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Home My WebLink About204-1401 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Monday, March 10, 2025 3:33 PM To:Miller, Nicklaus (Nick) Cc:Davies, Stephen F (OGC) Subject:RE: Placer #1 Sundry Number 324-516 (Oil Search Alaska LLC) Nick, Based on the additional background information mentioned in your email below, Oil Search has approval to proceed with the P&A without running the cement bond log across the 7” casing. All other conditions of approval still apply. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent: Wednesday, February 12, 2025 10:28 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Placer #1 Sundry Number 324-516 (Oil Search Alaska LLC) Bryan, Good morning! We’re geƫng close to performing the P&A work on both Placer wells and I came across some new/addiƟonal informaƟon regarding Placer #1 that I’d like to share with you. ASRC ExploraƟon LLC (AEX) originally submiƩed an abandonment package back in early 2016 that was approved, and I’ll show some important details of that package later in this e-mail. The informaƟon I’d like to review revolves around plugging the uncased porƟon of the wellbore and effecƟvely segregaƟng uncased and cased porƟons of the well. Per our approved sundry, we have a variance approval to 20 AAC 25.112 (a)(1)(C), 20 AAC 25.112 (a)(2) and 20 AAC 25.112 (b) to cement off the open hole secƟon of the well conƟngent on the following condiƟon being met: CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Santos would like to forego running the above menƟoned CBL based on new informaƟon sourced from the original ASRC abandonment sundry approved in 2016. Minimum calculated TOC outside 7” casing is 7,162’ per aƩached schemaƟc. The top of cement plug inside 7” is 7,062’ MD. Worst case, that puts TOC outside 7” casing 100’ below where we can effecƟvely log to with a CBL. Santos does not feel that running a CBL to confirm isolaƟon of the hydrocarbons in the Kuparuk sand is necessary for the following reasons that were originally submiƩed by ASRC: 3 4 In summary, we have a 305’ column of cement outside the 7” casing which creates a very competent shoe effecƟvely eliminaƟng verƟcal movement of fluids within the uncased porƟon of the wellbore. Santos will place an addiƟonal 5,400’ of cement inside the 7” to ensure no fluid movement in casing. Thank you, Nicklaus Miller Senior CompleƟons Engineer t:1 (406) 690-2896 | e: nick.miller@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email Placer 1— Current Status as Suspended k115' M D Section Lb/ft Grade Top MD Btm MD Btm TVD 16" 63 B Surface 115 115 9-5/8"' 40 L-80 Surface 2,528 2,269 7" 26 L-80 A8RDEUE Surface 7,467 6.053 6-118" OH NA NA 7,467 7,761 6,289 3-%:" 9.3 L-80 Surface 1,590 1,997 — 1,948' MD 2,000' MD — 2,528' MD 2,653' MD 11 ppg eu,d 6,010' MD — maximum calculated TOC (1,457') 7,162' MD- minimum calculated TOC (305') 7,062' MD 15.8 ppg Cement 313' 7,375' MD sand 10' 7,385' MD 82 ' 7,467' MD FIT 14 ppg 72' 7,539' MD Kuparuk MDT9.9ppg 21' 7,560' MD it ppg 201' LSND Mud 7,761' MD Page 4 of 7 Freshwater Diesel 11.0 ppg Cement Sand CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Miller, Nicklaus (Nick) Subject:RE: PTD 204-014 Placer 1 P&A for Santos (Sundry 324-516) Date:Monday, March 10, 2025 3:02:00 PM Attachments:image003.png Nick, Oil Search has approval to make these changes. The use of permafrost cement across the permafrost is a condition of approval on the sundry. Regards. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Miller, Nicklaus (Nick) <Nick.Miller@santos.com> Sent: Monday, March 10, 2025 2:01 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: PTD 204-014 Placer 1 P&A for Santos (Sundry 324-516) Bryan, I very much appreciate you taking the time over the phone to review a few small changes to the Placer 1 P&A sundry. Per our discussion, we will be pumping a permafrost cement blend on the OA Cement down squeeze rather than a full 15 ppg Class G cement that was mentioned in the approved P&A Sundry. We plan to pump the following blend on the OA Cement down squeeze: 22 bbls of 15ppg Class G lead 58 bbls of 11ppg ArcticCem Tail I look forward to your response. Regards, Nicklaus Miller Senior Completions Engineer t:1 (406) 690-2896 | e: nick.miller@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may beconfidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use,distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address: 3800 Centerpoint Drive, Suite 1400 Stratigraphic Service 6.API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): Middle Ground Shoal / MGS Oil Pools 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 10,093'N/A Casing Collapse Structural Conductor Surface 1,580 psi Intermediate 3,830 psi Production 13,450 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email:Katherine.oconnor@hilcorp.com Contact Phone: (907) 777-8376 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 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: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Signature: Operations Manager Katherine O'Connor PRESENT WELL CONDITION SUMMARY Length Size 6,340 psi N/A COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018756 204-140 50-733-20052-01-00Anchorage, AK 99503 Hilcorp Alaska, LLC MGS C31-26RD N/A TVD Burst 7,878 & 9,630 13,940 psi Tubing Size: MD 3,130 psi1,894' 7,133' 400' 1,895' 24" 10-3/4" 400' 7"7,091' 1,895' 10,093' Perforation Depth MD (ft): 7,291' 9,729 - 9,981 10,093' 7,850 (MD) 7,636 (TVD) / 9,584 (MD) 9,163 (TVD) & 316 (MD) 316 (TVD) Tubing Grade:Tubing MD (ft): 9,305 - 9,551 Perforation Depth TVD (ft): Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 5/5/2021 2-3/8" Daniel E. Marlowe Model D Perm Pkr & FH Retr Pkr / Baker TE-5 SSSV 4.7# / L-80 Other: Oil Safe AR Acid Soak 9,661'10,048'9,617'±3,500 psi 9,661'5" Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:47 am, Mar 16, 2021 321-132 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.03.16 09:49:43 -08'00' Dan Marlowe (1267) gls 3/17/21 SFD 3/16/2021 DSR-3/16/21 Oil Safe AR Acid Soak 10-404 Comm eption Required? Yes 3/17/21 dts 3/17/2021 JLC 3/18/2021 RBDMS HEW 3/18/2021 Well Prognosis Well Name:MGS C31-26RD API Number: 50-733-20052-01-00 Current Status:Gas-Lifted producer Leg:Leg #1 Estimated Start Date:5/5/2021 Rig:N/A Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:204-140 First Call Engineer:Katherine O’Connor (907) 777-8376 (O) (214) 684-7400 (M) Second Call Engineer:Karson Kozub (907) 570-1801 (M) Current Bottom Hole Pressure (top perf): 3978 psi @ 8,463’ TVD 0.47 lbs/ft – based off offset C42-23 buildup Maximum Expected BHP (Hemlock):3978 psi @ 8,463’ TVD 0.47 lbs/ft Maximum Potential Surface Pressure:±3500 psi (treatment pump limit) Brief Well Summary The Middle Ground Shoal C31-26RD is a gas lifted producer. Production has fallen off in the last year due to scale buildup in the liner, verified by wireline tags. This project will stimulate the well in an attempt to remediate suspected carbonate scale buildup. There is a tubing stub in the well and intention is to treat scale within and below the tubing stub. Procedure: 1. MIRU pumping equipment. 2. Pressure test surface lines to ±3,500 psi (treatment pump limit) 3. Pump ±1650 gallons Oilsafe AR (synthetic acid) 4. Displace with ±38 bbls FIW 5. Shut down pump and let for ±72 hours. 6. Rig down pumping equipment 7. Turn over to production Attachments: 1. Well Schematic Current 2. Fluid Flow Diagrams 3. Oilsafe AR – Technical Data Sheet (40 bbls) _____________________________________________________________________________________ Updated By: JLL 08/29/16 SCHEMATIC Middle Ground Shoal Well: MGS C31-26RD Last Completed: 08/13/2016 PTD: 204-140 API: 50-733-20052-01-00 PBTD =10,048’ TD =10,093’ a KB: 35’ 5” b c d e f 12 10-3/4” 7” 1 2-11 Sqz Hole in 7” @ 3,440-3,471 13 14 15 Top of Tubing @ 7,966’ g X X X CASING DETAIL Size Wt Grade Conn ID Top Btm 24” Conductor 18.750 Surf 400’ 10-3/4” 40.5 J-55 ASL 10.050 Surf 1,895’ 7” 23 N-80 BTC 6.366 200’ 5,600’ 7” 26 N-80 BTC 6.151 5,600’ 7,291’ KOP 5” 18 P-110 STL 4.276 Surf 634’ 5” 18 P-110 Ultra FJ 4.276 634’ 10,093’ TUBING DETAIL 2-3/8” 4.7# L-80 8rnd EUE 1.995 Surf 7,878’ 2-3/8” 4.7# L-80 8rd EUE 1.995 7,966’ 9,630’ Note: 7” casing cut off a total of 250’ below RT JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 316’ 316’ 1.875” 3.625” Baker TE-5 SSSV 2 1,838’ 1,837’ 1.995” 3.750” GLM 1 T1 Latch 3 3,260’ 3,258’ 1.995” 3.750” GLM 2 T1 Latch 4 4,265’ 4,244’ 1.995” 3.750” GLM 3 T1 Latch 5 4,947’ 4,904’ 1.995” 3.875” GLM 4 BK2 Latch 6 5,472’ 5,405’ 1.995” 3.875” GLM 5 BK2 Latch 7 5,981’ 5,892’ 1.995” 3.875” GLM 6 BK2 Latch 8 6,524’ 6,410’ 1.995” 3.875” GLM 7 BK2 Latch 9 7,062’ 6,916’ 1.995” 3.875” GLM 8 BK2 Latch 10 7,573’ 7,394’ 1.995” 3.875” GLM 9 BK2 Latch 11 7,748’ 7,549’ 1.995” 3.875” GLM 10 (Orifice) BK2 Latch 12 7,796’ 7,591’ 1.995” 3.750” Chemical Injection Valve T1 Latch 13 7,850’ 7,636’ 2.668” 3.968” Model D Permanent Packer w/ anchor latch assembly and seal bore extension 14 7,867’ 7,650’ 1.875” 3.063” X Nipple 15 7,878’ 7,660’ 1.995” 3.600” WLREG A 8,477’ 8,137’ 1.995 3.975” GLM 10 B 9,053’ 8,655’ 1.995 3.975” GLM 11 C 9,535’ 9,115’ 1.995 3.975” GLM 12 (Orifice) D 9,576’ 9,153’ 1.875 2.750” X Nipple E 9,584’ 9,163’ 1.978 4.125” Baker FH Retrievable Packer 43B #781-08- 1247 F 9,597’ 9,175’ 1.875 2.750” X Nipple G 9,630’ 9,208’ 2.000 4.030” WLREG PERFORATION DETAIL Zone Top (MD)Btm (MD) Top (TVD)Btm (TVD) FT Date Status H2 9,729' 9,741' 9,305' 9,317' 12' 10/18/2004 Open H2 9,740' 9,790' 9,316' 9,365' 50' 10/14/2004 Open (Frac’d) H2 9,791' 9,819' 9,366' 9,393' 28' 10/18/2004 Open H2-H3 9,846' 9,886' 9,419' 9,458' 40' 10/18/2004 Open H2-H3 9,890' 9,940' 9,462' 9,511' 50' 10/07/2004 Open (Frac’d) H2-H3 9,941' 9,947' 9,512' 9,518' 6' 10/18/2004 Open H2-H3 9,963' 9,981' 9,534' 9,551' 18' 10/18/2004 Open • Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Friday,January 27, 2017 1:50 PM To: Juanita Lovett I� Cc: Dan Marlowe; samantha.carlisle@alaska.gov 46 G� Subject: RE:Withdraw Sundry#316-398/PTD:204-140 - MGS_Of..46RD Juanita, D The AOGCC will withdraw sundry 316-398 for well MGS-C- as requested. Guy Schwartz Sr. Petroleum Engineer AOGCC SCANNED JUN 0 52017 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226)or(Guy.schwartz@alaska.gov). From:Juanita Lovett [mailto:jlovett@hilcorp.com] Sent: Friday,January 27, 2017 10:31 AM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Cc: Dan Marlowe<dmarlowe@hilcorp.com> Subject:Withdraw Sundry#316-398/PTD: 204-140-MGS C32-16RD Guy, Please withdraw the above mentioned sundry. The project will not be completed at this time. Scope of work was to add perforations in the Hemlock bench 1 and the F sands. Juanita Lovett Operations/Regulatory Tech Hilcorp Alaska,LLC 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Office: (907)777-8332 Email: jlovett@hilcorp.com 1 RBDMS I 1 0 2017 STATE OF ALASKA AAA OIL AND GAS CONSERVATION COM ION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon El Plug Perforations❑ Fracture Stimulate ❑ Pull Tubing 0 Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program 0 Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: Run New G/L Comoletion0 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory 0 204-140 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service 0 6.API Number: Anchorage,AK 99503 50-733-20052-01-00 7.Property Designation(Lease Number): 8.Well Name and Number: RFCEI E ADL0018756 MGS C31-26RD 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): AUG, N/A Middle Ground Shoal/E,F and G Oil Pools j 11.Present Well Condition Summary: AOGCC Total Depth measured 10,093 feet Plugs measured N/A feet true vertical 9,661 feet Junk measured N/A feet Effective Depth measured 10,048 feet Packer measured 7,850&9,584 feet true vertical 9,617 feet true vertical 7,636&9,163 feet Casing Length Size MD TVD Burst Collapse Structural Conductor w " Surface 1,895' 10-3/4" 1,895' 1,894' 3,130 psi 1,580 psi Intermediate 7,091' 7" 7,291' 7,133' 6,340 psi 3,830 psi Production 10,093' 5" 10,093' 9,661' 13,940 psi 13,450 psi Liner Perforation depth Measured depth 9,729-9,981 feet scog1�Y JAN 2 Lr n True Vertical depth 9,305-9,551 feet !d 2-3/8" 4.7#/L-80 7,878'(MD) 7,660'(ND) Tubing(size,grade,measured and true vertical depth) 2-3/8" 4.7#/L-80 9,630'(MD) 9,208'(ND) Model D Perm Pkr 7,850'(MD)7,636'(ND) Packers and SSSV(type,measured and true vertical depth) FH Retr Pkr 9,584'(MD)9,163'(ND) Baker TE-5 SSSV 316'(MD)316'(ND) 12.Stimulation or cement squeeze summary: Intervals treated(measured): . N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Md Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 52 12 388 572 71 Subsequent to operation: 68 30 438 783 79 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory❑ Development Service ❑ Stratigraphic 0 Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil 0 Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-315&316-418 Contact Dan Marlowe(907)283-1329 Email dmarlowe( hilcorp.com Printed Name Stan W.Golis Title Operations Manager Signature oa.. L'' li �Q1 Phone (907)777-8356 Date 6/ a 9 / !6 i'30-16 .0 -9t6a v Form 10-404 Revised 5/2015 RBDMS LI_ MIL; 3 0 2016 Icu Submit Original Only • • Middle Ground Shoal SCHEMATIC Well: MGSete : 08/ Last Completed: 08/13/2016 PTD:204-140 Hileorp Alaska,LLC API:50:074: 733 20052 01 00 KB:35' CASING DETAIL Size Wt Grade Conn ID Top Btm 24" Conductor 18.750 Surf 400' - t ", 10-3/4" 40.5 J-55 ASL 10.050 Surf 1,895' �- 7" 23 N-80 BTC 6.366 200' 5,600 7„ 26 N-80 BTC 6.151 5,600' 7,291' ''+4. KOP 143/4' 5" 18 P-110 STL 4.276 Surf 634' 64 g S 5" 18 P-110 Ultra F1 4.276 634' 10,093' at TUBING DETAIL 2-3/8" 4.7# L-80 8rnd EUE 1.995 Surf 7,878' 2-3/8" 4.7# L-80 8rd EUE 1.995 7,966' 9,630' ' � Note: 7"casing cut off a total of 250'below RT Sgz Hole in 7 n,,, I� r @3'aa0-3.471 j JEWELRY DETAIL r4' 2 1 =*: "„ Depth Depth 4..r, `'t No ID OD Item (MD) (TVD) . $11 1 316' 316' 1.995" 3.620" Baker TE-5 SSSV „' 2 1,838' 1,837' 1.995" 3.750" GLM 1 T1 Latch 1 ; i 3 3,260' 3,258' 1.995" 3.750" GLM 2 Ti Latch +, "`, I 4 4,265' 4,244' 1.995" 3.750" GLM 3 T1 Latch 3' . ,� 5 4,947' 4,904' 1.995" 3.875" GLM 4 BK2 Latch r . 11 6 5,472' 5,405' 1.995" 3.875" GLM 5 BK2 Latch s d 1 7 5,981' 5,892' 1.995" 3.875" GLM 6 BK2 Latch A 7 8 6,524' 6,410' 1.995" 3.875" GLM 7 BK2 Latch >' 1.11 + 9 7,062' 6,916' 1.995" 3.875" GLM 8 BK2 Latch '74.;," an ii an ii j 10 7,573' 7,394' 1.995" 3.875" GLM 9 BK2 Latch ' • 11 7,748' 7,549' 1.995" 3.875" GLM 10(Orifice)BK2 Latch 1 '#,'k a 12 7,796' 7,591' 1.995" 3.750" Chemical Injection Valve T1 Latch 7" ,moi {I* k. 13 7,850' 7,636' 2.668" 3.968" Model D Permanent Packer w/anchor latch , assembly and seal bore extension 0' 14 7,867' 7,650' 1.875" 3.063" X Nipple ii 12 4: • MD 15 7,878' 7,660' 1.995" 3.600" WLREG �8 13 1 a A 8,477' 8,137' 1.995 3.975" GLM 10 • 14 `E a B 9,053' 8,655' 1.995 3.975" GLM 11 154 C 9,535' 9,115' 1.995 3.975" GLM 12(Orifice) D 9,576' 9,153' 1.875 2.750" X Nipple _ _ E 9,584' 9,163' 1.978 4.125" Baker FH Retrievable Packer 43B#781-08- 0 Top of T•yis 1 1247 Tubing aF 9,597' 9,175' 1.875 2.750" X Nipple @7,966' M G 9,630' 9,208' 2.000 4.030" WLREG -7 bAlit 1 E in + c t i MII PERFORATION DETAIL e dII 'z Zone Top(MD) (MD)( ND) Btm(TVD) FT Date Status • f 4'b , M. '*. H2 9,729' 9,741' 9,305' 9,317' 12' 10/18/2004 Open 9 a H2 9,740' 9,790' 9,316' 9,365' 50' 10/14/2004 Open(Frac'd) T'; H2 9,791' 9,819' 9,366' 9,393' 28' 10/18/2004 Open = H2-H3 9,846' 9,886' 9,419' 9,458' 40' 10/18/2004 Open • T H2-H3 9,890' 9,940' 9,462' 9,511' 50' 10/07/2004 Open(Frac'd) I-12-H3 9,941' 9,947' 9,512' 9,518' 6' 10/18/2004 Open H2-H3 9,963' 9,981' 9,534' 9,551' 18' 10/18/2004 Open 5" sA; PBTD=10,048' TD=10,093' Updated By:JLL 08/29/16 �� Hilcorp Alaska, C ui�" pA�°k°,cL� Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MGS C31-26RD Moncla 404 50'733'30052'01-00 204'140 7/24/2016 8/13/2016 7/24/16-Sunday Circulated well withtaking returns to production,until getting 9.2 PPG returns.Shut down and monitor well.Monitored well for an hour,and built up to 200 PSI,we pumped an additional 33 BBLS of 905 PPG brine initially getting 8.5 PPG returns at 33 BBL away we were getting 9.5 returns.Shut down and monitored well.Meet with production and discuss plan on killing well.Casing pressure was at 90 PSI after installing fresh gauge. Pumped 70 BBL of 9.5 PPG brine down the tubing,taking returns to production.70 PSI system,we were getting an emulsion that weighed at 9.5 PPG back. Shut down and diverted the casing to a 15 PSI system pressure never went below 35 PSI.Shut in and monitored pressure.The casing pressure increased to 75 PSI,opened up tubing and had flow,shut the swab valve.Installed gauge and pressure built up to 70 PSI.Tested tubing hanger void to 5000 PSI for 30 minutes to ensure tubing hanger seal integrity during BOP testing.Took on FIW.,and built 81.BBL of 98 PPG rie.fumped 71 BBL down tubing taking returns to production.Initial returns were 9.5 PPG brine with oil and emulsion.Towards end of circulation returns started to clean up.Final weight taken of returns 9.7.Monitored well,all static.Rig down hoses make up BPV and attempt to set through tree,had several spots in tree were we had to punch through scale.Set BPV counted rounds valve set good.Nipple down tree inspected lift threads in tubing hanger 2 7/8 PH6 all good.Installed blind flange to secure flow line. Install test sub in top of tubing hanger.Pumped and locked open SSSV,attempt to stab on 7 1/16"5M x 13 5/8"5M DSA.The studs that were in the 7 1/16'side of the DSA were too long,appears that through bolt studs were used in place of pad studs.We removed the four studs that are situated above the outlets of the tubing spool and cut them down and reinstalled them so as to be able to bp(tnntbw, gsps,Setinriser and placed hatch cover over same,stacked on mud cross,double gate and annular preventer,start making up connections on same.Prep derrick to raise unrolling cables and stretching them out. 7/25/16 -K8on6uy Continue to torque up BOPE flange bolts,remove cables and guide wires in preparation of standing derrick.Stand derrickand scope out same.Secured guy wires hang and rig up floor.Changing pipe rams from 2 7/8"x 5"VBR to 2 3/8"conventional,and finish hooking up accumulator lines to BOP.Installed choke and kill lines,ran electrical lines for accumulator shack,the test pump,conex's and rig lights.Spotted cuttings tank under shaker,continue to work on stairs,handrails,and landings.Complete changing pipe rams from 2 7/8"x 5"VBR to 2 3/8"conventional.Build splash guards around cuttings tank, dress tongs and slips stage on rig floor.Rig up weight indicator,and build 95 BBL 9.8 PPG brine with 3%KCI.Build walkway from carrier to pits,work on stairs.Build 2.375"test joint,had to change tongs due to die issues.Take on FIW to fill stack,continue to work on hand rails,landings and stairs.Attempt to shell test BOP annular leaking on 2500 PSI test could visually see leak,continue with shell test closing pipe rams continued to have small leak at 3500 PSI,chasing that at report time. 7/26/16 Continue with shell test chasing leaks and air in system.Was able to get shell test against pipe rams,K3 valve,and Valves 1&2 on choke.Perform BOP test 250 low and 3500 PSI high per sundry had annular and Kill HCR failures.AOGCC BOP Test witness was waived by Jim Regg.Removed 13 5/8"5M Annular and replaced with a 13 5/8 x 7 1/16"5M spool and a 7 1/16"5M Hydrill GK annular preventer.Replaced failed HCR with new.Note:Jim Regg,AOGCC was notified of annular size change.Test 7 1/16"5M annular on 2 3/8"test joint 250 low and 2500 PSI.Test break down stream of Choke HCR to 3500 PSI,test Choke HCR to 250 low and 3500 PSI high,perform step down test on manual and hydraulic chokes,and perform drawdown test on the accumulator. Circulate down tubing through the BPV with blinds closed taking returns from tubing x casing annulus to production 75 PSI system,at 2 BPM rate.(Had 80 PSI on casing priorto pumping).Circulated a totalof78B8Lnf98ppGbrineinitia|lyhada94PPGbnne/emu|sion returning.oyend cfcirculation had 9.8 in and out.Shut down and monitored well,no flow on tubing had 60 PSI on casing bled it down to 20 PSI via productions 15 PSI system.Pulled 2"CIW Type"H"BPV no pressure, tub flow,pulled hanger to surface and disconnected SSSV control line.Laid down tubing hanger.Change out tongs tosmall Foster style tongs dressed for Z3/8''tubing.Pull l]/8''4.7# L80 EUE tubing out of hole to SSSV @ 301'and lay down same.Continue to pullout of hole laying down tubing topping hole off with 9.8 PPG brine every 40 joints.Recovered l3hJoints l.s75,tubing,1SSSV,3GLM.Should have a2.375 EUE lookinupbox on bottom of GLM#3 split and dropped pipe.Pick up Knight Oil Tools fishing assembly consisting of4z/8^xZ3/8''Mill guide,41/8''lower extension,41/8^overshot dressed with Z3/8"grapple and pack • . • Hilcorp Alaska, LLC Hileorp Alaska,LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MGS C31-26RD Moncla 404 50-733-20052-01-00 204-140 7/24/2016 8/13/2016 7/27/16-Wednesday Finished working boat.Run in hole picking up 2.375"PH6 work string with overshot assembly.Tag @ 4346',up wt 29k,down wt 27k.Rig up power swivel, tested lower Kelly valve 250/3500,good.Mill over upset on 2.375"tubing,engaged grapple.Work string weight 30K,remainder of tubing to packer 28K+ 30K for packer shear.Should release at 88K,worked up to 85K and weight fell off to 32K.Laydown power swivel and prep to trip out of hole with fishing assembly.Trip out of hole with fishing assembly racking work string back and filling hole every 20 stands.Laid fish down,recovered 2.375"pup below GLM#3 length3.85,and partial joint below pup 25.30.Both pieces had multiple holes from severe corrosion. Picked up fishing assembly#2 consisting of 4 1/8"x 2 3/8"Mill guide,4 1/8"lower extension,4 1/8"overshot dressed with 2 3/8"grapple,pack off,and 4 1/8"upper extension with a XO back to 2 3/8"PH6 work string.Run in hole with fishing assembly#2,set down and tagged at 4360.00'estimated top of fish 4387.00.Pick up power swivel and rotate and work down to 4374.00 pumping at.7 BPM rate,torque building to 1000.Pick up and clear cut lip mill guide started to have increasing pump pressure and 3-8K overpull.Annular velocity at 0.7 BPM=67 FPM.Picked up 1 joint and installed stripper rubber to increase pump rate,worked down fishing assemble with 1000 torque and 2 BPM rate until a pressure spike was noticed.The pumps were shut down and 15K weight set down.Picked up and slacked off working overpull up to 30K to ensure engagement.Rigged down power swivel and secured well with FOSV. 7/28/16-Thursday Housekeeping,rig maintenance,round up subs for upcoming wire line operation.Spot wire line unit and rig up same.Run in hole with 1.5"blind box to 4379'WLM,work down to 4383'could not get any deeper. Pull out of hole,no over pull experienced.Change out tool to 1.5"bailer.Run in hole with 1.5" bailer to 4379'work down to 4383'WLM,pull out of hole,no recovery.Rig down wire line&clear floor.Pull on tubing,work up weight to 100k,no movement,slacked off,rig up&pump.5 BPM,1300 psi pull tubing working up weight to92k,_weightrfeILoff to 0k_.Rig down circulating head,begin to pull out of hole,we started pulling into fill,rigged up and circulate bottoms up @ 3 bpm 1470 psi,monitored well for flow,well bore static.Rig down circulating lines.Pull out of hole with fishing assembly#2,found that we had recovered a partial joint 6.03'long,along with a partial joint 29.73 long.The end of the longer partial joint were it parted was plugged with a scale conglomerate(Most likely material that had fell back when we initially pulled on it). There were numerous holes in the tubing along with significant pitting.Pick up fishing assembly#3,had to modify a stop so as that the 2.375"tubing body could pass and it would stop on a coupling. Fishing assembly#3 consisting of 4 1/8"overshot dressed with 3 1/16"grapple with a 2.375"no go above, pack off,and 4 1/8"upper extension with a XO back to 2 3/8"PH6 work string.Note we are set up to swallow what little tube we have sticking up and engage the coupling.Run in hole with fishing assembly#3,to 2170'having to run in hole slow to keep from having fluid run over top of tubing.10 stands in we were out of balance,shut down and circulated 20 BBL from active system down tubing taking returns from tubing x casing annulus,check for flow well static.Continue to trip in hole (3.5 minutes slip to slip).Shut down for meal came back had pressure under FOSV,rigged up and circulated a surface to surface volume from 2170'at 2.25 BPM,checked for flow,well static.Run in hole with fishing assembly#3,from 2170'and tag at 4384'(wall scale) having to run in hole slow to keep from having fluid run over top of tubing,at 3973' we were out of balance,shut down and circulated 70 BBL from active system down tubing taking returns from tubing x casing annulus,check for flow well static.Continue to trip in hole. Had a damaged pin on bottom of stand had to lay down single.Pick up power swivel and reverse wash down to top of fish currently @ 4405',est TOF @ 4417',pumping @ 1.5 bpm,350 psi. • • • Hilcorp Alaska, LLC ililcorpAlaska,LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MGS C31-26RD Moncla 404 50-733-20052-01-00 204-140 7/24/2016 8/13/2016 7/29/16-Friday Continue to wash down to top of fish at 4417'and engage same,work pipe staging up to 80k weight fell off to 37k.Laid down power swivel.Pull out of hole,moved pipe up hole 30',unable to pull past 4387'.Started working string unable to make headway,rig up circulating line,stage pump up to 2 BPM, 650psi.Continue to work string,lost free movement and 10'of hole,continue working pipe up to 92K, indicator weight fell off to 31K.Trip out of hole and lay down fish,recovered 62.15'of tubing.Pick up BHA#4 consisting of 4 1/8"overshot with upper extension dressed with 3 1/16"grapple,3 1/8"bumper sub,3 1/8"Bowen fishing jar,(6)DC3 1/8",1 accelerator jar,and XO. Ran in hole to 4420'and tagged wall scale.Picked up Power swivel and connected hoses.Wash and ream from 4420'to 4446'at 2 BPM and 600 PSI,picked up 10'pup,reversed and rotated down to 4451',engaged fish.Beat down for approximately 30 minutes,had approximately 2'of free travel,picked up to neutral weight and pumped at 2 BPM rate 600 PSI.Worked weight up to 20K over pull and monitored weight indicator to see if there was a loss of weight,none seen.Appeared to be circulating at overshot(No Pack off),shut down pump.Cocked jar and pulled 10K over jars fired and worked up to 45K over,continue to work jars slacking off ensuring free travel remained.We were able to beat fish up the hole 40+'and started to pull free. With pipe pulling free looks like 7-8K additional weight above work string weight.Trip out of hole with fish from 4411'filling hole every 20 stands to BHA,and laid it down.Recovered 18 Joints 2.375'tubing and a partial joint totaling 566.67'.Parted end was deformed from beating down with bumper sub and drill collars in addition to being packed with scale.Condition of tubing laid down was poor with severe pitting and holes,scale plugging was intermittent with some joints plugged and others not.Clean and police work area. 7/30/16 Saturday Pick up BHA#5„ onsistingof 4 1/8""overshot with upper&lower extension dressed with 2 3/8"grapple,and a mill guide,3 1/8"bumper sub,3 1/8" Bowen fishing jar,(6)DC3 1/8",1 accelerator jar,and XO.TIH to 4457'and tagged wall scale.Pick up power swivel&install stripper element.Wash& ream from 4457'to 5043'.Rotating wt 35K,Torque off bottom 700,pump rate 2 bpm,750 PSI.Wash and rotate over fish did not see much drag going over stub,slapped down several times,no down movement.Pick up to 50K set back down to neutral picked up 75K(35K over pull)and fired jars,weight fell off to neutral.Set down and picked up to 50K and grapple slipped off fish,repeated several times no joy.Possible damage to wickers on grapple while rotating over.Skim oil from active pits and ship to production.Circulate bottoms up had 1400 units gas at bottoms up,prep to trip out of hole.Rig down power swivel.Trip out of hole with fishing assembly#5,laid down 7 joints and pulled 1 stand,well out of balance.Shut in well and had power failure, rigged up hose and began circulation to even out mud weight.Corrected power failure found breaker thrown. Build a dry job slug while circulating. Continue to trip out of hole, filling hole every 20 stands. 7/31/16-Sunday V Continue to pull out of hole to BHA,no recovery.Replace grapple,whickers appeared to be rolled,with a 2.25"grapple.Make up BHA.Tran.hole with 01 BHA#6,slow to keep from flowing over tubing,pumping tubing volume as needed to help balance.Engage fish at 5043'began jarring up at 40-45K over pull,moved fish up hole approximately 30'.Rig up circulating hose and circulate 2 bottoms up to clear oil and gas that was migrating up hole and to level out fluid weights to help with u-tubing. Circulated at 2.25 BPM rate 800 PSI had 1250 units gas at bottoms up.Continue to pull out of hole,had to jar on fish a few times to get it started up hole. Looks like 12K additional weight.Pulled 15 stands and circulated bottoms up to try and circulate out any oil and gas that was disturbed from jarring fish loose.Continue to trip out of hole to 270',filling every 20 stands.Well was flowing up tubing,pumped fluid around to equalize weights no joy,pumped heavy slug did not work,circulated around was getting oil and some gas back at shaker._Shut in and monitored p[essuGellad_12 125251 Q ti bing nq_preSWITP.on casing.Appears oil and gas migrating up from were fish was recovered.Pumped a tubing volume and made up a single joint of 2.375 PH6 tubing with FOSV made up and hanging in elevators,continued process to 775'circulated 2 bottoms up,gas dropped from 600 units to 70 units. Continue process to 834'. • • Hilcorp Alaska, LLC Hilcorp Alaska,LLQ: Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MGS C31-26RD Moncla 404 50-733-20052-01-00 204-140 7/24/2016 8/13/2016 08/01/16-Monday Cont.rih w/singles using safety valve to keep fluid from running over tubing to 1045'.Circulate hole volume @ 2bpm 340 psi,monitor u-tube,static. Cont.RIH t/4695'.Circulate 1 1/2 hole volume,@ 2bpm,730 psi,had max 770 units gas.S/d monitor well 60 min,static.CBU had 256 units gas max @ B/U.P/U hanger m/u landing jt,wait on xo.R/u t/pump fluid from pits t/injection well C-44-14.Pump pits volumes down injection well C44-14,pump 75bbls @ 2 BPM 1050 psi.Pick up&rig up BOPE test equipment and hanger.Set BPV.C/O HCR choke valve.Fill stack with FIW and shell test 250 LOW and 3500 HI.Mix 80 bbl 10.5 ppg brine.BOPE Test as per AOGCC&Hilcorp,Hydril 250 LOW/2500 HI.Remainder of BOPE tests 250 LOW/3500 high.AOGCC witness waived by Jim Regg,8-1-16 11:43.Mix 2nd 80 bbl 10.5 ppg brine.Rig down/Lay down test equipment. Circulate 32 bbl tubing volume 10.5 ppg brine.Pull BPV. Check fluid weight finish weighting up t/10.5. 08/02/16 Tuesday Get with Production operators,line up&pump 10.5PPG brine down hole taking returns to production.Pump 58 bbls s/d,fill mix tank from rig tank, weight up t/10.5ppg,pump down hole checking returns to production until 10.5 fluid back.Pull hanger/test plug&I/d.C/o handling tools.POOH slow standing back 54 stands of 2-3/8"work string in derrick,lay down 37 joints.Lay down jars and overshot.Start laying down 2-3/8"tubing.86 jts parted jt 17.82' total=2809.68'.Top of fish @ 7852.68'.Weight up 27 bbl to 10.5 ppg brine.Mix 30 bbl 10.5 ppg brine,c/o swabs on pump.Pick up BHA#7, 4 1/8"w/2 3/8"ID wavy btm shoe,xo bushing,4 1/8"overshot with upper&lower extension dressed with 2 3/8"grapple, 3 1/8"bumper sub,3 1/8" Bowen fishing jar,(6)DC3 1/8",1 accelerator jar,and X0=212.04'.RIH w/2-3/8"work string.RIH w/42 stands slow,started u-tube while running in, pumped tubing volume to balance.Continue TIH w/2-3/8"work string t/4606'. 08/03/16-Wednesday Cont.in hole t/5084'&tag wall scale.Test lower Kelly valve 250 low/3500 high good.P/U swivel&install halls insert,wash down t/5140'@ 2.25 BPM, 1480 psi.Start running clean t/5199'.R/D swivel.RIH t/5349.Unload boat.Mix batch of brine to over balance tubing,pump 6 bbl weighted slug spot in tubing.Cont.RIH p/u singles t/7558',up wt.49k,dn.wt.43k.Engage TOF @ 7852'.P/U Swivel.Cont.RIH p/u singles washing down @ 1.60 BPM,750 psi. Tag top of fish at 7852'.Up wt.53K. Rev circ 2 BU w/10.3 ppg brine.Latch fish and work pipe to PU wt.92K and break free.Holding 5K additional wt.Mix 80 bbl 10.3 ppg brine.Rev.circ 1.5 BU w/10.3 ppg.POOH slowly standing back 2-3/8"work string stands in derrick.Work string U-tubing 10.0 ppg returns.Pump 18 bbl(10.3 ppg)to work string,U-tubing continues.Pump additional 11 bbl(10.3 ppg)slug,U-tube returns stop.L/D swivel.Cont.POOH slowly standing back 2-3/8"work string filling hole as needed w/10.3 ppg brine.Work String U-tubing returns.Weight up 22 bbl to 10.8 ppg.Pump 6 bbl slug 10.8 ppg to tubing and displace w/2 bbl 10.3 ppg.Cont.POOH slowly to BHA,standing back work string filling hole as needed w/10.3 ppg brine. 08/04/16`-Thursday Cont.POOH.L/d BHA,recover 5.25'of 2 3/81 tubing P/U BHA#7-4 1/8"overshot with upper extension dressed with 2 3/8"grapple, 3 1/8"bumper sub, 3 1/8"Bowen fishing jar,(6)DC3 1/8",1 accelerator jar,and X0=206.25.C/o tongs.RIH with stands 2 3/8"wk string,t/7837',tagged above fish unable to wk dn.P/U power swivel&r/u,unable to start,appears bad starter.Arrange deck to accommodate backup swivel that will be coming on boat, housekeeping&maintenance while waiting on arrival.Circulate hole w/10.4 ppg brine.Offload M/V Titan.Install power pack replacement starter.Power pack starts.Wash down to fish @ 7857',PU wt=52K.Latch fish and work pipe.Jar lick @ 70K.Continue to work pipe&break free @ 90K.Holding 52K. Rev circ 1.50 BU @ 1.50 bpm,650 psi.L/D 1 pup,1 single,1 pup&swivel.POOH slowly standing work string back in derrick,breakdown BHA recover 2 partial jts=19.4'. 08/05/16-Friday #m . P/U BHA#8-4 1/8"w/2 3/8"ID wavy btm shoe,xo bushing,4 1/8"overshot with upper&lower extension dressed with 2 3/8"grapple, 3 1/8"bumper sub,3 1/8"Bowen fishing jar,(6)DC3 1/8",1 accelerator jar,and X0=212.07.TIH t/7824',p/u 2 singles,tag at 7877',up wt 49k,dn wt 44k.Attempt to get over fish,unable.P/u swivel wash down over fish,unable to slack off over fish without rotating.P/u grapple slipping off @ 65k.CBU @ 2.5 BPM,1730 psi, I/d swivel.POOH standing back in derrick.BHA @ surface,breakdown BHA,recovered twisted-mangled section of pipe=5'.New TOF=7882'.M/U BHA#8 -4 1/8"w/2 3/8"ID wavy btm shoe,xo bushing,4 1/8"overshot with upper&lower extension dressed with 2 3/8"grapple, 3 1/8"bumper sub,3 1/8" Bowen fishing jar,(6)DC3 1/8",1 accelerator jar,and X0=212.07.TIH,25 stands in pump 3 bbl 10.8 ppg to tbg.Cont.TIH t/TOF=7882'.PU wt.=49K.PU swivel.Wash down over fish,PU pup&continue to wash down.Unable to latch&hold fish.Circulate 1-1/2 BU @ 2.10 BPM,1550 psi,r/d circ.line,prep t/POOH. • • Hilcorp Alaska, LLC Hi!carp Alaska,LLC Well Operations Summary Well Name Rig _ API Number Well Permit Number Start Date End Date MGS C31-26RD Moncla 404 50-733-20052-01-00 204-140 7/24/2016 8/13/2016 08/06/16-Saturday POOH. LID BHA recover 6'piece&some small pieces in upper extension.M/U BHA#9-4 1/8 Bladed concave junk mill,3 1/8 mud motor,Double pin xo, 2-junk baskets,double box xo,3 1/8"bumper sub,3 1/8"Bowen fishing jar,(6)DC3 1/8",and XO=219.58.R/u&surface test mud motor,good,2.4 bpm, 800 psi.TIH filling tubing every 2000',t/7862'.P/U swivel.RIH tag @ 7887', start milling operation,rot 20 rpm,pump 2.2 BPM,1800 psi,rot wt 45k. fvlilljng,ahead, rot_20rpm,pump 2.2 BPM,1800 psi,rot wt 45k,MD=7917'.PU and Circ BU X 2 @ 2.2 BPM,1750 psi.L/D swivel+1 jt. Start POOH standing work string back in derrick.Pulling wet.Pump 3 bbl 10.8 ppg brine to tubing.Cont.POOH t/6778'. �,�"7 . ti, 08/07/16-Sunday Cont.POOH w/milling assy.L/D BHA.P/U BHA#10-4 1/8"overshot with upper&lower extension dressed with 2 3/8"grapple,and a mill guide,3 1/8" bumper sub,3 1/8"Bowen fishing jar,(6)DC 3 1/8",1 accelerator jar,and XO,=208.40'.TIH t/7882'.P/U swivel,wash down to see top of fish @ 7917', set down over fish.P/u w/no over pull,wk a couple times.L/d swivel.POOH.Fishing BHA returns to surface empty.L/D fishing BHA.M/U BHA#11-341/8 Piranha mill,3 1/8 mud motor,Double pin xo,2-junk baskets,double box xo, 3 1/8"bumper sub,3 1/8"Bowen fishing jar,(6)DC3 1/8",and XO=220.88. R/u&surface test mud motor,good,2.4 bpm,800 psi.RIH filling tubing every 2000't/7895'.PU wt=50K.Had an H2S alarm,crew responded secured well,&went to muster area.The area for alarm was checked with hand held monitor&was clear.The gas head was still in alarm and would not reset.It was replaced w/a spare unit&bump tested good.Then resumed operations.PU swivel+1 jt.RIH tag @ 7922',start milling operation,rot 20 rpm,pump 2.1 BPM,1920 psi,rot wt 45k,mill t/7930'. 08/08/16 Monday Cont.Milling f/7930't/7960',rot 20 rpm,pump 2.2 BPM,1920 psi, 50-200 differential,rot wt 45k.Cont.Milling f/7960't/7966',rot 20 rpm,pump 2.9 BPM,3060 psi, 50-200 differential,rot wt 45k.MD=7966'.Mud pump engine overheats and shuts down.Add fluid to coolant system,replace 1/4-turn valve on manifold.Resume pumping and engine overheats again.L/D swivel+3 jts.POOH.Pulling wet,pump 4 bbl 10.6 ppg brines.Return to POOH,still pulling wet,pump additional 4 bbl lOppg brine,pulling dry.Cont.to POOH.BHA at surface.L/D BHA.Mill cored out.M/U 2 3/8"test jt,install w/test plug, shell test 250/3500 good. 08/09/16-Tuesday Finished with BOPE pretest.Tested all BOPE to 250#s low 3500#s high as per Sundry in accordance with AOGCC and Hilcorp requirements(annular tested to 250#s low 2500#s high). Performed successful accumulator drawdown test. Mr.Johnnie Hill/AOGCC witnessed and approved test.Pulled test plug and B/D test jt.Received directions to cease cleanout.R/I L/D(6)KOTs 3 1/8"DCs.M/U KOTs BHA#13(4 1/8"Piranha mill(rerun),3 3/4"casing scraper f/5" casing,3 1/8"x 1 1/4"DB sub,3 1/8"x 1 1/8" XO sub=8.93').TIH w/mill&scraper on 2 3/8"5.95#P-110 workstring to 7,685' (124 stands).P/U R/I nine singles of workstring and tagged fish at 7,966'.P/U 2'and M/U safety valve and Kelly hose.Circulated hole clean in reverse at 3 BPM 2600#s(across magnets and screens)-using 10.5#CaCl2.Total pump strokes=11,800(3-hole volumes)-screens&magnets clean. 4 bbls total fluid losses.Pumped 4 bbl 10.6 ppg brine to tubing.L/D 1 jt.POOH standing back 2-3/8"work string filling hole every 20 stands back.L/D KOTs mill&scraper-MJU HE$5"to packer(5"X 7.71'Test Packer,_2-3/8"X 2.87"X-over,TL=7.71').RIH t/7960'.Set packer.Test=1500,FAIL.PUH t/7929',1500 TEST FAIL.PUH t/ 609',/ TESTED TO 1500#S ON CHART F/30 MINS-GOOD TEST. C.iCk'' ‘1 i• (C X45° s5 l aiJA • • • Hilcorp Alaska, LLC Hileorp Alaska,LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MGS C31-26RD Moncla 404 50-733-20052-01-00 204-140 7/24/2016 8/13/2016 08/10/16 Wednesday Finished testing 5"casing with Halb RTTS tool-leak located between 7,889-7,919'. Charted 30 min 1500#s at 7889'(solid st).Would not test at 7,919'. POOH w/Halb RTTS tool laying down 2 3/8"PH-6 workstring.Filled hole every 20 jts.B/D test tool. R/I B/D one stand of workstring from derrick.Offload M/V Titan.Spotted&R/U E-Line unit on drill deck.M/U Packer w/anchor latch assy:5"Model D Permanent Packer(1.41'),2.688"Concentric Pkr Bottom (0.53'), 2.688"Seal Bore Ext(4.48'),Tbg Adapter w/2-3/8"EUE Box(0.59'), Pup jt(9.63'), X landing nipple(1.19'),Pup jt(10.03'), WLEG(0.52') =28.38' TL. ELU P/U GR/CCL,#10 Setting Tool&Packer Assy.GR/CCL to top of Packer=11.7'.RIH t/7860' (WLM). Log up to 7448'to correlate depth,correct depth+1.0'.RIH t/7872'.Logged up to place packer on depth=7838.3'CCL+11.7'=7850'Top of Packer(EOT @ 7,878').POOH. R/D ELU.Spot Control Line spooler on drill deck.P/U 1st bundle of 2-3/8"production tubing,chem mandrel&GLM#1 in V door.M/U Anchor latch/pup joint.RIH per 2-3/8" tubing completion procedures/schematic.Control line clamps at each end of mandrel&every other jt,3 bands per mandrel&1 band per each jt w/o clamp-torqueing tb to 1800 FPT. 74 jts of prod string+mandrel assy=2,442'in hole at report time. 08/11/16-Thursday Continued RIH w/production string from 2,442' as per designed tb detail.At 109 jts in hole(3,570'),1/4"control line stainless steel metal banding was scraped off while going thru top of annular.Stopped TIH and conferred w/Tripoint,Pollard and Engineer-decision was made to continue in hole,land seal assy partially then make gauge run w/S/L prior to setting RHCP plug in nipple below pkr. Moncla pusher&crew determined plan forward to prevent reoccurrence.Continued RIH w/production string as directed.1545 hrs M/U SSSV @ 321'(PM)(EOT @ 7,558'(PM).Tested same to 4000#s f/30 mins- (valve opens at 1650#s).RIH to tag top of packer assy lightly circulating down tubing 1.0 BPM,110 psi,taking returns at mud tank(P/U 42k S/O 35k).Tag top of packer w/jt 240,lose returns at mud tank&pump pressure=600 psi,stop pump.Mark jt 240.PUH,2.3'of 1T.240 in hole to tag top of packer. L/D jt 239&240.M/U hanger head.Inject 89 bbl 10.5 ppg CaCl2 brine to Well C44-14RD,1.60 bpm,880 psi.Spot SLU on pipe deck.RU SLU.M/U SL BHA w/ 1.75"Blind Box.RIH w/1.75"Blind Box t/7862'SLM,set down.Work tools,fall thru to 7909'SLM.PUH to 7800'.RIH to 7909'SLM clean.POOH.L/D 1.75" Blind Box.M/U X-line running tool& 1.75" RHCP plug.RIH w/plug set in selective position t/7862'SLM,locate X profile.Work tools to set plug,fall thru profile 2 times.POOH to inspect plug and X-line running tool.SLU return to surface w/plug on running tool.SLU change out X-line running tool.RIH w/ 1.75"X-plug to 7862'SLM,set plug in X-profile.Work tools,shear off.POOH SLU returns to surface w/X-plug in running tool,FAILED RUN. • Hilcorp Alaska, LLC HiileorpAlaska,LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MGS C31-26RD Moncla 404 50-733-20052-01-00 204-140 7/24/2016 8/13/2016 08/12/16-Friday Pollard S/L operator accessed condition of running tool and found it to be good.Conclude there to be debris in profile of X-nipple at 7,862'preventing dogs from engaging fully. B/O running tool and plug.M/U S/L Run#5(1 1/2"rope socket,11'of 1 1/2"stem,1 1/2"knuckle,1 1/2"oil&spang jars, paraffin scratcher).TIH to 7,862'and made multiple pass thru X-nipple in efforts to clear debris. POOH-recovered brown Teflon type wrapping material/tape from scratcher.B/0 scratcher.M/U S/L Run#6(same tool string w/X-line running tool&1.75"RHCP plug)-TIH and passed thru EOT-P/U and engaged X-nipple,jarred down to shear 1st set of pins,jarred up to release from plug.POOH(w/o plug)and 13/0 X-Line running tool.M/U S/L Run#7 (same tool string w/SB running tool&prong).TIH and land prong in plug-jarred down and released prong in place,POOH.R/D S/L.M/U Kelly hose then P/U on tb string to pull seals from sealbore.Took 5k over to pull out(47K).Pumped 200 bbls FIW LW flushing CaCl2 from wellbore into injection well C 44- 14RD at 2 BPM 1050 TP(beginning)1400 TP(ending)-zero pressure on casings. RID Kelly hose.Drained stack and landed 6'seals fully-3k weight down when hanger landed.Lined up to pressure up down annulus to 1500#s,reading pressure also on tb side. Held 1500#test on chart for 30 mins-bleed off pressure slowly on tb side.Lined up to pressure up down tb.to 1500#.Testing on chart.Small pressure bleed off over 30 mins—150 psi loss.Bleed tbg to 0 psi.Pressure up tbg to 1500#testingon chart_Pressure up annulus to 150#observing w/gauge. Small tbg pressure bleed off over 30 mins—150 psi w/ ZERO pressure gain on annulus,annulus=150 psi.Bleed off casing pressure and then tbg pressure.M/U SLU Run#7(1 1/2"rope socket,11'of 1 1/2" stem,1 1/2"knuckle,1 1/2"oil&spang jars,1-1/4"JD OS) to pull prong. RIH t/7862,work tools,unable to latch prong,POOH.MISSED RUN. R/D koomey lines and remote panel while pumping away 76 bbls of FIW from active tank into clean tank.M/U SLU Run#8 (1 1/2"rope socket,11'of 1 1/2" stem,1 1/2"knuckle,1 1/2"oil&spang jars,1-1/4"JU OS) to pull prong. RIH t/7862,work tools,latch prong,POOH w/prong. R/D Swaco unit,M/U SLU Run#9 (1 1/2"rope socket,11'of 1 1/2"stem,1 1/2"knuckle,1 1/2"oil&spang jars,1-1/4"GS spear) to pull plug. RIH t/7862,work tools,unable to latch plug,POOH. MISSED RUN. Cleaned sand trap in active tank.M/U SLU Run#10 (1 1/2"rope socket,11'of 1 1/2"stem,1 1/2"knuckle,1 1/2"oil& spang jars,1-1/4"Pump Bailer). RIH t/7862,work tools,POOH w/1/4 cup of thick,gritty sludge in bailer. Rolled up air hoses and R/D choke house.M/U SLU Run#11 (1 1/2"rope socket,11'of 1 1/2"stem,1 1/2"knuckle,1 1/2"oil&spang jars,1-1/4"GU spear) to pull plug. RIH t/7862,work tools,POOH w/plug.Monitor tbg press,120#build in 30 mins.Close SSSV,monitor tbg press,ZERO build up in 15 mins.R/D SLU,B/0 landing jt.Set BPV.Cleared rig floor,removed beaver slide and floor supports. 08/13/16 Saturday Unpin and remove rig floor-detach all guy lines-scope down/laid derrick in carrier.N/D BOPE. Began dismantling all workover components and electrical.NOS rep prepped hanger and flange to receive tree. Rig crew began washing/steaming equipment as it was broken down(prior to being loaded on boat). N/U tree and tested void to 500#s f/5 mins,5000#s f/15 mins. Pulled BPV and installed 2-way check.Loaded M/V Titon w/all BOPE components.Shell tested tree to 3800#s f/15 mins-released pressure and pulled 2-way check-opened SSSV to 150#s tb pressure-turned well over to production at 1400 hrs. • OFT,I • • e,`'\1///,/ iv?. THE STATE Alaska Oil and Gas ' ce ofALAsKA Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER _.--..,w. Anchorage, Alaska 99501-3572 wti , �-..' Main: 907.279.1433 OFA "e'P' Fax: 907.276.7542 www.aogcc.alaska.gov Stan W. Golis Operations Manager ; t� ' Hilcorp Alaska, LLC ,Ckt* 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Middle Ground Shoal Field, E,F, and G Oil Pools, MGS C31-26RD Permit to Drill Number: 204-140 Sundry Number: 316-418 Dear Mr. Golis: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. oerster Chair DATED this 11 day of August, 2016. RBDMS LI- AUG 1 5 2016 • • , `QED STATE OF ALASKA • 10 ALASKA OIL AND GAS CONSERVATION COMMISSION AUGg2u1r APPLICATION FOR SUNDRY APPROVALS �; /620 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations El Fracture Stimulate ❑ Repair Well ❑ Operations shutdown Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program 0 Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC • Exploratory ❑ Development 0 ' 204-140 ' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic CIService ❑ 6.API Number. Anchorage,AK 99503 50-733-20052-01-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No 0 MGS C31-26RD 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018756 . Middle Ground Shoal/E,F and G Oil Pools • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 10,093 . 9,661 • 10,048 ' 9,617 . 3,257 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,895' 10-3/4" 1,895' 1,894' 3,130 psi 1,580 psi Intermediate 7,091' 7" 7,291' 7,133' 6,340 psi 3,830 psi Production 10,093' 5" 10,093' 9,661' 13,940 psi 13.450 psi Liner • Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 9,729-9,981 4 9,305-9,551 2-3/8" 4.7/L-80 9,630 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): Baker 5"FH Ret.Packer and Baker T5 SSSV " 9,584'(MD)9,163'(ND)&301'(MD)301'(TVD) 12.Attachments: Proposal Summary 0 Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory El Stratigraphic❑ Development 0 Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: In progress under Sundry#316-315 OIL 0 . WINJ ❑ WD6PL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: V.A,Q„AA e lttI ib GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Trudi Hallett(907)777-8323 Email thallettOhilcorp.com Printed Name Stan W.Golis Title Operations Manager Signature 317 et; Phone (907)777-8356 Date Site) ! IL COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. _/ 3\1.x— Li« Plug Integrity El BOP Test�IQ Mechanical Integrity Test ❑ Location Clearance CIOther: Ice-0 t, ic� TE 'i-c ,F fir)t Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No i Subsequent Form Required: ,O -- 404 RBDMS IA, AviA 15 2016 APPROVED BY Approved by: 2-L41 — COMMISSIONER THE COMMISSION Date: f-/I—/ ' f lallS- M3-u.° 0. i #elo GIN I _^ t Submit ane Form 10-403 Revised 11/2015031;4 I a d for 12 months from e�dats of approval. Attachments in Duplicate • • • Well Prognosis Well: C-31-26RD Ilileorp Alaska,LL Date:08/10/2016 Well Name: C-31-26rd API Number: 50-733-200052-01 Current Status: S/I Oil producer(gas-lift) Leg: Leg#1 Estimated Start Date: 07/01/16 Rig: HAK-C Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 204-140 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Trudi Hallett (907) 777-8323 (0) (907) 301-6657 (M) Current Bottom Hole Pressure: 3,600 psi @ 8,000'TVD 0.450 lbs/ft(8.66 ppg) Maximum Expected BHP: 3,600 psi @ 8,000'TVD 0.450 lbs/ft(8.66 ppg) Maximum Potential Surface Pressure:3,257 psi Using 0.1 psi/ft gradient 20 MC 25.280(b)(4) Brief Well Summary The C31-26rd well is currently completed with a 2-3/8" gas-lift completion installed 10-19-2004.The tubing parted in 2006 at 4,358' right below GLM #3.This workover will restore tubing integrity •- • .. - tib 8/10/2016 UPDATE STATUS: Unable to retrieve all of the tbg from the well leaving the TOF @ 7,966'. Hilcorp plans to test casing to establish integrity and run gas lift completion above the remaining tbg and existing packer. (Current and proposed schematic attached) —)t � ler)S � psi ��r�h� ,e5 c - PctC1L z MSC? Brief Procedure: C't �a 'I 1. MIRU Rig. 3. Notify AOGCC 48 hours before pending BOPE test. Set BPV, ND tree, NU BOPE.Tcst all BOP equipment per AOGCC guidelines to 250psi low and 5,000psi high. 1. Monitor well to ensure it is static. 5. Unseat hanger and POOH with upper completion. z. . - • . - . ... _ 7. RIH w/mill/scraper BHA and Cleanout to +/-7,966' (TOF). POOH. 8. PU retrievable test packer and RIH to +1-7,890'. Set packer, test casing to '1,500 psi and chart for 30 minutes. POOH. 9. Run gas-lift completion setting packer @ +/-7,890'. 10. Test IA to 1,500 psi and chart for 30 min. ✓- 11. Set BPV. ND BOP. NU tree,test same. 12. Turn well over to production. 13. Conduct SVS tests per AOGCC regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Current/ Proposed 4. BOP drawing 5. Fluid Flow Diagram 6. RWO Sundry Revision Change Form Middle Ground Shoal SCHEMATIC • Well:MGS C31-26RD • tir . Last Completed: 10/19/2004 As of 8/10/16 PTD:204-140 i►a� r,�,tI:��k.�.IAA: API:50-733-20052-01-00 KB:35' CASING DETAIL Size Wt Grade Conn ID Top Btm 24" Conductor 18.750 Surf 400' 10-3/4" 40.5 155 ASL 10.050 Surf 1,895' 7" 23 N-80 BTC 6.366 200' 5,600' 7" 26 N-80 BTC 6.151 5,600' 7,291' KOP 10-3/4" 5" 18 P-110 STL 4.276 Surf 634' 5" 18 P-110 Ultra FJ 4.276 634' 10,093' TUBING DETAIL 2-3/8" 4.7 L-80 8rd EUE 1.995 Surf 9,630' 2 3/8" 5.95 P110 PH-6 1.805 surf SgzHole in7" JEWELRY DETAIL @3,440-3,471 ' No Depth Depth ID OD Item (MD) (TVD) `MIII. III ..87 ' Iii ' Milled up A 8,477' 8,137' 1.995 3.975 GLM 10 8 9,053' 8,655' 1.995 3.975 GLM 11 7" 1 6- C 9,535' 9,115' 1.995 3.975 GLM 12(Orifice) D 9,576' 9,153' 1.875 2.750 X Nipple E 9,584' 9,163' 1.978 4.125 Baker FH Retrievable Packer 43B#781-08-1247 a ® F 9,597' 9,175' 1.875 2.750 X Nipple G 9,630' 9,208' 2.000 4.030 WLREG Fish top@ ® POOH 1/d hanger, assorted pups 3-GLM, SSSV, KN nipple 136'ts =4302.49 7966' b g 1� 1> 1111 J BHA#1 Recover 25.30' c 0 BHA#2 Recover 35.76' BHA#3 Recover 62.15' d x BHA#4 Recover 18 jts 566.67 TOF 5043' + 689.88 e in fta BHA#5 run 1 no Recovery, possible damage to grapple rotating on fish, c/o t/2 1A" grapple. f x A. BHA#5 run 2 Recover 2809.68' parted jt 17.82' TOF 7852' 1734' est to fish s BHA#6 Recover 5.25' 7857' BHA#7 Recover 19.4' 7877' , BHA#8 Recover 4',twisted in 3 piece, had hard time getting on fish 7881 .•''', BHA#9 Recover 6' & 3' in pieces 7887' BHA#10 Mill &mud mtr. Mill t/7917' BHA#11 overshot no recovery T BHA#12 Mill &mud mtr tagged @ 7922'milled to 7966' mill cored out PBTD=10,048' TD=10,093' Middle Ground Shoal PROPOSED 110 Well: MGSC31 26RD n 4111Last Completed: Future PTD:204-140 J[ilcurp Alaska,LLC API:50-733-20052-01-00 KB:35' CASING DETAIL Size Wt Grade Conn ID Top Btm 1 r 24" Conductor 18.750 Surf 400' 10-3/4" 40.5 1-55 ASL 10.050 Surf 1,895' la', 7" 23 N-80 BTC 6.366 200' 5,600' 7" 26 N-80 BTC 6.151 5,600' 7,291' 4 KOP 10-3/4" is"; 5" 18 P-110 STL 4.276 Surf 634' V 5" 18 P-110 Ultra FJ 4.276 634' 10,093' TUBING DETAIL 2-3/8" 4.7# L-80 8rnd EUE 1.995 Surf ±7,920' 2-3/8" 4.7# L-80 8rd EUE 1.995 7,966' 9,630' Sqz Hole in Y' + @3,aaa3,471 0 JEWELRY DETAIL Depth Depth No (MD) (ND) ID Item 1 ±300' ±301' 1.875" SSSV 2 ±1,851' ±1,850' 1.995" GLM 1 1 3 ±3,252' ±3,250' 1.995" GLM 2 4 ±4,271' ±4,250' 1.995" GLM 3 2-11 5 ±4,949' ±4,900' 1.995" GLM 4 1 6 ±5,467' ±5,400' 1.995" GLM 5 7 ±5,989' ±5,900' 1.995" GLM 6 8 ±6,514' ±6,400' 1.995" GLM 7 9 ±7,045' ±6,900' 1.995" GLM 8 10 ±7,587' ±7,400' 1.995" GLM 9 11 ±7,860' ±7,645' 1.995" GLM 10(Orifice) A 12 ±7,890' ±7,670' 2.668" Packer w/anchor latch assembly and seal .14 bore extension 4 13 ±7,915' ±7,690' 1.875" X Nipple 6' 14 ±7,920' ±7,694' 1.995" WLREG ® k A 8,477' 8,137' 1.995 GLM 10 12 + r B 9,053' 8,655' 1.995 GLM 11 13 '1 C 9,535' 9,115' 1.995 GLM 12(Orifice) D 9,576' 9,153' 1.875 X Nipple 14 9,163' 1.978 Baker FH Retrievable Packer 43B#781-08- 4, E 9,584' 1247 e F 9,597' 9,175' 1.875 X Nipple Top of ► i G 9,630' 9,208' 2.000 WLREG Tubing a @7,966' "a ' b ,t c , PERFORATION DETAIL d Ur i Zone Top(MD) Btm(MD) Top(ND) Btm(ND) FT Date Status e H2 9,729' 9,741' 9,305' 9,317' 12' Open fii .' H2 9,740' 9,790' 9,316' 9,365' 50' Open 7" g H2 9,791' 9,819' 9,366' 9,393' 28' Open •-.1- H2-H3 9,846' 9,886' 9,419' 9,458' 40' Open H2-H3 9,890' 9,940' 9,462' 9,511' 50' Open T =r H2-H3 9,941' 9,947' 9,512' 9,518' 6' Open H2-H3 9,963' 9,981' 9,534' 9,551' 18' Open s" PBTD=10,048' TD=10,093' Updated By:JLL 08/10/16 • • •• ,. liiPlatform C 31-26RD 05/31/2016 IIilrorp 11.1.1.4,IAA. Platform C Tubing hanger,Cactus-CXS, 31-26RD 24x10%x7x5x23/8 7"x27/8RTS-6 lift and susp, w/2%type H BPV profile, 7"casing is not tied into the 6.250"extended neck,1-'''A wellhead,cut off 200'below non continuous control line port BHTA,CIW,External knock-up,2 9/16 5M FE t7:n ret I F 34 O• O CSG y� �' o Valve,Swab,WKM-M, L 0 (�' � .� 0114°' 2 9/16 SM FE,HWO,DD trim �� lU' Ja49 ,��h�� c�°�k,;' ��ti fie: h3 Ci nrn MI nil ��'L J�,,,l. Valve,Master,WKM-M, K•J OO 2 9/16 5M FE,HWO,DD trim N 1.1'.1 lull.. Tubing head,Cactus C, _. I , "_�I 7 115M x71/165M,w/2- 11111.1111.811.1r _ ' 2 1/16 5M SSO,w/NX ' i n bottom Valve,WKM-M,2 1/16 5M, lir . 111Ipir 1111, i 1_13 HWO l'44-1 ( I , - .03.4 . . • �� er, A.: \i i Casing head,CIW-WF,11"SM FE top x 11"3M liii �'ii Cameron clamp flat face Valve,CIW-F,2 1/16 5M, bottom,w/2-2 1/16 5M SSO HWO Ely r IM M Landing hub,CIW,11 3M Cameron Clamp flat m, x 10 X.casing threadbottom, bottom, LH acme lift Conductor housing,24"ASA ' � � , 150#RFx24' SOW I' 'I Id 24" 10 Y" 5" 2 3/8" OP Stack(Moncla) H lrarp al4,.LIt.I,•.I; • itl 111111 111 111 111 111 111 I 3.74' Shaffer 135/85M lil lit Illlil Ill 111111 IU 111 ioCIW-U �� Variable 27/8-5 4.67' 13 55//88--5000 =moll I - .... , *.,iw _ _ wmc Blind Rams ill I11.IiIi&I iIi E Choke and Kill Valves 2 1/16 5M w/Unibolt connections for / 116911'1111.1111.1 I hoses 2.00' . 5, 13 5/8 -5000 _ 1[01 Cl: i i I.111.111r1i1.111 . I ° 11111/1/11 111 111 111 111 I I Riser,13 5/8 5M FE X 13 5/8 SM API#13 hub 13.70' • . ?00000 0000 O U O V O V U O D U O o _1 65 5dUI m 5 N T V 5 1' 5 5 0 UUUUUUUUU UO .-I N T O N 01 r-I N T a N 10 I. 00 01 N O O O O O t 0 0 0 0 0 0 0 0 0 0 0) OJ O U N 'C �C C C C C C C c C j a a a a a W 01 1 01 g g g g g g 1 g g g U A g> ma. .. .. .. c c > 01 01 0 01 01 01 01 01 01 0.1 01 ] Y E E E E E -� o 0 0 0 0 0 0 0 0 0 o n � w aaaaa ie- i'e = u uuvuvuuuvuv, 2 In Oiii.v v m O 'w Y .• OC C iAlN al IT U 2 1 p 11 11 CS1 0)0 r CO u I (0 0 aJ 1-1...-I /-$� a W 0 M Z O COU �re WI 2U � K O h O A> J rT . 0 => L, m' j III III I.. 11 = lp d Y T— d (_) 'm O Q mI— U) wHa a ❑ z z 0 ° ~ Z ajw Z CO ❑ CL J U) J D • i H II a A Z 0O_ O H C ❑ Ill UD Q 0Q > U — J J > W ULLQOv) o ❑ g ❑ rI 2DOw r JOzw In � H tLZ � � m Z Q = H J ❑ J U CC 0 a e• O U O u 0 O O U O • ./ O u 0 u 0 u u 0 u U O ';--1- o rl N CO O LOrt N (V a Ill b n OD ca• a a a a M J U u u u u u u u u o rl N en O Vl W r1 N CO V VI lD N CO CO rl -o0 U -o V 'O V 'O '0 '0 '0 'O 0 'O N 0 0 0 0 0 L 0000000000 c c c c c L1y c c c c c c c c c c t O j 10 10 A IO 'y N N c N N N N t0 A O U N n n n a o. c c j" m d a, 00 u v w w y w .,L' E EEEE 0 0 U 0 0 0 0 0 0 0 0 0 0 o n c 0 D 0 a a 0 Y Y 2 u u u u u u u u u u u 0 f N v c IS U a w O vl f r1 11 4k co mk In - (o U r a 1 ►'' 1 Q J Q WY 0 P) 20 r1 4U X I< 0 IXO I LL aw EI\y w SU Y llil T m „' OQ mH V) w H O. zIllH u) Cl) Q J D z Z g Z ~ w Q a ❑ z Z — l z- Q o O U Q Q � E w , o ,- <1 0 O m O 4 � JDJ 2021 74 � Lij C JOO rO u) aN Li- Za ._ Om z 0H Z ❑ Ilr ❑ 1 N LL D U Ct 0 • • Moncla Rig 404 BOP Test Procedure Attachment#1 FliIcor') Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Moncla Rig 404, WO Program — Oil Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. • Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Shoot fluid level at least 24 hours before moving on well. 4) Shoot fluid level again, right before ND/NU. Confirm that well is static. Initial Test(i.e.Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2-way check in hanger. 3) Space out test joint so end of tubing(EOT)is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.Profile and/or landing threads must be prepped while tree is off.Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful,shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV.As approved in the sundry, proceed as follows: a) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2-way valve,or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale,attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand,or MU landing(test)joint to lift-threads d) For ESP wells-Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and/or a penetrator leaks, notify Operations Engineer(Hilcorp), Mr.Guy Schwartz(AOGCC)and Mr.Jim Regg(AOGCC)via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE b) With stack out of the test path,test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump,(monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed,test the remainder of the system following the normal test procedure(floor valves,gas detqction,etc.) • . • Moncla Rig 404 BOP Test Procedure Hilrorp Alaska,i,i.c Attachment#1 f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile/ penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger(or test plug)in tubing head. Test BOPE per standard procedure. Subsequent Tests(i.e.Test Plug can be set in the Tubing-head) 1) Remove wear bushing. a) Use inverted test plug to pull wear busing. MU to joint of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same-RIH with test plug on joint of tubing. Install a pump-in sub w/test line plus an open TIW or lower Kelly valve in top of test joint w/open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE(after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump-install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 2) Note: When testing, pressure up with pump to desired pressure,close valve on pump manifold to trap pressure and read same with chart recorder(test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 15c valve on standpipe manifold,close valves 1, 2, 10 on choke manifold and close the annular preventer,open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and 2,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer,close safety valve and open IBOP on test joint,close outside valve on kill side of mud cross,open 15t valve of standpipe, close valves 3,4&9 on choke manifold,open valves 1&2 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. c) Test Dual Rams. If the well has dual tubing,and dual rams are installed in the stack,test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close inside valve/open outside valve on kill side of mud cross,close valves 5&6/open valves 3&4 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. e) Close manual and super choke/open valves 5&6 on choke manifold. Pressure up to 1200 psi and bleed off 200—300#s recording change and stabilization. If passes after 5 minutes, bleed of pressure back to tank. f) Close HCR(outside valve on choke side of mud cross),open manual&super choke. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. • Moncla Rig 404 BOP Test Procedure �.�.c Attachment#1 Hilcarp Alaska, g) Close inside valve/open outside valve(HCR)on choke side of mud cross. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Ensure all pressure is bled off-open pipe rams and pull test joint leaving test plug/2-way check in place. Close blind rams and attach test line to valve 10 on choke manifold,close valve 7&8/open valve 10 on choke manifold. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) Test additional floor valves(TIW or Lower Kelly Valve)and IBOPs as necessary. STANDARD TEST PROCEDURE OF CLOSING UNIT(ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record "Accumulator Pressure". It should be+/-3,000 psi. 3) Close Annular Preventer,the Pipe Rams,and HCR. Close 2nd set of pipe rams if installed (e.g.dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read "10 bottles at 2,150 psi"). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually+/-30 seconds. 8) Once 200 psi pressure build is reached,turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure(+/-3,000 psi). Note: Make sure the electric pump is turned to"Auto", not"Manual"so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP,FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves,for correct operating position 3) Fill out the AOGCC BOPE Test Form(10-424)in Excel Format and e-mail to AOGCC and Juanita Lovett. Document both the rolling test and the follow up tests. • 0 c2CD � � a a) c 0 £ kJ2 Q _ ■ ¥ a ■ § 2 E W o E / \ 2 k •§ f « E ® o c 2 _ f § i 0 m.c a » < .- 7 / 2 0) - a 5 k = I • \f 0 ƒ / % / n -0 ■ ■ 2 — ' R 0 k co % t �>- N O CZJ 03 w I- 0 � 0 B 2 77 CD CD co / ,- C.) 0kg k k2u. gf c »e QU — c0 0 \ -00 P. C < E § ° 2 O k ƒ : a o a 16. _ / a) S la \ / & c �f - -a § p c L t 2 0 2 1 L 2 § � ■ % o 0 0. E a ■ QC CF « / \ 00. . / 2 % � § 0 o 2 ■ q Q $ q 1- - § x m = g Q § CO .§ @ 0- 2 S % £ 2 it o 0 .. ii E . . ° 0 -o k ¢ 0 -0 E0 2al o v a_ 2 k k 0 2 • i cS C_ SI-2-6,e± ze4i4-00 Regg, James B (DOA) From: Harold Soule - (C) <hsoule@hilcorp.com> Sent: Monday, August 08, 2016 11:26 AM K4'c To: Regg, James B (DOA) r( Cc: Juanita Lovett;Trudi Hallett Subject: Failure of H2s gas head Mr. Regg At approx. 2:00 am this morning we had an H2S alarm, crew responded secured well, &went to muster area, the area for alarm was checked with hand held monitor&was clear, the gas head was still in alarm and would not reset, it was replaced with spare unit, & bump tested good.Then resumed well work operations. Date: 8-8-2016 Hilcorp Alaska Well number C31-26RD, MGS "C" Platform, PTD 2041400, Sundry#316-315 Moncla 404 Engineers: Dan Marlow/Trudi Hallett Harold Soule 907-776-6754 Cell 227-9400 SCANNED JAN I 12017 • ti OF 7•4 • 4w\�\�/7:cs. THE STATE Alaska Oil and Gas '►-�'�.s �, ofALAsKA Conservation Commission ____ ! 333 West Seventh Avenue �*ti GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 ,;,_ Q, Main: 907.279.1433 ALAS Fax: 907.276.7542 SCANNED ti fi� i� �� www.aogcc.alaska.gov c Stan W. Golis Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 Re: Middle Ground Shoal Field, E, F, and G Oil Pools,MGS C31-26RD Permit to Drill Number: 204-140 Sundry Number: 316-398 Dear Mr. Golis: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, ii Cathy P oerster Chair /' 4±DATED this `-f- day of August, 2016. RBDMS +," AUG 1 1 2016 • • • RECEIVED STATE OF ALASKA JUL 2 8 201b ALASKA OIL AND GAS CONSERVATION COMMISSION DTS /'T /.6 APPLICATION APPLICATION FOR SUNDRY APPROVALS A 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate Cl Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate 0 • Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill 0 Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Dill Number. Hilcorp Alaska,LLC • Exploratory ❑ Development 0 204-140 3.Address: 3800 Centerpoint Drive,Suite 1400Stratigraphic ❑ Service 0 6.API Number. Anchorage,AK 99503 50-733-20052-01-00 • 7.If perforating: 8.WeN Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 44 Will planned perforations require a spacing exception? Yes ❑ No 0 / MGS C31-26RD • 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018756 - Middle Ground Shoal/E,F and G Oil Pools 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth ND: MPSP(psi): Plugs(MD): Junk(MD): 10,093 . 9,661 • 10,048 - ., 9,617 3,257 psi NA N/A Casing Length Size MD TVD Burst Cofapse Structural Conductor Surface 1,895' 10-3/4" 1,895' 1,894' 3,130 psi 1,580 psi Intermediate 7,091' 7" 7,291' 7,133' 6,340 psi 3,830 psi Production 10,093' 5" 10,093' 9,661' 13,940 psi 13,450 psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 9,729-9,981 , 9,305-9,551 2-3/8" 4.7/L-80 9,630 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(It): Baker 5"FH Ret.Packer and Baker 15 SSSV - 9,584'(MD)9,163'(ND)&301'(MD)301'(TVD) 12.Attachments: Proposal Summary 0 Wellbore schematic 9 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development 0 - Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 8/15/2016 OIL 0 , WINJ Cl WDSPL ❑ Suspended El 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Dan Marlowe(907)283-1329 Email dmarlowe.hilco . com Printed Name G�kStan W.Golis 0 Title Operations Manager Signature •-r ��( .(4.' Phone (907)777-8356 Date 7// 2 ( I to COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ' - D°1)1. Plug Integrity 0 BOP Test❑ Mechanical Integrity Test El Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ tl� Spacing Exception Required? Yes ❑ No /G Subsequent Form Required: "`�01 1 Cl1)eizAPPROVED BY �/ Approved by: /°. .,€..4,14,-...._... COMMISSIONER THE COMMISSION Date: g - .7 -/_ Q 1 ails Submit Form ane Form 10-403 Revised 11/2015 Approved application Is I' 1 r�r th th hie of approval. Attachments in Duplicate RBDMS L`— AUG 1 1 2616 • • • Well Prognosis Well: C31-26RD HilcorU Alaska,LL Date:07/25/2016 Well Name: C31-26rd API Number: 50-733-200052-01 Current Status: Oil producer(gas-lift) Leg: Leg#1 Estimated Start Date: 08/15/2016 Rig: N/A Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 204-140 First Call Engineer: Dan Marlowe (907)283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Trudi Hallett (907) 777-8323 (0) (907)301-6657 (M) Current Bottom Hole Pressure: 3,600 psi @ 8,000'TVD 0.450 lbs/ft(8.66 ppg) Maximum Expected BHP: 3,600 psi @ 8,000'TVD 0.450 lbs/ft(8.66 ppg) Maximum Potential Surface Pressure:3,257 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Shut In Tubing Pressure: 945 psi Brief Well Summary This project will conduct thru-tubing perforating in the C31-26rd.We are currently changing out the parted tubing and performing a cleanout under Sundry 316-315/This job will add perforations in the Hemlock Bench 1 and the F sands. E-line Procedure: 1. MIRU E-line, PT lubricator to 3,500 psi Hi 250 Low. 2. RU e-line guns and perforate F Sands with well flowing per program. 3. RD E-line. 4. Turn well over to production to flow test. 5. MIRU E-line, PT lubricator to 3,500 psi Hi 250 Low. 6. RU e-line guns and perforate Hemlock Bench 1 Sands with well flowing per program. 7. RD E-line. 8. Turn well over to production to flow test. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed • Middle Ground Shoal n 1110 Well: MGS C31-26RD SCHEMATIC Last Completed: 10/19/2004 PTD:204-140 API:50-733-20052-01-00 tlilcarp Alaska,LLC KB:35' CASING DETAIL Size Wt Grade Conn ID Top Btm b . 24" Conductor 18.750 Surf 400' 10-3/4" 40.5 1-55 ASL 10.050 Surf 1,895' 7" 23 N-80 BTC BTC 6.366 6.151 200' 5,600' 7" 26 N-80 5,600 7'291 KOP 10-3/4" 5" 18 P-110 STL 4.276 Surf 634' 5" 18 P-110 Ultra FJ 4.276 634' 10,093' 0 TUBING DETAIL 2-3/8" 4.7 L-80 8rd EUE 1.995 Surf 9,630' Note: 7"casing cut off a total of 250'below RT 09/27/2004 Sqz Hole in 7" @3,440-3,471 JEWELRY DETAIL Parted Tbg * No Depth Depth @4,358' � � (MD) (TVD) ID OD Item 33.20 33.20 2.485 7.062 Cameron'N'FBB(extended neck)RTS6 top,8rnd bottom 1 301' 301' 1.875 3.630 Baker T5 SSSV 2 1,905' 1,904' 1.995 3.975 GLM 1 • 3 3,228' 3,226' 1.995 3.975 GLM 2 4 4,337' 4,315' 1.995 3.975 GLM 3 5 5,256' 5,198' 1.995 3.975 GLM 4 6 5,990' 5,901' 1.995 3.975 GLM 5 }I 7 6,475' 6,363' 1.995 3.975 GLM 6 8 6,929' 6,790' 1.995 3.975 GLM 7 b) 9 7,414' 7,248' 1.995 3.975 GLM 8 10 7,931' 7,702' 1.995 3.975 GLM 9 11 8,477' 8,137' 1.995 3.975 GLM 10 7' 12 9,053' 8,655' 1.995 3.975 GLM 11 �j 13 9,535' 9,115' 1.995 3.975 GLM 12(Orifice) 14 9,576' 9,153' 1.875 2.750 X Nipple S 15 9,584' 9,163' 1.978 4.125 Baker FH Retrievable Packer 43B#781-08-1247 `' 16 9,597' 9,175' 1.875 2.750 X Nipple '' 17 9,630' 9,208' 2.000 4.030 WLREG °a PERFORATION DETAIL x lx Zone Top(MD) Btm(MD) Top(ND) Btm(ND) FT Date Status ., H2 9,729' 9,741' 9,305' 9,317' 12' 10/18/2004 Open 0, H2 9,740' 9,790' 9,316' 9,365' 50' 10/14/2004 Open(Frac'd) H2 9,791' 9,819' 9,366' 9,393' 28' 10/18/2004 Open x H2-H3 9,846' 9,886' 9,419' 9,458' 40' 10/18/2004 Open L-'_ ,i H2-H3 9,890' 9,940' 9,462' 9,511' 50' 10/07/2004 Open(Frac'd) H2-H3 9,941' 9,947' 9,512' 9,518' 6' 10/18/2004 Open +t' , H2-H3 9,963' 9,981' 9,534' 9,551' 18' 10/18/2004 Open jf t' �'- 4- -= k ' Notes PBTD=10,048' TD=10,093' Updated By:JLL 05/18/16 Middle Ground Shoal PROPOSED Well: MGS C31-26RD . ti Last Completed: Future Option B-Revised PTD:204-140 xacaru Alaska,LLC API:50-733-20052-01-00 KB:35' CASING DETAIL ei Size Wt Grade Conn ID Top Btm 1 24" Conductor 18.750 Surf 400' r. 10-3/4" 40.5 1-55 ASL 10.050 Surf 1,895' , ,'.- 7" 23 N-80 BTC 6.366 200' 5,600' 0-,"y, N-80 BTC 7,291' 4151 7" 26 i 6.151 5,600' KOP 10-3/4" j.4 :`" 5" 18 P-110 STL 4.276 Surf 634' 1 i 5" 18 P-110 Ultra F1 4.276 634' 10,093' '1 TUBING DETAIL 2-3/8" 4.7# L-80 8rnd EUE 1.995 Surf ±8,780' i F'AH4 SgzHole inr' i* f" ?. JEWELRY DETAIL @ 3,440-3,471'I Depth Depth ' No (MD) (N) ID Item 1st i 1 ±300' ±301' 1.875" SSSV 2 ±1,851' ±1,850' 1.995" GLM 1 3 ±3,252' ±3,250' 1.995" GLM 2 4 ±4,271' ±4,250' 1.995" GLM 3 I. , 5 ±4,949' ±4,900' 1.995" GLM 4 V 2-V i 4,r. 6 ±5,467' ±5,400' 1.995" GLM 5 '4.4i i 111 7 ±5,989' ±5,900' 1.995" GLM 6 i `1 8 ±6,514' ±6,400' 1.995" GLM 7 ";' ,r 9 ±7,045' ±6,900' 1.995" GLM 8 ,.: III 10 ±7,587' ±7,400' 1.995" GLM 9 >7 «+ � "�' 11 ±8,179' ±7,900' 1.995" GLM 10 �, 12 ±8,720' ±8,350' 1.995" GLM 11(Orifice) 4 rki I 13 ±8,750' ±8,377' 2.668" Packer w/anchor latch assembly and sear bore extension 14 ±8,775' ±8,399' 1.875" X Nipple ' ' 15 ±8,780' ±8,404' 1.995" WLREG It II : `-t 13 14tAk £ PERFORATION DETAIL 15 Zone Top(MD) Btm(MD) Top(ND) Btm(ND) FT Date Status s /-- F Sands ±8,935' ±8,964' ±8,545' ±8,572' ±29' Future Proposed P, / H-1 ±9,248' ±9,268' ±8,839' ±8,858' ±20' Future Proposed f H2 9,729' 9,741' 9,305' 9,317' 12' Open "'4 H2 9,740' 9,790' 9,316' 9,365' 50' Open /,; H2 9,791' 9,819' 9,366' 9,393' 28' Open - H2-H3 9,846' 9,886' 9,419' 9,458' 40' Open J,4',1 i. L ' H2-H3 9,890' 9,940' 9,462' 9,511' 50' Open MH2-H3 9,941' 9,947' 9,512' 9,518' 6' Open w H2-H3 9,963' 9,981' 9,534' 9,551' 18' Open "1 y`"Y y�r ti Notes 'a PBTD=10,048' TD=10,093' Updated By:JLL 07/27/16 Regg, James B (DOA) From: Harold Soule - (C) <hsoule@hilcorp.com> ��4} 511116, (I IG, Sent: Monday, August 01, 2016 2:42 PM To: Regg, James B (DOA) l Cc: Trudi Hallett; Dan Marlowe Subject: Report for BOPE use Moncla 404, C31-26RD Mr Regg As per our conversation here is a summary for report; Yesterday (7-31-2016)we Tripped in hole latched onto a fish @ 5043' &worked it free, circulated 2 annular volumes POOH to 4106' circulated a hole volume, continued POOH t/last stand above BHA (270' ) stopped & had flow from tubing made up FOSV and closed, r/u (installed head pin to safety valve&circulating hose, closed pipe rams leaving choke line open to monitor at pits during operation)we circulated hole volume @ 270' got some oil &gas back,tried putting some heaver fluid in &didn't work, let it flow to see if it would vent off then shut in FOSV to check& monitor pressure build, had 1251bs on on tubing, & nothing on the casing. We pumped hole volume, started tripping in hole using safety valve picking up singles running in to keep fluid from running over tubing to 1045' circulated hole volume& ran in hole t/4695' with no issues. Date: 7-31-2016 Well number C31-26RD, MGS "C" Platform, PTD 2041400, Sundry#316-315 Moncla 404 Engineers: Dan Marlow/Trudi Hallett BOPE used: Floor safety valve (FOSV), pipe rams closed for circulation (no flow from annulus) Note: Floor safety valve closed to prevent fluids flowing from tubing Eq. used will be tested during weekly BOPE test 8-1-2016 Harold Soule 907-776-6754 Cell 227-9400 SCANNED JAN 1 1 2D . 2-64-14-to Regg, James B (DOA) From: Regg,James B (DOA) Sent: Wednesday,July 27, 2016 12:14 PM 7(7,1 7(Z1�I�' To: 'Harold Soule - (C)'; Brooks, Phoebe L (DOA) Cc: Juanita Lovett; Dan Marlowe; Steve Lawrence - (C) Subject: RE: Moncla 404 7-26-2016 BOPE Test Report Attachments: BOP Moncla404 7-26-16 revised.xlsx Revised the test report to show FP on annular(13 5/8")—attached. Remarks include a good explanation of follow up actions. Thank you. Jim Regg Supervisor, Inspections AOGCC SCANNED JAN 12ZJ17, 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information. The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Jim Regg at 907- 793-1236 or jim.reggPalaska.gov. From: Harold Soule - (C) [mailto:hsoule©hilcorp.com] Sent: Wednesday, July 27, 2016 10:27 AM To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L(DOA) Cc: Juanita Lovett; Dan Marlowe; Steve Lawrence - (C) Subject: Moncla 404 7-26-2016 BOPE Test Report Hello Mr Regg As per our conversation yesterday, our 13 5/8" annular would not hold while shell testing, we changed it out for a 7 1/16" 5k annular for the workover on C31-26RD Sundry#316-315. Harold Soule 907-776-6754 Cell 227-9400 1. 0 • STATE OF ALASKA � OIL AND GAS CONSERVATION COMMISSION J rig" BOPE Test Report i\T-1�+ ' Submit to: jim.regq@alaska.gov AOGCC.Inspectors a@alaska.gov phoebe.brooks(a@alaska.qov Contractor: Moncla Rig No.: 404 DATE: 7/26/16 Rig Rep.: Jason Freeman Rig Phone: 907-776-6754 Operator: Hilcorp Alaska Op. Phone: 907-776-6754 Rep.: Harold Soule E-Mail hsoule@hilcorp.com Well Name: MGS C31-26RD - PTD# 2041400 - Sundry# 316-315 Operation: Drilling: Workover: X - Explor.: Test: Initial: X - Weekly: Bi-Weekly: Test Pressure(psi): Rams: 250-3500 - Annular: 250-2500 - Valves: 250-3500 _ MASP: 3257 - MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen. P - Well Sign P Upper Kelly 0 NA Housekeeping P - Rig P - Lower Kelly 0 NA PTD On Location P - Hazard Sec. NA Ball Type 1 - P Standing Order Posted P - Misc. NA Inside BOP 1 • P FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result MUD SYSTEM: Visual Alarm Stripper 0 NA Trip Tank NA NA Annular Preventer 1 • 13 5/8" FP .i Pit Level Indicators P P #1 Rams 1 2 7/8"x 5" • P ' Flow Indicator NA NA #2 Rams 1 blind • P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA Quantity Test Result Choke Ln.Valves 1 2 1/16" P - Inside Reel valves 0 NA HCR Valves 2 2 1/16" FP ✓ Kill Line Valves 2 2 1/16" • P Check Valve 0 NA ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure(psi) 2900 P CHOKE MANIFOLD: Pressure After Closure(psi) 2250 P Quantity Test Result 200 psi Attained(sec) 35 P No.Valves 10 P Full Pressure Attained(sec) 144 P Manual Chokes 1 P Blind Switch Covers: All stations Yes Hydraulic Chokes 1 . P Nitgn. Bottles#&psi(Avg.): 6 @ 2000 P CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 2 / Test Time: 12.5 ` Hours Repair or replacement of equipment will be made within N/A days. Notify the AOGCC of repairs with written confirmation to:AOGCC.Inspectors@alaska.gov Remarks: Tested w/2 3/8"TJ,We were unable to get a shell test w/our 13 5/8 annular&changed it out for a 7 1/16"5k annular after conversing with Mr Regg. Test times do reflect changing out our Kill HCR&changing out Annular, new componets tested good as well as breaks on kill line. AOGCC Inspection 24 hr Notice Yes Date/Time 7/24/16 1:32 PM Waived By Jim Regg Test Start Date/Time: 7/26/2016 8:30 (date) (time) Witness Test Finish Date/Time: 7/26/2016 21:00 Form 10-424(Revised 11/2015) BOP Moncla404 7-26-16 revised.xlsx t V OF TFJ • • 0,1\1//77,r THE STATE Alaska Oil and Gas ��= • Of LAsKA Conservation Commission • s � -_V_ 333 West Seventh Avenue `, GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 O - P Main: ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Stan W. Golis Operations Manager Hilcorp Alaska, LLC 5r moka �- B 2,C17' 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Middle Ground Shoal Field, E, F, and G Oil Pools, MGS C31-26RD Permit to Drill Number: 204-140 Sundry Number: 316-315 Dear Mr. Golis: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. oerster Chair DATED this 'ay of June, 2016. RBDMS k/JUir 1 3 2016 • • RECEIVED STATE OF ALASKA JUN 0 6 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ACC 20 MC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well 0 Operations shutdown 0 Suspend 0 Perforate 0 Other Stimulate 0 Pull Tubing 0 + Change Approved Program❑ Plug for Redrill 0 Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Run New GA.Completion Pl, 2.Operator Name: 4.Current Well Class: 5.Permit to DrN Number: Hilcorp Alaska,LLC - Exploratory ❑ Development 0 204-140 ' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic 0 Service ❑ 6.API Number. Anchorage,AK 99503 50-733-20052-01-00• 7.If perforating: 8.Weil Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes 0 No 0 / MGS C31-26RD 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018756 ' Middle Ground Shoal/E,F and G Oil Pools , 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth ND: MPSP(psi): Plugs(MO): Junk(MD): 10,093 - 9,661 , 10,048 - 9,617 • 3,257 psi WA N/A Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,895' 10-3/4" 1,895' 1,894' 3,130 psi 1,580 psi Intermediate 7,091' 7" 7,291' 7,133' 6,340 psi 3,830 psi Production 10,093' 5" 10,093' 9,661' 13,940 psi 13,450 psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 9,729-9,981 • 9,305-9,551 2-3/8" 4.7/L-80 9,630 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): Baker 5"FH Ret.Packer and Baker T5 SSSV , 9,584'(MD)9,163'(ND)&301'(MD)301'(TVD) . 12.Attachments: Proposal Summary 0 Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory ❑ Stratigraphic❑ Development 0 . Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 7/1/2016 OIL 0 - WINJ 0 WDSPL 0 Suspended 0 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ 0 Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Dan Marlowe(907)283-1329 Email dmarlowe@hilcorp.com Printed Name Stan W.Golis Title Operations Manager Signature c Z1Phone (907)777-8356 Date L Re / ( 4. COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. �� - 3 Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: 'K 35-00 p j RC)P —1-e75 e_5l'" Post Initial Injection MIT Req'd? Yes 0 No 0 Spacing Exception Required? Yes ❑ No / Subsequent Form Required: /b.-41 04-1 RBDMS l.-V JUi4 1 3 2016 I / APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 6-9,2,Z, ' In. l4, 1 dli f PIG ‘17-46-months from the 1 6/'7, Submit Form and Form 10-403 R ised 1 oarAttachments in Duplicate11/2015II i or 12 e date of approval. Middle Ground Shoal Ili 4111 410 Well: MGS C31-26RD SCHEMATIC Last Completed: 10/19/2004 PTD: 204 140 API:50-733-20052-01-00 Hilcurp Alaska,LLC KB:35' CASING DETAIL Size Wt Grade Conn ID Top Btm 24" Conductor 18.750 Surf 400' 10-3/4" 40.5 J-55 ASL 10.050 Surf _ 1,895' 7" 23 N-80 BTC 6.366 200' 5,600' 7" 26 N-80 BTC 6.151 5,600' 7,291' KOP 10-3/4" 5" 18 P-110 STL 4.276 Surf 634' 5" 18 P-110 Ultra FJ 4.276 634' 10,093' ^1 TUBING DETAIL 2-3/8" 4.7 L-80 8rd EUE 1.995 Surf 9,630' ' +. Note: 7"casing cut off a total of 250'below RT SgzHole in7' t @3,440-3,471 ' y; Parted Tbg __".,. JEWELRY DETAIL @4,358' t fr Depth Depth No ID Item (MD) (TVD) c 1 301' 301' 1.875 Baker T5 SSSV ` ' I 2 1,905' 1,904' 1.995 GLM 1 3 3,228' 3,226' 1.995 GLM 2 i ,, 1 1 4 4,337' 4,315' 1.995 GLM 3 5 5,256' 5,198' 1.995 GLM 4 6 5,990' 5,901' 1.995 GLM 5 ' 7 6,475' 6,363' 1.995 GLM 6 8 6,929' 6,790' 1.995 GLM 7 V 9 , 7,414' 7,248' 1.995 GLM 8 a10 7,931' 7,702' 1.995(121 GLM 9 11 8,477' 8,137' 1.995 GLM 10 • �/ 12 9,053' 8,655' 1.995 GLM 11 13 9,535' 9,115' 1.995 GLM 12(Orifice) RL , ,,.. h� 14 9,576' 9,153' 1.875 X Nipple 15 9,584' 9,163' 1.978 Baker FH Ret.Packer �` 16 9,597' 9,175' 1.875 X Nipple �, 17 9,630' 9,208' 2.000 WLREG ', PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(ND) Btm(TVD) FT Date Status X S H2 9,729' 9,741' 9,305' 9,317' 12' Open H2 9,740' 9,790' 9,316' 9,365' 50' Open H2 9,791' 9,819' 9,366' 9,393' 28' Open X H2-H3 9,846' 9,886' 9,419' 9,458' 40' Open H2-H3 9,890' 9,940' 9,462' 9,511' 50' Open 7' H2-H3 9,941' 9,947' 9,512' 9,518' 6' Open H2-H3 9,963' 9,981' 9,534' 9,551' 18' Open T Notes s" .1 I` . • PBTD=10,048' TD=10,093' Updated By:AL 05/18/16 Middle Ground Shoal 0 H PROPOSED • Well: MGS C31-26RD Last Completed: Future Option A PTD: 204-140 Hilcorp Alaska,LLC API:50-733-20052-01-00 KB:35' CASING DETAIL Size Wt Grade Conn ID Top Btm 1 24" Conductor 18.750 Surf 400' 10-3/4" 40.5 J-55 ASL 10.050 Surf 1,895' 7" 23 N-80 BTC 6.366 200' 5,600' 7" 26 N-80 BTC 6.151 5,600' 7,291' KOP 10-3/4" 5" 18 P-110 STL 4.276 Surf 634' 5" 18 P-110 Ultra FJ 4.276 634' 10,093' 2 " 0 TUBING DETAIL 2-3/8" 1.995 3 e LI SgzHole in7" JEWELRY DETAIL @3,440-3,471 4 ' m Depth Depth 5 No ID Item (MD) (ND) r. 1 ±300' ±301' SSSV 2 ±1,905' ±1,904' GLM 1 , , 3 ±3,230' ±3,228' GLM 2 4 ±4,340' ±4,318' GLM 3 5 ±4,370' ±4,348' Sealing Overshot r 6 ±5,255' ±5,197' GLM 4 7 ±5,990' ±5,901' GLM 5 8 ±6,475' ±6,363 GLM 6 9 ±6,930' ±6,791' GLM 7 10 ±7,415' ±7,249' GLM 8 6-1 11 ±7,930' ±7,702' GLM 9 12 ±8,480' ±8,139' GLM 10 4 e a 13 ±9,055' ±8,657' GLM 11 14 ±9,535' ±9,115' GLM 12(Orifice) 15 ±9,575' ±9,154' X Nipple b 16 ±9,585' ±9,164' Packer 17 ±9,600' ±9,178' X Nipple 18 ±9,630' ±9,208' WLREG U PERFORATION DETAIL 15 X Zone Top(MD) Btm(MD) Top(ND) Btm(TVD) FT Date Status H2 9,729' 9,741' 9,305' 9,317' 12' Open 16 H2 9,740' 9,790' 9,316' 9,365' 50' Open H2 9,791' 9,819' 9,366' 9,393' 28' Open 17 x 18 Q H2-H3 9,846' 9,886' 9,419' 9,458' 40' Open H2-H3 9,890' 9,940' 9,462' 9,511' 50' Open 7' H2-H3 9,941' 9,947' 9,512' 9,518' 6' Open H2-H3 9,963' 9,981' 9,534' 9,551' 18' Open Notes PBTD=10,048' TD=10,093' Updated By:JLL 05/26/16 H 4110 Middle Ground Shoal PROPOSED Well: MGSC31 26RD Last Completed: Future Option B PTD:204140 Hilcorp Alaska,LLC API:50-733-20052-01-00 KB:35' CASING DETAIL Size Wt Grade Conn ID Top Btm 1 o• 24" Conductor 18.750 Surf 400' 10-3/4" 40.5 J-SS ASL 10.050 Surf 6.366 200' 6.151 1,895' 7" 23 N-80 BTC 5,600' 7" 26 N-80 BTC 5,600 7'291 KOP 143/4" 5" 18 P-110 STL 4.276 Surf 634' 5" 18 P-110 Ultra F1 4.276 634' 10,093' TUBING DETAIL 2-3/8" Surf ±9,630' SgzHole in7' JEWELRY DETAIL @3,440-3,471 Depth Depth No ID Item (MD) (TVD) 1 ±300' ±301' SSSV 2 ±1,905' ±1,904' GLM 1 3 ±3,230' ±3,228' GLM 2 4 ±4,340' ±4,318' GLM 3 5 ±5,255' ±5,197' GLM 4 2-1 6 ±5,990' ±5,901' GLM 5 7 ±6,475' ±6,363 GLM 6 ' 8 1 GLM 7 9 ±7,415' ±7,249' GLM 8 10 ±7,930' ±7,702' GLM 9 11 ±8,480' ±8,139' GLM 10 12 ±9,055' ±8,657' GLM 11 A v 6 13 ±9,535' ±9,115' GLM 12(Orifice) 14 ±9,575' ±9,154' X Nipple 15 ±9,585' ±9,164' Packer i ® S!',, 16 ±9,600' ±9,178' X Nipple 17 ±9,630' ±9,208' WLREG PERFORATION DETAIL 14 X •r" Zone Top(MD) Btm(MD) Top(ND) Btm(ND) FT Date Status • '' ' H2 9,729' 9,741' 9,305' 9,317' 12' Open 15,: M .1; H2 9,740' 9,790' 9,316' 9,365' 50' Open H2 9,791' 9,819' 9,366' 9,393' 28' Open 16 x - H2-H3 9,846' 9,886' 9,419' 9,458' 40' Open 17 H2-H3 9,890' 9,940' 9,462' 9,511' 50' Open 7" _ - H2-H3 9,941' 9,947' 9,512' 9,518' 6' Open H2-H3 9,963' 9,981' 9,534' 9,551' 18' Open T Notes 5 PBTD=10,048' TD=10,093' Updated By:JLL 05/26/16 • • 0 Platform C . 11 31-26RD fl.kur�%I*sks.LI.( 05/31/2016 Platform C Tubing hanger,Cactus-CXS, 31-26RD 7"x 2 7/8 RTS-6 lift and susp, 24x103/4x7x5x23/8 w/2 X type H BPV profile, 7"casing is not tied into the 6.250"extended neck,1-'/. wellhead,cut off 200'below non continuous control line port BHTA,CIW,External knock-up,2 9/16 5M FE 111011111, 11 e LLll tat p A5S'CP' 4" v ,0, 3� QO r Valve,Swab,WKM-M, N,... ¢� , cs5 14 2 9/16 5M FE,HWO,DD trim �l'`_.,:,,,,,,.,„„,,c, e''''a'cy� .444"0.,, U v J roS4 ,tI•1 t ti 46.\''"•C' N 11. ti ]N:. (Th ir 14.1) _ UJJ Valve,Master,WKM-M, GOO 29/165M FE,HWO,DD trim :.;E: , ' z„„.....,,,,, mITrm .. Tubing head,Cactus C, 11 5M x 7 1/16 5M,w/2- _ ��__ '_�.. 2 1/16 5M SSO,w/NX :II jIIiiiIMl 121 bottom bottom _ - —'--Ij " Valve,WKM-M,2 1/16 5M, IN ,,, i II Casing head,CIW-WF, 11"5M FE top 11"3M 1 l Cameron clamp flat face Valve,CIW-F,2 1/16 SM, bottom,w/2-2 1/16 5M SSO HWO i F i i i i y' , (., . .. .4, , Landing hub,CIW,11 3M Cameron flat 9, x 10%casing thread bottom, LH acme lift Conductor housing,24"ASAIIIXI jr" 24" 10%" d 5", 2 3/8" • i . ii BOP Stack(Moncla) nnrnrp AIA.Ra.IAA. � �yoXi(fiTVn fit(felfna l ...-- 3.74'3.74' Shaffer 135/85M rainlrtnir lit 1. III III III III i I aw-U -�� Variable 27/8-5 ` 1II ® 7� 4.67' 1�e 13 5/8-5000 .A� ! ��o Blind Rams =lir. . . .. .. .,....., ...��te Iii III li l ill ,.." Choke and Kill Valves 2 1/16 5M w/Unibolt connections for hoses �. ii19l111r111 III kf 4; 2.D0' ic:: I� �'I'1111.111.111.111.111 i I: ..... 135/8-5000 I' 4, • al i 1 gel IF III i! I I Riser,13 5/8 5M FE X 13 5/8 ' 5M API 013 hub 13.70' Chi It `0 • Q O O u 0 u 0 04.) 0 O Uu O u O u u O u u 0 o _ _ 0 N N fA C1 U1 `� N N 01 a 111 l0 N CO 01 2 f f 2 f 2 ' f 2 2 2 2 f 2 2 2 0. O. 0. 1 0. U U U V U U U U U O 1-1 N 0 O IA a r1 N m Cr Ill l0 I0 00 O1 r-I 0 0 O 0 O 4- L �O 0 0 0 0 0 0 O O a 0 E EEEEC y .q � � � � C C C c c O L j ao 2 2 2 2 2 a a ToJ 2 2 2 2 2 2 2 2 2 2 . > a E 0. 0. E a C > -8 -8 -8 -8 -6 -6 -6 -6 -8 -8 Y Y Y Y Y Y 0./ Y Y W s E E E E E =' - ,:. '8 0 0 0 0 0 0 0 0 0 0 0. A ( 0 N J J . 0 . = = U L L L L L L L L L L L > 0. o. o. o. o. Y Y 2 V U V U V U U U U V U to 2 0.v a o `0 OwO O N .P, 5 OE U A 00 11 14 N N . co . to . (O . U z z r►•Z I '--.—.1 a J t W 0.0 10) . st z 0. o 10/1 0 2 U I I c O ceo w a U) 0 => CL-1-Ca, .... Y IIi I I T 0 <m 03 I-- (/) w a 1—ll H EE ❑ z a 1— co z CD 0 Z ~ w U Z El a A ofYz z O0t. * a < cn : fY w U ft r _ Q �Q Z U zin U < Oc1 ZO p 0 t 2 D O W r JOZw Io In aN Z Q m z J a st5 J U u_ CC U u e 2. 0000u0 00u0 0UIV O V ODUOU V 0 o .... a _ o ti .ti ry m a m `� ry m a u1 e n m m g ddddp - v 0 U 0 U 0 0 U 0 U 0 .-1 r4 m a V1 N . N m a 1/1 LID N 00 01 N -017 v v v V V a V V 0 0 0 0 L 0 0 0 0 0 0 0 0 0 0 Y N m ra co cc C C C ra .-1 N ; C C C C g p co C a, C C co LE -v u To 2 f 2 f 2 v w '0 f 2 2 2 2 2 f 2 2 2 u — > y D. a a a a C C j 21 d d O1 Y Y Y O1 N d Y N j 2 EEE ' o 0 0 0 0 0 0 0 0 0 0 0. 70 N J J J J J 0 0 U U Z U V V L V U L L L m N 1 d d O. d (1 Y Y = V V l.! V V V V U U U U c H n y v Z. 7 LL m t0 U 0 00 O ,n f III 2 K 111 4 LN,l 01 U w Z Z 1—...-•I :�1 Qa EX 111 Q Ill 0 MIn , Nt . Z o w cc> O ix O b Fc ai • 1 U s Ift...._ MG. E P _ d EPilli Y w w T a U Oa mI- w a 1—U iii a 0 z Q �� U) Q J D z O Z FI-LI Z 0z Q 0a acg21 0 — H > 2 a Z — <.. 2u) ( C) CYOU }- rv � wzcD ,— < 0 ° C° °rzq O o z = H � � � = J O O r-) In _ co�WQ m LLZp - 0m z co I I- z g 2 Q i J 1 D 0 Ct 0 S Well Prognosis Well: C-31-26RD Hiicorp Alaska,LL Date:06/06/2016 Well Name: C-31-26rd API Number: 50-733-200052-01 Current Status: S/I Oil producer(gas-lift) Leg: Leg#1 Estimated Start Date: 07/01/16 Rig: Moncla 404 Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 204-140 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Trudi Hallett (907) 777-8323 (0) (907) 301-6657 (M) Work-over program: Current Bottom Hole Pressure: 3,600 psi @ 8,000'TVD 0.450 lbs/ft(8.66 ppg) Maximum Expected BHP: 3,600 psi @ 8,000'TVD 0.450 lbs/ft(8.66 ppg) Maximum Potential Surface Pressure:3,257 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary The C31-26rd well is currently completed with a 2-3/8" gas-lift completion installed 10-19-2004.The tubing parted in 2006 at 4,358' right below GLM #3.This workover will restore tubing integrity. / Brief Procedure: 1. MIRU Rig. --�"� IS 2. Kill well and circulate Hydrocarbon off of well. Work over fluid to be KCL Brine. 3. Notify AOGCC 48 hours before pending BOPE test. Set BPV, ND tree, NU BOPE.Test all BOP equipment per AOGCC guidelines to 250psi low and S,OOOpsi high. 4. Monitor well to ensure it is static. s—<, • .,L, ��? 5. Unseat hanger and POOH with upper completion. 6. Option A a. RIH with overshot latching lower tubing at+/-4,358'. b. RIH with e-line and cut lower tubing mid joint at+/-4,370'. c. RIH with new completion, overshot with sealing pack-off stabbing over lower tubing at+/- 4,370'. 7. Option B a. RIH and latch lower tubing at+/-4,358', pull packer free, circulate well clean. POOH. b. RIH and Cleanout to+/-10,000'. POOH. c. Run new completion and set packer 8. Pressure test completion: a. Test tubing against plug in X nipple to 2500#and chart for 30 minutes. b. Test IA to 1,500 psi and chart for 30 minutes(This will pressure up tubing also). 9. Set BPV. NU tree,test same. 10. Conduct SVS tests per AOGCC regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Current/Proposed (Same) 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form • Moncla Rig 404 BOP Test Procedure flacorp ai�ska, Attachment#1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Moncla Rig 404, WO Program —Oil Producers, Water Injectors Pre Rig Move 1) Blow down well,bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. • Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Shoot fluid level at least 24 hours before moving on well. 4) Shoot fluid level again, right before ND/NU. Confirm that well is static. Initial Test(i.e.Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2-way check in hanger. 3) Space out test joint so end of tubing(EOT)is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off.Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful,shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV.As approved in the sundry, proceed as follows: a) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2-way valve,or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale,attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand,or MU landing(test)joint to lift-threads d) For ESP wells-Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and/or a penetrator leaks, notify Operations Engineer(Hilcorp), Mr.Guy Schwartz(AOGCC)and Mr.Jim Regg(AOGCC)via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. As outlined and approved in the sundry,proceed as follows: a) Nipple Up BOPE b) With stack out of the test path,test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump,(monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed,test the remainder of the system following the normal test procedure(floor valves,gas detection,etc.) • Moncla Rig 404 BOP Test Procedure Haeorp Alaska.►►.c Attachment#1 f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile/ penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger(or test plug)in tubing head. Test BOPE per standard procedure. Subsequent Tests(i.e.Test Plug can be set in the Tubing-head) 1) Remove wear bushing. a) Use inverted test plug to pull wear busing. MU to joint of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same-RIH with test plug on joint of tubing. Install a pump-in sub w/test line plus an open TIW or lower Kelly valve in top of test joint w/open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE(after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump-install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 2) Note: When testing, pressure up with pump to desired pressure,close valve on pump manifold to trap pressure and read same with chart recorder(test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 1st valve on standpipe manifold,close valves 1,2, 10 on choke manifold and close the annular preventer,open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and 2,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer,close safety valve and open IBOP on test joint,close outside valve on kill side of mud cross,open 1st valve of standpipe,close valves 3,4&9 on choke manifold,open valves 1&2 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. c) Test Dual Rams. If the well has dual tubing,and dual rams are installed in the stack,test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close inside valve/open outside valve on kill side of mud cross,close valves 5&6/open valves 3&4 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. e) Close manual and super choke/open valves 5&6 on choke manifold. Pressure up to^'1200 psi and bleed off 200—300 Us recording change and stabilization. If passes after 5 minutes, bleed of pressure back to tank. f) Close HCR(outside valve on choke side of mud cross),open manual&super choke. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each,bleed off pressure back to tank. • Moncla Rig 404 BOP Test Procedure Hilcorp,va5ka.IAA: Attachment#1 g) Close inside valve/open outside valve(HCR)on choke side of mud cross. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Ensure all pressure is bled off-open pipe rams and pull test joint leaving test plug/2-way check in place. Close blind rams and attach test line to valve 10 on choke manifold,close valve 7&8/open valve 10 on choke manifold. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each,bleed off pressure back to tank. i) Test additional floor valves(TIW or Lower Kelly Valve)and IBOPs as necessary. STANDARD TEST PROCEDURE OF CLOSING UNIT(ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record "Accumulator Pressure". It should be+/-3,000 psi. 3) Close Annular Preventer,the Pipe Rams,and HCR. Close 2nd set of pipe rams if installed (e.g.dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read "10 bottles at 2,150 psi"). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually+/-30 seconds. 8) Once 200 psi pressure build is reached,turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure(+/-3,000 psi). Note: Make sure the electric pump is turned to"Auto", not"Manual"so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP,FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves,for correct operating position 3) Fill out the AOGCC BOPE Test Form(10-424)in Excel Format and e-mail to AOGCC and Juanita Lovett. Document both the rolling test and the follow up tests. • 4 = Nr 0 . of C5 ❑ a) L CC c oCO ai V 1 CDS (DO VU as 2 aaa c a) a ... E L U c a) N c a -0a, � � CD CO o 2 ^i = Q 5 Q D- RS ao •N � -0 a> a) •VRI as 2 � cr L Z GI CI NCO Z a RI N CD h. o ❑ oTO a) to CL TD0 N -a Q V � Q 0 M a) o 2.a C.) oc Cl) Q2 c L a cv cu co O a) � o a h. `° aQ U 3 a) = a) i U O °te • a, s a) i ° °' ° d a _ �` as c th l c a) Cl) oi0 CO W Ua d as47. N o U a o a) r C - £ O Q o 0 0 w, CCS Q d ~ U cti X rn y U M v '`•' CI lL O V ELI 4) w ..'moi +' �" O = d .a E V a, o as 0 o 0_ _ .0 C >. 0_ a� ►`�' V 0 U) QOQ a Q a` :3 0 a) • • Schwartz, Guy L (DOA) From: Dan Marlowe <dmarlowe@hilcorp.com> Sent: Wednesday,June 08, 2016 1:37 PM To: Schwartz, Guy L(DOA) Subject: RE: C31-26RD RWO (PTD 204-140) Guy I didn't include a specific brine weight due to the complexity that you indicate. Ideally brine weight will be about 8.70 ppg. However,the tubing part will complicate things.Thankfully the well is fairly straight so weighted fluids should swap out readily allowing us to quickly swap out any oil for kill weight fluid and proceed with the workover. Progression will be as follows • circulate 8.5 fluid around at the part at 8,358' monitor well to ensure static, repeating as needed to circulate out migrating hydrocarbons • if required circulate slugs of up to 9.7 ppg KCL and allow to settle to ensure static, repeating as needed to circulate out migrating hydrocarbons • add in Option A is our preferred alternative but if we run into any issues with lower tubing we will move to option B.The drivers are likelihood and economics of restoring integrity. I.E. we won't waste a lot of time with Option A if it doesn't look favorable when we latch on and/or make the drift run before cutting pipe. From: Schwartz, Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent: June 08, 2016 9:17 AM To: Dan Marlowe Subject: C31-26RD RWO(PTD 204-140) Dan, What will be your Brine weight for the workover? You only specify KCL but not specifics. Also since the tubing is parted how are you going to ensure the well is properly killed before pulling the upper completion? What are your main drivers for choosing either options A or B? Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226)or(Guy.schwartz@alaska.gov). 1 • • Schwartz, Guy L (DOA) From: Larry Greenstein <Igreenstein@hilcorp.com> Sent: Tuesday, May 17, 2016 1:52 PM To: Schwartz, Guy L(DOA) Cc: Regg,James B (DOA) Subject: RE: MGS C31-26RD tubing part(PTD 2041400) Thank you, Guy. We will get the well shut-in this afternoon and let you know of any future plans to WO/repair this well as they are developed. Larry From: Schwartz, Guy L(DOA) [mailto:guy.schwartzalaska.gov] Sent:Tuesday, May 17, 2016 1:36 PM To: Larry Greenstein Cc: Regg, James B (DOA) Subject: RE: MGS C31-26RD tubing part(PTD 2041400) Larry, With the absence of direct written approval (emails from Oct/Nov 2010)to produce the well with parted tubing the well should be shut in from production as soon as possible and repaired as required under 20 AAC 200(d). The well appears to be a flow to surface well and needs competent tubing and packer to be in compliance. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guv.schwartz@alaska.gov). From: Larry Greenstein [mailto:Igreenstein@hilcorp.com] Sent:Tuesday, May 17, 2016 12:26 PM To: Schwartz, Guy L(DOA) Subject: MGS C31-26RD tubing part(PTD 2041400) Hi Guy As we discussed, he's the rather cryptic reference to AOGCC approval (in Oct 2010) for continued production from the C31-26RD oil well even though parted tubing was noted a few years earlier(in Dec 2006). As no other document or e- mail in our records or yours affirms this approval, the question arises if this note is sufficient to continue producing this well?? Please let me know where we stand...and thank you for your time to discuss this well in person and dig through your files looking for any backup to this note below. 1 • • Larry From: Dan Marlowe Sent: May 02, 2016 2:30 PM To: Tim Cowan; Cody Mishler; Barney Phillips Subject: FW: C31-26rd tubing part Gentlemen Can you check your files and see if you have any official letter granting this variance Thanks Dan From: Dan Marlowe Sent: May 02, 2016 1:32 PM To: Luke Saugier; Stan Golis Cc: James Young; Trudi Hallett Subject: C31-26rd tubing part I'm going to dig a little to see if I can find this permission slip before I talk to the state Looks like its parted at 4358' which is right below mandrel#3 at 4337' 2 . • 114-06 , RIH to 10,048 PMIXI 6 bbl One-St .. Laid acid pill from 10,048-9550 Soak acid 30 r RIH while arc out acid Acid wasillied31L20 bbl 1-shot acid a 1 BPM © 4000-5000 psi 1pm RIttia.10.048 & arc out acid. SI WH Scat 116 bbl acid ((t.' 05 BPM ft 1450 psi Wil 4800 CT press while running pipe ft 10 fpm Got leak on CT w 96bbl IN Went to flush ez, Had 2 leak cin CT Flushed acid from CT to flowback tank Bullhead 37 bbl acid down 2 tfin Start gas lifting well SD due to hi H2S Pumped H25 scavenger Flushed coil equipmer WH R D BJ 11-7-06 Start flowback well 11.10-06 Only recovered 45 WM GIN 01 would not open RIH wWL &cligd.out GLV 1 RTN to gas Ii Recvd,331 bbl load.euwd 84 bbls scale inhibitor followed by 160 bbl 3 KCL RU WL RIH w 1 845' gauge ring. Sat down by GLV t 3 4323 WLM. Could not gel lov POOH Ring was marked up RIM w/ 1 75 gauge ring & still could not get below 4323 RIF 1 75' impression block to 4323 Block showed belly of mandrel on 1 side w Jagged scrape other side 12-3-06 RIH wi Etticamera Found paned tbg at.4.358' 10,26.10 Well SI for annual on compressor There was an earthquake during the SD Well was opened on Oct 28'' and began free flowing w o gas lift Pnor prod 11 BO 78 OW& 87 MCI Atter on 30.10 105 BO. 772 OW & 356 MCI Contacted AOGCC and was granted permissior continue producing even with parted tbg @ 4358' 3 • • Schwartz, Guy L (DOA) From: Larry Greenstein <Igreenstein@hilcorp.com> Sent: Tuesday, May 17, 2016 4:13 PM To: Schwartz, Guy L (DOA) Cc: Regg,James B (DOA) Subject: RE: MGS C31-26RD tubing part (PTD 2041400) Attachments: Well 31-26RD Shut-In 5-17-16 Follow Up Flag: Follow up Flag Status: Flagged Guy & Jim, The C31-26RD well was shut-in at 3:45 this afternoon. Per the attached e-mail, all operators on both shifts were notified by e-mail that the well should remain shut-in until the tubing has been fixed. The well is being flagged to ensure it stays shut-in. Larry From: Larry Greenstein Sent: Tuesday, May 17, 2016 1:52 PM To: 'Schwartz, Guy L(DOA)' Cc: Regg, James B (DOA) SCANNED MAY 2 5 2616, Subject: RE: MGS C31-26RD tubing part(PTD 2041400) Thank you, Guy. We will get the well shut-in this afternoon and let you know of any future plans to WO/repair this well as they are developed. Larry From: Schwartz, Guy L(DOA) [mailto:guy.schwartz(aalaska.gov] Sent: Tuesday, May 17, 2016 1:36 PM To: Larry Greenstein Cc: Regg, James B (DOA) Subject: RE: MGS C31-26RD tubing part(PTD 2041400) Larry, With the absence of direct written approval (emails from Oct/Nov 2010)to produce the well with parted tubing the well should be shut in from production as soon as possible and repaired as required under 20 AAC 200(d). The well appears to be a flow to surface well and needs competent tubing and packer to be in compliance. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 1 • CONFIDENTIALITY NOTICE:This e-mail messa e,including any attachments,contains informatirom the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226)or(Guy.schwartz@alaska.gov). From: Larry Greenstein [mailto:Igreenstein@alhilcorp.com] Sent: Tuesday, May 17, 2016 12:26 PM To: Schwartz, Guy L(DOA) Subject: MGS C31-26RD tubing part (PTD 2041400) Hi Guy As we discussed, he's the rather cryptic reference to AOGCC approval (in Oct 2010) for continued production from the C31-26RD oil well even though parted tubing was noted a few years earlier(in Dec 2006). As no other document or e- mail in our records or yours affirms this approval, the question arises if this note is sufficient to continue producing this well?? Please let me know where we stand...and thank you for your time to discuss this well in person and dig through your files looking for any backup to this note below. Larry From: Dan Marlowe Sent: May 02, 2016 2:30 PM To: Tim Cowan; Cody Mishler; Barney Phillips Subject: FW: C31-26rd tubing part Gentlemen Can you check your files and see if you have any official letter granting this variance Thanks Dan From: Dan Marlowe Sent: May 02, 2016 1:32 PM To: Luke Saugier; Stan Golis Cc: James Young; Trudi Hallett Subject: C31-26rd tubing part I'm going to dig a little to see if I can find this permission slip before I talk to the state Looks like its parted at 4358' which is right below mandrel #3 at 4337' 2 • • . • ' 11-5 06 RIH to 10.048 Pmpd 6 bbl One-Shot acid. Laid acid pill from 10 048-9550Soak acid 30 r RIH while circ out acid Acid wash pert w 20 bbl 1-shot acid It 1 BPM @ 4000-5000 psi fpm RIH to 10.046 & circ out acid SI WH Sqz 116 bbl acid 0 5 BPM (c.0 1450 psi WHI 4800 CT press while running pipe i 10 fpm Got leak on CT w 96bo1 inj Went to flush ei Had 2'4 leak on CT flushed acid from CT to flowback tank Bullhead 3! MI acid down 2-: tbg Start gas lifting well SD due taikti2S Pumped US scavenger Flushed coil equipmer RD 6J 11-1-06 Start flowback well 11-10-06 Only recovered 45 bbbl GLV#1 would not open RIH WI WL&Chgd ouLGIN.1, RTN to gas i 11-13-06 Recid.231 bblload Prnpd 84 bbls scale inhibitor followed by 160 bbl 3°6 KCL 12.-3-011_ RU WL. RIM w 1 845' gauge ring Sat down by GLV t3 4323' WLM. Gould not get lo% POOH Ring was marked up RIH w; 1 75' gauge ring & still could not get below 4323 R11- 1 75- impression block to 4323 Block showed belly of mandrel on 1 side w/jagged scrape other side 12405amera. Found parted tlag.at 4358 10-26-10 Well SI for annual on compressor There was an earthquake during the SD Well was oper,, on Oct 28"' and began free flowing wio gas lift Prior prod 11 BO 78 BW& 87 MCF After 30.10 105 BQ 772 BW & 356 MCF Contacted AOGCC and was granted permissior continue producing even with parted tbg @ 4358 3 . Image Project Well History File Cover Page . XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ~ 0 y.. - J Y-O Well History File Identifier Organizing (done) tø<WO-Sided 11111111I1111111111 D Rescan Needed 111111111111111I11I RESCAN ~olor Items: D Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Diskettes, No. D Other, Noffype: D Poor Quality Originals: OVERSIZED (Non-Scannable) D Other: D Logs of various kinds: NOTES: D Other:: BY: ~ Date ILl c3Q / 0 ~ /5/ v11P Project Proofing 1111111111111111111 BY: C Maria) Date uj 60/00 I ~ X 30 = 1£;0 + ~ = TOTAL PAGES b~ / h b (Count does not include cover sheet) Date: I J 30 0 /5/ I I 1111111111111111111 /5/ @ Scanning Preparation BY: ~ Production Scanning Stage 1 Page Count from Scanned File: ~ (Count does ;nc7' sheet) Page Count Matches Number in Scanning Preparation: YES ~ Date /lld%fo If NO in stage 1 , page(s) discrepancies were found: NO /5/ vwP NO BY: Stage 1 YES BY: Maria Date: /5/ 111111111111111111I Scanning is complete at this point unless rescanning is required. ReScanned 111111111111111111I BY: Maria Date: /5/ Comments about this file: Quality Checked " 111111111I1111111 10/6/2005 Well History File Cover Page.doc Page 1 of 1 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, February 18, 2011 3:44 PM To: Aubert, Winton G (DOA) Cc: Regg, James B (DOA) Subject: FW: XTO MGS C31 -26RD (204 -140) Unexpected Prod Attachments: C31 -26RD Current WBD 9- 1- 05.doc; C31 -26RD Production.doc; C31 -26RD Well Tests.pdf Not sure I forwarded this to you. Only action that might be warranted would be assuring the safety valves meet the applicable regulations. From: Paul_Figel @xtoenergy.com [ mailto :Paul_Figel @xtoenergy.com] Sent: Monday, November 01, 2010 10:37 AM To: Maunder, Thomas E (DOA) Subject: XTO MGS C31 -26RD (204 -140) Unexpected Prod Tom, will call you to discuss. Here are files that will make the discussion easier. Gas lift was shut -off for compressor maintenance. Well was brought on & has been free flowing w/o gas lift since Sat and is making more prod than the last 5 years. Paul Figel Engineering Manager XTO Energy Inc. Midland, TX WOWED MASS 1 2i " Office: 432 - 620 -6743 Cell: 432 - 553 -5217 Fax: 432 - 687 -0862 2/18/2011 11/1/2010 ifilr Alaska Offshore Report 0 NERGY Division Midland Dates 10/25/2010 - 10/31/2010 Type Route Stop Type Value C31 -26RD Well Production Data 1 OIL 1 GAS 1 PRESSURE 1 Nam= Drndllt I- c(lnwn WT (irnccflil WtrCut Claan(lil Allnrnil Inj (;ac Prnri (;ac (;(F SiirfCP TP CP PnwprFluiri Cnmmantc C31 -26RD 10/25/2010 0 158 84.00 25 22 676 111 4,367 25 90 360 0 C31 -26RD 10/26/2010 3 139 84.00 22 19 594 95 4,274 25 90 360 0 CB #1 Annual C31 -26RD 10/27/2010 24 0 84.00 0 0 0 0 C 23 920 950 0 CB #1 Annual • C31 -26RD 10/28/2010 0 158 84.00 25 22 702 84 3,334 25 90 360 0 C31 -26RD 10/29/2010 0 158 84.00 25 23 231 556 21,954 150 90 965 0 C31 -26RD 10/30/2010 0 X 658 84.00 105 90 0 356 3,38C 110 80 885 0 C31 -26RD 10/31/2010 0 658 84.00 105 92 0 356 3,38C 90 80 865 0 Platform Summary Tyra Nama brndllt 1 (,rnccCitl Wtr(!J1 Claanlij (;ravl t;acMCF WtrRRII PSII Tamp 1 Cnmmantc • Page 1 of 2 Well Injection Data Names 1Drnrlf)t l Hniircfnwnl InjartardWatari SurfCPl Annulucl !MCP IP Cnmmantc Total: Miscellaneous Type (Uame rnrl Reading RunHnurcl Inctalllate HrsSrelnl f)aycSrelnl PSI Vnitcl Ampc Cnmmantc i 'Materials Usage Material Prnri l llcaga) Cumulative l Cnmmantc • Page 2 of 2 NroS (E) C31 -26RD MDDLE GRO 1000 SHOAL I�D ___1 500 1 -.. ... . 16-4 100 • wed■ 50 A1 ■ 1 iri , . . ,- 7 1 10 Y 0 1 / I H __ 6RD Ilk MI - coal ! , r - CDWtr CD Gas 1 05 06 07 08 09 10 Cum Oil 65958.783 Cate I�! h11F C31 -26RD HEMLOCK BBL 750 - -750 700 -700 660 - -660 600 - -600 550 - -550 Soo - -600 450 - -450 • 400 - -400 360 - -360 300 - -300 250 - -260 200 - -200 160 - - iiis 160 100 - -100 • 50 _ - . - 60 10/2/10 10 ;16 10/31/10 - Gas Oil — Water — Water lnj — Gas Injection -- 002 Injection — Gas Target — Oil T • ~_ ~. ,,"_ MICROFILMED 43/~1/2~08 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:1LaserFiche\CvrPgs_InsertslMicrofilm Mazker.doc . . Jt!R XTO Energy Inc. 200 North Loraine Suite 800 Midland, Texas 79701 432-682-8873 432-687-0862 (Fax) December 4, 2006 Alaska Oil and Gas Conservation Commission Attn: Mr. John Norman 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 ..Ý~ r~~' RE: Sundry Well Operations Report: Well #C31-26RD - Coil Tubing Stimulation Dear Mr. Norman, XTO Energy, Inc. hereby submits its Sundry Operations Report (Form 10-404) for the coil tubing ~ stimulation performed on the producing well #C3l-26RD. This well is located on Platform C, in the Middle Ground Shoal Field of Cook Inlet, AK. Please find attached the following information for your files: c·r, & iltJit..i;::;Wi "'\;#"Ti~~ .i.. l~ 1. Form 10-404 Sundry Well Operations Report 2. Daily Report of Operations 3. Present Wellbore Schematic If you have any questions or require additional information, please contact me at (432) 620-6742. 9lJi¿ Jeff Gasch Production Engineer Cc: Paul Figel Scott Griffith Tim Smith K t: \.."t:.1 V t::. U . STATE OF ALASKA __ ALA OIL AND GAS CONSERVATION COMIVW'I0N DEC 0 5 2006 REPORT OF SUNDRY WELL OPERATIONS Alaska Oil & Gas Cons. Commission 1. Operations Abandon U Repair Well U Plug Perforations U Stimulate ~ Other U w Performed: Alter Casing D Pull Tubing D Perforate New Pool D WaiverD Time Extension D Change Approved Program D Operat. Shutdown D Perforate D Re-enter Suspended Well D 2. Operator XTO Energy 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development 0 ExploratoryD 204-140 . 3. Address: 200 N. Loraine, Suite 800, Midland, Texas, Stratigraphic D ServiceD 6. API Number: 79701 50-733-20052-01 7. KB Elevation (ft): 9. Well Name and Number: 105' C31-26RD 8. Property Designation: 10. Field/Pool(s): A.,· I"'ÞIP ADL-18756 Middle Ground Shoal Field _, i' '1 ÞII... ?r;Þ/ 11. Present Well Condition Summary: Total Depth measured 10,093 feet Plugs (measured) None true vertical 9,666 feet Junk (measured) None Effective Depth measured 10,048 feet true vertical 9,622 feet Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1895' 10-3/4" 1895' 1894' 3130 1580 Intermediate 7091' 7" 7291' 7139' 6340 3830 Production 1 0093' 5" 1 0093' 9666' 13940 13450 Liner Perforation depth: Measured depth: 9729' True Vertical depth: 9310' Tubing: (size, grade, and measured depth) 2-3/8" L-80 9630' Packers and SSSV (type and measured depth) Baker 5" FH Retreivable Packer @ 9584' & Baker T5 SSSV @ 301' 12. Stimulation or cement squeeze summary: Intervals treated (measured): R.BDMS 8Ft DEC 1. 4 2006 Treatment descriptions including volumes used and final pressure: Acidized w/ 8400 gals 75/25 10% HCL/Xylene through coiled tubing. Final pressure 4800 psi @ 0.5 BPM. 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 35 11 212 805 140 Subsequent to operation: 17 24 199 - 420 80 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run ExploratoryD Development 0 - Service D Daily Report of Well Operations X 16. Well Status after work: Oil0 - Gas D WAG D GINJ D WINJ D WDSPL D 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ISUndry Number or N/A if C.O. Exempt: 306-302 Contact Jeff Gasch Printed Name Jeff Gasch . Title Production Engineer Signature Oil.YÍ.. j Phone 432-620-6742 Date 12/4/2006 ~cf4 !. . Submit Original Only Form 10-4 4 Revised 04/2006 ORIGINAL hrrt ~~l£¿{z{ÌI((~ .¿tfþ ,~. t ,.ÞÇ. Page 1 of2 {(TO Energy - Midland District W orko~eport Midland Well Workover Re.t ¡IMIDDLE GROUND SHOAL C II Objective: Coil Tbg Cleanout & Stim Treatment First Report: AFE: 10/31/06 Well # 31-26RD II II 05/20/2006 652855 Clear decks for coil job. Transfer equipment from Platform A to Platform C. Spot coil equipment and PTS flow back tank. Filled active and storage pits with FIW. Prep to mix up KCL in active. SDFN 11/1/06 RU CT unit, hard lines and hoses. Unload second boat with chemicals and equipment. Mix up 450bbls of 3% KCL in active pits. MU riser and BOPE on tree. Rig up back flow tank and filter skid. SDFN 11/2/06 Finish rigging up PTS tank, dress off coil tubing end, make up lubricator. Stab on BOP. Clean coil tbg- pump. Pressure test BJ lines to 6500 psi & flow back lines to 4500 psi. Test BOPE to 5000 psi (Test witness waived by Mr. Jim Regg of AOGCC). Open well RIH with motor and 1.75" drag bit @ 40 fpm, pumping FIW @ 0.8 bpm @ 1100psi. Slow down speed @ GLM's. Mill scale from 7500' to 8500' pumping FIW @ 0.8 bpm @ 1900 psi. RIH & tag @ 10045'. Drop ball to open circ sub. Pump 20 bbl high vis sweep. With sweep chased 45bbls up annulus pipe hung up. Work pipe free & POOH with clean out assembly @ 100fpm pumping 0.8bpm @ 1600psi. Close swab valve & secure coil unit. SD for 6-8 hours. Prep to blend acid. 11/3/06 Send fluid from PTS tank to disposal. Prep for acid job. Prejob safety and operation meeting with BJ, IDA, & XTO employees. RIH with rotojet wash tool @ 25 fpm pumping 1 bpm @ 5200 psi. Tag up @ 7435'. Work pipe and make hole to 7615'. Pump 10 bbls acid to assist clean out wi no success. 11/4/06 POOH with rotojet tool, secure coil equipment & SD 8hrs. RIH with vortex wash nozzle @ 80 fpm pumping 0.3bpm @2000psi to 7300'. Slow speed to 25 fpm pumping 1 bpm @ 4500-5000psi. Wash hard scale from 7890' - 8225'. RIH to 10048'. Pump 20 bbl high vis sweep followed by 90bbls FIW to clean up well. Notice lining of acid tank flaking off and dropping into acid. Pull coil up to 9500' & SD pump. Lining up screens and filters to remove plastic lining from acid. 11/5/06 Coil set @ 9500'. RU equipment to filter tank lining from acid. Filter 220 bbls acid. RIH to 10048' circulating FIW @ 1 bpm @ 3100 psi. Pump 6 bbls one shot acid @ 1 bpm @ 3800 psi. Chase with 16 bbls slick 3% FIW. POOH laying acid from 10048' to 9550'. Continue circ 0.5 bpm @ 1500psi. Wait on acid 30 minutes, bring rate to 1 bpm @ 3400psi. RIH to 10048' circulating FIW @ 1 bpm @ 3400psi. Circulate clean wi 50 bbls 3% FIW. Acid wash perfs wi 20 bbls one shot acid @ 1 bpm @ 4000-5000 psi while POOH @ 10 fpm. RIH to 10048' and circulate 50bbls 3% FIW. Start acid injection job. Inject 116 bbls acid @ 0.5 bpm & pump pressure 4800psi, WH pressure 1450 psi while working coil @ 10 fpm over perfs. 11/6/06 Injecting one shot acid át 0.4 bpm, 6000psi on coil, 2400psi on wellhead. Pin hole in coil 9730' (118bbls pumped 96 injected). SD pumping, secure coil and leak. Displace acid with 3% FIW at min rate & leak stopped. Pump acid at min rate until leak reappeared (total pumped 135 bbls & 113 bbls injected). Displace acid with 10 bbls FIW to clear pin hole leak. POOH with coil & while POOH another hole in coil was found @ 2700'. Finish POOH & flush acid from coil with FIW, containing acid and sending to flow back tank. Bullhead 37.3 bbls one shot acid into 2 3/8" tubing. SI swab valve. Pump remaining acid to flow back tank and give tanks rinse with FIW. Pump acid in flow back tack down disposal well. Cool down N2 pumps & blow down reel. RD injector head. RU flow back tank to production. Open well to flow back, and start gas lift. High H2S, SI well and shut down gas lift. RU chemical pump for H2S scavenger. / 11/7/06 Finish RU chemical pump for H2S scavenger. H2S dropped to 5 ppm. Flush lubricator, BOPE and lines wi http://dor/rept_workover.asp 11/21/2006 XTO Energy - Midland District W orkoWeport Page 2 of 2 water. RD BJ CT equipment. RU flow back lines to PTS tank. Start.ow well, sight glass and isolation valve leaking on PTS tank. SI well to repair. Open well. Just starting to get fluid returns @ 6:00 am 11/8/06 Flowing back well monitoring PTS tank. Back load boat wi CT equipment. At 9:00 pm had recovered 38 bbls fluid. No more fluid recovered from 9:00 pm to 6:00 am. 11/9/06 Flowed 7 bbls last 24hrs. Total flow back from well - 44.5bbls 11/10/06 Attempt to flow well. No fluid recovered in last 24 hours. Recovered 44.5 bbls total from well. 11/11/06 SD gas lift. Pump 13 bbls FIW down tbg. RU slickline and change out top gas lift valve @1905'. RD slickline. RTWP. Recovered 47 bbls in 18 hrs. 11/12/06 Cont. flowing well to PTS tank. Recovered 151 bbls in last 24 hrs. 11/13/06 Cont. flowing well to PTS tank. Recovered 129 bbls in 13 hrs. SD gas lift at 7:00 pm to prepare for scale squeeze. Left well flowing to PTS tank. Recovered 331 bbls total @ 6:00 am. 11/14/06 RD flow back lines. RU BJ pumps & test lines to 4000 psi. Pump 84 bbls Nalco EC6085 scale inhibitor pill followed by 160 bbls 3% KCL FIW flush. Finished @ 0.8 bpm @ 3475 psi. RD BJ pumps. SI well for 24 hrs. http:// dor/rept_ workover. asp 11/21/2006 . ;[19 MGS C31-26RD Cook Inlet, Alaska Leg 1 Conductor 5 API No. 50-733-20052 Spud: Original Oct 1967 Sidetrack: Aug 2004 Surf Csg: 10 3/4", 40.5 Ib, J55. Set @ 1,895'. Cmt wI 1,600 sk. SOZ hole in 7" @ 3,440-71' wI 95 sk. (9-3-2004) Intermediate: 7" N80 BTC. Window Milled @ 7,291' Original Set @ 9,927'. 23# : 200 - 5,600' (200' was cut off) 26# : 5,600 - 8,100' 29# : 8,100 - 9,927' Cmt wI 1,350 sk. TOC by CBL @ 6,260' Longstring: 5" 18# P11 O. Set @ 10,093' Surf to 634' : STL 634 - 10,093' : Ultra FJ Cmt wI 384 sk. PBTD: 10,048' MD (9,622' TVD) , TD: 10,093' MD (9,666' TVD) ¡ . PLF 6-1-05 KB: 35' Water Depth: 73' MSL Tbg: 2-3/8" 4.7# L80 8rd EUE @ 9,630'. Set on 10-19-04 Item MD TVD Psc Pso Port GLM1 1905 1904 940 978 10 GLM2 3228 3225 940 974 10 GLM3 4337 4335 930 969 12 GLM4 5256 5203 920 950 12 GLM 5 5990 5906 910 929 12 GLM 6 6475 6368 900 918 12 GLM 7 6929 6795 890 910 12 GLM8 7414 7253 880 898 12 GLM 9 7931 7707 870 886 12 GLM 10 8477 8142 860 873 12 GLM11 9053 8660 850 858 12 GLM 12 9535 9118 ORIFICE 20 Tba hnar TOP is 2_718" RTS-6 wI 2_318" 8rd BTM X-over 2-7/8" RTS-6 Pin X 2-3/8" 8rd Box @ 34' 6' Pup Jt 2-3/8" 4.7# L80 8rd EUE @ 294' Baker T5 SSSV (1.875" ID) @ 301' 4' Pup Jt 2-3/8" 4.7# L80 8rd EUE @ 305' 2-3/8" X Nipple (1.875") 9Cr @ 9,576' 6' Pup Jt 2-3/8" 4.7# L80 8rd EUE @ 9,578' 5" Baker FH Rtr Pkr @ 9,584' 8' Pup Jt 2-3/8" 4.7# L80 8rd EUE @ 9,589' 2-3/8" X Nipple (1.875") 9Cr @ 9,597' 1 Jt 2-3/8" 4.7# L80 8rd EUE @ 9,598' WLREG @ 9,630' HN: 9,729 -9,741' (24 holes) / HN: 9,740 -9,790' (150 holes) Frac'd 63k# HN: 9,791 -9,819' (56 holes) HR: 9,846 -9,886' (82 holes) HR: 9,890 -9,940' (150 holes) Frac'd 20k# HR: 9,941 -9,947' (12 holes) HR: 9,963 -9,981' (36 holes) 1 Of ~(v')ó\~ DATA SUBMITTAL COMPLIANCE REPORT 10/13/2006 Permit to Drill 2041400 Well Name/No. MGS C31-26RD Operator XTO ENERGY INC 5¡...¿ g ¥ ~L{ API No. 50-733-20052-01-00 MD 10093 /' TVD 9666 /' Completion Date 1 0/19/2004 ~. Completion Status 1-01L Current Status 1-01L UIC N ~~~~ --- REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes DATA INFORMATION Types Electric or Other Logs Run: Gamma Ray, Resistvity, Compensated Neutron Well Log Information: (data taken from Logs Portion of Master Well Data Maint Log/ Data Ty D Electr Digital Dataset Med/Frmt Number Name C Dls 12878 Induction/Resistivity Log Log Scale Media Run No Interval OH / Start Stop CH 7301 10194 Open . _._-~.------- Received Comments 11/17/2004 Array Induction GR Litho- I Density Compensated Neutron DUS files MD & I TVD .pds graphics included Well Cores/Samples Information: Name Interval Start Stop Sent Received Sample Set Number Comments ADDITIONAL INFOR~~. ION Well Cored? Y ~ Chips Received? ~ Formation Tops lðN (fJN Daily History Received? Analysis Received? ~ . Comments: ~ Compliance Reviewed By: Date: '1 J£J ~ t., i ."-.= . i. j' FRANK H. MURKOWSKI, GOVERNOR AI,ASIiA OIL AND GAS CONSERVATION COMMISSION 333 W. 7TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Jeff Gasch Production Engineer XTO Energy 200 North Loraine, Ste 800 Midland Texas 79701 Re: Middle Ground Shoal Field, Hemlock E, F, G Oil Pool, C31-26RD Sundry Number: 306-302 Dear Mr. Gasch: 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. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, DATED this~ day of September, 2006 Encl. . . ;[!~ XTO Energy Inc. 200 North Loraine Suite 800 Midland, Texas 79701 432-682-8873 432-687-0862 (Fax) September 5, 2006 Alaska Oil and Gas Conservation Commission Attn: Mr. John Norman 333 West 7th Ave., Suite 100 Þu1chorage,Alaska 99501 RECEIVED SEP 0 6 2006 RE: Request for Sundry Approval to acid stimulate well C31-26RD. Alaska Oil & Gas Cons. Commission Anchorage Dear Mr. Norman: .' XTO Energy, Inc. hereby submits its Application for Sundry Approval to acid stimulate well C31- 26RD on Platform C, in the Middle Ground Shoal Field of Cook Inlet. The treatment will be done using coil tubing. The well is an oil producer in the East Flank Hemlock reservoir. Please find attached the following information for your files: 1. Form 10-403 Application for Sundry Approval 2. Job Procedure 3. Present Wellbore Schematic Please contact me with any questions @ 432-620-6742. S?jM Jeff Gasch Production Engineer Cc: Scott Griffith Paul Figel Kameron Fivecoat . , 20 AAC 25.280 as a as Cons. " 0 1. Type of Request: Abandon D Suspend D Operational shutdown D Perforate D Waiver DAnchorage Other D Alter casing D Repair well D Plug Perforations D Stimulate 0 . Time Extension D Change approved program D Pull Tubing D Perforate New Pool D Re-enter Suspended Well D 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: XTO Energy Inc. Development 0 Exploratory D 204-140 . 3. Address: Stratigraphic D Service D 6. API Number: 200 North Loraine, Suite 800, Midland, Texas 79701 50-733-20052-01 . 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes D No 0 C31-26RD . 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ~'1'C >I- ADL-18756,; 105' Middle Ground Shoal Field ELPI i:" OU.. 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 10,093' . 9,666' . 10,D48' 9,622' None None Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,895' 10-3/4" 1,895' 1,894' 3,130 1,580 Intermediate 7,091' 7" 7,291' 7,139' 6,340 3,830 Production 1 0,093' 5" 10,093' 9,666' 13,940 13,450 Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 9,729' 9,310' 2-3/8" L80 9,630' Packers and SSSV Type: Baker 5" FH Retrievable Pkr / Baker T5 SSSV Packers and SSSV MD (ft): Pkr @ 9,584' / SSSV @ 301' 13. Attachments: Description Summary of Proposal 0 14. Well Class after proposed work: Detailed Operations Program D BOP Sketch D Exploratory D Development 0 Service D 15. Estimated Date for 10/2/2006 16. Well Status after proposed work: Commencing Operations: Oil 0 Gas D Plugged D Abandoned D 17. Verbal Approval: Date: WAG D GINJ D WINJ D WDSPL D Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Jeff Gasch Printed Name Jeff Gasch Title Production Engineer Signature ÇAt ~ Phone 432-620-6742 Date 9/5/2006 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: :?:i"1n..... .~~ Plug Integrity D BOP Test ~ Mechanical Integrity Test D Location Clearance D Other: :J 5000 ~~\ ßO\? ~7\- CJ..s. ~ \ ",\'\..v..-e , Subsequent Form Required: '-\OL\ -/ APPROVED BY ~ ~~ Approved by: ì / / V /""'''C.,'", I I THE COMMISSION Date: / / ~ ....... Form 10-403 Revised 06/20060 Rl GINA L '-Sft.~ l ð ~ KW¡Y J) ~ .....s6bmi~in ~te ~.Þ' .~ , o'. 1. 7ß STATE :::~AS'J8/b i RECEIVED AL. OIL AND GAS CONSERVATION COM.ION flëttc(; S E P 0 6 2006 APPLICATION FOR SUNDRY APPROVALS AI k 01 & G n /#? ;[tg . . XTO ENERGY INC. MGS C31-26RD EAST FLANK PRODUCER COOK INLET, ALASKA COIL TBG CLEANOUT, ACID STIMULATION & SCALE SQZ PROCEDURE WELL DATA: SURFACE CASING: 10-3/4",40.5#, J55. Set@ 1,895'. Cmt wi 1,600 sx. INTERMEDIATE CASING: 7",23,26 &29#, N80, BTC. Set @200'-7,291' (Window). LONGSTRING: 5",18#, PllO, STL & UFJ. Set@ 10,093'. Cmt wi 384 sx. PBTD: 10,048' PERFORATIONS: HN: 9,729-9,741' (24 holes) HN: 9,740-9,790' (150 holes) Frac'd 63k# HN: 9,791-9,819' (56 holes) HR: 9,846-9,886' (82 holes) HR: 9,890-9,940' (150 holes) Frac'd 20k# HR: 9,941-9,947' (12 holes) HR: 9,963-9,981' (36 holes) NET PAY: 204' TUBING: 2-3/8",4.7#, L80, 8rd EVE @ 9,630'. PACKER: 5" Baker FH retreivable pkr @ 9,584'. BHST: 165 Deg F BHP: 5,000 psi SMALLEST ill: 2-3/8" XNNipp1e: 1.875" ill @9,576' & 9,597'. MAX DEVIATION: 40 degrees from 7,993-8,200' PRESENT STATUS: Producing 40 BOPD, 240 BWPD OBJECTIVE: Clean out, acidize and scale squeeze well using Coil tbg. NOTES: · Acid to be tested wi oil sample that contains 500 ppm ferric iron (Fe3). · No acid is to be pumped into the production header system. A 250 bbl flowback PTS tank will be used to handle all acid returns. · AFE # 652855 Procedure 8-29-06 XTO Energy Inc. MGS C31-26RD Cook Inlet, Alaska . . 2 Materials Required: · 11,100 gal (264 bbl) 10% One Shot Plus HCL (mix acid w/ fresh water) · 1,100 bbl3% KCL FIW Water (Friction Reducer Supplied by BJ) ~ 1 gal/lOOO gal FRW-14 BJ Friction Reducer ~ 11,000 lbs KCL (1,000 lbs /100 bbl FIW for 3%) Supplied by MI · N2 bottles to purge reel after job · 2,000 lbs Soda Ash (Supplied by MI) · 40 bbl Gel Pill (3#/bbl Flo- Visc + 5 gall 1 00 bbl Greencide provided by MI) Equipment Required: · BJ 1 1/2" CTU: Install press gauges on CT, CT annulus and 2-3/8" tbg annulus. · 1 ea HP Triplex Pump · 500 bbl Plastic Lined Acid Tank (Supplied by R&K) · RotoJet wash tool · 250 bbl Flowback Tank ~ Mud Pump to be tied into tank to pump load to C44-14RD Disposal Well ~ Install 2" line for gas tied to header · Return line w/ choke manifold to 250 bbl Flowback Tank & to Production Header ~ Manifold to contain a sample catcher to monitor fluids pH ~ Send only "clean" returns to the Production Header ~ Send live acid and or fluids containing scale or solids to Flowback Tank · Have a H2S monitor @ the Flowback Tank Acid System to contain these additives: (Tests to be verified) · 10% One Shot Plus HCL (75:25 Acid/Xylene. Acid to be titrated on location.) · 15 gpt AS-6 Anti Sludge Agent · 8 gpt CI-27 Corrosion Inhibitor · 7 ppt F200 Iron Reducing Agent · 30 ppt F300 Iron Chelating Agent · 15 gpt AS-6 Anti-sludge Procedure 8-29-06 XTO Energy Inc. MGS C31-26RD Cook Inlet, Alaska PROCEDURE: . . 3 1. SD gas lift. 2. MIRU BJ 1.5" Coil tbg unit, riser, BOP's & Injector head. Contact AOGCC 24 hrs prior to BOP test. Press test BOP's to 5,000 psi. Test treating lìnes to 6,000 psi. Max press is 5,000 psi. MU Baker 1.69" OD Navi-Drill-X- Treme Motor assembly wi 1.80" drag bit. CTU operator to ensure all tools to be calipered before RIH. Smallest ID = 1.875" @ SSSV @ 301' & XN Nipples @ 9,576 & 9,598. 3. Hold safety meeting with all service & production personnel about the procedure, corrosive chemicals, and possible H2S exposure. 4. Open WH for circ. RIH wi coil tbg @ 40 fpm max down the tbg while pumping @ 1 BPM slick 3% KCL FIW. Send returns to PTS tame 5. Clean out tbg to the EOT @ 9630'. Primary scale buildup is @ ~8000', however, scale is likely present throughout the tbg string. Continue RIH to PBTD @ 10,048'. Circ hole clean wi 20 bbl Flo- Visc pill to surface followed with 90 bbl slick 3% KCL. Send all returns to the Flowback Tank. Pump load from PTS tank into disposal well C44-14RD. 6. POOH and lay down motor assembly and drag bit. 7. MU Rotojet wash tool to CT. Open WH for circulation. RIH wi coil tbg @25 fpm max down the tbg while pumping @ 1 BPM slick 3% KCL FIW. Slow tbg rate to 10 fpm while passing over each gas lift mandrel (see WBD). 8. Cont RIH @ 25 fpm to 9,729'. Slow tbg down to 10 fpm. Wash perfs wi slick 3% KCL @ 1.5 BPM while taking returns to the PTS tank. Tag PBTD @ 10,048'. Circ hole clean wi 20 bbl Flo- Visc pill to surface followed with 90 bbl slick 3% KCL. Send all returns to the Flowback Tank. ACID SPOT & SOAK: 9. Lay 6 bbl of acid/xylene from 10,048' to 9,729' while pulling up hole with coil tbg. Displace acid out of coil with 3% KCL. Pull up to 9,600' & maintain circulation. Let acid soak for 30 min. Have 2,000 lbs soda ash in PTS flowback tank. 10. Keeping the CT annulus open, RIH @ 40 fpm to 10,048' while circ slick 3% KCL to surface @ 1.5 BPM. Circ hole clean wi 50 bbl slick 3% KCL. Send all returns to the Flowback Tank. Pump load from PTS tank into disposal well C44-14RD. ACID WASH PERFS: 11. Keeping the CT annulus open, acid wash perfs wi 20 bbll 0% HCL @ 1 BPM while moving tool uphole @ 10 fpm. Make 1 pass at this rate covering perfs from 9,981 - 9,729' . 12. RIH @ 40 fpm to 10,048' while circ slick 3% KCL to surface @ 1.5 BPM. Circ hole clean wi 50 bbl slick 3% KCL. Do NOT mix any friction reducer (FRW-14) to the 3% KCL FIW beyond this step. Procedure 8-29-06 XTO Energy Inc. MGS C31-26RD Cook Inlet, Alaska ACID INJECTION JOB: 13. SI in the WHo Inj 10,000 gals (238 bbl) 10% HCL while making passes across the perfs from 9,981 - 9,729' while pumping @ 0.5 BPM and moving the coil tbg @ 10 ft/min. Maximize pump rate under 5,000 psi. . . 4 14. Finish pumping all acid @ 9,981'. Over-displace acid by injecting 50 bbl3% KCL (NO FRICTION REDUCER) @ ±0.5 BPM while making passes from 9,981- 9,729' @ 10 fpm. 15. Open the WHo POOH wi coil tbg @ 100 fpm. Close the swab valve. 16. Start up and adjust the gas lift rate to achieve adequate returns. Objective is to recover load of spent acid (+1- 290 bbls). Send returns to PTS tame Check pH periodically during flowback. SD gas lift after acid load has been recovered. SCALE INHIBITOR SOZ: 17. RIH wi CT @ 80 fpm to 9,729' while circ 3% KCL FIW @ 11 BPM. Spot NALCO scale inhibitor to the EOT. Close the CT annulus and squeeze perfs wi scale inhibitor @ 1 BPM while making passes wi CT @ 10 fpm. Overflush scale inhibitor 3% KCL FIW per NALCO's recommendation while making passes across perfs. (Note: Chemical and overflush volume is still being determined by NALCO.) 18. Open the WHo POOH wi coil tbg @ 100 fpm. Close the swab valve. 19. Purge the CT reel wi N2. RD BJ coil tbg unit. 20. SD per NALCO's recommendation. Leave Flowback tank rigged up while well is producing acid load. 21. Start up gas lift slowly as to what the PTS tank can handle. Flow load back to PTS tank. Once load is recovered & fluid is acceptable, turn well to the header system and put well in test. Monitor the well for ±3 days taking readings every other hour. Put well back into regular test rotation after 3-4 days. Record any use of the disposal well with fluid type, volume and injection rates & press. Overflush by 125 bbl FIW at end of disposing fluids. Procedure 8-29-06 }[!~ MGS C31-26RD Cook Inlet, Alaska Leg 1 Conductor 5 API No. 50-733-20052 Spud: Original Oct 1967 Sidetrack: Aug 2004 . Surf Csg: 103/4",40.5 Ib, J55. Set @ 1,895'. Cmt wI 1,600 sk. SOZ hole in 7" @ 3,440-71' wI 95 sk. (9-3-2004) Intermediate: 7" N80 BTC. Window Milled @ 7,291' Original Set @ 9,927'. 23# : 200 - 5,600' (200' was cut off) 26# : 5,600 - 8,100' 29#: 8,100 - 9,927' Cmt w/1 ,350 sk. TOC by CBL @ 6,260' Longstring: 5" 18# P110. Set @ 10,093' Surf to 634' : STL 634 - 10,093' : Ultra FJ Cmt wI 384 sk. PBTD: 10,048' MD (9,622' TVD) TD: 10,093' MD (9,666' TVD) Current ComDletion . PLF 6-1-05 KB: 35' Water Depth: 73' MSL Tbg: 2-3/8" 4.7# L80 8rd EUE @ 9,630'. Set on 10-19-04 Item MD TVD Psc Pso Port GLM 1 1905 1904 940 978 10 GLM2 3228 3225 940 974 10 GLM3 4337 4335 930 969 12 GLM4 5256 5203 920 950 12 GLM5 5990 5906 910 929 12 GLM6 6475 6368 900 918 12 GLM7 6929 6795 890 910 12 GLM8 7414 7253 880 898 12 GLM9 7931 7707 870 886 12 GLM 1 0 8477 8142 860 873 12 GLM 11 9053 8660 850 858 12 GLM 12 9535 9118 ORIFICE 20 Tba hnar TOP is 2-718" RTS-6 wI 2-318" 8rd BTM X-over 2-7/8" RTS-6 Pin X 2-3/8" 8rd Box @ 34' 6' Pup Jt 2-3/8" 4.7# L80 8rd EUE @ 294' Baker T5 SSSV (1.875" ID)@ 301' 4' Pup Jt 2-3/8" 4.7# L80 8rd EUE @ 305' 2-3/8" X Nipple (1.875") 9Cr @ 9,576' 6' Pup Jt 2-3/8" 4.7# L80 8rd EUE @ 9,578' 5" Baker FH Rtr Pkr @ 9,584' 8' Pup Jt 2-3/8" 4.7# L80 8rd EUE @ 9,589' 2-3/8" X Nipple (1.875") 9Cr @ 9,597' 1 Jt 2-3/8" 4.7# L80 8rd EUE @ 9,598' WLREG @ 9,630' / HN: 9,729 -9,741' (24 holes) HN: 9,740 -9,790' (150 holes) Frac'd 63k# HN: 9,791 -9,819' (56 holes) HR: 9,846 -9,886' (82 holes) HR: 9,890 -9,940' (150 holes) Frac'd 20k# HR: 9,941 -9,947' (12 holes) HR: 9,963 -9,981' (36 holes) " , . 2-0<{-- /t{ð · ;{t9 XTO Energy Inc. 200 North Loraine Suite 800 Midland, Texas 79701 432-682-8873 432-687-0862 (Fax) November 16, 2004 Alaska Oil and Gas Conservation Commission Attn: Mr. John Norman 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Well Completion Report: Well C31-26RD Dear Mr. Norman, XTO Energy, Inc. hereby submits its Well Completion Report (Form 10-407) for the re-drill performed for the C31-26RD on Platform C, in the Middle Ground Shoal Field of Cook Inlet, AK. The well was completed in the Hemlock HN & HR zones. A two stage fracture treatment was performed in two 50' perforated intervals over the ±400' gross pay. After the wellbore was cleaned out, the blank sections of the pay zones were then perforated for additional exposure. Please find attached the following information for your files: 1. Form 10-407 Well Completion 2. Daily Drilling Reports 3. Present Wellbore Schematic 4. Well Surveys 5. OH Logs: GR, Resistivity, Porosity Logs (CD format) If you have any questions or require additional information, please contact me at (432) 620-6743. Sincerely, ?.-...f ;l . ç;p Paul L. Figel Engineering Manager Cc: Doug Marshall Tim Smith ORIGINAL , STATE OF ALASKA ALAS"IL AND GAS CONSERVATION COMM~N WELL COMPLETI~ OR RECOMPLETION ~ORT AND LOG 1a. Well Status: Oil~ GasU Plugged U Abandoned 0 Suspended 0 WAG 0 1 b. Well Class: 20AAC 25.105 20AAC 25.110 Development 0 Exploratory 0 GINJD WINJD WDSPL 0 No. of Completions 1 Other Service 0 Stratigraphic Test 0 2. Operator Name: 5. Date Comp., Susp., or , 12. Permit to Drill Number: XTO Energy Inc. Aband.: Com: 10/19/0~ 204-140 3. Address: 6. Date Spudded: 13. API Number: 200 North Loraine, Suite 800, Midland, Texas 79701 September 8, 2004 50-733-20052-01 4a. Location of Well (Governmental Section): Platform C, Leg 1 7. Date TD Reached: 14. Well Name and Number: Surface: Cond 5, 537' FSL, 1593' FEL, Sec 23, T8N, R13W, S.M. September 26, 2004 C31-26RD Top of Productive Horizon: 8. KB Elevation (ft): 15. Field/Pool(s): 1529' FNL, 1875' FEL, Sec 26, T8N, R13W, S.M. 105' Middle Ground Shoal Field Total Depth: 9. Plug Back Depth(MD+ TVD): 1529' FNL, 1951' FEL, Sec 26, T8N, R13W, S.M. 10,048' + 9622' 4b. Location of Well (State Base Plane Coordinates): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 231363· y- 2474225 , Zone- AK4 10,093' + 9666' , ADL-18756 , TPI: x- 231033 y- 2472165 Zone- HN 11. Depth Where SSSV Set: 17. Land Use Permit: Total Depth: x- 230957 ' y- 2472167' Zone- HR 301' 18. Directional Survey: Yes ~ No U 19. Water Depth, if Offshore: 20. Thickness of Permafrost: 73 feet MSL 21. Logs Run: Gamma Ray, Resistvity, Compensated Neutron -r/IJ¡ ;"'d""k) .~ Z-") I ' ,/7'/ Z> S1> TI-3'iì'/Y'b II· 2.tf.t:>,/ 22. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD CEMENTING RECORD AMOUNT CASING FT. GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE PULLED 1 0-3/4" 40.5 J55 Surf 1895' Surf 1894' 15" 1600 sxs 7" 23,26,29 N80 200' 7291' 200' 7139' 9-7/8" 1350 sxs· 200' 5" 18 P110 Surf 10093' Surf 9666' 6" 384 sxs 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET (MD) HN: 9729-9741' MD (9310-9321' TVD) 24 holes 2-3/8" 9630' 9584' HN: 9740-9790' MD (9320-9369' TVD) 150 holes HN: 9791-9819' MD (9370-9398' TVD) 56 holes 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. HR: 9846-9886' MD (9424-9463' TVD) 82 holes DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED HR: 9890-9940' MD (9467-9516' TVD) 150 holes HR: 9941-9947' MD (9517-9523' TVD) 12 holes 9740' - 9790' Frac w/63,000# Bauxite HR: 9963-9981' MD (9539-9556' TVD) 36 holes 9890' - 9940' Frac w/20,000# Carbolite 26. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): October 20, 2004 Gas lift Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: I ~as-Oil Ratio: 11/12/2004 12 Test Period ..... 32.5 46.5 261.5 2" 1431 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity - API (corr): Press. 80 680 24-Hour Rate .... 65 93 523 28.5 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". None rrÔi'7;:!';:~',\, . ¡ - :. . . .,.;. ¡,'.. I '-..J ~\ I;, RBDMS BFL NOV 2 9 2004 .. ';þ'¡\" .- f 1.Q~i~_t?¡s' V~ ¿OO4 I ,,,-,,, '-"-'0 , ORIGINAL t~ \ j - -----. , ""'''-'''.''~ ~."",...,,_........,.,,~._J " «'f'O" GÎ:: Form 10-407 Revised 12/2003 CONTINUED ON REVERSE 28. GEOLOGIC MARK 29. TION TESTS NAME TVD Include and briefly summarize test results. List intervals tested, and GN 8566 8218 attach detailed supporting data as necessary. If no tests were conducted, state "None". GO 8621 8267 None GR 8920 8536 GS 8966 8579 HC 9200 8798 HD 9275 8870 HE 9324 8917 HF 9400 8989 HI 9453 9040 HK 9518 9103 HN 9660 9242 HR 9828 9407 9985 9560 30. List of Attachments: CD of GR. Array Induction. CNL. Schematic. Morning Re orts and Survey Data 31. Contact Enai neeri na Manaqer Signature Phone 432 - 620 - 6743 Date 11/16/04 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service Wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. . Item 4b: TPI (Top of Producing Interval). Item 8: the Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 17: Used for Exploration wells only. Provide the permit number or ID issued by the landowner for surface operations (DNR, BLM, MMS, CIRI,ARSC, etc.). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 7/2003 . . 1 XTO Energy Inc. C31-26RD Daily Well Report Objective: Drill Sidetrack 8/28/04 ND Tree @ 0', MW 12.3, Vis 45, PV 12, YP 27, Gels 8/12, pH 10.0, WL 8.0, Cake 1.0, Alk 0.6, CI16,000, Ca 1,400, Solids 16.0, Added 2sx caustic soda, 20sx Flo-Vis Plus, 1,980 Mi- Bar, 9sx Polypac Supreme UL. Circ 7-1/2 hrs, Build Mud Vol/Wt 7-1/2 hrs, Circ out Kick on Choke 7 hrs, NU/ND Tree 1 hr, Monitor WeIll hr. Built mud vol & weighted up pit vol. Disp well w/FIW. Taking rtns to production. Pmpd @ 1 BPM. Monitored well, 900 psi SIP. Circ 12.3 ppg mud dwn tbg. Disp well to prod @ 1 BPM. Circ thru choke to pits. Monitored well. Set BPV. Std to ND tree. 8/29/04 Testing BOP's @ 0', MW 12.3, Vis 45, PV 12, YP 27, Gels 8/12, pH 10.0, WL 8.0, Cake 1.0, Alk 0.6, CI16,000, Ca 1,400, Solids 16.0. NU/ND BOP/Diverter 18 hrs, NU/ND Tree 4 hrs, Testd BOPS/Diverter 2 hrs. ND tree. Set riser. NU BOPE & flowline. RU to press tst BOPE to 250-1,000 psi. 8/30/04 LD 3-1/2" Tbg @ 0', MW 12.3, Vis 45, PV 12, YP 27, Gels 8/12, pH 10.0, WL 8.0, Cake 1.0, Alk 0.6, CI16,000, Ca 1,400, Solids 16.0. LDIPU Drill Pipe/Tbg 10-1/2 hrs, Test BOPS/Diverter 6 hrs, Perf'd 3-1/2 hrs, RU/RD Service Tools 2 hrs, Circ 2 hrs. Press tstd BOPS to 250-1,000 psi (John Crisp w/AOGCC waived witnessing the BOP tst). Pulled BPV. Backed out tbg hgr lock dwn studs. Pulled tbg hgr out of tree. Attempted to reI pkr w/60K over pull (no success). Circ tbg, well taking fluid. RU APRS WL. Rill w/jet cutter. , Cutter stopped @ 7,872'. Shot jet cutter & cut tbg @ 7,849' (WLM). POOH wlWL. Left jet cutter tool string in hole (23). RD APRS WL. RU Weatherford tongs, ramp, catwalk & pipe rack. Std TOOH LD 3-1/2", 9.3#, 8rd, L-80 tbg. 8/31/04 Rill wIT' Csg Scraper @ 0', MW 11.4, Vis 40, PV 12, YP 28, Gels 12/15, pH 10.0, WL 8.2, Cake 1.0, Alk 0.6, CI16,000, Ca 1,400, Solids 12.5, Added 14sx Flow-Vis Plus, 770sx Mi- Bar & 4sx Polypac Supreme UL. LDIPU Drill Pipe/Tbg 16-1/2 hrs, Other 4-1/2 hrs, PU/LD BRA & Tools 2 hrs, Circ 1 hr. Fin LD 254 jts of 3-1/2" tbg. Ck'd for norm. Lots of scale on btm 1,000'. Cleaned scale off of rig floor. RD tbg tongs. Back loaded boat w/tbg & misc items. Set wear ring. PU 7" csg scraper w/6" bit & 2 - 4-3/4" DC's. PU & Till w/3-1/2", 15.50#, S-135 DP. Circ hole @ 6,400'. Cont'd Till & PU 3-1/2" DP. 9/1/04 PU Isolation Pkr For Csg Tst @ 0', MW 11.1, Vis 42, PV 11, YP 28, Gels 10/13, pH 10.0, WL 9.0, Cake 2.0, Alk 0.6, CI16,000, Ca 1,200, Solids 12.5, Added 2sx Flow-Vis Plus, 220sx Mi-Bar, Isx Polypac Supreme UL & Isx Soda Ash. Trip 12 hrs, Circ 4 hrs, Slip & Cut Drill Line 2 hrs, Press Inject/Lot/Fit 2 hrs, LDIPU Drill Pipe/Tbg 1-1/2 hr, W & R 1 hr, Tstd Csg 1 hr, Serviced Rig 1 hr. TIH wIT' csg scraper. PU 3-1/2" DP. Washed fr 7,787'- 7,850'. Circ btms up. Mixed & pmpd dry job. TOOH wIT' csg scraper. RIH w/Baker drillable cmt retainer. Circ thru retainer. Set retainer @ 7,839'. Pulled out of retainer & circ above retainer. Held pre-job safety mtg. Stung into retainer. Attemted to establish an inj rate. Press up twice to 4,000 psi, could not establish inj. Repeated process @ 5,000 psi, . . 2 could not establish inj. Closed pipe rams. Press tstd csg above retainer w/BJ pmps. Established inj rate into csg lk@ 0.5 BPM @ 720 psig, 1 BPM @ 790 psi, 1.5 BPM @ 900 psi. Opened rams & circ above retainer. Slipped & cut drlg line. Serviced rig. TOOH LD Baker retainer running tool. PU Baker isolation pkr. 9/2/04 Prep To Spot Cmt Plug @ 7,839', MW 11.0, Vis 39, PV 8, YP 17, Gels 5/7, pH 9.5, WL 10.0, Cake 2.0, Alk 0.4, CI16,000, Ca 1,200, Solids 12.0, Added 24sx Durogel. Trip 10 hrs, Circ 9 hrs, Tstd Csg 3-1/2 hrs, Cmt'd 1 hr, PU/LD BRA & Tools 1/2 hr. RIH w/Baker isolation pkr to 3,720'. Press up below pkr to 1,000 psi. Injected above pkr @ 1 BPM & 400 psi. Std moving pkr up hole & tstg csg. Hole was isolated between 3,440'-3,471'. TOOH wlisolation pkr. LD Baker isolation pkr. PU 3-1/2" muleshoe. TIH w/3-1/2" DP to 7,839'. Circ hole. Prep to spot cmt plug on top of retainer @ 7,839' per AOGCC instructions. Held pre-job safety mtg. Tstd lines to 2,000 psi. Std mixing cmt. Mixing pmp cplg broke on BJ unit. Parts to be on 1st chopper in the a.m. Circ well. Unloaded boat. Cleaned cellar & lwr deck. Working on drains to production. 9/3/04 RIH W/Clean Out Assembly @ , MW 10.7, Vis 31, PV 5, YP 12, Gels 2/3, pH 8.5, WL 15.0, Cake 3.0, CI15,000, Ca 2,500, Solids 9.0, Oil 0.5, Added 6sx bicarbonate of soda, 20sx citric acid & 36sx Durogel. Circ 9-1/2 hrs, Trip 8-1/2 hrs, Cmt Plug 4 hrs, Service Rig 1 hr, PU/LD BRA & Tools 1 hr. Circ well. Worked on drains to production. Relp cplg on BJ's cmt mixing pmp. Held pre-job safety mtg. Pmpd 8 BFW, press tstd lines to 2,000 psi, tstd OK. Cmt retainer @ 7,839' (could not inj below retainer). Batch mixed & pmpd 76sx (15.5 bbls) of CI "G" cmt containing 0.3% CD-32, 0.25% R3 & 0.05% FL63. Disp w/2 BFW & 45 bbls mud. Cmt in place @ 11:45 a.m. 9/2/04. POOH to 7,333'. Circ btms up @ reduced rate, monitored rtns. Fin TOOH. PU & TIH w/cmt retainer. Set retainer @ 3,503'. C & C mud for cmt job. Held pre-job safety mtg. Sqz'd csg lk @ 3,440'-3,471' w/95sx (18.6 bbls) of CI "G" cmt containing 0.4% CD-32, 1 % CaCl2 & 1 GPS FP (16.2 ppg, 1.10 cuft/sx). Disp w/2 BFW & 16.3 bbls mud. CIP @ 0030 hrs 9/3/04. Press climbed to 860 psi during cmt placement, dropped to 300 psi & stabilized. TOOH to 2,911'. Circ DP vol. Closed rams & BJ sqz'd 12.5 bbls of cmt. Circ to clean pipe, monitored rtns. TOOH & LD setting tool. PU clean out assembly. TIH w/clean out assembly. 9/4/04 Circ w/Scraper Assembly @ 7,350', MW 10.9, Vis 34, PV 7, YP 9, Gels 2/3, pH 11.0, WL 15.0, Cake 3.0, Alk 6.0, CI15,000, Ca 2,500, Solids 10.0, Oil 0.5, Added 60sx Barite & 22sx citric acid. Trip 10-1/2 hrs, Other 5 hrs, WO Cmt 4-1/2 hrs, Circ 3-1/2 hrs, Tstd Csg 1/2 hr. TIH w/clean out assembly to 2,910'. Circ & WOC. Cleaned pits & trip tnk. Cleaned out turbos on 398 top drive CAT, organized decks. TIH & tagged cmt @ 3,360'. Drld cmt. Hard cmt fr 3,394'-3,500'. Circ btms up. Press tstd csg to 500 psi for 30 min, tstd OK. Cont'd drg cmt & cmt ret fr 3,500'-3,505'. Washed dwn to 3,595'. Circ btms up. TIH w/clean out assembly. Tagged up @ 7,330'. Washed dwn fr 7,330'-7,427'. At 7,427', cmt held 15,0000# wt & confirmed cmt plug. Circ btms up. TOOH w/clean out assembly. PU 7" scraper assembly & TIH to 7,350'. Circ btms up. 9/5/04 Build Mud, Rig Up J-Tube, MW 8.5, Vis 27, CI16,000, Added Isx Clean Up. Circ 18 hrs, Build Mud VollWt 6 hrs. Circ hole. Prep & inject old mud. Cleaned pits. Build new mud. Cleaned out mud line. Removed cuttings augger. RU J-tube. 9/6/04 Testing BOPS, MW 9.5, Vis 45, PV 17, YP 24, Gels 8/12, pH 9.0, WL 5.4, Cake 2.0, Alk . . 3 0.6, CI12,000, Ca 120, Solids 6.0, MBT 5.0, Added 380sx Barite, 2sx bicarbonate of soda, 12sx FIo-Vis, 40sx Mi Gel, 12sx Polyac, 24sx Resinex & 4sx soda ash. Build Mud VollWt 12-1/2 hrs, Test BOPS/Diverter 6-1/2 hrs, Disp 3 hrs, Trip 2 hrs. Mixed new mud. RU J- tube. Disp hole w/9.5 ppg mud. TOOH w/c1ean out assembly. Pulled wear ring. RU test assembly. Press tstd BOPS/Hydrill to 250-2,500 psi, rams & valves to 250-5,000 psi. Chg'd door seal on BOP. 9/7/04 POOH wlWindow Mills @ 7,315', MW 9.5, Vis 78, PV 20, YP 41, Gels 14/20, pH 9.0, WL 5.4, Cake 2.0, Alk 0.4, CI12,000, Ca 90, Solids 6.0, MBT 6.0, Added 20sx Bore-Plate, lOsx Flo- Vis & 2sx soda ash. Mill/Cut Sect or Window 9 hrs, Other 5 hrs, Trip 5 hrs, PU/LD BHA & Tools 2 hrs, Circ 1 hr, Orient Tool Face 1 hr, Tst BOPS/Diverter 1 hr. Fin tstg BOPS. Tstd gas alarms & accumulator. Set wear ring. RD tst assembly. RU APRS WL. Held pre-job safety mtg. PU bridge plug. RIH wlbridge plug on WL. Set bridge plug @ 7,296'WLM. RD WL. PU Baker Oil tools whipstock assembly. Oriented face w/MWD & UBHO sub. Surf tstd MWD. Rill w/whipstocck to 7,255'. Oriented whipstock face 40 deg right while working dwn bridge plug. Tagged bridge plug @ 7,309'DP measurement. Set anchor & sheared off whipstock. Milled window fr 7,291'-7,315'. Circ btms up. Ck'd flow. - Pmpd dry job. Std TOOH w/window mill assembly. 9/8/04 Slide Drlg @ 7,407' (92'/24 hrs), MW 9.5, Vis 54, PV 17, YP 28, Gels 10/17, pH 8.7, WL 5.8, Cake 2.0, Alk 0.4, CI13,OOO, Ca 100, Solids 6.0, MBT 6.0, Added 70sx Barite, 2sx Polypac & 3sx soda ash, Bit #1,6", Smith MA74PX, SN# JT2284, Bit/Nozzles 16/16/16, In @ 7,315' (92'/12-1/2 hrs), ROP 7.36, WOB 20K, RPM 80, PP 2,300#, SPM 90, GPM 269, Liner Size 5-1/2" x 10". Slide Drlg 10-1/2 hrs, PU/LD BHA & Tools 5 hrs, Trip 5 hrs, Drlg 2 hrs, LD/PU Drill Pipe/Tbg 1 hr, Orient Tool Face 1/2 hr. TOOH w/window mill assembly. Ckd mills. LD mill asssembly. Till & LD steel DC's. PU BHA w/Bit #1. Surface tstd MWD. PU HWDP. Till w/Bit #1. Oriented tool face. Worked bit thru window fr 7,291'- 7,304'. Washed & reamed to 7,315' (TD). Drld fr 7,315'-7,407'. 9/9/04 Drlg @ 7,598' (191 '/24 hrs), Surveys: 20.78 deg @ 7,400' (187.52 deg Azimuth, 7,241' TVD) & 24.44 deg @ 7,530' (208.50 deg Azimuth, 7,361' TVD), MW 9.5, Vis 54, PV 17, YP 26, Gels 10/16, pH 9.1, WL 6.0, Cake 2.0, Alk 0.6, CI14,000, Ca 80, Sd.2, Solids 7.0, MBT 6.0, Added 40sx Barite, 5sx Bore-Plate, 4sx FIo-Vis, 7sx Polypac, lOsx Resinex & 8sx Soda Ash, Bit #1, In @ 7,315' (283'/32-1/2 hrs), ROP 8.71, WOB 20K, RPM 357, PP 2,300#, SPM 90, GPM 269, Liner Size 5-1/2" x 10". Slide Drlg 15-1/2 hrs, Drlg 4-1/2 hrs, Rig Repair 4 hrs. Drld fr 7,404'-7,465'. Rig repair (replaced fuel filters on top drive 398 CAT). Drlg fr 7,465'-7,504'. Pulled 3 stands into window. Worked on top drive. Removed & CO turbos. Chg'd oil & oil filters. Re-installed turbos. Rill w/3 stands & oriented TF. Drld fr 7,504'-7,598'. 9110/04 Rotary Drlg @ 7,860' (262'/24 hrs), Surveys: 27.50 deg @ 7,622' (209.06 deg Azimuth, 7,444' TVD) & 31.20 deg @ 7,808' (199.10 deg Azimuth, 7,607' TVD), MW 9.5, Vis 55, PV 19, YP 27, Gels 8/10, pH 9.5, WL 5.9, Cake 2.0, Alk 0.6, CI15,000, Ca 80, Sd .2, Solids 7.0, MBT 7.5, Added 6sx Bore-Plate, 2sx Caustic Soda, 6sx Polypac, 14sx Resinex & 6sx Soda Ash, Bit #1, In @ 7,315' (545'/56-1/2 hrs), ROP 9.65, PP 2,400#, SPM 88, GPM 263, Liner Size 5-1/2" x 10". Slide Drld 16-1/2 hrs, Drld 7-1/2 hrs. Drld fr 7,598'-7,860'. 9/11/04 Drilling @ 8,165' (305'/24 hrs), MW 9.6, Vis 51, PV 18, YP 24, Gels 7/9, pH 9.7, WL 6.0, . . 4 Cake 2.0, Alk 0.6, Cl15,000, Ca 80, Sd .25, Solids 8.0, MBT 10.0, Added 50sx Barite, 7sx Bore-Plate, 3sx Caustic Soda, 6sx Polypac, 14sx Resinex & 3sx Soda Ash, Bit #1, In @ 7,315' (850'/78 hrs), ROP 10.90, WOB lOK, RPM 264, PP 2,400#, SPM 90, GPM 269, Liner Size 5-1/2" x 10". Drld 12 hrs, Slide Drld 9-1/2 hrs, Circ 1 hr, Trip 1 hr & Service Rig 1/2 hr. Drld fr 7,860'-8,049'. Circ btms up. Ck'd for flow & pmpd pill. Short tripped up into window, smooth. Serviced rig & top drive. TIH to btm. Oriented TF. Drld fr 8,049'-8,165'. 9/12/04 TIH w/Bit #2 @ 8,190' (25'/24 hrs), MW 9.5, Vis 51, PV 20, YP 24, Gels 6/7, pH 9.5, WL 5.8, Cake 2.0, Alk 0.6, Cl14,000, Ca 100, Sd .25, Solids 7.0, MBT 10.0, Added 60sx Barite, 4sx Bore-Plate, 2sx Caustic Soda, 3sx Polypac & 7sx Resinex, Bit #1, In @ 7,315', Out @ 8,190', (875'/85-1/2 hrs), ROP 10.23, WOB lOK, RPM 264, PP 2,400#, SPM 90, GPM 269, Liner Size 5-1/2" x 10", Bit #2,6", SEC FM2643, SN# 5013392, Bit Nozzles 14/14/14, In @ 8,190'. Drld 7-1/2 hrs, Trip 5-1/2 hrs, Tstd BOPS/Diverter 4 hrs, LD/PU Drill Pipe/Tbg 3 hrs, PU/LD BHA & Tools 3 hrs & Circ 1 hr. Rot drld fr 8,165'-8,190'. Circ btms up. Ck'd for flow, pmpd pill. TOOH w/Bit #1. LD bit, mtr, stab & MWD. Pulled wear ring. RU tst asssembly. Press tstd BOP's to 250-5,000 psi, tstd OK. Tstd gas alarms & koomey. Set wear ring. RD tst assembly. PU 63 jts of 3-1/2" DP & pmpd through same. POOH & stood back DP. PU Bit #2, mtr, pony collar, MWD & pulser. Surf tstd MWD. TIH w/Bit #2. 9/13/04 Slide Drlg @ 8,415' (225'/24 hrs), Surveys: 40.28 deg @ 8,181' (198.50 deg Azimuth, 7,902 TVD), 36.49 deg @ 8,270' (201.39 deg Azimuth, 7,972' TVD), MW 9.6, Vis 52, PV 20, YP 23, Gels 6/8, pH 9.5, WL 5.6, Cake 2.0, Alk 0.6, Cl13,OOO, Ca 100, Sd .25, Solids 7.0, MBT 12.5, Added 6sx Bore-Plate, 4sx Polypac & 7sx Resinex, Bit #2,6", SEC FM2643, SN#5013392, Bit Nozzles 14/14/14, In @ 8,190' (225'/18 hrs), ROP 12.50, WOB 5K, RPM 266, PP 2,700#, SPM 85, GPM 254, Liner Size 5-1/2" x 10". Drld 10 hrs, Slide Drld 8 hrs, Trip 3 hrs, Slip & Cut Drill Line 1-1/2 hr & Service Rig 1-1/2 hr. TIH w/Bit #2 to window. Filled pipe @ 4,000' & @ window. Serviced rig & top drive. TIH to btm. Drld fr 8,190'- 8,415'. 9/14/04 Rot Drlg @ 8,678' (263'/24 hrs), Surveys: 34.77 deg @ 8,365' (197.88 deg Azimuth, 8,049 TVD), 33.35 deg @ 8,457' (199.85 deg Azimuth, 8,126' TVD), 29.36 deg @ 8,550' (199.96 deg Azimuth, 8,205' TVD), MW 9.6, Vis 53, PV 20, YP 24, Gels 5/10, pH 9.7, WL 5.6, Cake 2.0, Alk 0.7, Cl12,500, Ca 100, Sd .25, Solids 7.0, MBT 12.5, Added 1l0sx Barite, 8sx Bore-Plate, 2sx caustic soda, 2sx Flo- Vis, 4sx Polypac & 6sx Resinex, Bit #2, In @ 8,190' (488'/42 hrs), ROP 11.62, WOB lOK, RPM 267, PP 2,700#, SPM 85, GPM 254, Liner Size 5-1/2" x 10". Drlg 14-1/2 hrs, Slide Drlg 9-1/2 hrs. Drld fr 8,415'-8,678'. 9/15/04 Circ Btms Up To Work On 398 CAT @ 8,835' (157'/24 hrs), Surveys: 27.58 deg @ 8,643' (200.04 deg Azimuth, 8,287 TVD), 26.39 deg @ 8,735' (200.37 deg Azimuth, 8,369' TVD), MW 9.7, Vis 56, PV 21, YP 24, Gels 5/12, pH 9.6, WL 5.5, Cake 2.0, Alk 0.7, Cl13,OOO, Ca 100, Sd .25, Solids 8.0, MBT 15.0, Added 160sx Barite, 5sx Bore-Plate, 2sx caustic soda, lsx Flo- Vis, 3sx Polypac & 4sx Resinex, Bit #2, In @ 8,190' (645'/56 hrs), ROP 11.52, WOB lOK, RPM 266, PP 2,700#, SPM 85, GPM 254, Liner Size 5-112" x 10". Drlg 12-1/2 hrs, Rig Repair 6-1/2 hrs, Circ 1-1/2 hr, Slide Drlg 1-1/2 hr, Trip 1-1/2 hr, Service Rig 1/2 hr. Rot drld fr 8,678'-8,8,691'. Circ btms up. Ckd for flow. Pmpd pill. POOH to window (smooth). Serviced rig & top drive. Rig repair (top drive CAT: cleaned out turbos, chg'd out 2 fuel nozzles). TIH. Washed 90'to btm. Rig repair (top drive CAT died). Trouble shot fuel system. Bled out air & chg'd fuel filter. Drld fr 8,691 '-8,835'. Circ btms up. Prep to . . 5 TOOH to window to work on top drive CAT. Turbo plugging & oil press dropping. 9/16/04 SD for Repairs to Top Drive CAT @ 8,835', Miss (lm), MW 9.7, Vis 56, PV 17, YP 20, Gels 5/9, pH 9.5, WL 5.6, Cake 2.0, Alk 0.6, ClI3,000, Ca 100, Sd .25, Solids 8.0, MBT 15.0. Added 100sx Barite, Isx Caustic Soda, lOsx Durogel, Bit #2, In @ 8,190' (645'/56 hrs), ROP 11.52, PP 2,700#, SPM 85, GPM 254, Liner Size 5-1/2" x 10". Rig Repair 22-1/2 hrs, Trip 1 hr & Circ 1/2 hr. Circ btms up, ck'd for flow, pmpd pill. POOH to window (smooth). Monitored well. Trouble shooting top drive 398 CAT. Removed & CO turbo, chg'd oil & oil filters, ck'd & set valve lash. Found burnt exhaust valve on #6 cylinder. Pulled ahead. Found cylinder liner washed out. Prep to chg cylinder package. Parts arrived early this morning. Brought out first chopper. 9/17/04 Drlg @ 8,880' (45'124 hrs), Miss Lm, Survey: 26.39 deg @ 8,735' (200.37 deg Azimuth, 8,369' TVD), MW 9.8, Vis 58, PV 23, YP 24, Gels 6/10, pH 9.3, WL 5.5, Cake 2.0, Alk 0.5, Cl13,OOO, Ca 100, Sd.3, Solids 8.0, MBT 17.5, Bit #2, In @ 8,190' (690'/61-1/2 hrs), ROP 11.22, WOB 12K, RPM 80, PP 2,750#, SPM 80, GPM 239, Liner Size 5-1/2" x 10". Rig Repair 16-1/2 hrs, Drlg 4-1/2 hrs, Slide Drlg 1 hr, Trip 1 hr, W & R 1 hr. Rig repair (top drive 398 CAT). TIH fr above window to 8,693'. W & R to btm. Circ btms up (2,600 units of gas on btms up). Drlg 8,835'-8,880'. 9/18/04 Drlg 6" Hole @ 9,155' (275'/24 hrs), MW 11.4, Vis 50, PV 19, YP 20, Gels 6/11, pH 9.5, WL 6.2, Cake 2.0, Alk 0.6, Cl13,OOO, Ca 80, Sd .5, Solids 15.0, MBT 17.5, Added 950sx Barite, 4sx Bore-Plate, 2sx caustic soda, Isx Flo- Vis, 4sx Polypac & Isx Resinex, Bit #2, In @ 8,190' (965'/85-1/2 hrs), ROP 11.29, WOB 15K, RPM 80, PP 3,250#, SPM 80, GPM 239, Liner Size 5-1/2" x 10". Drlg 19 hrs, Slide Drlg 5 hrs. Drld fr 8,880'-9,155'. 9/19/04 TIH w/New 6" Bit & 1.0 Deg Motor @ 9,200' (45'/24 hrs), MW 11.4, Vis 57, PV 25, YP 25, Gels 8/16, pH 9.6, WL 6.0, Cake 2.0, Alk 0.7, Cl13,OOO, Ca 80, Sd .6, Solids 15.0, MBT 17.5, Added 160sx Barite, Isx Bioban, 5sx Bore-Plate, 2sx caustic soda, Isx Flo-Vis, 7sx Polypac & 8sx Resinex, Bit #2, In @ 8,190', Out @ 9,200' (1,010'/92-1/2 hrs), ROP 10.92, WOB 15K, RPM 80, PP 3,250#, SPM 80, GPM 239, Liner Size 5-1/2" x 10", Bit #3,6", SEC FM2643, SN# 10671857, In @ 9,200'. Trip 7 hrs, Test BOPS/Diverter 7 hrs, Drlg 3- 1/2 hrs, Slide Drlg 3-1/2 hrs, PU/LD BHA & Tools 2 hrs, Circ 1 hr. Drlg 9,155'-9,200'. Circ btms up. Pmpd dry job. TOOH. Pulled wear ring & press tstd BOPS to 250-5,000 psi, tstd OK. Chuck Scheve w/ AOGCC waived witnessing BOP tst. Set wear ring. MU new bit, 1.0 deg AKO mtr setting & BHA. TIH. 9/20/04 Working On Top Drive 398 CAT Gen Motor @ 9,404' (204'124 hrs), MW 11.5, Vis 72, PV 28, YP 25, Gels 8/18, pH 9.4, WL 6.1, Cake 2.0, Alk 0.6, ClI2,000, Ca 80, Sd .25, Solids 15.0, MBT 17.5, Added 6sx Bore-Plate, 2sx caustic soda, 8sx Polypac & 6sx Resinex, Bit #3,6", SEC FM2643, SN# 10671857, In @ 9,200' (204'/18-3/4 hrs), ROP 10.88, WOB 8K, RPM 100, PP 3,100#, SPM 77, GPM 230, Liner Size 5-1/2" x 10". Drlg 18-3/4 hrs, Trip 2- 1/2 hrs, Circ 1-1/4 hr, Service Rig 1 hr, Rig Repair 1/2 hr. Serviced top drive @ the 7" window. TIH. Washed 60'to btm. Drld fr 9,200'-9,404'. Top drive gen mtr losing oil press, rattling in the same cylinder as before. Circ btms up & pmpd dry job. Called into Caterpillar in Anchorage. TOOH to 7" window @ 7,300'. Rig repair (working on top drive 398 CAT gen mtr). . . 6 9/21/04 NC CAT Working On 398 Top Drive Motor @ 9,404', MW 11.3, Vis 60, PV 25, YP 23, Gels 7/16, pH 9.6, WL 6.0, Cake 2.0, Alk 0.6, CI12,000, Ca 80, Sd .25, Solids 14.0, MBT 17.5, Added 90sx Barite, 2sx Bore-Plate, 1sx caustic soda, 1sx defoamer & 2sx Polypac, Bit #3, In @ 9,200' (204'/18-3/4 hrs), ROP 10.88, PP 3,100#, SPM 77, GPM 230, Liner Size 5- 1/2" x 10". Rig Repair 24 hrs. Worked on top drive 398 CAT mtr. Found inj pmp setting on #6 cyliner set @ 2.2670. Supposed to be set @ 2.1565, causing fuel to be pmpd into cylinder early & @ a higher rate. Causing valve guide to wash out & lubricate to be washed off cylinder. Chg'd out complete cylinder head & cylinder pkg. 9/22/04 Drilling @ 9,543' (139'/24 hrs), Survey: 15.34 deg @ 9,477' (206.34 deg Azimuth, 9,063' TVD), MW 11.4, Vis 70, PV 25, YP 25, Gels 7/9, pH 9.7, WL 6.4, Cake 2.0, Alk 0.7, Cl 12,000, Ca 80, Sd .25, Solids 15.0, MBT 17.5, Added 3sx Bore-Plate, 2sx caustic soda, 4sx Drispac, 3sx Polypac & 3sx Resinex, Bit #3, In @ 9,200' (343'/31-1/4 hrs), ROP 10.98, WOB lOK, ROP 100, PP 3,100#, SPM 71, GPM 212, Liner Size 5-1/2" x 10". Drlg 12-112 hrs, Rig Repair 9-1/2 hrs, Trip 3/4 hr, W & R 3/4 hr, Survey 1/2 hr. Fin putting 398 CAT back together. NC CAT random ck'd inj settings on 3 more cylinders (1, 2 & 5). They were found to be within tolerance. Std up mtr & ran under a load before going back to btm. TIH fr 7" window @ 7,300'. Washed 60' to btm @ 9,404'. Drld fr 9,404'-9,543'. 9/23/04 Drilling @ 9,780' (237'/24 hrs), Surveys: 11.84 deg @ 9,570' (223.64 deg Azimuth, 9,154' TVD) & 11.18 deg @ 9,662'(242.04 deg Azimuth, 9,244' TVD), MW 11.1, Vis 68, PV 29, YP 28, Gels 7/19, pH 9.4, WL 5.2, Cake 2.0, Alk 0.6, CI12,000, Ca 100, Sd .25, Solids 14.0, MBT 22.5, Added 9sx Bore-Plate, 4sx caustic soda, 11sx Drispac & 7sx Resinex, Bit #3, In @ 9,200' (580'/54-1/2 hrs), ROP 10.64, WOB lOK, ROP 100, PP 3,100#, SPM 71, GPM 212, Liner Size 5-1/2" x 10". Drlg 23-1/4 hrs, Survey 3/4 hr. Drld fr 9,543'-9,780'. 9/24/04 Prep to Make Bit Trip @ 9,925' (145'/24 hrs), Surveys: 11.63 deg @ 9,756' (259.74 deg Azimuth, 9,336'TVD) & 12.27 deg @ 9,848'(267.43 deg Azimuth, 9,426' TVD), MW 11.1, Vis 70, PV 27, YP 25, Gels 7/20, pH 9.8, WL 5.2, Cake 2.0, Alk 0.7, Cl 12,000, Ca 100, Sd .25, Solids 14.0, MBT 22.5, Added 150sx Barite, 8sx Bore-Plate, 6sx caustic soda, 3sx Drispac, 6sx Resinex & 25sx Tannathin, Bit #3, In @ 9,200' (725'/75-1/2 hrs), ROP 9.60, WOB lOK, ROP 90, PP 3,100#, SPM 71, GPM 212, Liner Size 5-1/2" x 10". Drlg 20-3/4 hrs, Circ 1-1/2 hr, Wiper Trip/Short Trip 1 hr, Service Rig 1/2 hr & Survey 1/4 hI. Drld fr 9,780'-9,810'. Attempted to drop angle. Drld fr 9,810'-9,869'. Made 11 stand short trip. Drld fr 9,869'-9,925'. 9/25/04 Drlg 6" Hole @ 9,992'(67'/24 hrs), Survey: 12.52 deg @ 9,941'(274.51 deg Azimuth, 9,517' TVD), MW 11.1, Vis 69, PV 27, YP 25, Gels 8/22, pH 9.7, WL 5.0, Cake 2.0, Alk 0.7, Cl 12,000, Ca 100, Sd .25, Solids 14.0, MBT 22.5, Added 4sx Bore-Plate, 2sx caustic soda, 4sx Drispac & 4sx Resinex, Bit #3, In @ 9,200', Out @ 9,925' (725'/75-1/2 hrs), ROP 9.60, WOB lOK, RPM 100, PP 3,100#, SPM 71, GPM 212, Liner Size 5-1/2" x 10", Bit #4, 6", HTC HC407, SN# 7101193, Bit Nozzles 15/15/15/16, In @ 9,925' (67'/10 hrs), ROP 6.70, WOB lOK, RPM 100, PP 3,100#, SPM 71, GFM 212, Liner Size 5-1/2" x 10". Drld 10 hrs, Trip 8 hrs, PU/LD BHA & Tools 2 hrs, Circ 1-1/2 hr, Slip & Cut Drill Line 1-1/2 hr, Survey 1/2 hr & Wash/Ream 1/2 hr. Circ btms up & pmpd dry job. TOOH for bit (worked through tight pipe @ 8,450' & 8,260). Chg'd out bit, mtr & MWD. Till to 8,270' (tight). Washed & reamed fr 8,260'-8,320'. Cont'd Till. Washed 30'to btm. Drld fr 9,925'-9,992'. . . 7 9/26/04 Circ @ TD, Prep to Short Trip to Window @ 10,093' (101'124 hrs), Survey: 11.99 deg @ 10,034' (276.26 deg Azimuth, 9,608' TVD), MW 11.0, Vis 63, PV 25, YP 20, Gels 5/14, pH 9.7, WL 5.5, Cake 2.0, Alk 0.7, CI12,000, Ca 100, Sd .25, Solids 13.0, MBT 22.5, Added 60sx Barite, 12sx Bore-Plate, 4sx caustic soda, 8sx Drispac & IOsx Resinex, Bit #4, In @ 9,925', Out @ 10,093' (168'/32-112 hrs), ROP 5.17, WOB IOK, RPM 100, PP 3,100#, SPM 71, GPM 212, Liner Size 5-112" x 10". Drld 22-112 hrs, Survey 1 hr & Circ 1/2 hr. Drld fr 9,992'-10,093' (TD). Circ btms up. Prep to make wiper trip to window. 9/27/04 Nippling dn BOP's & Well Head @ 10,093', Survey: 11.99 deg @ 10,034' (276.26 deg Azimuth, 9,608' TVD), MW 11.0, Vis 63, PV 25, YP 21, Gels 5/14, pH 9.7, WL 5.2, Cake 2.0, Alk 0.7, CI12,500, Ca 80, Sd .25, Solids 13.0, MBT 22.5, Added 220sx Barite, 5sx Bore-Plate, 2sx Caustic Soda, 1sx Defoamer, 5sx Drispac, 2sx Flo- Vis & 5sx Resinex. Circ 4-1/2 hrs, Mill/Cut Sect or Window 4-112 hrs, Trip 4 hrs, Open Hole Logging 4 hrs, NUIND BOPlDiverter 3 hrs, Wiper Trip/Short Trip 2-112 hrs & PUILD BHA & Tools 1-112 hr. Circ btms up & pmpd dry job. Made wiper trip to window @ 7,291'. Wiped tight spots @ 8,880', 8,790', 8,540' & 8,140'. Pmpd around weighted sweep & dry job. POOH fr/logs (pipe pulled better than on wiper trip). LD flex collars, mtr, MWD & bit. Schlumberger pre-job safety meeting. Ran GRlRESIDENS/CNUSP/CAL open hole logs frWireline TD @ 10,104' to 7" window @ 7,301' (WLM). Pulled wear ring & Baker bridge plug. Set @ 300'. LD running tool. PU Baker 7" csg cutter, cut 7" @ 250' below RT & 20' below wellhead. Circ out gas fr between 7" & 10-3/4" csg. Ck'd for flow & drain stack. ND flowline & BOP's. 9/28/04 Prepared to Make 6" CO Run @ 10,093', MW 11.0, Vis 80, PV 25, YP 21, Gels 5/14, pH 9.7, WL 5.2, Cake 2.0, Alk 0.7, CI12,500, Ca 80, Sd .25, Solids 13.0, MBT 22.5. NU/ND BOPlDiverter 9 hrs, Run/Retrieve Casing 6-112 hrs, Test BOPSlDiverter 4-112 hrs, NU Casing Head 1-112 hr, RU Service Tools 1-112 hr & LDIPUD Drill Pipe/Tbg 1 hI. Nippled dn BOP's & Cameron Type Uni-head. MU 7' spear. Laid on wellhead & 20' of 7" csg. Speared into & LD remaining 7" csg (a total of 250' below RT). Rigged dn 7" tongs & cleared floor. NU Cameron Retro-Spool. NU BOP's & flowline. Back loaded boat. Set tst plug & tstd BOP's @ 250/5,000 psi (Lou Grimaldi w/ AOGCC waived witnessing the BOP tst). LD extra drill pipe out of derrick. PU pkr retrieving tool & retrieved & LD pkr fr 300'. 9/29/04 Trip to Bottom Before Laying Down DP @ 10,093', MW 11.2, Vis 83, PV 20, YP 21, Gels 6/15, pH 9.2, WL 4.9, Cake 2.0, Alk 0.2, CI12,000, Ca 100, Sd .25, Solids 14.0, MBT 25. Added 135sx Barite, 2sx Caustic Soda & 2sx Resine, Bit #5,6", STC XR20, SN# MK7921, Bit Nozzles 20/20/20, In @ 10,093', PP 3,100#, SPM 71, GPM 212, Liner Size 5-112" x 10". Trip 11 hrs, Circ 6-1/2 hrs, Wiper Trip/Short Trip 3-1/2 hrs & PUILD BHA & Tools 3 hrs. MU BHA for wiper trip. RIH w/clean out assembly. Worked thru stub @ 250' & tight spots fr 8,200' to 8,800'. Circ btms up. Pmpd dry job. Made wiper trip to window. Cont'd to have tight spots fr 8,200' to 8,800'. Circ btms up. Pmpd weighted pill. Tripped to window. Worked pipe thru tights spots fr 8,800' to 8,200'. Finished POOH. Chg'd used CO bit. LD 1 DC & stab. RIH (worked thru stub @ 250) @ 0600 RIH @ 6,000'. 9/30/04 Running 5" Casing @ 10,093', MW 11.1, Vis 81, PV 18, YP 20, Gels 6/15, pH 9.4, WL 5.7, Cake 2.0, Alk 0.6, CI13,OOO, Ca 100, Sd .25, Solids 13.0, MBT 22.5. Added 45sx Barite, Bit #5, In @ 10,093', Out @ 10,093', PP 3,100#, SPM 71, GPM 212, Liner Size 5-1/2" x 10". LDIPU Drill Pipe/Tbg 10 hrs, Run/Retrieve Casing 5 hrs, RUIRD Service Tools 3 hrs, NUIND BOPlDiverter 2 hrs, Trip 1-112 hr, Circ 1-112 hr & Test BOPSlDiverter 1 hI. TIH . . 8 w/CO assembly to TD. Circ & cond hole. Ck'd for flow, pmpd pill. TOOH & LD DP. Chg'd pipe rams to 5". Set tst plug, press tstd BOP's to 2,500 psig, OK. Pulled tst plug. RU to run csg. Started in hole w/5" prod csg. 10/1/04 Picking Up BOP Stack @ 10,093', MW 11.4, Vis 62, PV 18, YP 15, Gels 4/6, pH 9.5, WL 5.4, Cake 2.0, Alk 0.6, CI13,OOO, Ca 100, Sd .25, Solids 13.5, MBT 22.5, Added 2sx Caustic Soda, Isx Defoamer & 3sx Desco Chrome Free. Run/Retrieve Casing 14 hrs, Circ 4-1/2 hrs, NU/ND BOP/Diverter 3 hrs, Cementing 2 hrs & RU Service Tools 1/2 hr. Continued in hole w/5" csg. Instld turbolizer centralizers as per prognosis. Circ 5" csg volume @ 4 BPM & 900 psi. Cont running 5" csg. Tagged btm @ 10,093'. RU cmt head & lines. Circ & cond mud. Pipe stuck @ 10,093'. Worked stuck pipe while circ. RU BJ unit, held PJSM. Cmt'd csg w/4 BW. Dropped first wiper plug, pmpd 1 BW. Press tstd lines to 3,000 psi. Pmpd 30 bbls of 12.5 ppg MCS-4 weighted spacer (30 bbls MCS-4, 14 PPB R-3, 0.25 PPB CD-31, .5 GPB FP-6L, 1 GPB MCS-AG, 25.15 PPB Bentonite & 314 PPB Bar). Pmpd 150sx (56 bbls) of 12.5 ppg lead cmt containing 1.5% SMS, 0.4% CD-32, 0.7% R-3, 0.6% FL-52, 0.15% ASA-301, 1 GPS FP-6L. Pmpd 234sx (48 bbls) of Class "G" cmt @ 15.8 ppg containing 0.3% CD-32, 0.2% R-3, 0.8% FL-63, 0.05% ASA-301, 1 GPS FP-6L. Dropped second wiper plug w/5 bbls wtr & 174.8 bbls of 11.2 ppg mud. Pmpd 0.5 bbls addtl over max displacement. Plug did not bump. Bled press off & got back 0.5 bbls mud. Ck'd floats, OK. PD @ 0240 hrs. LD cmt head & lines. Prep to lift stack disconnect drlg nipple. Broke wellhead flange in wellhead room. PU stack to instl csg slips. 10/2/04 PU2-7/8"DP, SLM & Drift @ 1O,093',MW 11.3, Vis 65,PV 18, YP 14, Gels 3/5, pH 9.3, WL 5.3, Cake 2.0, Alk 0.6, CI13,OOO, Ca 80, Sd .2, Solids 14.0, MBT 22.5. NUIND BOP/Diverter 21 hrs, LD/PU Drill Pipe/Tbg 1-1/2 hr, Test BOPS/Diverter 1 hr, PU/LD BHA & Tools 1/2 hr. Lifted stack & riser. Set slips on 5" csg. Cut rough cut csg. Pulled csg out off lwr riser & stack. Split riser & stack. Moved stack aside. Pulled & LD riser. Made final cut on 5" csg. Installed & NU tbg hanger spool. Tstd flange & seals to 5,000 psig for 15", tstd OK. Lwrd riser. NU BOPS. Cleaned pits & back loaded boat. Set tst plug. Shell tstd BOPS to 2,500 psig. Pulled tst plug. made up 4-1/2" bit & 5" scraper. Rlli PU 2-7/8" DP, SLM & drift. 10/3/04 Cleaning Out 5" Csg @ 10,093', MW 11.3, Vis 70, PV 18, YP 15, Gels 3/5, pH 9.1, WL 5.3, Cake 2.0, Alk 0.6, CI13,OOO, Ca 80, Sd .2, Solids 14.0, MBT 22.5. LD/PU Drill Pipe/Tbg 18-1/2 hrs, Drld Cmt/Float Equip 3 hrs, Cleaned Mud Tnks 2-1/2 hrs. RIH w/c1ean out assembly. PU 2-7/8" DP, SLM & drift (SD several times 20 min due to high winds of 35-40 MPH). Stopped PU pipe due to wind. Cleaned pits. Cont'd PU DP. Tagged 9,382'. CO 5" csg fr 9,382'-9,455'. 10/4/04 Prep To POOH Wet Looking For Wash Out @ 1O,093',MW 11.0, Vis45,PV 13, YP 10, Gels 2/4, pH 11.9, WL 9.7, Cake 2.0, Alk 6.2, CI125,000, Ca 220, Sd .2, Solids 13.0, MBT 20.0. Drld Cmt/Float Equip 12 hrs, Trip 7-1/2 hrs, Circ 1-1/2 hr, Serviced Rig 1-1/2 hr, PU/LD BRA & Tools 1 hr, Other 1/2 hr. CO 5" csg fr 9,455'-9,640'. Circ btms up & pmpd pill. POH w/c1ean out assembly, broke off bit & scraper. PU bit & scraper w/9 DC's. RIH w/c1ean out assembly to 9,550'. Slip & cut 100' drill line. Serviced rig. CO 5" csg fr 9,640'- 9,835'. Loosing pmp press. Ck'd surf equip, OK @ 0600. POOH wet looking for wash out. 10/5/04 Building Vol, 3% KCI & Filtering @ 10,093', MW 8.4, Vis 26, CI125,000. Drld Cmt/Float . . 9 Equip 7-1/2 hrs, Circ 4-1/2 hrs, Cleaned Out Mud Tnks 4 hrs, Displace 4 hrs, Build Mud Vol 2 hrs, Trip 1-1/2 hr, Tstd Csg 1/2 hr. POOH wet looking for wash out. Found wash out @ 593' dwn (hole in pin & box). Chg'd out jts. Pmpd on string to ck press, OK. TIH to 9,835'. CO 5" csg fr 9,635'-10,048'. Circ btms up. Tstd 5" csg to 3,000 psi, held for 30", tstd OK. RU to disp hole. Pmpd out mud fr pits. Disp mud wIFIW. Rev circ @ 9 BPM. Cleaned pits, built sweeps & filled tnks w/FIW. Pmpd sweeps 30 bbls high vis, 20 bbls FIW, 30 bbls high vis & pmpd out. Pmpd 60 bbls sweep w/c1ean up soap & pmpd out. Filled pits w/FIW. Mixed 3% KCl & filter. 10/6/04 RIH w/Logging Tools @ 10,093', MW 8.4, Vis 26, Added 52sx KCl. Wireline Work 6 hrs, Trip 5 hrs, Test BOPS/Diverter 5 hrs, NU/ND BOP/Diverter 4 hrs, Mill/Cut Sect. Or Window 3 hrs, Disp 1 hr. Filled pits w/FW. Mixed 3% KCl & filter. Displ FW w/filtered 3% KCl. POOH w/CO assembly. LD bit & scraper. RU tst assembly. Tstd BOP's to 250- 5,000 psi. Tstd accumulator & gas alarms (Jim Regg of AOGCC waived witnessing the BOP tst). RD tst assembly, pulled tst plug. Removed drlg nipple. Installed shooting flange. RU slickline & Schlumberger memory cmt bond log tools. RIH wllogging tools. Tagged btm @ 1O,049'WLM. Press up csg to 1,000 psi. Logged up @ 60' per min. 10/7/04 RD Wireline @ 10,093', MW 8.7, Vis 26. Perf'd 11-1/2 hrs, WL Work 11 hrs, Other 1-1/2 hr. Cont'd logging up @ 60' per min w/Schlumberger memory tool on slickline. Holding 1,000 psi on csg. Ck'd tool. Re-ran bond log. Press up csg to 1,000 psi. Logged up w/cmt bond log. Unloaded frac equip fr boat. Secured WL operations & evacuated unit due to loads being moved over unit. Cont'd logging up w/bond long run #2. Dwnloaded data. RD & moved slickline unit. Spotted & RU APRS WL unit to perf wlExpro guns. Conducted pre- job safety mtg. PU & RIH w/gun #1. Correlated & perf'd fr 9,930'-9,940' wl3 SPF. POOH w/gun #1, all shots fired. PU & RIN w/gun #2. Correlated & perf'd fr 9,910'-9,930' w/3 SPF. POOH w/gun #2, all shots fired. PU & TIH w/gun #3. Correlated & perf'd fr 9,890'-9,910'. POOH w/gun #3, all shots fired. RD APRS WL & lubricator. 10/8/04 TOOH wIFish @ 10,093', MW 8.7, Vis 26. Trip 18-1/2 hrs, NU/ND BOP/Diverter 2-1/2 hrs, Other 2 hrs, PU/LD BRA & Tools 1 hr. ND shooting flange. Installed drlg nipple. PU Baker retrivamatic pkr & tail pipe. TIH w/pkr, ck'g every brk to 9,801' (tail @ 9,835). Attempted to set pkr @ 9,801',9,770' & 9,707'. Pkr would not set. TOOH to ck pkr. Left pkr & tail pipe in hole (unscrewed on X-O collar lOrd thread). Made up 5' scarper above the X- o collar. TIH. Tagged pkr @ 10,007'. Rot 12 turns to the right & screwed into fish. Std TOOH. 10/9/04 ND BOPE @ 10,093', MW 8.7, Vis 26. Trip 14-1/2 hrs, Other 4 hrs, Stimulation 3-1/2 hrs, PU/LD BRA & Tools 1 hr, NU/ND BOPE/Diverter 1/2 hrs, Service Rig 1/2 hr. TOOH & LD pkr & tail pipe. PU Baker Retrievamatic pkr & tail pipe. TIH w/pkr. Set pkr @ 9,801', tail pipe @ 9,836'. Attempted to tst csg & pkr to 3,500 psi. Would not hold press. Std POOH & found wash out 19 JFS. RIH & set pkr @ 9,801'. Attempted to press tst DP & pkr, would not press tst. Std POOH, looking for hole in DP. TIH w/pkr. Stopped @ 9,801', tail pipe @ 9,836' w/pkr unset. RU BJ Services. Prep to pickle csg. Held pre-job safety mtg. Closed pipe rams. BJ pmpd dwn annulus w/rtns up DP. Pmpd 3 BPM @ 1,600 psig. Pmpd 8 bbls of 10% HCl acid, 20 bbls of 3% KCl wtr, 8 bbls of acid, 20 bbls of 3% KCl wtr, then 8 bbls of acid. Displaced w/160 bbls of 3% KCl wtr. Sent last 100 bbls of displacement rtns to tst tnk. Tst tnk was pre-treated w/soda ash to neutralize acid. RD BJ Services lines. TOOH & LD pkr & . . 10 tail pipe. TIH & LD 2 stands ofDP (washed out on 2 connections). PU Baker G-Lok set bridge plug. RIH wlBP wIDC's & 2 stands ofDP. Set BP @ 452'. TOOH wIDP. ND BOPE. 10/10/04 Trouble Shooting Blender & Frac Pmp @ 10,093', MW 8.7, Vis 26. Stimulation 8 hrs, PUILD BRA & Tools 7 hrs, Other 4 hrs, RU/RD Service Tools 3 hrs, Trip 2 hrs. ND BOPE. Pulled & LD riser. NU 7-1116" frac valve on tbg spool. Set tst plug, made up tst flange. Press tstd valve & flange to 250-5,000 psi. Removed tst cap & pull tstd plug. TIH & pulled bridge plug @ 452'. RU Stingers Wellhead isolation tool. RU BJ Services. Bled dwn line. Held pre-job safety mtg. BJ primed pmps. Press tstd lines to 11,000 psi. Performed acid ballout w/36 bbls of 10% HCI & 224 BS (1.3 SG, 7/8" diam). Flushed to btm perfs w/177 bbls of 3% KCI wtr. AIR 10.4 BPM, Avg surface press 9,075 psi. Max STP 10,025 psi. ISIP 6,800 psi (frac grad 1.17 psi/ft), 5" SIP 5,563 psi, 10" SIP 5,150 psi & 15" SIP 4,885 psi. Performed inj tst @ 14.6 BPM @ 9,230 psi w/62 bbls of 2% KCI wtr. ISIP 7,420 psi (FG = 1.23 psi/ft). Gelled up frac tnk. Loaded prop in silo. Primed & press tstd lines to 11,500 psi. Pmpd 169 bbl pad containing 35lbs Borate x-linked @ 18 BPM & 9,900 psi. SD job due to blender problems. Flushed pad away w/200 bbls of 3% KCI wtr. SD job until morning to trouble shoot blender & repair one frac pmp. Trouble shooting blender & frac pmp. Built volume in pits wl2% KCI wtr. 10/11/04 Back Flowing Well, NU BOPE @ 10,093', MW 8.7, Vis 26. Stimulation 12-112 hrs, Other 11-112 hrs. Trouble shoot blender problem & mixed 3% KCI wtr. Topped off gel tnk wl3% KCI wtr & gelled up. BJ mechanic ck'd blender & frac pmp. Std frac job. Opened well, WHP 2,950 psi. Tstd frac pmp & blender for 10 bbls FIW. Std pmpg pad (35# delayed Borate x-link). Pmpd 114 bbl pad @ 20 BPM & 9,325 psi. Blender had trouble gokng to 1 PP A prop stage. Pmpd 95 bbls @ 0.4 PP A. Aborted frac. Overftushed pad w/90 bbls of 3% KCI wtr. SD w/ISIP @ 7,880 psi. BJ trouble shooting blender problem. Unloaded prop fr blender tub. Found unit performing OK. Problem was the two blender augers being mis- labled on screw size. BJ to gell up wtr for 3rd attempt. Fin gelling up. Could not obtain good x-link during QC tst. Discovered that production group had bleached wtr flood plant & got FIW in frac tnks contaminated. Worked additives to get good x-link & re-ran break tsts. Re- primed frac pmps. OWU w/3,420 psi. Pmpd 114 bbl pad (dropped 2 PPA slug for 20 bbls to ck blender), 42 bbls @ 1 PP A, 55 bbls @ 2 PP A, 95 bbls @ 3 PP A, 76 bbls @ 4 PP A, 26 bbls @ 5 PPA & 95 bbls flush (out of 176 bbl flush) before screen out. Avg press was 9,350 psi @ 20 BPM. Pmax was 10,930 psi. Placed 20,000# of 20/40 Carbolite in fmt & left 12,000# in csg (+/- 1,200' fill). Well locked up when 4 PPA hit perfs. Load to revocer, inc1 both prev attempts is 892 bbls. Flow well back & bled well dwn to flowback tnk to get press below 5,000 psi to POOH w/Stinger csg saver. WHP dwn to 4,300 psi. SWI. RD Stinger csg saver. WHP 3,950 psi. OWU & cont'd to flow back load to flowback tnk. Rec 100 bbls FIW. Std to rec broken gel. Lwrd riser. NU BOPE (monitored flow back tnk). At 0600 had flwd back 375 bbls. 10/12/04 Circ Frac Sand Out of 5" Csg @ 10,093', MW 8.7, Vis 26. NUIND BOPIDiverter 10 hrs, Test BOPSIDiverter 5-112 hrs, Trip 5 hrs, Rig Repair 2-112 hrs, W & R 1 hr. NU BOPE (back flwg well to tnk). RU tst assembly. Press tstd BOPS to 250-5,000 psig. Tstd accumulator & gas alarms (Jim Regg of AOGCC waived witnessing the BOP tst). RD tst tools. Till w/muleshoe. Tagged sd @ 8,825'. Std washing sd, cutting auger mtr broke, rebuilt auger mtr. Rev out frac sd fr 8,825'-8,995'. . . 11 10/13/04 Rill w/Gun #1 @ 10,093', MW 8.7, Vis 26. Wireline Work 9-1/2 hrs, W & R 7 hrs, Trip 4 hrs, NU/ND BOPIDiverter 2-1/2 hrs, Circ 1 hr. Washed out sd fr 8,995'-9,854'. Circ high vis sweep. TOOH w/muleshoe. Removed drlg nipple. ND BOP stack. Installed shooting flange on riser. RU APRS WL. PU composite BP & RIH. Set BP @ 9,820'. POOH w/WL. Press tstd BP to 3,000 psi, tstd OK. PU Gun #1, std in hole. Prep to add perfs. 10/14/04 NU BOP's After Frac @ 10,093', MW 8.7, Vis 26. NU/ND BOPIDiverter 7 hrs, RU/RD Service Tools 6 hrs, Stimulation 6 hrs, Perf'd 5 hrs. Fin Rill w/Gun #1, corelated & perf'd fr 9,765'-9,790' w/3 SPF. POOH w/Gun #1, all shots fired. LD gun. Made up Gun #2. Rill, corelated & perf'd fr 9,740'-9,765' w/3 SPF. POOH w/Gun #2, all shots fired. LD Gun #2. RD lubricator. Pulled & LD riser. RU Stinger's WH isolation tool. RU BJ lines. Held pre- job safety mtg. Primed pmps. Press tstd lines to 11,500 psi. Est inj rate @ 6 BPM & 6,200 psi w/3% KCI wtr. Incr rate to 11 BPM @ 7,075 psi. SD. ISIP 5,320 psig (FG=1.03 psi/ft). Std pmpg 36 bbls of 10% HCI acid. Lost electricity in computer van two times due to short w/automatic ball inj. Rebooted & cont'djob, manually dropping 224 BS (1.3 SG, 7/8" diam). Overflushed acid by 50 bbls w/225 bbls of 3% KCI wtr. Balled out @ 10,500 psi. Surged balls & cont'd flushing. Had good ball action w/several breaks. ATP 8,500 psi @ 14 BPM, Pmax 10,500 psi. ISIP 2,440 psi (FG=0.72 psi/ft), 5" SIP 1,863 psi, 10" SIP 1,595 psi & 15" SIP 1,446 psi. Surged balls. Removed ball inj. Prep 900 bbls of 35# frac gel. Re-tstd lines to 11,500 psi. Frac'd "HN" perfs fr 9,740'-9,790' w/23,000 gals of 35# Spectrafrac (delayed borate) w/62,800# of 20/40 Bauxite as follows: 3,700 gal pad, 500 gal 2# slug, 4,000 gal pad, 1,400 gals @ 1 PPA, 4,000 gals @ 2 PPA, 3,800 gals @ 3 PPA, 1,300 gals @ 4 PPA, 2,400 gals @ 5 PPA & 2,000 gals @ 6 PPA. Flushed to top perf @ 9,740'w/linear gel. Avg press 4,765 psi @ 20 BPM. Pmax 6,430 psi. ISIP 4,230 psi (FG=0.91 psi/ft), 5" SIP 3,230 psi, 10" SIP 2,920 psi & 15" SIP 2,770 psi. Ttlload to rec fr acid ball out & frac is 1,000 bbls. SWI. RD Stinger csg saver. Left well SI for 2 hrs for gel to break. Lwrd riser, NU BOP's (bleeding well to TT). 10/15/04 Prep To Till w/Muleshoe @ 10,093', MW 8.7, Vis 26. Trip 10 hrs, W & R 9 hrs, Monitor Well 2 hrs, NU/ND BOPIDiverter 2 hrs, PU/LD BRA & Tools 1/2 hr, Test BOPSIDiverter 1/2 hr. NU BOP's & worked on flow nipple. Shell tstd BOP's to 250-5,000 psi. MU 4-1/8" mill & Till w/2-7/8" DP. Tagged sd @ 9,527'. Washed fr 9,527'-9,820'. Pmpd gelled sweeps to lift sd. Drld bridge plug @ 9,820'. Washed fr 9,820'-9,890'. Pmpd gelled sweep. POOH, LD 4-1/8" mill. MU 2-3/8" muleshoe. Monitored well. Let well flow back to gray tank. Prep to Till w/muleshoe. 10/16/04 Prep To Circ Out Frac Sand (Fr 9,875) @ 10,093', MW 9.2, Vis 26. Trip 16-1/2 hrs, Monitor Well 5 hrs, Circ Out Kick On Choke 1-1/2 hr, Circ 1 hr. Baek flwd well to PTS tnk @ 28 BPH (8% oil) w/some gas. MU dart valve & stripped in hole thru annular to 9,700'. SWI & monitored. Iner mud wt to 9.2 ppg by adding CaCI2. Circ thru choke, displ well w/9.2 ppg fluid. Monitored well & pmpd dry job. TOOH & LD dart valve & safety valve. Till w/2-3/8" muleshoe. Tagged fill @ 9,875'. Prep to eirc out sd. 10/17/04 Prep To Run Expro Perf Guns On APRS WL @ 10,093', MW 9.2, Vis 26, Added 3sx Flo- Vis. LD/PU Drill Pipe/Tbg 10-1/2 hrs, Circ 9 hrs, Perf 4 hrs, PU/LD BHA & Tools 1/2 hr. Circ out frac sd fr 9,875'-10,048' (PBTD). TOOH, LD 2-7/8" DP. LD 3-1/8" DC. Cleared floor. ND flow nipple. NU & tstd shooting flange & lubricator. Prep to run Expro perf guns . . 12 on APRS WL. 10/18/04 Running 2-3/8" Tbg @ 10,093', MW 9.2, Vis 26. Perf 19 hrs, LD/PU Drill Pipe/Tbg 3 hrs, RU/RD Service Tools 2 hrs. Ran Expro 3-3/8" perf guns on APRS elec line. Ran #1 & perf'd fr 9,963'-9,981', ran #2 & perf'd fr 9,941 '-9,947', ran #3 & perf'd fr 9,866'-9,886', ran #4 & perf'd fr 9,846'-9,866', ran #5 & perf'd fr 9,799'-9,819', ran #6 & perf'd fr 9,791 '-9,799', ran #7 & perf'd fr 9,729'-9,741'. RD WL & lubricator. NU drlg nipple. RU to run 2-3/8" tbg. Held pre-job safety mtg. MU w/leg, 1 jt of 2-3/8",4.7#, L-80, 8rd tbg, 1.87" x-nipple, pup jt, 5" FH retrievable pkr, pup jt, 1,875" x-nipple, 1 jt of 2-3/8",4.7, L-80, 8rd tbg, #12 GLM. Still running tbg @ rept time. Hole taking 2 BPH while logging & RU to run tbg. 10/19/04 Released Rig (Fr C31-26RD @ 06:00) @ 10,093', MW 9.2, Vis 26. LD/PU Drill Piperrbg 10-112 hrs, NU/ND Tree 4-1/2 hrs, NU/ND BOP/Diverter 3-1/2 hrs, Pressure/Inject/Lot/Fit 2 hrs, RU/RD Service Tools 2 hrs, Displl-1/2 hr. Landed 2-3/8", 4.7#, L-80, 8rd, EUE tbg wltops as follows: WLEG @ 9,629.42', 1 jt tbg, X-nipple @ 9,597.04', 8' pup jt, Baker FH retrievable pkr @ 9,583.49',6' pup jt, X-nipple @ 9,576.27', 1 jttbg, 4' pup jt, GLM #12 @ 9,534.84', 15 jts tbg, GLM #11 @ 9,053.14', 18 jts tbg, GLM #10 @ 8,476.66', 17 jts tbg, GML #9 @ 7,930.90',16 jts tbg, GLM #8 @ 7,413.86',15 jts tbg, GLM #7 @ 6,929.37', 14 jts tbg, GLM #6 @ 6,475.24', 15 jts tbg, GLM #5 @ 5,989.85',23 jts tbg, GLM #4 @ 5,255.98', 29 jts tbg, GLM #3 @ 4,335.69', 35 jts tbg, GLM #2 @ 3,228.28',42 jts tbg, GLM #1 @ 1,904.92',51 jts tbg, T-5 SSSV @ 301.25',8 jts tbg, 2 pup jts, X-over 2-7/8" PH6 pin x 2-3/8", 8rd box, Cameron hgr w/2-7/8" RTS6 threads in top @ 33.20', 19 SS bands on control line. Mixed & pmpd 20 bbls Biocide pill w/4 gals NALCO EC1124A pkr fluid + 10 gals NALCO 99VD-049 Biocide in 20 bbls FIW. Under displaced pill by 10 bbls inside the tbg. Landed tbg hanger. Dropped RHC plug dwn hole to set in X-nipple w/lock @ 9,597'. Press up to 3,000 psi, held for 10 min to set pkr. Set BPV. ND BOPS. NU Cameron tree. Press tstd neck seals & flanged gasket to 5,000 psi for 15 min. Pulled BPV & ran TWC. Tstd tree to 5,000 psi for 20 min, pulled TWC. Cleared floor, cleaned pits, prep to back load boat. RD lines fr rig floor to PTS tnk. ReI rig fr C31-26RD to move to C22A- 26LN @ 06:00 hrs 10/19/04. 10/20/04 All depths are WLM unless where noted. RU WL & press tested lubricator. Rill w/2" JDC pulling tool. Sat down on SSSV @ 305'. Tool would not pass through flapper valve. Valve was differentially locked closed. Went to 3,600 psi on control line & pressured down tubing to 3,000 psi to open valve. RIH w/2" JDC pulling tool to 9,599'. Latched & POOH wlball rod assembly. Rill w/2" GS pulling tool to 9,603'. Latched & POOH w/1.875" X-type RHC plug. RD WL. Welder finishing up flowlines. 10/21/04 Started up gas lift slowly. Inj ±200 MCF @ 925 psi csg press. Well prod ±400 BPD w/trace of oil. 10/22/04 Cont'd gas lifting well w/960 psi csg press. (Lifting off GL V #1). Put well in test @ 0100 hrs. Producing 474 BPD. 10/23/04 Well test: 60 BOPD, 435 BWPD & 5 MCF. Inj 160 MCF w/950 psi csg press. (Lifting off GLV #1). . . 13 10/24/04 Well test: 69 BOPD, 560 BWPD & 5 MCF. Inj 198 MCF w/950 psi csg press. (Lifting off GLV #1). 10/25/04 Well test: 66 BOPD, 444 BWPD & 4 MCF. Inj 200 MCF w/950 psi csg press. (Lifting off GLV #1). 10/26/04 RU WL. Rill wlPanex press temp tool for gas lift survey. Stopped @ GLV #6. POOH making gradient stops. Downloaded survey. Survey shows well lifting @ GL V #2 & gas is heading @ GLV #1. Extrapolated BHFP = 3,470 psi @ 9,848' midperfs. 10/27/04 All depths are WLM unless where noted. RIH wiN-Kick Over tool & 1.25" ML pulling tool to 3,208'. Latched & POOH w/GL V # 2 (5/32" port). Rill & set 3/8" orifice valve to 3,208'. POOH. RD WL. RWTP. Started up gas lift. Injecting 700 MCF. Csg press fell from 960 to 640 psi (well lifting @ GLV #2). Put well in test. Prod: 104 BO, 760 BW & 81 MCF. 10/28/04 P. 85 BO, 624 BW & 25 MCF. Lift gas @ 771 MCF w/CP @ 570 psi. 10/29/04 P. 63 BO, 511 BW & 18 MCF. Lift gas @ 847 MCFw/CP @ 605 psi. 10/30/04 P. 52 BO, 468 BW & 16 MCF. Lift gas @ 852 MCF wCP @ 575 psi. 10/31/04 P. 52 BO, 468 BW & 3 MCF. Lift gas @ 843 MCF w/CP @ 560 psi. 11/1/04 P. 45 BO, 452 BW & 10 MCF. Lift gas @ 690 MCF w/CP @ 560 psi. 11/2/04 All depths are WLM unless where noted. RU WL. RIH wIN-Kick Over tool & 1.25" ML pulling tool to 4,317'. Latched & POOH w/GL V #3. RIH to 3,208' & pulled 3/8" orifice valve fr GLM #2. POOH. RIH wloriginal GL V (5/32") & set in GLM #2 @ 3,208'. POOH. RIH w/3/8" orifice valve & set in GLM #3 @ 4,317'. POOH. RTWP @ 1400 hrs. 11/3/04 P. 73 BO, 661 BW & 59 MCF. Lift gas @ 935 MCF w/CP @ 720 psi. 11/4/04 P. 73 BO, 661 BW & 59 MCF. Lift gas @ 916 MCF w/CP @ 720 psi. 11/5/04 All depths are WLM unless where noted. RU WL. RIH wlPanex BHP/Temp tool below GLM #5 to 6,004'. Well stabilized @ 650 BPD w1720 psi csg press injecting 924 MCF. Started survey making stops above & below GLV's #1-#4. POOH. Good data. Survey results show the BHFP @ 2,839 psi @ 9,433' TVD of midperfs. 11/6/04 P. 79 BO, 529 BW & 91 MCF. Lift gas @ 885 MCF w/CP @ 715 psi. 11/7/04 P. 44 BO, 508 BW & 89 MCF. Lift gas @ 889 MCF w/CP @ 715 psi. 11/9/04 Well test: 62 BO, 498 BW & 75 MCF. Lift gas @ 858 MCF wi CP 680 psi. All depths are . . 14 WLM unless where noted. RU WL. RIH wIN-Kick Over tool & 1.25" ML pulling tool to 4317'. Latched & POOH w/orifice in GLV #3. RIH to 5,241'. Latched & POOH w/GLV #4. RIH w/original GL V (3/16") & set in GLM #3 @ 4,317'. POOH. RIH wI 3/8" orifice valve & set in GLM #4 @ 5241'. POOH. RWTP. 11/10/04 P. 69 BO, 623 BW & 328 MCF. Lift gas @ 764 MCF w/CP @ 680 psi. 11/13/04 P. 65 BO, 523 BW & 93 MCF. Lift gas @ 958 MCF w/CP @ 680 psi. . ;[t~ MGS C31-26RD Cook Inlet, Alaska Leg 1 Conductor 5 API No. 50-733-20052 Spud: Original Oct 1967 Sidetrack: Aug 2004 Surf Csg: 103/4", 40.5Ib, J55. Set @ 1,895'. Cmt w/1 ,600 sk. SOZ hole in 7" @ 3,440-71' wI 95 sk. (9-3-2004) Intermediate: 7" N80 BTC. Window Milled @ 7,291' Original Set @ 9,927'. 23# : 200 - 5,600' (200' was cut offi 26# : 5,600 - 8,100' 29# : 8,100 - 9,927' Cmt w/1 ,350 sk. TOC by CBL @ 6,260' Longstring: 5" 18# P11 O. Set @ 10,093' Surf to 634' : STL 634 - 10,093' : Ultra FJ Cmt wI 384 sk. PBTD: 10,048' MD (9,622' TVD) TD: 10,093' MD (9,666' TVD) . PLF 11-16-04 KB: 35' Water Depth: 73' MSL Tbg: 2-3/8" 4.7# L80 8rd EUE @ 9,630'. Set on 1 0-19-04 Item MD TVD GLM 1 1905 1904 GLM 2 3228 3225 GLM 3 4337 4335 GLM 4 5256 5203 GLM 5 5990 5906 GLM 6 6475 6368 GLM 7 6929 6795 GLM 8 7414 7253 GLM 9 7931 7707 GLM 10 8477 8142 GLM 11 9053 8660 GLM 12 9535 9118 Psc Pso 940 978 940 974 930 969 ORIFICE 910 929 900 918 890 910 880 898 870 886 860 873 850 858 ORIFICE Port 10 10 12 24 12 12 12 12 12 12 12 20 Tba hnar TOP is 2-718" RTS-6 wi 2-318" 8rd BTM X-over 2-7/8" RTS-6 Pin X 2-3/8" 8rd Box @ 34' 6' Pup Jt 2-3/8" 4.7# L80 8rd EUE @ 294' Baker T5 SSSV (1.875" ID) @ 301' 4' Pup Jt 2-3/8" 4.7# L80 8rd EUE @ 305' 2-3/8" X Nipple (1.875") 9Cr @ 9,576' 6' Pup Jt 2-3/8" 4.7# L80 8rd EUE @ 9,578' 5" Baker FH Rtr Pkr @ 9,584' 8' Pup Jt 2-3/8" 4.7# L80 8rd EUE @ 9,589' 2-3/8" X Nipple (1.875") 9Cr @ 9,597' 1 Jt 2-3/8" 4.7# L80 8rd EUE @ 9,598' WLREG @ 9,630' HN: 9,729 -9,741' (24 holes) HN: 9,740 -9,790' (150 holes) Frac'd 63k# HN: 9,791 -9,819' (56 holes) HR: 9,846 -9,886' (82 holes) HR: 9,890 -9,940' (150 holes) Frac'd 20k# HR: 9,941 -9,947' (12 holes) HR: 9,963 -9,981' (36 holes) ;l!~ XTO Energlc.,slot #1-5 Platform C, Middle Ground Shoals,Cook Inlet, Alaska SURVE-eTING Page 1 Wellbore: C31-26Rd Well path: MWDw/Sag <7372 -10093'> Date Printed: 15-Nov-2004 '.Iii. BAKER HUGHES INTEQ C31-26 Nárne Platform C Coordinates are relative to NE Corner of Sec. 23, T8N, R13W, SM All data is in Feet unless otherwise stated Coordinates are from Installation MO's are from Rig and TVO's are from Rig (Actual Datum 105.0ft above mean sea level) Vertical Section is from 4743.00S 1593.00W on azimuth 185.85 degrees Bottom hole distance is 2096.68 Feet on azimuth 189.83 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ~TO ~kRGY XTO Energyl:.,slot #1-5 Platform C, Middle Ground Shoals,Cook Inlet, Alaska SURVEv&ING Page 2 Well bore: C31-26Rd Wellpath: MWDw/Sag <7372 -10093'> Date Printed: 15-Nov-2004 r&ií. BAKER HUGHES INTEQ 0.00 0.00 0.00 0.00 4743.00S 1593.00W 0.00 0.00 231362.64 2474224.54 75.00 0.00 180.00 75.00 4743.008 1593.00W 0.00 0.00 231362.64 2474224.54 _1Q.º-,Q.L _. 0.17 153.00 100.00 4743.03S 1592.98W 0.E¡8 0.03 ---- 231362.66 2474224.51 I-_J.?5.0o..__ --- 0.08 38.00 125.00 4743.058 1592.96W 0.87 0.05 231362.68 2474224.49 150.00 0.08 102.00 150.00 4743.04S 1592.93W 0.34 0.03 231362.71 2474224.50 175.00 0.08 25.00 175.00 4743.038 1592.90W 0.40 0.02 231362.74 2474224.51 1---200.00 0.17 279.00 200.00 4743.01S 1592.93W 0.83 0.00 231362.71 2474224.53 225.00 0.08 236.00 225.00 4743.018 1592.98W 0.50 0.01 231362.66 2474224.53 1---250.0.9_ 1--- 0.25 42.00 250.00 4742.98S 1592.96W 1.31 -0.02 231362.68 2474224.56 -- 275.00 0.25 59.00 275.00 4742.918 1592.88W 0.30 -0.10 231362.76 2474224.63 300.00 0.08 60.00 300.00 4742.888 1592.82W 0.68 -0.14 231362.83 2474224.66 325.00 0.17 274.00 325.00 4742.868 1592.84W 0.96 -0.15 231362.81 2474224.68 350.00 0.00 0.00 350.00 4742.868 1592.88W 0.68 -0.15 231362.77 2474224.68 361.00 0.08 277.00 361.00 4742.868 1592.88W 0.73 -0.15 231362.76 2474224.68 420.00 1.50 130.00 419.99 4743.358 1592.33W 2.66 0.28 231363.30 2474224.18 464.00 2.00 170.00 463.97 4744.488 1591.76W 2.92 1.34 231363.85 2474223.04 621.00 2.25 159.00 620.87 4750.068 1590.18W 0.30 6.73 231365.30 2474217.43 838.00 1.50 165.00 837.75 4756.77S 1587.92W 0.36 13.19 231367.41 2474210.66 1057.00 1.50 190.00 1056.68 4762.378 1587.67W 0.30 18.72 231367.52 2474205.06 1137.00 I 2.00 180.00 1136.64 4764.798 1587.86W 0.73 21.16 231367.29 2474202.64 1386.00 1.75 203.00 1385.51 4772.648 1589.34W 0.32 29.11 231365.62 2474194.83 _1608.00 1.00 143.00 1607.45 4777.318 1589.50W 0.68 33.77 231365.36 2474190.17 1900.00 0.00 180.00 1899.44 4779.348 1587.97W 0.34 35.64 231366.84 2474188.10 2080.00 0.50 20.00 2079.44 4778.608 1587.70W 0.28 34.88 _231367.13 2474188.83 _¡303.0Q... _1.25 260.00 2302.42 4778.11S 1589.76W 0.70 34.60 231365.08 2474189.37 2523.00 1.50 267.00 2522.36 4778.688 1595.00W 0.14 35.70 231359.83 2474188.92 2743.00 2.00 240.00 2742.26 4780.758 1601.20W 0.43 38.39 231353.58 2474186.99 2991.00 2.00 263.00 2990.11 __ 4783.448 1609.25W 0.32 41.88 231345.48 2474184.49 3124.00 5.00 185.00 3122.90 4789.508 1612.06W 3.75 48.20 231342.53 2474178.49 3187.00 8.00 175.00 3185~~ _.A.I96..608 1611.92W 5.07 55.25 231342.51 2474171.39 3282.00 10.75 178.00 3279.21 4812.058 1611.03W 2.94 70.52 231343.04 2474155.93 3419.00 12.00 178.00 3413.52 4839.058 1610.09W 0.91 97.29 231343.37 2474128.91 3544.00 12.75 180.00 3535.61 4865.838 1609.64W 0.69 123.89 231343.21 2474102.13 3702.00 11.75 180.00 3690.01 4899.358 1609.65W 0.63 157.24 231342.44 2474068.61 3857.00 8.50 180.00 3842.58 4926.608 1609.65W 2.10 184.34 231341.82 2474041.38 3958.00 8.75 178.00 3942.44 4941.748 1609.39W 0.39 199.37 231341.74 2474026.23 4020.00 9.75 182.00 4003.63 4951.70S 1609.41W 1.92 209.28 231341.49 2474016.28 4178.00 11.75 187.00 4158.85 4981.04S 1611.84W 1.40 238.72 231338.40 2473987.00 4280.00 11.00 165.00 4258.90 5000.768 1610.59W 4.29 258.21 231339.20 2473967.26 4342.00 9.50 156.00 4319.91 5011.158 1606.97W 3.53 268.18 231342.57 -- 2473956.79 4432.00 10.25 144.00 4408.59 5024.428 1599.25W 2.43 280.58 231349.99 2473943.35 4463.00 11.00 148.00 4439.05 5029.158 1596.06W 3.39 284.97 .1--- 231353.07 2473938.54 4523.00 11.25 _~ __._ 151.00 4497.93 5039.138 1590.19W 1.05 294.30 231358.71 . ~_2473928.43 4584.00 12.00 149.00 4557.68 5049.778 1584.04W 1.40 304.26 ---- 231364.62 2473917.66 4679.00 14.00 .-. 155.00 4650.24 5068.658 1574.10W 2.54 322.03 231374.13 2473898.55 4771.00 15.25 156.0.0 4739.26 5089.808 1564.48W 1.39 342.08 231383.27 -- 2473877.20 4863.00 15.00 154.00 4828.07 5111.558 1554.34W 0.63 362.69 231392.91 2473855.22 4957.00 17.00 160.00 49t8.43 5135.408 1544.31W 2.76 38.5.39 231402.39 2473831.14 5052.00 17.75 164.00 5009.10 5162.388 1535.57W 1.48 411.33 231410.52 2473803.98 5149.00 17.75 164.00 5101.48 5190.808 1527.42W 0.00 438.78 231418.01 2473775.38 5275.00 I 17.75 I - 167.00 5221.49 5227.988 1517.81W - 0.73 474.78 --.--- 231426.78 2473737.99 All data is in Feet unless otherwise stated Coordinates are from Installation MO's are from Rig and TVO's are from Rig (Actual Datum 105.0ft above mean sea level) Vertical 8ection is from 4743.008 1593.00W on azimuth 185.85 degrees Bottom hole distance is 2096.68 Feet on azimuth 189.83 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ~TO .ÀtkRGY XTO Energ'C.,Slot #1-5 Platform C, Middle Ground Shoals,Cook Inlet, Alaska SURVEeTING Page 3 Well bore: C31-26Rd Well path: MWDw/Sag <7372 -10093'> Date Printed: 15-Nov-2004 '&ii. BAKER HUGHES INTEQ ~~~ 5402.00 17.00 168.00 5342.69 . 52Q5.Q~ -. 1509.60W 0.64 510.78 231434.14 2473700.79 --""_. 5527.00 16.25 171.00 5462.47 _~300.15~_ _.._1503.07W 0.91 545.08 231439.87 247366.5,~P____ ~31.00 15.75 lZJ"OQ_ _5562.44_ 5328.548 1499.08W 0.72 572.91 231443.22 2473637.03 5773.00 17.00 .175.00 5698.68 5368.358 1494.93W 0.97 612.09 231446.46 2473597.14 5905.00 18.00 177.00 5824.57 5407.948 1492.18W 0.88 651.19 231448.31 2473557.50 6085.00 17.25 :1.ß..O.Op 5996.12 5462.408 1490.73W - 0.65 705.22 231448.51 2473503.01 6224.00 16.75 184.00 6129.05 5503.00S 1492.14W 0.91 745.75 231446.19 2473462.47 6371.00 17.75 187.00 6269.44 5546.37S 1496.35W 0.91 789.32 231440.99 2473419.20 ~_ 6445.00 18.00 184.00 6339.87 5568.978 1498.53W 1.29 812.03 231438.30 2473396.65 6474.00 18.25 179.00 6367.43 5577.988 1498.76W 5.43 821.02 231437.86 2473387.65 6504.00 19.25 177.00 6395.84 5587.628 1498.42W 3.96 830.57 231437.98 2473378.01 6536.00 20.50 170.00 6425.94 5598.418 1497.17W 8.39 841.17 231438.98 2473367.20 6681.00 20.25 172.00 6561.87 5648.268 1489.28W 0.51 889.96 231445.74 2473317.18 6760.00 19.75 175.00 6636.10 5675.108 1486.22W 1.44 916.35 231448.19 2473290.28 6931.00 19.50 174.00 6797.17 5732.278 1480.72W 0.24 972.66 231452.38 2473233.00 7026.00 18.75 178.00 6886.93 5763.308 1478.54W 1.59 1003.30 231453.86 2473201.93 7152.00 18.50 .1I!;I.00 7006.33 5803.528 1477.49W 0.32 1043.21 231454.00 2473161.69 7259.00 18.00 182.00 7107.95 5837.028 1477.77W 0.99 1076.56 231452.95 2473128.21 7372.00 21.54 .. 198.81 7214.36 5874.148 1485.08W 5.90 1114.24 231444.80 2473091.26 7437.00 21.71 204.10 7274.79 5896.418 1493.84W 3.01 1137.29 231435.53 2473069.20 7530.00 24.44 208.50 7360.35 5929.038 1510.05W 3.47 1171.39 231418.59 2473036.96 7622.00 27.50 209.06 7443.05 5964.33S ..-1§?9.~6W 3.34 1208.48 231398.38 2473002.11 -- 7715.00 28.02 205.76 i-_]5?5.35 6002.77~_ _.__1549.39W 1.74 1248.79 231377.58 2472964.13 -- 7808.00 31.20 , 199.10 7606.22 6045.238 1566.78W 4.92 1292.76 231359.23 2472922.09 .. 7901.00 36.11 199.73 7683.61 6093.818 1583.93W 5.29 ... 1342.84 231340.98 2472873.90 7993.00 39.23 202.34 7756.42 6146.258 1604.16W 3.81 1397.07 231319.57 2472821.94 8086.00 38.90 199.18 7828.64__. .-----º201.03~ _J 624.94W . 2.17 1453.Q9 231297.55 2472767.64 8151.00 40.44 198.15 7878.67 6240.348 1638.21W 2.58 1494.15 231283.38 '-----.~472728.65 8180.00 40.28 198.50 7900.77 6258.178 1644.12W 0.96 1512.48 231277.07 2472710.96 _ª_272.0º- __36.49 . 201.39 7972.88 6311.87S 1663.55W 4.96 1567.88 231256.42 - """ i-------.2472657.72 8365.00 34.77 197.88 8048.47 6362.86S 1681.79W 2.87 1620.47 231237.03 2472607.16 8457.00 33.25 199.85 8124.73 6411.55S 1698.42W 2.04 1670.60 231219.30 2472558.86 8550.00 29.36 199.96 8204.18 6456.988 1714.87W 4.18 1717.47 231201.82 2472513.82 8643.00 27.58 200.04 8285.93 6498.638 1730.03W 1.91 1760.45 231185.71 2472472.52 8735.00 26.39 200.37 8367.91 6537.818 1744.45W 1.30 1800.89 231170.40 2472433.68 8828.00 24.58 202.44 8451.86 6575.068 1759.04W 2.17 1839.44 231154.98 2472396.77 8921.00 22.49 203.38 8537.12 6609.278 1773.49W 2.28 1874.94 231139.75 2472362.90 9013.00 20.80 200.74 8622.63 6640.708 1786.26W ..2.12 1907.51 431126.27 -. 2472331.77 9106.00 20.54 198.72 8709.65 6671.598 1797.35W 0.82 1939.37 231114.48 2472301.14 .. 9200.Qº- 18.22 199.67 8798.31 6701.058 1807.59W 2.49 1969.72 231103.57 2472271.92 _9292.0Q_ ___17.29 198.94 8885.93 6727.528 1816.87W 1.04 .. 1997.01 231093.69 2472245.67 9385.00 16.28 203.00 8974.97 6752.608 1826.46W 1.66 2022.92 231083.~4 24722~0.82 9477.00 15.34 206.34 ___90¡¡3.4!L __ 6775.37~__. 1836.90W 1.42 2046.65 231072.58 2472198.29 .._,-,-~ 9570.00 11.84 223,64 9153.91 6793.318 1848.95W 5.73 2065.72 ... 231060.12_ 2472180.63 9662.00 11.18 242.04__ . 9244.09 6804.328 1863.35VV 4.04 2078.1.5 231045.48 2472169.95 .-. - 9756.00 11.63 259.74 9336.26 6810.288 1880.73W 3.74 2085.85 231027.97 24721.64.38 9848.00 12.27 267.43 9426.27 6812.378 1899.62W 1.86 2089.85 231009.03 2472162.72 9941.00 12.52 .-. 274.52 9517.11 6812.028 1919.54W 1,Q6 2091.53 230989.13 2472163.53 10034.00 11.99 276.26 9607.99 6810.178 1939.19W 0.69 2091.69 230969.52 2472165.83 10093.00 11.99 276.26 9665.70 6808.838 1951.38W 0.00 2091.61 230957.37 2472167.44 All data is in Feet unless otherwise stated Coordinates are from Installation MD's are from Rig and TVD's are from Rig (Actual Datum 105.00 above mean sea level) Vertical 8ection is from 4743.008 1593.00W on azimuth 185.85 degrees Bottom hole distance is 2096.68 Feet on azimuth 189.83 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated · ;[~ XTO EnergJc.,slot #1-5 Platform C, Middle Ground Shoals,Cook Inlet, Alaska SURVEeTING Page 4 Wellbore: C31-26Rd Well path: MWDw/Sag <7372 -10093'> Date Printed: 15-Nov-2004 ".. BAKER HUGHES INTEQ All data is in Feet unless otherwise stated Coordinates are from Installation MD's are from Rig and TVD's are from Rig (Actual Datum 105.0ft above mean sea level) Vertical Section is from 4743.00S 1593.00W on azimuth 185.85 degrees Bottom hole distance is 2096.68 Feet on azimuth 189.83 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated Re: BOP Inlet XTOC 31-26RD D Thanks for the explanation¡ you are granted a waiver from the BOP test due Sunday, 9/26, to complete drilling of the open hole section of this well. Please advise should you encounter problems or delays that cause open hole activities to extend beyond Tuesday, 9/28. Contact us when you are ready to decomplete the existing wellhead and reinstall new wellhead¡ the Commission may send someone to witness that work. Also, please provide 24 hour notice of BOP test after nipple up. You can contact me during office hours, or our North Slope office at 659-2714 after business hours. Jim Regg AOGCC Drilling Foremen wrote: Jim Regg: Our weekly BOP test is due on Sun the 26th. We are presently drilling at 9850' and our TD is to be @ 10130'. At that time open hole logs will be run. Then a bridge plug will be set at 250' and the 7" csg will be cut at 200' & pulled. A new well head will be installed and the BOP's nippled back up & tested at that time. Thanks for the help. Larry Driskill 776 2534 3<.(fPO,rl11 ~ :JßI2.;i)z'>104- - l3.ð? --k_SJ.- Wj4-I'\~S~ cß //Z/04-/' YW fì<.;Iu..r~.s ~4i3ðP -ksts "S1f\C'è W\~eS5 ~ ck¡tW¡&J¡æhJ ~ ~~c¿ wi ~~j l~ cr,h'~ BoPe 1 of 1 9/23/2004 4:27 PM "'~ . ffi)~ ~~ ~[[ . ''to ) FRANK H. MURKOWSKI, GOVERNOR AI,ASIiA OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Bobby Smith Drilling Operations Manager XTO Energy 3000 N. Garfield, Suite 175 Midland, TX 79705 Re: Middle Ground Shoal Unit C31-26RD XTO Energy Pennit No: 204-140 Surface Location: 542' FSL, 1596' FEL, SEC. 23, T8N, R13W, SM Bottomhole Location: 1571' FSL, 1851' FEL, SEe. 26, T8N, R13W, SM Dear Mr. Smith: Enclosed is the approved application for pennit to redrill the above development well. In your application you note that due to the platfonn construction and the lack of sufficient headroom, it is only possible to employ 1 set of pipe (or variable) rams rather than the 2 sets required by 20 AAC 25.035(e)(1)(B)(i). You have requested a waiver as allowed by 20 AAC 25.035(h)(1). A waiver is allowed provided that the equipment employed provides "...an equally effective means of well control." Such a waiver was granted for your most recent operations between 2000 - 2002 and it is appropriate to continue the waiver. Operational test records indicate that the equipment showed a high degree of reliability. It is also likely that the maximum anticipated surface pressure calculated for this operation is conservative since the fonnation pressure is elevated due to waterflood and the Hemlock fonnation does not have high gas content. BOP tests during operations on this well should be conducted at an interval not to exceed 7 days. This pennit to redrill does not exempt you from obtaining additional pennits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. In addition, the Commission reserves the right to withdraw the pennit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska . J . . Permit No: 204-140 July 30, 2004 Page 2 of2 Administrative Code, or a Commission Order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission itness any required test. Contact the Commission's petroleum field inspector at (907) 65 3 (pager) BY ORDER w... THE COMMISSION DATED this~day of July, 2004 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. Mr. Bill Penrose, Fairweather E&P w/encl 1 a. Type of Work: Drill D Red rill 0 1 b. Current Well Class: Exploratory D Development Oil 0 Multiple Zone D Re-entry D Stratigraphic Test D Service D Development Gas D Single Zone 0 2. Operator Name: 5. Bond: Blanket 0 Single Well D 6Þ 11. Well Name and Number: XTO Enerav. Inc. Bond No. IÞ~'~Z(.a>] 7.1.1.0'/ C31-26RD 3. Address: 6. Proposed Depth: ./ ./ 12. Field/Pool(s): 3000 North Garfield. Suite 175. Midland TX 79705 MD: 10,128' TVD: 9,705' Middle Ground Shoal 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 542' FSL, 1596' FEL: Sec. 23, T8N, R13W, SM ./ ADL 18756 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1444' FNL, 1799' FEL, Sec 26, T8N, R13W, SM N/A 8/20/2004 Total Depth: J , 9. Acres in Property: 14. Distance to Nearest / 3481' ,¡ 1571' FNL, 1851' FEL, Sec 26, T8N, R13W, SM 5120 Property: , 4b. Location of Well (State Base Plane Coordinates): 10.1<8 Elevation 15. Distance to Nearest Well ./ surfac~"l"" 2474225 ~"231363 ~~z..'t.t+# Zone- AK-4 (Height above GL): 105 feet ASL Within Pool: 494' from C31-26 16. Deviated wells: Kickoff depth: 7290 feet ,/ 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 40 degrees Downhole: 5,200 psi ./ Surface: 4,134 psi I 1 18. Casing Program: Specifications Setting Depth Quantity of Cement Size Top Bottom c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 6" 5" 18# L-80 STL 3138' 6990' 6852' 10,128' 9705' 195 sx Class G 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 9935' 9707' Fill @ 9640' 9640' 9345' WL Fish @ 9658' Casing Length Size Cement Volume MD TVD Structural Conductor Surface 1895' 10-3/4" 1600 sx 1,895' 1.894' Intermediate Production 9927' 7" 1350 sx 9,927' 9.504' Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee l.:j BOP Sketch ~ Drilling Program ~ Time v. Depth Plot U Shallow Hazard Analysis U Property Plat D Diverter Sketch D Seabed Report D Drilling Fluid Program 0 20 AAC 25.050 requirements D 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Bobby Smith Title Drilling/Operations Manaaer Signature £'/¡J L (' ~..I/ Phone 432-620-6718 Date 7/¿~·k.~ / Commission Use Only , / Permit to Dril2D (j. . s1: API Number: :2.C052 -0/ Permit Approval See cover letter for other Number: .- / L) 50- 733.... Date: 7ho~¢ requirements. Conditions of approval: . Samples required Yes D No ~ Mud log required Yes D No N ~en sulfide measures.. Yes D No Directional survey required Yes ~ No D Oth.ro ~~:.v ".,\...., ~ \<>,,~ . !..... ~ o!.. ~\V,<ro"" c.. f~".0 òD þ.~.:;)S .<::> ~ 'S 1..1., " ~ \') . ß(),? "( J/fc...~\~'r~'O'\~~'>. BY OR EROF ~ ill. Approved y: A '.I ~ THE COMMISSION Date: '$IJ '#I- For~1~d12/~ r·, f \ubm~ inDu licate ¡ 'I",. J _ STATE OF ALASKA _ ALASK.... AND GAS CONSERVATION COMMI~ PERMIT TO DRILL 20 AAC 25.005 á tt¡~ f¡,f.. ß"t; " (If OR!GII~/-\L p . . XTO Energy, Inc. MGS C31-26RD Summary Sidetrack Procedure · With the rig over C31-26, the BOPE installed and tested, the C31-26 wellbore plugged ,/ with cement and the hole loaded with water-base mud, drill the C31-26RD sidetrack as follows: · R/U e-line and RIR with 7" bridge plug. Log casing collars and set bridge plug 5' above first collar below 7,290'MD. · Rill with 7" one-trip whipstock. Orient and set whipstock on the bridge plug at ±7,290'MD and mill window in 7" casing using a 6" mill. · Directionally drill 6" hole from 7,290' to 10,128' MD. ,/ · Run and cement 5", 17.95#, L-80, STC liner at 10,128' MD with TaL at approximately 6,990' (~300' oflap). Top of cement to be at top ofliner lap. Cement to consist of: 195 sx (224 cu. ft.) Class Gw/ additives (V olume calculated with 30% excess in open hole) · Clean out casing to float collar and pressure-test liner and lap to 3,000 psi. · Displace well to filtered Inlet water. · Run 2-7/8" X 2-3/8" completion with gas lift design. - · Pickle inside oftubing with RCI/xylene and circulate inhibited filtered Inlet water into annulus before setting packer. · N/D BOPE, N/U tree. Test tree to 5,000 psi. Release rig. . . XTO Energy, Inc. Middle Ground Shoal Unit BOP Waiver Reauest XTO Energy requests a variance from 20AAC25.035(e): Blowout Prevention Equipment and Diverter Requirements for its workover and drilling operations on Platforms A and C in Cook Inlet. This variance is being requested per 20AAC25.035(h) and is the same as the one requested and approved for XTO's 2000 - 2002 drilling/workover program at Middle Ground Shoal. Request XTO Energy requests authorization to utilize a 5,000 psi WP BOP stack that consists of an annular preventer, one blind ram preventer and one pipe or variable bore ram preventer for wells with calculated Maximum Anticipated Surface Pressures between 3,000 and 5,000 psi in lieu of the annular preventer and three rams required in the AOGCC's regulations. The pipe ram will be sized to fit around the pipe being run into and out of the hole. The variable bore rams will always be used for tapered stings but may be used for un-tapered strings. Rationale This variance is being requested because the lack of vertical space in the rigs' sub-bases on these small platforms does not permit the installation of a three-ram stack. Only a two-ram stack is short enough to fit. Background XTO Energy found at the commencement of its 2000 - 2002 drilling program, its first since purchasing Platforms A and C from Shell Oil Company, that a standard 3-ram BOP stack was too tall to fit in the platforms' rig substructures. The Commission was contacted and it was agreed that a 2-ram stack could be used as long as one ram was a blind ram and the other was a pipe ram that always had rams that fitted to the pipe being run into and out of the hole. Further, it was agreed that, if a tapered string was being used in the hole, a variable bore ram would have to be substituted for the pipe ram. The attached BOP schematic indicates the BOP stack arrangement proposed by XTO. If this is approved by the Commission, XTO requests that the Commission place this approved BOP Waiver Request and BOP Schematic on file as it is intended to apply to all workover and drilling projects on these platforms. ~TO ~kRGY XTO Energy Inc. BOP's for MGS Platform A & C 13 5/8" 5.000 PSI WP. HYDRIL GK ANNULAR PR£V£NTER W/ COMPANION FLANGE TO BELL NIPPLE DOUBLE 13-518" 5,000 PSI WP. SHAFFER SL BOP WI BLIND RAMS ON TOP 8< PIPE RAMS OR VARIABLE RAMS ON BOTTOM 5.0DO PSI WP RISER 3- 5.000 PSI WP W/ HYDRAULIC ACTUATOR GATE VALVE 3" 5.000 PSI WP MANUAL GATE VALVE 13 5/B" 5.000 PSI WP DRILLING SPOOL W/ TWO 3- 5101 PSI WP OUTLETS DSA 13 5/8- 5.000 PSI WP X 11" 5.000 PSI WP .... . - ;.. BOP COMPONENTS MIDDLE GROUND SHOAL fiELD PLATFORM "A" -... e C_a Timbers 011 Company 100~AK-P1003 0 - .... ........""'" ---..-----"-......-.-..-....---..,,,.--...--.--.... Prepared By: Paul Figel 7-21-04 . . XTO Energy, Inc. Drilling Fluid Program, Pressure Calculations, and Drilling Area Risks MGS C31-26RD Sidetrack Drillim! Fluid Properties: Density PV YP Funnel Vis Initial Gel 10 Minute Gel API Filtrate pH % Solids 6" Hole Section {7,290' - 10,128'MD 9.5 - 10.7 J 18 - 30 15 - 20 55 - 80 8 - 12 1 5 - 30 <10 9.5 <5 Drillinf;! Fluid System: Two Derrick Shale Shakers Desander, Desilter, Mud Cleaner Centrifu e De asser Pit Level Indicator Visual and Audio Alarms Tri Tank Fluid Flow Sensor Fluid A itators Maximum Anticipated Surface Pressure: The maximum anticipated surface pressure (MASP) for the 6" hole section in this sidetrack will be the lesser of the fonnation pore pressure (less a full gas column to the surface) at the 5" casing point or the fonnation fracture pressure at the kick-off point in the existing 7" casing (less a full gas column to the surface). Based on offset well data, the highest fonnation pressure expected in this 6" hole section is 5,200 psi at the section TD of9705' TVD (or 0.536 psi/ft). Well-documented fracture gradient data for this area indicates that the fracture gradient at 7,137'TVD (the kick-off point in the existing 7" casing) is 0.715 psi/ft. Complete evacuation of the wellbore, except for a 0.11 psi/ft gas gradient, is assumed. 6" hole section MASP (pore pressure) MASP (fin breakdown) (9,705 ft)(0.536 - 0.11) = 4,134 psi ,¡ (7,137 ft)(0.715 - 0.11) = 4,318 psi . . Therefore, MASP in the 6" open hole section is 4,134 psi and the 5,000 psi BOPE system to be used will be adequate. Well Proximity Risk: ./ The nearest wellbore to that ofC31-26RD is the abandoned C31-26 wellbore. The two wellbores begin at the same location at the KOP of 7,290' and diverge until they are 494' apart at the top of the productive interval. Drilline Area Risks: The primary drilling risks in the C31-26RD area are those of stuck pipe in the coals of the Tyonek and Hemlock Formations and waterflood-elevated pore pressure within the if" Hemlock Fm. The risk of stuck pipe in the Tyonek and Hemlock coals will be countered in two ways: I.) Drillers experienced at drilling the formations of the Cook Inlet Basin will be used. 2.) Bit selection will include those which experience a slower rate of penetration when entering coal beds, thus giving warning of coals being encountered and preventing the BHA from entering them until the coals can be reamed open. The pore pressure in the Hemlock interval has been elevated to approximately 5,000 - ./ 5,500 psi over the years as a result of water injection. The pressure will be controlled via the designed casing program and the use of appropriately weighted drilling fluid. BOPE will be appropriately rated and monitoring of the drilling fluid system for indications of influxes will be performed via mud logging and PVT system/alarms. Disposal of Muds and Cuttines: MGS Platform C has a dedicated Class II disposal well. All oil-base or sheening waste v/ wellbore fluids will be injected down the disposal well as will cuttings after they are ground. Non-sheening water-base fluids and cuttings will be discharged overboard. C31-26RD Casinf! Properties and Desif!n Verification Casing Perfonnance Properties Internal Collapse Tensile Strength Size Weight Yield Resistance Joint Body TVD MD Design Safety Factor* (in.) (lb/ft) Grade Cnxn fuill Ú!ill (1,OOOlbs) (ft RKB) (ft RKB) T B C 7 23 N-80 BTC 6,340 N/A 1.53 N/A 5 18 L-80 STC 10,140 10,490 396 422 9,705 10,128 8.42 5.09 2.54 . * Tensile design safety factor for the existing 7" casing is not calculated since it is already cemented in place. For the 5" liner, it is calculated using pipe weight less buoyancy. Burst design safety factor for the existing 7" casing is calculated using MASP. For the 5" liner, it is calculated at the top of the liner using reservoir pressure inside and a nonnal fluid gradient outside. Collapse design safety factor for t he existing 7" casing is not calculated since it is already in place and will be exposed to no different differential pressures than it currently experiences. For the 5" liner, it is calculated at TD assuming complete evacuation _ of the liner less a gas gradient to surface. ., Casing Setting Depth Rationale 5" 10,128' RKB, MD Production liner to provide hole stability for production operations. . . C31-26RD Summary of Drillinq Hazards POST THIS NOTICE IN THE DOGHOUSE .-.¡ The target Hemlock reservoir contains a waterflood-elevated .I pressure of approximately 5,200 psi. The mud and BOP systems used to drill this well are designed to contain this pressure. .-.¡ Pipe sticking tendency is possible in the coals above and in the Hemlock reservoir. .-.¡ This well bore is planned to pass approximately 494' from the abandoned C31-26 well bore at a depth of 9,239' MD. .-.¡ There is no H2S risk anticipated for this well. j CONSULT THE C31-26RD WELL PLAN FOR ADDITIONAL INFORMATION XT Energy Inc. S Pia arm C ud Pits Pit #2 145 BBl Pit #4 122 BBl Pit #3 201 BBl Mud Pit #1 54 BBl Pit #5 16 BBl Paul 11 ¢: 0 0 7000 ~ II E ü 7200 Q} (ü ü (/) 7400 7600 7600 - 8000 - ID .æ - 8200 .c: - Q. ID C 8400 m (J t: 8600 ID > ID 8600 :¡ I.. l- I V 9000 9200 9400 9600 9600 1??oo ~~"-~ Location: Field: II)!¡tallation: Energy, Inc.. !NTIêQ Cook Inlet, Alaska Middle Ground Shoals Platform C Slot: slot #19 Well: C31.26 Wellbore: C31.26A (PWB) Scale 1 cm = 40ft -400 20.78 23.47 DLS: 3.00 deg/100ft 29.01 31.84 34.69 37.57 EOC Begin Drop -320 Created by ; Planner Date plotted: 6-May-2004 Plo! raference is C31-26A(PWB). Refwellpath is C31-26A Vers#1. Coordinates are in feet referenca slot #19. True Vertical Depths are reference Rig D¡;¡tum. Measured Dep!hs are refe",nœ Rig Datum. Rig Da!um: Planned Datum Rig Datum to mean""" level: 1 05.00 ft. Plot North is aligned to TRUE North. (feet) -> -240 -160 -80 o 80 160 36.57 34.57 DLS: 2.00 deg/100ft 30.57 28.57 26.57 24.57 22.57 20.57 18.57 Target -Top Hemlock- Continue Drop 15.78 1~¡.78 DLS 2.00 deg/100ft 9.78 7.78 5.78 C31-26 (AWB) Target -Top Hemlock- Continue Drop End of Drop - 9704.00 Tvd, 2112.58 S 255.49 W 3.78 1.78 C31-26A(PWB TD - End Drop C31-26 (AWB) C31-26A (PWB 600 1000 1200 1400 1600 1600 2000 2200 2400 2600 Scale 1 cm = 100ft Vertical Section (feet) .> Azimuth 185.85 with reference 0.00 1\1, 0.00 E from slot #19 TD - End Drop -1280 -1840 -1820 -2000 -2080 (j) (") OJ q¡- (") 3 ;::¡, Iwellbore NamP. C31-26A (PWB) . . XTO Energy, Inc.,slot #19 Platform C, Middle Ground Shoals,Cook Inlet, Alaska '&ii. ~ INTEQ PROPOSAL LISTING Page 1 Well bore: C31-26A (PWB) Wellpath: C31-26A Vers#1 Date Printed: 6-May-2004 Iwell ~~~6 I creat~ 6-Ma -2004 I Last ~evised 6-Ma -2004 Slot Name Installation Platform C I=:G~OO ~OO. I Govemment ID I ~~~l~~~~~~ North 233063.0833 True 2478929.9820 I Eastin~ 34754 5480 I~~ ~ I~'"'' "."""n, I R MERICAN DATUM 1927 datum True INorth~ 00016.5290 Comments " All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Planned Datum 1 05. Oft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 185.85 degrees Bottom hole distance is 2127.97 Feet on azimuth 186.90 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated . . XTO Energy, Inc.,slot #19 Platform C, Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 2 Wellbore: C31-26A (PWB) Wellpath: C31-26A Vers#1 Date Printed: 6-May-2004 '&1. ,,\a INTEQ Wellpath Report MD[ft] Inc[de Azi[deg] TVD[ft] Vertical North[ft] East[ft] Station Station Dogie Vertical Station Comment g] Depth SS Position(Grid Position(Grid g Section North) East) [deg/1 ft] OOftl 7290.00 17.95 182.42 7137.44 7032.44 1103.56S 115.01E 2473118.66 231452.37 0.00 1086.11 KOP 3DS Tie On & Kick off Point 7<\1111 1111 1820 182 !:IS 714R!:IS 7041 !:IS 1148RF S7 ?:<14S? 1S :< 00 741111 1111 20.78 187.51 7241.21 7131'>21 .. "" n~" 111.741= At:> 2:<144827 300 7500.00 23.47 191.08 7333.85 7228.84 1176.99S 105.59E 2473045.47 231441.28 3.00 1160.11 71;1111 1111 21'>21 1!:1:<!:IS 74?4S!:I 7:<1 !:I 5!:1 1?17 !:I7~ !:IR.44F 71 ?:<14:<1 1!:1 :< 00 1?018~ 771111 1111 2!:101 1!:1R.:<1 751:< 1 !:I 7408 1 !:I 1?I;? I;OC:: 84 :<OF ?R ?:<14180:< :<00 1?475.1 7800.00 31.84 198.28 7599.42 7494.42 1311.02S 69.22E 2472912.31 231401.84 3.00 1297.1t 701111 1111 :<4 R!:I 1!:1!:1!:1R 7R8:<0? 7578 O? 1<\I;? R?C:: 51 ??F 0':1 ?:<1:<8? R7 :< 00 1:<SO 5~ RI1I1I1 1111 3757 201.42 77R:<.78 7R5R 78 1417!:1R~ :<03RF ?O ?:<nROSS 300 14075( 8075.44 39.75 202.40 7822.69 7717.69 1461.68S 12.77E 2472762.98 231341.97 3.00 1452.7~ EOC End of Build/Tum 810000 3!:175 ?0240 7841S7 773R 58 1A71; ?11C:: R 7!:1F 1;1 ?:< 1 :<:<5 R5 000 14R78:: R1.411 0:< <\07" 202.40 7873.05 77RR05 . ~"" ."" 318W 1;.4 23132513 000 . . OroD. End of Hold 8200.00 38.57 202.40 7918.85 7813.85 1534.88S 17.40W 2472690.49 231310.13 2.00 1528.6 R<\1111 1111 3R57 20240 7!:1!:1R11 78!:13 11 40 R?W I;R ?:<1?85 R? ? 00 158711 R41111 1111 34.57 202.40 807!:1.45 7!:17445 11;.4" I1?C::: R2 78W .4? 231?R224 200 1 R42.8f 8500.00 32.57 202.40 8162.77 8057.77 1696.14S 83.85W 2472530.80 231240.01 2.00 1695.8E RI;I1I1 1111 3057 202.40 8247!:17 814? !:I7 .7AA "''><> 1 0:< 80W RR ?:<1?18.!:IR ?OO 174RO:: R7nn nn ?R "7 202.40 8334.94 8229.94 1790.15S .70 231199.12 2.00 17!:13.3:: 8800.00 26.57 202.40 8423.59 8318.59 1832.93S 140.23W 2472395.33 231180.51 2.00 1837.6~ RQI1I1 1111 24.57 202.40 8513.79 M08 79 1 R7? R<\C::: R<\ 2:<11R31R 200 187!:1.Qf onnn nn ?? "7 ?11? 411 RI;I1" .4" 8500.45 17191W ?? 231147.0!:l 2.00 lH' ;1, 9100.00 20.57 202.40 8698.44 8593.44 1943.78S 185.91W 2472285.57 231132.31 2.00 1952.6C Q?1111 1111 1R57 202.40 87!:12.RR 8R87RR Q1 ?:<111R84 200 1!:1847( 9239.30 17.78 202.40 8830.00 8725.00 1986.07S 203.34W 2472243.69 231113.91 2.00 1996.4e Target -Top Hemlock- Continue Drop, C31-26RD Tgt Top Hemlock, End of 0':1':10 ':In 1" 78 ?11? 411 RQ?" 7.4 RR?11 7.4 ?111? 71;C::: ". "..., Z41ZZ .2R 2:<1102.31 ? 1111 ?11?.4 1 ~ 9439.30 13.78 202.40 9022.42 8917.42 2036.34S 224.07W 2472193.90 231092.05 2.00 2048.5 Q"<\Q <\11 11.78 202.40 911 !:I. 94 !:I014!:!4 ?11<=;1; 7QC:: R5 ?:<108315 ?OO 01;':10 ':In Q.78 202.40 9218.17 9113.17 2472156.53 231075.63 2.00 ZUXI 9739.30 7.78 202.40 9317.00 9211.99 2088.20S 245.44W 2472142.55 231069.50 2.00 2102.~ QR<\Q <\11 578 202.40 !:I41R 2!:1 !:I311 ?!:I ?O!:l!:l11~ 74 ?:<10R4 75 ? 00 00':10 ':In :< 7R 202.40 9515.94 9410.!:I4 ". "'" n"" 25311W 247212411 2310R1.40 2.00 2121.6~ 10039.30 1.78 202.40 9615.82 9510.81 2111.30S 254.96W 2472119.67 231059.45 2.00 2126.2f 10127.50 0.02 202.40 970400 !:I5!:1!:100 ?11258~ .41 ?:<105R8!:1 200 21?7R1 Fnci of DrOD 101?R ':111 11 no ?11? 411 Q711" 1111 9600.00 2112.58S 255.49W 41 2:<10588!:1 2.00 2127.61 TO - End Or"n Fnrl of DroD v .I / All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Planned Datum 1 05. Oft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 185.85 degrees Bottom hole distance is 2127.97 Feet on azimuth 186.90 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated . . XTO Energy, Inc.,slot #19 Platform C, Middle Ground Shoals, Cook Inlet, Alaska PROPOSAL LISTING Page 3 Wellbore: C31-26A (PWB) Wellpath: C31-26A Vers#1 Date Printed: 6-May-2004 1986.07S W151 30 12.5362 45 30.5607 Surve Standard '> All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Planned Datum 1 05. Oft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 185.85 degrees Bottom hole distance is 2127.97 Feet on azimuth 186.90 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated '&1. BAKlR HUGHIS INTEQ 2472243.69 . . XTO Energy, Inc. C31-26A Vers#1, C31-26A (PWB) slot #19, Platform C CLEARANCE LISTING Page 1 Date Printed: 7-Jul-2004 Middle Ground Shoals, Cook Inlet, Alaska BI. .... INTEQ Ellipse separations are reported ONLY if BOTH wells have uncertainty data Only Depth and Maç¡netic Reference Field error terms are correlated across tie points Proximities beyond ft with expansion rate of ft/1 OOOft are not reported Cutoff is calculated on CENTRE to CENTRE distance Summary data uses Closest Approach clearance calculation for all minima Hole size/Casinç¡s are NOT included Hole size/Casinç¡s are NOT subtracted from Centre-Centre distance Ellipses scaled to 2.00standard deviations. Closinç¡ Factor Confidence limit of 99.80% Errors on Ref start at Slot Permanent Datum (0.00) Report uses Revised: (D-C)/E Factor Calculation We II bore Name I Created I Last Revised C31-26A IPWB) I 6-Mav-2004 I 6-Mav-2004 Well Name I Government ID I Last Revised C31-26 I I 19-Jan-2003 Slot Name slot #19 Latitude N60 45 50.1185 Lon itude W151 308.4436 East 1593.00W Installation Name Platform C Eastin Coord S stem Name 2478929.982 AK-4 on NORTH AMERICAN DATUM 1927 datu nment True Field Name Middle Ground Shoals 234754.548 Coord S stem Name 2500016.529 AK-4 on NORTH AMERICAN DATUM 1927 datu nment True Eastin Clearance Summary Offset Offset Offset Offset Minimum MD[ft] Diverging Ellipse Ellipse Clearance Clearance WellName Wellbore Slot Structure Distance From[ft] Separation MD[ft] Factor MD[ft] Iftl ftl C31-26 C31-26 slot#19 Platform C 0.02 7290.0C 7290.0C IAWB) All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Planned Datum 105.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . XTO Energy, Inc. C31-26A Vers#1, C31-26A (PWB) slot #19, Platform C CLEARANCE LISTING Page 2 Date Printed: 7-Jul-2004 Middle Ground Shoals, Cook Inlet, Alaska 81. ..,. INTEQ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Separation Highside Distance [ft] deal ftl 7290.0C 7137.44 11 03.56~ 115.01E C31-26 7290.0C 7137.4 1103.55E 114.99E 112.7 0.02 7300.0C 7146.9E 11 06.66~ 114.86E C31-26 7300.0C 7146.9< 1106.63E 114.86E 177.8 0.03 7400.0C 7241.21 1139.85~ 111.74E C31-26 7399.9 7242.0~ 1137.20E 113.13E -160.5 3.12 7500.0C 7333.84 1176.99~ 105.59E C31-26 7499.5 7337.0< 1167.13E 110.90E -163.4 11.65 7600.0C 7424.5~ 1217.97~ 96.44E C31-26 7598.4C 7431.5< 1196.07E 108.38E -165.7 25.90 7700.0C 7513.1~ 1262.69E 84.30E C31-26 7696.1 7525.31 1223.55E 104.76E -168.8 45.79 7800.0C 7599.4 1311.02·< 69.22E C31-26 7792.9f 7618.3f 1249.84E 99.93E -171.6 71.03 7900.0C 7683.0 1362.82E 51.22E C31-26 7888.2 7709.9E 1275.46E 94.34E -173.6 101.08 8000.0C 7763.78 1417.96E 30.36E C31-26 7980.61 7798.9 1299.45E 88.23E -175.2 136.49 8075.44 7822.6~ 1461.68E 12.77E C31-26 8049.2f 7865.2C 1316.64E 83.47E -176.2 166.86 8100.0C 7841.58 1476.20E 6.79E C31-26 8071.3 7886.5 1322.16E 81.96E -176.1 177.21 8140.9" 7873.0 1500.40~ 3.18~ C31-26 8108.4f 7922.4 1331.46E 79.55E -176.1 194.48 8200.0C 7918.8 1534.88E 17.401/\ C31-26 8161.6 7973.8 1344.69E 76.11E -176.0 218.95 8300.0C 7998.11 1591.25E 40.621/\ C31-26 8251.31 8060.6< 1366.04E 69.83E -176.1 258.5 8400.0C 8079.4 1645.02E 62.781/\ C31-26 8342.4 8149.1 1386.61E 62.71E -176.3 295.60 8500.0C 8162.7 1696.14E 83.851/\ C31-26 8434.6r 8238. n 1406.55E 54.84E -1767 329.96 8600.0C 8247.9 1744.53E 103.801/\ C31-26 8527.5r 8329.2 1425.89E 46.33E -177.1 361.49 8700.0C 8334.9 1790.15E 122.601/\ C31-26 8622.1 ~ 8421.5 1445.04E 37.23E -177.5 390.05 8800.0C 8423.5 1832.93~ 140.231/\ C31-26 8718.11 8515.0 1463.94E 27.58E -177.9 415.55 8900.0C 8513.7~ 1872.83~ 156.671/\ C31-26 8813.3 8607.9 1482.17E 17.38E -178.4 437.93 9000.0C 8605.4 1909. 79~ 171.911/\ C31-26 8906.0r 8698.51 1498.98E 7.03E -178.9 457.65 9100.0C 8698.4 1943.78< 185.911/\ C31-26 9000.7~ 8791.3 1514.68E 4.00W -179.4 475.2 9200.0C 8792.6E 1974.74E 198.671/\ C31-26 9100.9< 8889.4 1531.20E 15.73V\ -180.0 489.44 9239.3C 8830.0C 1986.07E 203.341/\ C31-26 9139. 7~ 8927.4 1537.75E 19.98~ 179.8 494.08 rams Error Model Standard Standard All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Planned Datum 105.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (10) Prepared by Baker Hughes Incorporated r&i. ..,. . XTO Energy, Inc. . INTEQ Location: Cook Inlet, Alaska Field: Middle Ground Shoals Installation: Platform C Slot: slot #19 Well: C31·26 Well bore: C31·26A (PWB) ;[!~ Created by : Planner Date plotted: 7.Jui-2004 Plot reference is C31-26A (PWB). Ref wellpath is C31-26A Vers#1. Coordinates are in feet reference slot #19. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Planned Datum Rig Datum to mean sea level: 105.00 ft. Piot North is aiigned to TRUE North. 290 TRUE NORTH floo 8600 350 0 10 340 20 ,8500 300 330 .8400 30 2 0 40 320 310 50 300 60 70 280 80 270 3 0 90 260 100 250 110 240 120 230 130 220 140 2 0 210 3,0 150 200 160 190 180 170 Normal Plane Travelling Cylinder - Feet All depths shown are Measured depths on Reference Wel W&i. IIfILs INTEQ Scale 1 em = 20 ft XTO Energy, Inc. Location: Field: Installation: Cook Inlet, Alaska Middle Ground Shoals Platform C -80 -40 East (feet\ -> o 40 8(f 120 -1000 -1040 -1080 -1120 -1160 -1200 -1240 -1280 -1320 ^ I - ã) -1360 ~ - .s:: -1400 t:: 0 Z -1440 -1480 -1520 -1560 -1600 -1640 -1680 ¢:: 0 N II -1720 E (.) Q) -1760 ro (.) CJ) 3050 , 3100 . 3150 . 3200 , 3250 .: f!Jifi {J 2250 , 2300 . 2350 , 2400 . 2450 + 2500, , 2550 3000 ,2600 ,2650 2700 , .8400 ,8450 ,8500 2750 + + 8550 7850 .8600 , B650 .2650 ,2700 ,2750 2700 6SOO 6950 2750 7000 7050 2600 7100 2650 7150 7200 2900 7300 2950 3000 3050 3100 3150 3200 3250 3300 160 3650 3100 3150 3800 [11 ~ -80 -40 Seale 1 em = 20 ft -0 .. 2800 .2850 ,2900 ~ 2950 7550 .. 7800 + 7850 .7900 ,7950 .. 8100 .8150 .. 8200 ,8250 + 8300 ,8350 .8700 , 28'" . 2900 . 2950 , 3000 . 3050 40 80 120 East (feet) -> 160 200 3500 3550 3600 ¢:: o OJ') II E (.) ..... Q) ro (.) CJ) 200 Slot: Well: Wellbore: slot #19 C31-26 C31-26A (PWB) ;[!~ Scale 1 em = 50é/,. West (feet): East (feet) -> -300 -200 -100 -0 100 200 2900.. 2200, 30001- 3100, 2300, .7000 '¡'2700 .2800 KOp~7100' 7200f7200.2900 3200, 3300..' 2400, ..2800 7300-:'-73oo 3400. 7400/.7500 7500/f7600 J + 7700 1.'7800 .26007600/ .7900 / ,8000 7700/ .8100 3500. !-29oo 2500. 3000 3700, 3800. 3100.. 3900, ,8200 4100, 2700 í ,8300 3200 7:.00/.8400 ./ ..8500 /,8600 ,,8700 3300. 79ool'8800 6SOO¡ 9000./ 34001¡2~OO+I/ 9300,' ¡BOOO ~_" I !-2900 440083500: /8100 '"'00. 4300 [!j 3600, ..3000 /8200 i /8300 ,3100 3700, 3800, /8400 3900, ¡ 8500 ,3200 18600 /8700 ,3300 /8800 4100. /8900 4200. /'9000 If!d~:: ,3400 ,3500 ..3600 .3700 3600, 3900, ,",00. 4100, ,6600 ;'6700 4200 .. +6800 !-69oo 4300, 4400 ,7100 .;.2600 8200; .6400 ,8500 ,6600 6900·2700 ,C 7400 + 3000 ,3100 4400, 4500 -i- 5700 5800 " 6SOO 6000i 6100 I- 5000 ,6300 ..5500 ,,5600 ..5700 .5800 ,5900 -300 -200 -100 0 100 200 Seale 1 em = 50';¡' West (feet) : East (feet) -> .3100 ,3200 3300 ,3500 ,3600 .. 3700 ,3200 !-33oo .3400 ..3500 ;3600 ..3700 .;.3800 .3900 ,4000 .4100 .;. 5000 ,4200 .;. 5100 5200 ';'4300 5300 5600 4700 4800 .4900 + 5100 .5200 ,5300 5400 300 ,3800 -900 -1000 -1100 -1200 -1300 -1400 -1500 -1600 -1700 -1800 ^ I Z 0 -1900 ;:¡. ::r - cr -2000 ~ - -2100 -2200 -2300 -2400 -2500 -2600 (f) -2700 C") Q) ëD C") -2800 3 II CJ1 0 -2900 ;::> ,3900 :..4000 4'00 ;.4200 4300 .;. 4400 .4500 .4800 ~ 4700 .;. 4B00 .4900 300 . . XTO C31-26RD R~ILLING FL.UI SPR POSAL --. IFE ¡ Mi~~ XTO C31-26RD Cook Inlet Sidetrack Name Signature Date Originator: Pat Young Reviewed by: Mark Dick Customer Approval: Bill Penrose Version: 1.0 July 3, 2004 Location North Slope Alaska 7/8/2004 Confidential 1 . . XTO<C31-26RD Well Summary Well C31-26RD is a single string sidetrack. A whipstock will be placed at 7,290' (7,137'TVD) and the well displaced to a 9.5 ppg. LSND milling fluid. The well will be sidetracked off the whipstock and drilled to TD with a 10.7 ppg. and a 5" drilling liner will be ran. Displace to a 8.5ppg 3% KCL Brine and completed. IFE Benchmark and Goals IFE Benchmarks No Stuck Pi e No Mud Related HSE Issues Casin /Liner to Bottom Casin and Fluid Summa ~, Si%e in 7 Milling 5600 5500 LSND 9.5 8.0 7 6.0 7290 7137 LSND 9.5 8.0 5 6.0 10128 10120 LSND 10.7 8.0 ed Costs (no problem Costs De-completion 6,000 $1950 $7,950 $7,950 Milling - -7,290 $24,800 $1300 $26,100 $34,050 7,290-10,128 $56,750 $6,500 $63,250 $97,300 10,128 com letion $7,200 $1950 $9,150 $106,450 TOTAL Totals $106,450 Location North Slope Alaska 7/8/2004 Confidential 2 , . ,)'. XTO C31-26RD Milling Operation Drilling Fluid System LSND Key Products MI Barite, DUO-VIS, Pac Plus UL, Soda Ash, Caustic, Bicarb, Lubetex, FLO- LUBE II, Spersene, Desco CF Solids Control Shakers, Centrifuge, and Magnets Metal cuttings. Potential Problems Torque. Hole Cleaning. MILLING OPERATIONS MUD PROPERTIES Depth > MD Mud Wt. YieldPöint API Fluid Loss Chloride (ft) (Ib/gal) PV (lb/100fr) (11)1I30min) s (mg/l) 7,129 9.5 15-25 40+ 5-6 <1000 9.0 -9.5 LSND Mud Formulation: Soda Ash Gel Poly Pac Duo-VIs Barite Lubetex FLO-LuBE II 0.2 Ib/bbl 5.0lb/bbl 1.0 Ib/bbl 1.75lb/bbl For 9.5 ppg. 1.0 % If Needed for Torque and Drag 1.0 % If Needed for torque and Drag Milling Operations ~ The window will be milled with the 9.5 Iblgal LSND drilling fluid that is to be used to drill the Production section of the well. This will negate the need for a fluid swap and weighting up. ~ Maintain good rheology (40 YP) to remove the metal fragments from the well bore. ~ The possibility of problems caused by re-circulation of the metal shavings can be minimized by the use of the finest shaker screens possible, ensuring the condition of the screens is monitored, and the presence of sufficient magnets to capture all metal fragments. ~ After milling the window circulate at least 1 % bottoms up to ensure that the hole is clean. Consider using Super Sweep at the conclusion of the milling operations to assist in the removal of any residual metal. ~ Clean the BOPE's, flowline, and all other downstream equipment to remove as much of the metal debris as possible. Milling Operations Recommended Solids Control Equipment Shaker Screens Centrifu e Ma nets 110/160's or as needed to control mud loss over shakers. Run as needed to control drill solids %, as well as mud wei ht. At a ro riate locations Location North Slope Alaska 7/8/2004 Confidential 3 . . XTO C31-26RD Production Interval - 6.0" Drilling Fluid· System LSND Key Products MI Barite, MI Gel, DUO-VIS, Pac Plus UL, Soda Ash, Caustic, Bicarb, Resinex, Asphasol, Lubetex, FLO-LuBE II, Spersene, Desco CF Solids Control Utilize all available equipment Hole Cleaning Potential Problems Hole integrity and condition for liner running and cementing Directional control, Sliding Lost circulation INTERVAL MUD PROPERTIES Depth MD Mud Wt. Yield Point API Fluid Loss Chlorides (ft) (Ib/gal) (lb/100fr) (mI/30min) (mg/l) pH 7,129-10,128 9.5 - 10.7 15-20 8-1 0 cc <1000 9.5 Intermediate Hole Interval Operations > Continue to use the 9.5 Ib/gal LSND mud to drill the Production section. > Drill ahead using PAC materials to control fluid losses. Use Duo-vIS to maintain rheology. Tannathin, Desco CF, and Spersene may also be used to adjust and fine-tune the rheologies. > Adjust rheology, ROP, pipe rotation speed, pipe running speeds and pump rates as needed to balance hole cleaning and ECD. See Virtual Hydraulics Modeling attached. > Mud weight will be weighted as the hole dictates. Production Hole Interval Weight Up Fluid Soda Ash Poly Pac Duo-VIs Resinex Asphasol Barite 0.2 Ib/bbl 0.5 Ib/bbl 0.751b/bbl to bring the active system up to 41b/bbl to bring the active system up to 3 Ib/bbl to bring the active system up to 10.1 ppg > Ensure that the flow rate is at least 350 gpm to ensure adequate hole cleaning is being achieved. Reduce pump rates immediately if packing off occurs. Pump high viscosity weighted sweeps and ream carefully to clean the hole before proceeding with further drilling. > Upon reaching TD watch the bottoms-up cuttings closely. If the well does not readily cleanup or if there is any excess of torque, drag, pick-up or slack-off weights pump a second high viscosity sweep and circulate bottoms up again. > A G-Seal" and Alpine Co-polymer bead pill consisting of 6#/bbl. of G-seal and 6#/bbl. beads will be spotted in the open hole prior to running casing. > If hole conditions allow adjust rheology to reduce swab/surge pressures prior to pulling out of the hole for the 7.0" liner. (YP @ 20 - 25) Reduce viscosity according to cementing program after liner is on bottom. Cement the 7.0" liner as per program. Location North Slope Alaska 7/8/2004 Confidential 4 . . XTOC31-26RD Production Interval Drilling Concerns )0> Hole Cleaning: Drilled formations may change the rheology of the mud - be prepared to treat the mud should this occur. Watch the drill rates. Adjust rheology and drilling criteria to match the hole cleaning needs. RaP's above 100 fph should be carefully monitored due to the modeled poor hole cleaning that will occur at these rates. )0> Wellbore Stability: Monitor hole conditions closely and inspect cuttings for indications of well bore instability. )0> Lubricity: Record all torque and drag indicators before and after adding any lubricant is the need for lubricants become evident. Start with 1 % Lubetex and 1 % FLO-LUBE II along with sweeping the hole with 4-6 ppb. Of Alpine Co-Polymer Beads fine and coarse. Monitor torque and drag indicators. Speak with the Project Engineer if the need for additional lubricants is needed. >- Sliding: If additional lubricity is required for sliding, sweep the hole with a pill containing addition lubricant such as Lubetex and beads. Co-polymer beads in a pill form can aid in sliding and in the directional part of the hole in concentrations of 5-8 ppb. Lost Circulation Pill for LSND Be sure to have adequate Lost Circulation Material (LCM) on location. In the event that circulation is lost spot a pill containing LCM such as MIX II Fine and Medium andlor Nut Plug. Ensure particle sizes of bridging materials can pass through the down hole tools and motors prior to mixing and spotting. Mix up a LCM pill with 25 Iblbbl MIX II Fine and 15 Iblbbl MIX II Course cellulose material and spot across the lost circulation zone. If losses stop, pull into casing and apply 200-psi squeeze pressure and watch for pressure bleed-off. If pressure holds for 15 minutes, resume drilling. If pressure does not hold, spot another pill as described above. If seepage losses occur after drilling is resumed, consideration should be given to adding 5 - 8 Iblbbl MIX /I Fine cellulose material to the system while circulating. Sidetrack Interval Recommended Solids Control Equipment Œ.~ Shaker Screens 210/175 or as needed to control mud losses over shakers. De-sander Not needed. Mud Cleaner/De-silter As needed to control sand/silt, will help downstream equipment. CentrifuQe Run as needed to control drill solids %, as well as mud weight. Location North Slope Alaska 7/8/2004 Confidential 5 . . f£j Proposal No: 100185186A XTO Energy MGS C31-26RD Inlet Drilling Rig Middle Ground Shoal Field Alaska July 13, 2004 Well Recommendation Prepared for: Bill Penrose Project Drilling Engineer Fairweather E&P Services Inc. Prepared by: J. Jay Garner Manager, City Sales Kenai, Alaska Bus Phone: Email: Mobile: (907) 349-6518, Anchorage jgarner@bjservices.com (907) 229-6536 POW E R V I S I 0 NIM Service Point: Kenai, AK Bus Phone: Fax: (907) 776-4084 (907) 659-2329 (907) 776-4087 Service Representatives: J. Jay Garner Manager, City Sales Kenai, Alaska Bus Phone: Email: Mobile: (907) 349-6518, Anchorage jgarner@bjservices.com (907) 229-6536 Gr4105 . Operator Name: Well Name: Job Description: Date: XTO Energy MGS C31-26RO Production Liner July 13, 2004 . (£j Proposal No: 100185186A JOB AT A GLANCE Depth (TVD) Depth (MD) Hole Size Liner SizelWeight : Pump Via Total Mix Water Required Spacer MCS-4 Spacer Density Tail Slurry Liner Cement Density Yield Displacement Drilling Mud Density 9,705 ft 10,128ft 6in 5 in, 18 Ibs/ft Drill Pipe 31/2" 0.0. (2.764" .1.0) 13.3 # 5" 0.0. (4.276" .1.0) 18 # 1 ,042 gals 30 bbls 14.5 ppg 212 sacks 15.8 ppg 1 . 15 cf/sack 108 bbls 12.0 ppg Report Printed on: July 13, 2004 2:25 PM Gr4109 Page 5 . Operator Name: Well Name: Job Description: Date: XTO Energy MGS C31-26RD Production Liner July 13, 2004 . Lm Proposal No: 100185186A WELL DATA ANNULAR GEOMETRY ANNULAR 1.0. (in) 6.276 CASING 6.000 HOLE I I I MEASURED 7,290 10,128 DEPTH(ft} I TRUE VERTICAL I 7,137 i 9,705 SUSPENDED PIPES DIAMETER (in) I WEIGHT I DEPTH(ft} 0.0. I 1.0. (Ibs/ft) I MEASURED I TRUE VERTICAL 5.000 I 4.276 I 18 I 10,128 I 9,705 Drill Pipe 3.5 (in) 00, 2.764 (in) 10, 13.3 (Ibs/ft) set @ Drill Pipe 5.0 (in) 00, 4.276 (in) 10, 18 (Ibs/ft) set @ Depth to Top of Liner Float Collar set @ Mud Density Mud Type Est. Static Temp. Est. Circ. Temp. VOLUME CALCULATIONS 290 ft x 0.0785 cf/ft 2,838 ft x 0.0600 cf/ft 7,000 ft 10,128 ft 7,000 ft 10,128 ft 12.00 ppg Water Based 157 0 F 135 0 F :: 23 cf 221 cf 244 cf 44 bbls with 0 % excess :: with 30 % excess :: TOTAL SLURRY VOLUME :: Report Printed on: July 13, 2004 2:25 PM Page 6 Gr4117 . . Operator Name: Well Name: Job Description: Date: XTO Energy MGS C31-26RD Production Liner July 13, 2004 Wj Proposal No: 100185186A FLUID SPECIFICATIONS Spacer 30.0 bbls MCS-4 Spacer + 14 Ibs/bbl R-3 + 0.25 Ibs/bbl CD-31 + 0.5 gal/bbl FP-6L + 25.15 Ibs/bbl Bentonite + 314 Ibs/bbl Barite + 1 gal/bbl MCS- AG @ 14.5 ppg FLUID VOLUME VOLUME CU-FT FACTOR AMOUNT AND TYPE OF CEMENT Tail Slurry 244 I 1.15 = 212 sacks Class G Cement + 0.05% bwoc ASA- 301 + 0.2% bwoc R-3 + 0.8% bwoc FL-63 + 0.2% bwoc CD-32 + 1 gals/100 sack FP-6L + 43.6% Fresh Water 107.5 bbls Drilling Mud @ 12 ppg Displacement CEMENT PROPERTIES Slurry Weight (ppg) Slurry Yield (cflsack) Amount of Mix Water (gps) Amount of Mix Fluid (gps) SLURRY NO.1 15.80 1.15 4.91 4.92 1. Final system designs are subject to adjustment based on results of pending pilot blend testing. Report Printed on: July 13, 2004 2:25 PM Page 7 Gr4129 . . Wj Operator Name: XTO Energy Well Name: MGS C31-26RD Date: July 13, 2004 Proposal No: 100185186A PRODUCT DESCRIPTIONS ASA-301 Additive used to reduce or eliminate free water and settling in cement slurries. Barite A naturally occuring mineral (Barium Sulfate). It is widely used as a weighting material in cement spacers and occasionally in cement slurries. It can yield a slurry density in excess of 19 Ibs/gal. Bentonite Commonly called gel, it is a clay material used as a cement extender and to control excessive free water. CD-31 A free flowing high molecular weight dispersant used to lower slurry viscosity and help provide turbulent flow properties at reduced pump rates. CD-31 also assists in fluid loss control. CD-32 A patented, free-flowing, water soluble polymer that is an efficient and effective dispersant for primary and remedial cementing. Class G Cement Intended for use as a basic cement from surface to 8000 ft as manufactured, or can be used with accelerators and retarders to cover a wide range of well depths and temperatures. FL-33 A patented cement fluid loss additive that provides exceptional fluid loss control across a wide range of temperatures, salinity conditions, and remedial cementing applications at low to high temperature ranges. FL-63 A non-retarding, non-viscosifying fluid loss additive particularly suited for use with coil tubing and/or close tolerance liner cementing. FL-63 is effective from low to high temperatures. Concentrations of 0.2% to 1.0% BWOC are typical. FP-6L A clear liquid that decreases foaming in slurries during mixing. MCS-4 A turbulent flow spacer system that prevents water and oil-base mud and cement contamination and water-wets the casing to increase bonding. MCS-AG A surfactant used in cement spacer systems to prevent mud incompatability and improve bonding. R-3 A low temperature retarder used in a wide range of slurry formulations to extend the slurry thickening time. Report Printed on: July 13, 2004 2:25 PM Page 10 Gr4163 XTO APD . . Subject: XTO APD From: Bill Penrose <bill@fairweather.com> Date: Mon, 26 Ju12004 10:54:21 -0800 To: tom _ maunder@admin.state.ak.us Tom, I just dropped off some permitting documents to the Commission for approval. They are: Sundry Notice to P&A the existing C31-26 wellbore APD for drilling the C31-26RD sidetrack, containing... ... a BOP waiver request When/if these get approved, would you please send me copies of the approvals (including the waiver approval) when you send the originals to XTO? That way I can make sure that everything gets to the platform for reference when the inspectors arrive for their duties. Thanks! Regards, Bill 1 of 1 7/26/2004 1 :21 PM ;[!9 . . July 26, 2004 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Permit to Drill: C31-26RD Sidetrack Dear Mr. Norman, XTO Energy, Inc. hereby applies for a Permit to Drill an offshore 'development well from Platform C in the Middle Ground Shoal Field of Cook Inlet. The well is planned as a sidetrack of the existing C31-26 wellbore in order to penetrate and develop an un-drained portion of the Hemlock conglomerate in the vicinity of Platform C.,/ Approval of the associated pre-drilling work plan for the existing wellbore has been requested via a Sundry Notice submitted under separate cover. The anticipated spud date of C31-26RD is approximately August 20,2004. ./ / The well will be sidetracked at 7,290' from the existing 7" production casing. A 6" hole will be directionally drilled to the base of the Hemlock Reservoir, a 5" production liner will be cemented in place and a ~' gas lift completion installed. 'd"'1/'i>"'( d~[i/ lr'!"I\ '"1.(").'6 Please find attached information as required by 20 AAC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill per 20 AAC 25.005 (a). 2) Fee of $100.00 payable to the State of Alaska per 20 AAC 25.005 (c) (1). 3) A directional plat showing the well's proposed surface and bottomhole locations per 20 AAC 25.050 (c) (2). 4) Directional plots and proximity calculations in accordance with the requirements of 20 AAC 25.050. 5) Diagrams and descriptions of the BOP equipment to be used are submitted as required by 20 AAC 25.035 (a)(l) and (b) as well as a request for ./ waiver of one of the provisions of those regulations. 6) A complete proposed casing program is attached as per 20 AAC 25.030. 7) The drilling fluid program, in addition to the requirements of 20 AAC 25.033 is attached. 8) A copy of the proposed drilling program is attached. 9) XTO Energy does not anticipate the presence of H2S in the formation to be encountered in this well. However, H2S monitoring equipment will be vi functioning on the rig at all times during sidetracking, drilling and XTO Energy Inc.CQ~5ffili~.ß~r'lti§>~·ð R1~11\~fS~7f5 . (915) 682-8873 . Fax: (915) 687-0862 . . Mr. John Norman Page 2 10) While this well is considered to be a development well, basic mud logging / will be performed while drilling to aid in tracking the location, thickness and quality of the intervals penetrated. 11) A Summary of Drilling Hazards is attached. 12) The following are XTO Energy's designated contacts for reporting responsibilities to the Commission: 1) Completion Report (20 AAC 25.070) Bill Penrose, Senior Drilling Engineer (907) 258-3446 2) Geologic Data and Logs (20 AAC 25.071) Mike Langeler, Senior Geologist (817) 885-2581 If you have any questions or require additional information, please contact me at (432) 620-6718 or Bill Penrose at (907) 258-3446. Sincerely, XTO ENERGY, INC. fdh L ~ Bobby L. Smith Drilling/Operations Manager enclosures cc: Bill Penrose Or-\Ir"if' 'A L ;-< ILJ 11\1 í, MGS C31 RD Proposed 1-0il 2041400 SFD 7/27/2004 FAIRWEATHER EXPLORATION & PRODUCTION SERVICES INC. GENERAL ACCOUNT P.O. BOX 103296 ANCHORAGE, AK 99510-3296 PH. (907) 258-3446 12911 FIRST NATIONAL BANK A LAS K A 89-6-1252 DATE 7/23/2004 AMOUNT $100.00 PAY One Hundred Dollars And 00 Cents TO THE STATE OF ALASKA ORDER ALASKA DEPARTMENT OF REVENUE OF PO BOX 110420 JUNEAU AK 99811-0420 USA III 0 ¡. 2 9 ¡. ¡. III I: ¡. 2 5 2 0 0 0 b 0 I: o. ¡. 2 a 2 ~ 0 III 6J D ID D o ~ ~ ID o Æ " o o m (f) . NP e . . TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERJP ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME PTD# C3/-2~ t?~ ¡fl45 ? me¡ - /c/ò ./ Development Service CHECK WßA T APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API Dumber Jast two (2) digits are between 6.0-69) Exploration Stratigraphic "CLUE". The permit is for a new weJlbore segment of existing well . Permit No, API No. . Production. sbould continue to be reported as a function 'of tbe original API Dumber. stated above. HOLE ]n accordance with 2.0 AAC 25..0.05(1), an records, data and Jogs acquired for tbe pilot boJe must be dearly differentiated in botb name (name on permit plus PH) . and API Dumber (Sa - 70/80) from records, data and logs acquired for wen (name on permit). PÜJOT (PH) SPACING EXCEPTJON DRY DITCH SAMPLE The permit is approved subject ·to fuD . compJiance with 20 AAC 2S..oS5~ Approval to perforate and produce is contingent upon issuance of ~ conservation order approving a spacing exception. (Company Name) assumes tbe liability of any protest to the spacing .exception tbat may occur. AU dry ditch sample sets submitted to tbe Commission must be in no greater ·tban 3.0' sample intervals from below tbe permafrost or from where samples are first caugbt and 10' sample inter:vals througb target zones. D D Well bore seg Annular Disposal Off Program DEV On/Off Shore Unit Well Name MGS C31-26RD DEV / PEND GeoArea 820 MIDDLEGRQUN_D_ SHOAL, Governed by CO M _ _ CO # $tate$: n may be compl~ted_.. closer thao 1 QOO'. to aoy_ weJI ~(Îlling to or c_apable_ of pr9ductiog from the same pool,. .n Ne<ilrest welJ will be P&,ö.'d C:3J :26 J--:5DO' away) 5241j4 E,f,Q OLL_- Std_ 3630Q4_0_n_9l1]£200t 03652600, whJch_repJaced J Correct b9nd oumb_er iJ) . Ye$ Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes NA NA NA NA Initial ClassfType MIDDLE GROUND SHOAL, E,F,G OIL - 524114 Field & Pool Permit fee attache~ _Lease number appropriate _U_nlque well_n_arne_and ou.mb_er Jocated in_a_ d_efine~ pool_ from driJling unitb_ound_ary_ from otl}eJ wells _S_ufficienjacreage_ayailable in.dJilliog unjt Jtdevi<ilted, js weJlbore pl<iltjncJuded located pr.oper _distance Jocated pß)per ~lstance We We.1 WeJ 2 3 4 5 6 7 8 9 Administration _Operator ollly affected party _Oper.ator bas_appropriate_ bond lnJorce c_al1 be lssued wjtl}out conservation order c_al1 be lssued witl}out ~"~'n'~·'~':"':' """. Can permit "'co ~""'~'I~" "'~'~I _WeJI'^^^·^- i: Allw I I ) les~ ~\"I~,"~h~'~""_~~I"_'¡'. Y.......1!"'1:PvaJ LI¡¡;;; ......r-.v.....u UvlV,"e 10# in_cornrnel1t$) (For Il1jectioo Order. # (put jdeotlfied (FOr servjce _~elJ on'" than 3 mOl : ,,-,,,,,,~,,d wlthin area alld_strata _authori;.;ed by_ yI11.~J (Forser.vice well only) Per.mit Permil o 11 12 13 14 15 16 17 Date 7/27/2004 Appr SFD Sidetrack of _e~isting wel 02J2)(iii}. welJbore, jn origi.n<ilLwellbore. Or discharge per NPDES fullycemellted, Rig js 10c:atedol1 offs_hor_e _platform wilh _steeLpjts/tanlss. All waste Þ Clas_s JL "'leI 30A:2_87 E'ro)(imlt}/ analysis p~rtorme_d, Nearest welJboreJs <ilbandoned portjoRof original weJlbore. BOE' stack wi M<ilximum SHE' Rig jSßquippe_dwith 5 Ke.quipment,_but onJy2 CalcuJated MASf> 4134 psi._ E'laoned BOP Jest be_ io place. j 0.3 EMW. re_commended. mited .gas. E)(cep!lon -1O.]ppg. ram$ due to _height Jestrlctions. e LikeJY_MASf> much lower dueto press_ure_5_000 psJ H2S is nole~pe_cted._ Rig JS_ equipped_ with _sellSOrS .and alarms. Mud log planne_d, _NA NA NA NA Xes Yes Yes Yes Yes NA Yes No_ Yes Yes Yes No NA Con_siJ)tel1cyhas been J~sued_ for_ tbi$ pr_oiect_ Pre-produced ACfI/IP. Fjndjng of Conductor wellbore. ,A.11 ~"""^": AOCFRH7. Sur sing $et _al1d cemented jn_ oJigil1al Pre "~~,n" ~~·'n" cemented - - - - - - l'Ie1 s _seUo ongin_al ~'!!i"i~.;:, _"'~I._a!I'" koow_n -Pfo_duc;tiye bori~ons C,_T" S&_ perl1Jafr9st Adequate tankage OJ reserve pit _ . . . . . Jfare-drill. bas_a_ to:403 for abandonme.nt beeo apPJoved Jfdiverter required, does it meet reguJations_ DJilIiog flujd program schem<iltic& eQ.uip Jisladequate BOPEs, do_they meet j=)lan_ned mud weigh_ts 9.5 _(pu_t psig in_comments) 64) reguJa_tion test to _CMke.l1Janjfold çompJie~ w/APIRP-53 (May Work will OCC_Ur without _operatjonsbutdo_~n _ 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 ""_~')<>'" ex_empted. COIJdu_ctor _S_urface ~a _CMT v_ol jeQu_ateJo circ_utate_ o_nconduçtoc & SUJtCJ>g CMT vo jeQuateJo tie-tnJong .string to_surf ~g CMTwi :>Yer.aJ strlllg.provided ~...sing_pJotect~ all known USDWs Engineering Ca$il1g de_signs adeçua_te for _A~equatewe!lbore sep;;1ratjon -Pfoposed Date TEM 7/28/2004 ~~¡ Appr ralil1g appropriate; _BOPE.Pfes$ ~ instalJe_d_ Þe wiJ times dUJiog sidetrackjng _&_ c.ompletion operatiom¡. wUl Þe drilled with up_ to _be mudlogged aod 1:12S monJtorjng_eçuipmenl wells wlthin Jl.OR Yerified (for_ s_ervice welJ only) Js presence_ of H2S gas_ probable MeçbanicaLcoodjlion p{ wi andJun_ctionjng 9f the rig alaI H2S oo_t expected. butwel Yes Ye$ NA _NA NA C.al1 be issued wlo hydrogen_ s_ulfide measu(e$ Permit Datapreseoted on_ pote_ntial overpressurezOl1eJ) 135 136 Date 37 7/27/2004. 38 39 Geology 0.7 ppg mud. J (~1Q.4 ppg_EMW)~ Expected reservojr pre_S$UJe iJ) _5200 psi Appr SFD Seismic.analysjs_ of sballow gas_zooes Offset water injection has raised pressure in block. Expected reservoir pressure is 5200 psi or about 10.4 ppg EMW. Wel will be mudlogged and reservoir will be drilled with mud up to 1 D.7 ppg. Date off-sh_ore) _weelsly progress_reports [e~ploratory _ol1ly] Date ~:~ /j I I Engin.ee~ing /_ V -, -V "1 Commissioner I ;cItf7 Seabedcondjtioo $urvey -Clf Conta_ct namelphoneJor