3420 ~t 0.04 It~ .91 Shallo ittin . 108 3452 ~~ 0.03 1 ~' 2.89 109 3484 ~~ 0.04 1' 2.88 Shallow ittin . Lt. De sits. 110 3515 t~ 0.06 14 _' 2.91 Isol ted ittin . Lt. De sits. 111 3547 ~~ 0.03 l:i ' 2.90 Shallow ittin . Sli htbuc.klin . 112 3579 ~? 0.0 1 3 ' 2. 0 Shallow ittin . t. sits. 113 3611 ~? 0.03 1> ' 2.89 Shallow ittin . Lt [~e si . 114 3643 ~~ 0.04 I' -1 2.92 Shallow ittin . Lt. D sits. 115 3674 l) 0.04 I'i t 2.86 Shallow ittin . Ll. De osits. 116 370 ~~ .05 I t9 U 2.90 Shallow ~ittin . 117 3738 U 0.04 I ~ (~ 2.87 Shallow ittin . 118 3769 t~ 0.04 I 5 U '.89 Shallow ittin . Sli ht ucklin . 119 3801 U 0.04 IE~ ~~ 2.88 Shallow ittin . 120 3832 U 0.04 1 i I 2.89 Shallow ~ittin . t. e its. 121 3864 ~~ 0.04 1' 1 2.89 Shallow ittin . 122 3895 i) 0.04 17 I 2.88 Shallow ittin . 123 3926 U 0.04 17 u 2.89 Shallow ittin . 124 3958 (1 0.03 1 i 1 2.89 Shallow ittin . 125 3990 u 0.04 17 I 2.90 Shallow ittin . Sli ht bucklin . 126 4021 U A4 1-l 1 2.89 Shallow itti 127 4052 l1 0.04 15 I 2.89 Shallow ittin . 128 4084 ~~ 0.04 17 1 .89 Shallow ittin . 129 4116 U 0.04 14 0 2.89 Sha~low ittin . 130 4148 ~1 0.04 I 4 U 2.89 Shallow ittin . Sf ht bucklin . 131 4178 ~1 0.03 I t U 2.87 Shallow ittin . Lt. De sits. 1 4210 l~ .04 I`i 1 .88 Shallow itfn . Lt. D si . 133 4241 U 0.04 I; 2.91 Shallow ~ittin . 134 4273 O 0.03 I i u 2.87 hallow ittin . Lt. De sits. 135 4305 t) 0.04 15 I 2.87 Shallow ittin . 136 4336 I~ 0 04 1-l 2.90 Shallow c.orrosion. Sli t buc.ldin . 137 4368 U 0.04 15 1 2.90 Shallow ittin . 138 4399 l) 0.04 14 ~~ 2.88 Shallow itt n. 139 4430 (1 0.04 14 I 2.86 Shallow ittin . Lt. De sits. 140 4462 ~? 0. 4 1 d ~~ . 7 Shallow ittin . t. De sits. 141 4494 ~~ 0.03 1 ~' I 2.89 Sli ht buckli 142 452 5 ~~ 0.04 1-l t ~ 2.90 Shallow ~i tin . 143 4557 i~ 0.04 1 t, I 2.90 Shallow ~itrin . ~Penetration Body Metal Loss Body Page 3 ~ ~ PDS REPORT JOINT TABULATION SHEET Pipe: 3.5 in 9.3 ppf L-80 EUE SRL~ MUD Well: 2M-09A Body Wail: 0.254 in Field: Kuparuk Upset Wall: 0.254 in Company: ConocoPhillips Alaska, Inc. Nominal I.D.: 2.992 in Country: USA Survey Date: October 13, 2009 Joint No. Jt. Depth (Ft.) I'crn. l lE~,c~t Un~.j Pen. Body (Ins.) f'cn. `~~ ti1~~i.il I~,~~ ~~ Min. I.D. (Ins.) Comments Damage Profile (%wall) 0 50 100 1 4588 t ~ 0.04 1 i I 2. 9 Sh II w'ttin . 144.1 4b20 U 0.03 13 I . 3 P P Shallow itdn . t. De osits 144.2 4625 ii 0 t~ ~~ NA LM 1 atc~~38:30 1443 634 ti 0.04 1 5 U .84 PUP hallow ittin . Lt. De osits. 145 4b40 E~ 0.03 1 Z I 2.fl9 Shallow ittin . Sli ht bucklin . 145.1 4672 U 0 U u 2 1 Carnco W-1 Ni le 146 4673 u 0.03 13 1 .88 Shallow ittin . 146.1 4705 u 0.02 ~) ,' 2 9 NUP 147 4712 U 0.03 12 7 9 147.1 4740 c) 0 U ~~ 2.99 3.5" Tubin Tail Penetration Body Metal Loss Body Page 4 ~ ~ ~ ~^r ~ ~ ~ r ~ ~ r ~ ~r ~ ~ ~ ~ ~ ~ ~~4 ~+~ PDS Report Cross Sections Well: 2M-09A Survey Date: October 13, 2009 field: Kuparuk Tooi Type: UW MFC 24 No. 212330 Company: ConocoPhiltips Alaska, inc. Tool 5ize: 1.69 Country: USA ,'~'o. af Fingers: 24 Tubin : 3.5 ins 9.3 f L-80 EUE 8RD ~~tOD Anaivst C. Waldro Cross Section for Joint 2 7 at depth 912.82 ft Tool speed = 43 Nominal tD = 2.992 Nominal OD = 3.500 Remaining wall area = 99 % Tool deviation = 16 ° Finger 7 Penetration = 0.072 ins Isolated pitting 0.07 ins = 28°/a Wali Penetration HIGH SIDE = UP u ~ Cross Secdons page 1 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ PDS Report Cross Sections ~4 "- ~~~ ri Well: 2M-09A Survey Date: October 13, 2009 Field: Kuparuk Tool Type: UW MFC 24 No. 212330 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of fingers: 24 Tubin : 3.5 ins 9.3 f L-80 EUE 8RD MOD Anal st: C. Waldro Cross Section for Joint 26 at depth 885.76 ft Tool speed = 43 Nominal ID = 2.992 Nominal OD = 3.500 Remaining wall area = 99 % Tool deviadon = 16 ° Finger 24 Penetra6on = 0.071 ins Isolated pitting 0.07 ins = 28% Wall Penetration HIGH SIDE = UP • ~ Cross Sections page 2 • ~ 1 ~., Well: 2M-09A Field: Kuparuk Company: ConocoPhillips Alaska, Inc. Country. USA Maxirnum Recorded Penetration Comparison To Previous Survey Date: October t 3, 2009 Prev. Date: September 28, 2007 Tool: UW MFC 24 No. 212330 Tubing: 4.5" 12.616 L~0 Overlay Ma~c. Rec. Pen. (mils) 0 50 100 150 200 250 1 11 21 - --- 31 41 51 61 7 1 - • 81 91 101 111 121 131 141 -- ^October 13, 2009 ^September 28, 2007 ~ a 1 E ~ i .~ Difference ~ ~ ~~ Minimum Diameter Profile Well: 2M-09A Survey Date: October 13, 2009 Field: Kuparuk Tool: UW MFC 24 No. 212330 Company: ConocoPhillips Alaska Tool Size: 1.G9 inches Country: USA Tubing I.D.: 3.958 inches 1.69 1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 ~ ~E 73 Z 77 e 81 •a ~ 85 89 93 97 101 105 109 113 117 121 125 129 133 137 141 144 Mi~rimum Meuured Diameters (In.) 2.19 2.69 3.19 3.69 ~ ~ PDS Report Overview ~, ~.. Body Region Analysis Well: 2M-09A Survey Date: October 13, 2009 Field: Kuparuk Tool Type: UW MFC 24 No. 212330 Cornpany: ConocoPhillips Alaska, I~c. Tool Size: 1.69 Country: USA No. of Fingers: 24 Ana- sh C. Waldro Tubirig: Norn.OD Weight Grade &Thread Nom.ID Nom. Upset Upper len. Lower len. 4.5 ins 12.6 f L-80 3.958 ins 4.5 ins 6.0 ins 6.0 ins Penetration and Metal Loss (°~ wall) ~ penetration body ;~n metal loss body 150 ~ 100 50 ~ 0 to 1 to 10 to 20 to 40 to over ~% 1~% 2~% 4n% 8$% 8$% Number of'oints anal sed total = 146 pene. 0 0 9 134 3 0 loss 0 12 7 19 0 0 0 Damage Configuration ( body ) 150 100 50 0 isolateci gcncral line ring hole/ppss pitting corrosion corrosion corrosion ible hole Number of ~oints dama ed total = 146 4 142 0 0 0 Damage Profile (°,6 wall) ~ penetration body rnetal loss body 0 50 100 1 51 101 Bottom of Survey = 146 Analysis Overview page 2 • ~ PDS REPORT JOINT TABULATION SHEET Pipe: 4.5 in 12.6 ppf L-80 Well: 2M-09A Body Wall: 0.271 in Ficid: Kuparuk Upset Wall: 0.271 in Company: ConocoPhillips Alaska, Inc. Nominal LD.: 3.958 in Country: USA Su-vey Date: October 13, 2009 Joint No. Jt. Depth (Ft.) I'c~n. i lFxc~t (Inti.j Pen. Body (Ins.) I'c~n. °4, ~1c~t,il I os> ~~ Min. I.D. (Ins.) Comments Damage Profile (%wall) 0 50 100 1 4741 l1 0. 7 ?4 5 ".86 orr sion. l. De osits. 47 1 U 0.06 2l1 4 3. 7 Cvrro io . Lt. De osi . 3 4801 t~ 0.06 21 -1 .79 Corro ion. Lt. e osits. 4 4832 ~~ 0.09 ~~~5 i~ 3.91 Isolated ittin . 4863 ~ ~ 0.09 ~ ' ~ 3.89 Corrosion. 6 4892 ~~ 0.06 %3 `? 3 91 Corrosion. 7 4922 ~? 0.07 '~ 3.89 Corr sion. 8 4952 t~ 0.06 _' I - 3J Corrosion. Bu klin . De osits. 9 498 U 0. 7 ?6 7 3.81 Corrosion. Bucklin . t De sits. 10 5012 t~ 0.06 2> (~ 3.80 Corrosion. Buc li . t. De sits. 1 5042 (~ 0.06 L3 5 3.87 Corrosion. Lt. De osits. 1 507 U 0.10 s> i 3.84 Isolated ittin . Lt. De sits. 13 5101 ~~ 0.07 ~'i~ t> 89 Cor osion Lt. e sits. 14 31 ~~ 0.07 > 3.86 Corrosion. Bucklin . L De sits. 15 5160 tl 0.07 .!4 ~l 3.88 C rrosion. Buc i i. t. De osits. 16 5190 ll 0.06 Z s 7 3.87 Corrosio . Bucklin . Lt. De sits. 17 5220 (l 0.07 Z4 ~ . 9 Corrosion. Bucklin . Lt. De sits. 18 5249 (~ .07 _'~1 ~ 3.88 Corrosion. Bucklin . Lt. De sits. 19 5279 (~ 0.07 ~~fj ~ 3.87 ~orrosion. Buc li . L. De sits. 2 5307 U 0.09 ~_' 3.88 Corrosi n. Bucklin . Lt. sits. 21 5337 Il 0.06 .' I ~~ 3.84 Corrosion. Lt. De osi . 22 5366 t1.1~3 0.06 ~_' (, 3.89 Corrosion. Lt. De osits. 23 396 ~~.~~5 0.05 I" 3.68 Corro io . e si . 24 5425 O 0.07 ~' ~ t~ 3.86 Corrosion. Lt. De osits. 5 l~ 0. 7 ~'-1 ~~ .$4 Cor s'on. Lt. sits. 26 5485 O.U4 0.06 ~'Z !~ 3.91 Corrosion. 27 551 t~ 0.10 ;i ~~ 3.90 Corr si n. Lt. De osits. 28 5542 ~~ ~~5 0.07 24 3.71 Corrosion. De sits. 29 5573 U .07 ~'> i, 3.87 Corrosion. L. De osits. 30 5603 l~ 0.07 Z-t !~ 3.87 Corrosion. Lt. De osits. 31 56 2 U.U6 0.08 ~ i d .83 Corrosion. t. e o~ 32 5663 ~ 1 0.05 I ti (> 3.86 Corrosion. Lt. De osits. 33 5692 ~~ 0.05 1 i (i 3.81 Corrosion. Lt De osi . 34 5722 U 0.05 1~1 (~ 3.$3 Corrosion. Lt. De osits. 35 754 U 0.06 Z 1 ~ 3.87 Corro ion. Lt. De osits. 36 5783 U.O7 0.09 13 13 3J9 Corrosion. Lt. De osits. 37 5811 l) .06 ?-1 ~ 3J Corr sion t. Ue sits. 38 SH42 l1 0.06 '_' ~ 3.87 Corrosion. Lt. De osits. 39 5873 U 0.08 st~ -1 3.71 Corrosio . sits. 40 5901 O 0.07 ~ i 6 3J4 Corrosion. De sits. 41 5930 t~.~12 0.06 ~ 1 -1 3.88 Corrosion. Lt. e osits. 42 5959 u 0.07 24 t, 3.87 Corrosion. Lt. De osits. 43 5989 l~ 0.09 31 ~ 3.89 Corrosion. l.t De osits. 44 6018 U 0.08 ~li (, 3.87 Corrosion. Lt. De osits. 5 6048 U.US . 7 Zt3 ~ 3.89 ' rro ion. 46 6077 O.U~ 0.07 Z~ 4 3.84 Corrosion. Lt. De osits. 47 6109 (~ 0.07 ~4 > 3.88 Corrosion. 48 6138 ~ 1 0.07 ?' -1 3.87 Corrosion. Lt. De osits. 4 61 6 ~~ 0.06 2~~ ~s 3J8 Corrosion. Lt. De siYs. 50 6197 ~~ 0.05 1 t3 ~ 3.86 Corrosion. Lt. I~e osits. PeneUa6on Body ~ Metal Loss Body Page 1 . ~ PDS REPORT JOINT TABUL ATION SHEET Pipe: 4.5 in 12.6 ppf L-80 Well: 2M-09A F3ody Wall: 0.271 in Field: Kuparuk Upset Wall: 0.271 in Company: ConocoPhillips Alaska, Inc. Nominal I.D.: 3.958 in Country: USA Survey Date: October 13, 2009 Joint No. )t Depth (Ft) i'~~ii. t!E,~c~t Ilrn ~ Pen. Body (Ins.) P~n. % ~Ic~i,il loss ~~ Min. I.D. (Ins.) Comments Damage Profile (%wall) 0 50 100 51 6226 ~? 0.05 ZU 5 3.87 Corrosion. Lt. De osits. 52 6256 ~~ 0.06 '1 7 3.88 Corrosion. Lt. De osits. 53 285 ~~ 0.06 ' I ~ 3.86 Corrosion. Lt. D osits. 54 6314 '~ 0.06 '4 i~ 3.88 Corrosion. 55 6344 t~ 0.06 ~' s !~ 3.86 Corrosion. Lt. De osits. 56 6374 t? 0.07 - 3.88 Corrosion. L. D osits. 57 6404 l? 0.06 ~> 3.86 Corrosion. Lt. De osits. 58 6434 U 0.07 <-i ~ 3.87 Corrosion. Lt. De o its. 59 6464 ~? 0.07 .'S ~.~ 3.85 Corrosion. Lt. Dc osits. 60 6494 u 0.06 _' 1 ~~ 3J9 Corrosion. Lt. De osits. 61 6524 l~ 0.07 2~1 f; 3.85 Corrosion. Lt. De osits. 6' 6554 U 0.07 ~'7 !, 3.86 Corr sion. Lt.l~e osits. 63 6584 (~ 0.07 'S ti 3.65 Corrosion. De sits. 64 6614 (~ 0.06 _' ~ ~ 3.90 Corrosion. 65 6644 U 0.05 _'i~ - 3.86 orrosion. Lt De osits. 66 6674 l1 0.07 ~~ 3.82 Corrosion. Lt De osits. 67 6703 U 0.08 su G 3.82 Corrosion. Lt~ e osits. 68 6734 U 0.07 ~'-l i, 3.71 Corrosion. e sits. 69 6764 c~ 0.07 ~' i 4 3.88 Corrosion. Lt De osits. 70 6794 u 0.06 !4 7 3.90 Corr sion. 71 6823 (1 0.07 24 7 3.88 Corrosion. Bucklin . Lt. De sits. 72 6854 U 0.06 21 (~ 3.87 orrosion. Lt. De osi . 73 6883 ll 0.07 2.i - 3.90 C rrosion. t. De sits. 74 6914 U 0.08 Z~> 3.90 Corrosion. 75 694 ~) . 7 ld ~~ 3.90 rros'on 76 6973 O 0.06 2t) (, 3.86 Corrosion. Lt De osits. 77 7004 tl 0.06 Zl i 3.83 Corrosion. LL De osits. 78 7032 O 0.07 26 f, 3.90 Corrosion. 79 7061 t~.t) i 0.08 ?8 - 3.91 Corrosion. Bucklin . Lt. De osits. 80 7091 t) 0.07 Z i 0 3.89 Corrosion. Lt. De osits. 81 7121 t) .08 Z') ~ 3.77 Corrosion. Lt. De osi . 82 7152 u.Ub 0.08 sll 3.91 Corrosion. Lt. De osits. 83 7181 0 0.0 3l) 7 3.90 Corrosion. Lt. De osits. 84 7212 ~) 0.06 Z4 G 3.77 Corrosion. Lt. De osi~s. 85 7241 (1 0.07 ~'t, h 3.89 Isolated ittin . 86 7271 t~ 0.10 37 t, 3.91 Corrosion. 87 7302 U 0.06 '-~ i 3.88 Corrosion. 88 7333 u 0.06 ~2 ~ 3.91 Corrosion. Lt De osits. 89 7362 11.U!~ 006 Z3 4 3.83 C rrosion. Lt. De osits. 90 7394 l? 0.06 l I (> 3.89 Corrosion. f.t. De ~osits. 91 7424 U 0.07 ~ ~i (~ 3.80 Corrosion. Lt. De osits. 92 7454 U 0.12 -1"; 7 3.91 Corrosion. 93 7484 U 0.08 tt1 t5 3.89 Corrosion. 94 7514 ~) 0.08 ~~1 t~ 3.91 Corrosion. 95 7543 t~ 0.09 i? 5 3.90 Corrosion. 96 7573 !! 0.10 ~c, ~, 3.89 Corrosion. 97 7603 ~ 1 0.11 -1Z % 3.88 Corrosion. 98 7634 U 0.08 30 £3 3.88 Corrosion. Lt De osits. 99 7664 t) 0.08 31 3.87 Co r sion. Lt. De osits. 100 7694 l) 0.09 3~ - 3.90 Corrosion. f'enetration Body Metal Loss Body Page 2 ~ ~ PDS REPORT JOINT TABULATION SHEET Pipe: 4.5 in 12.6 ppf L-80 Well: 2M-09A Body Wall: 0.271 in Field: Kuparuk Upset Wall: 0.271 in Company: ConocoPhillips Alaska, Inc. Nominal I.D.: 3.958 in Country: USA Survey Date: October 13, 2009 Joint No. )t. Deptfi (Ft) I'~~n. U~,~~~~ Iln..) Pen. Body (Ins.) Pe~n. "4, ~Ic~t,il I~~,s ~~ Min. I.D. (Ins.) Comments Damage Profile (%wall) 0 50 100 101 7723 u 0.07 ~ 5 ~ 3. 0 Corrosion. Lt D osi . 102 7753 u 0.11 ;~) ~3 392 orrosion 103 7783 ~~ 0.07 '~ 3. 2 Corrosion. 104 7812 ~) 0.10 3.87 Corrosion. LL De osits. 105 7843 t~ 0.07 Z;' 3.86 Corrosion. Lt. De osits. 106 7875 t~ 0.09 >; 3.88 Corrosion. Lt. De osits. 107 7905 ~! 0.07 - 3.88 Corrosion. Lt. De sits. 108 7934 ~ i 0.07 ~ ~ - 3.91 Cor osion. Lt. De osits. 109 7964 i! 0.06 _'4 3.87 Corrosion. Bucklin . Lt De si . 110 7994 i~.i~E~ 0.10 ~5 Iti 3.90 orrosion. 111 8023 ~~ 0.08 ~~~ 3.90 Corrosion. 112 8053 U .07 16 ~ 3.92 Corrosion. 113 8086 ~~ 0.08 l~~ t~ 3.91 Co rosi n. 114 8115 ~~ 0.06 _' ~ - .88 Corrosion. L De osits. 115 8145 n 0.08 3(1 t; 3.91 Corrosion. 116 8175 t~ 0.06 '-a 3.89 Corrosion. Lt. De osits. 117 8207 U.11(> 0.07 ,~ 5 !~ 3.91 Corrosion. 118 8238 ~~.U ~ 0.08 sl 3.91 Corrosion. 119 8267 ~~ 0.08 '~~ - 3.89 Corrosion. Lt. De osits. 120 8296 ~. ~ 0.09 > I 3.90 Corrosion. 121 8326 U 0.08 ~l~ 3.91 Corrosion. 12 8356 ~ 1 0. 8 2 f3 0~~ .92 Corrosion. 123 8386 u 0. 9 ~4 i 3.92 Corrosion. 124 8415 t~ 0.09 ~~ 3.92 Corrosion. 125 445 t~ 0.10 5E, - 3.90 I I ted it'n . 126 8475 c~ 0.07 '~ ? 3.88 Corrosion. Lt. De osits. 127 8507 ~~ 0.07 ,' S 3. 1 C rrosion. 128 8537 n 0.08 sU ii~ 3.91 Corrosion. 129 8568 ~~ 0.07 ..'S I~ .65 Bend. Corrosion. 130 8601 t1 0.08 31 II 3.91 Corrosion. 1 1 8633 U 0.07 ~;!5 1_' 3.93 orro ~on. 132 8665 ~~.(u~ 0.07 25 i' 3.93 Corrosion. 133 869 U 0.07 '(~ I~ 3.93 Corrosion. 134 8728 tt 0.07 15 I' 3.93 Corrosion. 135 8761 u 0.06 _'-1 I I 3.90 Corrosion. Lt. De osits. 136 8793 t~ 0.07 = 5 I I 3.93 Corrosion. 137 8825 ~~ 008 ~ti ~ I 3.90 Corrosion. Lt. De osits. 138 8857 t~ 0.08 '>; i; 3.93 Corrosion. 139 8889 t~ 0.07 ;'i, ; 3.90 Corrosion. Lt. e osits. 140 8921 U 0.08 ,!'~~ 3.96 Corrosion. 141 8954 U.l)~~ 0.09 3-_' I+ 3.96 Co rosion. 142 8986 ~~ 0.07 Zt, 1 ~ 3.95 Corrosion. 14 .1 9017 O 0 U !! 2.31 Carnco D65- ~ le W Otis . 13" Profile 143 9024 ~1 0.07 _'S ~~ 3.96 Corrosion. 144 903 ~_).~~~> 0.08 .'ti I+ 3.93 Corrosion. 145 9052 t~.~15 0.11 ~~~ I' 3.74 Corrosion. 13ucklin . Lt. De sits. 146 9084 ~~.(1; 0.07 16 I S 2.74 Bend. f~e ~osits. ~ Penetration Body Metal Loss Body Nage 3 PDS Report Cross Sections ~u `~ „ Weil: 2M-09A 5urvey Date: October 13, 2009 Field: Kuparuk Tool Type: UW MFC 24 No. 212330 Company: ConocoPhillips Alaska, Inc. Tool Si2e: 1.69 Country: USA No. of Fingers: Z4 Tubin : 4.5 ins 12.6 f L-80 Anal st: C. Waldro Cross Section for Joint 92 at depth 7479.36 ft Tool speed = 43 Nominal ID = 3.958 Nominal OD = 4.500 Remaining wall area = 95 % Tool deviation = 43 ° Finger 15 Penetration = 0.116 ins Corrosion 0.12 ins = 43% Wall Penetration HIGH SIDE = UP ~ • Cross Sections page 1 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~ ~~ PDS Report Cross Sections Well: 2M-09A Survey Date: October 13, 2009 Field: Kuparuk Too) Type: UW MFC 24 No. 212330 Company: ConocoPhillips Alaska, Inc. Toot Size: 1.69 Country: USA No. of Fingers: 14 Tubin : 4.5 ins 12.6 f L-80 Anal st: C. Waldr~_ __ ___ ___ _ Cross Section for Joint 97 at depth 7617.62 ft Tool speed = 43 Nominal ~D = 3.958 Nominal OD = 4.500 Remaining wall area = 9b % Too) deviation = 43 ° Finger 15 Penetradon = 0.1 14 ins Corrosion 0.11 ins = 42% Wall Penetra6on HIGH SIDE = UP L ~ ~ J Cross Sections page 2 PDS Report Cross Sections '1 `-~ ,, u b'Vell: 2M-09A Survey Date: October 13, 2009 Field: Kuparuk Tool Type: UW MFC 24 No. 212330 Company: ConocoPhiilips Alaska, Inc. Tool Size: 1.69 Country: USA No. of fingers: 24 Tubin : 4.5 ins 12.5 f L-80 Anal st: C. Waldro Cross Section for Joint 146 at depth 9085.41 ft Tool speed = 43 Nominal ID = 3.958 Nominal OD = 4.500 Remaining wall area = 100 °!o Tool deviation = 41 ° Finger 6 Projection = -0.882 ins Deposits Minimum I.D. = 2.74 ins HIGH SIDE = UP ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ • C~ Cross 5ections page 3 PDS Report Cross Sections ~--~ ~-'~ ,. w Well: 2A~1-09A 5urvey Date; October 13, 2009 Field: Kuparuk Tool Type; UW MFC 24 No, 212330 Company; ConocoPhi{lips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 14 Tubin : 4.5 ins 12.6 f L-80 Anal st: C. Waldro Cross Section for Joint 129 at depth 8576.1 ft Tool speed = 43 Nominal ID = 3.958 Nominai OD = 4.500 Remaining wall area = 100 % Tool deviation = 37 ° Finger 2 Projection = -0.214 ins Bend Minimum I.D. = 3.65 ins HIGH S~DE = UP ~ • Cross Sections page 4 ~ ConocoPhillips Alaska, Inc. ~ KRU 2M-09A ~' 2M-09A API: 501032017701 Well T : INJ An le TS: 36 de 9084 SSSV Type: NIPPLE Orig Com letion: 6/14/1996 Angle @ TD: 33 deg @ 9405 Annular Fluid: Last W/O: Rev Reason: RKB TAG wa(5~a-5~5, Reference Lo : Ref L Date: Last U ate: 1126/2007 ~ 3~~ Last Ta : 9292 TD: 9405 ftKB TUBING (0-4719 Last Ta Date: 11/25/2007 Max Hole An le: 69 de 4124 , oo:a.eoo, Casin Strin - CONDUCTOR iD2.ss2) pescri tion Size To Battom TVD Wt Grede Thread CONDUCTOR 16.000 0 121 121 62.50 H-40 Cesin Strin - SURFACE Descri tion Size To Bottom TVD Wt Grade Thread SUR. CASING 9.625 0 4306 2775 40.00 L-80 Casin Strin - PRODUCTION Abandoned Ori inal Wellbore• Sidetrack Kick Off 4980 De~ri tion Size To Bottom ND Wt Grade Thread Gas l.irt ~ PROD. CASING 7.000 0 4980 3043 26.00 L-80 '^d^~~~my v N 1 Casin Strin - UNER a e (4631-4632 ^ I Descri tion Size To Bottom TVD Wt orade Thread , o~:s.5sa~ LINER 4.500 4717 9402 6297 12.60 L-80 PR~ Tubi Strin - TUBING CASiN~ ~~ Size To Bottom ND Wt Grade Thread ( . oo:~.ooo, 3.500 0 4719 2937 9.30 L-80 EUE 8RD MOD wc:zs.oo~ PerForetions Summa Intervat TVD Zone Status Ft SPF Date T e Comment N~P 9084 - 9096 6036 - 6046 C-4,A~ 12 3 7/10/1996 IPERF 2 1/8" HC, 180 deg. phase; oriented 165 deg. CCW F/ Hi h Si ~4sn-as~e, OD:3.500) 9104 - 9133 6052 - 6076 A-4 29 3 7/10/1996 IPERF 2 1/8" HC, 180 deg. phase; oriented 165 deg. CCW F/ Hi h Si 9149 - 9214 6089 - 6142 A-3 65 4 7/10/1996 IPERF 2 1/8" HC, 180 deg. phase; orie~ted 165 deg. CCW F/ Hi h Si Gas Lift MandrelsNelves St MD ND Man Mfr Man Type V Mfr V Type V OD Latch Port TRO Date Run Vlv Cmnt p~ 1 4631 2901 Camco MMM DMY 1.5 RK 0.000 0 6/14/1996 ~4~»-4»8, Other u s ui . etc. - JEVNELRY OD:6.151) Ds th ND T e Deeori Uon ID SPACEOUT (4718-4719 514 513 NIP Camco'DS' Ni le NO GO 2.812 , oo:a.soo~ 4677 2919 NIP Camco'W-1' 2.812 r2 4717 2936 PKR 8aker'ZXP' w/ 7.39' C2 Tie Badc Sleeve 4.438 (471&4720. OD:3.500) Q7~H 2936 SPACE OUT 2.992 a»s asa~ n~ 2.ssz 9017 5981 NIP Camco 5" X 3.813" DB5 Nipple w/3.81 maxi big bore lock w/Otis 2.313" X rofile 8 WL entr uide 2.313 Gener al Note s Date Note N~P 2/6/2006 NOTE: WAIVERED WELL: SHALLOW PACKER "`WATER INJECTION ONLY** ~soi~-so~a, OD:5.000) LINER (4717-9402, OD:4.500, Wt:12.60) Pert (90849096) Fert (91049133) Pert (9149-9214) k:r. ..~~~.r:.~~ ~-~9r'_~~. _~!~.~~ :4.J _- ~'o'i4~~~.?l~~y {~py _..^t~ +. ~t 1 ~,~ J:~ V~,~4~;• !-~,aS ;='ru~h~; 1 YG ~?~ • ~ 4~,? c~a~-~ ~~ t Tu~~t~~ ~ ur~F~ a~Arc. ~41~~v gt; ~K~ /~r~b~;drary cr~A~fa~rri~ Ftich~iar. ~- w~.: 2an~a aRTE- 611~,~s AA~; ~ ot t ~ ITEII~iS . CQlIAPI.ET'~ D~S~PTiOtlt OP ~CiUIF'~,4~N7 RUN ; I.~I~tGT'H p~`H 3:5" 'CSG 'TO~ ~ar[eet l~if~3 #~ Lc~clt D~rrt ~t~etws - 37.~Q _ _ 8I_4~J 4('!Q FMG ~~n 4 h~a.~r ~ 118` x 5,0~} p~ t 3.90 3~.4d~ 1 .~ES., 3.5". S.~l~. l.-8~ ~U~ ~rtrc~ MOO' . _ 31.5@ ~40.af~ ~ups 3.~°: 9.3+i~. l.•~, ~ll~ Btd Mtt~ ~'d.1a~ ~.i0, 8.15j 24~C 72.(38 i 3 Jt~.. ~,5 ", 9>3 ~, L SQ. ~UE 8rsi ~1.7 4~I ~t.4~ SrC.~ . ~~~ 3.5", 9.~~, L-B~O. ~UE B~r1 Mod ~.1tF ~7'.94 car.-~a Qs n~c~~. ~a2.at2 oQ ~ 7ry~. ~ua ~~, ~~ ~~.ooo~s- .v ' o.sx ~~a,~a FlQ;et cQUOIi~ F i[? 3.1}. tQt3 ~4 3ld 6.24 5'~S.U'i 13Q Jts., 3.5"~ 9~,3 #, L-8U, EUE 8rr1' MC1D _ ~_. 41 EYi.92 521,21 ~..., P'u p 3.~" ~~.3~, ~ 8a, Et#~ S~d 'utod _., , ~,.. 6.a[} .~.~.,_ 46~. i 3 C~rnco MMM mar~drel Krl f~V e~~d ~JC latdi, Q~ 5 9`~6 ~~ 8.T~ ~B3i,i3 ;~p 3.~", 9,3#, L-E3{i, EUE 8r~ Mod 5,~~ 4~~4.8~ t Jt„ 3.5", 9.3#, L-$Q, ~tJE ~d`f4100 31.3$ 4$~.84 Ca~nccs Wi ni~l0, ld 2 812. Qf'~ 4 7116, E~t4tN ?4,~1p 8{30t! asi 1:93 +iG~6.82 1 ,at.. 3,5", ~.3 ~« L•8U, ~E1E 3r~ MQC 31,36 48?`~.?`~ _ ,u. ~'up ~,5", ~.3€~; L.-80; EUE t~rp Mad B.t3 ± 4711~.1 i L~tar~ €~F} 415~'~6 i.£N,a 47~'G~4 Sp~;.~ o4E t.~0 47783~ , _ _ ___ ' ~71 ~.19 ~ t~,_._~_- _ _. . . ; . _.. . _ ._ -- .. __ - ~_~._ __.__ _ .~ .w~..__~ _. _ _ .n~ , ._ ~ __` _. Note; Ta~ c~ ~~k~r SB~ ~ Q7t 7~ by ::sg ta;ry° _ _ . ___ --_ .~. _ __.,.._ '' n€+ [;o~~; ~lati~n.a ~e~d f1e4 moGiti±d (~OL ~ti~]j __.~_. . - .~ ---- -- ~ - ----------- E _...____ ._~.__~ "-_ . ~ .. .._.. _._~_~~ ... ... . .. .. .. _. Ran f~-i~'ts~ i:~°th~ __ M. - r --~y - .~~ _ - -- ~e ._.~ . _ _ __ _.._ ,~Ec,;i Sds+~+Crl' ~+u~V~: ~e.L. ~L't~iet:Jf _I fF _~ "a~Jr 1_. ~~~Fiy t~: _'6 i~l~#.~lil'S ~~r,t i'3: ~ iJ~ ',~4:~ ?C?~ r~ru~lhr,r 1',~~V , , CASING i TUBIt~G 1 Ll~IEA QET~Itt. ~iR~C? AUt~t~lA ! S~~sicfary of ~tfantJc Ri~hl`'~tl Ff ~ :~;7rF' ~?31~ ~~.1 w~u.: ~osa DATE: 6J13~'~ P,~Q~~ t [t~ 1 # 1"[EA~IS __ . __ __ _ CC~MPLEY'E Ci~~FEI~~'TION OF ~t~l~iPI~1~NT RUN t~I~TFI Ol~'H 4.5" Rto~uctFt~n t,~ner ; _ '~j~ __ (~~F~R~:~CE 42` RKB RA~tIf~R 245 ~iKE~ ~Q UN~Fi I'~~ ~T 16.7~ , -- -- 4~t~:71 ~af~er T~CP Pack~r W.+(7.~9'; ~ tieUack sle~v ~nci 'ocator. 4 7~16' t39~4 4?t~:~i Baker t~~ Eir~rttr h~n~er fD ~ 7l1~` X 5 7~~' ~.aS ! 4?3t~.~ _..... p~R. I~ ~3.Uy X G3~ 5.4' . 12»3B ~._..,... ~Y37:18 - ft41~.+ifl~ia7~I~f ~~aYRVY: .. . . • .1.~1L~ ~ ~1~~?•;7fJ 14~ _ _s..-,.... jts A.5", f2.8t~, L-~O. NSa~'~. R2 ~265.~7 '~7'~C1:~B ,CamC4 D~6 ni~ple ~ x~.8t3. !-~.N ~A1i, w~ 8d34 ~Si 1.52 ~A1~:S~ Nl~fker,lt.4 a''.1~.a#. ~-8p. RtSCT, ~-?; Tap~tss.34, Bt'r^:=~5.£~- ~2.1~ ~iS.17 S jts~.5", ic~.8#, :.•6t}, NSC'f, f~ ~2.76 9~0;36 Baker z~ndin e~~ar: 1.14 99t3~.12 __ 1 jts 4.~'. 12.!8~, ~,-~fl'. h1~~T, Fi~ ~,~_ ~~ ,~4 . 93QR.26 8sker i1~at coflar 1.14 9~5.60 2 ~4.~°, 1~.~, L~, NSCT, R~ 63.11 ; $3~94 _ _ __ ~als~ar flt~: ~h~e 1.~5 ~J,#}5 B~IceF Ho~t slrae 8t ~{~.OQ ~,1~..~-~"1we211 ~~. ~~ thQ f3 i+ll~F~@tEfe_n r(~.n ~- ~~: 4C - ~" x g" R~T ~QUO` ~lR~OL12ERiS~ ~F~ur ~n firs: 4~ jks. P9caii:~~ beit~rpen ~Wy rin8 in-cente~ ~# ~t. arxfi aaNar. ~.~ Ahe~aling betvie~rt r~gi~t ~d feN hand every athsr;t. ~i ~tS~ P~tcic~~,~,,~t4^ apd x a nts~~ ta ,' ~~~ ~N,~1.l~9dS~t3 s ~ta• oa x ~a ~rr~ ~• m _,. _. Tp : g~p~_pp , p~e ~.a~ o~ X t.a~ ~a PBTI] = 93~.T2 ~.._ ~~!" ~t.8" CASING TQ S"1"AY IM PIPE SHE6 +" a,~r-+~~.~ ~ 3.[]~ Joln~a~~4 ti~ot~t 166 {13 jts, tasal) - _ ~.~ ~ip~ l~qpe: Natianal 1~ad r: ~~ ^~~fi~d 1BGL 2(7tl~Ji 7:3~~,1JED?'OS97~ l.~ner on hootc = 48~5.29 Rura~ing Iaa1=1Q,45 _~___. _. .._.:_. F?IG ~SUt'C RVI~L1~: <7r~naio' Lut~~;s f P~iC~E '( • MEMORANDUM TO: Jim Regg ~ ~ ~ 1~ i Z ~~~ P.I. Supervisor FROM: $ob Noble Petroleum Inspector r~ LJ State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, October 31, 2007 SLiBJECT: Mechanical Integrity 'tests CONOCOPHILLIPS ALASKA INC 2M-OIA Kl!P.4RUK t2IV IJNI"1'?M-09A Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Supr~~ Comm Well Name: KUPARUK RIV UNIT 2M-09A API Well Number: So- t o3-zo t 77-o t -oo Inspector Name: Bob Noble Insp Num: mitRCN071028044209 Permit Number: i96-o90-o Inspection Date: 1oi26i2o07 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well i zn-t-o~A ~TYpe Inj N -..TVD 2~se ~` IA o I~lo -~' teso t6~o i _ - - , - ,.. _.- ~ t - P.T. 1960900 ,TypeTest 1 sPT ;Test psi ~ 17to OA iao lao tao tao Interval REQVAR p~F P / Tubing noo logs loso I Iloo _,__ __._.. ~ ._ ._-- -1__. Notes: Well was S/I ~~~~~ ~ lr Ffi ~t_ ~ t ~ ~~ Wednesday, October 31, 2007 Page 1 of l 2M-09A (PTD 1960900) Waiver co fiance testing per AIO 26.004 Page 1 of 1 Re , James B DOA ~`/ /, (~` J9 ( ) I C~ '' (1 l From: NSK Problem Well Supv [n1617@conocophillips.com) Sent: Sunday, October 28, 2007 2:17 PM ~II, To: Maunder, Thomas E (DOA); Regg, James B (DOA) ~`r Cc: NSK Problem Well Supv Subject: 2M-09A (PTD 1960900} Waiver compliance testing per Al0 26.004 Attachments: MIT KRU 2M-09A 10-26-07.x1s; 2M-09a 09-28-07 Caliper PDS.pdf Tom & Jim, The waiver compliance testing for water injection well 2M-09A (PTD 1960900) has been completed as per AIO 28.004. Attached are the caliper log and the state witnessed MITIA form. Below is the summary from the waterflow log: 10/04/07 - RAN A WFL/LDL LOG PUMPED SEAWATER DOWN THE TBG AT 0.5 BPM, 2500 PSI FOR ALL PASSES AND WFL STATIONS, WELL WAS OPEN TO PERFS LOGGED AN UP AND DOWN PASS IN THE 4 1/2" LINER FROM 4650' TO t/' 9064' TOOK WFL STATION AT 10', 20', 30', 50' 100'. AND THEN EVERY 500' ABOVE THE PERFS NO LINER OR PACKER LEAKS DETECTED NO UP FLOW DETECTED BEHIND THE 4 1/2" LINER ABOVE THE PERFS TAGGED BOTTOM AT 9087'. Please let me know if you have any questions. «MIT KRU 2M-09A 10-26-07.x1s» «2M-09a 09-28-07 Caliper PDS.pdf» Brent Rogers Problem Weils Supervisor ConocoPhillips Alaska, Inc. Desk Phone (907} 659-7224 Cell Phone (907) 943-1999 Pager (907} 659-7000 pgr. 909 . __..:.~ 10/2912007 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to: Bob_Fleckenstein@admin.state.ak.us; Jim_Regg@admin.state.ak.us; Tom_Maunder@admin.state.ak.us OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska Inc. Kuparuk/ KRU / 2M-09A 10/26/07 Colee/Ives - AES Robert Noble ~~ Packer Depth Pretest Initial 15 Min. 30 Min. Well 2M-09A Type In~. N TVD 2,936' Tubing 1050 1075 1080 1100 Interval ~/ P.T.D. 1960900 T e test P Test si 1500 Casing 0 1710 1680 1670 P/F P Notes: 2 year witnessed MITIA per AIO 26.004 OA 140 140 140 140 Well T e In'. TVD Tubing Interval P.T.D. Type test Test si Casing P/F Notes: OA Well T e In'. TVD Tubing Interval P.T.D. T e test Test psi Casin P/F Notes: OA Well Ty e Inj. TVD Tubing Interval P.T.D. T pe test Test psi Casing P/F Notes: OA Well T pe Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well T pe In'. TVD Tubing Interval P.T.D. Ty etest Test si Casing P/F Notes: OA P =Drilling Waste M =Annulus Monitoring G =Gas P =Standard Pressure Test I =Industrial Wastewater R =Internal Radioactive Tracer Survey N =Not Injecting A =Temperature Anomaly Survey W =Water D =Differential Temperature Test I =Initial Test 4 =Four Year Cycle V =Required by Variance T =Test during Workover O =Other (describe in notes) MIT Report Form BFL 9/1 f05 M1T KRU 2M-09A 10-26-07.x1s i • ~~[. L~- ProActive Diagnostic Services, Inc. To: AOGCC Christine Mahnken 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 (907j 659-5102 RE : Cased Hole/Open Hole/Mechanical Lags and/or Tubing Inspectian(Caliper/ MTTj The technical data listed below is being submitted herevditF+. Please acknowledge receipt by resuming a signed copy of this transmitta{ fetter to the following : BP Exploration (Alaskaj, Inc. Petrotechnical iData Center Attn: Andy Farmer LR2-1 9~ E, Benson Blvd. Anchorage, Alaska 99508 and ~~ ~QV .~ ~ Zpa~ ~a ETC ~ q (o ' ~O ~ ISSc7.5 ProActive Diagnostic Services, l _ Attn: Robert A. Richey 130 West International Airport Road Suite C Anchorage, AK 99518 Fa~c (907j 245-8951 1 j Caliper Report 28Sep-07 2M-09A 1 Report / EDE 50-103-20177-01 ~- r ~ t~-Y ~, ~, . - Signed . Date ~i~~~~~$ Print Name: J0=6~ ~ i 5~ ~P ,[~,n (~.v~ ..o,~-~ _ ~, PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAL AIRPORT RD SUITE C, ANCHORAGE, AIC 99518 PHONE: (907)245-8951 Fax: (907)245-68952 E-NWL : ~dsanc3~mrac~efa7rraerraorylo~ WE9SITE : ~nraw.rvsernori9log.com D:\Mas[er_Copy_00_PDSANC-20~oc\Z Word\DistribuflonlTrans[niltal_Sheets\'[YansmiC_O[igmal_New.dac • Memory Mufti-Finger Caliper ,~ Log Results Sumrnar~y Company: ConocoPhiNips Alaska, Inc. Well: 2M-09a Log Date: September 28, 2007 Reid: Kuparuk Log No.: 7194 State: Alaska Run No.: 1 API No.: 50-103-20177-01 Pipet Desc.: 3.5" 9.3 tb L-80 EUE SRD Mod Top Log Intvl1.: Surface (MD) Pipet Use: Tubing Bot. Log Intuit.: 4,719 Ft. (MD) Pipet Desc.: 4.5" 12.6 Ib. L-80 Top Log Intvl1.: 4,719 Ft. (MD) Pipet Use: Liner Bot. Log Intvl1.: 8,944 Ft. (MD} inspection Type ; Corrosive & Mechanical Damage Inspection COMMENTS This caliper data is tied into the Tubing Tail ~ 4, 719' (Drillers Depth). This log was run to assess the condition of the tubing with respect to corrosive and mechanical damages. The caliper recordings indicate that the 3.5" tubing is in good to fair condition. Maximum penetrations ranging from 20% to 35% waA thickness are recorded in 12 of the 156 joints tagged. The caliper re~rded damage in the forms of Isolated Pitting and Corrosion. No significant areas ofcross-sectional wall loss or ID restrictions are recorded throughout the 3.5" tubing. The caliper recordings indicate that the 4.5" Liner is in good to fair condition with penetrations ranging from 20% to 40°~ wa8 thickness recorded in 96 of the 141 joints logged. The caliper recorded damage in the forms of Isolated Pitting, General Corrosion and Line Corrosion. No significant areas of cross-sectional wail loss or ID restrictions are recorded throughout the 4.5" liner. Cross-sectional drawings of the most s~nif~cant events recorded are included in this report. The distribution of maximum recorded penetrations is illustrated in the Body Region Analysis Page of this report. A graph illustrating the correlation of recorded damage to borehole profile is included in this report. 3.5" TUBING -MAXIMUM RECORDED WALL PENETRA71ONS Isolated Pitting (35°/ii) Jt. 26 @ 864 Ft. (MD} Isolated Pitting (27%) Jt. 24 ~ 800 Ft. (MD) Isolated Pitting (26°r6) Jt. 27 ~ 877 Ft. {MD) Isolated Pitting (25%) Jt. 36 C~ 1,181 Ft. {MD} Isolated Pitting (24°~) Jt. 30 ~ 969 Ft, (MD) 3,5" TUBING -MAXIMUM RECORDED CROSS-SECTIONAL METAL. LOSS No significant areas of cross-sectiona{ wa{I loss (> 12°~}are recorded. 3.5" TUBING -MAXIMUM RECORDED ID RESTRICTIONS : No other significant I.D, restrictions are recorded. `~~ oc~ ~ s ~oa~ ~i~ska fiJiE ii< has t;or~s, ~u~nrr~i~sicao ~nchexage PraActive Diagnostic Services, Inc / P.O. Sox 1369, Stafford, TX 77497 Phone; (281) or (888) 565-9085 Fax: {281) 565-1369 E-mail: PDS~c~memarylog.com Prudhoe bay Field Office Phone: (9Q7) 659-2307 l=ax; (9(I7) 659-2324 v'.C C 1qG -tea ~" /SSo~S~ • 4.5" LINER -MAXIMUM RECORDEp WALL PENETRATIONS Line Corrosion (40°k) Jt. 58 ~ 6,442 Ft. (MD) Corrosion (35°i6) Jt. 4 ~ 4,823 Ft. {MD} Isolated Pitting (35°~) Jt. i20 @ 8,302 Ft. {MD) Isolated Pitting { 34%) Jt. 31 ~ 5,627 Ft. (Mp) Isolated Pitting (33%) Jt. 104 ~ 7,805 Ft. (MD) 4.5" LINER -MAXIMUM REGORDED CROSS-SECTIONAL METAL LOSS ; Na significant areas of cross-sectional wall loss (> 1296} are recorded. 4.5" LINER -MAXIMUM RECORDED {D RESTRICTIONS No significant I.D. restrictions are recorded. Field Engineer. Vt/m McCnassan Analyst: J. Thompson Witness: C. Kennedy ProActive Diagnostic Services, ?nc. ;~ P.Q. Box 1369, Stafford, TX 77497 Phone: {281 j or (888) 565-9085 Fax: tZ81 565-1369 E-mail: PDS~a}memorylog.com Prudhoe Bay Fie{d Office Phone: (907) 659-2307 Fax: (907} 659-2314 • • Correlation of Recorded Damage to Borehole Profile Pipe 1 3.5 in (0.6' - 4720.5') Well: 2M-09a Pipe 2 4.5 in (4720.5' - 8933.5') Field: Kuparuk Company: ConocoPhillips Alaska, Inc. Country: USA Survey Date: September 28, 2007 ^ Approx. Tool Deviation ^ Approx. Borehole Profile 1 4 25 801 50 1594 75 2386 100 3179 125 3969 GLM 1 1 ~ 4720 p ~ ~~ , I - 5435 ~ ~ Z ,~ ~ j i w~ 6179 fl c ' . o ( _ p 7 ~ ~ ; "; I 6925 10t) 7674 125 ~ 8425 141 8934 0 50 100 Damage Profile (% wall) /Tool Deviation (degrees) Bottom of Survey = 141 U • PDS Report Overview ~~, ~. Body Region Analysis Well: 2 M-09a Survey Date: September 28, 2007 Field: Kuparuk Tool Type: UW MFC 24 No. 214040 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Anal st: .Thom son Tubing: Nom.OD Weight Grade & Thread Nom.ID Nom. Upset Upper len. Lower len. 3.5 ins 9.3 f L$0 EUE 8RD Mod 2.992 ins 3.5 ins 6.0 ins 6.0 ins Penetration and Metal loss (% wall) ~ penetration body ~ metal loss body 150 100 50 0 0 to 1 to 10 to 20 to 40 to over 1% 10% 20% 40% 85% 85% Number of 'oints anal sed total = 156 pene. 0 15 129 12 0 0 loss 39 115 2 0 0 0 Damage Configuration (body ) 150 100 50 0 isolated general line ring hole /pons pitting corrosion corrosion corrosion ible hole Number of ~oints dama ed total = 118 108 10 0 0 0 Damage Profie (% wall) ~ penetration body .;._~;_ metal loss body 0 50 100 GLM 1 Bottom of Survey = 147.1 Analysis Overview page 2 ~ ~ PDS REPORT JOINTTABULATION SHEET Pipe: 3.5 in 9.3 ppf L-80 EUE 8RD Mod Well: 2M-09a Body Wall: 0.254 in Field: Kuparuk Upset Wall: 0.254 in Company: ConocoPhillips Alaska, Inc. Nominal I.D.: 2.992 in Country: USA Survey Date: September 28, 2007 Joint No. Jt. Depth (Ft.) I'c~n. Upset (Ins.) Pen. Body (Ins.) Pen. % ~tctal I o5s `% Min. LD• (Ins.) Comments Damage Profile (%wall) 0 50 100 1 O 0.0 ~ (1 .96 PUP 1 4 O 0.0 i 3 2. 7 1.1 5 O .02 ~ 2.9 P P 1.2 44 U .01 -1 2.95 PUP 1.3 50 U .02 7 -1 2. 1 PUP 2 6 U 0.02 7 1 2.94 3 9 O 0.02 i I 2.9 4 123 O 0 02 7 I 2.95 5 155 0 0. 3 1 z (~ 2.95 187 U 0.03 12 1 2. 4 19 U .03 13 U 2.94 II w i tin . 8 250 a .03 1 1 .93 9 282 t) .03 1 1 I 2.94 10 314 t) 3 11 2. 4 11 345 (? .0 15 ri 93 Sh tlo itti its 12 377 O 0.04 1' ? 2.93 Shallow ittin . 13 409 U 0.0 1 s I 4 Is lated i t. De 14 441 U .05 1U (~ Bola ed 't' 14.1 473 (1 0.03 11 1 .94 PUP 14. 478 t) 0 U ti .81 Ni 14.3 480 O 0.01 5 I .9 PUP 15 486 a 0.03 12 1 2.94 6 517 t) 0.05 2U (~ .93 Shallow itti 17 549 U.U~ 0.04 17 ? 2.96 Shallow ittin . 1 5 0 t) 4 i hall w 'tt n. 19 612 U 0.04 1(~ I U 2.94 Shallow ittin . 2 644 U 0.04 1 ~ '~ .95 allow co osio . 21 675 l) 0.03 I2 II 2.94 2 707 U 3 13 7 .96 ha I itti 23 738 U 0.05 1 t9 ~~ 2.95 Sallow itti 4 77 U.05 0.07 17 It) 2.9 Isolat d ittin . 25 801 U 0.04 15 2.94 Shallow ittin . 26 833 U.U6 0.09 35 1 .96 Isolated ittin . 27 865 (1 0.07 Z(~ (~ 2.95 Isolated ittin . 2 897 tt .06 ~; t~ .94 Isolate ittin . 29 929 U 0.04 I' i' 2.95 Shallow ittin . 961 t) 0.06 ~'~ ~) 2.95 Isolated ~n . 31 992 U 0.06 2=1 b 2.94 Isolated ittin . 1024 U.U6 .04 1' f3 2.95 Shall ittin . 33 1056 a 0.04 1 ~ t3 2.96 Shallow corrosion. 34 1 7 U 4 1' ~~ .9 Sh I ow it ~n . 35 1119 O 0.06 ~4 2.95 Isolated itti 6 151 U 0. 6 'S Y 5 Is lated it ~n 37 1183 U 0.04 17 t; 2.95 Shallow it6n . 1 14 U 005 ~' I ~3 6 I ated it 'n . 39 1246 O 0.04 16 (, 2.95 Shallow ittin . 40 1278 (1 0.04 I' .94 Shallow ittin 41 1310 ~~ 0.04 I(, 1 2.96 Shallow ittin . 42 134? (1.(14 2.15 Shallt~~~~ ~~,rrosicm. ~~ ~ 1.ii ~ t).(1.~ _~ '.') i SI61~1(~tA ~lilll^,. Penetration Body Metal Loss Body Page 1 ~ ~ PDS REPORT JOINTTABUTATION SHEET Pipe: 3.5 in 9.3 ppf L-80 EUE 8RD Mod Well: 2M-09a Body Wall: 0.254 in Field: Kuparuk Upset Wall: 0.254 in Company: ConocoPhillips Alaska, Inc. Nominal I.D.: 2.992 in Country: USA Survey Date: September 28, 2007 Joint No. Jt. Depth (Ft.) I'~~n. 111>s~~t Iln;.) Pen. Body (Ins.) Pc~n. `% Mct.~l Ic~s~ °~> Min. LD• (Ins.) Comments Damage Profile (%wall) 0 50 100 44 1404 t) 0.04 1.> 5 2.93 Shallow ittin . 4 1436 U 0.03 1:3 I 2.94 Shallo itti 46 1467 ~) .03 la '~ 2. 5 Shallow 'ttin . 47 1499 ~ ~ 0.04 1 ~ `~ .94 hallow corrosion. - 48 1531 ~ ~ 0.03 12 3 2.94 49 1563 ~ ~ 0.05 1 `> 2.94 Shallow 'tti 50 1 94 ~ ~ .03 1 ~ ~ 2.93 51 1626 t ~ 0.03 I _~ i~ 2.94 Shalbw 'ttin . 52 165 t~ 0 03 11 4 2.94 53 1689 ~ ~ 0.03 1 I =~ 2.95 54 1721 (~ 0.03 12 ~~ .94 Shal ow ittin . 55 1753 l1 0.04 14 ri 2.95 Shallow corrosion. 56 1784 (~ 0.03 I _' I U 2.95 Shallow itti 57 1816 t~ 0.04 14 293 Shallow ittin . 58 1848 a 0.0 1 3 2.94 Shallow ittin . 59 1880 ~ ~ 0.04 14 I 2.94 Shallow c rr sion. 6 1912 t ~ 0.0 ~) ~ 2.93 1 1943 U .02 ti ~, 2 92 - 62 1975 (~ 0.02 `~ 2.94 63 2007 t~ 0.0 11 b .93 64 2039 (~ 0.03 1~ 5 2.93 65 2 69 l~ .03 12 2.94 - 66 2101 t ~ 0.03 1 1 ~# 2.94 Lt De osi 67 2133 c~ 0.03 11 -1 2.94 6 2164 t~ .0 ~~ ~ .94 69 2196 U 0.03 I ~' ti 2.95 70 228 t1 0.03 12 ti 2.94 Lt. D osits. 71 2260 l1 0.04 17 ~ 2.93 Shallow itti 72 2291 U 0.0 13 ~ 2.88 Shallow it'n Lt. De its. 73 2323 I1 0.04 15 4 2.91 Shallow 'ttin . Lt. De sits. 74 2354 O 0.04 I (~ ~ 2.93 Sallow ittin Lt. De sits. 75 2386 ti 0.03 12 # 2.94 76 2418 (_1.1:3 0.03 13 4 2.91 Shall w ittin , 77 2449 t1 0.04 1-# -} 2.94 Shallow 'ttin . 78 2480 t1 0.0 I! 5 2.88 hallo 'ttin . Lt. D i 79 2512 U 0.04 l b 2.90 Shallow ittin . 54 t) 0.04 17 4 2.9 Shallow 'ttin . Lt. a sits. 81 2575 (1 0.04 1 ~ 4 2.91 Shallow 'ttin Lt. De sits. 82 2607 l~ 0.05 ' 1 ~ 2.90 Corrosion. 83 2638 a 0.04 15 _' 2.93 Shallow ittin . 84 2670 t) .04 I ti _' .92 Shallow itti 85 2702 U 0.03 1 3 3 2.92 Shallow ittin . 86 2734 t~ 0.04 17 ~ 2.87 hallow ittin Lt De sits. 87 2765 t1 0.04 14 ~ .94 Shallow ittin . 8 2797 (1 0.04 1 7 Z 2.91 Shallow ittin . Lt. De sits. 89 2829 (~ 0.04 14 (, 2.93 Shallow ittin . 90 8 1 U 0.03 1 3 4 2.94 hallow ~ttin . 91 2893 t~.t~(~ 0.03 I ? > 2.89 Lt. De osits. Pittin in u set. 92 926 ~' 0.04 I (, ~ ~ 2.93 hallow itti 93 2957 0.04 1-1 2.93 Shallow ittin . _ Penetration Body Metal Loss Body Page 2 • • PDS REPORT JOINT TABULATION SHEET Pipe: 3.5 in 9.3 ppf L-80 EUE 8RD Mod Well: 2M-09a Body Wall: 0.254 in Field: Kuparuk Upset Wall: 0.254 in Company: ConocoPhillips Alaska, lnc. Nominal I.D.: 2.992 in Country: USA Survey Date: September 28, 2007 Joint No. Jt. Depth (Ft.) Pc~n. I11net IIrn.) Pen. Body (Ins.) Pen. % ti1~~t,il I „sti Min. LD• (Ins.) Comments Damage Profile (%wall) 0 50 100 94 2989 l).U7 0.04 15 .91 Shallow itti 95 3 21 tt 0.04 16 Is .9 Shallo Lt D its. 96 30 1 tt 0.0 1 2.93 Shallow 't in . 97 3084 t) 0.04 14 ~ .91 Sallow it6 t s'ts. 98 3115 U 0.04 15 4 .92 Shallow 't ' 9 3147 l) 0.0 I3 5 2.94 Sallow ~tti 100 3179 t t 0.04 I S -1 .9 Shallow 'tti 101 3210 U 0.03 I ~ 5 .94 102 3242 U 0 04 1 S -l 2.92 Shallow ittin . 10 3274 11.t)~) 0.03 1 ~? i 2.94 Shallow ittin . 104 05 tt 004 17 2 2. 1 Shallow ittin . 1 37 U .04 1 5 3 2.91 Shallow 'ttin . 1 6 3369 tt .04 14 .9 Shallow itti 107 3401 t t 0.04 14 .94 Shallow 'tti 108 3432 n 0.03 13 .91 hallow 'ttin . 109 346 tt 0.0 13 ~I 2.91 Shallow ittin . 1 0 3495 a 0. 4 17 4 2.91 S all w it in . 111 35 7 U 0. 3 13 3 .9 h low it 'n . 112 355 tt 0.05 ? 1 2. Iso ated ittin . 113 35 1 U 0.04 14 s .93 Shallow i tin . 114 3622 1 t 0.04 15 - 2.92 Shall w corrosi 1 3654 t t 0.03 1 2.93 Shallow 'ttin . 116 3685 t t 0.0 t £i 1 2.90 Shallo ittin . 117 3717 U 0.04 I t, l) 2.91 Shallow itti 1 3749 U .04 14 U 1 I w ittin 119 3781 U 0.03 l 3 1 2.91 Shallow ittin . 120 3812 It 0.04 17 2 90 hallow it i t D si 121 3843 l) 0.04 I i ~ 2.89 Shallow itti 1 3875 It 0.0 I £3 1 .89 Shallow 'ttin . 123 3907 tt 0.04 15 I 2.90 Shallow corrosion. 1 4 3938 t t 0.04 14 ~' 2.93 Shallow itti 125 3969 tt 0.04 15 .' 2.91 Shallow ittin . 12 4001 U 0.04 I4 I 2.91 Shallow ittin . 127 4032 tl 0.04 I6 1 2.91 Shallow ittin . 128 4064 U 0.04 14 0 1 hallow 'ttin . 129 4095 U 0.05 19 U 2.90 Sh Ilow ittin . 130 412 U 0.04 14 I 2.90 Shal ow 'tin . 131 4158 tt 0.03 1 . 1 2.89 Shallow ~ttin . 1 2 4190 t) 0.04 1 5 1 2.91 Shallow it i 133 4222 U 0.04 14 4 2.91 Shallow itti Lt. De sits. 134 4253 0 0.03 13 tt 9 Shallo i ' 135 4 84 U 0.03 1:3 ? 2.90 Shallow ittin . 13 4316 ct 0.04 1(~ _' .90 Sh Ilo orr sio . 137 4348 tt 0.04 14 I 2.88 Shallow ittin . Lt De sits. 13 4379 tt 0.0 14 t) 6 Sh Ilow i t. a sits. 139 4411 t t 0.03 I t 1 2.90 Shallow ittin 140 444 tt 0.04 I ~ ? 2.8 Shallow itfn . 141 4475 t) 0.03 13 2 2.91 Shallow 't6n . 142 45 U 0. 4 14 1 Sallow it in . 143 4537 U 0.04 15 (1 2.89 Shallow ittin . _ Penetration Body Metal Loss Body Page 3 ~ ~ PDS REPORT JOINT TABULAT70N SHEET Pipe: 3.5 in 9.3 ppf L-80 EUE 8RD Mod Well: 2M-09a Body Wall: 0.254 in Field: Kuparuk Upset Wall: 0.254 in Company: ConocoPhillips Alaska, Inc. Nominal I.D.: 2.992 in Country: USA Survey Date: September 28, 2007 Joint No. Jt. Depth (Ft) I'~~n. UI„et Iln,.l Pen. Body (InsJ Pc~n. °/, ~Ic~~,il I c~sc ~~ Min. LD• (Ins.) Comments Damage Profile (%wall) 0 50 100 144 4569 ~) .04 1 ~ 1 9 Shallow 'tt 1441 4600 ~) 03 tU 1 .89 PUP 144. 4606 u U U N A LM 1 N A 144.3 4615 a 0.03 I t _' 2.86 P P Lt. D sits 145 21 ~~ 0.03 13 t 2.89 Shallow ittin . 145.1 4652 (~ 0 U U 2.81 W-1 Ni e 465 (~ 0.04 1(i I 2. 1 Shallow 'tti 146.1 4686 l) 0. 2 ~) O 2.91 P U 147 4692 O.54 0.0 l u 2 91 Shallow ~tti H le in u 147.1 4719 U 0 u t~ N A 1TL Penetration Body Metal Loss Body Page 4 ~~ _ ~+~ PDS Report Cross Sections Well: 2M-09a Survey Date: September 28, 2007 Field: Kuparuk Tool Type: UW MFC 24 No. 214040 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 3.5 ins 9.3 ppf 1-80 EUE 8RD Mod Analyst: I. Thompson Cross Section for Joint 26 at depth 864.06 ft Tool speed = 43 Nominal tD = 2.992 Nominal OD = 3.500 Remaining wall area = 99 Tool deviation = 20 ° Finger 3 Penetration = 0.09 ins Isolated Pitting 0.09 ins = 35% Wall Penetration HIGH SIDE = UP • • Cross Sections page 1 ~ ~ ~ r ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~4 ~+~ PDS Report Cross Sections Well: 2M-09a Survey Date: September 28, 2007 Field: Kuparuk Tool Type: UW MFC 24 No. 214040 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: 3.5_ins _ 9.3 ppf L-80 EUE 8RD Mod Anal st: .Thom son Cross Section for Joint 24 at depth 800.24 ft Tool speed = 43 Nominal ID = 2.992 Nominal OD = 3.500 Remaining wall area = 95 Tool deviation = 13 ° Finger 22 Penetration = 0.068 ins Isolated Pitting 0.07 ins = 27% Wall Penetration HIGH SIDE = UP • r~ ~J Cross Sections page 2 • • PDS Report Overview ~~ s * Body Region Analysis Well: 2 M-09a Survey Date: September 28, 2007 Field: Kuparuk Tool Type: UW MFC 24 No. 214040 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Ana st: J. Thom son Tubing: Nom.OD Weight Grade & Thread Nom.ID Nom. Upset Upper len. Lower len. 4.5 ins 12.6 f L-80 3.958 ins 4.5 ins 6.0 ins 6.0 ins Penetration and Metal Loss (°~ wall) w penetration body ,_.~;, metal loss body 150 - 100 50 0 0 to 1 to 10 ro 20 to 40 to over 1% 10% 20% 40% 85% 85% Number of'oints anal sed total = 141 pene. 0 0 45 96 0 0 loss 112 28 1 0 0 0 Damage Configuration (body ) 150 100 0 0 isolated general line ring hole /puss pitting corrosion corrosion conrosion ible hole Number of ~oints dams ed total = 141 108 22 11 0 0 Damage Profile (°~ wall) ~ penetration body metal loss body 0 50 100 1 51 101 Bottom of Survey = 141 Analysis Overview page 2 • PDS REPORT JOINT TABULATION SHEET Pipe: 4.5 in 12.6 ppf L-80 Well: 2M-09a Body Wall: 0.271 in Field: Kuparuk Upset Wall: 0.271 in Company: ConocoPhillips Alaska, Inc. Nominal I.D.: 3.958 in Country: USA Survey Date: September 28, 2007 Joint No. Jt. Depth (Ft.) I'en. Upset (Ins.) Pen. Body (Ins.) Pen. %~ :~te~tal I ~~ss °~~ Min. LD• (Ins.) Comments Damage Profile (%wall) 0 50 100 1 4720 0 0.05 lts I 3.71 Shallow it' Lt e its. 2 4752 t) 0.06 ? I I 3.67 Isolated ittin De osits. 3 4782 U.U ~ 0.05 1 `) I .81 hallow Corrosi n. Lt De its. 4 4813 O.U~ 0.10 3.5 2 3.77 Corrosion. Lt. a sits. 5 3 U 0.09 i! 1 3.8 Corrosi n. Lt. a osits. 6 4873 U 0.07 Z~1 I 3.80 C rrosion. Lt a osits. 7 4903 t) 0.07 18 I 3.82 Isolated ittin Lt. De sits. 8 4932 U 0.07 ! ~ I 3.81 Line corrosion. Lt. De osits. 9 4962 U 0.06 ~~1 I 3.80 Isolated ittin . Lt. De sits. 10 499 t).Ub 0 06 Z-1 I 3.81 I lated ittin Lt. a sits. 11 502 U 0.07 _'7 I 3.81 Isoated ittin . Lt De si 12 5052 U 0.08 _'~~ I 3.84 I lated itti Lt De si 1 508 a 0. 7 zt> I .74 Co rosion. a sits. 14 511 U 0.07 Z7 1 .82 Isolated ittin t. De 15 5141 U 0. 8 ~t9 1 3.83 late ittin . t. De s'ts. 16 5171 U 0.06 ' ~ I 3.7 Isolated ittin Lt. a sits. 17 5201 U D.05 1') 1 3.84 Shallow ittin . L De sits. 18 5230 U.05 0.06 2 I I 3.79 Isolated ittin Lt De sits. 19 5260 U 0.06 ZZ 1 3.46 Isol to ittin . De sits. 0 5288 U 0.04 17 1 3.85 Shallow corrosion. Lt. De o its. 21 5318 U 0.0 ' 1 b 3.82 Isolated ittin t. De sits. 22 5347 U 0. 6 12 1 3.8 Isolated ittin t. De sits. 3 5376 0 0.04 17 1 3.83 Sha low 'ttin Lt. s'ts. 24 5406 0 0.05 I ti i 3.84 Shallow corrosion. Lt. De osits. 25 543 t) 0.05 I ti t .83 Shall w ittin . 26 5465 t) 0.05 I t3 1 3.87 Shallow ittin . Lt. De sits. 27 5493 0 0.07 _' ~ I 3.85 Line rrosion. Lt. De si 28 5523 0 0.05 ZO 1 3.79 Shallow ~tti Lt. De sits. 9 554 U 0.0 19 I 3.8 Line shallow corrosion. Lt. a os'ts. 30 5584 U 0.05 1 t9 I 3.84 Shallow ittin Lt. De sits. 1 5613 U 0.09 34 1 3.66 Isolated ittin . Lt. De sits. 32 5644 U 0.05 18 1 3.84 Shallow ittin . Lt De sits. 33 5673 t) 0.05 17 I 3.80 Shallow 'ttin Lt De sits. 34 5703 U 0.05 I ~> I 3.81 Shallow corrosion. Lt. De osits. _ 5 5734 O 0.06 12 1 3.8 Isolated i ti Lt. De its. 36 5765 l).O7 0.08 a0 -3 3.85 Isolated ittin Lt. De sits. 37 5793 t) 0.08 28 1 3.76 C r osion. Lt. De o its. 38 5824 t) 0.06 11 I 3.83 Isolated itti Lt. De sits. 39 5854 U 0.06 1~i -1 3. 2 Isolated ittin Lt De sits. 40 5883 t) 0.06 ~0 1 3.83 Isolated ittin . Lt. De sits. 1 5911 t) 0.06 Z2 1 3. 2 I lat d itti t. a si 42 5941 U 0.07 15 I 3.83 Isolated ittin . Lt. De sits. 43 5969 U 0.07 ?4 5 3.84 Corrosi n. L e osits. 44 6000 U 0.08 i0 1 3.78 Isolated ittin . Lt De sits. 4 6029 U.05 0.0 Si) I 3.85 Isolated ittin . 46 6059 l) 0.05 ~U I 3.74 Isolated ittin Lt. De sits. 47 6091 0 0. _'8 I 3.85 Isolated itti Lt. D i 48 6119 U 0.07 ?4 1 3.84 Isolated ittin . 49 6148 0 0. 6 24 _' 3.86 Isolated ittin Lt. D si 50 6179 0 0.05 I8 1 3.80 Shallow >ittin Lt. De osits. Penetration Body Metal Loss Body Page 1 • PDS REPORT JOINT TABULATION SHEET Pipe: 4.5 in 12.6 ppf L-80 Well: 2M-09a Body Wall: 0.271 in Field: Kuparuk Upset Wall: 0.271 in Company: ConocoPhillips Alaska, Inc. Nominal I.D.: 3.958 in Country: USA Survey Date: September 28, 2007 Joint No. Jt. Depth (Ft) Pc~n. Up~c°t Iln~.) Pen. Body (Ins.) Pen. % Mc~t,il I ors °~~~ Min. LD• (Ins.) Comments Damage Profile (%wall) 0 50 100 51 6207 l) 0.05 1 £3 I 3.84 Shallow 'tti 2 6 36 t) 0.06 23 I 3.85 Isolated ittin . D its. 3 6 7 U 0.05 I £3 1 .8 Shallow ittin . 4 6 4 t ). U 5 0.06 ~~ 3.85 C rrosi n. Lt De o i. 55 6324 t) .0 I' I 3.8 Shall w itti 56 6354 t) 0.0 1 ti I 3.79 hallow itti L . De 'ts. 7 385 t) 0.0 21 1 3.87 Isolated ittin . 58 6415 U 0.11 4t) 1 3.83 Line corrosion. 59 6 5 U.US 0.0 ll 1 3.84 I late ittin Lt. a sits. 647 U.US 0.0 21 1 3. 6 I I ted itti 61 6504 t) .0 _' ~ I 3.84 I I ted itti L . si 62 6534 a 0. 5 I ~~ 1 3.84 Sha to it 'n . 63 6565 i) 0.0 2U I 3.87 Corrosion. t. si 64 6594 t) 0.06 21 3 3.74 I a ed ittin . i 65 6 4 t) 0.07 24 1 3.85 Isola ed ittin . Lt. si 66 6655 l).tLS 0.07 <'=1 I 3.68 Isolated ittin . osits. 67 668 U 0.06 Z3 I 3.86 I I ted it 'n . 6 6714 U .07 Z 7 I .84 C r osio Lt. a osi 69 6745 O 0.08 Z~1 1 3.83 Isoated 't' t i . 70 6775 it 0.05 1 t3 1 .84 Sh Ilow ittin Lt. si 71 6803 U 0.05 1 ti 1 3.86 Shallow ittin t. De sits. 7 6834 U 0.05 18 1 3. h Ilow ittin ~ts. 73 6865 U 0.0 27 1 .85 Isol ted ittin . Lt. D sits. 74 6895 t) 0.07 17 1 3.66 Isolated itti De osits. 75 69 U 0.07 ~~ 1 3 83 C rro ion. 76 6955 U.uS 0.05 1 ~~ 1 3.87 Shallow itti 77 6984 U 0.04 I S 1 3.85 Sh II w ittin . t 'ts 78 7012 t~ 0.07 Z7 1 3.85 Isolated ittin . 79 7042 t) 0.06 <' I 1 3 8 I lated ittin . Lt De 80 7073 U 0.05 1 t~ 1 3.85 Shallow ittin . 81 7102 tt 0.07 27 1 3.8 Line corrosion. 82 7132 U 0.05 1 ~) 1 3.87 Shallow ittin . Lt. a sits. 83 7162 U 0.05 2t) I 3.85 Isolated it'n . 84 7193 U 0.06 ' I I 3.88 Isolated ittin . 85 722 U 0.07 _' 7 I 384 C rrosion. Lt. a ~ts. 86 7252 U 0.07 Z 7 I 3.85 Isolated ittin . 7 728 t) 0.09 S > 1 .85 solated ittin t i 88 7314 U 0.05 1 t3 1 3.86 Shallow ~ttin . Lt. De sits. 89 734 a 0 0 1 ~) U 3.84 Shallow i ti 90 7375 t) 0.06 Z ~ I 3.85 Corrosion. Lt. De sits. 91 7404 U 0.05 1 ~~ I .85 Shallow it 92 7435 U 0.08 t) 1 3.84 Isolated itti 93 7465 t) .06 ~ 1 I 3.84 Isolated ittin . t. De sits. 94 7495 t) 0.07 27 I 3.87 Isolated ittin . 95 7524 U 0.08 31 I 3.83 Isolated ittin . Lt. ~ts. 96 7554 U 0.06 2 I I 3.85 Line corrosion. 97 7584 U 0.0 2 3 I .85 Isoated ittin . t. 'ts. 98 7614 U 0.08 ~~) 3.80 Isolated ittin . Lt. De sits. 99 7644 ~' 0.09 ~ 1 I 3. Isol_~tc~d r~ittin t_t. De si 100 7674 0.08 2~3 I 3.76 C~~rr~~~i~>n. Lt. Dc~osits. __ Penetration Body Metal Loss Body Page 2 ~ • PDS REPORT JOINT TABULATION SHEEP Pipe: 4.5 in 12.6 ppf L-80 Well: 2M-09a Body Wall: 0.271 in Field: Kuparuk Upset Wall: 0.271 in Corr any: ConocoPhillips Alaska, Inc. Nominal I.D.: 3.958 in Country: USA Survey Date: September 28, 2007 Joint No. Jt. Depth (Ft.) Neon. l1iriE°t (In,.) Pen. Body (IrtsJ Pcn. % al~~t,il loss °~~ Min. LD• (Ins.) Comments Damage Profile (%wall) 0 50 100 1 1 770 U.l~b 0.06 Z 1 1 3.83 corm ion. t De si 1 77 4 t) .06 Z 1 ~ 87 I lated i 'n t, De si 1 3 7763 It 0.07 24 ~ 3.85 Line c rrosion. Lt. e sits. 10 7793 t) 0.09 33 I .85 Isol ted i tin . 1 5 7 t~ 0.06 Za 4 .85 Isolate ittin . Lt. si 106 785 t) 0.06 Z I 1 3.84 Isol t d ittin . 1 7 7885 U 0.07 2(> ~ 3. 6 Isol ted it 'n Lt De si 108 7914 U 0.05 ~U I 3.86 Isolated ~ttin . 109 7944 t~ 0.07 2b I 3.82 I lated ittin 1 0 7974 U.US 0.08 3l) 1 3.84 Iola ed ittin t. e i 111 8004 t! .06 I 1 3.85 la ed itti 112 34 t) 6 22 I 3. Isolate ittin . 113 8065 t ~ 0.07 ~' > I 3.87 Isolated ittin . 114 8094 U 0.06 14 I 3.87 Cor osion. 11 1 U 0 21 I 8 solated it'n . 116 8156 U 0.06 24 a 3.85 I -ated i 'n 117 186 ~? 0.07 27 I 3.83 Isolated it' 118 8217 t~ 0.06 24 1 3.86 Isolated it6 De its. 119 8 6 U 0.06 22 1 3.8 Isolated ittin 120 827 (1 0.10 35 I .87 I olated ittin . 121 8306 U 0.08 2t3 I 3.71 Line rrosion. De si 122 8336 t).U ~ 0.06 '3 1 3.88 Isol ted itti D si 123 8366 t) 0.07 27 I .88 Isolate itti 124 8396 t) 0.07 25 1 3 88 Isolated itti 1 25 tl .0 27 1 I I 'ti L. of . 126 8454 U 0.08 28 1 3.85 Corrosion. 127 8487 u 0 2U 1 3.79 Isolated itti t. 128 8516 tl 0.07 25 ,? 3.87 Corrosion. 129 8549 t) 0. 22 1 ti 3.65 Corr lion. Sli Mash. 130 8581 tt 0.05 Z(t 3.89 Isolated itti 131 861 !~ 0.04 17 4 3.89 Shallow it'n . 132 8644 U 0.05 1 ti ~ 3.88 Shallow ittin . 1 8676 tt 0.0 2 I 3.85 Line corrosi n. Lt. De sits. 134 8708 U 0.0 1 t3 3.86 Shallow ~ttin . Lt. De sits. 135 8741 O 0.05 1 t3 3. 9 Shallow ittin . 136 8773 tt 0.06 22 -1 3.67 Corrosion. De 'ts. 1 7 8805 t~ 0.06 Z3 Z 3. 8 Corrosion. 138 8837 tt 0.05 lt3 5 3.88 Shallow itti Lt.De sits. 139 88 9 tt .0 18 3 .87 Shallow ittin . 140 8901 t~ 0.05 1 t3 3 3.91 Shallow 'ttin . 141 8934 U 0.0 14 ~' 3.92 Shall w itti Penetration Body Metal Loss Body Page 3 i i i ! i i i i i i i i i i i i i ! i PDS Report Cross Sections ~u -~ „ Well: 2M-09a Survey Date: September 28, 2007 Field: Kuparuk Toot Type: UW MFC 24 No. 214040 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubinu: 4.5 ins 12.6 ppf L-80 Analyst: I. Thompson Cross Section for Joint 58 at depth 6441.76 ft Tool speed = 43 Nominal ID = 3.958 Nominal OD = 4.500 Remaining wall area = 98 Tool deviation = 47 ° Finger 11 Penetration = 0.108 ins Line Corrosion 0.11 ins 40% Wall Penetration HIGH 51DE = UP • • Cross Sections page 1 PDS Report Cross Sections Well: 2M-09a Survey Date: September 28, 2007 Field: Kuparuk Tool Type: UW MFC 24 No. 214040 Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69 Country: USA No. of Fingers: 24 Tubing: __ _4.5 ins 12.6 f L-80 Anal st: .Thom .son Cross Section for Joint 4 at depth 4822.8 ft Tool speed = 43 Nominal ID = 3.958 Nominal OD = 4.500 Remaining wall area = 98 Tool deviation = 70 ° Finger 14 Penetration = 0.095 ins Corrosion 0.09 ins = 35% Wall Penetration HIGH SIDE = UP • • Cross Sections page 2 ' • KR U 2M- A 09 ConocoPhillips Alaska, Inc. ' 2M-09A API: 50103201 7701 Well T INJ An le TS: 36 d 9084 SSSV Type: NIPPLE Orig 6/14!1996 Angle ~ TD: 33 deg ~ 9405 Com lion: Annular Fluid: Last W/O: Rev Reason: TAG FILL ' NIP (514-515, Reference L Ref L Dete: Last U ate: 8/12/2007 o0:a.5oo) Last Ta : 9105' TD: 9405 ftKB TUBING 3 7~ Last T Date: 8/9/2007 Max Hole An le: 69 d 4124 , Casin Stri -CONDU CTOR tD:2.992) rl bon Size 7 ottom TVD reds Th d ' CONDUCTOR 16.000 0 121 121 62.50 H-40 C in Stri - SU FA CE Deecri lion Size To Bottom TVD Wt Grade Th SUR. CASING 9.625 0 4306 2775 40.00 L-80 Casin SM PRODU CTION Ab d O i fi l W • Sid d llb tr k ' k Off 4980 - Descri lion an on r na e ore e Size To Bottom TVD ac c Wt Grade Thread Gas LiR - ~ ~ PROD. CASING 7.000 0 4980 3043 26.00 L$0 ~"~°°"my Casin Stri -LINER valve t ^ I Deecri don 81ze T tt B TVD Wt G d Th (as3t-4x32, OD:5.583) LINER 4.500 4717 o om 9402 6297 12.60 ra e L-80 ree PROD. -' Tubl Stri -TUBING CASING (0-4980 Slze 7 ottom TVD Wt Grade Thread , Op:7,0o0 3.500 0 4719 2937 9.30 L-80 EUE 8RD MOD , '^~~0°) Perforations Summa ' Interval Zone Status Ft SPF Date T e Comment 9084 -9096 6036 - 604 6 C-4,A-5 12 3 7/10/1996 IP ERF 21/8" HC, 180 deg. phase; oriented 165 deg. CCW F/ NIP HI h $I ' (4x77-4s7s, 9104 - 9133 6052 -6076 A-4 29 3 7/10/1996 IP ERF 2 1/8" HC, 180 deg. phase; 00:3.500) oriented 165 deg. CCW F/ Hi h Si 9149 - 9214 6089 - 6142 A-3 65 4 7!10/1996 IPERF 2 1/8" HC, 180 deg. phew; oriented 165 deg. CCW F/ ' H~ h Si Lift M G d l N l as an re s a v es 3t MD TVD Man Mfr Man Type V Mfr V Type V OD Latch Port TRO Date Run Vlv P~ 1 4631 2901 Camco MMM DMY 1.5 RK 0.000 0 6/14/1996 Cmnt ' (4717-47,8, Other ui et c -JEWEL o0.s.ts1) D th 7VD . T . Deacri tlon ID SPACE OUT (4718-4719, 514 513 NIP Camco'DS' Ni NO GO 2.812 OD:3.500) 4677 2919 NIP Camoo'W-1' 2.812 TTL 4717 2936 PKR Baker'ZXP' w/ 7.39' C2 Tie Badc Sleeve 4.438 ' (471s-arz°• 4718 2936 SPACE 2 992 00:3.500) OUT . 4719 2937 TTL 2.992 ' 9017 Gener 5981 al Note NIP s Camco 5" X 3.813" DB5 Nipple w/3.81 maxi big bore lode w/Otis 2.313" X 2.313 ro61e 8 WL en uide Ds Nola NIP 2/6/2006 NOTE: WAIVERE D WELL: SHALLOW PACKER "`WATER INJECTION ONLY"' (9017-9018, OD:5.000) LINER (4717-9402, OD:4.500, VVt12.60) Pert (9064-9098) Pert (9704-9133) Pert (9149-9214) Sehlußlbepge, NO. 4468 Schlumberger -DCS 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth Company: Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 s~ANNE.D OCT :) 1 2007 Field: Kuparuk Well Log Description BL Color CD Job# Date 2N-327 11839673 PERF/SBHP .;)D~ ~ ()G.C¡ 10/24/07 1 2T -201 (REPLACES 11839656 INJECTION PROFILE Ù -rC-- I c¡ 5' - f;:J rl 09/03/07 1 1A-23 11837520 PRODUCTION PROFILE /0, I-oc:f\ 10/04/07 1 2M-09A 11846446 WFL í):t..~ ,q(A -(-.p,ò 10/04/07 1 31-08 11837517 LDL / ~(A - (WI) 10/02/07 1 2M-24 11839670 PRODUCTION PROFILE Iq .;) -05""<) 10/03/07 1 1J-102 11846451 INJECTION PROFILE û-:tQ.. r9<::Io -/tÒ 10/10/07 1 1Y-02 11837516 INJECTION PROFILE í JTC'.I 'X~ - 059 10/01/07 1 1E-112 11846450 INJECTION PROFILE l )-r(l ~^<.1_rA 1 10/10/07 1 2T-12A 11839669 LDL J«v - I ~ 5(' 10/02/07 1 2B-07 11837522 INJECTION PROFILE UT c.. I "if4 -('A<..( 10/05/07 1 1E-12 11846447 DDL I "x".:l - N,., () 10/08/07 1 2N-327 11839671 SCMT d--O '1- - Oç, '9 10/23/07 1 Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. i3 10/25/07 . . • • ' - - SARAH PALIPV, GO!lERAIOR ~ 333 W. 7th AVENUE, SUITE 100 ~ ~~TT ~-y~gg ~ ~~1~t~~~~~aY®~ ~i®li ® ANCIiORAGE, ALASKA 99501-3539 L -7 PHONE ;907} 279-1433 FAX (907) 276-7542 ADIVIINIS~'RATNE APPROVAL NO. AID 2B.004 (Amended) Ms. MJ Loveland. Problem Well Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99~ 10-0360 RE: Kuparuk River Unit 2M-09A (196-090) Revised Administrative Approval Dear Ms. Loveland: ~`>~~1~ JAN ~~ ~ 2~0 Administrative Approval AIO 2B.004 issued February 6, 2006 set forth conditions for operating Kuparuk River Unit ('`KRU"j 2M-09A (PTD 196-090) including biennial mechanical integrity tests of the tubing and inner annulus. The specific tests were required by the Alaska Oil and Gas Conservation Commission ("Commission") to demonstrate integrity of the injection string (combination of tubing and liner) and the production casing (the 7" casing above the liner top). By electronic mail dated August 31, 2007 ConocoPhillips Alaska, Inc ("CPAI") advised of apparent damage to the nipple profile preventing installation of the plug for the injection string mechanical integrity test ("MIT-T"). Caliper and water flow logs were suggested by CPAI as alternatives to the required test. The Commission concurs with CPAI's recommendation to substitute caliper and water flow logs for the MIT-T. This revised administrative approval allowing injection in KRU 2tiI-09A is conditioned upon the following: 1. Injection is limited to WATER ONLY; 2. CPAI shall monitor and record tubing, inner annulus, and outer annulus pressures and injection rate daily; 3. CPAI shall submit to the Commission a monthly report of well pressures and injection rates; 4. CPAI shall demonstrate the continued integrity of the injection string every 2 years. A MIT-T employing the nipple profile at 9017' md, or water flow and caliper logs may be performed; 5. CPAI shall perform a mechanical integrity test of the inner annulus (`'MIT-IA"} every 2 years to demonstrate continued integrity of production casing; 6. CPAI shall immediately shut in the well and notify the Commission if there is any change in the well's mechanical condition; Admin;strati~e .Approval A[O ZI~UUdA September ~, ?007 Page ? of 2 7. After well shut in due to a change in the well's mechanical condition, Commission 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 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. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. D®NE at Ancage, Alaska and dated September ~, 2007. i .Nor an Dan T. Seamount Chairma Commissioner `~`~-- Cathy . Foerster Com issioner 2M-09A (PTD 196-090, AIO 28.004) , Page I of 3 Regg, James B (DOA) From: Regg, James B (DDA) Sent: Tuesday, September 04,200710:31 AM To: Maunder, Thomas E (DDA); 'NSK Well Integrity Prof Cc: 'NSK Problem Well Supv' Subject: RE: 2M-09A (PTD 196-090, AID 28.004) í<efT ?h1D7 SCANNED SEP 1 1 2007 This sounds like a permanent change to the conditions of the AA. We can issue a revised AA based on your email request. Will try to get that out to you within next couple days. Jim Regg . ADGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: Maunder, Thomas E (DDA) Sent: Friday, August 31, 20073:08 PM To: NSK Well Integrity Proj; Regg, James B (DDA) Cc: NSK Problem Well Supv Subject: RE: 2M-09A (PTD 196-090, AID 2B.004) MJ, Jim is gone for the day. I don't have a problem with your proposal. Lets follow up next week, but my suggestion would be to file a sundry for the alternate test. Don't send a sundry until we can talk with Jim. . Tom Maunder, PE ADGCC From: NSK Well Integrity proj [mailto:N1878@conocophillips.com] Sent: Friday, August 31,20072:37 PM To: Regg, James B (DDA); Maunder, Thomas E (DDA) Cc: NSK Well Integrity proj; NSK Problem Well Supv Subject: 2M-09A (PTD 196-090, AID 2B.004) Jim, 9/4/2007 2M-09A (PTD 196-090, AI0 28.004) , Page 2 of3 2M-09A (PTD 196-090, Ala 28.004) is a water only injector that has the an AA for the packer -4000' above the perforations. The AA requires a biennial compliance MIT-í and MIT- IA pressure tests which are coming due. Slickline has made several unsuccessful attempts to set a plug in the 2.313" Otis profile at 9017' as per directed in the AA for the MIT-T. It appears the nipple profile may be damaged. Due to the tubing size (3.5") and liner size (4.5") setting a wireline retrievable plug is not possible and setting an IBP in the 4.5" is not practical for plug recovery . Would it be acceptable to substitute a caliper log and waterfJow log for the required MIT-T? Alternatively we could pursue the MIT-T with a sand plug followed by a CTU clean out. Our preference is logging. I can rewrite and resubmit the AA if required. Attached is a schematic and a TIO plot. The well was Sian Aug 10th 2007. Please Advise. . Thank you MJ Loveland Well Integrity Project Supervisor ConocoPhillíps Alaska, Inc. Desk Phone (907) 659-7043 Cell Phone (907) 448-3114 «2M-09A.pdf» . 9/4/2007 2M-09A (PTD ! 96-090, AIO 28.004) ~ Page 3 of} 9/4/2007 plot Well Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska 907-659-7043 Tom Maunder MOhthly Data 09-06.xls What's 2M-09A" fluid_ volume injected, or Admio Approval IArO 2B04) in IA have nearly donbled and OA would result these effort to diagnose the source Jim Regg Re: 2M-09A Trend Plot . . AOGCC NSK Well Integrity Proj wrote: «CPAI Failed MITIA Monthly Data 09-06.xls» Attached is the September failed MIT report for Kuparuk/Alpine. Please let me know if you have any questions MJ Loveland ConocoPhillips Alaska Welllnteglity Project Supervisor Office (907) 659-7043; Cel (907) 448-3114 20£2 10/16/20064:33 PM e FRANK H. MURKOWSKI, GOVERNOR AlASIiA OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL 2B.004 Mr. Jerry Dethlefs Problem Well Supervisor ConocoPhi1lips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: Kuparuk River Unit 2M-09A (196-090)4 Request for Administrative Approval Dear Mr. Dethlefs: On November 5, 2005 ConocoPhillips Alaska, Inc ("CPAI") requested an administrative approval under Rule 9 of Area Injection Order ("AIO") 2A for service well Kuparuk River Unit ("KRU") 2M-09A (PTD 196-090). The specific request was to allow the continuation of water alternating gas ("WAG") injection. Please note that AIO 2B, effective December 12,2002, superceded AIO 2A. Your request to employ the well in WAG service is denied. The Alaska Oil and Gas Conservation Commission ("Commission") has determined that CP AI may employ the well in WATER ONLY service, as detailed below. 2M-09A is a redrill of 2M-09. The new bottom-hole location was accessed by plugging the original well and exiting the production casing at about 4980' measured depth ("md") and drilling new hole to 9405' md. A 4-1-2" liner was set from total depth to 4717' md. The liner was cemented to provide required formation isolation. The well is equipped with a 3-112" tubing string that is sealed into the liner top. As constructed, 2M-09A does not meet the requirements of 20 AAC 25.412 (b) for an injection well which is required to be equipped with a packer set not more than 200' measured depth above the top of the perforations. The purpose of this requirement is to ensure that the injection string can be monitored throughout its length for possible leakage. As constructed, over 4000' of this wellbore cannot be monitored. Where fresh water is not affected, 20 AAC 25.450 gives the Commission authority to approve less stringent well construction and integrity requirements. For wells similarly constructed, the Commission has exercised this discretionary authority and approved injection operations with the fluid limited to water only. CP AI has provided pressure test information using water that appears to demonstrate that the injection string (combination of tubing and liner) and the production casing (the T' casing above the liner top) do have integrity. However, experience has shown that it is still possible for gaseous fluids to leak where water will not. Were a leak to develop e e Administrative Approval AIO 2B.004 February 6, 2006 Page 2 0[2 somewhere in the liner, it could not immediately be recognized so operations could be halted. Allowing gaseous hydrocarbon fluids to escape from a wellbore, regardless of those fluids still being isolated below ground, could constitute waste as well as result in a subsurface hazard. Neither is acceptable. Per Rule 9 of Area Injection Order 2B, the Commission ("AOGCC") hereby grants, in part, CPAI's November 5, 2005 request for administrative approval to allow 2M-09A to remain in service. The Commission's administrative approval allowing injection In KRU 2M-09A IS conditioned upon the following: 1. Injection is limited to WATER ONLY; 2. CP AI shall monitor and record tubing, inner annulus, and outer annulus pressures and injection rate daily; 3. CP AI shall submit to the Commission a monthly report of well pressures and injection rates; 3. CP AI shall perform a mechanical integrity test of the tubing/liner string ("MIT- T,,) every 2 years by employing the nipple profile at 9017' md to demonstrate continued integrity of the injection string; 4. CP AI shall perform a mechanical integrity test of the inner annulus ("MIT -IA") every 2 years to demonstrate continued integrity of production casing; 5. CP AI shall immediately shut in the well and notify the Commission if there is any change in the well's mechanical condition; and 5. After well shut in due to a change in the well's mechanical condition, Commission 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 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. A person may not appe a Commission decision to Superior Court unless rehearing has been requested. rage, Alaska and dated Februar 6,2006. Page 1 of 1 Maunder, Thomas E (DOA) From: Cathy Foerster [Cathy_foerster@admin.state.ak.us] Sent: Wednesday, February 01, 2006 8:01 AM To: Maunder, Thomas E (DOA) Subject: Re: [Fwd: Re: A1026.OXX] Attachments: 2006_0124_2M-09A 196-090_tem_cpf edit.doc; cathy_foerster.vcf One little edit. Otherwise looks good. Thomas Maunder wrote: Cathy, Here is the latest draft that Jim and I worked on of that AA for 2M-09A. It has been mintzed and he was very kind. If you are in agreement with the form/content of this, then we can get Jody to finalize. Thanks, Tom -------- Original Message -------- Subject:Re: AI02B.OXX Date:Fri, 27 Jan 2006 14:41:59 -0900 From:Rob Mintz <robert mintz law.state.ak.us'> , _ ~, .; , Toaom maunder@admin.state.ak.u_s ,,a,~,,~v~ ~ ~`~.~-=~- Tom, looks good. »> Thomas Maunder <tom maunder@admin.state.ak.us> 1/25/2006 11:07:29 _. - __ AM »> Rob, I have made a further stab at this AA. Jim and I have discussed about including the paragraph I call "History". This is the first AA for this type of well we have done. I think it may be appropriate to provide some history and reasoning for the approval/denial "in part". I do get pretty specific about the possibility of gas leakage and the consequences. Do we need to state anything regarding water leakage? Water leakage is also possible, however less likely and the consequences of leaking water carry no where near the risk of a gas leak. FYI, the reason for this is that the gas or MI is an energized fluid. It is highly compressed and it will expand if given the opportunity. The lighter density of gas/MI makes it prone to migrate to lower pressure (shallower) if it has the opportunity. Water on the other hand is nearly incompressible and since its density is about the same as any other fluids external to the wellbore, there is not "driving force" to make it move. Please hack away. Tom 8/31/2010 Message Maunder, Thomas E (DOA) From: NSK Problem Well Supv [n1617@conocophillips.com] Sent: Tuesday, January 17, 2006 10:26 AM To: Maunder, Thomas E (DOA) Subject: RE: 2M-09A (196-090) I completely understand. "Straight forward" are not the words I'd use to describe this one.... mj -----Original Message----- From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Tuesday, January 17, 2006 10:03 AM To: NSK Problem Well Supv Subject: Re: 2M-09A (196-090) Page 1 of 2 Hi MJ, I am working on a reply and hope to have it out this week. This one has been under a fair amount of discussion. Tom NSK Problem Well Supv wrote, On 1/17/2006 8:58 AM: Tom, Where does this AA stand? Thanks MJ ----Original Message----- m: Thomas Maunder [ma_ilto:tom maunder@admin.state.ak.us] Sen . ednesday, November 09, 2005 10:25 AM To: NSK lem Well Supv Cc: ]im Regg Subject: Re: 2M-0 96-090) Jerry, I have received the AA applicatio have started my file research. Since the well was completed in 1996, the only item subm from the you all is a 404 from January 2002 with WINJ to WAG indicated. This is intere since according to the injection record MI first went into the well in March of 2000. Anywa , o fill out the record, could you please pull that "event summary" similar to what you sent me other day on 1F-18A?? This AA will be interesting. You have a monobore (as we them) and you are looking to have approval to inject MI. For the wells we knew of with simi construction, MI has not been allowed without "alteration" of the completion to provide a m 'torable annulus. How has the "short" IA been performing?? How far back can you provide information?? Being able to look at the pressure performance when the fluids hav een switched would be informative. Last time our record shows MI into the well was Feb 2004. Can you go back that far?? Has there been any need to manage the pressure in the IA aside from thermal effects when the fluids are changed?? Is there any plan to run a "gas 8/31/2010 • • Maunder, Thomas E (DOA) From: Thomas Maunder [tom maunder@admin.state.ak.us] Sent: Wednesday, January 11, 2006 8:38 AM To: 'Rob Mintz' Cc: Regg, James B (DOA) Subject: Re: [Fwd: 2m-09a denial] Rob, This is the short answer. I have a longer one, but this cuts to the chase. I don't think an amendment to the regulations is necessary. Yes, since this is a service well 25.412 (b) applies. But so does 25.450 which allows the Commission to grant variances when fresh water is not present. All aquifers were exempted at Kuparuk by EPA in the early days of the UIC program. For similarly constructed wells (there are a few out there), we have authorized use as water injectors only. This precedent was established by Blair in May 1997. This well only recently came up on our radar and they have been alternating water and MI in the well since March 2000. In their application, they clearly documented the redrill construction and their intent to employ the well as a WAG (water alternating gas) injector. The permit was approved with no stipulations or limits. They obviously know our position on the use of this well since they have applied for an AA to keep it in use. If they only wanted water, there likely wouldn't be a problem approving their request. Wanting also inject MI is the issue. We know that tubulars (screwed pipe) can and do develop leaks. We also know that MI can leak when water won't. The consequence of a water leak is much less than an MI leak. Our position is that if CPAI is intending to employ this well in MI service, that they should make their case in a public forum (hearing). Back in your court. Tom Rob Mintz wrote, On 1/10/2006 3:19 PM: > Tom, is the regulatory requirement in question 20 AAC 25.412(b)? >'Cause if it is, that provision has its own exception: "unless the >commission approves a different placement depth as the commission >considers appropriate given the thickness and depth of the confining >zone." > On the other hand, if the well construction truly deviates from the >requirements of one or more regulations that do not include their own >variance or exception provisions, then there is no way to make an >exception short of amending the regulation(s), since 20 AAC 25.505{b) >doesn't allow exceptions to be made to regulations "which govern >underground injection and the protection of freshwater." > So I think how we proceed depends on the answer to the first >question above, »»Thomas Maunder <tom maunder@admin.state.ak.us> 1/10/2006 8:59:42 AM »» »» »» >Rob, >Here is the proposed text of a letter to CPAI denying their request to >inject Mi (gas) into a well with non-standard construction. Would you >please have a look? >Thanks, >Tom 1 • >-------- Original Message -------- >Subject: 2m-09a denial >Date: Mon, 09 Jan 2006 15:44:12 -0900 >From: Thomas Maunder <tom maunder@admin.state.ak.us> >Organization: State of Alaska >To: Cathy Foerster <cathy_foerster@admin.state.ak.us> >CC: Jim Regg <jim regg@admin.state.ak.us> >Cathy, >Here is the proposed letter Jim and I have collaborated on regarding >CPAI's request and non-standard well construction. >Please hack. >Tom Jerry, You are correct there are some discrepancies in the history of this well in particular and monobores in general. As with the SCP rules and workover waivers, there is a difference between injection and production wells. While having been accepted for production wells (3H-lOB for example), once the other wells construction was "discovered" their use was limited (water only). So far as the AOGCC review with regard to this particular well, the review sheet (signed May 2, 1996) indicates that Blair did not review this well's permit to drill. The approval of this permit was about a year in advance of the date of the letter from David Johnston to Mike Zanghe that stated that construction similar to the 5 "known injection wells" would not be approved. I am doing an assessment of your request and will incorporate all the information available on 2M-09A. All factors will be considered in reaching a decision. Tom Maunder, PE AOGCC Dethlefs, Jerry C wrote, On 11/21/2005 10:25 AM: Tom. fter reviewing the AOGCC web well file for 2M-09A, the approved PTD from 1996 (pages 17-21) s the intent to set the packer above the casing window (i.e., shallow). There are also notes within document that say this will be an injector. The PTD was approved without mention of MIT re 'rements or design elements that do not meet regulatory requirements. How is it that the AOGCC approve a PTD that does not meet design criteria? I would think that is why approval for a PTD is uired--to ensure these types of issues are caught before the work begins. The Completion Report (10-407) also lis a packer set depth, perforation depths, and classification of the well as an injector. Gran it says "water injector" at that point. The 10-404 dated January 2002 was one of a number of wel ou may recall) that were found not to have been properly approved for WAG service and "catch- " Sundry's were filed to straighten out their classification. Throughout this process it appears tha th CPA and the AOGCC missed the big picture on this well, specifically the packer set depth in rela ' to the perforations. This is all more for the "food for thought' category as anything else, but n both sides miss the details it is easy to see why we are having to retroactively straighten out the rwork on this well. Please let me know if you need more information for the AA on this well. Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska 907-659-7043 of Supervisor ConocoPhillips Alaska 907-659-7043 11/21/20053:32 PM Jerry Dethlefs Problem Wel This is all more for the "food for thought" category as anything else, but when both sides miss the details it is easy to see why we are having to retroactively straighten out the paperwork on this well. Please let me know if you need more information for the AA on this well The Completion Report (10-407) also lists the packer set depth, perforation depths, and classification of the well as an injector. Granted it says "water injector" at that point. The 10-404 dated January 2002 was one of a number of wells (you may recall) that were found not to have been properly approved for WAG service and "catch-up" Sundry's were filed to straighten out their classification. Throughout this process it appears that both CPA and the AOGCC missed the big picture on this well, specifically the packer set depth in relation to the perforations. Tom: After reviewing the AOGCC web well file for 2M-09A, the approved PTD from 1996 (pages 17-21 shows the intent to set the packer above the casing window (i.e., shallow). There are also notes within the document that say this will be an injector. The PTD was approved without mention of MIT requirements or design elements that do not meet regulatory requirements. How is it that the AOGCC can approve a PTD that does not meet design criteria? I would think that is why approval for a PTD is required--to ensure these types of issues are caught before the work begins. M :th Date u.., 2 To: tom _maundcr((~alhTI1n.statc.ak.us CC: jiI11Jcgg@admin.statc.ak.us, NSK Problcm Dethlefs, .Jerry C" <Jerry.C.Dcthlefs@conocoph / We lIips.com> Supv <n16 7 (á}conocophill ips.com>, \.1........ -09 AA Request cfs, J CITY cn Nov 2005 <Jerry.C.Dcth 0:25:41 -O()OO Suhject From 2M-09 AA Request e c fsCC,¿}conocoph i Iii pS.COI11 .- e FW: 2M-09A (196-090) AA e e Sub.ieet: FW: 2M-09A (I 96-0(0) Ai\. From: nDcthlcfs, ./erry en <.Jcrry.C.Dcthlcfs@conocophil1ips.com> Date: Sun, 20 No\! 200519: 10:27 -0900 To: tom_maundcr@.admin.statc.ak.us CC: jim.Jcgg@admin.state.ak.us, NSK Problem Well Supv <n1617(?i)conocophillips.com>, nDcthlcfs, Jcrry C" <Jcrry.C.Octhlcfs@conocophillips.com> Tom: It took a little digging back in history for T/I/O plots, and alii was able to retrieve was tubing and IA data. Not sure where the OA data went--. Attached is the TI plot going back a year or two with at least one cycle of MI gas injection. I did not see any trend anomalies, neither are there any records of the well requiring bleed events. Also attached is a well work event summary since the workover took place. We do not have plans to perform any logging on the well that I am aware of. We have not considered any remedial changes to this well since it has been operating just fine for several years and was only recently discovered to not meet construction standards. We don't have any reason to think there is a problem downhole since the MITT passed testing. You are correct about the requirement on our sinÇJle casing injectors to have a liner installed for monitoring if the well is to have gas injection. However, since those wells only have one casing string, that was a prudent move from the standpoint of layers of protection between the reservoir and surface. 2M-09A has a surface casing in addition to the production casing and tubing, so has sufficient safeguards (at least from the packer up). The only issue, then, is the risk associated with out of zone injection below the packer. Take a look at the data and see what you think. I would be happy to discuss this further if you have reservations--maybe there are some other mitigation actions we can dream up. Thanks! Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska 907-659-7043 -----Original Message----- From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Wednesday, November 09, 2005 10:25 AM To: NSK Problem Well Supv Cc: Jim Regg Subject: Re: 2M-09A (196-090) Jerry, I have received the AA application. I have started my file research. Since the well was completed in 1996, the only item submitted from. you all is a 404 from January 2002 with WINJ to WAG indicated. This is interesting since according to the injection record MI first went into the well in March of2000. Anyway, to fill out the record, could you please pull that "event summary" similar to what you sent me the other day on IF-18A?? This AA will be interesting. You have a monobore (as we know them) and you are looking to have approval to inject MI. For the wells we knew of with similar construction, MI has not been allowed without "alteration" of the completion to provide a monitorable annulus. How has the nshort" IA been performing?? How far back can you provide TIO information?? Being able to look at the pressure performance when the fluids have been switched would be informative. Last time our record 100 11/21/2005 3 :31 PM FW: 2M-09A (196-090) AA e e shows MI into the well was February 2004. Can you go back that far?? Has there been any need to manage the pressure in the IA aside from thermal effects when the fluids are changed?? Is there any plan to run a "gas log" (PNL, I believe) to investigate for the presence of gas external to the liner?? Has running a coil tubing string been considered to set this well up like the 30 well?? One other thing, in our earlier exchange (below) you mentioned of looking for "sleepers". That is probably a good idea. I haven't tied all the monobores we know about together, but it seems to me with a "few" out there (that we know of) it is likely that there are more since this design philosophy likely was adopted on a number of wells at that time. I did a look for sidetracks ("A wells") at KRU with permit numbers near 2M-09A. One I found was 2X-12A (195-176), a producer and it has some 3300' of 4-112" liner. I suspect there are others out there. Look forward to your reply. Tom Maunder, PE AOGCC NSK Problem Well Supv wrote, On 11/7/2005 8:34 AM: Yes. I called you about this well about a month or two ago (telephone). This is the well that the Field Inspector questioned the packer depth during the 4-year test in August. You agreed at the time that the proper way to document the construction was through an AR. The sidetrack that resulted in the high packer was done several years ago before we were watching for this type of thing. During this time lag we have set a tubing plug and performed the MIT. We are also researching to see if there may be any other "sleepers" out there we are not aware of. Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska 907-659-7224 -----Original Message----- From: Thomas Maunder [maílto:tom maunder@admin.state.ak.us] Sent: Monday, November 07, 20058:06 AM To: NSK Problem Well Supv Cc: iim reqq@admin.state.ak.us Subject: Re: Kuparuk MIT Test Form For 2M-09A Jerry, Has there been any prior notice regarding this well?? I am looking in my message files, but so far I have not found anything. Tom Maunder, PE AOGCC NSK Problem Well Supv wrote, On 11/5/20054:17 PM: Tom: Attached is an MIT test form for Kuparuk injection we1l2M-09A (PTD 1960900). The test was performed to support an Administrative Relief request that is on the way to your office. A copy of the test form will be attached to the AR for reference. Let me know if you have any questions. «MIT KRU 2M-09A 10-29-05.xls» Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska 907 -659-7224 20f3 11/21/2005 3 :31 PM FW: 2M-09A (196-090) AA TIO 30f3 e e Content-Description: 2M-09A no Data.xls Content-Type: applicationlvnd.ms-excel Content-Encoding: base64 Content-Description: 2M-09A Events.xls Content-Type: applicationlvnd.ms-excel Content-Encoding: base64 11/21/20053:31 PM Date o ('I!') ('I!') ('I!') 000 000 N N N -.... -.... -.... ~ ~ ~ ~ ~ -.... -.... -.... -....-.... ~ ('I!') ~ ~ ('I!') ~ ~ ~ 4000 3000 1500 2M-09A Pressure ConocoPhillips Alaska, Inc. 2M-09A Wellwork Events \~(O'-OS(j Event Date.5ervice Typ-e Event Description 10/30/05 SLICK LINE BAILED FILL OVER PERF'S, UNPLUGGED PERF'S, WILL INJECT. 10/29/05 SLICK LINE 1 0/28/05 SLICK LINE 10/26/05 SLICK LINE 10/25105 r SLICK LINE 10/24/05 SLICK LINE WEEKLY SAFETY MEETING, MITT, BAILED FILL FROM ON TOP OF PERF'S RETRIEVED TOOLSTRING FROM WELL, LDFN, JOB IN PROGRESS. PULLED CUTTER BAR, BAILLED FILL ON TOOLSTING, RAN LIB TO TOP OF TOOL STRING, GOOD PICTURE OF ROPE SOCKET. e BAILED FILL, FINAL Y GOT PICTURE OF ROPE SOCKET, JOB IN PROGRESS. BAILED FILL FROM TOP OF CUTTER BAR, CLEANED OUT 3 FOOT OF FILL. I 10/20105 I-COILED TUBING Jetted lob'" 'rnm ,"<faœ to tag '18948' "'Ihd~'el. 'ATTACH JUMPER TO M-08 TO FLOW OUT SHMOO & SCALE. TAG W/ 2.5" BAILER @ 8948' (WLM), ATTEMPT TO TAG FISH W/2.75" LIB, HIT INJ 10/05/05 I SLICK LINE SCHMOO @ 4546' WLM, CONFIRM W/2.5" BAILER RUN "/I'" I ABLE TO GET DOWN HOLE THE 1 ST RUN, SD @ 8924' (WLM). AFTER THE FIRST RUN, TAGGED AND BAILED FROM 3376' (WLM) TO 3964' (WLM). 1 0/9~ SLICK LINE JOB IN PROGRESS. [FISH] __~__ 10/03/05 SLICK LINE TAG TS W/ 2.70" LIB @ 8912' (WLM) SHOWS FILL. BAIL FILL FROM 2089' (WLM) TO 3390' (WLM). JOB IN PROGRESS. [FISH, TAG] e 10/02/05 I I SLICK LINE 'BRUSH NIPPLE PROFILE 9017' (RKB). LOST TS AND CUTTER BAR IN HOLE. JOB IN PROGRESS. [FISH] 10/01/05 SLICK LINE BRUSH & FLUSH TUBING. GUAGE TO CAMCO NIPPLE 9017' (RKB) W/ 2.69". JOB IN PROGRESS. [TAG, ANN COM ISSUES] 08/09/00' SLICK LINE LOGGED FROM 9005' RKB TO 9156' RKB; TAGGED FILL @ 9276' WLM. [PROD-INJ PROFILE] , _ 08/01/99 ELECTRIC LINE I COMPLETED INJECTION PROFILE. FIELD SPLITS = 28% C4-A5, 56% M, 16% A3. NO CROSSFLOW SEEN. [PROD-INJ PROFILE] I DRIFTED TUBING W/ 2.21" TAGGED FILL @ 9277' RKB, EST 63' OF RAT HOLE, EXTRMEL Y SLOW GOING IN HOLE FROM 1200' TO 5000'. JOB 07i~--ª,º!< LINE _ COMPLETE. [TAG] _ __ _ _ ConocoPhillips Alaska, Inc. 2M-09A Wellwork Events \~~-o~O '---1 I 07124199 I COILED TUBING tEANOUT PROPPANT FROM 9063' RKB TO HARD BOTTOM AT 9268' CTM USING SLICK SW AND DIESEL GEL [FCOI .... _ _ _ b ATTEMPT TO CLEAN OUT WELL WI VORTECH NOZZLE - NOZZLE PLUGGED UP WITH ROAD ROCKS AFTER PUMPING COIL VOLUME - REVERSE ~~/23/99 COILED TUBING FLUSH COIL - PUMP THROUGH COIL - ALL CLEAR - WILL CONTINUE FCO IN AM [FCO] ... , 07/21/99 COILED TUBING ATTEMPTED FCO - NOZZEL PLUGGED WI FRICTION REDUCER - JOB SUSPENDED [FCO] ~~ 07/11/99 SLICK LINE TAGGED @9063' RKB, EST. 151' FILL. RECOVERED SAMPLE FOR DSE. [TAG] , PUMPED HPBD AS PER PROCEDURE. 7137 # OF 16/20, 2604# ROCK SALT. AT AVG PRESSURE OF 5390 # AND AVG. RATE OF 26 BPM. TURNED 07111/9'1 JUMPING WELL OVER TO OPERATOR TO PUT ON INJECTION. ~BD] .- .. ._._-~ 07/10/98 SLICK LINE TAGGED FILL @ 9302' RKB, EST. 88' RATHOLE. TESTED CSG TO 3500 PSI, TEST GOOD. [TAG, PT TUB-CSG] 03/08/97 STATE TESTING STATE WITNESS MIT-PASSED. 50 PSI FALLOFF IN 30 MINUTES PERF 'C' SAND INTERVAL 9084'-9096' & 9104'-9133' @ 3 SPF AND 'A' SAND INTERVAL 9149'-9214' @ 4 SPF USING 2-1/8" HOLLOW CARRIER WI DP 07/10/96 CHARGES, 180 DEG PH, ORIENTED 165 DEG CCW FI HIGH SIDE. DETERMINED A STATIC BHP @ 9100' RKB OF 2864 PSIA. JETTED OUT ICE PLUG @ 2175'. RIH TO 5000' CTM. FREEZE PROTECTED 3-1/2" TUBING FROM 4000' TO SURFACE W/DIESEL. I OBTAINED SL T J 06/30/96 I COILED TUBING BOND LOG. GOOD CEMENT TO APPROX. 7900' ..~ .m~_ ~9~1 ! ATTEMPTED TO RUN SL TJ LOG. SAT DOWN AT 2175' - SUSPECT ICE PLUG. RDFN. SLICK LINE SET NIPPLE REDUCER ON AVA LOCK 06/13/96 .- 06/12/96 SLICK LINE ATTEMPT SET NIPPLE REDUCER WITHOUT SUCCESS. . 03/20/96 SLICK LINE TESTED TBG TO 2500 PSI, LOST 750 PSI IN 20 MIN. GAUGED TUBING WITH 2.69 SWAGE TO 11,681' WL. PULLED 1-1/2" DV @ 11,612'RKB. CTU CEMENT SQUEEZE COMPLETED. PUT 14.5 BBLS OF15.8 PPG CEMENT BELOW THE CHECK VALVE ASSY. @ 11696' AND SQUEEZED INTO THE FORMATION. USED 390 BBLS OF SEAWATER AND 80 BBLS OF DIESEL. LEFT 700 PSI ON WELLHEAD FOR CEMENT SET UP AND WILL PERFORM -º}/15/9i FLOWBACK TEST 03/14/96 i SET 1 112" DV ON RK @ 11,612' RKB, SET DOUBLE FLAPPER CHECK ON CR LOCK @ 11,696' RKB. WELL IS READY FOR CTU. e e e e \ ~~ -o<1u MECHANICAL INTEGRITY REPORT' ...... ~ /t ._<2. ( .. 5 ? U D D .~_ ;: ~ : '0\ \0 --G "'c-- -.,..- <c.¡ _C ( :"..!... L\.... !...,.:. r..': ;:,:. I \ f) "'\. \ø ~ MONG~Q,Q~ ~ ~r"I ~LL DATA TD: OPER Ex FIELD - CV ~ r \(.~~\~ "- ~£:LL NUHJ3ER .) M - 0 ~ ~. _=-:¡e~: L\\/J -:-'Joi:;g :S'I:;) Packe::!:' ::ole Size ~I/Çs Shoe: C\4CJ) MD TVD: :?BTD: HD TVD TVD¡ DV: HI) ·!v!) TVD i :OP: l..\'l \ \HD ;:~rD TVD¡ Set: ê.t '-.\~\ \ '\ Perfs ~ a x-L\ to . till.. Ca.si:;g: Shoe: HD HI) ana :-:ECF.ÞJEc;·..L INTEGRITY - PART 11 Annulus Press Test: ~p 15 illl.n 30 min Comments: ,.,..- ~CHÞ_1\ncþ...L INTEGRITY - PAR! ¡ 2 ~L\\o ~~\'> Cement: Volumes:' Amt. Liner J')S ~"f.; Csg i DV Cwt -.¡01 to cove::!:' Der::s ~'O~~\"> ~\"j~~K\€...K.~ .~ u::,~~~ ~~~~ . I ? \ '-.:) ~ S't:)O I T~eoretical TOC e. s'020\(S\'C)C ~;)9;;~ ~~ 'at '\CC.. \~ ~l<6·~O). ~ Cement Bond Log (Yes or No) ~~~ ÀC-VJ~\"" .~ ~ : In AOGCC File ./ .~,,~ '\\)~oTO C bC\~ t^'-'- \aö\<.s, E.~a:,\ct~~ .) CBL ~valuation, zone ë.oove perfs Prociuction Log: Type Evaluation CONCLUSIONS: . :? ar t t 1: k ~ "~~~I~\~~0-\~ ~,,\~ \'"'~~ ~T A... ~ ~/c., \J\ \ \\ ? ar:: : Z: k:S:::- ~'-> \'f'.¿;\c..~..~.\-~..~ I~. A \\f .-0";- ßi)! IV( I tI . Summary by Month: Individual Well Injection / Disposal Well Name: KUPARUK RIV UNIT 2M-09A API: 50-103-20177-01-00 Permit to Drill: 1960900 Operator: CONOCOPHILLIPS ALASKA INC Field/Pool: KUPARUK RIVER, KUPARUK RV OIL Sales Cd: 40 Acct Grp: 213 Final Status: 1 WIN] Current Status: W AGIN 1997 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth WAG WAG WAG WAG WAG WAG WAG Days 30 31 31 30 31 30 31 Wtr 97,061 73,623 65,295 64,710 55,122 76,402 60,190 Gas 0 0 0 0 0 0 0 1997 Totals: Water 492,403 Gas 0 Cum Wtr 492,403 Cum Gas 0 1998 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG It Days 31 28 31 30 31 30 31 31 30 31 30 31 Wtr 67,099 51,700 41,682 28, III 29,697 35,081 11,601 31,064 30,506 29,117 17,857 15,103 Gas 0 0 0 0 0 0 0 0 0 0 0 0 1998 Totals: Water 388,618 Gas 0 Cum Wtr 881,021 Cum Gas 0 1999 Jan Feb Mar Apr May Jun Jut Aug Sep Oct Nov Dee Meth WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG Days 31 28 31 30 31 30 27 29 30 31 30 31 Wtr 24,840 28,079 35,950 41,044 46,486 46,794 39,545 54,988 59,169 91,679 72,679 78,616 Gas 0 0 0 0 0 0 0 0 0 0 0 0 1999 Totals: Water 619,869 Gas 0 Cum Wtr 1,500,890 Cum Gas 0 2000 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG Days 31 29 26 30 31 30 30 31 28 31 30 31 e Wtr 69,244 69,726 31,884 0 0 0 0 0 23,795 106,264 78,649 63,1 08 Gas 0 0 137 19,365 61,867 55,281 11,823 40,216 18,025 0 0 0 2000 Totals: Water 442,670 Gas 206,714 Cum Wtr 1,943,560 Cum Gas 206,714 2001 Jan Feb Mar Apr May Jun Jut Aug Sep Oct Nov Dee Meth WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG Days 31 28 31 30 31 30 31 31 30 31 30 31 Wtr 62,492 54,718 50,866 30,918 28,009 0 0 0 0 0 0 0 Gas 0 0 0 0 6,172 6,923 36,431 39,335 34,393 37,898 18,077 19,963 2001 Totals: Water 227,003 Gas 199,192 Cum Wtr 2,170,563 Cum Gas 405,906 Wednesday, November 09,2005 Page I Summary by Month: Individual Well Injection / Disposal Well Name: KUPARUK RIV UNIT 2M-09A API: 50-103-20177-01-00 Permit to Drill: 1960900 Operator: CONOCOPHILLIPS ALASKA INC FieldlPool: KUP ARUK RIVER, KUP ARUK RV OIL Sales Cd: 40 Acct Grp: 213 Final Status: IWINJ Current Status: WAGIN 2002 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG Days 31 28 31 30 31 30 31 31 30 31 29 31 Wtr 0 0 0 0 0 0 0 2,005 30,000 31,000 37,597 51,633 Gas 10,945 6,606 9,654 28,446 29,740 37,070 44,200 41,471 0 0 0 0 2002 Totals: Water 152,235 Gas 208,132 Cum Wtr 2,322,798 Cum Gas 614,038 2003 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG e Days 31 28 31 30 31 30 31 31 30 31 30 31 Wtr 40,368 40,166 40,050 30,892 31,370 0 0 0 0 0 0 0 Gas 0 0 0 0 8,&41 20,443 25,897 37,700 33,465 45,270 50,848 41,567 2003 Totals: Water 182,846 Gas 264,031 Cum Wtr 2,505,644 Cum Gas 878,069 2004 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG WAG Days 31 29 31 30 31 30 31 31 30 31 30 31 Wtr 0 11 ,653 37,129 35,246 36,190 20,875 49,166 49,166 47,580 49,166 47,580 41,001 Gas 42,916 22,619 0 0 0 0 0 0 0 0 0 0 2004 Totals: Water 424,752 Gas 65,535 Cum Wtr 2,930,396 Cum Gas 943,604 2005 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dee Meth WAG WAG WAG WAG WAG WAG WAG WAG WAG Days 31 28 31 30 31 30 30 31 30 e Wtr 40,199 40,954 42,628 42,370 38,533 30,922 39,721 42,839 38,224 Gas 0 0 0 0 0 0 0 0 0 2005 Totals: Water 356,390 Gas ° Cum Wtr 3,286,786 Cum Gas 943,604 Wednesday, November 09,2005 Page 2 KTUU.com I Channe12 News is Alaska's News Source e http://www.ktuu.com!cms/temp lates/master. asp ?articleid=83 O&zoneid= 1 e '~:!~rn '!'::;;~-;.. i. ~~~ ="""~"-~gli~' lib&. --·r.: JðiII!IIIIIIII Contact Us . . ..' ,.',,:. ',,': "". <c....·· ... ,. .. ..... .... ..... ':.d't'\.-a~ ~ (\<;'~,-O~O)': S-O-\6~-;()\\ t -0 ( - "~<L\\I'Z\ ~ '\ "¡ ") '.;) ç: ';)S;, \ I.> -'~(>o " ~¡-:, \ \. -\- \~i~~ "c..~ ~l \ '( ;. YO i ,-£)\~ \.\~€-0<L \O\,N¿"--~ ¿, \ I ~\"~Æ. '2.-0"'-~ ~-.)«t N:j~,,> ~~ S~\> \() w\:,.\\\S~,c"':~ \1\.\ ¢: "-vt~ ~ ù,\DO~ \.}p ~ '. ..' ....::,;-. ..' '.' , Y'\~"-- ~ Þn "<:"',p_~",-~ \cXJO \ 0.~ \0 ~\Jf , <;S5~' ~ ~~Jt~èo' t'j>" ~\(¿< " NSCT ~"'~ C~.~\~, ~~ C) 5(/ ð:'\ Ë"-J \::: ce; '0 \"'oD , n- ~ ~""'C,"J 't) "i ..1,'0' \.\ -- "-'7fN0 ~ l <:0-1.1,0 .' ......·..··~\f'I\.D .... ~ (\r' - c:::;.:.. '. >'r \ '" ".. .... \ \\. "'\. \ \ V \'¡o O--">':S<L,~\L(C 'IN \'-.J ~ .. ---- ..' ~ \(? \\CJL~vt~~ ~ld";;)S::~"{. TOL .ç~<M..'~~ \c ~~¡ ~ \=\L'>S~ ~ ~ .- ..~-. '\OL'1\\\ ~~<J~ .. ~\> ~(U~ qO~Ta 'L.~1? ~()'2;\ ~") \ \%'<i\~'0\'0 h\ T 'S}: -Çb, anS; ."-C.S. ~\ \ ~ ~(~.._~ ~ .... 30f3 10/20/2005 8:31 AM • • Maunder, Thomas E (DOA) From: James Regg (jim_regg@admin.state.ak.us] Sent: Monday, November 07, 2005 8:55 AM To: Maunder, Thomas E (DOA) Subject: Re: [Fwd: RE: Kuparuk MIT Test Form For 2M-09A] Attachments: jim_regg.vcf jim_regg.vcf 2 yr MIT? ;~-`~ " t_"cam 1~~.11 r7 .~ ! rl~r-' _'~. r Thomas Maunder wrote: > Jim, > I finally remembered about this "newly discovered" monobore. As the > current sundries expire on the other wells, they will be submitting AAs. > Tom > -------- Original Message -------- > Subject: RE: Kuparuk MIT Test Form For 2M-09A > Date: Mon, 07 Nov 2005 08:34:20 -0900 > From: NSK Problem Well Supv <n1617@conocophillips.com> > To: Thomas Maunder <tom maunder@admin.state.ak.us> > Yes, I called you about this well about a month or two ago > (telephone). This is the well that the Field Inspector questioned the > packer depth during the 4-year test in August. You agreed at the time > that the proper way to document the construction was through an AR. > The sidetrack that resulted in the high packer was done several years > ago before we were watching for this type of thing. During this time > lag we have set a tubing plug and performed the MIT. We are also > researching to see if there may be any other "sleepers" out there we > are not aware of. > Jerry Dethlefs > Problem Well Supervisor > ConocoPhillips Alaska > 907-659-7224 > -----Original Message----- > *From:* Thomas Maunder [mailto:tom maunder@admin.state.ak.us] > *Sent:* Monday, November 07, 2005 8:06 AM > *To:* NSK Problem Well Supv > *Cc:* jim regg@admin.state.ak.us > *Subject:* Re: Kuparuk MIT Test Form For 2M-09A > Jerry, > Has there been any prior notice regarding this well?? I am looking > in my message files, but so far I have not found anything. > Tom Maunder, PE > AOGCC > NSK Problem Well Supv wrote, On 11/5/2005 4:17 PM: » Tom: Attached is an MIT test form for Kuparuk injection well » 2M-09A (PTD 1960900). The test was performed to support an » Administrative Relief request that is on the way to your office. A i Message ~ i Maunder, Thomas E (DOA) From: NSK Problem Well Supv [n1617@conocophillips.com] Sent: Monday, November 07, 2005 8:41 AM To: Maunder, Thomas E (DOA) Subject: RE: Kuparuk MIT Test Form For 2M-09A--now I know Page 1 of 1 If "being considered" really means "we were told to do so" then yes we are. As you suggested, as the 2-year MITs come due we will update the paperwork. However, 30-19 and 3Q-21 are still out of service so we will update that paperwork when we get them into some kind of shape. Still wellwork required on both to get them in shape. Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska 907-659-7224 -----Original Message----- From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Monday, November 07, 2005 8:07 AM To: NSK Problem Well Supv Cc: jim_regg@admin.state.ak.us Subject: Re: Kuparuk MIT Test Form For 2M-09A--now I know Hold the electrons! ! ! 2M-09A is that newly discovered monobore. Since you are applying for an AA on this well, is that being considered for the others?? Tom Thomas Maunder wrote, On 11/7/2005 8:05 AM: Jerry, Has there been any prior notice regarding this well?? I am looking in my message files, but so far I have not found anything. Tom Maunder, PE AOGCC NSK Problem Well Supv wrote, On 11/5/2005 4:17 PM: Tom: Attached is an MIT test form for Kuparuk injection well 2M-09A (PTD 1960900). The test was performed to support an Administrative Relief request that is on the way to your office. A copy of the test form will be attached to the AR for reference. Let me know if you have any questions. «MIT KRU 2M-09A 10-29-05.x1s» Jeny Dethlefs Problem Well Supervisor ConocoPhillips Alaska 907-659-7224 8/31/2010 e e ~ 7o~ >~ Conoc~Phillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 November 5,2005 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 Subject: Kuparuk We1l2M-09A (PTD 1960900) Request for Administrative Relief to Continue WAG Injection Operations Dear Mr. Maunder: ConocoPhillips Alaska, Inc., requests approval to continue WAG injection operations into Kuparuk well2M-09A. This request is pursuant to Area Injection Order No. 2A, Rule 9 Administrative Relief. Kuparuk we1l2M-09A was completed with a packer that does not meet construction requirements in 20 AAC 25.412 (b). Pressure testing of tubing and casing strings indicates the well has competent mechanical integrity and can be safely operated. Three barriers have been defined that will prevent an inadvertent release and confine fluids to the approved zones. The attached Technical Justification includes a proposed operating and monitoring plan. Daily monitoring of the wellhead and casing mechanical integrity tests are proposed to verify the well continues to be safe to operate. Should observations or tests indicate a compromise of well integrity the well will be shut-in and the AGOCC will be notified. There is no source of underground drinking water in this area and so is not endangered by this proposal. If you need additional information, please contact me at 659-7043, or Marie McConnell / MJ Loveland at 659-7224. Sincerely, fl- .fJc~ Jerry Dethlefs Problem Well Supervisor Attachments e e ConocoPhillips Alaska, Inc. Kuparuk We1l2M-09A (PTD 1960900) Technical Justification for Administrative Relief Request Proposal ConocoPhillips Alaska, Inc., proposes that the AOGCC approve this Administrative Relief request for an exception of20 AAC 25.412 (b) well construction standards for Kuparuk injection well2M-09A. Well History and Status Kuparuk River Unit well2M-09A (PTD 1960900) was originally completed in January 1993 (PTD 92-79) as a producing well. In June 1996 the well was sidetracked to a new bottom-hole location and re-named 2M-09A. The well was converted from a producing (development) well to a WAG injector (service well) at the time of completion of the sidetrack. The completion subsequent to the sidetrack in 1996 includes a packer that was set at 4717' MD (2936' TVD). The top of the perforated zone in the well is 9084' MD (6036' TVD). As per 20 AAC 25.412 (b), the completion configuration does not meet the 200' maximum distance from the packer to the approved injection zone. The distance between the packer and perforations is 4367' MD (3100' TVD). The completion includes a nipple profile in the liner section at 9017' MD (5981' TVD) that is within the depth requirement of20 AAC 25.412 (b). The profile can be used to test the production casing between the packer and perforated interval via setting a plug and performing an MIT. The distance between the profile and perforations is 67' MD (55' TVD). On October 29,2005 a sand plug was found above the perforations at 9073' MD (4706' TVD). An MIT -Twas conducted against the sand plug to 3000 psi for 30 minutes. Based on this data the tubing and casing have integrity down to the approved injection zone. Attached are test forms for the MIT-T performed 10/29/05 plus the previously submitted MIT-IA performed 8/12/05. Barrier and Hazard Evaluation Tubing: The 3-112" 9.3# L-80 tubing has integrity to the packer @ 4717' MD based on passing MIT tests dated 9/30/2001 and 8/12/2005. Test pressures were 1850 and 2060 psi, respectively. Production casing: The 7" 26# L-80 production casing has integrity to the packer @ 4717' MD based on the MIT tests described above. Surface casing: The well is completed with 9-5/8" 40# L-80 surface casing with an internal yield pressure rating of 57 50 psi. The surface casing is set at 4306' MD (2775' TVD). An 80 bbl cement shoe was pumped on 8/19/1988 which passed a 1000 psi pressure test. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Second barrier: The production casing is the secondary barrier should the tubing fail. NSK Problem Well Supervisor ll/5/2005 1 e e Third barrier: The surface casing and cement shoe will act as a third barrier should the first two barriers have failures. Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or production casing above the surface casing shoe it will be noted during the daily monitoring process. Any deviations from approved MAOP annular pressures require investigation and corrective action, up to and including a shut-in of the well. Proposed Operating and Monitoring Plan 1. Approve service for either water or MI gas injection; --- 2. Perform MIT -IA at 2-year frequency to verify tubing and production casing have not developed communication problems; 3. Perform MIT-Tubing at 2-year frequency by setting a plug in the nipple @ 9017' MD (5981' TVD) to verify integrity ofthe production casing from the packer to the approved zone within the depth criteria required in 20 AAC 25.412 (b); 4. Notify the AOGCC should MIT test results, injection rates or wellhead pressures indicate annular communication problems have developed. NSK Problem Well Supervisor 11/5/2005 2 or e e STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:Tom_Maunder@admin.state.ak.us;Bob_Fleckenstein@admin.state.ak.us;Jim_Regg@admin.state.ak.us OPERATOR: FIELD I UNIT I PAD: DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska Inc. Kuparuk I KRU 12M 1 0/29/05 Wilson - HES o F o P Well P.T.D. Notes: Well P.T.D. Notes: Test Details: TYPE INJ Codes F = Fresh Water Inj G = Gas Inj S = Salt Water Inj N = Not Injecting TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover 0= Other (describe in notes) MIT Report Form Revised: 06/19/02 MIT KRU 2M-09A 10-29-05.xls ~ e e STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:Tom_Maunder@admin.state.ak.us;Bob_Fleckenstein@admin.state.ak.us;Jim_Regg@admin.state.ak.us OPERA TOR: FIELD I UNIT I PAD: DATE: OPERATOR REP: AOGCC REP: ConocoPhillips Alaska Inc. KRU 2M 08/12105 Arend/Savageau AES Chuck Scheve s P Packer Depth TVD 6,040' Tubing Test psi 1510 Casing Test Details: 4 P 4 P 4 P 4 P 4 P 4 P 4 F 4 P 4 P TYPE INJ Codes F = Fresh Water Inj G = Gas Inj S = Salt Water Inj N = Not Injecting TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = F our Year Cycle V = Required by Variance T = Test during Workover o = Other (describe in notes) M IT Report Form Revised: 06/19/02 MIT KRU 2M 08-12-05.xls Pelf (9149-9214) Pelf (9104-9133) Pelf (9084-9096) - NIP (9017-9018, 00:5.000) LINER (4717-9402, OD:4.500, Wt:12.60) Camco 5" X 3.813" OB5 Nipple w/3.81 E!:ofile & WL en!!Y...illJide PKR (4717-4718, OD:6.151) SPACE OUT (4718-4719, OD:3.500) TIt (4719-4720, OD:3.500) : .- ¡¡ï L.U 4719 9017 \.l~I~r. Depth 514 4677 4717 4718 2937 5981 TVD 513 2919 2936 2936 ~ NIP NIP PKR SPACE OUT TTL NIP -. . ~_~.:(hr~ãd '~.' Th~ealL - -. ~~ - 3.500 0 .- ~erf(),.atións..SQI'I'1I'1'1$ry·:·· Interval I TVD Comment·n --... 9084 - 9096 6036 - 6046 21/8" HC:1I!Õ· deg~ ph¡¡se: oriented 165 deg. cew F! High Si . . __ _ . 21/8" He. II!U deq. phase: oriented 165 deg. CCW F! HighSi 21/8" He. II!O deg. phuse; oriented 165 deg. CCW FI High Si ~~ 1 463 V Type r V OD MMM I OMY I 1.5 RK ..JEWELRY Description Cameo 'OS' Nipple NO GO Camco 'W-1' Baker 'ZXP' wI 7.39' C2 Tie Back Sleeve maxi big bore lock w/Otis 2.313" X Port Vlv Cmnt 0.000 ID 2.812 2.812 4.438 2.992 2.992 2.313 9104 - 9133 6052 - 6076 A-4 9149 - 9214 6089 - 6142 A-3 V Mfr 65 4 Latch 7/10/1996 IPERF NIP (4677-4678, OD:3.500) ndrellDummy Vahle 1 (4631-4632, OD·.5.563) PROD. CASING (0-4980. OD:7.000, Wt26.00) NIP (514-515, 00:3.500) WBING (0-4719, OD:3.500, ID:2.992) ....- ..- (] ].... .--.: .i I , : .....~. _.~- ~" 29 3 7/10/1996 IPERF Grads· H-4Õ TAG ·Fïli 10/31'2005 .Jtir~äd _ .- - API: SSSV Type: 501032017701 NIPPLE Rev Reason: Last Update: --rÄngle @ TS: ~ngle@TD: .--- ~ de.9_.@ 99~ 33 deg @ 9405 ~ '!' ConocoPhiUips AJ8skat - Jnc. e KRU 2M-09A • Maunder, Thomas E (DOA) From: Dethlefs, Jerry C [Jerry.C.Dethlefs@conocophillips.com] Sent: Friday, September 23, 2005 4:41 PM To: Maunder, Thomas E (DOA) Cc: 'NSK Problem Well Supv' Subject: RE: Monobore Injection Wells Tom: To my knowledge you are correct. Since we recently "discovered" 2M-09A, I cannot guarantee there are not other anomalous wells out there we do not know about. But your list looks complete for the wells we do know about. Should we come across another in this situation you will be the first to know. Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska ~~ ,~, ~- ~ ( ~ ~~ ~~r; 907-659-7043 s+w~ ~-.:;4~ i~;,1u .r. ?'~~:~ -----Original Message----- From: Thomas Maunder [mailto:tom maunderCadmin.state.ak.us] Sent: Friday, September 23, 2005 9:22 AM To: NSK Problem Well Supv Cc: Jim Regg Subject: Monobore Injection Wells Jerry, et al: We are checking our records and wanted to confirm the wells that are monobores. There are various wells out there that have had the name "monobore" attached to them. For this message, monobore means a well that does not have a separate production casing set proximate to the injection horizon and the packer is set a significant distance above the zone. The first 4 wells on the list have the packers set in the surface casing. The wells on our "list" 3K-22 30-19 3Q-21 3R-25 and possibly 2M-49A 3H-lOB would also be on converted. are: ~Cl~-~~~ the list, but it is Thanks in advance for your assistance. Tom Maunder, PE AOGCC a producer never having been 1 ') MEMORANDUM State of Alaska ') Alaska Oil and Gas Conservation Commission TO: Jim Reo-o- ·'7/K'. ell I ~ O"'/ 00 tl-t(] q '> P.I. Supervisor l\. DATE: Wednesday, August 17,2005 SUBJECT: Mechanical Integrity Tests CONOCOPHILLLPS ALASKA INC 2M-09A KUPARUK RIV UNIT 2M-09A 8rc: Inspector gO tolO , \CA: FROM: Chuck Scheve Petroleum Inspector NON-CONFIDENTIAL Reviewed By: P. I. 8 u p rv ,,~')J3r,-- Comm Well Name: KUPARUK RIV UNIT 2M-09A Insp Num: mitCS050812195528 Rei Insp Num: API Well Number: 50-103-20177-01-00 Permit Number: 196-090-0 Inspector Name: Chuck Scheve Inspection Date: 8/12/2005 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. -'W~iiTiM~Õ9A'Type injl-w' TVD--- '--¡-2936!- '!AT--'-950-'--¡Zõ6ü---¡'--zo6o·-r- 206Õ-'--i---'--r--'- ------"" P. T J -]960900:1~YI'~TestÈl£stPsI±:7J~ .~. 10;+"440· L - 48o...._~~-=+ 480 -~=-r ___=-= Interval 4YRTST P/F P Tubmg, 2400 I 2400 I 2400 2400 I I "h"_._ _._._____ _.._.. ..____......_____....__._...__.L..____.-L._.._ ...._._---L__u.. __...J__.__._...__----L._.... ____.. __-L.._..._____..... Notes: The packer in this well is at 4717. The top perf is at 9084. This test was on the top half of the well only, 4367' of liner not tested. Io.. (".),:_ ~._I...~ '1,'..0 O\[~ to'f"" 1:\ \.iÙ~\Ì1W:'::[. (\: ., Ii) .. ,_ L V t)~~tt~'I;'~'" ~~"~í"~"'" ~(o1" .....~J Wednesday, August 17,2005 Page 1 of 1 Message Maunder, Thomas E (DOA) From: NSK Problem Well Supv [n1617@conocophillips.com] Sent: Monday, August 15, 2005 9:29 AM To: Maunder, Thomas E (DOA) Cc: 'NSK Problem Well Supv' Subject: RE: Kuparuk MIT Data Attachments: 2M-04 History.xls rags i vi ~ Tom: It is not uncommon for MI injectors to build up a gas pocket over time. As you are aware, MI will find a way to migrate even in good tight tubulars. Typically there will be a small gas pocket that we bleed down and fluid pack prior to doing MIT's. The gas is actually to our benefit during operation of the well to minimize annular pressure changes. We typically do not fluid pack these unless we are preparing to perform an MIT. Attached is our Ann Comm history for the well. There are some notes from a few years ago about high IA pressure plus diagnostic results. Nothing was really found to be wrong, plus the MITs have been good. We may have just missed this well for fluid packing prior to Scheve's visit. Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska 907-659-7224 -----Original Message----- From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Monday, August 15, 2005 7:57 AM To: NSK Problem Well Supv Cc: Jim Regg; Chuck Scheve Subject: Re: Kuparuk MIT Data Jerry, I just looked into the files on 2M-09 [192-079] and 2M-09A [196-090]: It would appear that 2M- 09A is a monobore, like 30-19 and the others. 2M-09 had 7" casing set to TD as normal, but when the well was redrilled, the new wellbore was drilled from a window in the 7" casing not far below the 9-5/8" shoe. If this well were to be proposed today, I believe that the 7" casing would be cut and pulled so a new string could be set. I see that Nordic 3 did the redrill, that rig would not likely have been capable of pulling the 7". An AA is probably the way to go. This would be the first monobore to be considered that way. According to the completion diagram, there is a properly sized nipple (actually a reducer) not far above the perforations. That would allow a plug to be run so the liner could be pressure tested. With regard to 2M-04, is it usual to find "lots of gas" on the annulus of what I presume are MI injectors?? It would seem that the expectation is that the tubing does not leak MI. What is the history of 2M-04?? Call or message with questions/comments. Tom Maunder, PE AOGCC NSK Problem Well Supv wrote, On 8/13/2005 2:13 PM: 8/31/2010 Message t aga, ~, vi ~, Tom: After a phone conversation with Chuck Scheve regarding the Kuparuk MITs that were performed yesterday, we have a couple items that need to be dealt with. 1. Well 2M-04 (PTD1920930) had high IA pressure with a lot of gas so a drawdown test was performed. At the time of the test it was called a pass, but on review it appears to be more of a linear leakoff. Our plan is to check out the well, make sure it is fluid packed, and repeat the MIT. We will call the Inspector again to witness the MIT. 2. 2M-09A (PTD 1960900) schematic shows the well to be another with the packer located significantly up hole from regulatory requirements. The packer is at 4717' MD and the pert top is «2M-09A.pdh> at 9084' MD (attached). I suspect we should file an Administrative Relief on the well for operating parameters we can agree on. Please let me know if concur with both of the plans proposed above. Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska 907-659-7224 8/31/2010 Maunder, Thomas E (DOA) From: Jeff A Spencer [jspencer@ppco.com] Sent: Monday, January 07, 2002 10:18 AM To: Maunder, Thomas E (DOA) Subject: GKA Sundry Reports Tom, Just wanted to give you a quick heads up that we are sending in 8 Sundry Reports (one 403, seven 404's) for your review and approval. Also, just wanted to give a little more info on two of the wells. 2K-25: (P-to-I Conversion Candidate) CBL was questionable (not run under pressure, but looks like a potential channel to me). Anyway, we submitted a Form 10-403 but plan on running a Water Flow Log to verify zonal isolation and will forward the results to you as soon as we get it. ~ ~~ ' o~~ 2M-09A: (H20 to WAG Injector) In our ongoing efforts to reconcile AOGCC _~„ PAI's records we noticed that this well's Form 10-404 was missing and so 10-404 showing initial gas injection commencing in March 2000. Hope you had a great Holiday Season! Jeffrey A. Spencer Production Engineering & Offtake Supervisor Phillips Alaska, Inc. 907-659-7226 Slope jspencer@ppco.com records with submitted a new 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 2. Name of Operator 5. Type of Well: 6. Datum elevation (DF or KB feet) Phillips Alaska, Inc. Development RKB 146 feet 3. Address Exploratory 7. Unit or Property name P. O. Box 100360 Stratigraphic Anchorage, AK 99510-0360 Service X Kuparuk Unit 4. Location of well at surface 8. Well number 5163' FNL, 5155' FEL, Sec. 27, T11 N, RSE, UM (asp's 487965, 5948986) 2M-09A At top of productive interval 9. F;ermit number / approval number 700' FNL, 349' FWL, Sec. 3, T1 ON, RSE, UM 196-090/ At effective depth 10. APl number 50-103-20177-01 ,At total depth 11. Field / Pool 874' FNL, 4971' FEL, Sec. 3, T10N, R8E, UM (asp's 488151, 5942715) Kuparuk Oil Pool ,, 12. Present well condition summary Total depth: measured 9405 feet Plugs (measured) true vertical 6299 feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured Depth True vertical Depth CONDUCTOR 121' 16" 21o sx AS I 121' 121' SUR. CASING 41C¢3' 9-5/8" 745 sx PF E & 780 sx Premium G 4306' 2775' PROD. CASING 4834' 7" 200 sx C~ass G 4980' 3043' LINER 4685' 4-1/2" 225 sx C~ass G 9402' 6297' LINER _.:::.:::: _.:.;-:-:::-::::.: :.:::-:::-:._.:...: :.:-. ::.::-:.-.:: :::-. _:. :._: :c-_.:._-::..::: --;.:._.: ..:...:.:: :.:._ :.. :.:: :.:-- ::.....::.;.:._ :. :.:::: :..:. ::: :.:.:.:.: :..:.. :-.- :.:. :. :.: ..... . :.:. :.:..::. :-:::_;:: :-::: _::::.:::::.::: _ :_. :::::::-:-:: .., :.:::::-.:, :.-.:..-:.:-::.:: ._:.:.:. :-.:: _::.:: _ :::-::_:::..::: -:-_.::_::-.-: .::.:.. :. :..-: .:. :.. :. :..:.:.: ..: .::. :.:: :.:.:: :.: .: ·. :.:... :.: ::i.-;!!:!i: i:i:i.:Z!Z:.i!:-i-:.i (!. !!Z::~:-:i::ii :!!:::i::-?i'i;:i!Z:'i-:-:::-E::?:;i::;¥ti.i:i;!i!-:'- i-:.!.{:! i.!'!:!:-~:::i.i;i':'!:- ::- i '.i.:;!.- :- i ;:.; -!i-:- i.-i- :-.;:ii- i-i- ~.-.i'. i- i- ;. ;- }.. ~ :i.:!- i- i !-;! , ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: :..:..:.:.:..:..:..:.:.::...:...:.:.:.:.::...:.:.:..- ... : . ,. j; =~,~,~./~, ::;-;-:_ ::_:: :.:-..:-; :.__:.:.::_-:-: :.._: :.:..-:..-:._.:...:. :.:.:...:.:::: ..:-_.:.. c _: :-_-:::.:. ::. :. -: :::.:._.::. :.. :. :.:.: :.:. :.. :._.:. -... _ :. :.: :. :...: ..: :.: ..:. - -.: ::. :. :..: .:. :. :.: ...: : Tubing (size, grade, and measured depth) ~!~i~;:.~!~;~.~i.?~i:!.i.!;~::.~?~ii.!..i.:i~::~i:i.?:::!~.::i.:?:i:~::~:.ii~ -i;:}?:::::'i:::~:ii::i?i!:::?i.:i:;:;"i.:i~'i: ],/.~ Packers & SSSV (type & measured depth) ~!~ ~,~':~i~i~:!~~;'~'i:~4~:~i-!~?:::ii;;i'!'i :!::(:.~!.i??::i:!:'!":::i:,i:i-~';¢i;';;~'~;i};[i}~i::i):*i.i;; 13. Stimulation orcement squeeze summary '" ..... ' ............. ' .......... ' ' ...................................... ,','-,:4i.' ....... ~ '" · .:.:..:.::: :-:...:.:..-...:.:.:.: :.:.:. -: :.:...:.. :: :-...-:.: ;.:.:..:.:.:..:.:.:..-::.:.:..:,.:-?:::.:.:-::,:-:..:,. Treatment description including volumes used and final pressure .... "'-:.-:':' :."-:'-:' :' :" ':-:';'":'.:':': :' 14. Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcr Water-Bbl Casing Pressure Tubing Pressure ....... . ......... .-. ....... . ............ ........ ...... . .............. . ............... . ............................ . .... . ....... :...: :..::......... 15. Attachments Copies of Logs and Surveys run 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Questions? Call Jeff Spencer 659-7226 Signed Title Production E~gineering Supervisor Date ¢'"~dJ4 · ~)-~._ JaffA. Spencer ~ Prepare~y ,Robert Christensen 659-7535 Form 10-404 Rev 06/15/88 · SUBMIT IN DUPLICATE • 2M-09A • DESCRIPTION OF WORK COMPLETED SUMMARY Date Event Summary 3/16100 Commenced WAG FOR Injection Maunder, Thomas E (DOA) From: Tom Maunder [tom_maunder~admin.state.ak.us] Sent: Thursday, September 27, 2001 5:20 PM To: 'NSK Problem Well Supv' Subject: Re: Phillips Kuparuk Well 2M-09A Attachments: tom maunder.vcf ~J tom_maunder.vcf Jerry, Thanks for the heads up. I will take a look and get back to you. Tom NSK Problem Well Supv wrote: > Tom: I found something on Kuparuk well 2M-09A (injector 1960900) that > has me a little confused. The construction of the well resembles our > "failed MIT" monobores in that the packer is way up hole from the > perforations. The well was sidetracked in 1996 leaving this > configuration. The last MIT was done in 1997 and I am getting ready to > do one this week with Spaulding. I noticed the problem while preparing > my paperwork. It appears this well at least has a nipple profile near the perfs. Let me know what you think. > Jerry Dethlefs > Phillips Problem Well Supervisor ,+ t ~~1~ ~. , , . r ~ ,_~~: ~~;,,v~'ta'- 1 oN OR BEFORE c:LOp, IXMTILM.DOC PERMIT AOGCC Individual Well Geological Materials Inventory DATA T DATA PLUS Page: 1 Date: 06/09/98 RUN RECVD 1 07/18/96 1,2 10/25/96 1,2 10/25/96 10-407 c.P~OMPLET I ON DATE DAILY WELL OPS R ~/ ~;/¢6 / TO ~/{~/ Are dry ditch sar~ples required? yes ~_~And received? Was the well cored? yes ~alysis & description received? Are well tests required? yes n~~'Ceived? Well is in compliance In~[~al COMMENTS ~-/G/.~7/ ~/r~/~ yes ne~- ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 May 2, 1997 Mr. David J. Johnston Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 ORIGINAL Subject: 2M-09A (Pennit No. 96-90) Well Completion Report Dear Mr. Commissioner: Enclosed is the well completion report to cover any changes made to the completion during the recent operations to sidetrack KRU 2M-09. If there are any questions, please call 263-4183. Sincerely, D. K. Petrash Drilling Engineer Kuparuk Drill Site Development DKP/skad STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION CC,,/,,vllSSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 Status of Well Classification of Service Well OIL E~ GAS E~ SUSPENDED ~ ABANDONED [] SERVICE ~ Water Injector 2 Name of Operator 7 Permit Number ARCO Alaska, Inc 96-90 3 Address 8 APl Number P.O. Box 100360, Anchorage, AK 99510-0360 50-103-20177-01 4 Location of well at surface ~t' ........................... ~:(~i'47~ ~ Fj,0~.i ~ i [. 9 Unit or Lease Name 114' FSL, 124' FWL, Sec. 27, T11N, RSE, UM ~ ,~ Kuparuk River Unit At Top Producing Interval i ~ i~i/-;'i'F-i ~ !i illl~ !i 10 Well Number 700' EEL, 349' FWL, Sec. 3, T10N, R8E, UM i ;~/~,~L~ ~ ;~"'~' i'" 2M-09A At Total Depth · ..... ,~',.~. _~..._~ ~_,; t ~ ,~-~ !' 11 Field and Pool 877' FNL, 308' FWL, Sec. 3, T10N, R8E, UM ...... '~" ......... ' ..... ~'~'~ ~ - KUPARUK RIVER 5 Elevation in feet (indicate KB, DF, etc.) 6 Lease Designation and Serial No. Rig RKB 41', PAD 105' ADL 25589 ALK 2675 12 Date Spudded I 13 Date T.D. Reached i4 Date Comp., Susp. or Aband. 15 Water Depth, if offshore 116 No. of Completions 06-Jun-96 (sidetrack) 10-Jun-96 10-Jul-96 (peri'd) NA feet MSLI 2 17 Total Depth (MD+TVD) I 18 Plug Back Depth (MD+TVD) 19 Directional Survey 120 Depth where SSSV set 21 Thickness of permafrost 9405'MD~6300'TV9'I9306'M~S6218'W~ ~ES ~ NoDI ~A feetMD ~1380'ss ^PPROX 22 Typo Electdc or Other Logs Run Slim-1 GR, GR/CCL/SLT-J 23 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT GRADE TOP BTM HOLE SIZE CEMENT RECORD 16" 62.5# H-40 SURF. 121' 24" 210 sx AS I 9.625" 47# L-80 SURF. 4306' 12.25" 745 sx Permafrost E, 780 sx Premium G 7" 26# L-80 SURF. 4980' 8.5" 200 sx Class G 4.5" 12.6# L-80 4717' 9402' 6.125" 225 sx Class G 24 Perforations open to Production (MD+TVD of Top and Bottom and 25 TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 3.5" 4719' 4717' 9084'-9096' MD 3 spf 6037'- 6047'TVD 9104'-9133' MD 3 spf 6053'- 6077' TVD 26 ACID, FRACTURE, CEMENT SQUEEZE, ETC 9149'-9214' MD 4 spf 6090'- 6143' TVD DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 27 PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) njector Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO TEST PERIOD I~ FIowTubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OILGRAVITY-API (cerr) Press. 24-HOUR RATE I~ =24o 28 CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. ORIGINAL t,,,f,j i, 6' 1997 · 4l~*k'a.Oil 8, ~;as Cons. Commiss,. At, chorale Form 10-407 Submit in duplicate Rev. 7-1~80 CONTINUED ON REVERSE SIDE 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS D~PTH TRUE VERT. DEFFH GOR, and time of each phase. Top Kuparuk C 9081' 6031' Bottom Kuparuk C 9088' 6037' Top Kuparuk A 9088' 6037' Bottom Kuparuk A 9256' 6175' SIDETRACKED - ORIGINAL ANNULUS WAS ALREADY ARCTIC PACKED , 31. LIST OF A'FI'ACHMENTS Directional Survey, Daily Drilling History 32. I hereby certify that the foregoing is true 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 intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- lng and the location of the cementing tool. Item 27: Method of Operation' Flowing Gas Lift, Rod Pump, Hydraulic Pump, ' jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 i~AY ~ 1997' AJaska .0i~ & Gas Cons. C0mmiss,'. ~[]chora,qe Date' 6/17/96 ARCO ALASKA INCORPORATED WELL SUMMARY REPORT Page: 1 WELL:2M-09A RIG:PARKER WELL ID: AK8501 AFC: AK8501 TYPE' STATE:ALASKA AREA/CNTY' NORTH SLOPE WEST FIELD: KUPARUK RIVER UNIT SPUD: START COMP: BLOCK: FINAL: WI: 55% SECURITY:0 AFC EST/UL:$ OM/ OM API NUMBER: 50-103-20177-01 6/4/96 (1) PBTD' 4700' (0) SUPV:RLM DAILY: MW: 9.7 PV/YP: 14/14 APIWL: 9.8 CHANGE OUT HCR VALVE Move rig from 2M-35 to 2M-09A. Accept rig @ 1500 hfs 6/4/96. Nipple down tree and pull hanger. Nipple up 13-5/8" stack. $396,710 CUM: $396,710 ETD: $0 EFC:$396,710 6/5/96 (2) PBTD: 4700' (0) SUPV:RLM DAILY- MW: 9.7 PV/YP: 16/15 APIWL: 9.6 RIH @ 4600' Test rams, Hydril, all valves and lines to 300/5000 psi. RIH with 3.5" drill pipe to 1800' Started hitting cement stringers at 3895' $65,542 CUM: $462,252 ETD: $0 EFC:$462,252 6/6/96 (3) PBTD: 5085' (105) SUPV'RLM DAILY: MW: 9.3 PV/YP: 11/13 APIWL: 13.2 DRILLING @ 5500' Clean out intermittent cement stringers from 3616 to 4630'. Drill hard cement from 3616' to 4985'. RIH to 4845'. Wash from 4845 to 4895'. Directional drill 6.125" hole from 4985 to 5040'. FIT to 12.5 ppg EMW. Drill 6.125" hole from 5040 to 5085' $89,919 CUM: $552,171 ETD: $0 EFC:$552,171 6/7/96 (4) PBTD: 6138'(1053) SUPV:RLM DAILY: MW: 9.4 PV/YP: 15/14 APIWL: 7.8 DRILLING @ 6700' Directional drill 6.125" hole from 5085' to 5777'. ROP was 100+ fph after getting on bottom, then quit drilling. Spent 2 hours trying to get bit to drill. Motor failed. Direction- al drill 6.125" hole from 5777' to 6138' $79,243 CUM: $631,414 ETD: $0 EFC:$631,414 6/8/96 (5) MW: 9.3 PV/YP: 13/14 APIWL: 6.6 PBTD: 8312' (2174) DRILLING @ 8900' SUPV:RLM Directional drill 6.125" hole from 6138' to 8312' DAILY: $81,050 CUM: $712,464 ETD: $0 EFC:$712,464 6/9/96 (6) PBTD' 8978'(666) SUPV:RLM DAILY' MW: 9.8 PV/YP: 18/18 APIWL: 4.4 DRILLING @ 9080' Directional drill 6.125" hole from 8312' to 8978'. Minor sloughing from HRZ. Wash and ream tight hole from 8953' to 8978' Circulate bottoms up. Mix 4 ppb fine barafiber and 2 ppb coarse baraseal. Weight up from 9.8 to 10.6 ppg. $100,653 CUM: $813,117 ETD: $0 EFC:$813,117 6/10/96 (7) PBTD: 9405'(427) MW: 10.6 PV/YP' 19/24 APIWL: 4.0 PULL WEAR BUSHING SUPV:RLM DAILY: 6/11/96 (8) PBTD: 9405'(0) SUPV:DCL DAILY: 6/12/96 (9) PBTD: 9405' (0) SUPV:DCL DAILY: 6/13/96 (10) PBTD: 9405' (0) SUPV:DCL DAILY: 6/14/96 (11) PBTD: 9405' (0) SUPV:DCL DAILY: Rotary drill from 8978' to 9405'TD. Wipe hole from TD to 8953' Had to back ream from 9200 to 8859'. RIH to 9405' Free no fill. $89,427 CUM: $902,544 ETD: $0 EFC:$902,544 MW: PV/YP: 18/22 APIWL: 4.8 PREP TO CEMENT LINER Held pre-job safety meeting. RIH w/4.5" liner to 4618'. RIH w/4.5" liner on 3.5" DP to 9402' $74,143 CUM: $976,687 ETD: $0 EFC:$976,687 MW: 10.6 PV/YP: 20/23 APIWL: 4.4 POH W/2-7/8" TBG Dowell tested lines to 5000 psi. Pump cement. Bumped plug to 3000 psi to set hanger. Held prejob safety meeting. RIH w/2-7/8" tbg. $156,063 CUM: $1132,750 ETD: $0 EFC:$1132,750 MW: PV/YP: APIWL: LD 3.5" DP RIH w/3.812 AVA maxi lock w/2.313 id X nipple and WL entry guide. Set in DB5 nipple at 9016'. RIH w/3.5" completion equipment to 4717' $130,241 CUM: $1262,991 ETD: $0 EFC:$1262,991 MW: PV/YP: APIWL: RIG RELEASED Pressure test annulus to 2500 psi 15 min. OK. Test tbg to 2500 psi for 15 min. ND BOPE. NU tree adapter and master valve. Test to 5000 psi. Released rig @ 1200 hfs 6/14/96. $80,028 CUM: $t343,019 ETD: $0 EFC:$1343,019 KUPARUK RIVER UNIT WELL SERVICE REPORT K1 (2M-09A(W4-6)) WF.I I. JOB SCOPE 2M-09A PERFORATE, PERF SUPPORT DATE DAILY WORK 07/10/96 PERFORATE A/C SAND DAY 1 OPERATION COMPLETE YES SUCCESSFUL YES I JOB NUMBER 0709962255.3 UNIT NUMBER KEY PERSON SUPERVISOR SWS-SCHWARTZ PAIGE -initial Tbg Press Final Tbg Press I lnitial Inner Ann Final Inner Ann ] Initial Outer Ann I Final Outer Ann 0 PSI 50 PSI 0 PSI 0 PSI 0 PSI 0 PSI DAILY SUMMARY IPERF 'C' SAND INTERVAL 9084'-9096' & 9104'-9133'@ 3 SPF AND 'A' SAND INTERVAL 9149'-9214'@ 4 SPF USING 2-1/8" HOLLOW CARRIER W/DP CHARGES, 180 DEG PH, ORIENTED 165 DEG CCW F/HIGH SIDE. DETERMINED A STATIC BHP @ 9100' RKB OF 2864 PSIA. TIME LOG ENTRY 07:30 MIRU SWS. HELD SAFISI'Y MTG. 11:15 AT SURF W/GUN#1; ALL SHOTS FIRED. 09:30 PT LUB TO 3000~; TEST OK. RIH W/GUN#1 - PGGT, MPD, 20' 2-1/8" HOLLOW CARRIER W/DP CHARGES, 4 SPF, 180 DEG PH, ORIENTED 165 DEG CCW F/LOWSIDE TO SH(X)T 9194'-9214' (REF SLTJ DATED 6]30/96) 10:30 IN POSfI'ION TO SHOOT INTERVAL; PUT 500~ ON WELLHEAD TO ACHIEVE THE DESIRED 200# UNDERBALANCE. FIRED GUN#I; POH. 12:00 PT LUB TO 3000~; TEST OK. RIH W/GUN#2 - WGT, MI>D, CCL, 20'/5' SW1TCHED 2-1/8" HOLLOW CARRIER W/DP CHARGES, 4 SPF, 180 DEG PH, ORIENTED 165 DEG CCW F/LOWSIDE TO SHOOT 9169'-9189' & 9189'-9194' (REF SLTJ DATED 6/30/96) 13:00 FIRED GUN#2 @ 9189'-9194' & FIRED SWITCH @ 9169'-9189'; POH. 13:45 AT SURF W/GUN#2; ALL SHOTS FIRED. 14:00 PT LUB TO 30000; TEST OK. RIH W/GUN#3 -MPD, CCL, 20' 2~1/8" HOLLOW CARRIER W/DP CHARGES, 4 SPF, 180 DEG PH, ORIENTED 165 DEG CCW F/LOWSIDE TO SHOOT 9149'-9169' (REF SLTJ DATED 6]30/96) 15:00 FIRED GUN#3; POH. 15:30 AT SURF W/GUN#3; ALL SHOTS FIRED. 16:00 PT LUB TO 3000~; TEST OK. RIH W/GUN#4 -MPD, CCL, 20' 2-1/8" HOLLOW CARRIER W/DP CHARGES, 3 SPF, 180 DEG PH, ORIENTED 165 DEG CCW F/LOWSIDE TO SHOOT 9113'-9133' (REF SLTJ DATED 6/30/96) 17:00 FIRED GUN#4; POH. 17:30 AT SURF W/GUN#4; ALL SHOTS FIRED. 18:30 PT LUB TO 300041; TEST OK. R1H W/GUN#5 - WGT, MPD, CCL, 12'/9' SWITCHED 2-1/8" HOLLOW CARRIER W/DP CHARGES, 3 SPF, 180 DEG PH, ORIENTED 165 DEG CCW F/LOWSIDE TO SHOOT 9084'-9096' & 9104'-9113' (REF SLTJ DATED 6/30/96) 19:15 FIRED GUN#5 @ 9104'-9113' & FIRED SWITCH @ 9084'-9096'; POH. 20:00 20:30 21:30 22:00 23: 00 AT SURF W/GUN#5; ALL SHOTS FIRED. PT LUB TO 30004; TEST OK. RIH W/T(X)L STRING -WGT BAR, GR, lYF SONDE TO OBTAIN STATIC BHP STATIC BHP @ 9100' RKB - 2864 PSIA AT SURF W/TOOL STRING RDFN. .... .Oil.& 1 O/24/96 GeoQuest 500 W. International Airport ROad Anchorage, AK 99518-1199 ATTN: Sherrie NO. 10514 Company: Alaska Oil & Gas Cons Comm Attn: Lori Taylor 3001 Porcupine Drive Anchorage, AK 99501 Field: Kuparuk (Open Hole) Well Job # Log Description Date BL RF Sepia LIS Tape SIGNED: .... Please si§n and return one copy of this transmittal to Sherrie at the above address. Thank you. ARCO Alaska, Inc. Date: July 16, 1996 Transmittal #: 9723 RETURN TO: ARCO Alaska, Inc. Attn.: Julie Nash Kuparuk Operations File Clerk AT©-1119B P.O. Box 100360 Anchorage, AK 99510-0360 Transmitted below are the following Cased Hole items. Please acknowledge receipt and return one signed copy of this transmittal. 1F-17 Cement Bond Log 06/29/96 6050-6748 1 F- 18 Cement Bond Log 06/29/96 7794-7799 1Q-02A Cement Bond Log 06/26/96 7900-8680 2M-09A Cement Bond Log 06/30/96 4900-9292 Acknowledge' Date: DISTRIBUTION' RECEIVED duLi 8 1996 Sharon AIIsup-Drake DS Development ATO-1205 -Larry Gmht (¥sepia) ~ AOGCC 3001 Porcupine Drive Anchorage, AK 99501 Chapman/Zuspan NSK Wells Group NSK69 TONY KNOWLE$, GOVERNOR 3001 PORCUPINE DRIVE ANCHOFtAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 t907) 276-7542 May 16, 1996 Denise Petrash Drill Site Develop. Supv. ARCO Alaska, Inc. P O Box 100360 Anchorage, AK 99510-0,360 Re: Kuparuk River Unit 2M-09A ARCO Alaska. Inc. Permit No. 96-90 Sur. Loc. 114'FSL, 124'Fa,¥T,, Sec. 27, T11N, R8E, UM Btmnhole Loc. 1034'FNL, 318'FWL, Sec. 3, T10N, R8E, UM Dear Ms. Petrash: 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 required bv 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 pr/or to drilling new hole. Notice may be given by ~~um field inspector on the North Slope pager at 659-3607... David WK. Johnston Chairman~ BY ORDER OF THE COMMISSION dlf/Enclosures CC: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA Ai~oKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 MAY 02 1995 la. Type of Work Drill X Redrill [] lb Type of we, Exploratory [] Slratigraphic Test [] ~'~]o-I:~i~a'FoJl X Re-Entry D Deepen I-'1 Service r-! Development Gas D Single Zone X Multiple Zone [-~ 2. Name of Operator 5. Datum Elevation (DF or KB) 1 0. Field and Pool ARCO Alaska, Inc. Ricj RKB 41', Pad 105' feet Kuparuk River Field 3. Address 6. Property Designation Kuparuk River Oil Pool P. O. Box 100360, Anchora~le, AK 99510-0360 ADL 25589, ALK 2675 4. Location of well at surface 7. Unit or property Name 1 1. Type Bond (see 2O AAC 25.025) 114' FSL, 124' FWL, Sec. 27, T11N, RSE, UM Kuparuk River Unit Statewide At top of productive interval (@ TARGET) 8. Well number Number 827' FNL, 348' FWL, Sec. 3, T10N, R8E, UM 2M-09A #U-630610 At total depth 9. Approximate spud date Amounl 1034' FNL, 318' FWL, Sec. 3, T10N, RSE, UM 5/20/96 $200,000 1 2. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) property line 2 M- 14 9559' MD 827' @ TD feet 603' @ 6180' MD feet 2560 6365' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 2o AAC 25.035(e)(2)) Kickoff depth 5000' feet Maximum hole angle 41.08° Maximum surface 1807 pslg At total depth (TVD) 3300 pslg 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 6.125" 4.5' 12.6# L-80 NSCT 4759' 4800' 2964' 9559' 6365' 200SxClass G Top 1000' above Kuparuk 19. To be completed for Reddll, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured 51 80 feet Plugs (measured) 7' Baker 'N-I' bridge plug @ 5180' true vertical 3124 feet Cement kick-off plug @ +4716'-5116' Effective depth: measured _+471 6 feet Junk (measured) true vertical _+2935 feet Casing Length Size Cemented Measured depth True Vertical depth Structural 8 0' 1 6 ' 210 SX ASI 1 21 ' 1 21' Conductor surface 4265' 9-5/8' 745 sx PF E & 780 sx Class G 4306' 2775' Intermediate Production 1211 6' 7 ' 200 sx Class G 121 57' 6406' Liner 7' cut f/4980' to 5030' Perforation depth: measured All perforations have been P & A'd true vertical 20. Attachments Filing fee X Properly plat [] BOPSketch X Diverter Sketch [] Drilling program X Drilling fluid program X Time vs depth plot E] Refraction analysis [-] Seabed report ~] 20 AAC 25.050 requirements X 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed ~ ~-'~~ Title Drill Site Develop. Supv. Date Commission Use Only ~:~ m~,,,.~ I I I See cover letter for Pe ....u AP150.number/~::3 3 '"' ,,,,~- O/77_0 / Approval date ~_ I ~" C~ ~_~ other recluirements Conditions of approval Samples required E] Yes ,~ No Mud log required ~ Yes 'J~ No Hydrogen sulfide measures [] Yes ,1~ No Directional survey required '~ Yes E] No Required working pressure forBOPE r-~ 2M ~ 3M E] 5M E] 10M [~ 15M Other; Original Signed By David W, Johnston by order of ~- Approved by Commissioner the commission Date Form 10-401 Rev. 7-24-89 Submit in triplicate GENERAL DRILLING PROCEDURE KUPARUK RIVER FIELD 2M-09A SIDETRACK Pre-Parker Operations: Nordic Rig #1 has P&A'd the original Kuparuk location, milled a window in the 7" casing, and set a kickoff plug as described in the Sundry approved on 3/14/96, No. 96-058. 1. Move in and rig up Parker #245. Install and test BOPE to 3000 psi. RIH to cement plug and establish sidetrack from original well. Estimated kickoff point is _+5,000'. Perform leak off test to 12.5 ppg EMW in new open hole. Drill 6-1/8" hole to total depth (9,559') according to directional plan. Run open hole evaluation logs or LWD tools as needed. Run and cement 4-1/2" liner on drillpipe, with 4" polished seal bore. Set liner hanger and liner-top packer with 200' of liner lap from the kickoff point. Release from liner. Note: Due to the long length of the liner, the cementing program is not designed to reach the liner lap but to extend 1000' above the top of the Kuparuk. Note: If significant hydrocarbon zones are present above the Kuparuk, sufficient cement will be pumped for isolation in accordance with Rule 20 AAC 25.030. Pressure test casing and liner-top packer to 3500 psi. Run completion assembly. Sting into polished seal bore with seal assembly and pressure test tubing and annulus. ND BOPE and install production tree. Note: As a dedicated injector, cased hole cement bond logs will be run on electric line after Parker 245 leaves the well. Shut in and secure well. Clean location and RDMO in preparation for coiled tubing cleanout and perforating. , . , . . . , . 10. 11. 12. RECEIVED MAY 0 2 199B Na~t 9il & ~la~ Cea~. Cemmtssto, DRILLING FLUID PROGRAI~ Well 2M-09A Density PV YP Viscosity Initial Gel 10 Minute Gel APl Filtrate pH % Solids Kick-off to weight up 8.4-9.6 5-15 5-8 30-40 2-4 4-8 8-10 9.5-10 4-7% Weight up to TD 10.7 10-18 8-12 35-50 2-4 4-8 4-5 through Kuparuk 9.5-10 <12% Drilling Fluid System: Tandem Brandt Shale Shakers Triple Derrick Shale Shakers Solids Processing System to minimize drilling waste Mud Cleaner, Centrifuges, Degasser Pit Level Indicator (Visual and Audio Alarm) Trip Tank Fluid Flow Sensor Fluid Agitators Notes: RECEIVED MAY 0 2 1996 Nalka Oil & Gas Cons. Commission Af~om~ Drilling fluid practices will be in accordance with the appropriate regulations stated in 20 AAC 25.O33. Maximum anticipated surface pressure is calculated using a leak-off at the kick-off point of 13.5 ppg EMW and a gas gradient of 0.11 psi/ft. The kick-off will occur just under the surface casing shoe and as such has similar formation integrity. This shows that formation breakdown would occur before a surface pressure of 1,807 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3000 psi. The nearest existing well to the 2M-09A sidetrack is 2M-14. As designed, the minimum distance between the two wells would be 603' @ 6180' MD. Annular Pumping Activities- Incidental fluids developed from drilling operations will be hauled to the nearest permitted disposal well or will be pumped down the surface/production casing annulus of an existing well. That annulus will be left with a non-freezing fluid during any extended shut down (> 4 hr) in pumping operations. The 2M-09A surface/production casing annulus has been Arctic packed. Drilling Area Risks- The main risks in the 2M-09A drilling area include lost circulation and high pressures in the Kuparuk formation. Lost circulation above the Kuparuk will be addressed with lost circulation material (LCM) and reduced circulating rates as needed. 4-1/2" casing will be topset above the Kuparuk and Nordic Rig #1 or the CTU will drill out a 3-3/4" hole, and run a 3-1/2" FJ or 2-7/8" liner to TD if lost circulation cannot be controlled with LCM and reduction of circulating pressure alone. Efforts to reduce Kuparuk geopressure at the target location and careful analysis of pressure data from offset wells show that a mud weight of 10.7 ppg will provide sufficient overpressure to safely drill, trip pipe, and cement. The 7" kickoff point will be tested to an equivalent mud weight of 12.5 ppg upon establishing the sidetrack. *Spud mud should be adjusted to a FV between 50-80 sec/qt to drill gravel beds. Diesel Cap to 2000' MD 9.6 ppg Milling Fluid 9.6 ppg Mud 2M-09 Plugback: Current Status APl #: 50-103-20177 Sundry Approval No. 96-058 RKB = 146' GL = 105' 9-5/8" 36#, J-55/47# L-80 set @ 4306' MD 17.0 ppg Cement Kick-off plug +4716 - 5116' MD 7" Casing section milled 4980'- 5030' MD 18.0 ppg Mud from 5130' - 5180' MD. 7" Baker 'N-I' Bridge Plug @ 5180' MD. RECEIVED MAY 0 2 1996 0il & Gas Cons. Commission Anchorage 15.8 ppg Cement plug spotted on top of packer; TOC 11,272' MD Abandoned A Sand Perfs 7", 26#, J-55/L-80 3-1/2" x 7" Camco 'HRP-I-SP' Retrievable production packer w/PBR bbl @ 11,677' MD. Tubing tail below packer includes: 3-1/2" x 10' pup, Landing nipple, 3-1/2" x 10' pup. Double check valve on Camco 'C' lock set in landing nipple @ 11,696' MD with cement squeezed below, down to top of fill at +/-12,031' MD. Top perforation @ 11,798' MD Bottom perforation @ 11,816' MD Top perforation @ 11,823' MD Bottom perforation @ 11,857' MD Top of fill at +/-12,031' MD. PBTD =12,069' MD TD = 12,177' MD WSI 3/23/96 DKP 4/29/96 7" BTC Mod from 5500' MD to surface Section in 7" +5000' MD/3052' 2M-09A Proposed Completion I. 3-1/8" 5M FMC Gen IV tubing hanger with 3-1/2" L-80 EUE 8rd-Mod pup, pin down (can reuse current equipment on well after redressing) H. 3-1/2", 9.3#, L-80 EUE 8rd MOD tbg to sudace G. 3-1/2" CAMCO 2.812" nipple with 'DS' NoGo profile set at +/- 500' MD, with 3-1/2" flow coupling bucked onto bottom of nipple F. 3-1/2" L-80 EUE 8rd MOD tbg (well should get credit for original tubing after inspection) E. 3-1/2" x 1-1/2" CAMCO 'MMM' mandrel w/DV & RK latch. 6' L-80 handling pups installed (can reuse current MMG-2 after testing and redressing) D. 1 jt 3-1/2" L-80 EUE 8rd MOD tbg C. 3-1/2" CAMCO 2.812" nipple with ~N' selective profile B. 1 jt 3-1/2" L-80 EUE 8rd MOD tbg A. Baker 3-1/2" seal assembly w! 10' of stroke and special Iocator to locate in liner tieback sleeve. Locator 5.125" OD, seals 4.0" OD. 6' L-80 handling pup installed. Liner-top assembly: · 6' extension sleeve with 4" GBH Iocator · ZXP 5" x 7" mechanical packer with hydraulic pusher sleeve · HMC 5" x 7" hydraulic hanger · 5" x 4" PBR with 10' seal bore with XO on bottom to NSCT all conx must be VAM through PBR 18.0 ppg Mud f/ ????' MD. Cement ret. set at ????' MD 3-1/2" 15.50 G105 drillpipe with 3-1/2" IF conx to drill 6-1/8" hole and run liner TOC min 1000' above top Kuparuk 4-1/2" CAMCO 3.812" nipple with 'DB' NoGo profile AVA nipple reducer f/3.812" 'DB' to 2.75" 'D' profile Abandoned C and A Sand Perfs (currently single completion) 7", 26#, L-80 BTC PBTD 12069' 4-1/2" 12.6 ppf L-80 NSCT liner @ 9559' MD / 6365' TVD Final angle 41.1° Future C & A Sand Peals 4-1/2" float equipment (for NSCT tubing) Run marker joint RECEIV£D MAY 0 ?_ 1996 Alaska Oil & (~a$ C0.1).""~ "'"'"'"~~/96 ARCO ALASKA, Inc.i Structure : Pad 2M Well : 9A l Field : Kuparuk River Unit Location : North Slope, Alaska l Creoted by : jones For: D PETRASH Dote plotted : 5-Apr--96 Plot Reference #7. is 9A Version ICoordinotes ore in feet reference slot iTrue Veriicol Depths ere reference wellheod. SURFACE LOCATION: 114' FSL, 124' F'WL SEC. 27, T11N, RSE ........ East --> 350 0 350 700 9 5/8 Csg KOP 1050 1400 S 2.06 DEG E 6225' (TO TARGET) ***PLANE OF PROPOSAL*** 245O .. ~ 51502 3500_ ~-- 3850_ _ 4200_ 4550_ (1) 4900_ - 5250_ I - I 5600_ ¥ 5950_ _ 6500_ _ 6650_ TARGET LOCATION: 827' FNL, 348' FWL 9 5/8 Csg KOP/SIDETRACK PT TVD=3052 TMD=5000 0EP=3375 57.06 4 DEG / 100' DIS 50.47 SEC. 5, TION, RSE TARGET TVD=6124 TMD=9239 DEP=6225 SOUTH 6221 EAST 224 EOD TVD=3509 TMD=5770 DEP=3982 C50 C40 035 C30 HRZ Midpoir~ K-1 Ida rko/ TARGET - T/ A3 S~nds[ Bose Kup $onds~,! _5600 _ _5950 AVERAGE ANGLE 41.08 DEG C50 C40 TD LOCATION: 1034' FNL, ~18' FWL SEC. ~, TION, RSE 'x~30 HRZ MIDPOINT TVD=5857 TMD=8885 OEP=5996 T/ UNIT ~ TVn-gnRa T~n--a~Rv ~p-R~vv '%. B/ HRZ TVD=S904 TMD=8948 DEP=6056 ' ~T_ki~GE~-_~/"~§~]~ ...... % K-1 MARKER "I'VD=5994 TMD=9067 DEP=6113 T/ UNIT A ]VD 6075 TMD 7 TD - 4 1/2" CSG PT TV1)=6365 TMD=9559 DEP=6431 ~] M/~¥ 0 ~ 199~ 2450 2800 ~150 3500 3850 4200 4550 ¢900 5250 5600 5950 6500 6650 Scale 1 · 175.00 Vedical Section on 177.94 azimuth with reference 0.00 N, 0.00 E from slot #9 I I V I 7 i , 6 > > < 4 I 1. 16" - 2000 PSI STARTING HEAD 2. 11" - 3000 PSI CASING HEAD 3. 11~' - 3000 PSI X 13-5/8" - 5000 PSI SPACER SPOOL 4. 13-5/8" - 5000 PSI PIPE RAMS 5. 13-5/8"- 5000 PSI DRLG SPOOLW/ CHOKE AND KILL LINES 6. 13-5/8" - 5000 PSI DOUBLE RAM W/ PIPE RAMS ON TOP, BLIND RAMS ON BTM 7. 13-5/8" - 5000 PSI ANNULAR 13 5/8" 5000 F,.¢I BOP STACK ACCUMULATOR CAPACITY TEST 1. CHECK AND FILL ACCUMULATOR RESERVOIR TO PROPER LEVEL ~^!!TN HvDPAUUC FLUID, 2. ASSU,~E Ti~AT AGGUIViULATOR PRESSURE ~S 30bO icSi WiTH 1500 PSI DOWNSTREAM OF THE REGULATOR. 3. OBSERVE TIME, THEN CLOSE ALL UNITS SIMULTANEOUSLY AND RECORD THE TIME AND PRESSURE REMAINING AFTER ALL UNITS ARE CLOSED WITH CHARGING PUMP OFF. 4. RECORD ON THE IADC REPORT. THE ACCEPTABLE LOWER LIMIT IS 45 SECONDS CLOSING TIME AND 1200 PSI REMAINING PRESSURE. SOP STACK TEST 1. FILL BOP STACK AND MANIFOLD WITH WATER. 2. CHECK THAT ALL HOLD-DOWN SCREWS ARE FULLY RETRACTED. PREDETERMINE DEPTH THAT TEST PLUG WILL SEAT AND SEAT IN WELLHEAD. RUN IN LOCK-DOWN SCREWS IN HEAD. 3. CLOSE ANNULAR PREVENTER AND CHOKES AND BYPASS VALVES ON THE MANIFOLD. ALL OTHERS OPEN. 4. TEST ALL COMPONENTS TO 250 PSI AND HOLD FOR 3 MINUTES. INCREASE PRESSURE TO 3000 PSI AND HOLD FOR 3 MINUTES. BLEED TO ZERO PSI. 5. OPEN ANNULAR PREVENTOR AND MANUAL KILL AND CHOKE LINE VALVES. 6. CLOSE TOP PIPE RAMS AND HCR VALVES ON KILL AND CHOKE LINES. 7. TEST TO 250 PSI AND 3000 PSI AS IN STEP 4. CONTINUE TESTING ALL VALVES, LINES, AND CHOKES WITH A 250 PSI LOW AND 3000 PSI HIGH. TEST AS IN STEP 4. DO NOT PRESSURE TEST ANY CHOKE THAT IS NOT A FULL CLOSING POSITIVE SEAL CHOKE. 8. OPEN TOP PIPE RAMS AND CLOSE BOTFOM PIPE RAMS. TEST BOTTOM RAMS TO 250 PSI AND 3000 PSI FOR 3 MINUTES. 9. OPEN PIPE RAMS. BACKOFF RUNNING JT AND PULL OUT OF HOLE. CLOSE BLIND RAMS AND TESTTO 3000 PSI FOR 3 MINUTES. BLEED TO ZERO PSI. 10. OPEN BLIND RAMS AND RECOVER TEST PLUG. MAKE SURE MANIFOLD AND LINES ARE FULL OF ARCTIC DIESEL AND ALL VALVES ARE SET IN THE DRILLING POSITION. 11. TEST STANDPIPE VALVES TO 3000 PSI FOR 3 MINUTES. 12. TEST KELLY COCKS AND INSIDE BOP TO 3000 PSI WITH KOOMEY PUMP. 13. RECORD TEST INFORMATION ON BLOWOUT PREVENTER TEST FORM. SIGN AND SEND TO DRILLING SUPERVISOR. 14. PERFORM COMPLETE BOPE TEST ONCE A WEEK AND FUNCTIONALLY OPERATE BOPE DAILY. VBRS WILL ACCOMODATE 3-1/2" TO 5-1/2" OR 5" TO 7" PIPE ODS AS APPROPRIATE. RECEIVED MAY 0 2 1996 Alaska Oil & Gas Cons. Commission Anchorage · WELL PERMIT CHECKLIST WELL NAME_ .., -: PROGRAM: FIELD & POOL d-'72.~,,,'"~:::~ ~ INIT CLASS Z~ /-<::~ ? ? GEOL AREA exp [] dev/~ redrl~ serv [] wellbore seg [] ann. disposal para req [] UNIT# / ////~'~::~ ON/OFF SHORE ADMINISTRATION 1 1 1. Permit fee attached ...................... 2. Lease number appropriate .................. 3. Unique well name and number ................ 4. Well located in a defined pool ................. 5. Well located proper distance from ddg unit boundary .... 6. Well located proper distance from other wells ........ 7. Sufficient acreage available in ddlling unit .......... 8. If deviated, is wellbore plat included ............. 9. Operator only affected party .................. O. Operator has appropriate bond in force ........... 1. Permit can be issued without conservation order ..... 2. Permit can be issued without administrative appmvai .... 3. Can permit be approved before 15-day wait. ENGINEERING REMARKS GEOLOGY DA,TE .~ 14. Conductor string provided ................... Y N 15. Surface casing protects ail known USDWs .......... Y N 16. CMT vol adequate to circulate on conductor & surf csg .... Y N 17. CMT vol adequate to tie-in long s~ng to surf csg ....... Y N 18. CMT will cover all known productive hodzons ......... Q N 19. Casing designs adequate for C, T, B & permafrost ..... ~ N 20. Adequate tankage or reserve pit ................ 21. If a re-drill, has a 10-403 for abndnmnt been approved .... 22. Adequate wellbore separation proposed ............ (.~ N . ti 23. If diverter required, is it adequate ................ -Y--N-~/O/,Z~ 24. Ddlling fluid program schematic & equip list adequate... ('~N 25. BOPEs adequate ....................... .F~N 26. BOPE press rating adequate; test to ~¢~:::)..___psig~ 27. Choke manifold complies w/APl RP-~ (-~ay~ ..... ,.--Y--N-Iv'' 28. Work will occur without operation shutdown .......... (~ N 29. Is presence of H2S gas probable .............. ~_.~N 30. Permit can be issued w/o hydrogen sulfide measures ..... Y N/,,~) 31. Data presented on potentJai overpressure zones ....... Y 32. Seismic anaiys~s of shallow gas zones ............. 33. Seabed condition survey (if off-shore) ........... .~.Y N 34. Contact name/phone for weekly progress reports .... ~/.. Y N J-explora tory only] GEOL~,: RPC~r~ ENGINEERING: COMMISSION: BEW DWJ _ Comments/Instructions: HOW/lib - A:~FORMS"cheklist rev 4,/96 Well HistorY File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. ~rO~I~ H.I.~ON : H~I~O~IO~ )~12Htfdl2kr : ~I4VN O~I~ lf60-f4K : ~f4VN ~I~I~Id 'DNI '~SV~tf ODHV : ~14VN ANVdf40D LIS Tape Verification Listing Schlumberger Alaska Computing Center 24-0CT-1996 13:3i PAGE: **** REEL HEADER **** SERVICE NAME : EDIT DATE : 96/10/24 ORIGIN : FLIC REEL NAME : 96239 CONTINUATION # : PREVIOUS REEL : CO~NT : ARCO ALASKA INC., KUPARUK 2M-O9A, API #50-103-20177-01 **** TAPE HEADER **** SERVICE NA~E : EDIT DATE : 96/10/24 ORIGIN · FLIC TAPE NAME : 96239 CONTINUATION # : 1 PREVIOUS TAPE : CO~4~VT : ARCO ALASKA INC. , KUPARUK 2M-O9A, API #50-103-20177-01 TAPE HEADER KUPARUK MWD LOGS WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: JOB DATA JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: SURFACE LOCATION BIT RUN1 ......... 96239 OLIVER MORRISON SECTION: TOWNSHIP: RANGE: FNL : FSL: FEL '. FWL.. ELEVATION(FT FROM MSL O) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: WELL CASING RECORD 1ST STRING 2ND STRING 2M-O9A 501032017701 ARCO ALASKA, INC. SCHLUMBERGER WELL SERVICES 24-0CT-96 BIT RUN 2 BIT RUN 3 27 liN 8E 114 124 146.00 146.00 105.00 OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 6.125 7.000 4980.0 LIS Tape Verification Listing Schlumberger Alaska Computing Center 24-0CT-1996 13:31 3RD STRING PRODUCTION STRING Data from SLIM1GR logged 6-JUN to lO-JUN-96. Log was depth shifted to SWS CBL GRCH logged 30-JUN-96. CBL log had a lot of sticking which led to difficult depth correlations. $ $ PAGE: **** FILE HEADER **** FILE NAME : EDIT .001 SERVICE · FLIC VERSION : O01CO1 DATE : 96/10/24 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE NUMBER: 1 EDITED MERGEDMWD Depth shifted and clipped curves; all bit runs merged. DEPTH INCREMENT: 0.5000 FILE SOF~fARY LDWG TOOL CODE .............. SLWD $ BASELINE CURVE FOR SHIFTS: GRCH CURVE SHIFT DATA (MEASURED DEPTH) START DEPTH STOP DEPTH 4941.0 8924.0 BASELINE DEPTH .............. 88888.0 8912.0 8905.0 8891.0 8876.0 8856.5 8840.0 8830.5 8800.5 8777.0 8763.5 8738.0 8727.5 8690.5 8675.0 8588.0 8568.0 .......... EQUIVALENT UNSHIFTED DEPTH SLWD 88857.0 8881.0 8871.5 8862.0 8846.5 8818.0 8797.5 8787.5 8769.5 8748.0 8737.5 8706.5 8695.5 8655.0 8641.5 8540.5 8521.5 LIS Tape Verification Listing Schlumberger Alaska Computing Center 24-0CT-1996 13:3~ PAGE: 8563.5 8555.5 8471.0 8466.0 8300.5 8162.5 7916.0 7814.5 7686.5 7595.5 7549.0 7228.0 7197.0 7119.0 7087.0 6980.0 6902.0 6853.0 6846.5 6827.5 6815.5 6782.5 6759.0 6711.0 6709 0 6694 5 6649 5 6600 5 6320 5 6247 0 6189 0 6153 0 5976 5 5333 0 5303 5 5283.5 5266.5 5263.5 5238.0 5213.0 5095.0 5075.5 100.0 $ MERGED DATA SOURCE LDWG TOOL CODE $ RE'lARKS: 8511.5 8502.5 8418.5 8412.5 8256.0 8115.0 7867.5 7766.0 7647.0 7550.0 7509.0 7211.5 7176.5 7103.5 7065 5 6963 0 6882 0 6830 0 6819 0 6803 0 6792 5 6729 5 6709 0 6676 0 6668.0 6643.0 6607.0 6558.5 6275.0 6215.5 6173.5 6142.5 5967.0 5324.0 5287.0 5267.5 5242.0 5240.0 5213.5 5175.0 5050.5 5031.5 56.0 BIT RUN NO. MERGE TOP MERGE BASE Log data and interpolation of SLIM1 GR. Data depth shifted to SWS CBL GRCH logged 30-JUN-96. $ LIS FORMAT DATA LIS Tape Verification Listing Schlumberger Alaska Computing Center 24~0CT-1996 13:3~ PAGE: ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE- 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 20 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 51 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 0 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP EL, EM CODE (HEX) DEPT FT NA O0 000 O0 0 1 1 1 4 68 0000000000 GRRWMWD AAPI NA O0 000 O0 0 1 1 1 4 68 0000000000 GRIN MWD AAPI NA O0 000 O0 0 1 1 1 4 68 0000000000 ROP MWD FPHR NA O0 000 O0 0 1 1 1 4 68 0000000000 GRCH CBL GAPI NA O0 000 O0 0 1 1 1 4 68 0000000000 ** DATA ** DEPT. 9000.000 GRCH. CBL 109.161 DEPT. 8000.000 GRCH. CBL 102.282 DEPT. 7000.000 GRCH. CBL 107.032 DEPT. 6000.000 GRCH. CBL 102.364 GRRW. MWD -999.250 GRIN. MWD -999.250 ROP.MWD GRRW. MWD -999.250 GRIN.MWD 93.859 ROP.MWD GRRW. MWD -999.250 GRIN.MWD 96.086 ROP.MWD GRRW. MWD -999.250 GRIN.MWD 70.060 ROP.MWD -999.250 170.707 40. 873 309. 262 LIS Tape Verification Listing Schlumberger Alaska Computing Center 24~0CT-1996 13:3~ PAGE: DEPT. 5000.000 GRCH. CBL 81.441 DEPT. 4930.000 GRCH. CBL 49.258 -999.250 GRIN.MWD -999.250 GRIN. MWD 79.560 -999.250 ROP. MWD ROP. MWD 74.100 -999.250 ** END OF DATA ** **** FILE TRAILER **** FILE NAME : EDIT .001 SERVICE : FLIC VERSION . O01CO1 DATE · 96/10/24 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NAME : EDIT .002 SERVICE : FLIC VERSION : O01CO1 DATE : 96/10/24 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE NUMBER 2 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 1 DEPTH INCREMENT: O. 5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH SLWD 4986.0 $ LOG HEADER DATA DATE LOCGED: SOFTWARE: SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY or REAL-TIME): TD DRILLER (FT) : TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : STOP DEPTH 8978.0 lO-JUN-96 5.3B 5.5C REAL-TIME 9405.0 4985.0 8978.0 LIS Tape Verification Listing Schlumberger Alaska Computing Center 24-0CT-1996 13:3~ PAGE: BIT ROTATING SPEED (RPM) : HOLE INCLINATION (DEG) MINIMUM ANGLE: MAXIMUM ANGLE '. 73 37.5 66.1 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE GR GAMMA RAY $ TOOL NUMBER ........... SLIM1 013 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLERS CASING DEPTH (FT) : 6.125 4980.0 BOREHOLE CONDITIONS MUD TYPE: LSND MUD DENSITY (LB/G): 9.60 MUD VISCOSITY (S) : MUD PH: MUD CHLORIDES (PPM) : FLUID LOSS (C3): RESISTIVITY (OH~) AT TEMPERATURE (DEGF) : MUD AT MEASURED TEMPERATURE (MT): O. 000 MUD AT MAX CIRCULATIONG TEMPERATURE : MUD FILTRATE AT (MT): O. 000 MUD CAKE AT (MT): O. 000 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: DRILLED INTERVAL WITH SLIM1 GR 4985' - 8978' SLIM1 NOT RUN FROM 8978' TO TD AT 9405' BIT TO GR - 54.88' WELL TD'D AT 9405' 1817 lO-JUN-96 $ LIS FORMAT DATA 0.0 0.0 0.0 ** DATA FORMAT SPECIFICATION RECORD ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 LIS Tape Verification Listing Schlumberger Alaska Computing Center 24-0CT-1996 13:31 PAGE: 7 TYPE REPR CODE VALUE 3 73 32 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 32 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NAM~ SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT NA O0 000 O0 0 2 1 1 4 68 0000000000 GR RAW CPS NA O0 000 O0 0 2 1 1 4 68 0000000000 GR MWD AAPI NA O0 000 O0 0 2 1 1 4 68 0000000000 GR INT AAPI NA O0 000 O0 0 2 1 1 4 68 0000000000 ROP MWD F/HR NA O0 000 O0 0 2 1 1 4 68 0000000000 ROPSN~D F/HRNA O0 000 O0 0 2 1 ! 4 68 0000000000 ROP5 INT F/HR NA O0 000 O0 0 2 1 1 4 68 0000000000 VDEPMWD FT NA O0 000 O0 0 2 1 1 4 68 0000000000 ** DATA ** DEPT. ROP.MWD DEPT. ROP.MWD DEPT. ROP.MWD DEPT. ROP.MWD 8955.000 OR.RAW -999.250 GR.MWD -999.250 GR.INT -999.250 103.000 ROPS.MWD 102.600 ROPS.INT 102.600 VDEP.MWD 5931.400 8000.000 GR.RAW -999.250 GR.MWD -999.250 GR. INT 82.172 193.100 ROPS.MWD 188.800 ROPS.INT 188.800 VDEP.MWD 5200.300 7000.000 GR.RAW -999.250 GR.MWD -999.250 GR.INT 94.403 137.700 ROPS.MWD 145.800 ROP5.INT 145.800 VDEP.MWD 4471.900 6000.000 GR.RAW -999.250 GR.MWD -999.250 GR.INT 69.663 227.300 ROPS.MWD 260.700 ROP5.INT 260.700 VDEP.MWD 3734.800 DEPT. 5000.000 GR.RAW 19.500 GR.MWD ROP.MWD 92.700 ROPS.MWD 67.500 ROPS.INT 46.310 GR. INT 46.310 67.500 VDEP.MWD 3053.100 LIS Tape Verification Listing Schlumberger Alaska Computing Center · _ 24-0CT-1996 13:31 PAGE: DEPT. 4985.000 GR.RAW -999.250 GR.MWD ROP.MWD 64.000 ROPS.MWD 33.900 ROP5.INT -999.250 GR.INT 33.900 VDEP.3~D -999.250 3033.300 ** END OF DATA ** **** FILE TRAILER **** FILE NAbfE : EDIT .002 SERVICE : FLIC VERSION : O01CO1 DATE : 96/10/24 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** TAPE TRAILER **** SERVICE NAME : EDIT DATE : 96/10/24 ORIGIN : FLIC TAPE NAME : 96239 CONTINUATION # : 1 PREVIOUS TAPE : C03~4ENT : ARCO ALASKA INC. , KUPARUK 2M-O9A, API #50-103-20177-01 **** REEL TRAILER **** SERVICE N;24E : EDIT DATE . 96/10/24 ORIGIN . FLIC REEL NAME : 96239 CONTINUATION # : PREVIOUS REEL : COM31ENT : ARCO ALASKA INC., KUPARUK 2M-O9A, API #50-103-20177-01
