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Home My WebLink About202-055Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250807 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 23 50133206350000 214093 6/26/2025 AK E-LINE PPROF T40741 BCU 25 50133206440000 214132 7/16/2025 AK E-LINE Plug/Cement T40742 BRU 211-35 50283201890000 223050 6/11/2025 AK E-LINE Perf T40743 BRU 211-35 50283201890000 223050 6/20/2025 AK E-LINE PPROF T40743 BRU 213-26 50283201920000 223069 7/7/2025 AK E-LINE Perf T40744 BRU 213-26T 50283202040000 225038 7/2/2025 AK E-LINE Perf T40745 BRU 213-26T 50283202040000 225038 7/4/2025 AK E-LINE Perf T40745 BRU 213-26T 50283202040000 225038 6/28/2025 AK E-LINE Perf T40745 BRU 241-23 50283201910000 223061 7/18/2025 AK E-LINE Perf T40746 GP 11-13RD 50733200260100 191133 6/2/2025 AK E-LINE PPFROF T40747 KBU 32-06 50133206580000 216137 7/1/2025 AK E-LINE PPROF T40748 MPU E-28 50029232590000 202055 5/8/2025 AK E-LINE Caliper T40749 MPU F-21 50029226940000 196135 7/10/2025 AK E-LINE Caliper T40750 MPU G-02 50029219260000 189028 7/6/2025 AK E-LINE Puncher T40751 MPU I-01 50029220650000 190090 7/7/2025 AK E-LINE TubingPunch T40752 NS-19 50029231220000 202207 6/27/2025 AK E-LINE Perf T40753 PBU J-07C 50029202410300 225026 5/29/2025 BAKER MRPM T40754 PBU N-07B 50029201370200 223122 6/7/2025 BAKER MRPM T40755 PCU-05 50283202030000 225037 7/10/2024 AK E-LINE Perf T40756 TBU D-07RD2 50733201170200 192155 7/19/2025 AK E-LINE Perf T40757 TBU M-09 50733204760000 196127 7/18/2025 AK E-LINE Perf T40758 Please include current contact information if different from above. T40749MPU E-28 50029232590000 202055 5/8/2025 AK E-LINE Caliper Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.08 11:16:55 -08'00' 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:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Cc:Brooks, Phoebe L (OGC) Subject:FW: Trading Bay Unit G-12RD3 (PTD 2020550) - AIO 5.031 Compliance Temperature Survey - April 2022 Date:Wednesday, May 25, 2022 9:45:06 AM Attachments:G-12RD3 Temperature Survey Overlay Plot - 2022_04_28.pdf From: Josh Allely - (C) <Josh.Allely@hilcorp.com> Sent: Thursday, May 19, 2022 12:12 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: Trading Bay Unit G-12RD3 (PTD 2020550) - AIO 5.031 Compliance Temperature Survey - April 2022 Mr Wallace, Per AIO 5.031 (Administrative Approval), Trading Bay Unit G-12RD3 (PTD 2020550) requires a biennial temperature survey. The 2022 survey was completed on 4/28/2022. The survey data (see attached plot) is consistent with previous temperature surveys and confirms that all the injected fluids are being contained in the approved strata. Let me know if you have any questions or require additional information/data. Thanks Josh Allely Well Integrity Engineer Kenai – Hilcorp Alaska 907-777-8505 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Well: Field:04/28/2022Hilcorp G-12RD3 Grayling 50 60 70 80 90 100 110 120 130 140 150 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 0 500 1000 1500 2000 2500 3000 3500 4000 4500 Temperature (Deg. F)Depth-MD, (feet)Pressure (psia) Pressure 22 Perfs 26"17 3/4"13 3/8" 7"9 5/8"4 1/2"Press 20 Press 14 Temperature 22 Press 20 Temp 14 Pressure-Temperature Profile 1. Going in hole Overlay 2. Static 3. 2014 - 2020 -2022 Wallace, Chris D (CED) From: Wallace, Chris D (CED) Sent: Wednesday, September 2, 2020 3:32 PM To: Katherine O'connor Cc: Dan Marlowe; Juanita Lovett Subject: RE: [EXTERNAL] RE: TBU G-12RD3 (PTD 2020550) Possible Communication Katherine, Plan for additional 14 days diagnostics, monitoring, and testing is approved. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Katherine O'connor <Katherine.Oconnor@hilcorp.com> Sent: Wednesday, September 2, 2020 3:27 PM To: Wallace, Chris D (CED) <chris.waIlace @alaska.gov> Cc: Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: TBU G-12RD3 (PTD 2020550) Possible Communication Hi Chris We are just getting out of the 30 days Hilcorp originally requested and would like to extend the diagnostic period 14 more days. A static temperature survey was run on 8/27/2020, and we would like to run a temperature survey while the well is on injection to confirm fluid is going into the reservoir and not the annulus. Please let me know if you have any questions. Thanks! Katherine O'Connor CIO Operations Engineer Katherine.oconnor@hilcorp.com W: (907) 777-8376 C: (214) 684-7400 From: Holly Tipton Sent: Monday, August 10, 2020 4:27 PM To: Wallace, Chris D (CED) <chris.waIlace @alaska.Rov> Cc: Katherine O'connor <Katherine.Oconnor@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg /'5 P.1. Supervisor n��Gi �2(I (Gr DATE: Wednesday, August 21, 2019 SUBJECT: Mechanical Integrity Tests (C Hilcorp Alaska LLC G-12RD3 FROM: Austin McLeod TRADING BAY UNIT G-12RD3 Petroleum Inspector Sre: Inspector Reviewed By: P.I. Suprv._-w_— NON -CONFIDENTIAL Comm Well Name TRADING BAY UNIT G-12RD3 API Well Number 50-733-20116-03-00 Inspector Name: Austin McLeod Permit Number: 202-055-0 Inspection Date: 8/19/2019 Insp Num: mi[SAM190820111019 Rel Insp Num: Packer Depth G-12RD3 ' Type Inj I W 'TVD 8948 2020550 Type Test SPT Test psi 2237 nped: 1.2 '11313L Returned: I 4YRTST P/F P I Notes: MIT -IA Pretest Initial I5 Min 30 Min 45 Min 60 Min Ubing 2900 2900 - 2900- 2900 - IA 1558 2399 2397 2;95 OA 17 17 17 17 Wednesday, August 21, 2019 Page 1 of I Wallace, Chris D (CED) From: Holly Tipton <hotipton@hilcorp.com> Sent: Monday, August 10, 2020 4:27 PM To: Wallace, Chris D (CED) Cc: Katherine O'connor; Dan Marlowe; Juanita Lovett Subject: RE: [EXTERNAL] RE: TBU G-12RD3 (PTD 2020550) Possible Communication Hi Chris, Thank you for the prompt response and approval for diagnostics. On the morning of August 4th, the facility noticed what was thought to be slight thermal expansion consistent with historic seasonal cyclic swings on G-12RD3 and discussed it with the Operations Manager. At this point, the cold injection water was shut-in and allowed to warm up and stabilize over the next few days which can be observed on the injection volume drop. As the well warms up, the IA pressure builds and stabilizes. On August 6th , normal stabilization pressure was observed so injection resumed. Midday on Saturday August 8th a more obvious increase within 15 minutes (^2600 IA / ^2900 T) occurred indicating that we had tubing by IA communication. Operations immediately shut-in the well and notified the operations manager, operations engineer, and the regulatory techs. If you have any further questions please let us know. Thank you, Holly From: Wallace, Chris D (CED) [mailto:chris.wallace@alaska.gov] Sent: Monday, August 10, 2020 3:02 PM To: Holly Tipton <hotipton@hilcorp.com> Cc: Katherine O'connor <Katherine.Oconnor@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <j i ovett @ h i l co rp. co m> Subject: [EXTERNAL] RE: TBU G-12RD3 (PTD 2020550) Possible Communication Holly, Thank you for the information. Plan for diagnostics, monitoring, and testing is approved. Looking over the data provided, I see significant possible Tubing and IA transference from 08/03/2020 to 8/4/2020. 1 Water Date Tubing IA OA OOA OOOA OOOOA Injection 8/10/2020 0 8/9/2020 200 0 12.5 13 125 125 0 8/8/2020 0 0 12.5 13 125 125 3541 8/7/2020 2850 1700 12 12.5 125 125 6458 8/6/2020 2800 1700 12.5 13 128 125 4682 8/5/2020 175 1850 12 12.5 125 125 0 8/4/2020 175 1625 11.7 12.5 125 125 2711 8/3/2020 2900 325 12 12.5 125 125 6479 8/2/2020 2800 315 12 13 125 125 6387 8/1/2020 2900 250 12 13 125 122 6469 1 7/31/2020 2700 225 12 12 125 122 5927 Looking at AIO 5 Rule 6 amended October 10, 1986: "Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action, and when an USDW is not endangered, obtain Commission approval to continue injection." Please give me a brief description of the internal timeline and process Hilcorp went through to help me understand what at first glance appears to be a failure by Hilcorp to notify AOGCC on the first business day after an indication of a pressure communication. If there is any additional information that was passed to the commission on this matter that I am not aware of please let me know. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chrismaIlace@alaska.pov CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Chris Wallace at 907-793-1250 or chris.wallace@alaska.c�ov. From: Holly Tipton <hotipton@hilcorp.com> Sent: Monday, August 10, 2020 2:11 PM To: Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: Katherine O'connor <Katherine.Oconnor@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Juanita Lovett <ilovett@hilcorp.com> Subject: TBU G-12RD3 Possible Communication Hi Chris, G-12RD3 was shut-in yesterday after an unexpected IA pressure increase. Hilcorp requests 30 days to conduct well diagnostics to test for potential communication. During that time, the well would be brought back online as needed to conduct temperature surveys, wellhead tests, etc. A well schematic and 90 Day TIO plot are attached for your review. Please let me know if you have any questions. Thanks! Holly Tipton Regulatory Tech - CIO Asset Team Hilcorp Alaska, LLC o: (907) 777-8330 1 m: (281) 543-8964 e: hotipton@hilcorp.com • • Brooks, Phoebe L (DOA) PTD*. 2O2.OSSO From: Larry Greenstein <Igreenstein@hilcorp.com> Sent: Saturday, September 19, 2015 8:50 AM To: Brooks, Phoebe L(DOA) Subject: RE: MIT Grayling 08-27-2015 Attachments: G-04rd Schematic 2015-08-27.doc; G-07 Schematic 2015-08-26.doc; G-12RD3 Schematic 2015-09-18.doc; G-14ARD Schematic 2015-09-18.docx Just got them Phoebe. The G-04RD you should already have, but here are the rest. Larry SCANNED yi;_ Original Message From: Brooks, Phoebe L(DOA) [mailto:phoebe.brooks@alaska.gov] Sent:Thursday, September 10, 2015 11:21 AM To: Larry Greenstein Subject: RE: MIT Grayling 08-27-2015 Larry, Would you please send me the schematics on these wells(G-04RD, G-07, G-12RD3, and G-14ARD)so I can verify the Packer TVDs? Thank you, Phoebe Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 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 Phoebe Brooks at 907-793- 1242 or phoebe.brooks@alaska.gov. Original Message From: Larry Greenstein [mailto:lgreenstein@hilcorp.com] Sent: Tuesday, September 08, 2015 9:49 AM To: Regg,James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L(DOA); Wallace, Chris D (DOA) Subject: MIT Grayling 08-27-2015 1 0 SCHEMATIC • McArthur River Field,TBU Well: G-12RD3 ililnnrn Alaska-IAA, As Completed: 08/21/15 RKB to TBG Head=40.73' CASING AND TUBING DETAIL Tree connection: Hole Cmt SIZE WT GRADE CONN ID TOP B66:1-70063:92,3,, TM. Size TOC Rotating Hrs 26" :S"WT Surf 369' Driven NA 9.5 hrs 775sx " 17-3/4" 0.312"WT Weld Surf 602' 22" Surf 116 hrs 2,215sx ;r 13-3/8" 61# K-55 Butt 12.515' Surf 6,013' 17" Surf 669 hrs LI 9-5/8" 47# P-110 Seal Lock 8.681" Surf 73' u ?'. 9-5/8" 40# N-80 Seal Lock 8.835" 73' 6252' 1000 sx ` `" 9-5/8" 43.59 N-80 Seal Lock 8,755" 6252' 6939' 4565'est `iq' „ DV Collar 6939' 6941' 12-1/4" 932 hrs 9-5/8" I 43.59 t N-80 I Seal lock 1 8.755" 6941' 8276' r Redrill#3 2002 Window cut in 9-5/8",43.58,N-80 8276' 8310' 1.000 sx c li Redrlll#2 1978 Window cut in 9-5/8",47#,N-80 10,257' 10,313' 11,027'est Redrill#1 1970 Window cut In 9-5/8",47#,P-110 12,420' 12,478' 945 sx 6,01$ ` - 7" 29 L-80 Butt TKC 6.184" Surface 14,060' 7048'est s0 hrs V „ i Tubing: q� �.' 4-1/2" 112.60/13.55 I L-80 I BTC Ext Polycore 13.598 I Surface 112,379' , I I;t u JEWELRY DETAIL NO. MD TVD OD ID Item 40.73' Hanger TOW@8,276 figg:. 1 1 12,352' 8,948' 5.875 3.991 7"Hydraulic Set Packer EMW=11.18 ppg,� 2 12,370' 8,961' 4.500 2.813 X Nipple x 3 12,379' 8,968' 4.500 2.992 Wireline Re-entry Guide Fish/Plug j NO. Depth Date Description A +/-13,700 6/16/02 42'gun assy(2-1/2"Power Jet gun(30'))and approx.300'of E-line wire. B 13,645' 6/29/02 Posi-Set plug at 1.3670'w/25'of cement dumped on top. 1 PERFORATION DATA 24, Zone Interval(MD) Interval(TVD) FT SPF Status GZN-1 12,476' 12,518' 9,039' 9,070' 42' 5 Open 3 wA GZN-2 12,562' 12,580' 9,102' 9,115' 18' 5 Open GZN-3 12,654' 12,694' 9,169' 9,197' 40' 5 Open AA GZN-4 12,708' 12,732' 9,208' 9,225' 24' 5 Open . GZN 1 GZN-4 12,743' 12,776' 9,233' 9,256' 33' 5 Open GZN-4 12,785' 12,802' 9,263' 9,275' 17' 5 Open .11 GZN 2 GZN-4 12,812' 12,830' 9,282' 9,295' 18' 5 Open GZN 3 GZN-4 12,708' 12,836' 9,208' 9,299' 128' 6 Open GZN 4 GZN-4 12,888' 12,914' 9,335' 9,353' 26' 6 Open GZN-4 12,892' 12,911' 9,338' 9,351' 19' 5 Open GZN 5 GZN-5 12,943' 12,961' 9,372' 9,384' 18' 5 Open to GZN 6 GZN-5 13,055' 13,092' 9,443' 9,466' 37' 5 Open GZN 7 GZN-6 13,108' 13,148' 9,476' 9,499' 40' 5 Open GZN-7 13,211' 13,270' 9,536' 9,569' 59' 5 Open ( HB-1 GZN-7 13,227' 13,270' 9,545' 9,569' 40' 12 Open HK-1 13,302' 13,379' 9,587' 9,628' 77' 5 Open HK-1 13,315' 13,377' 9,594' 9,627' 62' 12 Open Tagged 13,641' - HB-2 HK-2 13,402' 13,439' 9,640' 9,659' 37' 5 Open On 8/16/15 HK-2 13,410' 13,441' 9,644' 9,660' 31' 12 Open HK-2 13,455' 13,515' 9,668' 9,699' 60' 12 Open B ., HK-2 13,460' 13,565' 9,670' 9,726' 105' 5 Open LJ P`' HB-3 HK-2 13,595' 13,624' 9,741' 9,756' 29' 5 Open . HK-3 13,699' 13,729' 9,796' 9,812' 30' 6 Isolated HK-3 13,900' 13,930' 9,902' 9,918' 30' 6 Isolated A, 14,060' Is PBTD=13,960' TD=14,070' MAX HOLE ANGLE=60.5° @ 2600' Updated by: 1LL 09/18/15 STATE OF ALASKA ALADA OIL AND GAS CONSERVATION COMAION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Plug Perforations ❑ Fracture Stimulate El Pull Tubing O Operations shutdown ❑ Performed: Suspend ❑ Perforate 0 Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool❑ Repair Well ❑ Re-enter Susp Well❑ Other:Run New Injection Completion ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development❑ Exploratory❑ 202-055 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service Q 6.API Number: Anchorage,AK 99503 50-733-20116-03 7.Property Designation(Lease Number): 8.Well Name and Number: SEP 1 8 2015 ADL17594&ADL18730 Trading Bay Unit/G-12RD3 f� 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): IAOGG .8 N/A McArthur River Field/Hemlock Oil&Middle Kenai G Oil Pools 11.Present Well Condition Summary: Total Depth measured 14,070 feet Plugs measured 13,645 feet true vertical 9,994 feet Junk measured ±13,700 feet Effective Depth measured 13,641 feet Packer measured 12,352 feet true vertical 9,765 feet true vertical 8,948 feet Casing Length Size MD TVD Burst Collapse Structural 369' 26" 369' 368' Conductor 602' 17-3/4" 602' 601' Surface 6,013' 13-3/8" 6,013' 4,346' 3,090 psi 1,540 psi Intermediate 8,276' 9-5/8" 8,276' 5,988' 5,750 psi 3,090 psi Production 14,060' 7" 14,060' 9,989' 8,160 psi 7,020 psi Liner Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet t 241 satt*Ef Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 12,379'(MD) 8,968'(ND) 12,352'(MD) Packers and SSSV(type,measured and true vertical depth) 7"Hyd Packer 8,948'(ND) SSSV:N/A 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: 0 0 0 0 3100 Subsequent to operation: 0 0 3568 162 3100 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 0 Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ 0 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: 315-317 Contact Dan Marlowe Email dmarlowei hilcorp.com Printed Name Dan Marlowe Dan Title Operations Engineer likatortSignature �, 'r D.t.i► 1/ry�,�LrIIowe Phone (907)283-1329 Date 9/18/2015 Form 10-404 Revised 5/2015 i.2'1 �S IBDIEP Lo Submit Original Only • SCHEMATIC • McArthur River Field,TBU ,„ H Well: G-12RD3 Memo Alaska.LTC As Completed: 08/21/15 RKB to TBG Head=40.73' CASING AND TUBING DETAIL Tree connection: Hole Cmt ' ' At c. SIZE WT GRADE CONN ID TOP BTM. Size TOC Rotating Hrs 26" '4"WT Surf 369' Driven NA 9.5 hrs 17-3/4" 0.312"WT Weld Surf 602' 22" 75urf 116 hrs 13-3/8" 61# K-55 Butt 12.515" Surf 6,013' 17" 2 Surf x 669 hrs 9-5/8" 47# P-110 Seal Lock 8.681" Surf 73' 9-5/8" 40# N-80 Seal Lock 8.835" 73' 6252' 1000 sx 9-5/8" 43.5# N-80 Seal Lock 8.755" 6252' 6939' 4565'est i' DV Collar 6939' 6941' 9-5/8" I 43.5# I N-80 I Seal Lock I 8.755" 6941' 8276' 12-1/4" 932 hrs Redrill#3 2002 Window cut in 9-5/8",43.5#,N-80 8276' 8310' 1000 sx Redrill#2 1978 Window cut in 9-5/8",479,N-80 10,257' 10,313' 11,027'est Redrill#1 1970 Window cut in 9-5/8",47#,P-110 12,420' 12,478' 6,013 7" 29 L-80 Butt TKC 6.184" Surface 14,060' 945 sx 0 hrs Tubing: ,.- 7048'est ' ` 4-1/2" 112.60/13.55 I L-80 I BTC Ext Polycore 13.598 I Surface I 12,379' s. . "*' JEWELRY DETAIL NO. MD TVD OD ID Item 40.73' Hanger TOW @8,276' r a 1 12,352' 8,948' 5.875 3.991 7"Hydraulic Set Packer EMW=11.18 ppg 2 12,370' 8,961' 4.500 2.813 XNipple 3 12,379' 8,968' 4.500 2.992 Wireline Re-entry Guide Fish/Plug NO. Depth Date Description A +/-13,700 6/16/02 42'gun assy(2-1/2"Power let gun(30'))and approx.300'of E-line wire. B 13,645' 6/29/02 Posi-Set plug at 13670'w/25'of cement dumped on top. .i"+ - . ''' 1 PERFORATION DATA X 2 Zone Interval(MD) Interval(TVD) FT SPF Status GZN-1 12,476' 12,518' 9,039' 9,070' 42' 5 Open 3 GZN-2 12,562' 12,580' 9,102' 9,115' 18' 5 Open GZN-3 12,654' 12,694' 9,169' 9,197' 40' 5 Open GZN-4 12,708' 12,732' 9,208' 9,225' 24' 5 Open GZN 1 GZN-4 12,743' 12,776' 9,233' 9,256' 33' 5 Open GZN-4 12,785' 12,802' 9,263' 9,275' 17' 5 Open GZN 2 GZN-4 12,812' 12,830' 9,282' 9,295' 18' 5 Open _GZN 3 GZN-4 12,708' 12,836' 9,208' 9,299' 128' 6 Open GZN 4 GZN-4 12,888' 12,914' 9,335' 9,353' 26' 6 Open GZN-4 12,892' 12,911' 9,338' 9,351' 19' 5 Open _.--.=GZN 5 GZN-5 12,943' 12,961' 9,372' 9,384' 18' 5 Open =GZN 6 GZN-5 13,055' 13,092' 9,443' 9,466' 37' 5 Open .-w& GZN 7 GZN-6 13,108' 13,148' 9,476' 9,499' 40' 5 Open GZN-7 13,211' 13,270' 9,536' 9,569' 59' 5 Open SHB-1 GZN-7 13,227' 13,270' 9,545' 9,569' 40' 12 Open HK-1 13,302' 13,379' 9,587' 9,628' 77' 5 Open HK-1 13,315' 13,377' 9,594' 9,627' 62' 12 Open Tagged 13,641' =H B-2 HK-2 13,402' 13,439' 9,640' 9,659' 37' 5 Open ' On 8/16115 HK-2 13,410' 13,441' 9,644' 9,660' 31' 12 Open HK-2 13,455' 13,515' 9,668' 9,699' 60' 12 Open B HK-2 13,460' 13,565' 9,670' 9,726' 105' 5 Open I FHB-3 HK-2 13,595' 13,624' 9,741' 9,756' 29' 5 Open HK-3 13,699' 13,729' 9,796' 9,812' 30' 6 Isolated HK-3 13,900' 13,930' 9,902' 9,918' 30' 6 Is A '� 14,060' PBTD=13,960' TD=14,070' MAX HOLE ANGLE=60.5° @ 2600' Updated by: ILL 09/18/15 • • Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-12RD3 50-733-20116-03 202-055 8/1/15 8/21/15 Daily Operations: 08/01/2015-Saturday Loosen rear clamps on master skid, hooked up jack power pack,skidded master skid west t/well center, r/d jacks, r/u sub- base jacks,skidded rig south t/well center,tq clamps on sub base,installed roof panels,spotted dog house, r/u service lines t/same. Installed dog house stairs,torque master skid clamps, installed service lines,spot catwalk, install slide. Circulated well while skidding 3 BPM. Check pressure in accumulator bottles, pull floor assembly, install handrails. Check well static,set BPV, N/D tree. N/U riser, BOP stack&tq flanges,install BOP scaffolding, r/d BOP lift plate, install flow nipple,flow line&flow sensor,install drip pan&floor assy. Hook up remote panel&function test same good. M/U 3 1/2 TJ. 08/02/2015-Sunday Serviced choke manifold, mud cross&standpipe valves,shell tested BOPE 250 low,3,000 high, had a failure on dart valve, it started leaking after bleeding off high test.We continued housekeeping&punch list. Test BOPE as per Hilcorp&AOGCC regulations.Witness was waived by AOGCC inspector, Bob Noble @ 8:30am 8-2-15,tested w/3-1/2"Ti's. Test 250 low, 3,000 high, 2,500 high on annular, had one retest on annular pressure dropped below test pressure, re-tested good. Tested PVT&gas system had one gas alarm not functioning. Repaired gas alarm&re-tested good,serviced rig,& housekeeping,while working on upper DS landing. Pulled hanger,came free @ 60k,cont. pull up t/160 made 5.6',worked f/70k-160k several times making 12'total then started moving up hole @ 140k,dropping t/125k with hanger at floor. L/D hanger&landing jt. POOH w/3-1/2" L-80.9.20# Butt completion, I/d 162jts, 2 GLM, 1-SSSV, up wt 70k,dn wt 42k. 08/03/2015-Monday Cont. POOH w/3-1/2" L-80 9.20# Butt completion, L/D total 383 jts, 14 GLM's, 1-SSSV,seal assy,x-nipple, wleg, Clean& clear floor, lay out tools f/next run,unload boat. Install wear bushing. P/U BHA#1,6" bit,csg scraper, bit sub, bumper jar, oil jar,6 4-3/4"drill collars,xo=213.82'. TIH w/3-1/2" PH-6 wk string f/derrick t/9,700', up wt 156k,dn wt 66k. R/U CBU clean @ 3.8 BPM, 520 psi. V 08/04/2015-Tuesday Cont.CBU clean @ 4 BPM,513 psi. Cont.TIH p/u 3-1/2" PH-6 wk string,t/10,719' up wt 180k, dn 68k. CBU 3.5 BPM 400 psi. Cont.TIH p/u 3-1/2" PH-6 wk string,t/11,670', up wt 190k,dn wt 74k. CBU 3.5 BPM, 445 psi. Cont.TIH p/u 3-1/2" PH-6 wk string,t/12,482", up wt 215k, dn wt 72k. CBU x2 clean @ 4 BPM, 710 psi, attempt t/rotate, no go. POOH t/ 11,986'clutch start slipping,treated,cont. POOH 1/d c/o assembly. C/O clutch on D/W. P/U 7" RTTS packer assembly. TIH w/RTTS on 3-1/2"wk string t/3726', up wt 58k,dn 38k. 08/05/2015-Wednesday Cont.TIH F/3,726't/12,357', up wt 210k,dn wt 68k.Worked tq down hole&set packer w/30k dn. R/U break circ through kill line.Test csg 2500 f/30 min good. Put 4 turns in string wk tq down hole t/set packer,nogo. Repeat process putting 6 turns in string working tq dn set packer w/30k dn. C/o clutch band. P/u release packer. POOH t/11,939'. Pulled clutch& deglazed drum. Cont. POOH. L/d test packer. Pull clutch,deglaze clutch drum&prep BHA. 08/06/2015-Thursday Finish working on clutch&re-assemble. P/U BHA#2=6" Burn shoe,W/P ext. top bushing, D-pin xo, 2-boot baskets, D-box xo,string magnet, bumper jar,oil jar,6-4 3/4 DC,acc jar,xo=283.74. TIH w/3 1/2 wk string t/tag @ 12,481',fill pipe every 2,000' up wt 220k dn wt 76k. R/U power swivel&p/u 10'pup. Milled on packer pumping 4 BPM, 1200 psi, running 250 differential pressure,packer started moving down hole chased it down t/12,497'. R/D swivel. • • Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-12RD3 50-733-20116-03 202-055 8/1/15 8/21/15 Daily Operations: 08/07/2015-Friday Cont. r/d swivel. R/u mud bucket&pump. POOH wet f/12,487't/9,708'. Remove clutch guard&circulating head.Get measurements for drum removal,re-install. Cont. POOH wet. L/d BHA,shoe worn 50%, markers in shoe gone 14.5". Clean &clear floor.C/O clutch drum assembly on D/W. 08/08/2015-Saturday Cont c/o clutch&drum assembly.Troubleshoot&repair hyd.C/o bad fitting. P/U BHA#3-spear,spear ext,stop sub,xo, pump out sub, bumper jar,oil jar,6 4 3/4" DC,acc jar,xo=235.98'. Repair leak on circulating head. TIH w/3 1/2"wk string t/6,734'. Pump 88 bbl cfs 520 pill. Cont.TIH t/12,497' up wt 220k,dn 78k. Pump 88 bbl cfs 520 pill. Cut&slip drill line. Cont.TIH t/13,115'engage packer set down 6k. Wk string unable to wk up hole, 245k up,79k dn,circulate 4 bpm, 810 psi. R/U power swivel, attempt wk tq past deviation, pipe started moving uphole. L/d swivel.Cont. POOH t/12,537', up wt 221k,dn 78k. 08/09/2015-Sunday Cont. POOH. L/d BHA, no recovery,grapple was released,stop sub was scarred, had marks on btm of stop sub showing fish top. Clean&clear floor. M/U test jt. Pull wear bushing,m/u test plug,fill stack&surface eq. Test BOPE as per Hilcorp& AOGCC regulations.Witness was waived by AOGCC,Jim Regg @ 19:56 on 8-8-15.Tested w/2 7/8&3-1/2"TJ's. Test 250 low,3,000 high, 2,500 high on annular,all good. Tested PVT&gas system,good. R/D test jt. Installed wear bushing. P/U BHA-spear,spear ext,stop sub,xo, pump out sub, bumper jar,oil jar,6 4 3/4" DC,acc jar,xo=235.98'. TIH p/u 2 7/8 PH-6 wk string t/1,026'. 08/10/2015-Monday Cont.TIH, p/u 2 7/8 PH-6 wk string t/8,463'. C/o handling eq&cont.TIH w/3 1/2 wk string t/13,102', up wt 176k,dn 76k. P/U swivel, rih latch fish @ 13,115'chase down t/13,125', p/u 54k over.Wk up hole, l/d 5 jts,o/p decreasing t/10- 20k. L/d swivel. Cont. POOH, l/d 150 jts 3 1/2 wk string t/8,463'. Cont. POOH standing back 2 7/8 wk string t/2,369'. 08/11/2015-Tuesday Cont. POOH 1/d BHA. Recovered packer mandrel w/seal bore ext 17.6'. Clean&clear floor. P/U BHA#5-6" concave mill, mud motor,string magnet, bumper jar,oil jar,6-4 3/4" DC,acc jar,xo=257.99.TIH w/270 jts 2 7/8 ph-6 wk string t/ 8,485'. C/o handling eq. M/u xo.Cont.TIH w/3 1/2 wk string t/9,395'. Spot second mud pump,string out hoses. Cont.TIH t/13,126', up wt 185k,dn 60k. POOH 1/d 18 work joints t/12,555'. RIH w/9 stands t/13,105'. R/u swivel&single. R/u 2nd pump&function test. Wash&ream f/13,126't/13,260', circulate @ 6 BPM, 1830 psi. Run 100-150 differential pressure. 08/12/2015-Wednesday Cont.wash f/13,250',t/13,273',circulate @ 6 BPM, 1830 psi. Run 100-150 differential pressure,stopped making headway. L/d swivel. R/u mud bucket. POOH leave 77 stands 3 1/2 PH-6 wk string in derrick. L/d 98 jts 3 1/2 wk string. C/O handling eq.Cont POOH stand back 2 7/8 PH-6 wk string. L/d BHA. Mill worn on outside leading edge,shows 5 5/8" wear ring on face. L/D magnet&p/u 5/5" mill. BHA#6=5.5" mill, DP xo, mud motor, bumper jar,oil jar,6-4 3/4 dc,acc jar,xo=250.65.Surface test motor,good.Tih w/2 7/8 wk string t/8,479', up wt 84k,dn wt 46k. • • Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-12RD3 50-733-20116-03 202-055 8/1/15 8/21/15 Daily Operations 08/13/2015-Thursday Cont.tih f/8,479',t/13244' up wt 178k,dn 68. P/U swivel.Wash down t/tag @ 13,277'. Cont.wash&ream t/13,278.5' break through,circ @ 273 gpm, 1950psi off, 2120 on. Cont.wash down t/13,394',circ @ 273 gpm, 2130psi off,2240 on. wk pipe circulate w/#2 pump @ 168 gpm, 1850psi while working on#1 pump. Cont/wash down f/13,394',t/13,584',circ @ 273 gpm, 2190 psi off, 2260 on. 08/14/2015-Friday Cont/wash down f/13,584',t/tag cmt @ 13,657',circ @ 273 gpm, 2190psi off, 2260 on. CBU clean.circ @ 273 gpm, 2150psi. R/U &pump pits t/production @ 3.5 BPM,950 psi tubing,390psi ann. Cleaned pits&filled w/FIW. Displace well t/FIW,taking returns t/Production. Pump 3.5 BPM,960 psi tubing,400psi ann. Reciprocate while pumping. Pump#1 went down.Troubleshoot,r/u pump #2. Cont.displace well w/FIW,till clean,taking returns t/Production. Circ.3.5 BPM,960 psi tubing,400psi ann. Pump 1158 bbls, reciprocate while pumping. R/d swivel&halls head assembly. POOH wet f/13,646' t/13,492', up wt 190k,dn 70k.Started pulling heavy, unable to p/u,free down,cont.trying to wk up, no go. R/U swivel& p/u single, put tq in string attempt t/get upward movement, no go. Pump 4 bpm, 1000 psi. POOH up wt 190k.Cont. pump OOH. L/d singles t/12,903'. Clear deck&setup pipe rack. Mix&pump lube pills,spot in casing. Pump 4 BPM 1030psi. 08/15/2015-Saturday Finish spotting CFS 520 pill in ann up t/6,000'. Pull&I/d 2 jts t/12,851'up wt 176k. L/d swivel. Cont. POOH wet. L/d collars w/BHA. Recovered e-line,wrapped around mandrel of jars. L/d mill,worn 95%,core marking's 3 1/8". M/U 3 1/2" tj. Pull wear bushing.Set test plug. Fill surface eq. Test BOPE as per Hilcorp&AOGCC regulations.Witness was waived and allowed t/test early by AOGCC,Jim Regg @14:46on 8-15-15.Tested w/2 7/8,3-1/2"&4 1/2"TJ's. Test 250 low, 3,000 high, 2,500 high on annular. Had failure on annular. Tested PVT&gas system,good. Pull test tj,&I/d.Close blinds, r/d floor,clean drip pan. 08/16/2015-Sunday Removed flow nipple,drip pan, r/d flow line&flow meter. R/u broke cap on Hydril annular.Changed element, prepped& re-installed cap. R/u flow line,flow nipple drip pan,floor panels. R/u 2 7/8" test jt. Function tested annular. Filled stack. Shell tested, had leak on tj. Repaired,good. Tested 250 low&2500 high,good. Pull test plug. Install wear bushing. R/d test jt. R/U e-line, m/u Gamma ccl,4"junk basket&5.35 GR. Rih t/13,425',attempt t/wk through,no go. POOH. Junk basket had some rubber pieces, metal flat& 1/2"x 1 x3.5" piece. Remove 5.35"GR from assembly. Rih t/13,425'tag,wk through. Rih tag btm,correlate t/log,tagged @ 13,641'. POOH. R/d e-line.Arrange deck. Prep to pick up TCP assembly. PJSM. P/u 4 1/2 TCP assembly. P/U 24 guns. • • Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-12RD3 50-733-20116-03 202-055 8/1/15 8/21/15 Daily Operations: 08/17/2015-Monday Cont. P/U 4 1/2"TCP assembly.TIH w/2 7/8&3 1/2" PH-6 taper string t/tag PBTD @ 13,657'pipe measurement. P/u t/ 13,650'. R/U e-line. RIH w/1 11/16"GR/CCL, locate RA marker. Log f/12,420'-12,150',correlate log t/Digital perf correlation log. P/u string 15', re-log. Move string up 1', placing top shot @ 12,476', BTM shot @ 13,623.75'. POOH, l/d e- line. R/U TIW valve. Drop bar, monitor well.Good indication at surface guns fired. Perf using 4 1/2" 5 spf,Super Deep Penetrator RDX charge 60deg Phasing. Perf:Zone intervals MD:GZN-1 12,476'--12,518'/GZN-2 12,562'--12,580'/GZN-3 12,654'--12,694'/GZN-4 12,708'--12,732'/GZN-4 12,743'--12,776'/GZN-4 12,785'--12,802'/GZN-4 12,812'--12,830'/GZN- 4 12,892'--12,911'/GZN-5 12,943'--12,961'/ GZN-5 13,055'--13,092'.GZN-6 13,108'--13,148'/GZN-7 13,211'--13,270'/ HK-1 13,302'--13,379'/HK-2 13,402'--13,439'/HK-2 13,460'--13,565'/HK-2 13,595'--13,624'. Monitor well.Tubing on vac. Filled hole 18 bbls. R/d TIW. POOH t/12,463' pulled free @ 228k, broke over t/up wt 178k,dn wt 70k. R/U CBU @ 4 bpm, 1034 psi. POOH t/9,426'. L/d 96 jts 3 1/2 PH-6 wk string. RIH w/25 stands of 3 1/2 PH6 wk string t/10,947'. POOH t,10,202'. L/d 25 jts 3 1/2 wk string. 08/18/2015-Tuesday Cont. POOH 1/d 3 1/2 wk string. L/d 25 jts.C/o handling tools t/2 7/8, POOH l/d 30 jts 2 7/8 wk string. R/D extra mud pump while c/o bladder on weight indicator. Cont/POOH 1/d 2 7/8 wk string l/d 240 jts. C/o handling eq. l/d 4 1/2"TCP assembly.All guns fired. Cleaned&cleared floor. R/u&pull wear bushing. C/o handling eq t/p/u 4 1/2 completion. Unload tubing f/boat. P/U completion jewlrey=WLEG,3 1/2pup,x-nipple,pup jt,xo,5" mill out ext. 7" Hyd set packer,4 1/2" LTC pup,xo pup=48.24'. Rih p/u 4 1/2" L-80 12.6/13.55#BTC Ext. polycore tubing,45 jts t/1,265', up wt 28k,dn wt 26k. 08/19/2015-Wednesday Cont. Rih p/u 4 1/2" L-80 12.6/13.55#BTC Ext. polycore tubing,f/1,265',t/12284', up wt 180k,dn 76k. 08/20/2015-Thursday Cont. Rih p/u 4 1/2" L-80 12.6/13.55#BTC Ext. polycore tubing,f/12,284't/12,334', up wt 182k,dn 77k. M/U landing jt& hanger`R/U&spot packer fluid inann f/12,360'-surface.Circ 2 bpm, 120 psi. Drop bar, pressure up tubing t/set packer @ 3800 psi&hold 30 min. R/u&test ann. (w-o MIT)2650, psi hold f/30 min on chart, good. Finish r/u w/l. PT lub. 1000 good. Rih w/2"jdc pulling tool w/2.69 bell guide. RIH latch dart, hit 3x jar licks pull free,tubing on vac. POOH, l/d dart. Rih latch plug. POOH recover&l/d same. R/D w/l. Drain pits. Fill pill pit w/drill water,flush surface eq. Blow down same. Pull landing jt,set BPV. Clear&clean floor. Pull floor panels&drip pan. N/d flow nipple,annular DSA, &double gate. 08/21/2015-Friday N/D mud cross&riser. N/u tree,test void t/250&5000-good. Drain pits, install SSSV&Blind on tree.Test tree t/5000, had leak on cap. Repaired, re-tested good. Break down riser spools& mud cross valves.Wash BOPE&prep for transport. Gather rental subs,wash, inventory &prep t/ship. R/d PVT system. R/d suction lines,accumulator lines, un-plug&coil electrical lines t/pits,r/d gas system, load boat, break down HP lines f/pump t/sub-base, Pull shaker&start cleaning sand trap. 110 • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission Jim Re DATE: Thursday,September 10,2015 TO: gg j o 9iZcf�C P.I.Supervisor SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC G-12RD3 FROM: Jeff Jones TRADING BAY UNIT G-12RD3 Petroleum Inspector ) LI 1,:,J? Src: Inspector Sat4a Reviewed By: P.I.Supry,?i NON-CONFIDENTIAL Comm Well Name TRADING BAY UNIT G-12RD3 API Well Number 50-733-20116-03-00 Inspector Name: Jeff Jones Permit Number: 202-055-0 Inspection Date: 8/27/2015 Insp Num: mitJJ150906060431 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min ri r Well G I2RD3 Type Inj W 'TVD 8947 ' Tubing 1850 - ' 1850 • 1850 - 1850 - - 450 2400 • 2400 ' 2400 ' PTD� Type Test 'Test psi 2237 IA 2020550 � SPT Interval INITAL P/F 1 P OA 58 58 58 58 - Notes: 1 well inspected,no exceptions noted. ' Thursday,September 10,2015 Page 1 of 1 u G- IzP-b3 • PT62t a0S5• o Regg, James B (DOA) From: Harold Soule - (C) <hsoule@hilcorp.com> ` �f l��/�5 Sent: Monday, August 10, 2015 9:11 AM 1 To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Subject: Moncla 301, 8-9-15 BOPE Test Report Attachments: Moncla 301 8-9-15.xlsx; Charts BOPE 8-9-15.pdf Harold Soule 907776-6754 1 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: jim.regqaalaska.gov AOGCC Inspectors(a,alaska.gov phoebe brooks(a,alaska.gov Contractor: Moncla Rig No.: 301 DATE: 8/9/15 Rig Rep.: Jason Freeman Rig Phone 776-6639 Operator Hilcorp Op. Phone: 776-6754 Rep.: Harold Soule E-Mail hsoule@hilcorp.com Well Name. TBU G-12RD3 - PTD# 2020550 . Sundry# 315-317 - Operation Drilling: Workover: x Explor Test: Initial: Weekly. x • Bi-Weekly: Test Pressure(psi): Rams: 250/3000 ,. Annular: 250/2500 • Valves 250/3000- MASP: 1773 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 1 P PTD On Location P - Hazard Sec. P 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 P P • Annular Preventer 1 - 13 5\8" - P Pit Level Indicators P - P #1 Rams 1 . 2 7/8x5 var ' P - Flow Indicator P P . #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 3 1/8 P - Inside Reel valves 0 NA HCR Valves 2 • 3 1/8 P - Kill Line Valves 2 . 3 1/8 2 1/16 • P Check Valve 0 NA ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure(psi) 2950 • P - CHOKE MANIFOLD: Pressure After Closure(psi) 1800 - P ' Quantity Test Result 200 psi Attained(sec) 46 - P • No. Valves 11 P- Full Pressure Attained(sec) 173 - P • Manual Chokes 1 - P , Blind Switch Covers. All stations Yes • Hydraulic Chokes 1 P . Nitgn. Bottles Avg. (#and psi): 4@2150 - P - CH Misc 0 NA ACC Misc 0 _ NA Test Results Number of Failures: 0 - Test Time: 5.0 . Hours Repair or replacement of equipment will be made within days. Notify the AOGCC of repairs with written confirmation to: AOGCC Inspectors@alaska goy Remarks: Tested w/2 7/8&3 1/2"TJ, re-tested IBOP, k-3, CMV- 11,10,8, due to test pressure low, tested gas system good,., AOGCC Inspection 24 hr Notice Yes Date/Time 8-7-2015/9:OOam Waived By Jim Regg Test Start Date/Time: 8/9/2015 20:00 " (date) (time) Witness Test Finish Date/Time. 8/10/2015 1:00 Form 10-424(Revised 06/2014) Moncla 301 8-9-15(2)xlsx I/ -4:,30.„--:, 00 \ -----7---_._� --- ;�— ...- ____----- -.�__3p0p \ -- --1500 `\ 2:(6.,2°05°,°C) -- ::---....-----.:4.'. .'1 I S I I I ii". _t 0,:\\, \'c.,to '0 101' 4411111111 "` � oo 771- -1000(�� 4,7 ' 200 500 \ \\ G f o 400101 , - , . , - tr ,h. -6k ,i, H O 1 p O O r N '''\ MFT�R Me M,o'sp ,� on AR� ,,,„,......„\,,,„,......„\ 1NR C/t per l ,Pc © I 1 , n �'Arro Al ..., ter1 1 ' . N c £MARj'��/ rA K1/ } AFF li � r�f O O .flN N, , 0 \ C6241 oo` • t/ 00s � _! 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".. • .. • . . • ... . . .. . 0 . 4 1,'' 0 0 CO • 1 . . i .. • , i ? :, I 43. 4-'‘.‘ 1 ! ._ 1:54''C • I'' tp4,7-4 . I Co't \''......." ,fk t•' I 1 1 \ .• (..1--- . / i • ‘-‘`k _ 9 ,,, 0 •e- o\-‘ ‘^ -12 ty91,„„x• ,s;;) .., .s. . , , A A 0 -_, 4; v) ' 1 .•• - ,,, ,..‘4.„..„,,,;_-klei:lit, Ii".6•.-t, .. , .... c...11 -v-, ,c,c),(IN . ,, i oo 0-- -•, .... cy, , ck 6, • o , e 100 . iv : - i -_„."--T - loge' ' 6'6. / . - , . •. . -. .. ,,... . 0491._ : - . ____ . . . ' . • '''' /7 • • --- . \..., ,. . • \ .--- •• ------i -- , • , • _ - -.--------1-_ - ..-.--"" „.....„„.,-- . ,..'' ...:.:. ___, ____,... ., ------„,„ ------- _____ . ____4---------_,----- ,------- ., - ' - NNN\ , .,....On •---..... -0... ---...., _______ r -- --__ --, - 00- -----------___,___ ----- _ ----- __ - __- ___----- _--- ---- _ _ -VP-, --_ _...--- _----- ----- _ --------__ _ _ __ ----- — .-- - -• - -- - ---- .. - - . -- � OF Ty � \�� j�,s, THE STATE Alaska Oil and Gas - i � /� T Conservation Commission o f l 1�JASKl 1 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main' 907.279.1433 OFALASIC1P Fax: 907.276 7542 www.aogcc alaska.gov SHED ,11)1 p X015 Dan Marlowe © /.- 0J"�`5 Operations Engineer p� Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field, Hemlock and Middle Kenai Oil Pools, TBU G-12RD3 Sundry Number: 315-317 Dear Mr. Marlowe: 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 La day of May, 2015 Encl. ECEWVED STATE OF ALASKA MAY 2 2 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION 0--/-5 sl26 /S APPLICATION FOR SUNDRY APPROVALS ,OGCC! 20 AAC 25.280 1.Type of Request Abandon❑ Plug Perforations 0 Fracture Stimulate ❑ Pull Tubing 1=1 Operations shutdown ❑ Suspend El Perforate 0 Other Stimulate ❑ Alter Casing ❑ Change Approved Program❑ Plug for Redrill 0 Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other. Run New Injection Completion❑ 2 Operator Name 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC . Exploratory ❑ Development El 202-055 ' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service I] • 6.API Number. Anchorage,AK 99503 50-733-20116-03• 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 228A Will planned perforations require a spacing exception? Yes ❑ No 0 Trading Bay Unit I G-12RD3• 9 Property Designation(Lease Number): 10.Field/Pool(s): ADL17594&ADL18730 • McArthur River Field/Hemlock Oil&Middle Kenai G Oil Pools 11 PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft) Effective Depth TVD(ft): Plugs(measured). Junk(measured) 14,070 - 9,994 13,645 - 9,767 13,645 ±13,700 Gun Assembly Casing Length Size MD ND Burst Collapse Structural 369' 26" 369' 368' Conductor 602' 17-3/4" 602' 601' Surface 6,013' 13-3/8" 6,013' 4,346' 3,090 psi 1,540 psi Intermediate 8,276' 9-5/8" 8,276' 5,988' 5,750 psi 3,090 psi Production 14,060' 7" 14,060' 9,989' 8,160 psi 7,020 psi Liner Perforation Depth MD(ft). Perforation Depth TVD(ft) Tubing Size: Tubing Grade: Tubing MD(ft)• See Schematic / See Schematic 3-1/2" 9.3#/L-80 12,516 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): BOT F-1 Perm.Packer&Baker TE-5 TRSSSV . 12,480'(MD)9,042'(ND)&416'(MD)416'(ND) 12.Attachments Description Summary of Proposal 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic ❑tevelopment❑ Service 0 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 7/15/2015 OIL ❑ WINJ ❑ - WDSPI❑ Suspended ❑ 16.Verbal Approval: Date. GAS ❑ WAG ❑ GSTOFC SPLUG ❑ Commission Representative: GIN.) El Op Shutdown ❑ Abandoned ❑ 1 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Dan Marlowe Email dmarlowe@hilcorp.com Printed Name Dan Marlowe Title Operations Engineer Signature 3 I , 2 HA-R.-at Phone (907)283-1329 Date 5/22/2015 -{-Or II r V 1 WU IOW COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number �// �// 3I5-SI7 Plug Integrity ❑ BOP Test 6/ Mechanical Integrity Test LTJ Location Clearance ❑ Other • 1 rfr1 C-: 9(kSGt e,-"..-3� 0 be i� a. '7 L. A i l0 s",050 3300c.) dos(. i3 (' 7 - - ( AAASP 1773 F> .,) Spacing Exception Required? Yes 0 No 1‘ Subsequent Form Required. /0 -yd Q APPROVED BY Approved by ialet,/ 30.t.44/4"—_- COMMISSIONER THE COMMISSION Date: 5 •z8 — /,- g"2:7-!S 1 s�z ��S RBDMS\ JUN - 3 2015 0?2�G�N /"1 �/�� SubmitForm and Form 10-403 Revised 5/2015 r I O lid for 12 months from the date of approval. Attachments in Duplicate e.IN II, / di L i,,-5 i. • Well Work Prognosis Well: G-12rd3 eacar��Alaska,i.i.c Date: 05/22/2015 Well Name: G-12rd3 API Number: 50-733-20116-03 Current Status: Shut-in Injector Leg: Leg#2 (NE corner) Estimated Start Date: 07/15/15 Rig: HAK#1 Reg.Approval Required? 403 _ Date Reg.Approval Received: Regulatory Contact: Juanita Lovett Permit to Drill Number: 202-055 First Call Engineer: Dan Marlowe Office: 907-283-1329 Cell:907-398-9904 Second Call Engineer: Ted Kramer Office: 907-777-8420 Cell:985-867-0665 Current BHP: -2,851 psi @ 9,627'TVD* 0.296 psi/ft(5.7 ppg)Mid Perf Max Expected BHP: -2,851 psi @ 9,627'TVD 0.296 psi/ft(5.7 ppg)Mid Perf(no new pools) Max anticipated surface pressure: 1,773 psi Using 0.1 psi/ft gradient 20 MC 25.280(b)(4) *based on 2009 shut-in pressure survey. Note:This well was a producer prior to the 2013 conversion with no nearby injector support. Brief Well Summary G-12RD3 was the furthest down-dip producer on the east flank of the main structure. In 2012 the well produced 95—97%watercut and net production of 30—40 bopd and was converted to injection service in 2013, until being shut-in in 2014 due to continued tubing by casing communication. This workover is intended to pull the gas lift completion, remove the production packer, clean out fill, re-perforate,"and run a packer and new tubing. The well is expected to take about 5,000-bwpd on injection. Notes Regarding Wellbore Condition • Currently completed as an injector with dummy valves isolating the gas-lift mandrels." • Estimated Top of Cement in the 7"casing is 7,048' '' • Last Casing Pressure Test: MIT conducted 02/28/13 ✓ Procedure: 1. RU HAK Rig 1 over G-12rd3. 2. RU and circulate hydrocarbons from well. 3. Notify AOGCC 48 hours before pending BOPE test. Set BPV, ND tree, NU BOPE. Test all BOP equipment per AOGCC guidelines to 250 psi LOW and 3, 00 psi HIGH. 4. PU landing joint and make-up to tubing hanger. 5. Attempt to pull tubing free from packer, if unsuccessful, RU and cut tubing as deep as possible. 6. POOH laying down completion. 7. Fish any remaining tubing. 8. Mill out and recover packer at 12,480'. 9. Cleanout to top of isolation plug at 13,645'. 10. PU RIH with RTTS to+/- 12,350' Pressure test casing to 2,500 psi and chart for 30 minutes. 11. PU TCP guns and RIH and re-perforate the G and Hemlock zones per the Perf Recommendation. 12. After detonation, circulate perf gas, confirm well is static, POOH. 13. PU and run injection string. 14. Set packer and pressure test the inner annulus to^'2,500 psi and chart for 30 minutes. 15. Conduct work-over MIT-IA documenting same. 16. Set BPV. NU tree,test same. 17. Schedule initial MIT-IA with AOGCC within 2 weeks of stable injection as per regulations. Well Work Prognosis Well: G-12rd3 Hilcorp Ala.ka,LLC Date: 05/22/2015 Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Current Wellhead Diagram 4. Proposed Wellhead Diagram 5. BOP Stack 6. Rolling BOP Test Procedure II SCHEMATIC McArthur River Field,TBU Well: G-12RD3 Hikora Alaska.1.1.1. As Completed: 02/08/13 RKB to TBG Head=40.73' CASING AND TUBING DETAIL Tree connection: Hole Cmt SIZE WT GRADE CONN ID TOP BTM. Size TOC Rotating Hrs 1 26" al"WT Surf 369' Driven NA 9.5 hrs 17-3/4" 0.312"WT Weld Surf 602' 22" ]Surf 116 hrs 1 13-3/8" 61# K-55 Butt 12.515" Surf 6,013' 17" 2 Surf 215sx 669 hrs 9-5/8" 47# P-110 Seal Lock 8.681" Surf 73' `+r i%, 9-5/8" 40# N-80 Seal Lock 8.835" 73' 6252' 1000 sx 5? �- 9-5/8" 43.5# N-80 Seal Lock 8.755" 6252' 6939' 4565'est )'6 _ C DV Collar 6939' 6941' 1 9-5/8" I 43.5# I N-80 I Seal Lock 8.755" 6941' 8276' 12-1/4" 932 hrs Redrill#3 2002 Window cut in 9-5/8",43.5#,N-80 8276' 8310' 1000 sx Redrill#2 1978 Window cut in 9-5/8",474,N-80 10,257' 10,313' 11,027'est '"444-; -, '" 44 Redrill#1 1970 Window cut in 9-5/8",47#P-110 12,420' 12,478' 7" 29 L-80 Butt-TKC 6.184" Surface 14,060' 945 sx 7048'est 6,013' 0 hrs +c° ++ Tubing: 411 f 3-1/2" I 9.3 I L-80 I BTC-Imp I 2.992 I Surface I 12,516' 1JEWELRY DETAIL I NO. Depth Length OD ID Item `- 40.73' 0.60' Cameron 11"x 3-Y,"DCB w/3-34"8rd top z Butt Btm Tbg Hngr 0.06 TOW@8,276' 1 416' 5.22' 5.400 2.810 Baker TE-STRSSSV 1 EMW-11,18 ppg GLM#1 3276' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve ti iJ GLM#2 5103' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#3 6100' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve K' GLM#4 6909' 8.93' 5.968 2.867 3-1/2"SF0-2 GLM;1.5"Dummy Valve •e:. I i .�„� GLM#5 7599' 8.92' 5.968 2.867 3-1/2"510-2 GLM;1.5"Dummy Valve 4-441 =.e GLM#6 8223' 8.90' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 7i t! GLM#7 8781' 8.93' 5.968 2.867 3-1/2"5FO-2 GLM;1.5"Dummy Valve •4 14a GLM#8 9308' 8.94' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 1 '1 1 GLM#9 9834' 8.94' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 4: iNg GLM#10 10416' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#11 10975' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve I� t,. GLM#12 11505' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#13 11969' 8.93' 5.968 2.867 3-1/2"S1O-2 GLM;1.5"Dummy Valve I44,1 GLM#14 12427' 8.91' 5.968 2.867 3-1/2"SF0-2 GLM;1.5"Dummy Valve 2 12,478' 14.50' 4.250 3.000 Locator Seal Assy,Size 80-40 w/(2)seal units&5'spacer tube 4,01 1r 3 12,480' 18.01' 5.838 4.000 7"BOT Model F-1 Perm Packer(85-40)w/14.69'of SBE • 4" , +y 4 12,503' 1.53' 3.865 2.812 Baker"X"Nipple #w 11. JI .+v 5 12,516' 0.75' 3.857 2.992 EOT(WL Re-entry) x'43 IIS Fish/Plug WLREG: l� : 4 'Y'!? NO. Depth Date Description MD:12,516ft . �, A +/-13,700 6/16/02 42'gun assy(2-1/2"Power Jet gun(30'))and approx.300'of E-line wire. Dip 3,065ft,. 5 Dip:43° 4 u G-Zone: B 13,645' 6/29/02 Posi-Set plug at 13670'w/25'of cement dumped on top. }1 Bench 2-4 Tp:12,562ft Btm:12,914ft Last Tag: PERFORATION DATA SLM:13,173ft w/2-3/4'GR 4`,4! GZN 7 Accum il Zone Interval(MD) Interval(TVD) FT SPF Status ;� HB-1 GZN-2 12,562' 12,580' 9,102' 9,115' 18' 6 Open ?" GZN-3 12,654' 12,694' 9,169' 9,197' _ 40' 6 Open 4 Iytgq GZN-4 12,708' 12,836' 9,208' 9,299' 128' 6 Open 1r Tagged rill gt 13,604' L} HB-2 GZN-4 12,888' 12,914' 9,335' 9,353' 26' 6 Open �, tar 2.79"GR on 3108 ZI'�'" GZN-7 13,227' 13,270' 9,545' 9,569' _ i 40' 12 Open y - - HK-1 13,315' 13,377' 9,594' 9,627' 62' 12 Open B t: se.-.---- -. ' HK-2 13,410' 13,441' 9,644' 9,660' 31' 12 Open HK-2 13,455' 13,515' 9,668' 9,699' 60' 12 Open s U -4:-HB-3 HK-3 13,699' 13,729' 9,796' 9,812' 30' 6 Isolated HK-3 13,900' 13,930' 9,902' 9,918' 30' 6 Isolated 4 41 'a A i A 14,060' ilblib PBTD=13,960' TD=14,070' MAX HOLE ANGLE=60.5° @ 2600' Updated by: ILL 07/17/14 PROPOSED McArthur River Field,TBU Well: G-12RD3 Hibor,Alaska.LH: As Completed: Future RKB to TBG Head=40.73' CASING AND TUBING DETAIL Tree connection: Hole Cmt )i.. i - SIZE WT GRADE CONN ID TOP BTM. Size TOC Rotating Hrs 26" N"Wi Surf 369' Driven NA 9.5 hrs 17-3/4" 0.312"Wi Weld Surf 602' 22" 75urf116 hrs • 13-3/8" 618 K-5S Butt 12.515" Surf 6,013' 17" 2 Surf x 669 hrs 15 9-5/8" 47# P-110 Seal Lock 8.681" Surf 73' 9-5/8" 40# N-80 Seal Lock 8.835" 73' 6252' 1000 sx 9-5/8" 43.58 N-80 Seal Lock 8.755" 6252' 6939' 4565'est DV Collar 6939' 6941' 12-1/4" 932 hrs 9-5/8" I 43.58 I N-80 I Seal Lock I 8.755" 6941' 8276' i ii Redrill#3 2002 Window cut in 9-5/8",43.5#,N-80 8276' 8310' 1000 sx ". Redrill#2 1978 Window cut in 9-5/8",474,N-80 10,257' 10,313' 11,027'est Redrill#1 1970 Window cut in 9-5/8"474,P-110 12,420' 12,478' 6,013' 7" 29 L-80 Butt TKC 6.184" Surface 14,060' 945 sx 0 hrs 7048'est Tubing: 3-1/2" I 9.3 I L-80 I STC-Imp I 2.992 I Surface I 12,516' • JEWELRY DETAIL NO. Depth OD ID Item a 40.73' Hanger TOW@8,276'a EMW=11.18 1 ±12,300' Packer w/seal assembly PP9' 2 ±12,330' X Nipple '- 3 ±12,350' Wireline Re e.r.+-,Guide Fish/Plug NO. Depth Date Description , A +/-13,700 6/16/02 42'gun assy(2-1/2"Power let gun(30'))and approx.300'of E-line wire. B 13,645' 6/29/02 Posi-Set plug at 13670'w/25'of cement dumped on top. v3C, ,`v7 •' 1 , PERFORATION DATA X 2 Zone Interval(MD) Interval(ND) FT SPF Status GZN-1 ±12,476' ±12,518' ±9,039' ±9,070' ±42' Future 1'-__ 3 GZN-2 ±12,562' ±12,580' ±9,102' ±9,115' ±18' 6 Pert/Open GZN-3 ±12,654' ±12,694' ±9,169' ±9,197' ±40' 6 Perf/Open GZN-4 ±12,708' ±12,732' ±9,208' ±9,225' ±24' Future GZN 1 GZN-4 ±12,743' ±12,776' ±9,233' ±9,256' ±33' Future GZN 2 GZN-4 ±12,785' ±12,802' ±9,263' ±9,275' ±17' Future GZN-4 ±12,812' ±12,830' ±9,282' ±9,295' ±18' Future C; GZN 3 GZN-4 12,708' 12,836' 9,208' 9,299' 128' 6 Open GZN 4 GZN-4 12,888' 12,914' 9,335' 9,353' 26' 6 Open GZN 5 GZN-4 ±12,892' ±12,911' ±9,338' ±9,351' ±19' Future -I GZN-5 ±12,943' ±12,961' ±9,372' ±9,384' ±18' Future GZN 6 GZN-5 ±13,055' ±13,092' ±9,443' 39,466' ±37' Future GZN 7 GZN-6 ±13,108' ±13,148' ±9,476' ±9,499' ±40' Future GZN-7 ±13,211' ±13,270' ±9,536' ±9,569' ±59' Future LHB-1 GZN-7 13,227' 13,270' 9,545' 9,569' 40' 12 Open HK-1 ±13,302' ±13,379' ±9,587' ±9,628' ±77' Future HK-1 13,315' 13,377' 9,594' 9,627' 62' 12 Open -HB-2 HK-2 ±13,402' ±13,439' ±9,640' ±9,659' ±37' Future ".i HK-2 13,410' 13,441' 9,644' 9,660' 31' 12 Open B • HK-2 13,455' 13,515' 9,668' 9,699' 60' 12 Open • HK-2 ±13,460' ±13,565' ±9,670' ±9,726' ±105' Future LJ 3 HB-3 HK-2 ±13,595' ±13,645' ±9,741' ±9,767' ±50' Future HK-3 13,699' 13,729' 9,796' 9,812' 30' 6 Isolated HK-3 13,900' 13,930' 9,902' 9,918' 30' 6 Isolated A 14,060'4 ChIft PBTD=13,960' TD=14,070' MAX HOLE ANGLE=60.5° @ 2600' Updated by: JLL 05/18/15 Grayling Platform . 14 G-12rd3 Current Hilrnrp Alaek■_I.I.C: 08/15/2012 Grayling Platform Tubing hanger,CIW-CSX, G-12rd3 11 5M X 3''A IBT lift and 133/8X95/8X7X31/2 susp,w/3"type H BPV profile,9'%EN,%non continous control line port, alloy material BHTA,CIW,3 1/8 5M FE X External Acme knockup rl Ili IIk.�.1I.III MINIMMINI 1■I I#I 6.41 ISI Valve,swab,WKM-M, `,1(,�.�L+,..� 3 1/8 5M FE,HWO, leo 7-40---. 4 T-24 iii li I..I•I Ii ii 1S1 Tee,stdd,3 1/8 5M XRI , , 3 1/8 5M 1 • 111.11.1111111111 .011- iii n Valve,upper master, ,7 l KM-M,3 1/8 5M FE, 1-a W HWO,T-24 V V III II�1 1■1 ISI -_ MIMI 1P11.1 J V. Valve,lower master, ,V/" '(WF WKM-M,3 1/8 5M FE, 0 . HWO,T-24 Ji'Tt tt Yr[hI Spool,4 1/16 5M X I.1■I 1■1 31/85M 'o oat oat■1 Adapter, 1/165M,w/11A5M controlCIW-EN,line port,9 w, extended neck pocket 'ilaa 1 ImmoEIs. Multi bowl assy,CIW- I g.`■ r i ^_ : 1 r MBS,135/83MX115M 'III�hl= ,)I - .( j}';I_1- stddtop,w/4-21/165M =■a_IIIMU'' 111- 11!I:_r�. SSO,R2 seal bottom prep '11!1 �- 1 j ii:i 7fr4,1% I i I • Casing head, 1" Shaffer KD, 9-1— ---r 13 5/8 3M X 133/8 SOW,w/2-2" O®a� LPO, 241 �(�JO\m. —111111 J Grayling Platform .11 G-12rd3 Proposed 05/19/2015 Hiltrwp Alaska,LU Grayling Platform Tubing hanger,CW-CCI,11 X G-12rd3 414 BTC lift and 4%BTC 133/8X95/8X7X41/2 susp,w/4"TypeHBPV profile,2-3/8 CCL,6'/. extended neck,17-4PH stainless steel BHTA,Bowen,4 1/16 SM X 7"-5 SA Bowen Union Full Stainless Steel ,_ 0... Elin LL1J Valve,swab,WKM-M, V U* 41 4 1/16 5M FE,HWO, 0 Valve,Wing,WKM-M, T-26 trim U 3 1/8 SM FE,w/15"Safeco operator,FF trim Full Stainless Steel Tee,stdd,4 1/16 5M X O 3 1/8 5M,Full SS —' .— Valve,lower m6 5M FE, OU ,� WKM-M,41/165MFE, 'QQ, t� HWO,T-26 trim O }_ ' 1 OU rr� Adapter,Cactus-EN,11 5M If FE X 4 1/16 5M,w/2-% control line port,6'/." extended neck pocket !IX. 1 V ! j Multi bowl assy,CIW-MBS, 11- _ — _ • -9C 0. i ��-i- 13 5/8 3M X 11 SM stdd top, ��+• ,I , ^ • w/4-2 1/16 SM 550,R2 seal — - bottom prep - - ! ! ! 111111111111i i 11. 1 I Casing head, Shaffer KD, 135/83MX , 0133/8 SOW,w/2-2" 1.* /�� 1,; ._y 50 LPO, I III" I' 13 3/8' 9 5/8" _ 7" 4," Grayling Platform . 11 2015 BOP Stack (HAK#1) I lem-,:VV,,.�u.In. 01/15/2015 Grayling Platform 2015 Workovers BOP Drawing(HAK#1) Quail Tool Rental Stack III iIIm 3.42' Shaffer 11"5.. III 111 111 U 11111�III 1II ill 4.54' ,talIU lil ��,r7r,iI III Kill Side i Choke side 1.00'to 2.00 21/16 5M w/HCR and Unibolt line M 2 1/16 5M w/HCR and Unibolt line connection 111111111111 III connection Drill deck Riser 11 5M FE X 16.00' 11 5M FE III i!i Ill 3.00' Spacer spool 115M FE X 115M FE iii nil 111,111 III Hilcorp HAK#1 BOP Test Procedure Ei icorp ni,gk,.IAA Attachment#1 Attachment #1 Hilcorp Alaska LLC. BOP Test Procedure: Hilcorp HAK #1, Dolly Varden 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 • II Hilcorp HAK#1 BOP Test Procedure Hilcorp Alaska.� Attachment#1IAA 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.) 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 1 jt. of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same, and RIH on 1 joint of tubing. Install a closed TIW or lower Kelly valve in top of test joint. 3) Break joint off test plug and pull up to space the bottom of tool joint above blind rams. 4) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2-way check or test plug is set) 1) Fill stack with rig pump and install chart recorder on the stack side of the pump manifold. 2) Note: When testing, pressure up with pump to desired pressure,close valve on pump manifold to trap pressure and read same with chart recorder. 3) Referencing the attached schematics test rams and valves as follows. a) Close C-2 (inside gate valve on choke side of mud cross) and close the annular preventer. Pressure test to 200 psi for 5 minutes and 1,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open annular. b) Close Pipe Rams. Test to 200 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open pipe rams. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack,test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 200 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open rams. Hilcorp HAK#1 BOP Test Procedure Hilcorp Alaska.LIS, Attachment#1 d) Open C-2. Flow through the choke manifold and purge air. Test the choke manifold starting with the outer most valves,to 250 psi low and 3,000 psi high,for 5 minutes each, as follows: (Valve numbers are in reference to Diagram B) i) Valves 1, 2, 10. After test,open same. ii) Valves, 3,4,9. After test,open valves 3 &4. Leave 9 closed. iii) Valves 5, 6, 9. After test,open valves 5 & 6, leave 9 closed. iv) Valves, 7, 8,9. After test, open all valves. e) Close C-3. This is the HCR(the hydraulic controlled remote)valve just outside C-1 on choke side of mud cross. Test to 250 psi low and 3,000 psi high. After test,open HCR, close C-1. f) Blind Rams. Make sure test ioint is above the blind rams. Close blind rams. Test to 200 psi Low for 5 minutes and 3,000 psi High for 5 minutes. Bleed down pressure. g) Bleed off all pressure. Line up pumps to pump down tubing. h) Test C-1, C-2, and C-4 on the kill (pump-in) side by pressuring up on tubing.Test to 200 psi Low for 5 minutes and 3,000 psi High for 5 minutes. i) Test floor valves TIW (or Lower Kelly Valve) and IBOP. STANDARD TEST PROCEDURE OF CLOSING UNIT(ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record "Accumulator Pressure". It should be+/- 3,000 psi. 3) Close Annular Preventer,the Pipe Rams,and HCR. Close 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. Wallace, Chris D (DOA) From: Larry Greenstein <Igreenstein@hilcorp.com> Sent: Tuesday, February 17, 2015 9:25 AM To: Wallace, Chris D (DOA) Subject: Request for Cancellation of Administrative Approval (AA)AIO 5.018 for Grayling G-12RD3 (PTD#2020550) Piz.losrtsk , C-114 -1/oir Chris &Jim, ✓upaka RIDMS c �eb rad As the G-12RD3 well's AA AIO 5.018 expired on 2/13/15, Hilcorp requests that AA AIO 5.018 be cancelled. The well has been shut-in until a WO is scheduled. Thank you. Larry SCANNED MAR 0 4 2015 1 ) ) 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. J ð~ - 05S Well History File Identifier Organizing (done) D Two-sided III11II1I1111111111 ~escan Needed 1111IIII11111111111 RESCAN p-tOlor Items: 0 Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) 0 Maps: 0 Diskettes, No. D Other, No/Type: 0 Other Items Scannable by a Large Scanner 0 Poor Quality Originals: NOTES: OVERSIZED (Non-Scannable) ¡ø'C09S of various kinds: 0 Other:: 0 Other: Scanning Preparation BY: Helen ~ ~ x 30 = [Po ¡ Date: fa- ¡ö 04' , . + á' ;:: TO~¡AL PAGES <61 (Count does fJt incl¿de cover sheet) t 1l1J. iO Date: / B-, I ~ Dlf /s/ V II" ,- , 1111111111111111111 Date la-liB Dlf /s/ mr . 1111111111111111111 /sl WI f -1 BY: Helen ~ Project Proofing BY: Helen ~ Production Scanning Stage 1 g- a (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ~/ YE~ Helen ~ Date I~ 13, blf YES NO NO /s/ VV1 P Stage 1 Page Count from Scanned File: BY: If NO in stage 1, page(s) discrepancies were found: BY: Helen Maria BY: Helen Maria Date: /s/ I I f \: \ III 1111111111111111111 Date: /s/ Quality Checked IIIIIII1I1111111111 Scanning is complete at this point unless rescanning is required. ReScanned Comments about thìs file: 8/24/2004 Well History File Cover Page.doc s. ``,--\\\I 61,--\\''\1/6-`*,, THE baa° U l -7 - 333 E Sever, - \,Cn e R:\' Ancr,orage Alas O 9950: 3572 NNEa �UL � SCA Stan Porhola Operations Engineer Hilcorp Alaska, LLC (� c5L, 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field/Hemlock Oil Pool, Trading Bay Unit/G-12RD3 Sundry Number: 314-317 Dear Mr. Porhola: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy '. Foerster Chair iket DATED this�day of May, 2014. Encl. RECEIVED . r f STATE OF ALASKA MAY 1 4 2014 ALASKA OIL AND GAS CONSERVATION COMMISSION ITS 5-12-2/ APPLICATION FOR SUNDRY APPROVALS ADGCC 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrill❑ Perforate New Pod CI• Repair Well❑ Change Approved Program❑ Suspend❑ Plug Perforations❑ Perforate❑ Pull Tubing❑ Time Extension El Operations Shutdown❑ Re-enter Susp.Well❑ Stimulate❑ Alter Casing❑ Other. ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC . Exploratory ❑ Development ❑ 202-055 e 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service 0 • 6.API Number. Anchorage,AK 99503 50-733-20116-03 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 228A- Will planned perforations require a spacing exception? Yes ❑ No I] ' Trading Bay Unit/G-12RD3• 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL17594&ADL18730' McArthur River Field/Hemlock Oil Pool• 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 14,070 • 9,994• 13,645 9,767 13,645 ±13,700(Gun Assy) Casing Length Size MD ND Burst Collapse Structural 369' 26" 369' 368' Conductor 602' • 17-3/4" 602' 601' Surface 6,013' ▪ 13-3/8" 6,013' 4,346' 3,090 psi 1,540 psi Intermediate 6,941' • 9-5/8" 8,276' 5,988' 5,750 psi 3,090 psi Production 14,060' 7" 14,060' 9,989' 8,160 psi 7,020 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Schematic See Schematic 3-1/2" 9.3#/L-80 12,516 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): BOT F-1 Perm Pkr&Baker TE-5 TRSSSV 12,480'(MD)9,042'(ND)&416'(MD)416'(ND) 12.Attachments: Description Summary of Proposal 0 . 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development❑ Service 0 14.Estimated Date for 15.Well Status after proposed work: 5/19/2014 Commencing Operations: Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ 0• GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR El SP LUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Dan Taylor Email dtaylor@hilcorp.com Printed Name Dan T,Aggir Title Operations Engineer Si.nature �� Phone 907 777-8319 Date 5/14/2014 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3\'-1- 3 -( Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes ❑ No i Subsequent Form Required: /4 ,4,,i0` APPROVED BY Approved by: / �Cti-_---a_1COMMISSIONER THE COMMISSION Date: �.Z Z_ 67 - Sig.1Y i kk .S/! I`1 A L .. r 1 sl/y p Submit Form and Form 10-403(Revised 10/2012) Approve i 1 d or 12 months from the d to f approval. fee SPIT$ AY 2 3 24 ' Well Prognosis Well: G-12RD3 flilcorp Alaska,LL Date:5/14/2013 Well Name: G-12RD3 API Number: 50-733-20116-03 Current Status: Injector Leg: 3 Estimated Start Date: May 19,2014 Rig: NA Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 202-055 First Call Engineer: Dan Taylor (907)777-8319(0) (907)947-8051 (M) Second Call Engineer: James Young (907)777-8421 (0) AFE Number: Current Bottom Hole Pressure: 2,800 psi @ 9,623ft TVD/13,371ft MD 0.29 psi/ft at mid-pert, Survey 2009 Maximum Expected BHP: 2,800 psi @ 9,623ft TVD/13,371ft MD 0.29 psi/ft at mid-pert, Survey 2009 Max.Allowable Surface 763 psi 2/3 TVD*0.1 psi/ft+ 1/3 TVD Pressure: *0.435psi/ft Brief Well Summary Grayling G-12RD3 is injection well in the Hemkcck formation. It is currently injecting at 3,200psi and 5,000bpd. This program calls for adding new perforations in the G-Zone in anticipation of adding rate/reserves thru injection and pressure support of surrounding wells. Future perforation depths are: Zone TOP MD(ft) BTM MD(ft) Length(ft) TOP TVD(ft) BTM ND(ft) GZN 2 12,562 12,580 18 9,102 9,115 GZN 3 12,654 12,694 40 9,169 9,197 GZN 4 12,708 12,836 128 9,208 9,299 GZN 4 12,888 12,914 26 9,335 9,353 Procedure: 1. Identify and record fluid level. 2. Hold pre-job safety meeting. 3. Prepare well for e-line perforating. a. Check well head pressure. b. Ensure crown and wing valves are closed. c. Bleed pressure from well head. d. Ensure there is no trapped pressure. e. Ensure there is proper lighting for operations. f. Keep excess personnel away from operations. g. Ensure perforating unit is grounded. 4. Rig up lubricator and wire line: a. Test lubricator to+/-1,500psi.1,--- 5. Run in hole with 2-3/4in Dummy Gun to tag. a. Last tag on 2-21-2014 with 2-3/4in GR found at+/-13,173ft. 6. Run in hole with perforating gun, GR and CCL. a. Tie in to correlation log. b. Well will be perforated while balanced. c. Perforate interval:Top Shot 12,562ft to Bottom Shot 12,914ft MD. d. Total number of runs to cover interval(GZN's 2-4): +/-10. 7. Pull out of hole with perforating guns. --� 8. Rig down lubricator. 9. Turn well over to production. Attachments: 1. As-built Well Schematic 2. Proposed Well Schematic 3. Surface Equipment Diagram McArthur River Field,TBU SCHEMATIC Well: G-12RD3 . n Ililepro Alaska.LLC As Completed: 02/08/13 RKB to TBG Head=40.73' CASING AND TUBING DETAIL Tree connection: Hole Cmt SIZE WT GRADE CONN _ ID TOP BTM. Size TOC Rotating Hrs ' 1 26" 34"WT Surf 369' Driven NA 9.5 hrs • 4 17-3/4" 0.312"WT Weld Surf 602' 22" Surf 116 hrs 13-3/8" 61# K-55 Butt 12.515" Surf 6,013' 17" z Surf 215sx 669 hrs 4, 9-5/8" 47# P-110 Seal Lock 8.681" Surf 73' I___- 1 9-5/8" 40# N-80 Seal Lock 8.835" 73' 6252' 1000 sx 9-5/8" 43.58 N-80 Seal Lock 8.755" 6252' 6939' 4565'est DV Collar 6939' 6941' 1 9-5/8" I 43.5# 1 N-80 I Seal Lock I 8.755" 6941' 8276' 12-1/4" 932 hrs Redrill#3 2002 Window cut in 9-5/8',43.58,N-80 8276' 8310' 1000 sx Redrill#2 1978 Window cut in 9-5/8",47#,N-80 10,257' 10,313' 11,027'est 1Redrill#1 1970 Window cut in 9-5/8",478,P-110 12,420' 12,478' •6,O13'�r � 945 sx 7.. 29 N-80 Butt 6.184" Surface 14,060' 7048'est 0 hrs I 1 Tubing: . 3-1/2" I 9.3 I L-80 I BTC-Imp I 2.992 I Surface I 12,516'I _.. 1 JEWELRY DETAIL I 1 NO. Depth Length OD IDItem 40.73' 0.60' Cameron 11"x 3-A"DCB w/3-'4"8rd top x Butt Btm Tbg Hngr TOW@8,276'a 11-- 1 ,a 1 416' 5.22' 5.400 2.810 Baker TE-S TRSSSV EMW=11.18 ppg•. . GLM#1 3276' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#2 5103' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve I1 GLM#3 6100' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#4 6909' 8.93' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 4 IL 1 GLM#5 7599' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve t• GLM#6 8223' 8.90' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve y 1 GLM#7 8781' 8.93' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#8 9308' 8.94' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 1 GLM#9 9834' 8.94' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#10 10416'_ 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#11 10975' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 1 - GLM#12 11505' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve E.' GLM#13 11969' 8.93' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve I 1 GLM#14 12427' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 2 12,478' 14.50' 4.250 3.000 Locator Seal Assy,Size 80-40 w/(2)seal units&5'spacer tube 1 3 12,480' 18.01' 5.838 4.000 7"BOT Model F-1 Perm Packer(85-40)w/14.69'of SBE 2 4 12,503' 1.53' 3.865 2.812_ Baker"X"Nipple -MI=- 5 12,516' 0.75' 3.857 2.992 EOT(WL Re-entry) ,,,.............4.! ..-... __ 3 Integrity Issues Type Remediation Date 4142 i HOLE in 9-5/8"(6972'6987') None.Leak rate @ 3.5 bpm @ 4200 psi.no break down. 10/68 r$ A 4 "A"x"B"Annuli Communication _ 10sx Gyp-Seal Top Job 3/69 WLREG: ," HOLE in 9-5/8"@ 6962' Cmt sqz 900sx.Tested to 2000psi,bled to 1900psi in 30 min 4/69 MD:12,516ft 4w . TVD:9,0650 5 Milled 9-5/8"csg w/8-1/2"taper mill f/1563'to 2452' 11 hrs of milling.Recovered(3)pieces of csg iron. 5/87 Dip:43° - Csg Caliper Log in 9-5/8" Pitting shallow w/50%to 60%of wall loss in multiple areas. 5/87 "A"x"B"Annulus Held 2500 psi.Was trying to get a break down rate. 5/87 13-3/8"csg stub cracked between bowl&17-3/4"cut Welded crack.Pressure test to 900 psi. 5/87 Last Tag: off. Date:2-21-2014 _. Test 9-5/8"csg Pressure test to 2250 psi for 30 min. _ _ 3/98 SLM:13,173(1 w/2-3/4"GR -H B-0 Test 9-5/8"csg Pressure test to 1500 psi for 15 min. 5/02 Unable to"U-tube"gas thru GLM#1 Pumped Acid down"A"Annulus 11/04 HB-1 Fish/Plug Tagged fill @ 13,604' wl 2.79"GR on 3/08 SHB-2 NO. Depth Date Description :,T..{.}.{,},;:;.;:.{M1;v v.,.k:;:M1,-Sq:i.M1;,,-� A +/-13,700 6/16/02 42'gun assy(2-1/2"Power Jet gun(30'))and approx.300'of E-line wire. B 13,645' 6/29/02 Posi-Set plug at 13670'w/25'of cement dumped on top. B j U - HB-3 r',- 1 l+ ��= PERFORATION DATA 14,060' IiLi Accum 1 PBTD=13,960' TD=14,070' Zone Interval(MD) Interval(TVD) FT SPF Status MAX HOLE ANGLE=60.5° @ 2600' HB-0 13,227' 13,270' 9,545' 9,569' 40' 12 open HB-1 13,315' 13,377' 9,594' 9,627' 62' 12 Open HB-2 13,410' 13,441' 9,644' 9,660' 31' 12 Open 13,455' 13,515' 9,668' 9,699' 60' 12 Open HB-3 13,699' 13,729' 9,796' 9,812' 30' 6 Isolated 13,900' 13,930' 9,902' 9,918' 30' 6 Isolated Updated by: JLL 04/14/14 II PROPOSED McArthur River Field,TBU Well: G-12RD3 117l`preAlaska.LLC As Completed: 02/08/13 RKB to TBG Head=40.73' CASING AND TUBING DETAIL Tree connection: Hole Cmt v ♦ SIZE WT GRADE CONN ID TOP BTM. Size TOC Rotating Hrs ` 26" "A"WT Surf 369' Driven NA 9.5 hrs o. 17-3/4" 0.312"WT Weld Surf 602' 22" 75urf 116hrs ry 13-3/8" 61# K-55 Butt 12.515" Surf 6,013' 17" 2 Surf x 669 hrs i. 9-5/8" 47# P-110 Seal Lock 8.681" Surf 73' I 9-5/8" 40# N-80 Seal Lock _ 8.835" 73' 6252' 1000 sx r 9-5/8" 43.5# N-80 Seal Lock 8.755" 6252' 6939' 4565'est DV Collar 6939' 6941' { I 1 9-5/8" I 43.5# I N-80 I Seal Lock I 8.755" 6941' 8276' 12-1/4" 932 hrs tr Redrill#3 2002 Window cut in 9-5/8",43.5#,N-80 8276' 8310' 1000 sx •, Redrill#2 1978 Window cut in 9-5/8",47#,N-80 10,257' 10,313' 11,027'est k' I Redrill#1 1970 Window cut in 9-5/8",47#,P-110 12,420' 12,478' 6,013' 111 7" 29 N-80 Butt 6.184" Surface 14,060' 945'sxest 0 hrs ,;rr„4,� r Tubing: 7048 ''y, I 3-1/2" I 9.3 I L-80 I BTC-Imp I 2.992 I Surface 112,516' I 1 JEWELRY DETAIL I t NO. Depth Length OD ID Item 40.73' 0.60' Cameron 11"x 3-16"DCB w/3-16"8rd top x Butt Btm Tbg Hngr TOW@8,276'db. i I • 1 416' 5.22' 5.400 2.810 Baker TE-STRSSSV EMW=11.18 ppg-. - GLM#1 3276' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#2 5103' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve I, I GLM#3 6100' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#4 6909' 8.93' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve I I GLM#5 7599' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#6 8223' 8.90' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve I GLM#7 8781' 8.93' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve IGLM#8 9308' 8.94' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 1 GLM#9 9834' 8.94' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#10 10416' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve . GLM#11 10975' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve I GLM#12 11505' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#13 11969' 8.93' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve I I GLM#14 12427' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 2 12,478' 14.50' 4.250 3.000 Locator Seal Assy,Size 80-40 w/(2)seal units&5'spacer tube r" I 3 12,480' 18.01' 5.838 4.000 7"BOT Model F-1 Perm Packer(85-40)w/14.69'of SBE Ii. . 2 4 12,503' 1.53' 3.865 2.812 Baker"X"Nipple Y; I 5 12,516' 0.75' 3.857 2.992 EOT(WL Re-entry) ' - . i .3 Integrity Issues r a Type Remediation Date HOLE in 9-5/8"(6972'6987') None.Leak rate @ 3.5 bpm @ 4200 psi.no break down. 10/68 4 "A"x"B"Annuli Communication 1050 Gyp-Seal Top Job 3/69 WLREG: ,�,.. HOLE in 9-5/8"@ 6962' Cmt sqz 900sx.Tested to 2000psi,bled to 1900psi in 30 min 4/69 ' MD:125169 TVD:9,0659 5 Milled 9-5/8"csg w/8-1/2"taper mill f/1563'to 2452' 11 hrs of milling.Recovered(3)pieces of csg iron. 5/87 Dip:43° �„_G-Zone: g Caliper Log in 9-5/8" Pitting shallow w/50%to 60%of wall loss in multiple areas. 5/87 Bench 23 '"x"B"Annulus Held 2500 psi.Was trying to get a break down rate. 5/87 Tp:72,5629 3-3/8"csg stub cracked between bowl&17-3/4"cut Btm:12,9145 Welded crack.Pressure test to 900 psi. 5/87 Last Tag: off. Date:2-21-2014:j,._._._._._._._._._._. Test 9.5/8"csg Pressure test to 2250 psi for 30 min. 3/98 SLM: ft w/2-3/4"/4"G �'- r Test 9-5/8"csg Pressure test to 1500 psi for 15 min. 5/02 GRR I Unable to"U-tube"gas thru GLM#1 Pumped Acid down"A"Annulus 11/04 ,y p ;t -+j'-HB-1 -" 1 ` Tagged fill @ 13,604' ;" FFish/Plug wl 2.79"GR on 3/08 _H B-2 NO. Depth Date Description h; ;; r; yyy „' A +/-13,700 6/16/02 42'gun assy(2-1/2"Power Jet gun(30'))and approx.300'of E-line wire. B 13,645' 6/29/02 Posi-Set plug at 13670'w/25'of cement dumped on top. B HB-3 PERFORATION DATA Accum el u A Zone Interval(MD) Interval(TVD) FT SPF Status GZN-2 12,562' 12,580' 9,102' 9,115' 18' 6 New GZN-3 12,654' 12,694' 9,169' 9,197' 40' 6 New 14,060' GZN-4 12,708' 12,836' 9,208' 9,299' 128' 6 New PBTD=13,960' TD=14,070' GZN-4 12,888' 12,914' 9,335' 9,353' 26' 6 New HB-0 13,227' 13,270' 9,545' 9,569' 40' 12 Open MAX HOLE ANGLE=60.5° @ 2600' HB-1 13,315' 13,377' 9,594' 9,627' 62' 12 Open HB-2 13,410' 13,441' 9,644' 9,660' 31' 12 Open 13,455' 13,515' 9,668' 9,699' 60' 12 Open HB-3 13,699' 13,729' 9,796' 9,812' 30' 6 Isolated 13,900' 13,930' 9,902' 9,918' 30' 6 Isolated Updated by: DT 04/14/14 .. Wireline Pressure Control Certification Level 2 - 10K Line Wiper il Stuffing Box (� r !Packoff L _ -4-----7 Grease Injection I Control Head E [ ik,____ i 1 ? Pressure Control Grease Injector Unit 1 t t Ball check valve ! i Head Catcher (5.-;:::::-.--.;‘,\. 1 44 71 Lubricator _ Tool Trap ! �_ - Wireline t IC i ri , ► 1�_ Valves s `!1 •■ Wellhead #,, Flange Adapter -L — 33:3 west Sevc nih Avenue (30VI k\OR2 S I :A:v DA N'I I . Ancho,cge Alaska 295 3572 Dan Taylor SCANNED MAY7 201 Operations Engineer �r-� s Hilcorp Alaska, LLC 0�.`- V 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field, Hemlock Oil Pool, Trading Bay Unit G-12RD3 Sundry Number: 314-241 Dear Mr. Taylor: 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, p... ..,....,(11.---- Cathy P oerster Chair DATED this�day of April, 2014. Encl. 1 014 !-1 t.�i lH • STATE OF ALASKA p' 44zZl (41- ALASKA OIL AND GAS CONSERVATION COMMISSION / ((tV � APPLICATION FOR SUNDRY A 'RQVALS 2QAAC 25.280 . Yi 1.Type of Request: Abandon 0 Plug for Redrill 0 Perforate New Pool :' Repair Well 0 Change Approved Program 0 Suspend 0 Plug Perforations 0 Perforate 0 Pull Tubing 0 Time Extensien io�Jif Operations Shutdown 0 Re-enter Susp.Well 0 Stimulate❑ Alter Casing 0 Other. Conve ae � /M 2.Operator Name: 4.Current Well Class: 5s Permit to Drill Number. 64 Hilcorp Alaska,LLC Exploratory 0 Development 0 202-055- it--22 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic 0 Service 0 6.API Number: ^ Anchorage,AK 99503 50-733-20116-03 ' 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 228A Will planned perforations require a spacing exception? Yes 0 No 0 Trading Bay Unit/G-12RD3 - 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL17594&ADL18730 • McArthur River Field/Hemlock Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 14,070 - 9,994 13,297 • 9,583 13,645 ±13,700(Gun Assy)- Casing Length Size MD TVD Burst Collapse Structural 369' 26" 369' 368' Conductor 602' 17-3/4" 602' 601' Surface 6,013' 13-3/8" 6,013' 4,346' 3,090 psi 1,540 psi Intermediate 6,941' 9-5/8" 8,276' 5,988' 5,750 psi 3,090 psi Production 14,060' 7" 14,060' 9,989' 8,160 psi 7,020 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Schematic i See Schematic 3-1/2" 9.3#/L-80 12,516 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): BOT F-1 Perm Pkr&Baker TE-5 TRSSSV 12,480'(MD)9,042'(TVD)&416'(MD)416'(TVD) ' 12.Attachments: Description Summary of Proposal 9 - 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Stratigraphic 0 Development 0' Service 0 14.Estimated Date for 15.Well Status after proposed work: 4/21/2014 Commencing Operations: Oil 0 • Gas 0 WDSPL 0 Suspended 0 16.Verbal Approval: Date: WINJ 0 GINJ 0 WAG 0 Abandoned 0 Commission Representative: GSTOR 0 SPLUG 0 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Dan Taylor Email dtavlor anhilcorp.com Printed Name Dan Taylor-•"' Title Operations Engineer Signature✓ M Phone (907)777-8319 Date 4/14/2014 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31—t.— 7j4 Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 ,,cc�� Other: RBDMS1MAY 0 7 2014 Spacing Exception Required? Yes 0 No i Subsequent Form Required: /a- L{O q C/ Approved by: 7 J COMMISSIONER THE COMMISSION Date: //. ,ZZ /��/� APPROVED BY � -PM-PM 4-11141i� �� /if? Submit Form and Form 10-403(Revised 10/2012) A /pproved Cii rG1 s`✓ i�fA2inonths from the date of approval. Attachments in Duplicate Well Prognosis Well: G-12RD3 Hilt-ora Alaska,LL' Date:4/14/2013 Well Name: G-12RD3 API Number: 50-733-20116-03 Current Status: Injector Leg: 3 Estimated Start Date: April 21,2014 Rig: NA Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 202-0550 First Call Engineer: Dan Taylor (907)777-8319(0) (907)947-8051 (M) Second Call Engineer: James Young (907) 777-8421 (0) AFE Number: Current Bottom Hole Pressure: 2,800 psi @ 9,623ft TVD/13,371ft MD 0.29 psi/ft at mid-perf, Survey 2009 Maximum Expected BHP: 2,800 psi @ 9,623ft TVD/13,371ft MD 0.29 psi/ft at mid-perf, Survey 2009 Max.Allowable Surface 763 psi 2/3 TVD*0.1 psi/ft+ 1/3 TVD Pressure: *0.435psi/ft Brief Well Summary Grayling G-12RD3 is injection well in the Hemlock formation. It is currently injecting at 3,200psi and 5,000bpd. This program calls for adding new perforations in the G-Zone in anticipation of adding rate/reserves. The well will be brought back on as a producer. Future perforation depths are: Zone TOP MD(ft) BTM MD(ft) Length (ft) TOP TVD (ft) BTM TVD (ft) GZN 2 12,562 12,580 18 9,102 9,115 GZN 3 12,654 12,694 40 9,169 9,197 GZN 4 12,708 12,836 128 9,208 9,299 GZN 4 12,888 12,914 26 9,335 9,353 Procedure: �/ 1. Identify and record fluid level. hie Cote, ie%a v,f C R ��`�� 2. Hold pre-job safety meeting. �/- 3. Prepare well for e-line perforating. I '1$T Co 4ti`Aa Tk r wC a. Check well head pressure. b. Ensure crown and wing valves are closed. & -liph. c,,o/ (e(/frn' T /72 c. Bleed pressure from well head. e__;_�� d. Ensure there is no trapped pressure. . 4-j roe f%s duce - yvj'( Ac'I ( mom - e. Ensure there is proper lighting for operations. f. Keep excess personnel away from operations. PO1f')Hq/ 7141 (?4vi, ,�f- I n, eGT771 - g. Ensure perforating unit is grounded. -jv y 4. Rig up lubricator and wire line: /r pope vit MNhG rap set- a. Test lubricator to+/-1,500psi. 5. Run in hole with 2-3/4in Dummy Gun to tag. �y ��/1��/ a. Last tag on 2-21-2014 with 2-3/4in GR found at+/-13,173ft. 0 z 6. Run in hole with perforating gun, GR and CCL. / a. Tie in to correlation log. b. Well will be perforated while balanced. c. Perforate interval:Top Shot 12,5 _2ft to Bottom Shot 12,914ft MD. d. Total number of runs to cover interval(GZN's 2-4): +/-107- 7. /-10-7. Pull out of hole with perforating guns. 8. Rig down lubricator. 9. Turn well over to production. Attachments: 1. As-built Well Schematic 2. Proposed Well Schematic H. SCHEMATIC McArthur River Field,TBU Well: G-12RD3 HiemsAlaska.ld.c As Completed: 02/08/13 RKB to TBG Head=40.73' CASING AND TUBING DETAIL Tree connection: Hole Cmt SIZE WT GRADE CONN ID TOP BTM. Size TOC Rotating Hrs S I 1 .. 26" 14"WT Surf 369' Driven NA 9.5 hrs i 775sx 17-3/4" 0.312"WT Weld Surf 602' 22" Surf 116 hrs 13-3/8" 61# K-55 Butt 12.515" Surf 6,013' 17" 2 Surf x 669 hrs ., 9-5/8" 47# P-110 Seal Lock 8.681" Surf 73' MII II v 9-5/8" 40# N-80 Seal Lock 8.835" 73' 6252' 1000 sx y' 9-5/8" 43.58 N-80 Seal Lock 8.755" 6252' 6939' 4565'est ? DV Collar 6939' 6941' I-I � 9-5/8" 43.5# I N-80 I Seal Lock I 8.755" 6941' 8276' 12-1/4" 932 hrs Redrill#3 2002 Window cut in 9-5/8",43.58,N-80 8276' 8310' 1000 sx 6. Redrill#2 1978 Window cut in 9-5/8",47#,N-80 10,257' 10,313' 11,027'est :r -I Redrill#1 1970 Window cut in 9-5/8",47#,P-110 12,420' 12,478' 7" 29 N-80 Butt 6,184" Surface 14,060' 945 sx 7048'est 0 hrs 6,07311111 . 4.% I Tubing: 3-1/2" I 9.3 I L-80 I BTC-Imp I 2.992 I Surface I 12,516' IIIIIIIIIIIIIIIMMI I Ill JEWELRY DETAIL NO. Depth Length OD ID Item 40.73' 0.60' Cameron 11"x 3-14"DCB w/3-N."8rd top x Butt Btm Tbg Hngr TOWc8,276' Ill 1. 1 416' 5.22' 5.400 2.810 Baker TE-STRSSSV EMW=11.18 ppg« a GLM#1 3276' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve .., ,s;; GLM#2 5103' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 4-t GLM#3 6100' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve Ct9 GLM#4 6909' 8.93' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 4: I ... GLM#5 7599' 8.92' __5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve irI..41 rd GLM#6 8223' 8.90' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 1! F.' GLM#7 8781' 8.93' _5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve p -I 7*'= -°t+ GLM#8 9308' 8.94' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve '' 4 GLM#9 9834' 8.94' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve I GLM#10 10416' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#11 10975' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve .11 -I GLM#12 11505' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve VIII " GLM#13 11969' 8.93' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve lad I ;,d GLM#14 12427' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve g a 2 12,478' 14.50' 4.250 3.000 Locator Seal Assy,Size 80-40 w/(2)seal units&5'spacer tube ll 3 12,480' 18.01' 5.838 4.000 7"BOT Model F-1 Perm Packer(85-40)w/14.69'of SBE I 4 4 12,503' 1.53' 3.865 2.812 Baker"X"Nipple Y' fi= JI tI 5 12,516' 0.75' _3.857 2.992 EOT(WL Re-entry) i3 Integrity Issues Type Remediation Date HOLE in 9-5/8"(6972'6987') None.Leak rate @ 3.5 bpm @ 4200 psi.no break down. 10/68 s 4 , "A"x"B"Annuli Communication 10sx Gyp-Seal Top Job 3/69 WLREG: ��.,.,, HOLE in 9-5/8"@ 6962' Cmt sqz 900sx.Tested to 2000psi,bled to 1900psi in 30 min 4/69 MVD 19 O65ft 5 V Milled 9-5/8"csg w/8-1/2"taper mill f/1563'to 2452' 11 hrs of milling.Recovered(3)pieces of csg iron. 5/87 Dip:43° .; „r ;-tt Csg Caliper Log in 9-5/8" Pitting shallow w/50%to 60%of wall loss in multiple areas. 5/87 "dry T -r1 it ' r "A"x"B"Annulus Held 2500 psi.Was trying to get a break down rate. 5/87 01 �J 13-3/8"csg stub cracked between bowl&17-3/4"cut Welded crack.Pressure test to 900 psi. 5/87 Last Tag: ''+ 'fKY off. Date:2-21-2014`,_,_,_,_,_,_,_._._._,_, + Test 9-5/8"csg Pressure test to 2250 psi for 30 min. 3/98 w/2 13,17311 t.' L.I B_0 Test 9-5/8"csg Pressure test to 1500 psi for 15 min. 5/02 Ittw/2- r --- - - , Unable to"U-tube"gas thru GLM#1 Pumped Acid down"A"Annulus 11/04 61 HB-1 y,t Fish/Plug +�" Tagged fill la 13,604' w/2.79"GR on 3108 HB-2 NO. Depth Date Description s`',;,ry;;2;5}1{.,,,,,• A +/-13,700 6/16/02 42'gun assy(2-1/2"Power Jet gun(30'))and approx.300'of E-line wire. B 13,645' 6/29/02 Posi-Set plug at 13670'w/25'of cement dumped on top. B .. /4 u 4HB-3 r jit A 1 PERFORATION DATA 14,060' Accum PBTD=13,960' TD=14,070' Zone Interval(MD) Interval(ND) FT SPF Status MAX HOLE ANGLE=60.5° @ 2600' HB-0 13,227' 13,270' 9,545' 9,569' 40' 12 open HB-1 13,315' 13,377' 9,594' 9,627' 62' 12 Open HB-2 13,410' 13,441' 9,644' 9,660' 31' 12 Open 13,455' 13,515' 9,668' 9,699' 60' 12 Open HB-3 13,699' 13,729' 9,796' 9,812' 30' 6 Isolated 13,900' 13,930' 9,902' 9,918' 30' 6 Isolated Updated by: JLL 04/14/14 r PROPOSED McArthur River Field,TBU Well: G-12RD3 Hilrrrn Alaska.LLC As Completed: 02/08/13 RKB to TBG Head=40.73' CASING AND TUBING DETAIL Tree connection: Hole Cmt SIZE WT GRADE CONN ID TOP BTM. Size TOC Rotating Hrs t1.1. 1 Z 26" '6"WT Surf 369' Driven NA 9.5 hrs 17-3/4" 0.312"WT Weld Surf 602' 22" ]Surf 116 hrs 1. + 13-3/8" 61# K-55 Butt 12.515" Surf 6,013' 17" 2 Surf x 669 hrs ti (.; 9-5/8" 47# P-110 Seal Lock 8.681" Surf 73' I, I 9-5/8" 40# N-80 Seal Lock 8.835" 73' 6252' 1000 sx 17 9-5/8" 43.59 N-80 Seal Lock 8.755" 6252' 6939' 4565'est ,t 11 DV Collar 6939' 6941' 12-1/4" 932 hrs 0, i re 9-5/8" I 43.5# I N-80 I Seal Lock I 8.755" 6941' 8276' Redrill#3 2002 Window cut in 9-5/8",43.54,N-80 8276' 8310' 1000 sx I. k 4 Redrill#2 1978 Window cut in 9-5/8",47#,N-80 10,257' 10,313' 11,027'est A -� A Redrill#1 1970 Window cut in 9-5/8",478,P-110 12,420' 12,478' 945 sx 6,013' II 29 N-80 Butt 6.184" Surface 14,060' 7048'est 0 hrs i Tubing: },. 3-1/2" I 9.3 I L-80 I BTC-Imp I 2.992 I Surface 112,516' I ' JEWELRY DETAIL I , NO. Depth Length OD ID Item '" 40.73' 0.60' Cameron 11"x 3-A"DCB w/3-14"8rd top x Butt Btm Tbg Hngr TOW@8,276' -i 1 416' 5.22' 5.400 2.810 Baker TE-STRSSSV EMW=11.18 ppgIII 4 GLM#1 3276' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve ; ..1„,r"-�, GLM#2 5103' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve "i" GLM#3 6100' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve m GLM#4 6909' 8.93' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve I I a GLM#5 7599' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve 1..', y GLM#6 8223' 8.90' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve IL LII • GLM#7 8781' 8.93' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve ( i GLM#8 9308' 8.94' 5.968 2.867 3-1/2"SFO-2 GLM;1 5"Dummy Valve " GLM#9 9834' 8.94' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve GLM#10 10416' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve ,'°� GLM#11 10975' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve ?° GLM#12 11505' 8.92' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve T + GLM#13 11969' 8.93' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve l I I v^f GLM#14 12427' 8.91' 5.968 2.867 3-1/2"SFO-2 GLM;1.5"Dummy Valve II Li 2 12,478' 14.50' 4.250 3.000 Locator Seal Assy,Size 80-40 w/(2)seal units&5'spacer tube 3 12,480' 18.01' 5.838 4.000 7"BOT Model F-1 Perm Packer(85-40)w/14.69'of SBE p !v 4 12,503' 1.53' 3.865 2.812 Baker"X"Nipple Y JI '1,,:* 5 12,516' 0.75' 3.857 2.992 EOT(WL Re-entry) a 3 Integrity Issues ; Type Remediation Date HOLE in 9-5/8"(6972'6987') None.Leak rate @ 3.5 bpm @ 4200 psi.no break down. 10/68 i 4 5• "A" Gyp-SealTop 3/69 x"B"Annuli Communication lOsx Job WLREG: .,.,.. - HOLE in 9-5/8"@ 6962' Cmt sqz 900sx.Tested to 2000psi,bled to 1900psi in 30 min 4/69 MD.12,516ft TVD:9,065fl 5 Milled 9-5/8"csg w/8-1/2'taper mill f/1563'to 2452' 11 hrs of milling.Recovered(3)pieces of csgiron. 5/87 Dip:43° -,4-0-Zone: Csg Caliper Log in 9-5/8" Pitting shallow w/50%to 60%of wall loss in multiple areas. 5/87 Bench 2� "A"x"B"Annulus Held 2500 psi.Was trying to get a break down rate. 5/87 Tp:12,562ft +�i�l'6�--Bim:12,914ft 13-3/8"csg stub cracked between bowl&17-3/4"cut Welded crack.Pressure test to 900 psi. 5/87 Last Tag: ' /'V off. Date:2-21-2014 _._._._ Test 9-5/8"csg Pressure test to 2250 psi for 30 min. 3/98 /2-3/4°GR t w 13,173ft HB-0 Test 9-5/8"csg Pressure test to 1500 psi for 15 min. 5/02 w/2- iUnable to"U-tube"gas thru GLM#1 Pumped Acid down"A"Annulus 11/04 HB-1 r. Fish/Plug +tlo Tagged fill pa 13,604' w/2.79"GR on 1108 HB-2 _ NO. Depth Date Description }4 {i{3aMp.41#rAi - A +/-13,700 6/16/02 42'gun assy(2-1/2"Power let gun(30'))and approx.300'of E-line wire. i , 1 7abt 16 a N 1$- B 13,645' 6/29/02 Posi-Set plug at 13670'w/25'of cement dumped on top. B ' I iHB-3 PERFORATION DATA Accum A ,.4.,. Zone Interval(MD) Interval(TVD) FT SPF Status LGZN-2 12,562' 12,580' 9,102' 9,115' 18' 6 New GZN-3 12,654' 12,694' 9,169' 9,197' 40' 6 New 14,060' GZN-4 12,708' 12,836' 9,208' 9,299' 128' 6 New GZN-4 12,888' 12,914' 9,335' 9,353' 26' 6 New PBTD=13,960' TD=14,070' HB-0 13,227' 13,270' 9,545' 9,569' 40' 12 Open _ MAX HOLE ANGLE=60.5° @ 2600' HB-1 13,315' 13,377' 9,594' 9,627' 62' 12 Open HB-2 13,410' 13,441' 9,644' 9,660' 31' 12 Open 13,455' 13,515' 9,668' 9,699' 60' 12 Open HB-3 13,699' 13,729' 9,796' 9,812' 30' 6 Isolated 13,900' 13,930' 9,902' 9,918' 30' 6 Isolated Updated by: DT 04/14/14 • Roby, David S (DOA) From: Daniel Taylor <dtaylor@hilcorp.com> Sent: Tuesday,April 15,2014 11:06 AM To: Roby, David S (DOA) Subject: RE:Sundry Application for TBU G-12RD3 (PTD 202-055) Dave, The new perforations in the G-Zone may yield an increase in oil production that outweighs the benefit G-12RD has been serving as an injector. There will be surface piping modifications as well in order to turn this well around. Please let me know if you would like to discuss further.Thank you Dave. Regards, Dan Taylor Operations Engineer Hilcorp Alaska, LLC. 0: 907-777-8319 • C: 907-947-8051 From: Roby, David S (DOA) [mailto:dave.roby@ alaska.gov] Sent: Monday,April 14, 2014 4:47 PM To: Daniel Taylor Subject: Sundry Application for TBU G-12RD3 (PTD 202-055) Dan, I'm reviewing your application to perforate the G-Zone in the subject well and to convert the well from an injector to a producer and have a question for you. Not much injection has been reported against this well since it was converted from a producer to an injector about a year ago. Can you please discuss why this is and why you're now proposing to convert the well back to an producer? Thanks, Dave Roby Sr. Reservoir Engineer Alaska Oil and Gas Conservation Commission (907) 793-1232 i Ott Q-Iz.12---&3 zez o s-1U Regg, James B (DOA) From: Regg, James B (DOA) Sent: Friday, April 26, 2013 10:01 AM A ry 41703 To: 'Ted Kramer; Schwartz, Guy L (DOA) Cc: Juanita Lovett; Larry Greenstein; Claude Owen; Wayne Johnson; Wallace, Chris D (DOA) Subject: RE: Grayling G-12 RD3 PTD -202-055 We need plot of tbg, inner annulus and outer annuli pressures and current well schematic. What were pressures (tubing, IA and OA) prior to any bleed-offs/SI? Jim Regg AOGCC t�q 333 W.7th Ave,Suite 100 FEB 5 2U l4 Anchorage,AK 99501 SCPI 4 D 907-793-1236 From: Ted Kramer [mailto:tkramer @hilcorp.com] Sent: Friday, April 26, 2013 9:37 AM To: Schwartz, Guy L(DOA); Regg, James B (DOA) Cc: Juanita Lovett; Larry Greenstein; Claude Owen; Wayne Johnson Subject: Grayling G-12 RD3 PTD - 202-055 Guy and Jim, Please be advised that the above injection well developed tubing to casing communication over night and was shut in at 0730 this morning 4-26-13. We believe it is a slow leak(possibly a leaking Dummy valve in a gas lift mandrel)and we will be mobilizing slick line to begin performing diagnostics to locate the leak. Please let me know if you require any further paperwork. Of course we are well aware that if a tubing patch is required, we will shut down until a 10-403 can be generated and approved. Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 1 • • Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Monday, April 15, 2013 12:53 PM To: Ted Kramer (tkramer @hilcorp.com) Cc: 'Regg, James B (DOA) (jim.regg @alaska.gov)'; 'McMains, Stephen E (DOA) (steve.mcmains @alaska.gov)' Subject: G -12RD3 (PTD 202 -055) Cony to WI Ted, We have the new 10- 404 report ( #312 -329) and we have updated our system to make it an injector. This was a rather complicated chain of events but the bottom line is it is approved for Injection. The original scope of work (312 -139) to swap GLV's to DV's and go directly to injection was what eventually happened . We will close out all sundries... you can start injection and notify us for a MIT -IA when stabilized. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907 -444 -3433 cell SCANNED JUL 1 0 2.013 907 - 793 -1226 office 1 • STATE OF ALASKA A OIL AND GAS CONSERVATION COM ION REPORT OF SUNDRY W OPERATIONS 1. Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Perforate ❑ Other G Convert to Injector Performed: Alter Casing ❑ Pull Tubing ❑ Stimulate - Frac ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other ❑ Re -enter Suspended WQ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development El Exploratory ❑ 202 -055 3. Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic El Service ❑ 6. API Number: Anchorage, AK 99503 50- 733 - 20116 -03 .-- 49 7. Property Designation (Lease Number): 8. Well Name and Number: ADL17594 & ADL 18730 Trading Bay Unit / G -12RD3 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): McArthur River Field / Hemlock Oil 11. Present Well Condition Summary: Total Depth measured 14,070 feet Plugs measured 13,645 feet true vertical 9,994 feet Junk measured +/- 13,700 Gun Assy feet Effective Depth measured 13,297 feet Packer measured 12,480 feet true vertical 9,583 feet true vertical 9,042 feet Casing Length Size MD TVD Burst Collapse Structural 369' 26" 369' 368' Conductor 602' 17 -3/4" 602' 601' Surface 6,013' 13 -3/8" 6,013' 4,346' 3,090 psi 1,540 psi Intermediate 6,941' 9 -5/8" 8,276' 5,988' 5,750 psi 3,090 psi Production 14,060' 7" 14,060' 9,989' 8,160 psi 7,020 psi Liner ` Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 3 -1/2" 9.3# / L -80 12,516' (MD) 9,068' (TVD) Packers and SSSV (type, measured and true vertical depth) BOT F - 1 Perm. Packer 12,480' (MD) 9,042' (TVD) Baker TE - 5 TRSSSV 416' MD 416' (TVD) 12. Stimulation or cement squeeze summary: y.Y Intervals treated (measured): APR 1 2 2013 N/A Treatment descriptions including volumes used and final pressure: AOGCO N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 30 9 1090 1320 120 Subsequent to operation: 0 0 5000 995 3020 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development❑ Service E Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil ❑ Gas ❑ WDSPL❑ GSTOR ❑ WINJ El WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 312 -329 (See- i/2. -/31 ife,. Leh. I - S ) / � Contact Ted Kramer Email tkramer @hilcoro.com y / Printed Name Ted Kramer Title Sr. Operations Engineer Signature ', ' Phone (907) 777 -8420 Date 4/12/2013 R8DMS APR 15 2013 ,2'1 � , �� f3 �� /� Form 10-404 Revised 10/2012 Submit Original Only • • McArthur River Field, TBU Well: G -12RD3 Hi kora Alaska. MX As Completed: 02/08/13 RKB to TBG Head = 40.73' CASING AND TUBING DETAIL Tree connection: Hole Cmt SIZE WT GRADE CONN ID TOP BTM Size TOC Rotating Hrs J 1 2 6" 'A" WT Surf 369' Driven NA 9.5 hrs 0 ' it. 775sx J 17 -3/4" 0.312" WT Weld Surf 602' 22" Surf 116 hrs I 13 -3/8" 61# K -55 Butt 12.515" Surf 6,013' 17" 2 Surf x 669 hrs 9 -5/8" 47# P -110 Seal Lock 8.681" Surf 73' 1 9 -5/8" 40# N -80 Seal Lock 8.835" 73' 6252' 1000 sx 9 -5 /8" 43.5# N -80 Seal Lock 8.755" 6252' 6939' 4565' est DV Collar 6939' 6941' 12 -1/4" 932 hrs 9 -5 /8" 1 43.5# 1 N -80 1 Seal Lock 1 8.755" 6941' 8276' 1 1 Redrill #3 2002 Window cut in 9-5/8", 43.5#, N -80 8276' 8310' 1000 sx Redrill #2 1978 Window cut in 9 -5/8 ", 476, N -80 10,257' 10,313' 11,027' est Redrill #1 1970 Window cut in 9 -5/8', 47 #, P -110 12,420' 12,478' I 1 II 29 N -80 Butt 6.184" Surface 14,060' 945 sx O hrs 3' 7045' est Tubing: ` 3 -1/2" 1 9.3 1 L -80 1 BTC -Imp 1 2.992 1 Surface 1 12,516' I 1 1 1 JEWELRY DETAIL r- 1 NO. Nigh Loath 0.2 ID Item, 40.73' 0.60' Cameron 11" x 3 -34" DCB w/ 3 -34" 8rd top x Butt Btm Tbg Hngr TOW @8,276'` 1 1 1 416' 5.22' 5.400 2.810 Baker TE- 5TRSSSV EM W =11.18 ppg, GLM #1 3276' 8.91' 5.968 2.867 3 -1/2" SFO -2 GLM; 1.5" Dummy Valve GLM #2 5103' 8.91' 5.968 2.867 3 -1/2" SFO -2 GLM; 1.5" Dummy Valve i 1 GLM #3 6100' 8.91' 5.968 2.867 3 -1/2" SFO -2 GLM; 1.5" Dummy Valve GLM #4 6909' 8.93' 5.968 2.867 3 -1/2" SFO -2 GLM; 1.5" Dummy Valve 1 1 GLM #5 7599' 8.92' 5.968 2.867 3 -1/2" SFO -2 GLM; 1.5" Dummy Valve GLM #6 8223' 8.90' 5.968 2.867 3 -1/2" SFO -2 GLM; 1.5" Dummy VaNe GLM #7 8781' 8.93' 5.968 2.867 3 -1/2" SFO-2 GLM; 1.5" Dummy Valve 1 GLM #8 9308' 8.94' 5.968 2.867 3 -1/2" SFO -2 GLM; 1.5" Dummy Valve GLM #9 9834' 8.94' 5.968 2.867 3 -1/2" SFO -2 GLM; 1.5" Dummy Valve 1 1 GLM #10 10416' 8.92' 5.968 2.867 3 -1/2" SFO -2 GLM; 1.5" Dummy Valve GLM #11 10975' 8.92' 5.968 2.867 3 -1/2" SFO -2 GLM; 1.5" Dummy Valve 1 1 GLM #12 11505' 8.92' 5.968 2.867 3 -1/2" SFO -2 GLM; 1.5" Dummy VaNe GLM #13 11969' 8.93' 5.968 2.867 3 -1/2" SFO-2 GLM; 1.5" Dummy Valve ., GLM #14 12427' 8.91' 5.968 2.867 3 -1/2" SFO -2 GLM; 1.5" Dummy Valve 1 1 2 12,478' 14.50' 4.250 3.000 Locator Seal Assy, Size 80-40 w/ (2) seal units & 5' spacer tube 3 12,480' 18.01' 5.838 4.000 7" BOT Model F -1 Perm Packer (85 -40) w/ 14.69' of SBE 1 1 4 12,503' 1.53' 3.865 2.812 Baker "X" Nipple 5 12,516' 0.75' 3.857 2.992 EOT (WL Re -entry) 1 1 Integrity Issues f \ TVD@ Remediation Date ISM _ HOLE in 9 -5/8" (6972' 6987') None. Leak rate @ 3.5 bpm @ 4200 psi. no break down. 10/68 4 "A" x "B" Annuli Communication 10sx Gyp -Seal Top Job 3/69 r■ 3 HOLE in 9 -5/8" @ 6962' Cmt sqz 900sx. Tested to 2000psi, bled to 1900psi in 30 min 4/69 �MIC Milled 9-5/8" csg w/ 8 -1/2" taper mill f/ 1563' to 2452' 11 hrs of milling. Recovered (3) pieces of csg iron. 5/87 Csg Caliper Log in 9 -5/8" Pitting shallow w/ 50% to 60% of wall loss in multiple areas. 5/87 ,=II ! "A" x "B" Annulus Held 2500 psi. Was trying to get a break down rate. 5 /87 13 -3/8" csg stub cracked between bowl & 17 -3/4" cut off. Welded crack. Pressure test to 900 psi. 5/87 5 Test 9 -5/8" csg Pressure test to 2250 psi for 30 min. 3/98 7 H B -0 Test 9 -5/8" csg Pressure test to 1500 psi for 15 min. 5/02 " Unable to "U- tube" gas thru GLM #1 Pumped Acid down "A" Annulus 11/04 I °`..A Obstruct HB -1 @ 13,297' Fish / Plug Tagged fill @ 13,604' w1 2.79" GR on 3108 NO. Death, Date Description - .. (#ni "r:' i ?''" i �= " ?£'t'i' i ;= in ' + T HB -2 A +/- 13,700 6/16/02 42' gun assy (2 -1/2" Power Jet gun (30')) and approx. 300' of E -line wire. - -- - -- - -- B 13,645' 6/29/02 Posi -Set plug at 13670' w/ 25' of cement dumped on top. B u ! HB - PERFORATION DATA Accum A Zone Interval (MD) Interval (TVD) FT SPF Status HB-0 13,227' 13,270' 9,545' 9,569' 40' 12 Open HB -1 13,315' 13,377' 9,594' 9,627' 62' 12 Open 14,060' HB -2 13,410' 13,441' 9,644' 9,660' 31' 12 Open 13,455' 13,515' 9,668' 9,699' 60' 12 Open PBTD = 13,960' TD = 14,070' HB -3 13,699' 13,729' 9,796' 9,812' 30' 6 Isolated MAX HOLE ANGLE = 60.5° @ 2600' 13,900' 13,930' 9,902' 9,918' 30' 6 Isolated Updated by: JLL04 /11/13 • Hilcorp Alaska, LLC Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G -12RD3 50- 733 - 20116 -03 202 -055 2/2/2013 2/8/2013 Daily Operations:; 02/02/13 - Saturday R /U, PT Lub & WLV- tested good. RIH w/2.74" GR to 12,412' KB work to 12,464' KB. POOH. RIH w /same to 12,464' KB work to 12,516' KB fall through tag fill at 13,248' KB. POOH. RIH w /3" OM -1 KOT w/1 -5/8" JDS 2 Dog to 3,276' KB latch & pull GLV pooh have valve. Bleed down tubing & casing. RIH w /3" OM -1 Kot w/1 -5/8" JDS to 12,427' KB couldn't latch. POOH. Trigger hung up on mandrel #2 at 5,103' KB. Latch & pull GLV, pooh have valve. 02/03/13 - Sunday R /U, RIH w /3" OM -1 KOT w/1 -5/8" JDS to 11,969' KB latch hit 3 oil jar Ticks come free, pooh rolled dogson pulling tool. RIH w /same to 6,100' KB KOT kicked out latch & pull GLV pooh have valve. RIH w /3" OM -1 KOT w/1 -5/8" Daniels PT to 12,427' KB couldn't latch. POOH, had metal marks on PT. RIH w /same to 6,909' KB latch & pull GLV pooh have valve. RIH w /same to 7,599 KB latch & pull GLV pooh have valve. RIH w /same to 8,223' KB latch & pull GLV pooh have valve. 02/04/13 - Monday R /U, RIH w /3" OM -1 KOT w /Bowen Overshot to 12,427' KB couldn't latch pull up to 11,969' KB latch GLV beat on 1.5 hrs come free, pooh have valve. RIH w /same to 11,505' KB latch GLV beat on for 1 hr 10 min come free, pooh have valve. RIH w/3.5 OM- 1 KOT w /Bowen Overshot Skirt to 12,427' KB couldn't latch pooh overshot skirt bent up. RIH w/3.5" OM -1 KOT w 1 -5/8" Daniels PT to 10,975' KB hit twice, pooh, dog's rolled again. 02/05/13- Tuesday R /U, RIH w/3.5" OM -1 KOT w/1 -1/2" LIB to 12,427' KB tag pocket. POOH, LIB shows empty pocket. RIH w/3.5" OM -1 KOT w /Bowen Overshot to 10,975' KB latch beat on for 1.5 hrs come free pooh have valve. RIH w /same to 10,416' KB latch valve beat on come free pooh have valve. RIH w /3" OM -1 KOT w /Bowen Overshot to 9,834' KB, locate, couldn't set down. POOH. RIH w /same to 9,308' KB latch & pull valve pooh have valve. RIH w /same to 8,781' KB. 02/06/13 - Wednesday Cont. RIH w /same to 8,781' KB latch & pull valve pooh have valve. R /U, RIH w/3.5" OM -1 KOT w/1 -5/8" Daniels PT to 9,834' KB set down, can't latch. POOH, have metal marks. RIH w/3.5" OM -1 KOT w/1 -5/8" Daniels PT to 9,834' KB set down can't latch pooh have metal marks. RIH w/3.5" OM -1 KOT w /Bowen Overshot to 9,834' KB set down beat on come free pooh have RT in overshot. RIH w/3.5" OM -1 KOT w /Bowen Overshot to 9,834' KB latch valve beat on for 2 hrs come free pooh have valve. RIH w/3.5" OM -1 KOT w /RK1 RT w/1.5" Dummy to 3,276' KB set dummy pooh. RIH w /same to 5,103' KB set valve pooh. RIH w /same to 6,100' KB set valve pooh. RIH w /same to 6,909' KB set valve pooh. RIH w /same to 7,599' KB. 02/07/13 - Thursday Cont. RIH w/3.5" OM -1 KOT w /RK1 RT w/1.5" Dummy to 7,599' KB set dummy pooh. RIH w/3.5" OM -1 KOT w /RK1 RT w/1.5" Dummy to 8,223' KB set valve pooh. RIH w /same to 8,781' KB set valve pooh. RIH w /same to 9,308' KB set valve pooh. RIH w/3.5" OM -1 KOT w/1.5" LIB to 9,834' KB tag pocket, pooh, LIB shows valve. RIH w/3.5" OM -1 KOT w/1 -5/8" Daniels PT to 9,834' KB latch & pull valve pooh. RIH w/3.5" OM -1 Kot w /RK1 RT w/1.5" Dummy to 9,834' KB set valve pooh. RIH w /same to 12,427' KB set valve pooh. RIH w /same to 10,416' KB set valve pooh. 02/08/13 - Friday RIH w/3.5" OM -1 Kot w /RK1 RT w/1.5" Dummy to 11,505' KB set valve pooh. RIH w /same to 10,975' KB set valve pooh. RIH w /same to 8,223' KB set down pooh shows valve. RIH w /same to 7,599' KB set down pooh shows empty pocket. RIH w/3.5" OM- 1 KOT w /RK1 RT w/1.5" Dummy to 7,599' KB set valve pooh. R/D W /L. . • • . Hilcorp Alaska, LLC Post Office Box 244027 Anchorage, AK 99524 -4027 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 Phone: 907 /777 -8300 April 12, 2013 Fax: 907/777. -8301 Ms. Victoria Ferguson Alaska Oil and Gas Conservation Commission 333 W. 7 Avenue, Suite 100 Anchorage, AK 99501 Re: Grayling Well Number G -12RD3 Sundry Numbers 312 -329 and 312 -139 31 z _ (5' Dear Ms. Ferguson, Attached please find form 10 -404, a well operations summary, and a well schematic for i the above mentioned well. I had a discussion yesterday with Stephen McMains of your office concerning this well. `l •/ - •13 Stephen contacted me because he had received a completed MIT form for this well but he still had it listed as a producer in his database. I researched the well and learned that the well had been converted to an injector in February of this year. I also found the two Sundry's listed above for this work. In ✓ talking to Mr. McMains, I learned that Sundry 312 -139 had been cancelled and Sundry number 312 -329 was written in its place. This has caused an issue because the work that was performed on the well in February was the work described in Sundry 312 -139. Our records did not indicate that that sundry was cancelled and we believed that it was still valid. It was only after speaking with Mr. McMains that we realized the error. When I Explained to Mr. McMains what had happened, he suggested that we submit the information attached to this letter with a 10 -404. No new perforations have been added to this well. It is set up to inject into Hemlock perforations only. We have shut this well in until we can correct this issue. Please let me know what Hilcorp needs to do to correct this paperwork so we can get the status of this well properly recorded according to its current status. Ms. Victoria Ferguson April 12, 2013 Page 2 of 2 Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC Attachments: Form 10 -404 Well Schematic Well Operations Summary , • • 'N C ---, FA F., Q-4) En.‘ ' li Lt El [F ALA S En SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276-7542 Mike Dunn Senior Reservoir Engineer ao_._._ Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: McArthur River Field, Hemlock 86 Middle Kenai G Oil Pool, G -12RD3 Sundry Number: 312 -329 Dear Mr. Dunn: SLANNi=U AUG 6 0 a Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 4 ,7.----7 Daniel T. Seamount, Jr. 776 Commissioner DATED thi day August, Au st, 2012. Encl. • n S(t V RECEIVED STATE OF ALASKA �b r ALASKA OIL AND GAS CONSERVATION COMMISSION AUG 2 3 201? APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 v Alaska Oil & Gas Cons. Commission 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool e / 4 ' v 1 Repair Well ❑ haffirkijibr -' . °.ved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate Q Pull Tubing ID ° Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other. Convert to Injector /Complete 1u 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Hilcorp Alaska, LLC Development Q Exploratory ❑ 202 -055 ' 3. Address: Stratigraphic [] Service ❑ 6. API Number. 3800 Centerpoint Dr., Suite 100 Anchorage, Alaska 99503 ' 50 -733- 20116-03 ' 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No El G -12RD3 9. Property Designation (Lease Number): 10. Field / Pool(s): Grayling Platform, Cook Inlet/ ADL17594 & ADL18730 McArthur River/ Hemlock/ft '(s ,../„../ (,.L /4„.„..„.c....„ a 7 t � / 11. PRESENT WELL CONDITION SUMMARY 5. 27. ,' Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 14,070 . 9,994 • 13,297 9,583 13,645' +/- 13,700 Gun Assy. Casing Length Size MD TVD Burst Collapse Structural 369' 26" 369' 368' Conductor 602' 17 -3/4" 602' 601' Surface 6,013' 13 -3/8" 6,013' 4,346' 3,090psi 1,540psi Intermediate 6,941' 9 -5/8" 8,276' 6,940' 5,750psi 3,090psi Production 14,060' 7" 14,060' 9,988' 8,160psi 7,020psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3 -1/2" 9.3 #/ L -80 12,516 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): BOT F -1 Perm. Packer and Baker TE -5 TRSSSV 12,480(MD)/ 9,042(TVD) and 416(MD)/ 416(TVD) 12. Attachments: Description Summary of Proposal Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch IN Exploratory ❑ Development ❑ Service © ' 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 9/1/2012 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: N/A WINJ 151 GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Mike Dunn Printed Name Mike D n / Title Sr. Reservior Engineer Signature , f , Phone 777 -8382 (o) 351 -4191 (m) Date 8/23/2012 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: , /3)p 3 0 0 0 p 5 - 4 / NO n 401700 � j l >tz`to/ 4 5 /v 1/ e e -c1 Subsequent Form Required: APPROVED BY fi 2 ` / I t, Approved by: C OMMISSIONER THE COMMISSION Date: `/ � S A 3 (� 4f 2---- , R Fo ®dD3 R��ed 1GD , �I C7 l 6 ��1�Submit in Duplicate � J oRIGINAL 4 • Well Work Prognosis Well: G -12RD3 Hilcorp Alaska, LLC Application Date: 8/16/2012 Well Name: G -12RD3 API Number: 50- 733 - 20116 -03 Current Status: Oil Producer Leg: Leg #2 (NE corner) Estimated Start Date: September 1, 2012 Rig: Williams Rig 404 Reg. Approval Req'd? 10 -403 Date 10-403 submitted: August 16, 2012 Regulatory Contact: Tom Fouts 777 -8398 Permit to Drill Number: 202 -055 First Call Engineer: Mike Dunn (907) 777 -8382 (Office) (907) 351 -4191 (M) Second Call Engineer: Ted Kramer (907) 777 -8420 (0) (985) 867 -0665 (M) AFE Number: 1221948 Budgeted Cost: � t Pressures: �r Bottom Hole Pressure (BHP); Maximum Potential Surface Pressure (MPSP) , f Current BHP: — 2,851 psi @ 9,627' TVD* .296 psi /ft. = 5.7 ppg r) j�A,i , •1 M Expected BHP: — 2,851 psi @ 9,627' TVD No new perfs or zones to be opened ; � I0 MPSP: 1,887 psi "Dig 0.1 psi /ft. of True Vertical Depth fr *based on 2009 shut -in pressure survey. Note: This well has been a producer with no nearby injector support. "? Brief Well Summary G -12RD3 is (was) the furthest down -dip producer on the east flank of the main structure. In February 2012, shortly after Hilcorp acquired the field, the water cut spiked from 60% to 95 -97% water cut, while the gross fluid jumped from 200 -bfpd to 1,000 -bfpd. It was suspected the aquifer had encroached from the east, or water was coning from the aquifer below. The well was shut -in for several weeks in an attempt to "heal" the coning channel — but to no avail. The well has remained on as a producer at 95 — 97% watercut and net production of 30 — 40 bopd. The time has come to convert this well to an injector. There is believed to be some reserves up -dip of G -12RD3 toward G -08 that can be swept with injection at this location. This workover is intended to pull the gas lift completion, remove the production packer, clean out fill, re- perforate, and run a packer and new tubing. The well is expected to take about 7,000 -bwpd once it is placed on injection. Cp (t/P // produz; / - ;5 ,O/ID Notes Regarding Wellbore Condition god wG . Coy idv 17 7 )o q Mi r /1 flee i '► /KJ�- cAol' /or ,'A4 , W teC o � %b* 740, f a • The tubing has a SSSV and 14 gas lift mandrels. • Casing integrity is believed to be intact. There are no indications of co munication behind the 9- 5/8" casing. Procedure: 1. Cut the tubing with jet cutter just above the packer. 2. Skid Williams Rig 404 over the G -12RD3 well slot. Raise mast. Prepare for wellwork operations. 3. Plumb FIW lines to circulate down the annulus and up the tubing, when the tubing is pulled out of the packer. 4. - Notify AOGCC of pending BOPE test. Set BPV, ND tree, NU BOPE. Test all BOP equipment per AOGCC guidelines to 250 psi LOW and 3,000 psi HIGH. Test Annular BOP to 250 psi LOW and 1,500 psi HIGH. Record pressures, fill out the 10 -424 form and send to Jim Regg at AOGCC and Juanita Lovett with Hilcorp. 14 • • Well Work Prognosis Well: G -12RD3 Hilcorp Alaska, LLC Application Date: 8/16/2012 5. PU landing joint and make -up to tubing hanger. Tug on tubing to pull the hanger free. Pull hanger up to floor height. Install stripper rubber. Circulate at least 2 bottoms -up to adequately clean hole. 6. POOH with completion tubing. LD same, check for NORM. 7. PU overshot assembly on workstring and RIH and latch tubing stub. Jar free, POOH. 8. PU packer milling and plucking assembly. Mill packer using stripper rubber and reverse circulation method. If losses are low, continue with plan. If losses are too high to circulate fill and /or metal shavings, pump polymer /salt pills as necessary to reduce fluid losses. Circulate hole clean of metal shavings. Use magnets at surface to catch metallic debris. Pluck packer out of hole. 9. After milling and retrieving packer, PU a flat bottom mill with open jets and clean out fill and potential obstructions down to TOC at 13,645'. Reverse circulate all fill out of hole. Displace hole with clean FIW from sand filters. POOH about 500' above top perf with mill. MU storm packer, RIH to 100'. Set same and release. POOH to change out tubing head. 10. ND BOP and install a new tubing head. NU BOP, test BOPs. RIH, pull storm packer. LD same. 11. MU Schlumberger TCP guns on workstring and RIH. RIH with E -line or memory GR tool on slickline. Position guns to perforate as follows, using the Hilcorp Digital Database Log (DDL) as the reference log. Proposed Perforations: � L fig' S 'tic "'— Zone Top Bottom Feet '- G1 12,476 12,518 42 ��'��` G2 12,562 12,580 18 27 ' G3 12,654 12,694 40 G4 12,708 12,836 128 G4 12,888 12,914 26 G5 12,943 12,962 19 JJ / ' -3 G5 13,049 13,094 45 G6 13,107 13,150 43 A l , ` LL `" LA / Lex., r G7 13,208 13,273 65 _ 1 _. HK1 13,300 13,380 80 HK2 13,455 13,545 90 �� + / � �� / Total: 596' /s,. 2.7. 1 Z- 12. When the guns detonate, the reduction of skin damage could cause the well to drink fluid until the fluid level finds the balance point between reservoir pressure and the column of fluid in the well. There is no need to circulate the hole, following the perforation event. After detonation, monitor well by shooting a fluid level. It is OK to fill the hole periodically with clean FIW since this will be an injector. Do not pump polymer and /or salt to slow the fluid loss. Once the well is determined to be static, POOH. 13. POOH with guns. LD same. Confirm that all charges fired. 14. PU 4 -1/2" X 7" packer and 4 -1/2" tubing. RIH. Space out and set packer at +/- 12,326'. Land the tubing hanger, and pressure up backside to confirm packer is set. Hold 2,500 psi for 30 minutes for the casing MIT test. If the pressure does not decline more than 250 psi in 30 minutes, the well has passed the Workover MIT. Provide Larry Greenstein with the pressure test results and the completed 10 -426 form for the MIT. • • Well Work Prognosis Well: G -12RD3 Hileorp Alaska, LLC Application Date: 8/16/2012 15. Set BPV. ND BOPE and NU tree. Test tree. 16. Turn well over to Production Supervision (TOPS) for re -start of injection. 17. Within 2 weeks of stable injection, schedule an Initial MIT with AOGCC. Provide the AOGCC 24 hour notice prior to the MIT test. All pressure test results and completed 10 -426 are to be provided to Larry Greenstein immediately following the test. • • • • Well Work Prognosis Well: G -12RD3 Hilcorp Alaska, LLf. Application Date: 8/16/2012 As -built (Old) Wellbore Schematic RKB to TBG Head = 40.73' CASING AND TUBING DETAIL Tree connection: il Hole Cmt 1 SIZE T GRADE CONN ID TOP BT IL Sin TOC Rotating fin 1,..-- W' 26" 4 "liT Surf 369' Driven NA 9Shrs ■ 1' -3`4" 0312 "RT 'Veld Surf 602' 2T' , ' 116hrs 13 -38" 61= K -55 Butt 12.515" Surf 6.013' 17" s o: 669hrs urf 1 9 -5 8" 4'= P-110 Seal Lock 3.681" Surf '3' 1 9.5 8•' 40= N -80 Seal Lack 8835" '3' 6252' 1000 ix 9 -5 3" 4 3 5e. N -80 Seal Lock 8'55" 6252' 6939' 4565'est t DV Collar 6939' 6911' 1 ) 9.5 9' 33 5= I N -80 1 SeslLac 8' 55" 6941' 82'6' 1. -14 932hn Redciii n3 1001 Nixdow cat in 9-J, , 43.54 M80 81 `6' 5310' 1000 xt Redr1114 19'S IRndoi cat ix 9.5 S 4'4 V40 10,1157' 10,313' 11,0 s.:1: 1 9 Redrila1 19'0 IT.ndow 55',4'4 -110 11.910' 11,4`' ? ?: -80 Butt 6 104 Surface 14.060' 3 - 2" I 945 sx 5 his 11 ID 048' eac 1 L -30 1 BTC -Irnu 1 2992 1 Snrfrcel 12.516' I A JEWELRY DETAIL \O- Dm6l Lea>•6 OD ID Item I D 1,.'":,, 40.73' 0.60' Cameron 11" x 3-55" DCB R., 3 -54" 8rd top x Butt B, Tbg Hngt M " tV` `7` 1. 416' 5.2.'' 5.400 2.810 Bake TE-5 TRSSSV I I A GLUI.1. 3276' 8.91' 5.968 2.867 3 -1 2" SFO-2 G1.AI; R -2 Valve RK Latch GLM 0 2. 5103' 8.91' 5.968 2.86' 3 -1/2" SFO-2 GLAI: R -2 Va1ve•RK Latch GLM 4. 6100' 8.91' 5.968 2.567 3 -112" SFO-2 GLAI; R -2 Va1ve'RK Latch GLM M. 6909' 8.93' 5 -968 2.86' 3 -1/2" SFO-2 GUI: R -2 ValveRK Latch GLM 4. '599' 8.92' 5 -968 2.867 3-112" SFO-2 GUI; R-2 Va1veRK Latch GL1U =6. 8223' 3.90' 5.968 2.867 3-1/2" SFO-2 CILIA: R-2 Valve/RK Linda 1 0 GLMI No 8781' 8.93' 5.968 2.86 3-122" SFO-2 GUI; R -2 Va1ve(RK Latch GLM =4. 9300' 8.94' 5.968 2.867 3 -112" SFO-2 GUM: R -2 VahveRK Latch GL\I 4 9834' 3.94' 5.963 2.867 3-1 2" SFO-2 OLA1; R -2 Va1ve'RK Latch GLU =10. 10416' 8.92' 5.968 2.867 3 -1 2' SFO-2 UM: R -2 Va1vaRK Latch GL]1 =11 10975' 8.92' 5.968 2.367 3 -1 2" SFO-2 GLM, R -2 Va1veRK Latch GL3[ =12 11505' 8.92' 5.968 2.86" 3 -1'2" SFO-2 GUI; R-2 Va1ve'RKLatch GLMI =13 11969' 3.93' 5.968 2167 3 -1 2" SFO-2 GUI; R -2 Va1ve Latch GL]t =1 12427' 8.91' 5.968 2.867 3 -1 2" SFO-2 GUI; R -2 On6cr_RK Latch G 2. 12,473' 14.50' 4.250 3.000 Locator Seal Ma, SiZe 1040 vv. (2) seal units & 5' spasm r,f � 3. 12,480' 10.01' 5.838 4.000 7" BOT Model F -1 Pan Fake (85-40) w 14.69' of SBE l 1. 12 1.53' 3.865 2.812 Baker 'X' Nipple 12.516' .. '5' 3.857 2.992 HOT (WL Reentry') Int gaitr Issues T Remediatioa Date ri 1 HOLE in9- 5' 698 ") None. Leak rate 2 3.5 Ipso 2 4210 psi =break down 1068 A" x'13" Annuli Comannication 10sx Gyp -S®1 Top Job 3 69 o HOLE in9- 5 8" x6962' Cmt sgz900sx Tested to2000pti bled to1900p5iin30n c 69 4B-0 !dined 9er8" 8- 1 2' taper nOlf 1563'to2452' 111usofm lBing Recovered (3)pieces ofcsgiron 3' Csa Caliper Log in9 -5'8" Pitting: allow.: 50% to 60%ofwall loss inmuhipleareas 5 3' • - -..-"'Ir - & t "A "x"B "Annulus Held 2500 psi Was tryiagto#ta breakdown rte 58' 13 -3 8" erg stub rsacl'edbetwembowl & 1' -3 4" cutoff 'Welded crack. Pressure test to 900psa. 5 8' Test 9-5 8 "csg Pressure testto2250pei fa30m . 3'98 " - ; ' HB-2 Test 9 -5I "csg Pressure testto1500psi fa 15min 502 tiJ4:4:ti+tifti:ti:ti-VtiJiS 11 . Unable to "U- tube" e i thruGLAC=1 Pvnped Acid down "A' Annulus 1104 E Fish lPlug LJ .y B.3 NO- Depth Date Desorption A -- 13.'00 6 16 02 42' gun a (2-1. Power 3et gun (30)) and approx300'of BAN wire. A B 13,545' 629.02 PAST Setoht°.at13610' 25• ofcentemdtanpedmto9 PERFORATION DATA `r Interval Accum 14 .040 Zone Interval(MD) (TVD) FT SPF Status PBTD = 13,960' TD = 14,070' 's -o 13z+ 13 1.70' 9541 - 9569 4o L open MAX HOLE ANGLE = 60.5' @ 2600' "g -1 0 313 11377' 9 514 9637 6: L Open •+ti -: 0 41C 13443 9641' 9660 33 t Open 13455 1335' 9661' 9699 60 t Oren x9. ::: :r34Y: ,1.7,'"I::- •:3Q:. .:a:•:- tpeae4 :?:!?9,?. : :139:3Q': :•3t•: :• :•a•:•: *thee* II • • Well Work Prognosis Well: G -12RD3 Hilcorp Alaska, ►.[.c Application Date: 8/16/2012 Proposed (New) Wellbore Schematic Casing Detail RIO ld TOG Head= 413 SIZE WT GRADE CONN ID TOP STM. Hole "" ' Tree eamectiorx Ow 23 l' AT ;Xi 363 Dr•,en 'iA 9305 las 17 -2 WT 4' 0.312' T Y ;;,+t ekl 602' 21 773sr to Surf. 11_ : - -.: r 221392 to 13.3/8' 61s C -73 butt 12313' ix/ 6,013 i ? Surf. 9.3 47s 0 -110 Seel Last 1.681' Surf 73 1030 sc r 9.3,.3' 409 4-30 3eaI u1n 1433' 73' 6,232' 4353 cr 9-348' 43.3s 4410 Seal left 8333 6,232' 6,939' A r DV Collar 5.939" 5.911 i. "k 9-3:3' 1 43.3e 1 N^60 1 Seal tact 1 3.733' 6,941 8,273 12.1/4' ..:S:1+ 1- 932002 Window tut in 91/8', 43311, 1940 8,276' 8,310' , es- 1 22 1978 Window Out in 93/5', 479, N-90 14,237' 1013' ?ppi 3.970 Windom *A in 9.3/8 ", 479, P-110 11420' 12..478' a to T' 23 MVO Hutt use Surface 14.080' 7,048' 443 1 Tubing Detail 4-1/2" 1 12.6 1 _40 1 are -Nod 1 1938 1 =_urece 1 _12.374' 70W/1427S Jewelry Detail EM11 =11 15 a.; ' NO. Depth Length OD ID Item 40.73' Cane ro n 11" x 4-Si" Dag tliag.r I. 312,326' Lrake r SA5-1 P cke r 2 112 'X" Nipple 3 112.362' WLEG Integrity Issues 1 11. r s ri r as . Type R emediation eat break HOLE in 9 -5/8" 16972' 69871 down. Leak rate 35 beat 4200 psi. as1 1Q /1 !__ "A "x" 8'' Annuli Communication 10sx Gyp-Seal Top Job 3/1 C.,untsce,900sx. Tested to 200Cpsi, bled to 1900psi in HOLE in 9 -5/8" 6962` 4/1 G-1 30 min Palled 9 -5/8"' t i w/ 8 -1/2' taper mill f/ 111229 of milling. Recovered 132 pieces of csg iron. 5/1 G- 2 1563' to 2452' " + Pitting shallow w/ 50°4 to 60°,1 of wall loss in multiple G-3 CsgCaliper Log in 9 -5/8" 5/1 Mat. 3 - "A" x "8" Annulus Held 2500 psi. Was trying to get a breakdown rate. 5/1 13-3/8' csg stub cracked betwee bowl & 17- Welded crack. Pressure test to 900 psi. 5/1 G-5 3/e cutoff. Test 9-5/8" Gig Pressure test to 2250 psi for 30 min. 3/1 • 3-6 Test 9-5/5" GSg Pressure test to 1500 psi for 15 min. 5/2 Unable to "Ll-tube" gas th ru GLM81 _ Pumped Acid down "A' Annulus 11/4 G Fish / Plug &1 NO. Depth Date Description I A + / - 13,7CC 6/16/2002 42' gun * 42- 1/ 2' PonerJetgunl3C 1 I andapprox.300'oft -line wire. 6 13.645' 6/29/2002 _ P. -set plug at 13670' w/ 25' of cement dumped on top. . 43-2 Perforations Zone Interval (MD. In terval (7113` F SPF Status E 6 4.1 :_. - X019 5,017 42' - =unre u _0.4 0-2 :12,_:; - -- - _02 5.115 13 - =uu•e ;r3 :12.534 :12,.6 :59 5.197 40 -utu 6.4 212,706 212836 25,205 5,299' 122 =.tu : 12;855 :12,914' 49,33_; :9.3.33. 25 'iru'c CO :12,941 :12.962' 1`9,372 5,:83 19 . 4..u-e, 213,045 :13,094' 19.440' St447 4:. =utu 1103: 6i 213,107 213,130 19,475 '3,_01 ;r_u'e POT D = 13.960' TD = 14,070' G7 213,2.03 :13,271 5,334 5.372 . - e MAX HOLE A NGLE = 60.5° it 2600' 6-7 11,127 11170 9 W 9,343 open 14151 213,300 :13,380 5" 3, E. , .../cu-e 13,313" 13,377 9,394` 9,527 62 .2 Open 11,410 13,441` 9,644 9,660' 5. .2. Open N&2 13,433 13,313` 9,668' 9,639° 60 12 Open 7_1 4__ :13,343^ "5,653 '4,713 90 _ Autu 1163 13,699 13,729' 30 5 13 .900 1.3.990 3'7 E. ■3.. • • Well Work Prognosis Well: G -12RD3 eacor Alaska, Application Date: 8/16/2012 P Williams Workover Rig 8 Grayling Platform 8OP 2012 111/ Weatherford Rental BOP Width 4.16' 3.74' Weight 13,100# Shaffer 13 5/8 5M Iftlfl inlitt t Shaffer L ' Total BOP height above 136A 5M _ _ drill deck 135/85M LWS -'- 9.48' min dimensions 11.48' max Length 7.73' — Width across body 2.72' _ - -_ Width across flanged outlets 4.00' = Weight95001bs . 9.00' III III III III • /. isu ' l r 'I ' Mud Cross 28501bs w/ valves M��!� ' I�M I1® 1.74' ti . 111 111111111111 • Riser above drill deck I ' fII This number will vary from well to well 1 00' 10 3.00' 5 Drill Deck 13 5/8 5M Riser 85001bs 15.00' 111 111 S f _ 1i1 111 Spacer Spool 135/85M X 135/85M 1.95' 18001bs *i �( 1 111 Crossover Spool 135/85M X115M 18001bs 2. - Top of Wellhead • • Note to File TBU G12 -RD3 (PTD 2020550; Sundry Applications 312315 and 312329 ) Review Sundry App No. 312329 regarding conversion to injection. New pool will be opened by proposed additional perforations above Hemlock Oil Pool. New perfs will be in Mid -Kenai G Oil Pool. Check orders; commingled FOR injection is allowed by AIO 5. Recall that the program that this application proposes is the same operations as in Sundry App No. 312315. Call Mike Dunn. He confirms that this application is the same program as that in Sundry App No. 312315, with changed packer depth and one different step in procedure. Ask Mike to send an email withdrawing Sundry App No. 312315 to close out that application. Mike will ask Tom Fouts send that email. Find Sundry App 312315 in Victoria's confidential box. Notice that Tom already provided the withdrawal email on 8/23/12. Oops. Phone Mike. Tom is just going to forward a copy of that withdrawal email to me. He will cc me on all such correspondence in the future. 5 2.7 / •�- • • Davies, Stephen F (DOA) From: Tom Fouts - (C) [tfouts @hilcorp.com] Sent: Monday, August 27, 2012 2:34 PM To: Davies, Stephen F (DOA) Cc: Mike Dunn; Larry Greenstein; Ferguson, Victoria L (DOA); Juanita Lovett Subject: RE: G -12RD3 (PTD 202 -055, Sundry 312 -315) Area of Review Steve, This Sundry was originally submitted on Aug. 16 2012. The attached email was sent to Victoria on Aug. 23 2012. In the future we will include you in our correspondence regarding these matters. Please feel free to contact me with any questions you may have. Thanks, Tom Fouts 1 Construction Manager Hilcorp Alaska, LLC tfouts(hilcorp.com Direct: (907) 777 -8398 Mobile: (907) 351 -5749 From: Tom Fouts - (C) Sent: Thursday, August 23, 2012 1:30 PM To: victoria.fergusor a>alaska.gov Cc: Michael Dunn; Larry Greenstein Subject: RE: G -12RD3 (PTD 202 -055, Sundry 312 -315) Area of Review Victoria, We are resubmitting the 10 -403 for G -12RD3 with the corrections for the packer depth stated in the procedure and wellbore schematic. Please discard the previous 10 -403 submitted for G- 12RD3. The replacement 10 -403 will be couriered to you today. If you have any questions please feel free to contact me. Thanks, Tom Fouts' Construction Manager Hilcorp Alaska, LLC tfouts@hilcorp.com Direct: (907) 777 -8398 Mobile: (907) 351 -5749 1 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 x) i v nl El 1. Type of Request: Abandon ❑ Plug for Redr Perforate New Pod [ /- ,i,IRepair Wen El Change Approved Program El Suspend ❑ Plug Perforations ❑ Perforate IS ' Pun Tubing 0 . Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Wen ❑ Stimulate ❑ Alter Casing ❑ Other Convert to Injector/Complete 0 . 2. Operator Name: 4. Current Well Class: 5. r it to DrH Number. Hilcorp Alaska, LLC Development Exploratory ❑ .2 -055 • 3. Address: Stratigraphic ❑ Service ❑ 6. API Number. 3800 Centerpoint Dr., Suite 100 Anchorage, Alaska 99503 50- 733-20116 -03 . 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Wen Name an . • ' r. • - property line where ownership or landownership cianges: Spacing Exception Required? Yes ❑ No 0 G -12RD3 'IN. 9. Property Designation (Lease Number): 10. Field / Pool(s): it Grayling Platform, Cook Inlet/ ADL17594 & ADL18730 McArthur River/ Hemlock 11. PRESENT WELL CONDITION SUMMAR Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Dep '•e (ft): Plugs (measured): Junk (measured): 14,070 ' 9,994 • 13,297 13,645' +/- 13,700 Gun Assy. li Casing Length Size MD TVD Burst Collapse • Structural 369' 26" 369 A . 368' Conductor 602' 17 -3/4" 602' 601' Surface 6,013' 13 -3/8" 6,0 ' 4,346' 3,090psi 1,540psi Intermediate 6,941' 9 -5/8" \ 6,940' 5,750psi 3,090psi Production 14,060' 7" 14,0:0' ,' 9,988' 8,160psi 7,020psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing ,.,. - e Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3 -1/2' 9.3 #/ L -80 12,516 Packers and SSSV Type: and SSSV MD (ft) and TVD (ft): BOT F -1 Perm. Packer and Baker TE -5 TRSSSV 12,480(MD)/ 9,042(TVD) and 416(MD)/ 416(TVD) llar 12. Attachments: Description Summary of Prop, 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketc Exploratory ❑ Development ❑ Service El . 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 9/1/2.' Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: • - WINJ 0 • GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing 's true and corre to the best of my knowledge. Contact Mike Dunn Printed Name , Mike 0 unn Title Sr. Reservior Engineer • ' Phone 777 -8382 0 351 -4191 m Signature � ' � ' O ( ) Date 8/16/2012 COMMISSION USE ONLY Conditions of approval: Notify Commission so hat a representative may witness Sundry Number: L Plug Integrity ❑ BOP Test ,',5 Mechanical Integrity Test Location Clearance ❑ Other: �JL,' �7 it: 7 ✓ I , V r �1 / j l 6eji C C r VI 5 D C f C i T5 1 Gi 5 i ki c l l '' o fi r Subsequent Form Required: 5 D" AUG ZQ� APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: - - ' - i7, A U G ORIGINAL � ' . N r •,,, •0 Form 10-403 R -d 1/20 , , , :.i.I it. S ubmit in Duplicate Well Work Prognosis Well: G -12RD3 Hilcorp Alaska, LLC Application Date: 8/16/2012 Well Name: G -12RD3 API Number: 50- 733 - 20116 -03 Current Status: Oil Producer - Leg: Leg #2 (NE corner) Estimated Start Date: September 1, 2012 • Rig: Williams Rig 404 Reg. Approval Req'd? 10 -403 Date 10-403 submitted: August 16, 2012 Regulatory Contact: Tom Fouts 777 -8398 Permit to Drill Number: 202 -055 First Call Engineer: Mike Dunn (907) 777 -8382 (Office) (907) 351 -4191 (M) Second Call Engineer: Ted Kramer (907) 777 -8420 (0) (985) 867 -0665 (M) AFE Number: 1221948 Budgeted Cost: Pressures: Bottom Hole Pressure (BHP); Maximum Potential Surface Pressure (MPSP) • °01 Current BHP: — 2,851 psi @ 9,627' TVD* .296 psi /ft. = 5.7 ppg .�� . 'JJ 1 o , ' Max. Expected BHP: 2,851 psi i si @ 9,627' TVD No new perfs or zones to be opened ened v� r � � � ►� MPSP: 1,887 psi Using 0.1 psi /ft. of True Vertical Depth 0619 *based on 2009 shut -in pressure survey. Note: This well has been a producer with no nearby injector support. (1.17/ Brief Well Summary G -12RD3 is (was) the furthest down -dip producer on the east flank of the main structure. In February 2012, shortly after Hilcorp acquired the field, the water cut spiked from 60% to 95 -97% water cut, while the gross fluid jumped from 200 -bfpd to 1,000 -bfpd. It was suspected the aquifer had encroached from the east, or water was coning from the aquifer below. The well was shut -in for several weeks in an attempt to "heal" the coning channel — but to no avail. The well has remained on as a producer at 95 — 97% watercut and net production of 30 — 40 bopd. The time has come to convert this well to an injector. There is believed to be some reserves up -dip of G -12RD3 toward G -08 that can be swept with injection at this location. This workover is intended to pull the gas lift completion, remove the production packer, clean out fill, re- perforate, and run a packer and new tubing. The well is expected to take about 7,000 -bwpd once it is placed • on injection. Notes Regarding Wellbore Condition • The tubing has a SSSV and 14 gas lift mandrels. • Casing integrity is believed to be intact. There are no indications of communication behind the 9- 5/8" casing. Procedure: 1. Cut the tubing with jet cutter just above the packer. 2. Skid Williams Rig 404 over the G -12RD3 well slot. Raise mast. Prepare for wellwork operations. 3. Plumb FIW lines to circulate down the annulus and up the tubing, when the tubing is pulled out of the packer. 4. Notify AOGCC of pending BOPE test. Set BPV, ND tree, NU BOPE. Test all BOP equipment per AOGCC guidelines to 250 psi LOW and 3,000 psi HIGH. Test Annular BOP to 250 psi LOW and 1,500 psi HIGH. Record pressures, fill out the 10-424 form and send to Jim Regg at AOGCC and Juanita Lovett with Hilcorp. • • Well Work Prognosis Well: G -12RD3 Hilcoep Alaska, LLC Application Date: 8/16/2012 5. PU landing joint and make -up to tubing hanger. Tug on tubing to pull the hanger free. Pull hanger up to floor height. Install stripper rubber. Circulate at least 2 bottoms -up to adequately clean hole. 6. POOH with completion tubing. LD same, check for NORM. 7. PU overshot assembly on workstring and RIH and latch tubing stub. Jar free, POOH. 8. PU packer milling and plucking assembly. Mill packer using stripper rubber and reverse circulation method. If losses are low, continue with plan. If losses are too high to circulate fill and /or metal shavings, pump polymer /salt pills as necessary to reduce fluid losses. Circulate hole clean of metal shavings. Use magnets at surface to catch metallic debris. Pluck packer out of hole. 9. After milling and retrieving packer, PU a flat bottom mill with open jets and clean out fill and potential obstructions down to TOC at 13,645'. Reverse circulate all fill out of hole. Displace hole with clean FIW from sand filters. POOH about 500' above top perf with mill. MU storm packer, RIH to 100'. Set same and release. POOH to change out tubing head. 10. ND BOP and install a new tubing head. NU BOP, test BOPs. RIH, pull storm packer. LD same. 11. MU Schlumberger TCP guns on workstring and RIH. RIH with E -line or memory GR tool on slickline. Position guns to perforate as follows, using the Hilcorp Digital Database Log (DDL) as the reference log. Proposed Perforations: Zone Top Bottom Feet G1 . 12,476 12,518 42 G2 12,562 12,580 18 G3 12,654 12,694 40 G4 12,708 12,836 128 G4 12,888 12,914 26 G5 12,943 12,962 19 G5 13,049 13,094 45 G6 13,107 13,150 43 G7 13,208 13,273 65 HK1 13,300 13,380 80 HK2 13,455 13,545 90 Total: 596' 12. When the guns detonate, the reduction of skin damage could cause the well to drink fluid until the fluid level finds the balance point between reservoir pressure and the column of fluid in the well. There is no need to circulate the hole, following the perforation event. After detonation, monitor well by shooting a fluid level. It is OK to fill the hole periodically with clean FIW since this will be an injector. Do not pump polymer and /or salt to slow the fluid loss. Once the well is determined to be static, POOH. 13. POOH with guns. LD same. Confirm that all charges fired. 14. PU 4 -1/2" X 7" packer and 4 -1/2" tubing. RIH. Space out and set packer at +/- 12,480'. Land the tubing hanger, and pressure up backside to confirm packer is set. Hold 2,500 psi for 30 minutes for the casing MIT test. If the pressure does not decline more than 250 psi in 30 minutes, the well has passed the Workover MIT. Provide Larry Greenstein with the pressure test results and the completed 10 -426 form for the MIT. • • Well Work Prognosis Well: G -12RD3 Hilcorp Alaska, LLC Application Date: 8/16/2012 15. Set BPV. ND BOPE and NU tree. Test tree. 16. Turn well over to Production Supervision (TOPS) for re -start of injection. 17. Within 2 weeks of stable injection, schedule an Initial MIT with AOGCC. Provide the AOGCC 24 hour notice prior to the MIT test. All pressure test results and completed 10 -426 are to be provided to Larry Greenstein immediately following the test. • • Well Work Prognosis Well: G -12RD3 11 . u.1.i, III Application Date: 8/16/2012 As -built (Old) Wellbore Schematic RKB to TBG Head = 40.73' CASING AND TL731NG DETAIL Tree connection: Hole Cmt 1 SIZE WT GRADE CONN ID TOP BTlli Size IOC Rotating Hn a }I I 26" 4" RT Swf 369' Dl":7" i - � 9 S hn l , , L 17 -34" 03L' "ti[T [Veld Surf 602' 116hn Surf 13 -3'8" 616 K -55 Sntt 12.515" Surt 6.413' - . 669hn 9 -5 8" 4'= P-110 Sal Lock 8.681" Surf - 3' 1 U 9 -51" 4 3= N -80 SalLock 8335" '3 5252• : "` 9 -5 `8" 435= N -80 Sa1Lock 8'55" 6252' 6939' 4 _S'.•a;: DV Collar I ) 9 -5 B" t3 5= N -B0 Seal Lock 8 '55" 6941 6939' 6 8 9 2 .1 6 1 " 12-1 4. Bsdriii 03 1001 Window cut in 45.3, 4330, 40 8176' 5310' 1 000 sx & d r i l l i 1 1976 Window cat in 45.3 , 474 N-80 10,257' 10.313' 11.02' at - di Y e d r r 7 J 4 1 1970 lifxdow cut ix 45.1, 474 P -1i 0 32,4 t' 11,476' 29 N -80 Butt 6 184" Surface 14060' 945 ix 0 h ■ 048'EiL I T om : 3 -1 2" 1 9 3 1 L -80 1 BTC -Imo 12 992 1 Surface 1 12,516' JEWELRY DETAIL NO Depth Lent OD ID Item 40.73' 0.60' Caramels 11" x 3-4i" DCB w, 3 -4i" EMI top x Butt Bening Haar "Cq- D 1. 416' 5.22' 5.400 2.810 Bake :'E -5 TRSSSV D GUI =1. 3276' 3.91' 5.968 2.867 3 -1 2" SFO-2 GUI; R -2 Va1ceRKLrtdt GUI e2. 5103' 3.91' 5.968 2.867 3 -1 2" SFO-2 C'LM: R-2 Va1veRK Lards I b GUI 3. 6100' 8.91' 5.968 2.867 3 -1.2" SFO-2 GLU: R-2 Val eRK Latch GUI =1. 6909' 8.93' 5.968 2.867 3 -1 2" SFO-2 GLRI: R -2 Valve lit Latch b GU( .5. '599' 8.92' 5.968 2.867 3 -12" SFO-2 GL�i: R -2 Valve RI'. Lech GUI =6. 8223' 1.90' 5.968 2.86 3 -1'2" SFO-2 GLU: R -2 Valve RX Lech 3 GUI a'7. 8781' 8.93' 5.963 2.867 3 -1 SFO-2 GUI: R -2 Va1veRK Latch 1 GU 1 .8. 9308' 8.94' 5.968 2.867 3 -1 SFO-2 GLU; R -2 VaheRK Lech li GUI 4. 9834' 3.94' 5.968 2.867 342" SFO-2 GUI: R -2 ValceRK Lich GUI =10. 10416' 3.92' 5.968 2.867 342" SFO.2 OLIa1: R -2 Va1teRK Latch U GUI =11. 10975' 3.92' 5.968 2.867 3-I12" SFO.2 GLU; R-2 Va14eRK Latch GUI 612. 11505' 3.92' 5.968 2.867 3-112" SFO-2 GLh1; R -2 Va1ceRK Letds GUI613. 11969' 3.93' 5.968 2.867 3-IrT' SFO-2 GUI: It-2 Val1eRKLatch GUI ell. 12427' 3.91' 5.968 2.867 347" SFO-2 GLU: R -2 Orifice'RK Lerch Il 2. 12. - - 5' 1 51' 4.250 3.000 Locator Seel Amy, Size 30-40 V (2) seal :sits 3c 5' space tube '. 3. 12,480' 18.01' 5.838 4.000 7 } BOT Model F -1 PeenPad:er (85 -40) w :4 59' ofSBE I -01 - 4. 12,503' L53' 3.865 2.812 Baker'X" Fipple = s1` 6. 12,516' 0.75' 3.857 2.992 EOT !Mt Re-entry) __I Integrity Issue i Twe Remediation Date HOLE in 9 -5 8' (69'2' MIS None. Lek rase 2 3 5 hpta p( 4203 p si as breakdown 10 63 "A" x "Jr Annuli Coon 10sx Cryp -Sa1 Top lob 3 59 5 HOLE in9- 5 Clot igz900sx. Tested to2000pd , bled to1943psiia30min 459 .1113.0 Milled 9-5.9 "mg w8- 12'tape mill 1563'to2452' 11 his of =him Reco ed(3)piecesofmgiron 5 3' � 't CsgCaliperLogin9 -5B Pitting s�8oww 53t4to60%ofwa1 lass inmuhipkareas 5 4 Obstruction +'--H61 "A "x 13" Annulus Held 2503 psi Was tryingtosptabrekd :mu:am 8 @ 13,237 13 -3 8" ag e&tb aac edbemembood & 1' -3 4' Cutoff y t ' e 1 d e d crack P r e r a w e t u t to 930 psi. 5 8 - Test 9 -53 "mg Pressure testto22500 far 30mm 3 93 tamed sts01044" - Test 9-5 8 "CSg Pressure testto153.3pii for 15s1a 502 44.2 7941343 On 7618 _.HB -2 S y r { , { r L r r ti`,r•C'tirtirti- U nableto - 'II-mbe os thtuGL31=1 Pumped Arid dou t "A' Arnim 11 34 B -, ,1� Fish i Plug Li H9.3 NO. D S Date Description A --13,700 51602 42' gua auS 1: Pincer Jet eve (30')) acdapprax 3.3J' ofE -line wire A B 13,645' 6 29 02 Ba i; Set phsere 136 ms V' w 25' ofcemeatdtmped catop PERFORATION DATA ksterval Acct 13' L Zorse in (TV D] FT SPF Status PBTD= 13,960' TD= 14,070' - -C 131:7' 13270' 9545 9569 4C C open MAX HOLE ANGLE = 60.5` @ 2600' "6 -1 0 313 13177• 9 534 36:7 6: t Coen •+6•: 4 41C' 13.441 3644' 366C' 31 t 0541 13 455 1376' 5657 3639 6V t Open '4'3::: :9..l: :11 :: • :332:• •••:a: ••• IForte4 :• 3Q•: :•:•a•:•: 1b Meek • • • Well Work Prognosis Well: G -12RD3 HilwrpAlseka,LLf. A pplication Date: 8/16/2012 Proposed (New) Wellbore Schematic RltE:t.:. TE:i Heid =4( 73' _ Tr ■•❑rl' t � asing rt' ; tdDE CONIJ ID TOP PT NI. 11-L Cmt rrn rs / [ li LC. :F' ,' t4T Surf 363' Omen N.4 95 hrt 17•'S' O_12 on. Weld Surf 6112 22 775:.m:urf . 116 hr, 13' +3' 614 1: -15 Butt 12515" surf 6,013' 17' 2 ' Surf I 9 -5,3' 474 6 -110 Seal Lock 3681" Surf ?3 1007u 9 -46" 4.74 r 4 Sv6" 435• µ30I Teal Lx1 3315" 6,252 4565'est - 1130 Seal Wee 8.715' 6939" �, µ I_C1 a „ uv 6941 �.,. 9 -43 I 1351 1 N30 Sea I LxM I 3755" 6941' 8276' 121/4' 10_0 s.: 11117 , 11 I Rdrill43 DM Windowcut in 9-543", 4357, N -80 8,279 8,310 11027'.51 Rdrl II 42 1978 Wudow cut or 9 -5/8', 4 ?i, N -33 10.257' 10313 ' gI ll Rdri11411970WIrd -5;6 47t+ owcut In 9', . 6 -110 12,411' 12, 478" 29 N-37 Butt 6134' Surface 14!0-!r yS5 I Tubing Dete11 TO,n 275' 4 I 126 I L80 1 B1t-Mod 1 3958 I Surface 1 t'. - _ _ EL1'n= 11 14 p Jewelry Detail rri Depth I.• rwth OD ID Item 40.73' Came tort 11 "x 4.34" Ttg Hrr r 1 * 1 2 , 4 8 0 ' Tri - mint StimTOp 6 :Is- s_t.s -I1_.. e_- 2 31 2,503' ".x Nipple - on - 1 3 312,516' _ WLEG - 2 NNW 3 Pertor ati ori_ '' - re IntervaI I;N1O;1 IntervaII;TVD;I Ft 5PF Ste t'i `. I_ 2 G1 !12.476' ±12518' x9189' 39 ,070' , 42' 5 Future G2 31256 312580 ±9 ,102 ±'9,115' 13' 5 Future G -3 0-3 312.654' 31269 4' ±9,169' 39,197' 40' 5 Future 1112706' 312,336' ±5,18' 39,299' 12' 5 Future G 4 G4 ±121183' ±12914' ±5335' ±3,353' 3' 5 Future ±12,943' ±1296 ±9 37 2 39 385' 19' 5 future G -5 GS 313)049' ±130 ±5,440 ±3,467' 45' 5 future G6 ±13,10T 113,150 ±±9 475' ±3501' 43' 5 future sa G-8 G? 313,218' ±13,713' ` " ±9571' 65' 5 future 07 13,227' 13,270 5,545' 9569' 40' 17 Open G -7 150 313300 ±13330 ±9556' ±9.69' 301' 5 Future 13,315' 13377' 9,594' 9,67' 62' 12 Open HB - 13,410 13,441' 9,644' 9,667' 31' 12 Open H5-2 13,65' 13,515' 9,668' 9)699' 62' 12 Open 313,455' ±13545' ±9,663' ±3 97' 5 Future _.._H B -1 9F3 13,699' 13,729' 33' 6 Ire*** 13,9010 13930 3I' 6 6>6 E: HE -8 A FCSfI ' PIU� ri'). Gepth 0,11.- �..- :t 14 U iU' • � 4 +/- 13 6/] 5/3702 12 un ass ll' -1 i2` Fr, M> z r1'tgunf :rill and apprOx , 3 1 ?Ycd Iir>e ire . P ETD = 13,960' TD= 14,070' 9 13,645' 6/29/ P_elS plug at136 ?0r ,,53',_4 nent dumped on top . MAX HOLE ANGLE = 60.5• @ 2600' Revised: 8/16/2012 by MDD • • Well Work Prognosis Well: G -12RD3 Application Date: 8/16/2012 Williams Workover Rig Grayling Platform BOP 2012 111 III III III ill III I11 Ali Width 4.16' 3.74' Weight 13,1008 Sheffer 13 8/8 5M ii Shaffer LWS Total BOP height above 135 /85M LWS 13 5/8 5M — - Sri dmn dimensions _ C — 11.48' max Length 7.73' 3.00' Width across body 2.72' Width across flanged :11 outlets 4.00' — Weight95001bs - — 9.00' i _ 111 11111111111 T� Mud Cross �j r r 28501bs w/ valves 011441 ~ s. !� . 1.74' y _ iii III III III ni - Riser above drill deck 1 11 1 1 I This number will vary from well to well 1.00' to 3.00' V Drill Deck 13 5/8 5M Riser 85001bs 15.00' • 1�1 1�1 111 Iil Spacer Spool ii:" 13 5/8 5M X 13 5/8 5M $ 1.95' 1800Ibs ! III III CfOSSOVer Spool 135/85M X115M ... {a 18001bs 2 83' 111 111 Top of Wellhead • • Ferguson, Victoria L (DOA) From: Tom Fouts - (C) [tfouts @hilcorp.comj Sent: Thursday, August 23, 2012 1:30 PM To: Ferguson, Victoria L (DOA) Cc: Mike Dunn; Larry Greenstein Subject: RE: G -12RD3 (PTD 202 -055, Sundry 312 -315) Area of Review Victoria, We are resubmitting the 10 -403 for G -12RD3 with the corrections for the packer depth stated in the procedure and welibore schematic. Please discard the previous 10 -403 submitted for G- 12RD3. The replacement 10 -403 will be couriered to you today. If you have any questions please feel free to contact me. Thanks, Tom Fouts Construction Manager Hilcorp Alaska, LLC tfouts@ hilcorp.com Direct: (907) 777 -8398 Mobile: (907) 351 -5749 From: Mike Dunn Sent: Thursday, August 23, 2012 10:39 AM To: victoria.ferguson(aalaska.gov Cc: Schwartz, Guy L (DOA); Tom Fouts - (C); Larry Greenstein Subject: FW: G -12RD3 (PTD 202 -055, Sundry 312 -315) Area of Review Victoria, The Packer setting depth is incorrect. We target 150' above the top perf on injectors, which would put the packer at 12326' MD. I will send over a revised 10 -403 with a correct procedure and correct proposed schematic. For confirmation of cement isolation, this issue was discussed with Guy Schwartz when it looked like we were going to do the conversion without a rig. The cementing report was reviewed and the determination was made that the cement job was good. As for running a CBL, we would like you to reconsider the value gained, vs. versus the time and expense of running the log. 1. It is extremely rare for the cement quality on the tail end of a full string of 7" to be inadequate. This is likely why Unocal did not run a CBL after the job. The excess cement that you are allowed to pump on a long string, as opposed to a liner where you are limited to how much cement you care to reverse out, is the primary reason why long strings have very, very high success rate. 2. Enclosed is the cement report for the cement job. There is no mention of lost returns, there is no reason to believe isolation is a concern. 3. The well has produced for over 20 years, with no indication that production was coming from outside the zone of interest. 4. The cost of a CBL on E -line, with rig time will be at least $30,000. 1 Given the location of this well down near the aquifer, see find little reason to spe�the money to run a CBL that will confirm we have isolation. We Mike Dunn I Senior Engineer Hilcorp Alaska, LLC Office: (907) 777 -8382 Mobile: (907) 351 -4191 Mike Dunn 1 Senior Engineer Hilcorp Alaska, LLC Office: (907) 777 -8382 Mobile: (907) 351 -4191 From: Larry Greenstein Sent: Thursday, August 23, 2012 7:13 AM To: Mike Dunn; Tom Fouts - (C) Subject: RE: G -12RD3 (PTD 202 -055, Sundry 312 -315) Area of Review Attached are the cementing reports that were sent to Guy. Larry From: Mike Dunn Sent: Wednesday, August 22, 2012 4:57 PM To: Tom Fouts - (C); Larry Greenstein Subject: FW: G -12RD3 (PTD 202 -055, Sundry 312 -315) Area of Review Tom, would you please find the cementing details for the 7" long string in this well. And please confirm there is no CBL for this well. Mike Dunn S Senior Engineer Hilcorp Alaska, LLC Office: (907) 777 -8382 Mobile: (907) 351 -4191 From: Ferguson, Victoria L (DOA) f mailto: victoria.fergusonCa�alaska.ciovl Sent: Wednesday, August 22, 2012 4:28 PM To: Mike Dunn Cc: Schwartz, Guy L (DOA) Subject: RE: G -12RD3 (PTD 202 -055, Sundry 312 -315) Area of Review Mike, We have the previous sundry information Hilcorp submitted on the area of review. Since you are pulling the tubing, could you run a CBL to confirm zonal isolation? Also, the packer is set at about 12,480' MD while the top perf is 12,476' MD. Is this correct? Thanx, Victoria 2 • • Note to File TBU G12 -RD3 (PTD 2020550; Sundry Applications 312315 and 312329 ) Review Sundry App No. 312329 regarding conversion to injection. New pool will be opened by proposed additional perforations above Hemlock Oil Pool. New perfs will be in Mid -Kenai G Oil Pool. Check orders; commingled FOR injection is allowed by AIO 5. Recall that the program that this application proposes is the same operations as in Sundry App No. 312315. Call Mike Dunn. He confirms that this application is the same program as that in Sundry App No. 312315, with changed packer depth and one different step in procedure. Ask Mike to send an email withdrawing Sundry App No. 312315 to close out that application. Mike will ask Tom Fouts send that email. Find Sundry App 312315 in Victoria's confidential box. Notice that Tom already provided the withdrawal email on 8/23/12. Oops. Phone Mike. Tom is just going to forward a copy of that withdrawal email to me. He will cc me on all such correspondence in the future. 2 .7 Z • • Davies, Stephen F (DOA) From: Tom Fouts - (C) [tfouts @hilcorp.com] Sent: Monday, August 27, 2012 2:34 PM To: Davies, Stephen F (DOA) Cc: Mike Dunn; Larry Greenstein; Ferguson, Victoria L (DOA); Juanita Lovett Subject: RE: G -12RD3 (PTD 202 -055, Sundry 312 -315) Area of Review Steve, This Sundry was originally submitted on Aug. 16 2012. The attached email was sent to Victoria on Aug. 23 2012. In the future we will include you in our correspondence regarding these matters. Please feel free to contact me with any questions you may have. Thanks, Tom Fouts 1 Construction Manager Hilcorp Alaska, LLC tfoutsPhilcorp.com Direct: (907) 777 -8398 Mobile: (907) 351 -5749 From: Tom Fouts - (C) Sent: Thursday, August 23, 2012 1:30 PM To: victoria.ferguson@aalaska.gov Cc: Michael Dunn; Larry Greenstein Subject: RE: G -12RD3 (PTD 202 -055, Sundry 312 -315) Area of Review Victoria, We are resubmitting the 10 -403 for G -12RD3 with the corrections for the packer depth stated in the procedure and wellbore schematic. Please discard the previous 10 -403 submitted for G- 12RD3. The replacement 10 -403 will be couriered to you today. If you have any questions please feel free to contact me. Thanks, Tom Fouts 1 Construction Manager Hilcorp Alaska, LLC tfoutsPhilcorp.com Direct: (907) 777 -8398 Mobile: (907) 351 -5749 1 Page 1 of 2 • Schwartz, Guy L (DOA) From: Tom Fouts - (C) [tfouts @hilcorp.com] Sent: Tuesday, July 31, 2012 2:19 PM To: Schwartz, Guy L (DOA) Cc: Mike Dunn; Larry Greenstein; Ferguson, Victoria L (DOA) Subject: RE: Sundry # 312 -139/ Well # G -12RD3 FT Zd z - © S - S Guy, r Thanks for the quick response. We request to cancel Sundry # 312 -139 for G- 12RD3. We will update and resubmit this procedure for approval. Sincerely, Tom Fouts 1 Construction Manager Hilcorp Alaska, LLC 4 AUG 0 8 202 tfouts @hilcorp.com Direct: (907) 777 -8398 Mobile: (907) 351 -5749 From: Schwartz, Guy L (DOA) [ mailto:guy.schwartz @alaska.gov] Sent: Tuesday, July 31, 2012 1:47 PM To: Tom Fouts - (C) Cc: Mike Dunn; Larry Greenstein; Ferguson, Victoria L (DOA) Subject: RE: Sundry # 312 -139/ Well # G -12RD3 Tom, That is a rather large departure from the approved sundry. The best way to handle it is to resubmit the sundry and cancel the current one. It shouldn't take log to reprocess .... Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Tom Fouts - (C) f mailto:tfouts@&hilcorp.com1 Sent: Tuesday, July 31, 2012 1 :38 PM To: Schwartz, Guy L (DOA) Cc Mike Dunn; Larry Greenstein Subject: Sundry # 312 -139/ Well # G -12RD3 Guy, We received the approved sundry 312 -139 for G -12RD3 (See attached) back in April. We have yet to 7/31/2012 Page 2 of 2 • perform the work outlined in our procedure and would like to request some changes. The request entails the addition of pulling the existing tubing with the Williams rig and complete the well with new tubing. We will also be perforating the G -Zone for this well (See attached Schematic.) Please let me know what additional information or documentation you will need for us to be able to proceed. Thank you Tom Fouts ( Construction Manager Hilcorp Alaska, LLC tfouts @hilcorp.com Direct: (907) 777 -8398 Mobile: (907) 351 -5749 7/31/2012 • • (10 7 rick „ CI) Li --,,, [; , . , , SEAN PARNELL, GOVERNOR ALASKA. OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 is�7�I PHONE (907) 279 -1433 FAX (907) 276 -7542 Keith Elliott Asset Team Lead Hilcorp Alaska, LLC aa� Cl aS 3800 Centerpoint Drive, Suite 100 --- Anchorage, AK 99503 Re: McArthur River Field, Hemlock Oil Pool, G -12RD3 Sundry Number: 312 -139 Dear Mr. Elliott: �+�' Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. S'sc . . Norman Co m' loner DATED this ?(day of April, 2012. Encl. • • • • 0000v 1 STATE OF ALASKA ZIOZ 0 MI ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS CI3AI933U 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other. Convert to Injector • El 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Hilcorp Alaska, LLC Development is • Exploratory ❑ 202 -055 • 3. Address: Stratigraphic ❑ Service ❑ 6. API Number. re. ',a, > ,;, 4t ..m i. ex: 3800 Centerpoint Dr., Suite 100 Anchorage, Alaska 99503 50- 733 - +2022• • Li •6 , i ,•,, , 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No el G -12RD3 • N. _ • • ,• 9. Property Designation (Lease Number): 10. Field / Pool(s): vi; y k 1 v I. .a Grayling Platform, Cook Inlet/ ADL17594 & ADL18730 McArthur River/ Hemlock . 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plu.. measured): Junk (measured): 14,070 • 9,994 • 13,297 9,583 r Gun Assy. Casing Length Size MD D Burst Collapse Structural 369' 26" 369' Conductor 602' 17 -3/4" 602' • 1 1 Surface 6,031' 13 -3/8" 6,031' 1111F ICIEV- 3,090psi 1,540psi Intermediate 6,941' 9 -5/8" 1111.KMMIIRACAMI 5,750psi 3,090psi Production 14,060' 7" 14,060' -,988' 8,160psi 7,020psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Siz bing Grade: I Tubing MD (ft): See Attached Schematic See Attached Schematic /2" / * /' 9.3#/ L -80 12,516 Packers and SSSV Type: • a • ers = nd . SSV MD (ft) and TVD (ft): BOT ZF -1 Perm. Packer and Baket TE -5 TRSSSV ®' 1 \ 80(MD)/ 9,042(TVD) and 416(MD)/ 416(TVD) 12. Attachments: Description Summary of Proposa 0 1 . -II Class after proposed work: Detailed Operations Program ❑ BOP Sketc )♦,, • loratory ❑ Development ❑ Service IS • • 14. Estimated Date for 15. ell Status after proposed work: Commencing Operations: • 4 ° ' N -o► Oil . Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: s . 1 WINJ © • GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and c' ect to the best of my knowledge. Contact Mike Dunn Phone 777 -8382 Printed Name Keith iott Title Asset Team Lead c _____. Signatures ( J .pnone 777 -8300 Date 4/5/2012 j COMMISSION USE ONLY ��jj q Conditions of approval: Notify Com scion so that a representative may witness, Sundry Number: `-�\ 2 ' �S I Plug Integrity / ❑ BOP Test ❑ � Mechanical Integrity Test gi Location Clearance ❑ U Other: X at‘---; vnc 4�rt e2 -tr s-a_ C, . t - DDD . Z Go � ^^ `'/ NO ST S .- le 44-- r e dt/ 46--( zo .44,25.,-ilLok) Subsequent Form Required: / r , L/ APPROVED BY Approved by: Of / Ci MMISSIONER THE COMMISSION Date: 9.2 , 7� Form 10-403 Revised 1/2010 O R A �,,. riPossenuoupv:!a 4. • • • 3000V STATE OF ALASKA ZLOZ 0 dV ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS t13AI 333 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other Convert to Injector • 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number Hilcorp Alaska, LLC Development IS • Exploratory ❑ 202 -055 • 3. Address: Stratigraphic ❑ Service ❑ 6. API Number. ce., .7y,(� i.r /f. 43 emr .. 3800 Centerpoint Dr., Suite 100 Anchorage, Alaska 99503 50- 733.4 -t 3 Z ' • &. ,1, 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No ID G -12RD3 • 9. Property Designation (Lease Number): 10. Field /Pool(s): Grayling Platform, Cook Inlet/ ADL17594 & ADL18730 McArthur River/ Hemlock . 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD (ft): Effective Depth ND (ft): Plugs (measured): Junk (measured): 14,070 • 9,994 • 13,297 9,583 13,645' +/- 13,700 Gun Assy. Casing Length Size MD TVD Burst Collapse Structural 369' 26" 369' 368' Conductor 602' 17 -3/4" 602' 601' Surface 6,031' 13 -3/8" 6,031' 4,359' 3,090psi 1,540psi Intermediate 6,941' 9 -5/8" 8,276' 6,940' 5,750psi 3,090psi Production 14,060' 7" 14,060' 9,988' 8,160psi 7,020psi Liner Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3 -1/2" 9.3#/ L -80 12,516 Packers and SSSV Type: Packers and SSSV MD (ft) and ND (ft): BOT ZF -1 Perm. Packer and Baket TE -5 TRSSSV 12,480(MD)/ 9,042(TVD) and 416(MD)/ 416(TVD) 12. Attachments: Description Summary of Proposal iral 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development ❑ Service El • 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 4/10/2012 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: N/A WINJ j0 • GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Mike Dunn Phone 777 -8382 Printed Name Keith iott Title Asset Team Lead c )/ _ Signature / ( e , --a Phone 777 -8300 Date 4/5/2012 jjj COMMISSION USE ONLY �j Conditions of approval: Notify Commission so that a representative may witness Sundry Number: v 2 % \q- q Plug Integrity s ❑ BOP Test ❑ Mechanical Integrity Test g Location Clearance ❑ !!l- Other: X t> -' m4 errL�``-�_ t+.. a � c, c r-i) L`, ,4i '> > e-ott•-•-•-- cfr,t-e- .1...--6 CA-urtc.-44--"-- Cert-,--4-1-...a.„~„e-4._, �,Qli r ,.) h -. 1(7 pr4.`z , e k r rr 4 L i t --� ,rte 00 .44c_25. Li -C11) Subsequent Form Required: / , LJ APPROVED BY Approved by: Or / C� MMISSIONER THE COMMISSION Date: ' �� •,� i ssf 41166 a�<<�- eePp (� , - F orm 10-403 Revised 1/2010 O R I G I N A„r s SUB irT Du. (.`� , d t .4. Chevron • • Trading Bay Unit %.1 Grayling Platform Well # G -12RD3 Originally Drilled 1968 API# 50- 733 - 20116 -03 As Completed 6/02 CASING AND TUBING DETAIL RKB to TBG Head = 40.73' Hole Cmt Tree connection: SIZE WT GRADE CONN ID TOP BTM. Size TOC Rotating Hrs IT 26" /" WT Surf 369' Driven NA 9.5 hrs 1 c 775sx 17 -3/4" 0.312" WT Weld Surf 602' 22" Surf 116 hrs .. i . "oS 0,, 13 -3/8" 61# K -55 Butt 12.515" Surf 6,013' 17" 2,215sx 669 hrs y 4 Surf 9 -5/8" 47# P -110 Seal Lock 8.681" Surf 73' 9 -5/8" 40# N -80 Seal Lock 8.835" 73' 6252' 1000 sx i 9 -5/8" 43.5# N -80 Seal Lock 8.755" 6252' 6939' 4565' est " DV Collar 6939' 6941' ..M 12 -1/4" 932 hrs _'. :: 9 -5/8" 1 43.5# 1 N -80 . 1 Seal Lock 1 8.755" 6941' 8276' ,, ■11.1 Redrill #3 2002 Window cut in 9-5/8", 43.5 #, N -80 8276' 8310' 1000 sx , Redrill 61 1978 Window cut in 9 -5/8 ", 476, N -80 10,257' 10,313' 11,027' est tip} • ` ►t Redrill #1 1970 Window cut in 9 -5/8 ", 47 #, P -110 12,420' 12,478' at 11 6,013' ' 7" 29 N -80 Butt 6.184" Surface 14,060' 7945'sx 0 hrs a Tubing: 3 -1/2" 1 9.3 1 L -80 1 BTC -Imp I 2.992 1 Surface 1 12,516' JEWELRY DETAIL NO. Depth Length OD ID Item 40.73' 0.60' Cameron 11" x 3 - %" DCB w/ 3 -'2' 8rd top x Butt Btm Tbg Hngr TOW@8,276' 1. 416' 5.22' 5.400 2.810 Baker TE -5 TRSSSV EMW =11.18 ppg; +' . IJIL GLM #1. 3276' 8.91' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve/RK Latch ". GLM #2. 5103' 8.91' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve/RK Latch ' GLM #3. 6100' 8.91' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve /RK Latch GLM #4. 6909' 8.93' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve/RK Latch 1. = b t GLM #5. 7599' 8.92' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve /RK Latch GLM #6. 8223' 8.90' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve /RK Latch - '.x GLM #7. 8781' 8.93' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve /RK Latch , GLM #8. 9308' 8.94' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve /RK Latch ,. i ;( GLM #9. 9834' 8.94' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve/RK Latch k. GLM #10. 10416' 8.92' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve/RK Latch I *, GLM #11. 10975' 8.92' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve/RK Latch ,A,:, GLM #12. 11505' 8.92' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve/RK Latch I i GLM #13. 11969' 8.93' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Valve/RK Latch GLM #14. 12427' 8.91' 5.968 2.867 3 -1/2" SFO -2 GLM; R -2 Orifice /RK Latch ' 2. 12,478' 14.50' 4.250 3.000 Locator Seal Assy, Size 80-40 w/ (2) seal units & 5' spacer tube 3. 12,480' 18.01' 5.838 4.000 7" BOT Model F -1 Perm Packer (85 -40) w/ 14.69' of SBE -El . 4. 12,503' 1.53' 3.865 2.812 Baker "X" Nipple i 2-4 /6 t = 4 : 3 5. 12,516' 0.75' 3.857 2.992 EOT (WL Re- entry) U . Integrity Issues Tvpe Remediation Date HOLE in 9 -5/8" (6972' 6987') None. Leak rate A 3.5 bpm A 4200 psi. no break down. 10/68 "A" x "B" Annuli Communicaton 10sx Gyp -Seal Top Job 3/69 s `# * "* (a4 HOLE in 9 -5/8" 6962' Cmt sqz 900sx. Tested to 2000psi, bled to 1900psi in 30 min 4/69 ' { HB -0 Milled 9 -5/8" csg w/ 8 -1/2" taper mill f/ 1563' to 2452' 11 hrs of milling. Recovered (3) pieces of csg iron. 5/87 Csg Caliper Login 9 -5/8" Pitting shallow w/ 50% to 60% of wall loss in multiple areas. 5/87 Obstruction H B - "A" x "B" Annulus Held 2500 psi. Was trying to get a break down rate. 5/87 13,297' 13 -3/8" csg stub cracked between bowl & 17 -3/4" cut off. Welded crack. Pressure test to 900 psi. 5/87 °ti Test 9 -5/8" csg Pressure test to 2250 psi for 30 min. 3/98 i° Tagged rill @ 13,604' Test 9 -5/8" csg Pressure test to 1500 psi for 15 min. 5/02 wl 2.79" GR on 3106 HB - Unable to "U- tube" gas thru GLM #1 Pumped Acid down "A" Annulus 11/04 B Fish/Plug %. U ' HB -3 NO. Depth Date Description ; A +/- 13,700 6/16/02 42' gun assy (2 -1/2" Power Jet gun (30')) and approx. 300' of E -line wire. , A s B 13,645' 6/29/02 Posi -Set plug at 13670' w/ 25' of cement dumped on top. PERFORATION DATA " - Accum 14,060' - ,* ' - Zone Interval (MD) Interval (TVD) FT SPF Status PBTD = 13,960' TD = 14,070' HB -0 13,227' 13,270' 9,545' - 9,569' 40' 12 Open MAX HOLE ANGLE = 60.5° @ 2600' HB -1 13,315' 13,377' 9,594' 9,627' 62' 12 Open S HB -2 13,410' 13,441' 9,644' 9,660' 31' 12 Open 13,455' 13,515' 9,668' 9,699' 60' 12 Open HB -3 13,699' 13,729' ` 30' 6 J Isolated 13,900' 13,930' 30' a 6 Isolated I' REVISED: 4/5/2012 BY: TDF • • Swanson River Field G -12RD3 4/5/2012 Hilcorp Alaska, LLC OBJECTIVE: • Convert from producer to water injection well. • Current BHP: 2,851 psi @ 9,627' TVD Max Downhole Pressure: 2,851 psi @ 9,627' TVD (Based on downhole 2009 Shut In survey) MASP: 1,887 psi (Based on a pressure gradient of 0.1 psi per foot of true vertical depth) PROCEDURE SUMMARY: 1 RU slickline and pressure test lubricator to 250psi low/ 2,500 high 2 RIH and change out all live GLM valves to dummy valves. 3 RD slickline and turn well over to production. 4 Production to install flow meter post down -hole procedure. /11,1<e Q,A,, LA/e/f brit Con % , , ; 'd COP G✓ s CV(reviI74 l ftod Q7 Z Ilan q 97 14/a . Vie wet/ r y �fo The A 1 4 i►vrst 6,'l (oc� t o o water ,1/) j E�C42e $ ,/ / j /Nf cd e fecove y iron, Pf/f , 7 g C t%S f i+ rI n e . e k' oes � � �:, .7.6) c , A4)12- 4..„(2 ,-;‘, 1/4i (_ - ,L __ 11s 3 isD !�( Bee_s i s ca / 1? d s'� wC u 7Z Cn /.3 76,f- a Z oo eZ W 11 Identifier a p` � t 3, Z..Z7 "^o REVISED BY: Initials MM- DD -YYYY • . zoi_05-< A-0 - : 2 ::: : : qii I IFIV.,4fill* G s � il y EK o - • .. 7 f -03' /oil;', c -21 RD ►. .;�� , , � . t I �� % , G -06 r . 11�� y� k 21 3a;:.. G -1 O Ay ; 51 �� ,4 -0 ' k p X . 5 it 11 -0 tt ' 1 Ni � � 7.1',050 � t3, ■ -14ARD , •a+ r iii �i..� ;Rp. ,05'�,q . (. ' 33 • 1 5 i 08;N -- 0 ! ,.� 34 '" 11,276 • c 1 I V 0-30 .,,, 1 $ pp , 38/ D' 1 ) n c/::1 ' D3 • 3 7,48: • -02 14,o r u -36■ -. 13 ,21 D-- i3 , : �i -12RD � �'r T9N 1 — r T9 22 r 13,7 a8 ,i G 12 D p 1f l: i�$ -01 T8N - . PpD -29- ) D -32 • 1 ,az5 D -02RD 3• D-41 r ' D- 001 r 12,56.7.4-D- fi 2 Page 1 of 4 • Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, April 24, 2012 2:24 PM To: 'Larry Greenstein' Subject: RE: G -12RD3 Conv to Inj (PTD 202 -055) Larry, After some more thought I tend to agree too... lots of gunk on casing by now after all these years and the CBL would most likely be suspect. A base temperature followed by another one after injection commences would be adequate. The cementing information tends to lean toward plenty of cement bond in the 7" x OH annulus. The TOC should be well above our injection zone. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Larry Greenstein [mailto:Igreenstein @hilcorp.com] Sent: Tuesday, April 24, 2012 11:06 AM To: Schwartz, Guy L (DOA) Subject: RE: G -12RD3 Conv to Inj (PTD 202 -055) Guy, Do you think a CBL could be successfully run after 10 years of production ?? Mechanically, the run could be made, but a CBL requires maintaining good contact with the casing to get interpretable results. That's why they are normally run right after the cement job while the casing is new, clean and without any other tubulars in the well. Any sand, paraffin, scale, etc would ruin any hope of getting a high quality log. An prove option to rove zonal isolation would be to use the cementing reports we do have on this well as a P starting point and, after a successful MIT, run a baseline temp survey. y With your permission, p lace the well on injection for 3 -4 weeks to create a stable temp profile and then run a follow -up temp survey. By overlaying these two surveys, you would know where the fluid is entering the reservoir (the Hemlock in this well) and whether it is moving uphole or not. Don't know what else is out there to prove zonal isolation. A WFL would do this too, but we had problems with WFL interpretations in the Inlet and prefer temp surveys to confirm fluid containment. We're just talking here, Guy, but I'm frustrated that a CBL wasn't run on this well and am trying to find a workaround that will make you comfortable with us using this well for injection. Are we really stuck if we don't have or can't get a CBL ?? Larry x Right -clicl here to j From: Schwartz, Guy L (DOA) [ mailto:guy.schwartz@alaska.gov] Sent: Monday, April 23, 2012 2:46 PM To: Larry Greenstein 4/24/2012 . . Page 2 of 4 Subject: RE: G -12RD3 Cement Reports 6 -9 -02 for AOR Larry, I looked at the well sketch and there isn't any reason that thru tubing CBL couldn't be run to verify cement quality. The top perforations are at 13227' and the tubing tail is at 12516' md. so a log from those intervals would verify zonal isolation. Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) x Right -clicl here to From: Larry Greenstein [ mailto:Igreenstein ©hilcorp.com] Sent: Monday, April 23, 2012 10:38 AM To: Schwartz, Guy L (DOA) Subject: G -12RD3 Cement Reports 6 -9 -02 for AOR Hi Guy, Found 4 different reports on the cementing done on G -12RD3 - the 407 summary, the Unocal daily, the Nabors daily, and the MI summary. Since we don't have any CBL or CET logs, these are the best we can do. Let me know if these provide enough info, in addition to the 1/4 mile radius spider map, to complete the AOR. Thanks Larry « File: G - 12RD3 Cement Reports 6 9 02.pdf » From: Larry Greenstein Sent: Tuesday, April 17, 2012 3:10 PM To: 'Schwartz, Guy L (DOA)' Subject: RE: G -12RD3 Cony to Inj (PTD 202 -055) Appreciate it, Guy. I'll get something from our well files and scan it for you to review. Hopefully we have a good quality log to work with. Larry G -12RD3 : Permit to Drill Approved — 4/4/2002 Completion Date — 6/16/2002 API# — 50- 733 - 20116 -03 PTD# - 202 -055 4/24/2012 Page 3 of 4 • From: Schwartz, Guy L (DOA) [ mailto :guy.schwartz(aalaska.gov] Sent: Tuesday, April 17, 2012 1:57 PM To: Larry Greenstein Subject: RE: G -12RD3 Conv to Inj (PTD 202 -055) Mike, A CBL showing a couple hundred feet of bond above the perfs would be what is needed. Don't need the whole log. Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) x Right -clicl here to L From: Larry Greenstein [ mailto: Igreenstein©hilcorp.com] Sent: Tuesday, April 17, 2012 10:20 AM To: Schwartz, Guy L (DOA) Subject: FW: G -12RD3 Conv to Inj (PTD 202 -055) Hi Guy, Mike asked me to get back with you about this well's conversion to injection. Thanks for the tip sheet to explain more of what you need to review the request for conversion. I've attached a spider map with a 1 /4 mile radius circle centered on the Hemlock perfs for G- 12RD3. Because this is a Hemlock only flank well, there doesn't appear to be any other wellbores within the immediate vicinity. As for the cement evaluation, would an image of the CBL above, across, and below the Hemlock perfs work ?? Assuming the CBL looks good, this would indicate the injection fluids would stay in the zone and have no other nearby wellbores to impact. Let me know if this is the right approach. These AORs were always prepared by the production engineers (as your tip sheet states) in the past, but somehow I got involved. Thanks. Larry « File: G 12RD3.png » From: Schwartz, Guy L (DOA) [ mailto :guy.schwartz(a�alaska.gov] Sent: Wednesday, April 11, 2012 1:15 PM To: Michael Dunn Subject: G -12RD3 Conv to Inj (PTD 202 -055) Mike I need a bit more info to approve the sundry to convert the well to injection. An AOR is required which involoves cement evaluation of this well and offset wells within 1 /4 mile. Here is a guidance document... gives some guidance to what is required. A spider map of all wells is required 4/24/2012 . • • Page 4 of 4 showing the wells in the area per 20 AAC 25.402 (c) (1 -15) and report on mech condition of affected % mile wells. There are some other requirements but basically just prove that the fluids will stay inzone and will not migrate out of the intended zones. Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) « File: 2007 -tips from the state.doc » 4/24/2012 • • Grayling Well G- 121�.. >3 End of the Well Summary 5/28/02 Directionally drill from.12,433' to 12,937' with a 9.4 ppg oil base mud. 5/29/02 Directionally drill from 12,937' to 13,173' with a 9.4 ppg oil base mud. Take a influx and shut well in. Circulate out kick with a maximum of 92 gas units. Continue with well control circulations bringing mud up to 9.7 ppg. 5/30/02 Continue to circulate Kill Weight Mud on choke. Bring mud weight up to 10.7 ppg. Perform a FIT to a 12.47 ppg EMW. Very little gas units seems we have a high pressure water flow from a pressurized water injection sand. 5/31/02 Ream bottom of hole from 13,055' to 13,173' with a total of 471 units of gas at bottoms up. Directionally drill from 13,173' to 13,433' with a 10.7 ppg oil base mud. 6/01/02 Directionally drill from 13,433' to 13,501' with a 10.8 ppg oil base mud. Circulate hole clean and POOH. Change out Bit and BHA. Set test plug and test BOP to 4,000 psi high/ 250 psi low and the annular to 3,500 psi high/ 250 psi low. M/U LWD tool. 6/02/02 RIH with BHA. Ream to bottom at 13,501'. Directionally drill from 13,501' to 13,547' with a 10.8 ppg oil base mud. 6/03/02 Directionally drill from 13,547' to 13,834' with a 10.8 ppg oil base mud. 6/04/02 Directionally drill from 13,834' to 14,020' with a 10.8 ppg oil base mud. Perform LWD logging run passes from 13,300' to 13,640'. 6/05/02 Continue with LWD logging runs. Ream to bottom and directionally drill from 14,020' to 14,070' (Well TD) with a 10.7 ppg oil base mud. Circulate to clean hole and condition mud. 6/06/02 Continue to condition hole. POOH with BHA. 6/07/02 Finish out of hole and R/U to run 7" casing. Run 7 ", L -80, 29# Buttress casing to 6,500' 6/08/02 Continue running 7 ", L -80 29# Buttress casing to 14,060'. Land casing hanger and establish circulation. Mix and pump 75 bbls 12.1 ppg mud spacer. t Drop bottom plug and then mix and pump 189 bbls of 15.8 ppg cement followed by a top plug. Dirplace top plug with water and bump plug with 4500 psi and hold for 15 minutes. Run casing annulus packoff and test same to 5,000 psi. P/U Baker ! FB -1 packer c/w seal extension. RIH and set with E -line at 12,480'. Change out rams from 7" to 3-1/2". 6/10/02 Test rams to 4,000 psi high/ 250 psi low and the annular to 3,500 psi high/ 250 psi low. R/U to run 3 -1/2" tubing. RIH with 3 -1/2" tubing. M/U sub surface safety valve and continue in hole. -2- • Daily Operations Report • . Date: June', 2002 ALA.9KA Well Name: Grayling G -12RD3 -drill UNOCAL476 Report #: 28 Platform: Grayling Field: TBU Rig: Unocal #54 DrIg Contractor: Nabors Project Objective: Redrill well for Hemlock Production AFE #: 153509 Spud Date: Present Depth: 14,070 ft RKB Height (ft): 40.73 AFE Cost: $ 2,233,012_ Project: 27 days 6.0 hrs Drilling Hours: 0.00 hrs Last BOP Test: 6/1/2002 Daily Cost: $ 169,827 F /Spud: 0 days 6.0 hrs Footage Drilled: - ft Pressure (High): 4,000 Previous Cum: Current Hole Size: 8 1/2" inches Average ROP: ftlhr Pressure (Low): 250 Cumulative Cst: HES Comments: None Days Without Accident: 28.5 Date: 1 Spills: 0 1 Spills to date: 0 1 AM Drill: 1 PM Drill: None Safety MTGS.: (2) PTSM: (2) PJSM. Pre iob on cementing Present Operation: Casing Shoeffubing Information Slow Pump Rates: Running 3 -1/2" production tubing Size LB/ft MD TVD LOT/PPG Pump: #1 #2 Total POB: 1 Drilling 1: Doug Nienhaus 17.75 0.31 602 602 SPM 15 15 76 DRLG: 2 Catering: 4 Foreman 2: Troy Whittington 13.375 61 6,013 4,336 Surf Sq Press: 780 780 Prod: 8 Welders: 4 Pusher R. Brumley / Lunda 9.625 40 8.276 5.988 11.18 Liner: 6 -1/2" 6 -1/2" Rig Cont: 23 Other: 14 7.0 Strk: 16 16 Boats: 2 Helicopters: 2 3.5 Depth 13.927 13.927 L-U-P From To HRS Operations Detail P 0 :00 1:00 1:00 Condition mud & circulate, fill ISO Tanks and finish mud push & mix chem wash in pill pit_ — — P 1:00 7:00 6:00 Pump cement job per plan.Test line to 5000 psi, drop bottom plug. Pump 45 bbl of 10 ppg chem wash, then _ .ump 70 bbl 12.5 ppg MudPush & 189 bbl 15.8 ppg cmt. Shut down & by pass cmt head and wash up cmt line. Dro • t• • • Iug and displace cement with FIW. Had to switch over to SLB to continue displacement 1111111111111Pleti - due to • ump effiency pumping FIW out of pill pit . Maintained 74% returns through job and reciprocated - -- — , _ casing until 30 +- bbl of cmt was on back side. Up weight was 340 kip started having to pull 450 kip. Continued — ^` displacing cementwhilelanding_hanger. - P 7:00 8:00 1:00 Bump blug 2600 psi (D 2 bbl per min & pressure up to 4500 psi & held 15 min. Built to 4600 psi. Bled off pressure — and floats held. Starting mud tank strap before job was 115 bbl. Tank strap after plug was bumped was 822 bbls. Lost 117 bbls through out cement job. h b k - P 8:00 9:30 1:30 RID cement lines and cmt head. Back out and UD landing jt. R/D elevators and swap out bails. - P _ 9:30 12:00 2:30 P/U 3-1/2" HWDP and Packoff w/ running tool. RIH w/ packoff and seat same. Run in lockdown pins. Fill w/ packing _ and test packoff to 5000 psi. U 12:00 14:00 2:00 Attempt to pull pack -off running , landing joint backed off at running tool, make attempts to recover same. ^T • 14:00 15:00 1:00 Pull • ack -off and break out running tool. RIH w/ pack -off and seat. Test pack -off to 5000 p i. P 15:00 16:30 1:30 Pull pack -off running tool and UD same. UD 3 -1/2" HWDP and break down 7" landing jt on deck. Schlumberger wire line, on platform & hands ready to rig up. At 0300 hrs.) - P 16:30 18:30 2:00 R/U SWS wireline egpt. P 18:30 20:00 1 :30 RIH w/ Baker FB -1 packer and seal extension _ — P 20:00 21:00 1:00 Make tie in passes and tie in to GR off of drill pipe measurements. Set packer ©12,480' Log up_ P 21:00 23:00 2:00 POOH, & Rig down Schlumberger. — — P 23:00 0:00 1:00 Change out rams in stack from 7" to 3 -1/2 ". Shaker screens: #1, 210/150/150 #2, 210/210/150 MR Grayling 0 -12R03 Redrii 06 -09 -02 Page 1 002 Revhed.7 @4199 by MWD ' LEASE WELL NO. API WELL NUMBER I WATER DEPTH DATE GRAYLING PLATFORM- G -12RD3 A0020 -06 50- 733 - 20374 -01 65.00 6/9/02 FIELD DISTRICT COUNTY STATE COUNTRY REEL NO GRAYLING PLATFOR - NABORS ALASK KENAI BOROUGH - ALASKA _ USA WIRE LINE RECORD SIZE MAKE WEIGHT GRADE NO. JOINTS LENGTH RKB TO CSG HD SET AT SIZE NO. LINES LENGTH SUPPED 1.375 10.00 LAST 7.000 29.00 L -80 '321 14,976.00 40.73 14,017.00 LENGTH CUT OFF PRESENT LENGTH CASING . TUBING WEAR OR TRIPS 1.642.00 OR LINER SINCE LAST CUT CUMULATIVE 66,571.06 WEAR OR TRIPS NIGHT TOUR DEPTH INTERVAL PUMP 1 PUMP 1 PUMP 2 PUMP2 METHOD RUN DRILL..D CORE FORMATION ROTARY WT. ON PUMP TOTAL SINGLE..S FROM TO REAM..R NO. (SHOW CORE RECOVERY) TABLE BIT (IN PRESSURE LINER S.P.M. LINER S.P.M. PUMP PARALLEL..P CORE..0 SPEED THOU) SIZE SIZE OUTPUT COMPOUNDED..0 6,50 30.00 6.50 30.00 463 DEVIATION DEPTH DEV 1 DIR ' TVD I HORZ DISP 1 DEPTH DEV DIR. TVD HORZ DISP. DEPTH DEV DIR. TVD HORZ DISP RECORD ■ 1 I ELAPSED CODE FROM TO TIME NO. DETAILS OF OPERATIONS IN SEQUENCE AND REMARKS 00:00 01:00 1.00 5 CONDITION MUD & CIRCULATE- -FILL ISO TANKS -MIX MUD PUSH 01:00 08:00 7.00 12 5 BBLS WATER -TEST LINES TO 5000 -45 BBL 10 PPG CHEM WASH -DROP ' :. PLUG -45 BBLS 12.5 MUDFLUSH -189 BBLS 15.8 CMT -CLEAN LINES -DIS- PLACE W/ RIG PUMPS -LND HANGER -BUMP PLUG WITH 640 BBLS -TEST CSG / TO 4650 PSI FOR 1/4 HR- 08:00 09:30 1.50 12 BRK & L/D CMT LINES, CMT HEAD -BACK OUT AND UD LND JT -L/D ELEVATORS -SWAP OUT BAILS - 09:30 10:30 1.00 21 P/U 3 1/2 DP -PACK OFF RUNNING TOOL -PACK OFF - LANDING JT -RIH 10:30 12:00 1.50 21 CHECK PACK OFF FOR SEAT -RUN IN LOCKDOWNS-ALL W/ PACKING - TEST TO 5000 PSI- DAY TOUR PUMP 1 PUMP 1 PUMP 2 PUMP2 METHOD RUN DEPTH INTERVAL DRIL .D C ORE FORMATION ROTARY WT. ON PUMP TOTAL SINGLE..S FROM TO REAM..R NO. (SHOW CORE RECOVERY) TABLE BIT (IN PRESSURE LINER S.P.M. LINER S.P.M. PUMP PARALLEL..P CORE .0 SPEED THOU) SIZE SIZE OUTPUT COMPOUNOED..0 3100 6.50 30.00 6.50 30.00 DEVIAT DEPTH 1 DEV I DIR. TVD HORZDISP DEPTH DEV DIR. TVD HORZDISP. DEPTH DEV DIR. TVD HORZDISP RECORD ELAPSED CODE FROM TO TIME NO. DETAILS OF OPERATIONS IN SEQUENCE AND REMARKS 12:00 14:00 2.00 21 ATEMPT TO PULL PACK OFF RUNING TOOL 14:00 15:00 1.00 8.Z UNABLE TO PULL PACK OFF RUNING TOOL,PULL PACK OFF BREAK RUNING TOOL, RERUN PACK OFF 1 5.00 15:45 0.75 21 PULL PACK OFF RUNING TOOL,L/D TOOLS AND DP 1 5:45 16:30 0.75 22 BREAK DOWN 7" LANDING JOINT 16:30 18:30 2.00 11 R/U WIRE LINE 18 :30 22:00 3.50 11 RIH W/ WIRE LINE W/ BAKER FB-1 PERMANENT PACKER PACKER SAT @ 12480' 1 • • w , Operator : UNOCAL Field /Area : COOK INLET Daily Well Name : G12RD3 Description : OFFSHORE Discussion Contractor : NABORS Location : GRAYLING PLATFOR M -I Well : 021223034 6/9/2002 TD = 14071 ft j Day 32 Cont circ while completing mixing of cmt spacer. R/U & cmt 7" csg (5 bbls FIW, 45 bbls 10.0 ppg Chem Wash, 70 bbls 12.5 ppg Mud Push, & 189 bbls 15.8 ppg cmt). Displaced w6 /FIW using rig pumps, 520 bbls calc t/bump plug -640 pumped by stokes.Test csg t/4650 psi. R/D cmt equip. Run pack -off tool. R/U & run Baker FB -1 permanent pkr on wireline & set @ 12480'. R/D wireline. CIO rams t/3.5 ". 12 bbls shown as dumped from cmt spacers mixed. Finsished loading 2nd ISO w/68 bbls of 10.1 OBM, 136 bbls total loaded out t/date. 782 bbls 11.2 ppg OBM left including the 60 bbls in sand trap. 948 bbl pumped during cmt operations w/707 bbls returned, 75.6% returns. Cont mixing cmt spacers. Cmt 7" csg. Run Baker FB -1 permanent packer on wireline & set @ 12480'. C/O rams. 6/10/2002 L TD = 14071 ft 33 Cont C/O rams & test BOP's. R/U & run 3.5" production tbg. 4 sacks CaC1 used for Chem Wash spacer and not charged off. Centrifuging OBM f/11.25 ppg down to 10.35 ppg in preparation for next well. 40 bbls FIW sent t/production displaced f /well bore by 3.5" tbg. Cont C/O rams & test BOP's. R/U & run 3.5" production tbg. 6/11/2002 TD = 14071 ft Day 34 Finish picking up 3.5" tubing, hanger, pump 2% crw 132 around, sting in and land tubing, nipple down, tree up. Centrifuge 10.6 ppg OBM in active back to 10.0 ppg. As of midnight 210 bbls have been processed thru centrifuge. Cont P/U 3.5" tbg. Disp well ticlean FIW w /2% CRW0132 inhibitor. sting in and land tubing, nipple down, tree up. 6/12/2002 TD = 14071 ft I Day 35 Test tree, lay down drill pipe. Prepare to rig down top drive. Continue to strip 10.6 OBM to 10 ppg. Required to increase centrifuge speed from 2500 to 3250 rpms to maintain a 10.0 ppg cut while processing thicker & heavier mud in pits 1, 2 & 3. At report time there is aprox, 100 bbls of mud remaining in pits to be processed. 7 SARAH PALIN, GOVERNOR ALASSA OII. A1~TD GA5 333 W. 7th AVENUE, SUITE 100 CO1~T5ER~PA'1'IO1~T CO1~IIrII551O1~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)276-7542 October 14, 2008 Mr. Chris Myers Field Superintendent Unocal PO Box 196247 Anchorage, Alaska 99519 RE: No-Flow Verification Trading Bay Unit G-12RD3, PTD 202-055 Dear Mr. Myers: F 6 ~:: ~{ ~~ b ~~ w y~; Lr r4.. 6 U ~~ On September 25, 2008 an AOGCC Petroleum Inspector witnessed a "no flow test" at Unocal's Grayling platform, Trading Bay Unit Well G-12RD3. The well was opened to atmosphere through flow measurement equipment with suitable range and accuracy and monitored. During the 3 hour monitoring period, unassisted flow of gas and liquid did not exceed the allowable flow rates (900 standard cubic feet per hour gas and 6.3 gallons per hour liquid). No liquid was produced to surface during the test. The subsurface safety valve may be removed from service in Well G-12RD3 based on this no-flow test result. Fail-safe automatic surface safety valve systems capable of preventing uncontrolled flow must be maintained in proper working condition in this well as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if the well demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a subsequent no flow test. Please retain a copy of this letter on the Grayling platform. Sincerely, ~- ~~ %~~~he James B. Regg Petroleum Inspection Supervisor cc: Bob Fleckenstein ;7 MEMORANDUM TO: Jim Regg ~ P.I. Supervisor ~~~~~ ~C~~I ~~ FROM: Jeff Jones Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: September 25, 2008 SUBJECT: No-Flow Test Unocal /Grayling PLT Well G-12RD3 PTD-2020550 MRF /Trading Bay Unit September 25, 2008: I traveled to Unocal's TBU Grayling Platform in Cook Inlet to witness a No-Flow Test on oil producing well G- 12RD3. Chevron Operator Chad Ebenezer performed the test today in a safe and proficient manner. Prior to the test we inspected the well and verified an open flow path from the well bore and discussed the test procedure. Well G-12RD3 was lined up from the tree top swab valve through an Armor-Flow model # 3461-03T0 flow meter (180 SCFH to 1800 SCFH span) and a 3/4" hose terminating in / an open top container. Flow from the well was monitored for 3 hours with readings recorded every 30 minutes (see below). Unassisted gas flow from the well was below the measurable range of the flow meter and no liquid was produced during the test. Well G-12RD3 meets the AOGCC requirements for a No-Flow determination. Summary: I traveled to Unocal's TBU Grayling Platform in Cook Inlet and witnessed a successful No-Flow test on oil well G-12RD3. ~ Attachments: none CC: Chris Meyers, John Liebenthal (Chevron) - -- - Well No-Flow Test Data _ Operator: Unocal Operator Rep: Chad Ebenezer AOGCC Rep: Jeff Jones Field/Unit/Pad MRF /TBU /Grayling PLT We11:G-12RD3 - - Tiuze~ --- ---- ~ > ~~11 Flow i - C0311ttIPiLfS -- - - - Gas _-- Li uid 10:00 <180 SCFH None Start Test 10:30 <180 SCFH None 11:00 <180 SCFH None 11:30 <180 SCFH None 12:00 <180 SCFH None 12:30 <180 SCFH None 13:00 <180 SCFH None End Test Produced to open top container through Armor-Flow meter model #3461-03T0 Tota] liquid produced: None '~ ~~~~~ ~y ~'~t ~ ~ 20u~ JBJ 02 Page 1 of 1 NO-FLOW Grayling PLT G-12RD3 9-25-08 JJ.xls STATE OF ALASKA ALA OIL AND GAS CONSERVATION COM ION ~` REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Repair Well Plug Perforations Stimulate Other Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver ^ Time Extension ^ Change Approved Program ^ Operat. Shutdown ^ Perforate Q Re-enter Suspended Well ^ 2. Operator Union Oil Company of California 4. Current Well Class: 5. Permit to Drill Number: Name: Development Q Exploratory ^ 202-055 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic^ Service^ 6. API Number: 50-733-20116-03 ' 7. KB Elevation (ft): 9. Well Name and Number: RKB to tbg head 40.73' G-12RD3 8. Property Designation: 10. Field/Pool(s): Grayling Platform, Cook Inlet/ ADL 17594 Jar ~ fj'7 ~ ~./. /C• °° McArthur River Field/Hemlock 11. Present Well Condition Summary: Total Depth measured 14,070 feet Plugs (measured) 13,645' posi set plug true vertical 9,994 feet Junk (measured) +/- 13,700' 42' gun assy Effective Depth measured 13,297' feet true vertical 9,583' feet Casing Length Size MD ND Burst Collapse Structural 369' 26' 369' 368' Conductor 602' 17-3/4" 602' 601' Surface 6,031' 13-3/8" 6,031' 4,358' 3090 psi 1540 psi Intermediate 6,941' 9-5/8" 8,276' 6940' 5750 psi 3090 psi Production 14,060' 7" 14,060' 9,988' 8160 psi 7020 psi Liner ~~~ APR ~ ~; 2008 Perforation depth: Measured depth: See attached Schemati c True Vertical depth: See attached Schematic Tubing: (size, grade, and measured depth) 3-1/2", 9.3#, L-80 @ 12,516' Packers and SSSV (type and measured depth) Baker TE-5 TRSSSV @ 416'; 7" BOT Modei F-1 Perm Pkr @ 12,480' 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: ~ S ~- r~N~t ~ `~ jel7tl 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 19 292 51 1060 100 Subsequent to operation: 300 500 200 1200 120 14. Attachments: 15. Well Class after proposed work: Copies of Logs and Surveys Run Exploratory^ Development ~° Service [] Daily Report of Well Operations X 16. Well Status after proposed work: Oil ^~ Gas ^ WAG ^ GINJ ^ WINJ ^ WDSPL ^ 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: n/a Contact Steve Tyler 263-7649 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature~f~~ Phone 907-276-7600 Date 4/10/2008 ~ APR ~, ~ bra Orin ~a Z~08 `~~~ COBS ~~ °j~9e ~ Form 10-404 Revised 04/2004 ~~~ ~ ~ ~ ~ A I AFE 160582 ~'~~ i/%l,~/~bmit Ori nal Only Chevron • Drilled 1968 RKB to TBG Head = 40.73' rFWFi.RV nFTAir. TO W EMW • Trading Bay Unit Grayling Platform Well # G-12RD3 As Completed 6/02 nFTarr. SIZE WT GRADE CONN ID TOP BTM. Hole Size Cmt TOC Rotatin Hrs 26" %," WT Surf 369' Driven NA 9.5 hrs 17-3/4" 0.312" WT Weld Surf 602' 22" 7Surf 116 hrs 13-3/8" 61# K-55 Butt 12.515" Surf 6,013' 17" 2'3urfx 669 hrs 9-5/8" 47# P-110 Seal Lock 8.681" Surf 73' 9-5/8" 40# N-80 Seal Lock 8.835" 73' 6252' 1000 sx 9-5/8" 43.5# N-80 Seal Lock 8.755" 6252' 6939' 4565' est DV Collar 6939' 6941' 12 1/4" 932 h 9-5/8" 43.5# N-80 Seal Lock 8.755" 6941' 8276' - rs Redrill #3 2002 Window cut in 9-5/8", 43.5#, N-80 8276' 83/0' 1000 sx Redril! #1 1978 Window cut in 9-.i~B", 47#, N-80 /0,2.17' !0,313' 11,027' est Redri!( #1 1970 Window cut in 9-5/8", 47#, P-!l0 !2,420' 12,478' 7" 29 N-80 Butt 6.184" Surface 14,060' 945 sx Tubin 3-1/2" 9.3 L-80 BTC-Im 2.992 Surface 12,516' VO. De th Len th OD ID Item 40.73' 0.60' Cameron I I" x 3-''/z" DCB w/ 3-%:" 8rd to x Butt Btm Tb Hn r 1. 416' 5.22' 5.400 2.810 Baker TE-5 TRSSSV 4LM #1. 3276' 8.91' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch .LM #2. 5103' 8.91' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch ,LM #3. 6100' 8.91' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch .LM #4. 6909' 8.93' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch ;LM #5. 7599' 8.92' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch .LM #6. 8223' 8.90' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch .LM #7. 8781' 8.93' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch .LM #8. 9308' 8.94' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch ,LM #9. 9834' 8.94' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch .M #l0. 104]6' 8.92' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch .M #11. 10975' 8.92' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch .M #12. 11505' 8.92' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch ~M #13. 11969' 8.93' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch .M #14. 12427' 8.91' 5.968 2.867 3-1/2" SFO-2 GLM; R-2 Orifice/RK Latch 2. 12,478' 14.50' 4.250 3.000 Locator Seal Ass ,Size 80.40 w/ (2) seal units & 5' s acer tube 3. 12,480' 18.01' 5.838 4.000 7" BOT Model F-1 Perm Packer (85-40 w/ 14.69' of SBE 4. 12,503' L~3' 3.8GS 2.812 Baker "\" Ni le 5. 12,516' 0.75' 3.857 2.992 EOT WL Re-en inteority Iccurc Obstru 13,2 T e Remediation Date HOLE: in 9-5/8" 6972' 6987' None. Leak rate 3.5 6 m 4200 si. no break down. 10/68 "A" x "B" Annuli Communication l Osx G Sea] To Job 3/69 HOLE: in 9-5/8" 6962' Cmt s z 900sx. Tested to 2000 si, bled to 1900 si in 30 min 4/69 1lilled 9->/8" csR w/ 8-1/2" to er mill f/ 1563' to 2452' 11 hrs of millin .Recovered (3 feces of a iron. 5/87 Cs Cali er Lo in 9-5/8" Pittin shallow w/ 50% to 60% of wall loss in multi le azeas. 5/87 "A" x "B" Annulus Held 2500 si. Was in to et a break down rate. 5/87 ]3-3/8" cs stub cracked between bowl & 17-3/4" cut off. Welded crack. Pressure test to 900 si. 5/87 Test 9-5/S" cs Pressure test to 2250 si for 30 min. 3/98 Test 9-5/8" cs Pressure test to 1500 si for 15 min. 5/02 Unable to "U-tube" as thru GLM#1 Pum red Acid down "A" Annulus 11/04 Fich / Plno NO. De th Date Descri lion A +/- 13,700 6/16/02 42' n ass 2-1/2" Power Jet n 30' and a rox. 300' of &line wire. B 13,645' 6/29/02 Posi-Set ]u at 13670' w/ 25' of cement dum ed on to . PERFOR:ITION DATA S Zone Interval FT Accum SPF Status HB-0 13,227' 13,270' 43' 12 Open HB-1 13,315' 13,377' 62' 12 Open HB-2 13,410' 13,441' 31' 12 Open 13,455' 13,515' 60' 12 Open HB-3 13.699' 13.729' 30' 6 isolated 13,900' 13,930' 30' 6 Isolated API# 50-733-20116-03 rec-~n evn REVISED: 4/10/08 BY: BCA PBTD = 13,960' TD = 14,070' MAX HOLE ANGLE = 60.5° ~ 2600' Chevron ~ # Chevron -Alaska Daily Operations Summary Well Name G-12RD3 Field Name McArthur River, API/UWI 507332011603 Lease/Serial ADL0017594 Orig KB Elev (ftK6) 99.0 Water Depth (ft) Primary Job Type Perforating Primary Wellbore Affected Original Hole Jobs AFE No. ' QC Eng R 7043 EXP Daily Operations 3/11/2008 00:00 - 3/12/2008 00:00 Operations Summary Ran GR and dummy guns to 13,604' RKB (slm). 3/13/2008 00:00 - 3/14/2008 00:00 Operations Summary RIH w/2-1/2" pert gun to 10,000', Wt to high at this depth. POOH and wait on tools. 3/14/2008 00:00 - 3/15/2008 00:00 Operations Summary RIH w/.23 line with new wt indicator to 10,000'. Still to much wt, POOH. RIH w/.39" cable and 2-1/2" pert gun and pert from 13,227'-13,267'. 3/15/2008 00:00 - 3/16/2008 00:00 Operations Summary RIH w/ pert gun and set down at 13,297'. Not deep enough. POOH. Secure well. C11EV1'Ot1Cisco Castro Chevron North ~rica Exploration and Production - hnical Assistant 909 W. 9th Ave -~~ Anchorage, AK 99501 Tele: 907 263 7844 Fax: 907 263 7828 E-mail: fcbn@chevron.com DATE April 15, 2008 To: AOGCC Mahnken, Christine R 333 W. 7th Ave. Ste# 100 Anchorage, AK 99501 NOTES- 4VELL LdGTYPE SCALE LOG DATE L RUN # 6-LINE CD aS` LOGGED P DUS CEMENT BOND LOG PDS, SLIM CEMENT LqS, HAPPY MAPPING TOOL PDF, VALLEY B-13 GR/CCL 5" 29-Mar-OS 3372 - 7664 1 1 1 DLIS COMPLETION PDS, RECORD LAS TBU G-12RD3 PERFORATIONS 5" 13-Mar-08 13227 - 13267 1 1 1 DLIS ~~yFi'~'~1L4~° ~P~ 6~ ~ 2~~~ ate "~~ ~ ~~1 c~ l Please acknowledge re pt by signing and returning one copy of this transmittal o~'f=AX fo 90'7 2637828. Received By~• ` // // / I Date: -.:-, / i t e e Chevron Timothy C Brandenburg Drilling Manager Union Oil Company of California P.O. Box 196427 Anchorage, AK 99519-6247 Tel 907 263 7657 Fax 907 263 7884 Email brandenburgt@chevron.com March 16, 2006 Steve McMains AOGCC 333 W. th Avenue, Ste. 100 Anchorage, Alaska 99501 Re: Outstanding Sundries d.O~-05'5 Dear Mr. McMains, We have conducted an internal audit of regulatory filings for 2003 and 2004. As a result, several projects were found to have outstanding sundries. We have researched the work and have prepared the sundries to close out the projects left uncompleted. The list of projects includes the following: 2003 Grayling, G-12RD3, Reperforate ../ Grayling, G-24, Reperforate Monopod, A-15RD2, Perforate Steel head , M-01, Repair Casing Patch Steel head , M-05, Perforate Swanson River, SCU 32-04, Reperforate (3 Sundries) Swanson River. SRU 12-15, Recomplete Swanson River. SRU 32A-33, Reperforate ;:'~; C 2004 Happy Valley, HV-A02, Coil Tubing Clean Out In order to assure that we do not have any such gaps in the future, we have implemented a database to track all drilling related AOGCC filling requirements. Please contact me directly at 263-7657 if you have any questions about these filings. Sincerely, 7~. J ~G' Timothy C. Brandenburg Drilling Manager Attachments Cc: Well Files TB:sk Union Oil Company of California I A Chevron Company http://www.chevron.com STATE OF ALASKA a ALA.IL AND GAS CONSERVATION COMM.ON REPORT OF SUNDRY WELL OPERATIONS PO Box 196247, Anchorage, AK 99519 Plug Perforations Perforate New Pool D Perforate D 4. Current Well Class: Development 0 Stratigraphic D ExploratoryD ServiceD 1. Operations Abandon Repair Well Performed: Alter Casing D Pull Tubing D Change Approved Program D Operat. Shutdown D 2. Operator Union Oil Company of California Name: 3. Address: Stimulate Other ../ WaiverD Time ExtensionD Re-enter Suspended Well D 5. Permit to Drill Number: Reperforate 202-055 6. API Number: 50-733-20116-03 9. Well Name and Number: G-12RD3 10. Field/Pool(s): McArthur River Field/Hemlock 7. KB Elevation (ft): RKB to tbg head 40.73' 8. Property Designation: Grayling Platform, Cook Inlet 11. Present Well Condition Summary: Total Depth Effective Depth Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: measured 14,070 true vertical 9,994 feet feet Plugs (measured) 13,645' posi set plug Junk (measured) +/- 13,700' 42' gun assy measured 13,645' true vertical 9,767' feet feet Length Size 369' 26' 602' 17-3/4" 6,031' 13-3/8" 6,941' 9-5/8" 14,060' 7" MD 369' 602' 6,031' 8,276' 14,060' TVD 368' 601' 4,358' 6940' 9,988' Burst Collapse 3,090 5,750 8,160 1,540 3,090 1,720 Measured depth: 13,250 - 13,930' True Vertical depth: 1,295 - 9,917' Tubing: (size, grade, and measured depth) 3-1/2",9.3#, L-80 @ 12,516' Packers and SSSV (type and measured depth) Baker TE-5 TRSSSV @ 416'; 7" BOT Model F-1 Perm Pkr @ 12,480' 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: n/a Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure 336 5,293 100 325 5,325 110 15. Well Class after proposed work: ExploratoryD Development 0 16. Well Status after proposed work: Oil0 Gas D WAG D 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Prior to well operation: Subsequent to operation: 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations 13. Oil-Bbl 460 476 Tubing Pressure 100 110 Service D x GINJ D WINJ D WDSPL D Sundry Number or N/A if C.O. Exempt: n/a Contact Steve Tyler 263-7649 Printed Name Timothy C. Brandenburg Signature Title Drilling Manager Date S ~-l- 0 b Form 1 0-404 Re~ìsed 04/2004 AFE 1605 Submit Original Only 5/9/03 e e PJSM. MI/RU. 3-1/2", 5000 psi, 10.25 diameter tree flange too small for Schl crossovers. Surveyed other platform trees and stock--no fits available. Found Pollard flange that would work. Discussed with Schlumberger. RU Schlumberger equipment then SDFN. 5/10/03 PJSM with emphasis on using Schlumberger SAFE system, rig air tugger to hoist sheve, and other normal perforating issues. RU on tree and pressure tested to 2,4,50 psi (ok). RIH with gun #1 (30 feet) and CCL. TP at 450 psi. Tied in with GLMs and tail and put on production. Logged down to 13,610' and tied in with short joint. Did not tag bottom. Fired gun. Perforated 13,485-13,515' (30 feet). Saw wt loss on line. Logged up, flagged line at 13,100', and POOH. RIH with gun #2 (30 feet) and ecL. TP at 1,100 psi. Tied in with flag and tail and put well on production. Fired gun. Perforated 13,455-13,485' (30 feet). TP at 200 psi. Saw wt loss on line. Logged up and POOH. RIH with gun #3 (30 feet) and eCL. Tied in as before and put well on production. Fired gun. Perforated 13,411-13,441' (30 feet). TP at 200 +/-. Saw wt loss. Logged up and reflagged line at 13,100'. POOH. Put cap on BOP. Turned well over to production to test HB-2 zone that was reshot. Remade head and SDFN. 5/11/03 PJSM. Reconnected lubricator, checked fire, and armed gun. RIH with gun #4 (30 feet) and CCL. Tied in with flag and jewelry. Put well on production. Fired gun. Perforated 13,347-13,377' (30). TP at +/-120 psi. Saw wt loss. Logged up and POOH. RIH with gun #5 (30 feet) and CCL. Tied in with flag and jewelry. Put well on production. Fired gun. Perforated 13,317-13,347' (30). TP at 120+/- psi. Saw wt loss. Logged up and POOH. RIH with gun #6 (20 feet) and CCL. Tied in with flag and jewelry. Put well on production. Fired gun. Perforated 13,248-13,268' (20). TP at 120+/- psi. Saw wt loss. Logged up and POOH. RD and prep. Schlumberger equipment to leave platform. G-12RD3 Reperf, 160582 morning report summary, CONFIDENTIAL: last revised 3/1/2006, Page 1. ] x 6,013' Butt Bttm Thg Hanger l. 416' 2.8]0" Baker TE-5 TRSSSV 2. 3. ]2,480' 4.000" T' BOT Model F-] Perm Packer (85-40) ]2,503' 5. ]2,516' 2.992" EaT (WL Re-entry) 8,276' 14,060' peTD ::: 13,960' TD ::: 14,070' MAX HOLE ANGLE::: 60.5° @ 2600' 26" 17-3/4" 0.312" WT Weld SUlface 602' ]3-3/8" 61# K-55 Butt 12.515" Surface 6,013' 9-5/8" 47# P-]IO Seal Lock 8.681" Surtàce 73' 9-5/8" 40# N-80 Sea] Lock 8.835" 73' 6252' 9-5/8" 43.5# N-80 Sea] Lock 8.755" 6252' 6939' DV Collar -------------------------------------------------------------------- 6939' 6941' 9-5/8" 43.5# N-80 Seal Lock 8.755" 6,94]' 8,276' 9-5/8" DriHed Window 8,276' 8,294 ' T' 29 N-80 Butt 6.]84" Surfàce ]4,060' Tubing: 3-112" 9.3 L-80 BTC-Imp 2.992 Surfàce 12,516' 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch 3-1/2" SFO-2 GLM; R-2 ValvelRK Latch 3-1/2" SFO-2 GLM; R-2 ValvelRK Latch 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch 3-1/2" SFO-2 GLM; R-2 ValvelRK Latch 3-1/2" SFO-2 GLM; R-2 ValvelRK Latch 3-1/2" SFO-2 GLM; R-2 ValvelRK Latch 3-1/2" SFO-2 GLM; R-2 ValvelRK Latch 3-1/2" SFO-2 GLM; R-2 ValvelRK Latch 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch 3-1/2" SFO-2 GLM; R-2 Valve/RK Latch 3-1/2" SFO-2 GLM; R-2 ValvelRK Latch 3-1/2" SFO-2 GLM; R-2 Orifice/RK Latch 3276' 5103' 6100' 6909' 7599' 8223' 8781 ' 9308' 9834' 10416' 10975' 11505' 11969' 12427' 2,867" 2.867" 2.867" 2.867" 2,867" 2.867" 2.867" 2.867" 2.867" 2.867" 2.867" 2.867" 2.867" 2.867" Fish I A +1- 13,700 6/16/02 42' gun assy (2-1/2" Power Jet gun (30')) and a rox. 300' ofE-line wire. B 13,645' 6/29/02 Posi-Set plug at 13670' wI 25' of cement dumped on to . Zone Interval FT HB-O 13,250 - 13,270 20' HB-l 13,315 - 13,377 60' HB-2 13,411 - 13,441 30' 13,455 - 13,515 60' HB-3 13,699 - 13,729 30' ,900 - 13 930 30' REVISED: 3/1/06 BY: DED e e MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs _ Inserts\Microfilm _ Marker.doc -3 ) ) ~~!Æ~E = F !Æ~!Æ~~~!Æ AI/~SIiA OIL AND GAS CONSERVATION COMMISSION ~()d- - O£S FRANK H. MURKOWSK/, GOVERNOR December 10, 2004 333 W. T" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Dwight Johnson Field Superintendent Unocal PO Box 196247 Anchorage, Alaska 99519 RE: Safety Valve System Inspections :No Flow Tests Trading Bay Unit, Grayling Platform Dear Mr. Johnson: On November 23, 2004 the Alaska Oil and Gas Conservation Commission ("AOGCC") inspected Unocal's Grayling platform, Trading Bay Unit. The Commission's inspection included witnessing semi-annual safety valve system ("SVS") tests, no-flow tests on four wells, and general platform safety inspections. The platform was found to be clean, orderly, and in good condition. The SVS associated with thirteen of the platform's wells were tested. Eleven wells were not tested during the November 23 inspection - four wells were shut in for no-flow testing, two wells were not tested at the request of the platform supervisorl, and five wells were not tested due to their "long term shut in" status. Unocal must provide a schedule for completing the semi-annual testing of the six wells2 that would normally be in operation, and provide the Commission with sufficient notice when SVS testing will be conducted so these tests can be witnessed. The Grayling platform production wells utilize artificial lift gas to produce hydrocarbons. It is unclear if a catastrophic failure of a well or flowline component will automatically shutdown artificial lift gas, or if the well will flow for several hours until it depressures. Unocal is requested to provide an explanation and relevant supporting flow schematics with sufficient detail to demonstrate the emergency shutdown system and its control over the artificial lift gas. 1 TBU G-14 (PTD 168-080) and TBU G-18DPN (PTD 183-135); reason for not testing was concern about disrupting the platform's fuel gas supply 2 TBU G-12 RD3, G-14, G-18DPN, G-21, G-31, and G-33 ') ') Dwight Johnson December 9,.2004 Page 2 of2 We also note that safety valve system test results at Grayling are not routinely provided to the Commission. Unocal should begin reporting all safety valve system tests to the Commission, particularly those tests that are not witnessed by a Commission inspector. Please contact Mr. Bob Fleckenstein at 793-1242 to get the proper reporting format. No Flow Tests Wells G-12RD3, G-21, G-31, andG-33 were no-flow tested on November 23 to determine if they qualify for removal of the subsurface safety valve. Each. well was opened to atmosphere through flow measurement equipment with suitable range and accuracy and monitored for 3 hours. Gas flow rates less than 180 SCF per hour, and total liquid recovery less than 12 gallon during the 3-hour monitoring period were determined for each well tested. Based on the results of no flow tests, the subsurface safety valve may be removed from. service in Wells G-12RD3, G-21, G-31, and G-33.A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition in each well as required in 20 AAC 25.265. The subsurface safety valve must be returned to service in any well that demonstrates an ability to flow unassisted to surface. Please retain a copy of this letter on the Grayling platform. Sincerely, S~\;S~ Jmnes B. Regg ~ Petroleum Inspection Supervisor cc: Bob Fleckenstein File: TBU G-12RD3 (pTD 202-055) TBU G-21RD (pTD 198-064) TBU G-31 (PTD 169-072) TBU G-33 (PTD 170-011) ) ) MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg ~ \~\~Ofr P.I. Supervisor lí FROM: Jeff Jones Petroleum Inspector DATE: November 23,2004 SUBJECT: No-Flow Test Unocall Grayling PL T G-12 PTD 2020550 McArthur River Fieldl TBU November 23,2004: I traveled to the Grayling Platform in Cook Inlet to witness a No-Flow Test on Unocal's McArthur River Field well G-'12. Unocal representative Darrel Bruce performed the test today in a safe and proficient manner. Well G-12 was lined up from the production tubing through a 1" hose terminating in an open top drum. Gas flow from this well was such that it was below the amount measurable (180 SCFH) with the Armor-flow model 3461-03TO flow meter usually used for No-Flow Tests. This well utilizes artificial lift gas to produce hydrocarbons, which was shut in at least 12 hours previous to the test, and the well was allowed to depressure into the test separator. This artificial lift gas may not be automatically shut off in the event of a catastrophic failure of well head or flow line components. depending on the nature of the failure. In the event of such a failure, it may be necessary to block in the lift gas manually, and in any case the well may flow for several hours unassisted until it depressures. Flow from the well was monitored for 3 hours with readings recorded every 30 minutes. Unassisted gas flow from the well during the test did not exceed the maximum permissible 900 SCF hourly flow rate and no significant amount of fluid was produced. Summary: I witnessed a s~ccessful No-Flow Test on Unocal's McArthur River Field well G-12 on the Grayling Platform in Cook Inlet. Attachments: none £Ç.¡ Dwight Johnson I J.C. Watski (Unocal) Operator: Operator Rep: AOGCC Rep: Field/V nitlPad : TI'r'! .':";':'; :. , j Gas 11:45 AM <180 SCFH 12:15 PM <180 SCFH 12:45 PM <180 SCFH 1:15 PM <180 SCFH 1 :45 PM <180 SCFH 2:15 PM <180 SCFH 2:45 PM <180 SCFH J~f;1~~~W3ffiNØ!ffl~~fTø~i~~ . Unocal Date Darrell Bruce Jeff Jones I\IRFrrBll Gra~'ling PL T Well: G-12 Well FloW.-- " ":.:'.'.." ~:~,:' COnlm,entS ",;.::;:-í,.~i-:''':>;' 11/23/2004 . Liquid < 1 cup < 1 cup < 1 cup < 1 cup < 1 cup < 1 cup < 1 cup Start Test End Test Produced to open top container. Total liquid produced: < 1/2 gallon SCA.NNED DEC 2 1 2004 RJF 09/19/02 Page 1 of 1 NO-FLOW Grayling PLT G-12 11-23-04 JJ.xls I ~ J v.~~ ^~(j ,-( DATA SUBMITTAL COMPLIANCE REPORT 7/6/2004 Permit to Drill 2020550 Well Name/No. TRADING BAY UNIT G-12RD3 Operator UNION OIL CO OF CALIFORNIA '5 (l l.L-¿ i 1 /'V1 J Ä (}-(J L API No. 50-733-20116-03..00 MD 14070"-' ND 9993./ Completion Date 6/16/2002 ~ Completion Status 1-01L --~- -------- _.-.-----~~-_.__._-----~---~----._-~ ---o-..._------~_._-----~-----~- REQUIRED INFORMATION Mud Log No Samples No -- --___-__n_-..--u ---------~--------- DATA INFORMATION LWD-CDRlAND/GR Types Electric or Other Logs Run: Well Log Information: Log/ Electr Data Digital Dataset ~_n~_ed~~n~~~__~umbe~~~:tion (---------Log Uompletion Log Log Run Scale Media No 5 BM 1 5 BM 5 BM 5 BM 5 Blu C5 Blu 25 BlU e:: Blu Blu v-°g camma Ray vt6g asing collar locator ..A:Ôg Completion ~COg ~ensity og Neutron ~L09 ~eutron Log ensity Log 9amma Ray ~ See Notes Log See Notes Log See Notes Log See Notes Log See Notes Rpt See Notes ~C v1133 See Notes ~g <,£ompletion ~g \../'Completion cJ-eg t.e6ñípletion 2 Blu ~Col ; 1 Col Col Col Col 5 5 BM BM 5 BM Current Status 1-01L UIC N Directional Survey ~'~ (data taken from Logs Portion of Master Well Data Maint) Interval OH/ ~ Start Stop CH Received Comments 12300 13310 Case 7/18/2002 4'fc)duction Packer 12290 13960 Case 7/18/2002?-'2~5" HSD Gun, 6spf, 60' Phase 12290 13960 Case 7/18/2002 c-vJ.L 12290 13960 Case 7/18/2002 Gv>AJl 13200 13645 Case 7/18/2002 £..2.5" Power Jet Guns 6 ~7/18/2002 SPF, 60 Deg. Phasing C2409 14037 cD K. fV))) 12409 14037 ~ 7/18/2002 (12409 14037 ~ 7/18/2002 C t) r(l, r-t/ -» 14037 ~(7/18/2002 12409 8350 13450 ~7/18/2002 12410 14070 ~ 7/18/2002 ADN 8277 14071 Case 7/18/2002 formation log ~ 8277 14071 Case 7/18/2002 formation log 8277 14071 Case 7/18/2002 dml - mwd combo log 8277 14071 Case 7/18/2002 dml - mwd combo log 8277 14071 Case 7/18/2002 End of well report 13150 13670 Case 1 0/3/2002 ~BT, 15' Cement Plug 13100 13696 Case 10/3/2002 ~5" HSD PJ 13150 13608 Case 10/3/2002 41Ý Cement Plug 13150 13670 Case 10/3/2002 &-POSiset Plug 15' cement DATA SUBMITTAL COMPLIANCE REPORT 7/6/2004 Permit to Drill 2020550 Well Name/No. TRADING BAY UNIT G-12RD3 MD 14070 TVD 9993 -~ED~;:7~C---Pds--~0 Completion Completion Date 6/16/2002 ~ L.-..e6mpletion to C Wrd ~Ð C Pdt c.J.D-' C Las ~286 Report: Final Well R ~286 Mud Log 1 Mud Log Well Cores/Samples Information: Name Cuttings // Interval Start Stop 8280 14071 ADDITIONAL INFORMATION y~ Well Cored? Chips Received? -v-t-N-- Analysis Received? --Y.J.-N--- . _._._---~._--_._-------~-- c~~;~~~~~--~ ~. ..~~ ~_\\.~~~Q-~.~ l..-. uJ D-C \J t2... (A- D M.. (~~_.__. .~-=~---:-~====N~i ~: ('...~ \~ ~ .\ ~ + j ~ Compliance Reviewed By: 12400 13610 Case 6/23/2003 Completion Record - 2.5" HSD Powerjet 6 SPF 12400 13610 Case 6/23/2003 t-Completion Record - 2.5" HSD Powerjet 6 SPF Located in Well History file. Formation Log Formation Log Operator UNION OIL CO OF CALIFORNIA Completion Status 1-01L 25 Current Status 1-01L 25 as 2 0 0 Case 8277 14071 Case 8277 14071 Case Sent Sample Set Number Comments 1102 ~ Received Daily History Received? QyN (j/N Formation Tops ~~~ Date: API No. 50-733-20116-03-00 UIC N ~' ~~~'f .~ ) Unocal Alaska 909 W. 9th Avenue Anchorage, AK 99501 Tele: (907) 263-7651 Fax: (907) 263-7828 E-mail: harrisonb@unocal.com UNOCAL(i> Beverly Harrison Business Ventures Assistant To: AOGCC Lisa Weepie 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL - '!~,:t:~<wEiit~/~ i-:~tir~';~:1:i~.!;!.~1?: tOG:TYPE:'~,-{i!,;~~J~t:;;;,.~~.7~;i'. :'. ¡;SCALF ,:,"; DATE'."I:~ J'¡INTERVAl~:~ :'~ a:'UNE" FILM'" CD:, COMPLETION RECORD - 2.5" HSD POWER JET 2506 HMX RST SIGMA MODE RST SIGMA MODE RST SIGMA MODE COMPLETION RECORD - 2.5" HSD POWER JET 6 SPF 21/2" HSD PWER JET 2506, HMX 31/2" HALLIBURTON PLUG CEMENT MAP TEMPERATURE SURVEY - CEMENT TOP IDENTIFICATION PBMS COMPLETION REPORT - 2.5" HSD POWER JET, 6 SPF 1.56" 1606 HMX, TUBING PUNCHER COMPJETION RECORD 3.5 HALLIBURTON CAST IRON PLUG CEMENT DUMP BAILER (!!);J-/8cr A-15RD ,~1-crt I-) AN-13RD2 J,(98-COU? AN-19 J ~t-¡cq - AN-37 fjc!).--cFÞ G-12RD3 (.) 1'\ ~"CJ-\ v'GRINER-1 au:><- ~ GRINER-1 ¿p3-C514 KGSF-3 \'V'1 -)3.-3 M-5 i97 Œ'KSRU 223-28 I SRU 223-28 6/17/2003 5 INCH 5/1/2003 11750-12550 5 INCH 5/22/2003 3400-4650 5 INCH 5/22/2003 3400-4650 51NCH 5/22/2003 3100-4250 51NCH 5/10/2003 12400-13610 5 INCH 4/19/2003 250-1780 4/8/2002 2 INCH 6/4/2003 3500-7020 5 INCH 4/16/2003 3600-3900 5 INCH 5/25/2003 1580-5606 5 INCH 5/24/2003 1662-5665 'h- l\ 1 ~e\ - \ l\ l '- 0 (\ -- \ C~ -- \ C1 \ ~ L\ 2 2 2 2 1 I;l: \\.5 1 F~\\~ 1 )8 \8-\ 1 l~ J l3 {& \ålO 2 1 1 ~'I~ 0 1 IÐ U~ 1 }ô 18tÀ 2 J\Ææ,,1 /81aß 1 \J~!) 1\J& II (0 ,J\6'. \ \ ci 1 1 1 (]' 1 0 ..... Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to (907) 263-7828. (~,.t.\lr2[) Received BY~O(~.~-..Q (J't -~ö/Y'\ Date: ~~D\n~ q 11\ \ ~) r'>: :~ (~ C:?: d~.ii 1 ,,.. \,1 I....,.'" (\jlr~(lornqn .' ::~ ;;- :.;C;~'if;, '~,~~'(f;'n~r~n:.l~~O~' .,\11 ') Unocal Alaska 909 w. 9th Avenue Anchorage, AI< 99501 Te1e: (907) 263-7651 Fax: (907) 263-7828 E-mail: hanisonb@unoca1.com ) September 23, 2002 ~oa-o-55 A-29RD A-29RD A-29RD A-29RD A-29RD A-29RD A-29RD ~ A-29RD '8 A-29RD ~ A-29RD ~ A-29RD ¥"{) A-29RD A-29RD ¡ ! A-29RD I ! A-29RD I I A-29RD ! A-29RD t ¡ A-29RD ! -- ! A-29RD ;w.. ro~oo51 D-1SRD2 - ¡ D-1SRD2 I- I DI-1S 7lt> -Otl51 DI-1S . ~"OS1! DI-16 ,0\ ~DI-16 c.f) I G-12RD3 (() I G-12RD3 9 ! G-12RD3 ~ 0 CO UNOCAL Beverly Harrison Business Ventures Assistant To: AOGCC . Lisa Weepie # 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL - ADN DIP DATA V ADNDIPDATA V ADN DIP DATA V ADNDIPDATA V CEMENT BOND LOG I GR I CCL V CEMENT BOND LOG I GR I CCL v CEMENT BOND LOG I GR I CCL V- I CEMENT RETAINER CASING PUNCHER V CEMENT RETAINER CASING PUNCHER V EPOCH FINAL WELL REPORT WI FORMATION LOG ./ EPOCH FINAL WELL REPORT WI FORMATION LOG V EPOCH FINAL WELL REPORT WI FORMATION LOG ý MWD/GR MD COMPOSITE FIELD PRINT V PERFORATION DEPTH CONTROL MEMORY GR I CCL V PERFORATION DEPTH CONTROL MEMORY GR I CCL V PERFORATION RECORD 2 7/8" PJ HSD 6 SPFV PERFORATION RECORD 27/8" PJ HSD 6 SPF V SCHLUMBERGER FORMATION EVALUATION LOGS V VISION SERVICE MD COMPOSITE FIELD PRINT V PL ADVISOR I INJECTION PROFILE MEMORY PLT WIFLOVIEW v PL ADVISOR I INJECTION PROFILE MEMORY PL T W/FLOVIEW v COMPLETION RECORD 2" HSD, POWER JETS v COMPLETION RECORD 2" HSD, POWER JETS v'" COMPLETION RECORD 2" HSD, POWER JETS v COMPLETION RECORD 2" HSD, POWER JETS V COMPLETION RECORD 10' CEMENT PLUG V COMPLETION RECORD 10' CEMENT PLUG V'" COMPLETION RECORD 2.5" HSD PJ V 2/5 INCH 2/5 INCH 2/5 INCH 5 INCH 5 INCH 2 INCH 2 INCH 2 INCH 2 INCH 5 INCH 5 INCH 2 INCH 5 INCH 5 INCH 5 INCH 5 INCH 5 INCH 5 INCH 5 INCH 5 INCH 5 INCH 8/2/2002 8/2/2002 8/2/2002 8/2/2002 8/5/2002 8/5/2002 8/5/2002 6/30/2002 8/112002 8/1/2002 6/30/2002 8/10/2002 8/10/2002 8/28/2002 8/28/2002 8/2/2002 6/30/2002 3/17/2002 3/17/2002 5/11/2002 5/11/2002 5/9/2002 5/9/2002 6/29/2002 6/29/2002 6/21/2002 12606-13220 11950-12650 12606-13220 12029-12713 5000-13211 5000-13211 5000-13211 1680-1999 1680-1999 1786-13300 1824-12685 12720-13240 12720-13240 13100-13207 13100-13207 1824-13300 9150-10050 ! 9150-10050 ¡ 11950-12555 ! 11950-12555 I ; 9800-1077 ! I 9800-1077 ! 13150-13608 I 13150-13608 I ¡ 13100-13696 ! 1 B-Line 1 B-Line 1 CD 1 CD 1 B-Line 1 CD 1 Film 1 B-Line 1 Film 3 B-Line i 1 CD 11 PAPER ! 1 B-Line ! 1 B-Line ! 1 Film I I 1 B-Line 1 Film 1 CD 1 B-Line 1 , B-Line f ¥ 1 CD 1 B-Line 1 Film 1 B-Line 1 Film 1 B-Line 1 I Film ! 1 I B-Line Please acknowledge receipt by signing and returning one copy of this transmittal or ~ ~~V3-1~~'--,~ !J'-L..v!::11 ~W' Received d.-( ~ Date: OCT 0;) 2002 A t~~~£¡,r.:. -".; .:~ .~.. .:;~ - ..... RI;;¡(JI\{;¡ Vfi ú; \,jas f..,OÏ¡E;. CommiSSion AnchoragQ (2 G-12RD3 Q G-12RD3 ~ G-12RD3 ~ G-12RD3 r1 K-30RD 10~cP K-30RD LRU C-1RD LRU C-1RD D'Î \ ~ M-4 \D' M-4 NNA-1 NNA-1 \0 - ro \ NNA-1 a ~ NNA-1 PEARL -1 PEARL -1 PEARL-1 PEARL -1 ::::. PEARL-1 0 PEARl-1 I rt) PEARl-1 CJ PEARl-1 '\) PEARl-1 PEARl-1 SRU 12-15 Od-do SRU 12-15 Jf SRU 12-15 SRU 12-27 SRU 12-27 SRU 12-27 SRU 12-27 SRU 212- 27 SRU 212- 27 ~ SRU 213- 10 SRU 213- 10 SRU 213- 10 SRU 213- "00 10 - SRU 213- ~ 10 f7\ SRU 213- . \J 10 Q SRU 213- () 10 SRU 213- 10 \ ÍD J ..0'9 SRU 23-33 ~ .1\ rJl \)r/P ~.. I COMPLETION RECORD 2.5" HSD PJ V"" ¡ 5 INCH COMPLETION RECORD POSISET PLUG 15' CEMENT V I 51NCH COMPLETION RECORD POSISET PLUG 15' CEMENT ./ I 51NCH COMPLETION RECORD POSISET PLUG 15' CEMENT V ¡ 51NCH PERFORATING DEPTH CONTROL MEMORY GR / CCL ....-- 5 INCH PERFORATING DEPTH CONTROL MEMORY GR / CCL v 5 INCH COMPLETION REPORT 2" HSD POWER JETS ./ 5 INCH COMPLETION REPORT 2" HSD POWER JETS v 5 INCH EPOCH MUD LOG v 2 INCH EPOCH MUD LOG ./ 2 INCH COMPLETION RECORD 2" HSD POWER JET v 5 INCH COMPLETION RECORD 2" HSD POWER JET V' 5 INCH GR / CCL CORRELATION FLUID LEVEL DETERMINATION V' 5 INCH GR / CCL CORRELATION FLUID LEVEL DETERMINATION v' 5 INCH COMPLETION RECORD 2" PJ HSD, 6 SPF V'" 5 INCH COMPLETION RECORD 2" PJ HSD, 6 SPF ~ 5 INCH COMPLETION RECORD 2" PJ HSD, 6 SPF V 5 INCH COMPLETION RECORD 2" PJ HSD, 6 SPF V 5 INCH GR / CCL / PRESSURE / TEMPERATURE / TOP OF FLUID DETERMINATION V 5 INCH GR / CCL / PRESSURE / TEMPERATURE / TOP OF FLUID DETERMINATION v-- 5 INCH GR / CCl / TEMPERATURE / PRESSURE / TOP OF FLUID, SAMPLE ,V'"' 5 INCH GR / CCL / TEMPERATURE / PRESSURE / TOP OF FLUID, SAMPLE ~ 5 INCH GR / CCL TEMPERATURE, PRESSURE TOP OF FLUID, SAMPLE v 5 INCH GR / CCL TEMPERATURE, PRESSURE TOP OF FLUID, SAMPLE v 5 INCH COMPLETION RECORD 111/16" POWER PIVOT ./ 5 INCH COMPLETION RECORD 111/16" POWER PIVOT V' 5 INCH COMPLETION RECORD POSISET PLUG 20' CEMENT PLUG ,,/ 5 INCH CEMENT RETAINER CPST SETTING TOOL"" 5 INCH MD FIELD PRINT 0/ 2/5 INCH NEUTRON / GR / CCL ./' 2/5 INCH NEUTRON / GR / CCL V 2/5 INCH 5.5" THRU-TUBING POSISET PLUG CEMENT DUMPT BAILER 25' CEMENT PLUG'? 5 INCH 5.5" THRU-TUBING POSISET PLUG CEMENT DUMPT BAILER 25' CEMENT PLUG v51NCH 2" HSD POWER JET 6 SPF COMPLETION RECORD v ¡ I 51NCH ) I 6/21/2002 . 13100-13696 6/27/2002 13150-13670 6/27/2002 13150-13670 6/27/2002 13150-13670 2/8/2002 9544-12045 2/8/2002 9544-12045 7/15/2002 5300-5975 7/15/2002 5300-5975 10/31/1999 1473-6430 10/31/1999 1473-6430 4/3/2002 8600-9750 4/3/2002 8600-9750 4/2/2002 8600-9790 4/2/2002 8600-9790 3/29/2002 5420-6066 3/29/2002 3690-4250 3/29/2002 5420-6066 3/29/2002 3690-4250 3/28/2002 3550-6954 3/28/2002 3550-6954 3/29/2002 3550-6607 3/29/2002 3550-6607 3/29/2002 100-6948 3/29/2002 100-6948 5/16/2002 5400-5600 5/16/2002 5400-5600 3/13/2002 4600-5642 6/27/2002 5600-6346 6/29/2002 6044-6912 6/26/2002 5600-6340 6/26/2002 5600-6340 8/20/2002 6025-6050 8/20/2002 6025-6050 8/4/2002 3800-4000 7/24/2002 1987-4105 7/24/2002 1987-4105 8/1/2002 I 0-4014 8/1/2002 0-4014 7/24/2002 1987-4105 i 7/18/2002 I 1952-4105 7/18/2002 1952-4105 5/19/2002 10350-10625 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 Film B-Line CD Film B-Line Film B-Line Film B-Line Vellum B-Line Film B-Line Film B-Line B-Line Film Film B-Line Film B-Line Film B-Line Film B-Line Film B-Line B-Line B-Line B-Line CD ARRAY INDUCTION / DENSITY / CNL / GR / SP / CALIPER / PEX v SINCH B-Line CD B-Line B-Line CD B-Line CD B-Line 2 B-Line 2 B-Line 1 B-Line Please acknowledge receipt by signing and returning one copy of this transmittal or E~t? (~O7)- 2~3-!828. Rt:CE!\lEJ~) ARRAY INDUCTION / DENSITY / CNL / GR / SP / CALIPER / PEX ,,-- 5 INCH CEMENT BOND LOG / GR / CCL v i ! 51NCH CEMENT BOND LOG / GR / CCL ,51NCH I 51NCH v COMPENSATED NEUTRON LOG IN CASING v SLlMPULSE / GR / MD / FIELD PRINT ../ SLlMPULSE / GR / VD / FIELD PRINT v 111/16 ENERJET GUN COMPLETION REPORT V ¡ i I 2/5 INCH ~ ! 2/S INCH I 51NCH Received BY~l ~-----../ Date: 0 ('T f';":' nr-.t"'r; ¡ I., J ~j --:J ..:. ".; :...' ...: Aìa~ka 0;'; ~~ (f(.HTIf11k;s k;-n An chc-rng 0 ) ) Unocal Alaska 909 W. 9th Avenue Anchorage, AK 99501 Tele: (907) 263-7889 Fax: (907) 263-7828 E-mail: oudeand@unocal.com UNOCALe "',.,",.',".,"",.,'. '^- -,'1 '~',":~ ;~~~:.,"~ t~"~~~ . ~ :: Debra A. Oudean Technologist September 12, 2002 DATA TRANSMITTAL To: Bren Mciver Alaska Oil & Gas 333 W 7th Ave, #100 Anchorage,AK99501-3539 From: Debra A. Oudean Unocal Alaska 909 W. 9th Avenue Anchorage, AK 99501 Transmitting data as follo'NS: Transmitting the following: Final Well Data CD Trading Bay Field A-15RD A-15RD ST1, A-15RD ST1 L 1 A-15RD ST L 1 A CD Trading Bay Unit G-12RD 3 Unocal Alaska 909 W. 9th Avenue Anchorage, AK 99501 Tele: (907) 263-7889 Fax: (907) 263-7828 E-mail: oudeand@unocal.com ) UNOCAL8 Debra A. Oudean Technologist September 12, 2002 DATA TRANSMITTAL To: Bren Mciver Alaska Oil & Gas 333 W 7th Ave, #100 Anchorage,AK99501-3539 From: Debra A. Oudean Unocal Alaska 909 W. 9th Avenue Anchorage, AK 99501 Transmitting data as follows: Transmitting the following: Final Well Data. ~~~ ~~),..\ '\<-~dL9- CD Trading Bay Field A-15RD , A-15RD ET1 , A-15RD ST1 L 1 A-15RD ST L 1 A CD Trading Bay Unit G-12RD 3- dO d. (J5::> FY öÇJ 'D\ c\ -#- II~S<6 .. ð Od - C) 1.\ 'ð 4/0. II 7-(g \ ~ \ n lol) 603 - o~~ l\ 1e%:j êlla 1'1S RECEIVED SEP 13 2002 A1IIkI 011 i GII ConI. ConIDiIIiDn "act.. G-12RD3 Pef. ') ') Subject: G-12RD3 Pef. Date: Wed, 11 Sep 2002 17:36:10 -0700 From: "Buster, Larry W" <lbuster@unoca1.com> To: "'Davies, Steve'" <steve_davies@admin.state.ak.us> CC: "Brown, Martha S -Contract" <brownms@unoca1.com> Steve, Further to our conversation, the G-12RD3 Perforation Completion Work Times are as follows: HB3 13,900 - 13,930' - 6/16/02 HB3 13,699 - 13,729' - 6/21/02 HB2 to G7 (depths as per completion report) - 7/1/02 I will discuss and give you some feedback as to electronic commerce on the AOGCC report forms. Regards, Larry W. Buster Drilling Engineer Unocal Alaska (907) 263-7804 - Office (907) 263-7884 - Fax (907) 351-6730 - Mob. ---. --. - "--- ---- ,.-- - ~ - ------. -"--- .-. "--- - -- - - -" --- ---- --------- -- ~ --------- ---~-~--~-------- -.----- n____- -- n___- ------------- - - ----- --- -------- - n-- -- -- --- ; ~Part 1.2; T~pe: WINWORD File (application/ms-tnet)! E n.~?~~"~~~~~~~~.~'~nw"^,.~,,,w,,.~,,,,,ww,,,,,,,,,,~;,,,w<"W'«<"»w.~~",,,~w;ww~J ) Unocal Corporation P.O. Box 196247 Anchorage, AK 99501 Telephone (907) 263-7660 UNOCAL8 Larry W. Buster Advising Drilling Engineer September 9, 2002 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Attn: Commissioner Cammy Taylor Re: Well Completion Report (Form 407a) Trading Bay Unit/McArthur River Field Grayling Platform, Well G-12RD3 Commissioner Taylor: Enclosed for your review is the Well Completion Report for the Grayling Well G-12RD3. This well was drilled to a TO of 14,070' MD and was completed as a oil producer in the Hemlock Formation. If there are any questions, please contact myself at 263-7804. s~~ ~.. W - 1 JJ ~ LarryW. Buster Advising Drilling Engineer Unocal Alaska LB/s L ) STATE OF ALASKA ) ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. status of Well Classification of Service Well OIL: x GAS: 2. Name of Operator U nocal 3. Address P. O. Box 196247 Anchorage, AK 99519-6247 4. Location of well at surface "_\-"'''''~''""'\I 1874' FSL and 1386' FEL Sec. 29, T9N, R13 W, SM r.oMP~T¡m~, At Top Producing Interval (12,665' md) . l ~rn ,. B 1703' FSL and 449' FEL, Sec. 33, T9N, R13W, SM . . "",'JIr- . PZt At Total Depth (14070' md) I VEB~~ j't 1114' FSL and 472' FEL Sec. 33, T9N, R13W, SM ~,.\, ',¿:?~:.._~:..... 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. 99' RT above MSL ADL-17594 12. Date Spudded 13. Date I.D. Reached 14. Date Comp., Susp. or ~~and. 5/1 6/2002 6/5/2002 6jjt2002 .flD 17. Total Depth (MD+ TVD) 18. Plug Back Depth (MD+ TVD) 19. Directional Survey 14070'/9993' 13645'/'9760' Yes: x No: 22. Type Electric or Other Logs Run LWD - CDR/ADN/GR SUSPENDED: ABANDONED: SERVICE: t!. . \ '\'- ", '--". 'I.OCA t'tONS i , YfG1~Flro ~ ~.S9Jt. ,- J!.~Æ_-=j 7. Permit Number 202-055 8. API Number 50- 733-20116-03 9. Unit or Lease Name Trading Bay Unit 10. Well Number G-12RD3 11. Field and Pool McArthur River/Hemlock 15. Water Depth, if offshore 16. No. of Completions 125 feet MSL 1 20. Depth where SSSV set 21. Thickness of Permafrost 414 feet MD N/A 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WI. PER FI. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD 26" 1" wt 0' 369' Drive Drive 17-3/4" .312" wt 0' 602' 22" 775 sxs 13-3/8" 61# K-55 0' 6013' 18" 2525 sxs 9-5/8" 40-47# N-80/P-110 0' 10257' 12-1/4" Window 7" 29# N-80 9734' 13782' 8-1/2" 700 sxs 24. Perforations open to Production (MD+ TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) 3-1 /2" 12516' AMOUNT PULLED PACKER SET (MD) 12482' See Attached Schematic 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED None None 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) 6/22/2002 Gas Lift Date of Test Hours Tested PRODUCTION FOR I OIL-BBL 7/1/2002 TEST PERIOD =>24 Hr 1296 Flow Tubing Casing Pressure CALCULATED OIL-BBL Press. 200 1315 24-HOUR RATE => As above 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. NONE GAS-MCF 915 GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO 726 open 706 WATER-BBL OIL GRAVITY-API (corr) RBDMS 8Fl 6P Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE i L.. SEP 2 3 2002 Submit in duplicate 29. ) 30. ) GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. HK-1 13302' 9586' 13402' 9639' 13695' 9793' HB-3, 13,900' -13,930' MD, 456 BWPD, 100% water cut, 200 psi FTP, 1250 psi CP on gas lift HK-2 HK-3 HB-3 add to above interval, 13,699' -13,729' MD, 660 BWPD, 99.8% water cut, 200 psi 200 psi FTP, 1050 psi CP on gas lift. 31. LIST OF ATTACHMENTS Daily Report Summary, Well S 32. I hereby certify that 'c and Survey Report. Note: Mud and well logs being submitted under a separate cover. reg' g is true and correct to the best of my knowledge Sigr'l \ I TOle ~lJ~ç::J ~11~t:~r.Date 9 9 () ') I NSTR UCTIONS 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. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other space on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the productin intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (OF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 L= UNOCAL8 RKB to TBG Head = 40.73' () L. 2 L 3 >< 6 7 . . .--"\. 5 8 - cCXS /' TD = 14,070' G-I2 RD3 rev2 Schematic I.doc -1 ..J ..J ~ 4 x = 9 - 10 - 11 " ~ ) ) Trading Bay Unit Well G-12RD3 Actual Completion ~ CASING AND TUBING DETAIL SIZE 26" GRADE CONN MD MD TOP BTM. Surf 369' Surf. 602' Surf 6,013' Surf. 73' 73 6,252' 6,251' 6,939' 6,939' 6,941' 6,941 ' 8,276 (window) Surf. 14,060' Surf 12,516' ID WT 1/2" Wall 17-3/4" .312 wall Weld 13-3/8" 61 K-55 Butt 12.515 9-5/8" 47 P-110 Seal Lock 8.681 9-5/8" 40# N-80 Seal Lock 8.835 9-5/8" 43.5# N-80 Seal Lock 8.755 D V Co liar ----------------------------------------------------------------------- 9-5/8" 43.5# N-80 Seal Lock 8.755 7" 29 L-80 Butt 6.184 Tubing: 3-1/2" 9.2 L-80 2.992 BTC-Imp NO. DETAIL Item Cameron Tbg Hngr, 3-112" BTC DCB. 3-112" Tubing Retrievable SCSSV, Baker TE-5 3 4 5 6 7 8 9 10 11 Depth 41' 414' 3-1/2" Gas Lift Mandrels #1 3276' #2 5103' #3 6100' #4 6909' #5 7599' #6 8223' #7 8781' #8 9308' #9 9834' #10 10416' #11 10975' #12 11505' #13 11969' #14 12427' 12478' 12482' 12483' 12489' 12503' 12516' 13645' 12670' 12675' 2.810" ID 4.0" 3-112" GLM 3-112" GLM 3-112" GLM 3-112" GLM 3-112" GLM 3-112" GLM 3-112" GLM 3-112" GLM 3-112" GLM 3-112" GLM 3-112" GLM 3-112" GLM 3-112" GLM 3-112" GLM BOT 3-112" Locator Seal Assembly Model F-l Perm Pkr Seal Bore Extension 3-112" Tubing Seal Assy BOT "X" Nipple 3-112" WLEG TOC 7" PosiSet Plug 42' Peñorating Gun (spent) toolstring wI 300' of 0.23" e-line PERFORATION DATA Zone Top Btm Amt SPF Last Opr. Present Condition G-3 12665 12695 30 6 Open G-7/HBO 13250 13270 20 6 Open HB-1 13315 13375 60 6 Open HB-2 13410 13440 30 6 Open HB-3 13699 13729 30 6 Plugged HB-3 13900 13930 30 6 Plugged DRAWN BY: LWB Date: 8/20/02 ) ) Gravling Well G-12RD3 Dailv Summary Unocal Alaska Drilling Daily Summary Report G-12RD3 Oil Well 5/14/02 to 6/12/02 5/14/02 Install new casing and tubing spools. N/U BOPE. Install test plug and test BOP to 4000 psi high/ 250 psi low. Test annular to 3500 psi high/ 250 psi low. M/U whipstock and milling assembly. 5/15/02 RI H with whipstock and orient with MWD tool. Set whipstock and mill out of 9-5/8" casing from 8276' to 8294' with 9.2 ppg oil base mud. Condition hole. 5/16/02 Perform a 11.18 ppg EMW FIT at the casing window. POOH. M/U drilling BHA and RIH thru the window. Directionally drill from 8294' to 8,475' with a 9.2 ppg oil base mud. 5/17/02 Directionally drill from 8,475' to 9,026' with 9.2 ppg oil base mud. 5/18/02 Directionally drill from 9,026' to 9,601' with a 9.25 ppg oil base mud. 5/19/02 Directionally drill from 9,601' to 10085' with a 9.25 ppg oil base mud. 5/20/02 Directionally drill from 10,085' to 10,092' with a 9.25 ppg oil base mud. Circulate hole clean. POOH for bit change. Set BOP test plug and test stack to 4,000 psi high/ 250 psi low and the annular to 3,500 psi high/ 250 psi low. M/U new bit and RIH. 5/21/02 RIH to bottom and directionally drill from 10,085' to 10,355' with a 9.2 ppg oil base mud. 5/22/02 Directionally drill from 10,355' to 10,478' with a 9.4 ppg oil base mud. Make short trip and continue out of hole for BHA change. Reconfigure BHA and RIH. Directional drill from 10,478' to 10,511' with a 9.4 ppg oil base mud. 5/23/02 Directionally drill from 10,511' to 11,327' with a 9.4 ppg oil base mud. 5/24/02 Directionally drill from 11,327' to 11,694' with a 9.4 ppg oil base mud. Circulate hole clean in preparation from pulling out of hole. 5/25/02 POOH. Reconfigure BHA and m/u new bit. RIH and directionally drill from 11,694' to 11,990' with a 9.4 ppg oil base mud. 5/26/02 Directionally drill from 11,990' to 12,182' with a 9.45 ppg oil base mud. Circulate hole clean and POOH. Set test plug and test BOP to 4,000 psi high/ 250 psi low and the annular to 3,500 psi high/250 psi low. 5/27/02 P/U new bit and RIH. Directionally drill from 12,182' to 12,433' with a 9.4 ppg oil base mud. - 1 - ) Grayling Well G-12Ru3 End of the Well Summary ) 5/28/02 Directionally drill from 12,433' to 12,937' with a 9.4 ppg oil base mud. 5/29/02 Directionally drill from 12,937' to 13,173' with a 9.4 ppg oil base mud. Take a influx and shut well in. Circulate out kick with a maximum of 92 gas units. Continue with well control circulations bringing mud up to 9.7 ppg. 5/30/02 Continue to circulate Kill Weight Mud on choke. Bring mud weight up to 10.7 ppg. Perform a FIT to a 12.47 ppg EMW. Very little gas units seems we have a high pressure water flow from a pressurized water injection sand. 5/31/02 Ream bottom of hole from 13,055' to 13,173' with a total of 471 units of gas at bottoms up. Directionally drill from 13,173' to 13,433' with a 10.7 ppg oil base mud. 6/01/02 Directionally drill from 13,433' to 13,501' with a 10.8 ppg oil base mud. Circulate hole clean and POOH. Change out Bit and BHA. Set test plug and test BOP to 4,000 psi high/ 250 psi low and the annular to 3,500 psi high/ 250 psi low. M/U LWD tool. 6/02/02 RIH with BHA. Ream to bottom at 13,501'. Directionally drill from 13,501' to 13,547' with a 10.8 ppg oil base mud. 6/03/02 Directionally drill from 13,547' to 13,834' with a 10.8 ppg oil base mud. 6/04/02 Directionally drill from 13,834' to 14,020' with a 10.8 ppg oil base mud. Perform LWD logging run passes from 13,300' to 13,640'. 6/05/02 Continue with L WD logging runs. Ream to bottom and directionally drill from 14,020' to 14,070' (Well TD) with a 10.7 ppg oil base mud. Circulate to clean hole and condition mud. 6/06/02 Continue to condition hole. POOH with BHA. 6/07/02 Finish out of hole and R/U to run 7" casing. Run 7", L-80, 29# Buttress casing to 6,500' 6/08/02 Continue running 7", L-80 29# Buttress casing to 14,060'. Land casing hanger and establish circulation. Mix and pump 75 bbls 12.1 ppg mud spacer. 6/9/02 Drop bottom plug and then mix and pump 189 bbls of 15.8 ppg cement followed by a top plug. Dirplace top plug with water and bump plug with 4500 psi and hold for 15 minutes. Run casing annulus packott and test same to 5,000 psi. P/U Baker FB-1 packer c/w seal extension. RIH and set with E-line at 12,480'. Change out rams from 7" to 3-1/2". 6/10/02 Test rams to 4,000 psi high/ 250 psi low and the annular to 3,500 psi high/ 250 psi low. R/U to run 3-1/2" tubing. RIH with 3-1/2" tubing. M/U sub surface safety valve and continue in hole. -2- ) Grayling Well G-12RD3 End of the Well Summary ) 6/11/02 Sting into production packer and test seals to 3,000 psi. Space out and m/u tubing hanger landing joint. Land tubing hanger and test same to 3,000 psi. N/D BOPE and N/U and test x-mas tree to 5,000 psi. 6/12/02 Start general rig down procedures and release rig to Production Group. - 3 - G-12RD3 Schlumberuer UNOCAL8 Survey Report - Geodetic Report Date: 09-Sep-2002 Survey I DLS Computation Method: Minimum Curvature / Lubinski Client: Unocal Vertical Section Azimuth: 129.620° Field: Trading Bay Unit Vertical Section Origin: N 0.000 ft, E 0.000 ft Structure I Slot: Grayling / G-12 (slot 37) TVD Reference Datum: KB Well: G-12 TVD Reference Elevation: 99.000 ft relative to Mean Sea Level Borehole: G-12RD3 UWI/API#: 507332011603 Magnetic Declination: +20.512° Survey Name I Date: G-12RD3/ June 5, 2002 Total Field Strength: 55405.997 nT Tort I AHD I DDII ERD ratio: 212.54r /9401.38 ft / 6.449 / 0.941 Magnetic Dip: 73.529° / Grid Coordinate System: NAD27 Alaska State Planes, Zone 4, US Feet Declination Date: June 05, 2002 ~ Location LatlLong: N 60 50 23.256, W 151 3646.047 Magnetic Declination Model: BGGM 2002 Location Grid N/E VfX: N 2502421.450 nus, E 212297.820 ftUS North Reference: True North Grid Convergence Angle: -1.40847566° Total Corr Mag North -> True North: +20.512° Grid Scale Factor: 0.99999419 Local Coordinates Referenced To: Well Head Grid Coordinates Geographic Coordinates Station ID MD Incl Azim TVD VSec N/.S E/.W DLS Northing Easting Latitude Longitude (ft) (°) (°) (ft) (ft) (ft) (ft) (0/100ft) (ftUS) (ftUS) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2502421.45 212297.82 N 60 5023.256 W 151 3646.047 622.00 0.25 124.00 622.00 1.35 -0.76 1.12 0.04 2502420.66 212298.93 N 60 50 23.248 W 151 36 46.025 700.00 4.00 146.00 699.93 4.13 -3.11 2.79 4.83 2502418.27 212300.53 N 60 5023.225 W 151 3645.991 800.00 8.50 143.00 799.31 14.67 -11.91 9.19 4.51 2502409.32 212306.71 N 60 50 23.139 W 151 36 45.862 900.00 11.50 131.00 897.79 31.83 -24.35 21.16 3.64 2502396.58 212318.38 N 60 50 23.016 W 151 3645.620 1000.00 16.00 129.00 994.90 55.59 -39.58 39.41 4.52 2502380.92 212336.24 N 60 50 22.866 W 151 3645.252 1100.00 20.00 128.50 1089.99 86.48 -58.90 63.51 4.00 2502361.00 212359.86 N 60 50 22.676 W 151 3644.766 1200.00 23.50 129.00 1182.85 123.53 -82.10 92.40 3.50 2502337.10 212388.17 N 60 50 22.447 W 151 3644.183 1300.00 27.25 130.00 1273.19 166.37 -109.38 125.44 3.77 2502309.03 212420.53 N 60 50 22.179 W 151 36 43.516~/ 1400.00 31.00 129.50 1360.53 215.04 -140.48 162.86 3.76 2502277.01 212457.18 N 60 50 21.872 W 151 3642.761 1500.00 35.00 129.50 1444.38 269.49 -175.12 204.88 4.00 2502241.35 212498.33 N 60 5021.531 W 151 3641.913 1600.00 38.50 132.00 1524.50 329.29 -214.20 250.16 3.81 2502201.17 212542.64 N605021.147 W1513641.000 1700.00 42.00 132.00 1600.81 393.84 -257.43 298.17 3.50 2502156.77 212589.57 N 60 50 20.721 W 151 3640.031 1800.00 46.25 132.00 1672.58 463.38 -304.01 349.89 4.25 2502108.94 212640.13 N 60 50 20.262 W 151 36 38.988 1900.00 50.00 133.50 1739.32 537.71 -354.56 404.54 3.91 2502057.06 212693.52 N 6050 19.764 W 151 3637.885 2000.00 52.25 133.00 1802.08 615.40 -407.89 461.24 2.28 2502002.35 212748.90 N 60 5019.239 W 151 3636.741 2100.00 53.50 133.50 1862.43 694.97 -462.53 519.32 1.31 2501946.30 212805.61 N 60 5018.701 W 151 3635.569 2200.00 54.50 133.00 1921.21 775.71 -517.96 578.24 1.08 2501889.44 212863.15 N6050 18.155 W1513634.380 G-12RD3 ASP Final Survey.xls Page 1 of 5 9/9/2002-11 :09 AM Grid Coordinates Geographic Coordinates Station ID MD Incl Azim TVD VSec N/.S E/-W DLS Northing Easting Latitude Longitude (ft) (°) (°) (ft) (ft) (ft) (ft) (0/100ft) (ftUS) (ftUS) 2300.00 56.50 134.50 1977.85 857.90 -574.95 637.76 2.35 2501831.00 212921.25 N 605017.594 W 151 3633.180 2400.00 58.50 132.00 2031.58 942.06 -632.71 699.19 2.91 2501771.75 212981.24 N 60 5017.025 W 151 3631.940 2500.00 59.50 134.00 2083.09 1027.62 -691.17 761.87 1.98 2501711.77 213042.47 N 60 50 16.449 W 151 3630.676 2600.00 60.50 137.00 2133.10 1113.75 -752.94 822.55 2.78 2501648.53 213101.61 N 605015.841 W 151 3629.451 2700.00 58.50 135.00 2183.85 1199.36 -814.92 882.39 2.64 2501585.09 213159.90 N 60 5015.231 W 151 3628.244 2800.00 56.50 135.00 2237.58 1283.33 -874.55 942.02 2.00 2501524.01 213218.05 N 60 5014.643 W 151 3627.041 2900.00 54.00 134.00 2294.57 1365.18 -932.14 1000.61 2.63 2501465.00 213275.21 N 6050 14.076 W 151 3625.859 3000.00 52.50 134.00 2354.41 1445.07 -987.80 1058.25 1.50 2501407.94 213331.46 N 605013.528 W 151 3624.697 3100.00 55.00 134.50 2413.53 1525.45 -1044.08 1116.00 2.53 2501350.27 213387.82 N 605012.974 W 151 3623.531 3200.00 57.50 135.00 2469.08 1608.25 -1102.61 1175.05 2.53 2501290.30 213445.40 N 60 5012.397 W 151 3622.340,,-/ 3300.00 59.00 134.00 2521.71 1692.98 -1162.21 1235.70 1.72 2501229.23 213504.57 N 605011.811 W 151 3621.117 3400.00 57.25 133.00 2574.51 1777.70 -1220.66 1297.29 1.95 2501169.28 213564.70 N 605011.235 W 151 3619.874 3500.00 55.00 134.00 2630.25 1860.53 -1277.80 1357.52 2.40 2501110.68 213623.51 N 605010.672 W 151 3618.659 3600.00 52.25 133.00 2689.55 1940.85 -1333.23 1415.90 2.87 2501053.83 213680.51 N 605010.126 W 151 3617.481 3700.00 50.50 134.50 2751.97 2018.76 -1387.24 1472.34 2.11 2500998.45 213735.61 N 60 50 9.594 W 151 36 16.343 3800.00 49.50 133.00 2816.25 2095.16 -1440.21 1527.67 1.52 2500944.13 213789.62 N 60 50 9.073 W 151 36 15.227 3900.00 47.50 133.00 2882.51 2169.92 -1491.29 1582.44 2.00 2500891.73 213843.12 N 60 50 8.570 W 151 3614.122 4000.00 45.50 133.00 2951.34 2242.33 -1540.76 1635.49 2.00 2500840.97 213894.93 N 60 50 8.082 W 151 36 13.052 4100.00 45.50 135.00 3021.44 2313.44 -1590.30 1686.79 1.43 2500790.18 213945.00 N 60507.594 W 151 3612.017 4200.00 46.50 134.50 3090.90 2385.09 -1640.94 1737.88 1.06 2500738.30 213994.83 N 60507.096 W 151 3610.987 4300.00 47.00 135.50 3159.42 2457.60 -1692.44 1789.38 0.88 2500685.55 214045.04 N 60 50 6.588 W 151 36 9.948 4400.00 47.50 134.00 3227.30 2530.73 -1744.13 1841.53 1.21 2500632.59 214095.91 N 60 50 6.079 W 151 368.896 4500.00 48.50 135.00 3294.22 2604.78 -1796.22 1894.53 1.25 2500579.22 214147.61 N 60 50 5.566 W 151 367.827 4600.00 49.25 135.50 3359.99 2679.74 -1849.72 1947.56 0.84 2500524.43 214199.31 N 60 50 5.039 W 151 36 6.757 4700.00 49.25 134.50 3425.26 2755.16 -1903.29 2001.12 0.76 2500469.57 214251.54 N 60 50 4.512 W 151 365.677 4800.00 49.00 134.50 3490.70 2830.50 -1956.29 2055.06 0.25 2500415.26 214304.15 N 60 50 3.990 W 151 36 4.589~ 4900.00 47.50 135.00 3557.29 2904.80 -2008.80 2108.04 1.55 2500361.45 214355.83 N 60 50 3.473 W 151 36 3.520 5000.00 46.50 137.00 3625.49 2977.48 -2061.40 2158.85 1.77 2500307.62 214405.33 N 60 50 2.955 W 151 362.495 5100.00 45.00 138.50 3695.27 3048.39 -2114.41 2207.01 1.85 2500253.45 214452.18 N 60 50 2.432 W 151 361.524 5200.00 44.75 139.00 3766.14 3118.05 -2167.46 2253.53 0.43 2500199.27 214497.38 N 60 501.910 W 151 36 0.585 5300.00 44.50 139.00 3837.31 3187.36 -2220.47 2299.62 0.25 2500145.14 214542.15 N 60 50 1.388 W 151 35 59.656 5400.00 44.50 137.50 3908.64 3256.65 -2272.76 2346.29 1.05 2500091 .72 214587.52 N 60 50 0.873 W 151 3558.715 5500.00 44.50 137.50 3979.96 3326.08 -2324.44 2393.64 0.00 2500038.90 214633.59 N 60 50 0.364 W 151 3557.760 5600.00 44.50 138.00 4051 .29 3395.46 -2376.32 2440.77 0.35 2499985.87 214679.42 N 604959.853 W 151 3556.809 5700.00 44.50 138.50 4122.61 3464.76 -2428.61 2487.44 0.35 2499932.45 214724.80 N 604959.338 W 151 3555.868 G-12RD3 ASP Final Survey.xls Page 2 of 5 9/9/2002-11 :09 AM Grid Coordinates Geographic Coordinates Station ID MD Incl Azim TVD VSec N/-S E/-W DLS Northing Easting Latitude Longitude (ft) (°) (°) (ft) (ft) (ft) (ft) (0/100ft) (ftU5) (ftU5) 5800.00 44.50 138.50 4193.94 3534.01 -2481.11 2533.88 0.00 2499878.83 214769.93 N 604958.821 W 151 3554.931 5900.00 44.50 138.50 4265.26 3603.26 -2533.60 2580.33 0.00 2499825.21 214815.07 N 604958.304 W 151 3553.995 6000.00 44.50 140.00 4336.59 3672.36 -2586.70 2626.08 1.05 2499771.01 214859.50 N 604957.781 W 151 3553.072 6100.00 44.25 139.00 4408.07 3741.26 -2639.87 2671.50 0.74 2499716.73 214903.60 N 604957.257 W 151 3552.156 6200.00 44.50 139.00 4479.54 3810.26 -2692.66 2717.38 0.25 2499662.84 214948.17 N604956.737 W1513551.231 6300.00 44.50 139.50 4550.87 3879.36 -2745.75 2763.13 0.35 2499608.63 214992.60 N 604956.214 W 151 3550.308 6400.00 44.50 139.50 4622.19 3948.41 -2799.05 2808.65 0.00 2499554.23 215036.80 N 6049 55.689 W 151 3549.390 6500.00 44.00 139.50 4693.82 4017.16 -2852.11 2853.97 0.50 2499500.07 215080.80 N604955.167 W1513548.476 6600.00 43.75 139.50 4765.91 4085.44 -2904.81 2898.98 0.25 2499446.28 215124.50 N 604954.648 W 151 3547.568 6700.00 43.00 139.50 4838.60 4153.09 -2957.04 2943.58 0.75 2499392.98 215167.81 N604954.133 W1513546.669. . 6800.00 42.00 139.50 4912.32 4219.65 -3008.41 2987.46 1.00 2499340.54 215210.40 N 604953.627 W 151 35 45.784 ~. 6900.00 41.50 139.50 4986.93 4285.25 -3059.04 3030.70 0.50 2499288.86 215252.39 N 604953.128 W 151 3544.912 7000.00 42.00 140.00 5061.54 4350.80 -3109.86 3073.73 0.60 2499237.00 215294.15 N 6049 52.628 W 151 3544.044 7100.00 43.00 142.50 5135.27 4416.96 -3162.55 3115.99 1.96 2499183.29 215335.11 N 604952.109 W 151 3543.192 7200.00 43.75 142.00 5207.95 4483.97 -3216.85 3158.04 0.82 2499127.97 215375.81 N 604951.574 W 151 3542.344 7300.00 44.50 142.00 5279.74 4551.98 -3271.71 3200.90 0.75 2499072.07 215417.31 N 604951.034 W 151 3541.480 7400.00 44.25 144.00 5351.22 4620.01 -3327.56 3242.99 1.42 2499015.21 215458.01 N 604950.484 W 151 3540.631 7500.00 45.00 148.00 5422.40 4687.37 -3385.78 3282.24 2.91 2498956.04 215495.82 N 604949.910 W 151 3539.840 7600.00 45.00 146.00 5493.12 4754.84 -3445.08 3320.75 1.41 2498895.82 215532.86 N 604949.326 W 151 3539.063 7700.00 43.50 144.00 5564.75 4822.11 -3502.24 3360.75 2.05 2498837.69 215571.45 N 604948.763 W 151 3538.257 7800.00 44.00 145.00 5636.99 4888.94 -3558.54 3400.91 0.85 2498780.42 215610.20 N 604948.209 W 151 3537.447 7900.00 43.00 145.00 5709.52 4955.31 -3614.92 3440.39 1.00 2498723.08 215648.29 N 604947.653 W 151 3536.651 8000.00 42.50 144.50 5782.95 5020.84 -3670.36 3479.56 0.60 2498666.70 215686.09 N 604947.107 W 151 3535.861 8100.00 41.00 148.50 5857.57 5084.54 -3725.84 3516.33 3.06 2498610.33 215721.48 N 604946.561 W 151 3535.120 8200.00 42.75 154.00 5932.05 5146.51 -3784.34 3548.36 4.07 2498551.07 215752.06 N 604945.985 W 151 3534.474 8276.00 42.94 154.00 5987.78 5193.59 -3830.79 3571.01 0.25 2498504.07 215773.57 N 604945.527 W 151 35 34.017~ 8294.00 44.64 150.64 6000.77 5205.08 -3841.81 3576.80 16.00 2498492.91 215779.08 N 604945.419 W 151 3533.901 8310.96 43.98 150.64 6012.91 5216.14 -3852.14 3582.61 3.89 2498482.44 215784.64 N 604945.317 W 151 3533.784 8313.05 43.98 150.41 6014.41 5217.49 -3853.40 3583.33 7.64 2498481.16 215785.32 N 604945.305 W 151 3533.769 8351.69 45.37 146.21 6041.90 5243.22 -3876.50 3597.60 8.45 2498457.72 215799.02 N 604945.077 W 151 3533.481 8447.52 46.84 136.51 6108.42 5310.68 -3930.27 3640.68 7.45 2498402.91 215840.76 N 604944.547 W 151 3532.613 8542.18 45.44 131.45 6174.03 5378.69 -3977.66 3689.73 4.13 2498354.33 215888.64 N 604944.081 W 151 3531.624 8637.73 44.96 128.10 6241 .37 5446.4 7 -4021.03 3741.82 2.54 2498309.69 215939.64 N 604943.653 W 151 3530.573 8689.76 43.90 123.96 6278.53 5482.81 -4042.45 3771.26 5.93 2498287.55 215968.54 N 604943.442 W 151 3529.980 8732.82 44.02 123.34 6309.52 5512.53 -4059.02 3796.14 1.04 2498270.38 215993.01 N 604943.279 W 151 3529.478 G-12RD3 ASP Final Survey.xls Page 3 of 5 9/9/2002-11 :09 AM Grid Coordinates Geographic Coordinates Station ID MD Incl Azim TVD VSec N/.S E/.W DLS Northing Easting Latitude Longitude (ft) (°) (°) (ft) (ft) (ft) (ft) (0/100ft) (ftUS) (ftUS) 8828.74 44.48 119.32 6378.25 5578.74 -4093.79 3853.29 2.96 2498234.21 216049.29 N 60 49 42.936 W 151 3528.325 8922.73 44.64 118.87 6445.22 5643.58 -4125.86 3910.92 0.38 2498200.74 216106.11 N 604942.620 W 151 3527.163 9020.64 45.34 119.28 6514.46 5711.63 -4159.50 3971.41 0.77 2498165.62 216165.76 N 604942.289 W 151 3525.943 9113.75 46.23 119.34 6579.39 5777.28 -4192.17 4029.61 0.96 2498131.53 216223.13 N 604941.967 W 151 3524.770 9208.19 45.88 119.44 6644.93 5844.20 -4225.54 4088.85 0.38 2498096.72 216281.54 N 604941.638 W 151 3523.575 9302.95 45.36 119.14 6711.20 5910.83 -4258.67 4147.92 0.59 2498062.14 216339.78 N 604941.312 W 151 3522.384 9396.77 45.63 119.10 6776.97 5976.62 -4291.24 4206.37 0.29 2498028.15 216397.41 N604940.991 W1513521.205 9491.36 46.22 119.02 6842.77 6043.43 -4324.24 4265.77 0.63 2497993.69 216455.98 N 60 49 40.666 W 151 3520.007 9588.67 45.96 119.40 6910.25 6112.38 -4358.46 4326.96 0.39 2497957.99 216516.31 N 604940.329 W 151 3518.773 9684.00 45.99 119.42 6976.50 6179.84 -4392.12 4386.68 0.03 2497922.87 216575.18 N 604939.997 W 151 3517.569, / 9777.67 43.76 119.78 7042.88 6244.91 -4424.75 4444.14 2.40 2497888.83 216631.82 N 604939.675 W 151 35 16.410 ~' 9874.03 43.99 120.07 7112.34 6310.75 -4458.07 4502.02 0.32 2497854.10 216688.87 N 604939.347 W 151 3515.243 9970.16 44.38 120.40 7181.28 6376.85 -4491.81 4559.91 0.47 2497818.95 216745.90 N 604939.014 W 151 3514.076 10029.02 44.29 119.75 7223.38 6417.41 -4512.42 4595.50 0.79 2497797.4 7 216780.98 N 604938.811 W 151 35 13.358 10051.41 44.12 120.13 7239.43 6432.80 -4520.21 4609.03 1.41 2497789.35 216794.32 N 604938.735 W 151 35 13.085 10147.01 44.92 120.16 7307.59 6498.92 -4553.88 4666.99 0.84 2497754.27 216851.43 N 604938.403 W 151 3511.917 10237.93 45.09 119.67 7371.87 6562.29 -4585.94 4722.72 0.42 2497720.85 216906.36 N 604938.087 W 151 35 10.793 10336.90 45.31 119.74 7441.61 6631.47 -4620.74 4783.72 0.23 2497684.56 216966.48 N 604937.744 W 151 359.563 1 0417.1 5 45.45 119.86 7497.98 6687.75 -4649.13 4833.29 0.20 2497654.96 217015.34 N 604937.464 W 151 358.563 10432.23 45.49 119.41 7508.55 6698.34 -4654.44 4842.63 2.14 2497649.42 217024.55 N 604937.412 W 151 35 8.375 10529.05 45.09 119.19 7576.67 6766.04 -4688.12 4902.64 0.44 2497614.28 217083.70 N 604937.080 W 151 357.165 10624.61 44.54 119.32 7644.46 6832.29 -4721.03 4961.40 0.58 2497579.93 217141.64 N 604936.756 W 151 355.980 10719.19 43.90 119.07 7712.24 6897.16 -4753.21 5018.98 0.70 2497546.35 217198.41 N 60 49 36.439 W 151 354.819 10814.07 43.44 119.17 7780.87 6961.58 -4785.09 5076.21 0.49 2497513.07 217254.84 N 60 49 36.124 W 151 353.665 10907.35 43.04 118.72 7848.82 7024.37 -4816.02 5132.13 0.54 2497480.78 217309.99 N 60 49 35.820 W 151 352.537 11005.14 42.19 119.32 7920.79 7089.45 -4848.13 5190.03 0.96 2497447.25 217367.08 N 604935.503 W 151 351.370<~ 11099.17 41.61 118.63 7990.78 7151.17 -4878.56 5244.97 0.79 2497415.49 217421.25 N 60 49 35.203 W 151 350.262 11194.36 41.64 118.22 8061.93 7213.20 -4908.65 5300.57 0.29 2497384.03 217476.10 N604934.907 W1513459.141 11288.38 42.02 117.95 8131.99 7274.63 -4938.17 5355.89 0.45 2497353.16 217530.67 N 604934.616 W 151 3458.025 11386.22 40.99 117.63 8205.26 7338.09 -4968.40 5413.25 1.07 2497321.53 217587.27 N 604934.318 W 151 3456.869 11477.60 39.84 117.11 8274.83 7395.99 -4995.64 5465.86 1.31 2497293.01 217639.19 N 6049 34.049 W 151 34 55.808 11573.63 38.68 116.86 8349.19 7455.28 -5023.22 5520.01 1.22 2497264.11 217692.65 N 604933.777 W 151 3454.716 11667.64 37.85 116.45 8423.00 7512.02 -5049.34 5572.04 0.92 2497236.72 217744.03 N 604933.520 W 151 3453.667 11756.11 38.75 116.37 8492.43 7565.40 -5073.73 5621.15 1.02 2497211 .13 217792.52 N 604933.280 W 151 3452.677 11858.83 39.27 116.28 8572.24 7628.33 -5102.40 5679.11 0.51 2497181.04 217849.75 N604932.997 W1513451.508 G-12RD3 ASP Final Survey.xls Page 4 of 5 9/9/2002-11 :09 AM Grid Coordinates Geographic Coordinates Station ID MD Incl Azim TVD VSec N/.S E/.W DLS Northing Easting Latitude Longitude (ft) (°) (°) (ft) (ft) (ft) (ft) (°/1 OOft) (ftU5) (ftU5) 11952.03 39.79 116.37 8644.13 7686.06 -5128.70 5732.27 0.56 2497153.44 217902.25 N 604932.738 W 151 3450.436 12048.79 40.13 115.64 8718.29 7746.45 -5155.95 5788.13 0.60 2497124.83 217957.42 N 604932.469 W 151 3449.310 12118.97 39.01 115.02 8772.39 7789.77 -5175.08 5828.53 1.69 2497104.71 217997.34 N 604932.280 W 151 3448.495 12145.50 38.86 114.95 8793.03 7805.91 -5182.12 5843.64 0.59 2497097.30 218012.28 N 604932.211 W 151 3448.191 12241.43 41.35 115.42 8866.39 7865.75 -5208.42 5899.56 2.61 2497069.63 218067.53 N 604931.952 W 151 3447.063 12335.53 43.00 115.77 8936.13 7927.04 -5235.72 5956.53 1.77 2497040.94 218123.81 N 604931.683 W 151 3445.914 12431.65 42.98 115.78 9006.44 7990.68 -5264.22 6015.55 0.02 2497011.00 218182.12 N 604931.402 W 151 3444.724 12526.50 43.04 116.54 9075.80 8053.60 -5292.74 6073.63 0.55 2496981.06 218239.47 N 604931.121 W 151 3443.553 12618.88 43.42 116.93 9143.11 8115.28 -5321.21 6130.13 0.50 2496951.21 218295.26 N 604930.840 W 151 3442.414 12715.44 43.92 118.02 9212.95 8180.46 -5351.97 6189.29 0.94 2496919.01 218353.64 N 604930.537 W 151 34 41.22L~ 12808.87 44.40 118.15 9279.98 8244.24 -5382.61 6246.71 0.52 2496886.96 218410.29 N 604930.235 W 151 3440.063 12903.69 46.93 119.00 9346.24 8310.80 -5415.06 6306.26 2.74 2496853.06 218469.02 N 604929.915 W 151 3438.863 12999.10 50.78 120.32 9409.00 8381.55 -5450.63 6368.67 4.17 2496815.97 218530.54 N 604929.564 W 151 3437.605 13095.08 53.38 121 .44 9467.99 8456.38 -5489.49 6433.64 2.86 2496775.52 218594.53 N 604929.181 W 151 3436.295 13190.35 53.82 120.72 9524.52 8532.21 -5529.08 6499.31 0.76 2496734.33 218659.21 N 604928.791 W 151 3434.971 13283.67 57.77 120.63 9576.97 8608.44 -5568.44 6565.68 4.23 2496693.35 218724.59 N 604928.403 W 151 3433.633 13377.85 57.98 120.58 9627.05 8687.21 -5609.05 6634.33 0.23 2496651.07 218792.22 N 604928.003 W 151 3432.249 13442.53 58.19 120.69 9661 .25 8741.44 -5637.03 6681 .57 0.36 2496621.94 218838.76 N 604927.727 W 151 3431.296 13484.19 58.31 120.63 9683.17 8776.43 -5655.09 6712.04 0.31 2496603.13 218868.78 N 604927.549 W 151 3430.682 13574.21 58.46 120.63 9730.36 8852.15 -5694.15 6778.00 0.17 2496562.46 218933.76 N 604927.164 W 151 3429.352 13672.44 58.27 120.96 9781.88 8934.80 -5736.97 6849.85 0.35 2496517.89 219004.53 N 604926.742 W 151 3427.904 13766.90 58.26 120.65 9831.57 9014.18 -5778.11 6918.85 0.28 2496475.07 219072.50 N 6049 26.336 W 151 34 26.512 13860.85 58.15 120.96 9881.07 9093.09 -5819.00 6987.43 0.30 2496432.50 219140.06 N 604925.933 W 151 3425.130 13952.76 57.19 120.95 9930.22 9169.87 -5858.95 7054.03 1.04 2496390.93 219205.66 N 604925.539 W 151 3423.787 14003.72 56.82 120.97 9957.97 9212.12 -5880.94 7090.69 0.73 2496368.05 219241.76 N 604925.323 W 151 3423.048 14070.00 56.30 120.97 9994.49 9266.80 -5909.40 7138.11 0.78 2496338.43 219288.46 N 6049 25.042 W 151 34 22.092'~ G-12RD3 ASP Final SUNey.xls Page 5 of 5 9/9/2002-11 :09 AM U local Corporation • P.O. Box 196247 • Anchorage, AK 99501 Telephone (907) 263 -7660 UNOCALO Tim Billingsley 8/21/2002 Drilling Engineer Alaska Oil an Gas Conservation Commission 333 West 7 Avenue Anchorage, Alaska 99501 Attn: Tom Maunder Re: Report on Annulus Disposal Trading Bay Unit, Grayling Platform, Well Grayling G -22 Mr. Maunder: &6-19 -- Enclosed is the final report on annulus disposal of A -29RD oil base mud (OBM) liquid waste into the G -22 annulus as required by the Sundry Application Approval #301 -304 dated November 6, 2001. Attached is the daily summary of disposal volumes in G -22 annulus while drilling at A -29RD. The following is the total volumes disposed in G -22 annulus by drilling well source. Well OBM, bbls Seawater Flush, bbls Total Bbls G -15RD 1269 2160 3429 2oc -cal( G -28RD 203 700 903 t, G -26RD 823 2155 2978 toa oi - A -15RD 1374 5067 6441 G12' 366 1050 1416 aot� A -' D 856 1494 2350 Total 17517 This concludes all presently scheduled disposals into the G -22 annulus. If there are any questions, please contact myself at 263 -7659. Sincerely, 5000 APB 2D� j "em Billingsley Drilling Engineer AOGCC G -22A -29RD waste annular disposal final report Created on 8/21/2002 10:13 AM Daily Injection Log of the 13 3/8" x 9 5/8" Annulus of G -22 Drilling Wastes From Monopod A -29RD Maximum Allowable Injection Pressure 2000 psi TVD 13 3/8" Casing Shoe Depth 4977' BBLS BBLS BBLS BBLS Date Slurry Flush Rate Injection Slurry Slurry Flush Total Total No No. BPM Pressure* PPG Volume Volume Slurry's Flushes 6/29/2002 1 2.0 1600 10.2 205 0 205 0 6/29/2002 2 2.0 1400 10.2 146 351 0 6/29/2002 3 1 2.0 1800 10.2 60 357 411 357 7/15/2002 2 2.0 1550 20 411 377 7/15/2002 4 2.0 1850 8.7 125 536 377 7/15/2002 3 2.0 1800 357 536 734 • 8/5/2002 4 2 1400 8.3 20 536 754 8/5/2002 5 2 1750 8.5 170 706 754 8/5/2002 5 2.5 1850 8.3 350 706 1104 8/10/2002 6 2 1500 8.3 20 706 1124 8/10/2002 6 2 1750 8.5 150 856 1124 8/10/2002 7 2.5 1850 8.3 370 856 1494 • *Injection pressure is the highest injection pressure observed while injecting • ) Unocal Alaska 909 W. 9th Avenue Anchorage, AK 99501 Tele: (907) 263-7651 Fax: (907) 263-7828 E-mail: haITisonb@unoca1.com -, c L~~ Beverly Harrison Business Ventures Assistant July 16, 2002 To: Lisa Weepie AOGCC 333 W. 7th Ave. Anchorage, AK 99501 DATA TRANSMITTAL - Grayling Platform lfì . G-12 RD3 t{) G-12 RD3 () G-12 RD3 r6 G-12 RD3 0 G-12 RD3 m : G-12 RD3 .. \) G-12 RD3 G-12 RD3 "':J- 1 COMPLETION RECORD /9 518" CEMENT : ¡ ~ G-12 RETAINER 5 INCH 5/12/2002 8000-8350 ¡ 1 I Film - . COMPLETION RECORD /9 5/8" CEMENT ¡ ! -' G-12 RETAINER 5 INCH 5/12/2002 8000-8350 I 1! B-Line , G-12 RD3 AND 2 INCH 6/7/2002 12408-14070 ! 1 I B-Line _.....~::J..?...B.P-~.............._.Ç.9MPLETION REQ.9RD 5 INCH 6/16/2002 12290=J.~~.60 I 1 L..ê.~.h!.!l~_.......... G-12 RD3 COMPLETION RECORD 5 INCH 6/16/2002 12290-13960 ¡ 1 I Film COMPLETION RECORD /2.5" POWER JET GUNS ! . G-12 RD3 /6 SPF /60 DEG PHASING I 5 INCH 6/29/2002 13200-13645 ¡ 1 I B-Line COMPLETION RECORD / 2.5" POWER JET GUNS I . , G-12 RD3 /6 SPF /60 DEG PHASING 5 INCH 6/29/2002 13200-13645 I 1 ¡ Film """-"'1'" ...-.................-..-.....t.---.-.-....... ! G-12 RD3 _!~QMPLETI2-~R~ÇQ~_!E.RODUCTION PACKER i 5 ~.9:!~9/2002 12300:1l~~~J Film COMPLETION RECORD / PRODUCTION PACKER I 51NCH 6/9/2002 12300-13310 I 1 ¡ B-Line DML-MWD COMBO LOG ! 21NCH 5/15/2002 8300-14100 ! 1 I B-Line EPOCH FINAL WELL REPORT i 6/5/2002 I 1 I B-Line FORMATION LOG I 21NCH 5/15/2002 6000-10000 I 1 I B-Line GR-CCL I 5 INCH 6/16/2002 12290-13960 I 1! Film GR-CCL ! 5 INCH 6/16/2002 12290-13960 ¡ 1 I B-Line MD / REAL TIME DATA / FIELD PRINT I 2 INCH 5/16/2002 8350-13450 I 1 i B-Line TVD / COMPOSITE FIELD PRINT i 2/5 INCH 6/1/2002 12409-14037 I 1 I'. B-Line VISION DENSITY NEUTRON / MD COMPOSITE I G-12 RD3 FIELD PRINT i 2/5 INCH 6/1/2002 12409-14037 I 1 B-Line Please acknowledge receipt by signing and returning one copy of this transmittal or FAX ~0e,¥E, [) ReceiV~~ JUL 1 8 2002 Date: ¡:~a3kaJ;') d.. Gasi.}.;mmi8sion tmchofage ) ') Unocal Alaska 909 W. 9th Avenue Anchorage, AK 99501 Te1e: (907) 263-7651 Fax: (907) 263-7828 E-mail: hamsonb@unocal.com UNOCALe Beverly Harrison Business Ventures Assistant July 16, 2002 To: AOGCC Lisa Weepie 333 W. 7th Ave. Anchorage, AK 99501 DATA TRANSMITTAL- Alaska / Offshore / Grayling Platform Dry Samples G-12 RD3 ;;t~^ - (0)-) 8280' -10460' 10460' - 12610' 12610' -14071' Box 1 of3 Box 2 of3 Box 3 of3 #= }I OL Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to (907) 263-7828. Received By: W Ô ~ Date: I~ J~ a(}O~ UsJL ~~ Unocal Corporation • / tx . P.O. Box196247 • Anchorage, AK 99501 Telephone (907) 263 -7660 UNOCAL Jim Harrison 7/3/2002 Drilling Manager Alaska Oil and Gas Conservation Commission 333 West 7 Avenue Anchorage, Alaska 99501 45 3 Attn: Tom Maunder a0 Re: Report on Annulus Disposal Trading Bay Unit, Grayling Platform, Well Grayling G -22 Mr. Maunder: Enclosed is the final report on annulus disposal of G -12RD3 oil base mud (OBM) liquid waste into the G -22 annulus as required by the Sundry Application Approval #301 -304 dated November 6, 2001. Attached is the daily summary of disposal volumes in G -22 annulus while drilling at G- 12RD3. The following is the total volumes disposed in G -22 annulus by drilling well source. Well OBM, bbls Seawater Flush, bbls Total Bbis X49 -c G -15RD 1269 2160 3429 G -28RD 203 700 903 1 14.-p4L G -26RD 823 2155 2978 Doi -iK9 A -15RD 1374 5067 6441 a Da-p55 - 2RD3 366 1050 1416 ota 15167 Unocal began disposing of drilling wastes from the A -29RD into the G -22 annulus on June 29, 2002. If there are any questions, please contact myself at 263 -7677 or Tim Billingsley at 263 -7659. Sincerely,, •� �Ilx('.0 V •�+'' //�/"J' c Seth APR Q Jim arrison Drilling Manager T 4ra3k i t) E k,4 AOGCC G -22 G -12RD waste annular disposal final report R1 Tim Billingsley Daily Injection Log of the 13 3/8" x 9 5/8" Annulus of G -22 Drilling Wastes From Grayling G -12RD3 Maximum Allowable Injection Pressure 2000 psi TVD 13 3/8" Casing Shoe Depth 4977' BBLS BBLS BBLS BBLS Date Slurry Flush Rate Injection Slurry Slurry Flush Total Total No No. BPM Pressure* PPG Volume Volume Slurry's Flushes 6/10/2002 1 1 3 1800 9.1 170 350 170 350 6/15/2002 2 2 2 1800 8.3 11 350 181 700 6/17/2002 3 3 2 1750 8.4 185 350 366 1050 "• is the highest injection pressure observed while injecting ) ) c?\ 0;;)-055-- Unocal Corporation P.O. Box 196247 Anchorage, AK.99501 Telephone (907) 263-7805 UNOCAL8 i}J,':¡'" Alaska James R. Harrison Drilling Manager June 3, 2002 Alaska Oil and Gas Conservation Commission 333 West ih Avenue Anchorage, Alaska 99501 Attn: Thomas E. Maunder Sr. Petroleum Engineer Re: Recap of Well Control Incident Grayling Well G-12RD3 May 29 to 30,2002 Dear Mr. Maunder: We were drilling with an 8-1/2" directional assembly at 13,173' MDI 9514' TVD in the G-6 Sand with a 9.4 ppg oil base mud. The crew detected an increase in the flow show upon making a connection and shut the well in at the annular. The initial pressures were recorded at SIDDP = 280 psi and SICP = 300 psi with a 10 bbl pit gain. The first stage of the Drillers Method was commenced and upon bottoms up water contaminated mud and a gas count of 187 units. The recorded SICP after the first stage of the Drillers method was recorded at 620 psi. The KWM was calculated at 10.7 ppg. The mud was brought up in stages to 9.7 ppg -10.1 ppg -10.4 ppg and finally 10.7 ppg. The well was stable at 10.7 with no gains or losses. The annular preventor was then closed, and a 12.47 EWM open hole formation integrity test was performed. We then drilled ahead with no more gains or losses. The source of the pressure is felt to be from water flood injection pressure. The virgin pressures in the area are all expected to be normal and all indications during the kick were that the pressure was coming from water flood injection pressure; contaminated mud, not much gas associated with kick. If you have any questions, or need additional information, please contact me at 263-7948. V~c ely, . ' ~ ' Leo Phel p Acting Drilling Manager RECEIVED Cc: Larry Buster Don Byrne Shane Hauck JUN 0 5 2002 G-12RD3 Recap Ala.ska Oil & Gas Gûns. GomríH5SíO¡ Anc~Qe UNOCAL8 UNOCAL ALASKA RESOURCES G-12RD3 TRADING SA Y UNIT Section 29- T9N-R13W-SM Cook Inlet, Alaska ) June 05, 2002 Andrew Buchanan - Sr. Logging Geologist Brian O'Fallon ~ Sr. Logging Geologist John Morris - Sr. Logging Geologist U EPOCH d o¡;;- oSS ) TABLE OF CONTENTS UNOCAL8 G-12RD3 MIDDLE GROUND SHOAL COOK INLET, ALASKA WELL RESUME ......... .................... ................... ....... ........ ........................ ...................... 2 LITHOLOGY AND CO MMENTS. ...... ...... .................. .... ......... ..... ........ ................ ............ 3 DAILY ACTIVITY SU MMARY ...... ........ ........ .......... ........... ........... ......... ........ ............... 14 SURVEY SU MMARY. ......... ..................... ...... ........... ........ ........ ....... ..... .......... .............. 16 MUD SU MMARY ........................... ............ ..................... ...... ...... ..... .......... ..... ........ ...... 18 BIT RECORD............................................................................................................... 19 DAYS VERSES DEPTH ....... ........... .......... ........... ....... ......... ........... .......... ....... ..... ....... 20 LOGS............................................................................................................. APPENDIX J [::I EPOCH 1 Operator Well Name Field Region County State Coordinates Elevation AFE# API Index Spud Date Kick Off Point ) Hole Size Total Depth Contractor Rig Tool Pushers Company Representatives Directional Company Personnel MWD Company Tools: Main Hole Last Bit Run Personnel Epoch Personnel Mud Company Personnel UNOCAL8 G-12RD3 WELL RESUME Unocal Alaska Resources G-12RD3 Trading Bay Cook Inlet Kenai Borough Alaska Sec. 29, Town. 9, R. 13W SM 99' RKB 153509 50-733-20116..03 05/15/2002 1600 hrs 8277' 8.5" 14071'md; 9995' TVD @ 06/05/02 1630 hrs Nabors Drilling Alaska Grayling Platform Ernie Sandidge, Rick Brumley, David Smith, Robert Kennedy Doug Niehaus, Shane Hauck Baker-Hughes Scott Levad, Overman Schlumberger Anadrill Real Time GR Real Time GR; ADN; COR Carlos Pacheco, Izwan Megat, Wissam Chan, Nakia Bowman Andrew Buchanan, Brian O'Fallon, John Morris MI Drilling Fluids Monty Kanta, Keith Olson ~ EPOCH 2 UNOCAL8 G-12RD3 LITHQLOGY AND COMMENTS 8290' Claystone = medium gray to light brownish gray; smooth to slightly silty/gritty texture; subblocky to lumpy to flaky; noncalcareous; some thin coal stringers and interbedded with sand; slough in part. 8340' Sand = light gray overall; very fine to medium grains and scattered coarse and pebble; subangular; some bit impacted fragments; moderately sorted and loosely consolidated in slight to locally moderate ashy kaolic matrix; 80% quartz, and 20% clay, chert, and feldspar with chert increasing in coarser fraction; estimate some fair to good porosity and permeability; oil indicators masked by oil based mud contamination. 8400' Claystone = light gray to medium gray to brownish gray; amorphous to flaky and common PDC bit markings; earthy to some gritty/silty texture; commonly ashy and kaolic; commonly slightly to moderately organic with thin coal partings and stringers; moderately hydrophilic; very slightly calcareous; occasionally grading ashy sandstone. 8450' Carbonaceous Shale = brownish gray to brownish black; slightly firm and crunchy; flaky to hackly fracture; moderately to very organic with coal partings and thin beds; commonly grading to lignite. 8405' Sand = light gray to medium light gray; fine to coarse lower and scattered very coarse grains; locally scattered pebbles and fragments; angular to subrounded; moderate sphericity; moderate to poorly sorted; slight to moderate kaolic-ashy clay matrix; 85% quartz, and 15% clay lithics, chert, feldspar, and calcareous matter; estimate some fair to good porosity and permeability; oil indicators masked by oil based mud contamination. ) 8550' Coal = brownish black to grayish black; moderately brittle to crunchy; flaky to hackly; slightly shiny luster; lignite with slight interbedded carbonaceous shale. 8585' Tuffaceous Clavstone = light to medium gray with common dark brownish gray; slightly firm; amorphous PDC bit deformed cuttings; smooth to gritty texture; dull to matte luster; commonly ashy; commonly carbonaceous with occasional coaly laminations; commonly finely interbedded with very fine sand in part; hydrophilic in part; trace calcareous. 8640' Coal = dark brownish black to black; hard; conchoidal to hackly to sub platy fracture; jagged irregular cuttings; resinous, waxy luster; smooth to occasional gritty texture; trace visible minor bleeding gas. 8675' Tuffaceous Clavstone = light to medium gray with common dark brownish gray; slightly firm; amorphous PDC= bit deformed cuttings; smooth to gritty texture; dull to matte luster; commonly ashy; commonly carbonaceous with occasional coaly laminations; commonly interbedded with sandstone. 8720' Sandstone/Sand = very light gray to light greenish gray; very fine to medium with rare coarser grains; subangular to angular; low to occasional moderate sphericity; moderately to in part well sorted; composed of 70% quartz, 30% lithic fragments; unconsolidated with consolidated horizon at 8710-8715' and a very coarse to pebble size quartz, chert and quartzite conglomerate lag at 8770 8780'; consolidated portion grain and kaolin/ash matrix supported; estimate some fair to good porosity and permeability; oil indicators masked by oil based mud contamination. ~ EPOCH 3 UNOCAL8 G-12RD3 8805' ) Conglomeratic Sand = medium light gray to light olive gray; fine to coarse and scattered to locally common very coarse to pebble sized grains and fragments; subangular to angular; moderately to poorly sorted in mostly very slight to locally moderate ashy-kaolic matrix; locally grading ash fall tuff; 85% quartz, and 15% black to gray to red to translucent grains including lithics, chert, and feldspar; estimate mostly fair to poor porosity and permeability; oil indicators masked by oil based mud contamination. 8880' Carbonaceous Shale = brownish gray to brownish black; slightly firm; subblocky to slightly flaky; moderately organic overall occasionally grading lignite and occasional coal partings; smooth; interbedded with conglomerate and grading to tuffaceous claystone and sand. 8920' Sandstone = medium light gray; very fine to medium grains; subangular to angular; poorly to some moderately sorted in kaolic-ashy matrix; often matrix supported; locally conglomeratic; poorly consolidated; 85% quartz, and 15% clay and coallithics, and minor chert and feldspar; estimate mostly poor to fair porosity and permeability; oil indicator masked by oil based mud contamination. 8975' Coal = black to brownish black; slightly firm and brittle; hackly to flaky; slightly shiny luster; lignite occasionally grading to carbonaceous shale; mostly massive. 9005' Conalomerate = medium light gray to gray; pebbles and fragments in kaolic clay and sand matrix; poorly sorted; larger fraction mostly cherty metalithics; finer fraction mostly quartz; matrix commonly slightly organic in part; grading to and interbedded with claystone, carbonaceous claystone, and minor coal. , 9055' ) Coal = brownish black to black; slightly firm to moderately firm; brittle to crumbly; hackly to flaky fracture; thin beds , lignite grading to and interbedded with organic to slightly organic claystone; slightly shiny to earthy luster. 9110' Claystone = medium dark gray to brownish gray; slightly firm and crunchy to crumbly; moderately hydrophilic; amorphous to subplaty; smooth to slightly silty/gritty texture; very slight to some slightly to moderately organic; occasionally grading carbonaceous shale with coal partings and thin beds and streaks; very slightly calcareous; trace disseminated mica. 9165' Coal = black to grayish black to brownish black; moderately firm and slightly brittle to brittle; hackly to flaky fracture with some visible lamina; lignite to subbituminous; massive to thinly interbedded with carbonaceous shale and claystone. 9210' Sand = very light gray overall; occasional very fine to predominantly fine to coarse with occasional horizons of coarse to pebble size grains; angular to subangular; low sphericity; composed of 80%-90% quartz and 10%-20% lithic fragments; predominate moderate sorting with common intervals of conglomeratic sand with very poor sorting as well as occasional pebble conglomerate; unconsolidated with up to 10% grain supported, kaolin/ ash matrix infilled consolidated cuttings; estimated overall poor to fair intergranular porosity; oil indicators are obscured by oil based mud. 9290' Sand/Conalomeratic Sand = very light gray overall; medium to coarse with occasional finer and coarser grains; angular to subangular; low sphericity; predominantly moderate with poor and very poor sorting in conglomeratic horizons; composed quartz with up to 10% lithic fragments; predominantly unconsolidated; increasing consolidation to 20% at 9350'; consolidated cuttings are grain supported with a kaolin/ash matrix infilling porosity; estimate poor to fair porosity overall; oil indicators obscured by oil based mud. ~ EPOCH 4 UNOCAL8 G-12RD3 9365' ) Tuffaceous Clavstone = very light greenish gray to very light brownish gray; firm to stiff; crumbly; predominantly PDC= bit deformed cuttings; smooth to occasional gritty texture; matte to earthy luster; occasional grades to siltstone. 9400' Coal = black to dark brownish black; hard; brittle; conchoidal to hackly with common sub planar fracture; irregular to jagged cuttings; resinous to vitreous luster; common visible banding; occasional partings of clay; very rare grading to carbonaceous shale; very minor visible bleeding gas. 9445' Tuffaceous Clavstone = very light greenish gray to medium brownish gray; firm to stiff; crumbly; predominantly PDC= bit deformed cuttings; smooth to occasional gritty texture; matte to earthy luster; grades to carbonaceous shale by 9460'. 9480' ÇQãl = black to dark brownish black; hard; brittle; conchoidal to hackly with common sub planar fracture; irregular to jagged cuttings; resinous to vitreous luster; common visible banding; occasional partings of clay; very rare grading to carbonaceous shale; very minor visible bleeding gas. 9530' Conglomeratic Sand = light gray to medium light gray; fine to coarse grains and scattered very coarse including fragments; subangular to angular with occasional bimodal rounded grains in coarse fraction; poorly to moderately sorted; possible slight overall clay matrix with occasional streaks clay supported; 90% quartz, 10% clay, chert, coal, and feldspar; estimate mostly poor to fair porosity and permeability; oil indicators masked by oil based mud contamination. 9610' ) Claystone = medium light gray to medium dark gray to dark brownish gray; slightly firm and crunchy; smooth to gritty/silty texture with interbedded fine sand and siltstone; moderately hydrophilic; mostly slightly to some moderately organic including some thin partings and beds of coal; some coal clasts in tuffaceous claystone; occasional calcareous matter. 9670' Tuffaceous Claystone = very light greenish gray to medium brownish gray; firm to stiff; crumbly; predominantly PDC bit deformed cuttings; smooth to occasional gritty texture; matte to earthy luster; commonly grades to siltstone and carbonaceous shale. 9710' Coal = black to dark brownish black; hard; brittle; conchoidal to hackly with common sub planar fracture; irregular to jagged cuttings; resinous to vitreous luster; common visible banding; occasional partings of clay; very rare grading to carbonaceous shale; very minor visible bleeding gas. 9755' Tuffaceous Siltstone = very light brownish gray to medium gray; firm to soft; brittle to malleable; irregular fracture with PDC bit deformed cuttings; highly variable composition including quartz, lithics ash and abundant clay; common laminae of tuffaceous ash; grades to very fine sandstone in part; interbedded with and grading tuffaceous claystone. 9805' Sandstone/Sand = light gray to very light brownish gray; very fine lower to occasional medium size grains; angular; low sphericity; moderately to well sorted; composed of 50% quartz, 40% lithics, 10% assorted minerals and clasts; predominantly consolidated with kaolin/ash matrix; grain and matrix supported; commonly grades to tuffaceous siltstone; occasional laminations of ash; estimated very poor to nil porosity; oil indicators masked by oil based mud. [j EPOCH 5 UNOCAL8 G-12RD3 9870' ) Tuffaceous Clavstone = very light greenish gray to medium brownish gray; firm to stiff; crumbly; predominantly . PDC= bit deformed cuttings; smooth to occasional gritty texture; matte to earthy luster; commonly grades to siltstone and occasionally grades to carbonaceous shale; occasional visible laminations of tuffaceous ash. 9925' Sand = medium gray to light olive gray; medium to fine grains; subangular; moderately sorted; moderate to high sphericity; very slight clay matrix and possible thin zones tuffaceous claystone and minor siltstone; 90% quartz, and 10% clay and coallithics, feldspar, and minor chert; estimate mostly fair porosity and permeability; oil indicators masked by oil based mud contamination. $980' Sand/Conalomeratic Sand = light olive gray to medium gray; fine to coarse grains, especially medium, with scattered to locally common very coarse grains and fragments; subangular to angular; moderate sphericity; moderately to poorly sorted; very slight overall kaolic clay matrix; occasional thin beds variably organic claystone and minor coal; 85% quartz, and 15% clay, coal, and minor tuff lithics, minor feldspar, and trace green lithics and chert; chert increasing in conglomeratic fraction; estimate mostly fair porosity and permeability; oil indicators masked by oil based mud contamination. 10100' Sand = very light gray overall; very fine to medium with abundant coarse; subangular to angular; low to moderate sphericity; the overall grain size increases with depth; composed of 80% quartz, 20% lithlcs with abundant chert and metamorphic minerals comprising the coarser grains; unconsolidated with rare consolidated cuttings grain supported with a ashy matrix and very poor intergranular porosity; occasionallamiOé~e of ash and clay as well as occasional horizons having very coarse and bit fractured larger grains; estimated poor to fair intergranular porosity; oil indicators masked by oil based mud contamination. 10195' Sand/Conglomeratic Sand = medium light gray to light olive gray; fine to very coarse, especially fine upper to coarse lower, and scattered coarse to pebble sized fragments; subangular to angular; moderately to poorly sorted in probable very slight overall clay matrix; occasional streaks kaolic claystone; 85% quartz, and 15% clay and coal, minor feldspar, chert, and siliceous metalithics, with chert and metalithics increasing in coarser fraction; estimate poor to fair intergranular porosity and permeability; oil indicators masked by oil based mud contamination. 10275' Clavstone = medium gray to brownish gray to brownish black; slightly firm and crunchy to crumbly; moderately hydrophilic; smooth to slightly silty texture; variably organic grading carbonaceous shale with streaks, thin beds and partings of lignite; some interbedded conglomerate and sand; noncalcareous; trace mica; trace disseminated pyrite associated with organic matter. 10330' Conglomeratic Sand = olive gray to medium gray; fine to coarse lower grains and scattered to common coarse to pebble sized fragments; angular to subangular; poorly to moderately sorted; overall very slight kaolic/ashy matrix and occasional streaks matrix supported sandstone and claystone; 85% quartz, and 15% clay and coallithics, metalithics, and feldspar; grading conglomerate with increasing lithics and clay matrix; estimate poor to fair porosity and permeability; oil indicators obscured by oil based mud contamination. 10420' Coal = black to brownish black; slightly to moderately firm and brittle to crunchy; hackly to irregular platy fracture; some visible lamina; lignite thin beds and streaks in variably organic claystone; traces micropyrite; slow bleeding gas. [:I EPOCH 6 UNOCAL8 G-12RD3 10460' ) Claystone = medium gray to brownish gray to brownish black; slightly firm; amorphous; abundant PDC= bit markings; smooth to earthy; some sandy grading kaolic sandstone; variably organic with streaks and thin beds of coal mostly lignite; hydrophilic; noncalcareous; some interbédded sand with mostly medium to fine grains and scattered coarse to trace pebble. 10515' Conglomeratic Sand/Sand = medium gray to olive gray; fine to coarse lower and scattered to occasionally common coarse fragments and minor pebble; angular to subangular; moderately to poorly sorted; overall slight kaolic clay matrix with streaks and thin beds matrix supported sand and claystone, some variably organic; 60% quartz, and 40% coal and clay lithies, and feldspar; estimate poor to fair porosity and permeability; oil indicators masked by oil based mud contamination. 10585' Coal = black to grayish black to brownish black; slightly firm and brittle; hackly to flaky fracture; slightly shiny luster; lignite; massive to thin bedded and as clasts in sand; grading to carbonaceous shale in part; traces micropyrite and very slight bleeding gas. 10625' ~and/Çonglomeratic Sand = medium gray to olive gray; fine to coarse lower and scattereq to rare common coarse fragments and local minor pebbles; angular to subangular; moderately to poorly sorted; overall slight kaolic clay matrix with streaks and thin beds matrix supported sand and claystone, some variably organic; 70% quartz, and 30% coal and clay lithies, and feldspar; estimate poor to fair porosity and permeability; oil indicators masked by oil based mud contamination. 10695' Coal = black to grayish black to brownish black; slightly firm and brittle; hackly to flaky fracture; slightly shiny luster; lignite; massive to thin bedded; grading to and interbedded with carbonaceous shale; some interbedded tuffaceous sand and claystone and conglomeratic sand; slight bleeding gas. ) 10740' Çonalomeratic Sand/Sand = medium gray to olive gray; fine to coarse lower and scattered to locally common coarse fragments and pebbles; angular to subangular; poorly to moderately sorted in slight to moderate kaolic/ashy clay matrix with streaks and thin beds matrix supported sandstone and claystone; 70% quartz and 30% lithies; estimate poor to fair porosity; oil masked by oil based mud 10800' Sand = light gray overall; very fine to medium with occasional coarse and bit fractured coarser grains; angular to subangular; low to moderate sphericity; moderate to poor sorting to occasional very poor sorting; composed of 60% 80% clear, transparent and smoky quartz, 20% 40% lithic fragments with proportionally more metamorphic-lithies in coarser grains; 80% 1 00% unconsolidated; consolidated grains are predominantly infilled with ash/clay matrix and have very poor intergranular porosity; estimated very poor to poor with common fair intergranular porosity; oil indicators masked by oil based mud. 10885' Coal = black to dark brownish black; hard; brittle; conchoidal to hackly with common sub planar fracture; irregular to jagged cuttings; resinous to vitreous luster; common visible banding; occasional partings of clay; very rare grading to carbonaceous shale; very minor visible bleeding gas. 10930' Tuffaceous Claystone = very light greenish gray to medium brownish gray; firm to stiff; crumbly; predominantly PDC= bit deformed cuttings; smooth to occasional gritty texture; matte to earthy luster; occasionally grades to siltstone as well as grading to carbonaceous shale in part; occasional visible laminations tuffaceous ash. [:I EPOCH 7 UNOCAL8 G-12RD3 . 10980' ) Coal = black to dark. brownish black; hard; brittle; conchoidal to hackly with common sub planar fracture; irregular to jagged cuttings; resinous to vitreous luster; common visible banding; occasional partings of clay; very rare grading to carbonaceous shale; very minor visible bleeding gas. 11025' Sand/~andstone = light gray overall; very fine to predominantly fine to medium; angular to subangular; low to moderate sphericity; moderate to well sorted; composed of 70% quartz, 30% lithic fragments, assorted minerals and coal; 50% consolidated with ash/clay matrix; porosity is entirely infilled; occasionally graces to siltstone; estimate very poor intergranular porosity; oil indicators obscured by oil based mud system. 11095' Clavstone = brownish gray to medium gray to medium light gray to grayish black; slightly firm to moderately soft; variably organic; smooth to earthy to slightly silty; light gray often sandy and kaolic occasionally grading sandstone; some grading to and interbedded with coal; hydrophilic; noncalcareous. 11140' Sandstpne/Sand = olive gray to medium light gray; medium to fine grains with locally scattered coarse to trace pebble; subangular to angular; moderate to high sphericity; moderately to some poorly sorted in very slight overall kaolic clay matrix and occasional streak of matrix supported sandstone and claystone; 85% quartz, and 15% clay and coallithics and minor feldspar and trace calcareous matter; estimate fair to poor porosity and permeability; oil indicators masked by oil base mud contamination. 11215' Sand/Sandstone = light olive gray to medium light gray; fine to coarse lower grains, and scattered very coarse to locally pebble sized grains and fragments; angular to subangular; moderately to poorly sorted in very slight overall clay matrix and rare streaks kaolic claystone and matrix supported sandstone; 90% quartz and 10% clay and coallithics, and minor feldspar; estimate fair to poor porosity and permeability; oil indicators masked by oil based mud contamination. ) 11285' Sandstone/S,ard = medium light gray to light olive gray; fine to coarse, especially medium, and scattered coarse to trace pebble sized fragments; subangular to angular; moderate sphericity; poorly to moderately sorted in slight to moderate kaolic-ashy matrix with streaks claystone and matrix supported sandstone; slight streaks coal/organic matter in claystone; 85-90% quartz; 1015% clay, coal, and minor feldspar and chert; estimate poor to fair porosity; oil indicators maskéd by oil base mud. 11375' Coal = black to dark. brownish black; hard; brittle; conchoidal to hackly with common sub planar fracture; irregular to jagged cuttings; resinous to vitreous luster; common visible banding; occasional partings of clay; very rare grading to carbonaceous shale. 11415' Tuffaceous Claystone = very light greenish gray to medium brownish gray; firm to stiff; crumbly; predominantly PDC= bit deformed cuttings; smooth to occasional gritty texture; matte to earthy luster; occasionally grades to siltstone as well as grading to carbonaceous shale in part; occasional visible laminations tuffaceous ash; hydrophilic; noncalcareous. 11470' Tuffaceous Siltstone = very light brownish gray to medium gray; finn to soft; brittle to malleable; irregular fracture with PDC= bit defonned cuttings; highly variable composition including quartz, lithics ash and abundant clay; common laminae of tuffaceous ash; grades to very fine sandstone in part; interbedded with and grading to tuffaceous clay. ~ EPOCH 8 UNOCAL8 G-12RD3 11520' ) Tuffaceous Claystone = very light greenish gray to medium brownish gray; firm to stiff; crumbly; predominantly PDC= bit deformed cuttings; smooth to occasional gritty texture; matte to earthy luster; occasionally grades to siltstone as well as grading to carbonaceous shale in part; occasional visible laminations tuffaceous ash; hydrophilic; noncalcareous. 11575' Sandstone/Sand = light gray overall; very fine lower to medium with rare coarser and bit fractured grains; angular overall; low to moderate sphericity; moderate sorting with local very poor sorting; composed of 60% quartz, 40% lithics and assorted minerals as well as transported coal; 30-50% matrix supported consolidated sandstone; consolidated cuttings are infilled with ash and clay and have very poor to no porosity; estimate poor to fair porosity with decreasing matrix; oil indicators masked by oil based mud contamination. 11660' Coal = black to grayish black to brownish black; moderately brittle; hackly to flaky fracture; slight to moderately shiny; lignite to subbituminous thinly bedded and grading to organic claystone. 11695' Tuffaceous Claystone = very light greenish gray to medium brownish gray; soft to firm; crumbly; predominantly PDC= bit deformed cuttings; smooth to occasional gritty texture; matte to earthy luster; occasionally grades to siltstone as well as grading to carbonaceous shale in part; hydrophilic; non-calcareous. ) 11740' Sandstone/Conglomeratic Sand = very fine to predominantly fine to medium with common to abundant coarse and bit fractured larger grains; very angular to angular; low sphericity; predominantly moderately sorted with well sorted horizons and common very poorly sorted laminations; composed of 60% 70% quartz 20% 30% lithic fragments, increasing chert and metamorphic-lithic content with increased grain size; 60% to 90% unconsolidated; sandstone cuttings are predominantly infilled with ash/clay matrix; predominantly grain supported; common laminae of tuffaceous ash; occasionally interbedded with clays; estimate very poor grading to occasional fair intergranular porosity; no visible oil indicators oil based mud. 11840' Claystone = brownish gray to medium dark gray to medium light gray to brownish black; slightly firm to moderately soft; variably organic grading carbonaceous shale with interbedded coal, mostly lignite; mostly smooth to earthy texture; some tuffaceous grading matrix supported kaolic sandstone and conglomeratic sand; hydrophilic; noncalcareous. 11890' Conalomeratic Sand/Sandstone = medium light gray to light olive gray; medium to fine grains and scattered to locally common coarse to pebble sized grains and fragments; subangular to angular; occasional bimodal rounded pebbles; poorly to moderately sorted with slight to moderate kaolic-ashy matrix occasionally grading matrix supported sandstone and conglomerate; 70-90% quartz, and 10-30% lithics, chert, metalithics, and feldspar; estimate mostly poor to occasionally fair porosity; oil indicators masked by oil base mud contamination. 11980' Sandstone/Conqlomeratic Sand = medium light gray to medium gray; fine to coarse lower grains and scattered coarse to pebble sized grains and fragments; subangular to angular, some bimodal rounded grains in coarser fraction; poorly to occasionally moderately sorted in ashy-kaolic matrix and often matrix supported grading to ash fall tuff, tuffaceous claystone, and variably organic claystone with minor coal; clasts include quartz, silicates partially altered to clay, reworked clay and coal; overall very poor porosity; oil indicators obscured by oil based mud contamination. ~ EPOCH 9 UNOCAL8 G-12RD3 12070' Sand = light gray overall; very fine to medium with abundant coarse and bit fractured coarser grains; angular to subangular; low to moderate sphericity; moderate to poor sorting to occasional very poor sorting; composed of 60% 80% clear, transparent and smoky quartz, 20% 40% lithic fragments with proportionally more metamorphic-lithics in coarser grains; 80% 100% unconsolidated; consolidated grains are predominantly infilled with ash/clay matrix and have very poor intergranular porosity; common laminae of tuffaceous 11260' 11280'; lower section commonly finely interbedded with silt, ash and clay with common carbonaceous streaks; estimate very poor to occasional fair intergranular porosity; no shows due to oil based mud. 12185' Sand/Sandstone = light gray overall; very fine to predominantly fine to medium; angular to subangular; low to moderate sphericity; moderate to well sorted; composed of 70% quartz, 30% lithic fragments, assorted minerals and coal; 30% consolidated with ash/clay matrix; porosity is commonly infilled; occasionally grades to siltstone; estimate very poor to poor intergranular porosity; oil indicators obscured by oil based mud 12245' Tuffaceous Claystone = very light greenish gray to medium brownish gray; soft to firm; crumbly; predominantly PDC= bit deformed cuttings; smooth to occasional gritty texture; matte to earthy luster; occasionally grades to siltstone as well as grading to carbonaceous shale in part; hydrophilic; non-calcareous. 12290' Sandstone/Conplomeratic Sand = very light gray to light greenish gray; very fine to predominantly fine to medium with abundant coarse and bit fractured larger grains; angular; low sphericity; poor to very poorly sorted; 70% quartz, 300/0 lithics; 70% consolidated with ash/clay matrix; poor estimated porosity; oil indicators masked by oil based mud contamination. ) 12345' Sandstone/Sand = medium light gray to olive gray; fine to coarse lower and scattered coarse to very coarse grains and fragments; angular to subangular; poorly to moderately sorted; poorly to moderately consolidated in kaolic clay matrix; occasional siliceous streak in matrix; 70% quartz, and 30% clay, minor coal, feldspar, and metalithics; estimate poor to some fair porosity; oil indicators obscured by oil based mud. 12420' Claystone = brownish gray to medium dark gray; slightly firm and crunchy to crumbly; moderately hydrophilic; smooth to silty texture; occasionally sandy grading sandstone; variably organic with interbedded coal; occasional calcite. 12455' Coal = black to some brownish black; hackly to flaky to occasional conchoidal fracture with visible lamina; massive with occasional interbedded organic claystone; traces micropyrite; slight bleeding gas. 12490' Sandstone/Sand = medium light gray to medium gray; fine upper to coarse lower grains and locally scattered coarse to trace pebble sized fragments; angular to subangular; poorly sorted and inter bedded with variably organic to kaolic claystone and minor siltstone and coal; poorly to some moderately consolidated in slight to moderate clay matrix; 80% quartz and 20% lithics and minor metalithics; estimate mostly poor to locally porosity; oil indicators obscured by oil based mud 12560' Tuffaceous Claystone = very light greenish gray to medium brownish gray; soft to firm; crumbly; irregular to subblocky cuttings; smooth to common gritty texture; matte to earthy luster; commonly grades to siltstone; occasional thin interbeds of carbonaceous material; in part; hydrophilic; non-calcareous. [j EPOCH 10 UNOCAL8 G-12RD3 12605' Tuffaceous Siltstone = very light brownish gray to medium gray; firm to soft; brittle to malleable; irregular and common sub planar fracture; highly variable composition including quartz, lithics; ash and abundant clay; common laminae of carbonaceous material; grades to very fine sandstone; interbedded with and grading to tuffaceous clay. 12655' Sandstone = very light gray to greenish gray to very light brownish gray; very fine lower to predominantly fine to medium with common to abundant coarse and bit fractured larger grains; angular to very angular, low to moderate sphericity; poor to very poor sorting; composed of 60% quartz, 30-40% lithic fragments, up to 10% carbonaceous material and other rip up clasts; 50% consolidated overall with high local variation; consolidated grains show common ash/clay infilling of porosity; grain supported; abundant tnin interbeds of clay, carbonaceous material and siltstone; sandstone commonly grades to siltstone; estimate very poor to poor with occasional fair intergranular porosity; oil indicators obscured by oil based mud 12755' Tuffaceous Claystone = very light greenish gray to medium brownish gray; soft to firm; crumbly; irregular to subblocky cuttings; smooth to common gritty texture; matte to earthy luster; commonly grades to siltstone; occasional thin interbeds of carbonaceous material; in part; hydrophilic; non-calcareous. 12805' Coal = black to dusky brownish black; firm; brittle; tabular, splintery and irregular cuttings habit; shiny luster; smooth texture; variable clay content; occasionally interlaminated with tuffaceous claystone; bituminous grade. ) 12845' Sand/Sandstone/Conglomerate = white, light gray to dark gray, rarely medium greenish gray; clasts range from very fine upper to pebble fragments; angular to subround; poorly sorted; composed of 70% quartz, 30% metamorphic and volcanic lithics; traces of chert; rare consolidated pieces have tuffaceous clay matrix, grain supported; very slightly calcareous; poor estimated porosity and permeability; oil indicators are obscured by oil based mud. 12925' Tuffaceous Claystone = light to medium brownish gray, light to medium greenish gray; soft to firm; crumbly to rarely moderately tough; irregular, blocky and tabular cuttings habit; matte, earthy luster with scattered to common sparkles; moderately smooth to occasional gritty texture; non to locally slightly calcareous; commonly with ashy appearance; locally silty, grading in part to tuffaceous siltstone. 12990' Tuffaceous Siltstone = light brownish gray to salt and pepper; firm to stiff; brittle to crumbly; irregular and common sub planar fracture; highly variable composition including quartz, lithics; ash and abundant clay; common laminae of carbonaceous material; grades to very fine sandstone; interbedded with and grading to tuffaceous clay. 13040' Coal = black to dark brownish black; hard; brittle; conchoidal to hackly with common sub planar fracture; irregular to jagged cuttings; resinous to vitreous luster; common visible banding; occasional partings of clay; occasional grading to carbonaceous shale. 13080' Tuffaceous Clavstone = very light greenish gray to medium brownish gray; soft to firm; crumbly; irregular to subblocky cuttings; smooth to common gritty texture; matte to earthy luster; commonly grades to siltstone; occasional thin interbeds of carbonaceous material; in part; hydrophilic; non-calcareous. ~ EPOCH 11 UNOCAL8 G..12RD3 13125' Sand = light gray overall; fine to medium with common coarse; very angular to subangular; low sphericity overall; poor to occasional moderate sorting; composed of 80% 90% quartz, 10% 20% lithics and other minerals; <95% unconsolidated in sample; very rare visible ashy/clayey matrix material; occasional laminae of siltstone grading to very fine sandstone in part; occasional laminae of ash; estimated fair porosity and permeability. 13225' Tuffaceous Clavstone = very light greenish gray to medium brownish gray; soft to firm; crumbly; irregular to subblocky cuttings; smooth to common gritty texture; matte to earthy luster; commonly grades to siltstone; occasional thin interbeds of carbonaceous material; in part; hydrophilic; non-calcareous. 13270' Sandstone = light gray overall; very fine lower to fine upper with abundant coarse and larger bit fractured grains; subangular to angular; moderate sphericity; predominantly well sorted; composed of 70% quartz, 30% lithics and assorted minerals; coarse and pebble size contain proportionally more metamorphic-lithics; 700/0 consolidated; siliceous cement with occasional clay and rare ash matrix; commonly grades to siltstone; finely interbedded with silt and clay; estimate very poor to poor intergranular porosity no visible oil indicators. 13350' Sand/Sandstone/Co~glomerate = white, clear, light to dark gray, medium greenish gray, occasional dark reddish orange; clasts range from very fine upper to pebble fragments; angular to rounded; larger grains are dominantly more angular; common pitted grains; common bit sheared grains; poorly sorted overall; composed of 70 to 80% quartz and other siliceous minerals, 20 to 30% metamorphic and volcanic lithics; distinctive trace amts of jasper; firm when consolidated; tuffaceous clay matrix; dominantly grain supported; non calcareous to occasionally very slightly calcareous; common interbeds of tuffaceous claystone/ash fall tuff; occasional interbeds of carbonaceous shale grading in part to argillaceous coal; estimated porosity ranges from poor to good in the "cleaner" sands; oil indicators are obscured by oil based mud. ) 13480' Sa,nd/Sandstone/Conglomerate = variable colored, dominantly milky white, light to medium gray; occasional light to medium greenish gray; rarely reddish orange; clasts range from very fine to pebble fragments; angular to well rounded; finer fraction is common subround to well rounded; coarser fraction is mostly subangular to angular; poorly sorted; composed of 70% quartz and other siliceous minerals; 30% metamorphic and volcanic lithics; traces of jasper; friable to firm when consolidated; ashy clay matrix; non to very slightly calcareous; dominantly grain supported; "cleaner" appearing zones with fair estimated porosity and permeability; common thin ashy beds; oil indicators remain obscured by oil based mud. 13595' Tuffaceous Claystone = very light greenish gray to medium brownish gray; soft to firm; crumbly; irregular to subblocky cuttings; smooth to common gritty texture; matte to earthy luster; commonly grades to siltstone; common disseminated carbonaceous material; slightly hydrophilic; non-calcareous micromicaceous; abundant laminae of tuffaceous ash. 13650' Sand/Conglomeratic Sandstone = very light gray to light greenish gray to light beige; very fine to medium with abundant coarse and bit fractured larger grains; very angular to subangular; low sphericity; poor to very poor sorting; composed of 50% quartz, 30% metamorphic-lithics and 20% other lithics and assorted minerals; coarser cuttings show distinct grain alignment; abundant ash infilling porosity; common chloritization in ash; estimate very poor to poor intergranular porosity with oil indicators masked by oil based mud. ~ EPOCH 12 UNOCAL8 G-12RD3 13720' ) Tuffaceous Siltstone = light brownish gray to salt and pepper; firm to stiff; brittle to crumbly; irregular and common sub planar fracture; highly variable composition including quartz, lithics; ash and abundant clay; commonly grades to very fine sandstone. 13765' Sand/Sandstone/Conglomera~e = multicolored with dominantly milky white, light gray, pale greenish gray; friable when consolidated; clasts range from very fine lower to pebble fragments; angular to well rounded; common pitted grains; common bit sheared grains; poorly sorted; composed of 70% quartz and other siliceous minerals, 30% metamorphic and volcanic lithics; rare jasper grains; dominantly unconsolidated; ashy clay matrix when present; dominantly grain supported; dominantly non to very slightly calcareous; locally moderately to very calcareous; estimate fair visual porosity and permeability; oil indicators are obscured by oil based mud. 13870' Sand/Sandstone/Conglomerate = light to medium gray to greenish gray; very fine to very coarse with abundant bit broken pebble size grains; angular to subround; low to moderate sphericity; overall very poor sorting with local moderately to well sorted; composed of 40% quartz, 30% metamorphic-lithics, 30% other lithics and minerals; ranges from 30% 70% consolidated; commonly grain supported with siliceous cement and minor matrix as well as tuff ash matrix supported; abundant laminations of tuff ash ranging from mm to cm thick; estimate overall very poor intergranular porosity, oil indicators obscured by oil based mud 13960' Sand/Sandstone/Conglomerate = light greenish gray overall; dominantly milky white, light to dark greenish gray, light to medium gray, black, rare reddish orange; clasts range from very fine lower to pebble fragments; angular to well rounded; poorly sorted; composed of 60% quartz and other siliceous minerals, 40% metamorphic and volcanic lithics; common free chunks of tuffaceous material, assumed to be matrix; friable when consolidated; very slight acid reaction overall; estimated fair porosity and permeability in "cleaner" sections; oil show indicators obscured. 14030' Tuffaceous Clav = very light gray to very light greenish gray; firm to stiff; crumbly to brittle; irregular to subplanar fracture; massive cuttings habit; matte to common sparkly luster; micromicaceous in part; commonly grades to siltstone; interbedded with silt, sand and ash. 14071' Total Depth: 9995' TVD @ 06/05/02 1630hrs. [j EPOCH 13 UNOCAL8 G-12RD3 DAILY ACTIVITY SUMMARY Epoch Well Services on location 05/14/02 and commenced logging at 8277'. 05/15/2002 Make up the bottom hole assembly and run into the hole. Orient and set the whipstock at 8300'. Displace the hole to oil based mud while continuing to on load and build volume in pits. Circulate and condition mud prior to milling the window from 8276' to 8310'. Work pipe through window and clean the hole. 05/16/2002 Perform Formation Integrity Test (Okay) before pulling out of the hole for Bottom Hole Assembly #3. Lay down mill and make up bottom hole assembly #3. Run into the hole and begin drilling 8 %" directional hole to a midnight depth of 8476'. 05/17/2002 Continue drilling ahead sliding for well path to a midnight depth of 9023'. 05/18/2002 Continue drilling ahead 8 %" directional sliding as required for well path to 9564'. Circulate hole clean and trip out 4009'. Pick up pipe and run into the hole. Resume drilling to a midnight depth of 9601'. 05/19/2002 Continue drilling ahead sliding as necessary to maintain well path to a midnight depth of 1 0082' OS/20/2002 Continue to drill ahead with very poor result to a depth of 1 0091'. Circulate hole and mix a weighted high viscosity sweep. Pumped the sweep around and pumped a dry job before pulling out of the hole for a new bit. ) OS/21/02 Finish picking up new BHA with new bit #3 and mud motor; pick up and run in hole with 72 joints (24 stands) of drill pipe; run in hole to window and cut and slip drill line; work pipe through window and wash and ream to bottom; drill ahead, rotating from 10092' to 10350', and sliding from 10350' to 10355'. OS/22/02 Drill ahead, rotating and sliding, from 10355' to 10481'; work pipe and condition hole, building mud weight from 9.2 to 9.4 ppg; pull out of hole to shoe and pump dry job; pull out of hole for new bit #4, mud motor, and stabilizer; trip in hole and drill ahead from 10478-10520'. OS/23/02 Drill ahead from 10520'to 11332', sliding from 11186to 11212'. OS/24/02 Drill ahead from 11332' to 11694', sliding from 11549-63' and 11659-68'; wash for logging from 11629-94' after Anadril encoder failure; circulate and condition mud and pump dry job to begin trip for bit. OS/25/02 Trip out of the hole for bit #5 (RR#2) and new mud motor; trip to bottom, 76 units of trip gas; drill ahead, rotating and sliding, from 11694' to 12004'. OS/26/02 Drill ahead, rotating and sliding, from 12004' to 12187'; pull out of hole for new bit #6 (tri-cone) and mud motor; test BOPs. OS/27/02 Run in with BHA with new bit #6 (tri-cone) and new mud motor, and trip to bottom; drill ahead, rotating and sliding, from 12187' to 12433'. ) U EPOCH 14 UNOCAL8 G-12RD3 OS/28/02 ) Drill from 12430' to 12700', change out swab in #2 pump, Drill from 12700' to 12864', slide from 12864' to 12937'. OS/29/02 Drill and slide from 12937' to 13003', check for flow-no flow. Drill to 13173', well flowing. Stand back two stands and shut in well. Record pressures: DP=860, CSG=300, 10 barrel gain. Circulate kick out of hole with driller's method. Shut down pumping and record pressures: DP=860, CSG=580. Continue circulating with driller's method, shut down pump. Record pressures: DP=840, CSG=560. Monitor for 15 minutes. DP=800, CSG=600, bled down casing to 500. Monitor for 15 minutes. DP=780, CSG=480. Bled down casing to 400. Rose to 460; bled down to 400; rose to 460. Began killing well with 9.8 PPG mud. 05/30/02 Weight up surface mud system to 10.1 ppg. Monitor well on choke (380psi), reciprocate pipe. Bleed pressure as needed. Build 100 bbl of 17.0 ppg mud. Begin second circulation with 10.1 ppg mud. Breaker tripped on mix pump-shut down circulation. Shut in well. Continue circulation. Pressure on choke was 200 psi. Monitor and bleed pressures as needed. Get 10.1 ppg all around. Get 10.4 ppg mud all around, well still flowing. Get 10.7 ppg mud all around. Monitor well. Perform FIT. 05/31/02 Ream 13055' to 13173'. Drill and slide to 13345', plugged jet. Drill to report depth. 06/01/02 Drill to 13501', circulate bottoms up, pump 6 stands out of hole, monitor well, POOH, test BOPE, pick up new BHA. 06/02/02 Run into hole, pick up 12 joints drill pipe, run in hole to 5500', circulate and condition mud. Run in hole to shoe, cut off drilling line. Run in hole to 13411'. Tight spots at 12003' to 12130', 13230' to 13385'. Ream 13411' to 13431'. Trouble shoot pumps and top drive. Mud too thick, circulate with one pump. Clean suction screen on #1 pump. Ream from 13437' to 13452'. Clean suction and discharge screens on pumps. Circulate at minimum rate while welder repairs suction screen for pump #2. Circulate over shakers to remove solids from pit system. Ream 13452' to 13501'. Drill from 13501' to 13509'. Plugged suction screen on pump #1. Drill from 13509' to 13541' with one mud pump. Clean pits. 06/03/02 Drill ahead rotating the whole way from 13541' to 13832'. 06/04/02 Drill from 13832' to Total Depth at 14020', then circulate bottoms up. Begin MAD pass from Total Depth to 12500'. 06/05/02 Continue MAD pass then RIH to bottom and continue drilling ahead to the new total depth at 14071'. Wiper trip 12 stands and circulate hole clean (300 units of wiper gas). Begin trip out of the hole for casing. 06/06/02 Continue to trip out of the hole for casing. Well not taking the correct fill. Trip back to bottom and begin circulating and conditioning the mud (335 units of trip gas). Increase mud weight to 11.1 ppg. Begin tripping out of the hole for casing. ~ EPOCH 15 UNOCAL8 G-12RD3 ) SURVEY SURflMARY MD Incl Azim Course TVD Vertical Displacement Diaplacement Total At Azimuth Dogleg Length Section (+N I -S) (+E I -W) Displacement (ft) (°) (°) (ft) (ft) (ft) (ft) (ft) (ft) (°) (°/100') 8200 42.75 154.00 0 5932.05 5151.80 "3784.34 3548.36 5187.69 136.84 0 8313.05 43.98 150.41 113.05 6014.25 5223.70 -3852.97 3584.57 5262.56 137.07 2.44 8351.69 45.37 146.21 38.64 6041.73 5249.50 -3876.07 3598.84 5289.20 137.12 8.44 8447.52 46.84 136.51 95.83 6108.25 5317.08 -3929.84 3641.92 5357.91 137.18 7.45 8542.18 45.44 131 .45 94.66 6173.86 5385.13 -3977.23 3690.98 5426.01 137.14 4.13 8637.73 44.96 128.10 95.55 6241.20 5452.91 -4020.60 3743.06 5493.24 137.05 2.54 8689.76 43.90 123.96 52.03 6278.36 5489.23 -4042.02 3772.50 5528.99 136.98 5.93 8732.82 44.02 123.34 43.06 6309.36 5518.93 -4058.58 3797.38 5558.08 136.90 1.04 8828.74 44.48 119.32 95.92 6378.08 5585.05 -4093.36 3854.53 5622.55 136.72 2.96 8922.73 44.64 118.87 93.99 6445.05 5649.78 -4125.43 3912.16 5685.44 136.52 0.38 9020.64 45.34 119.28 97.91 6514.29 5717.73 -4159.07 3972.66 5751.51 136.31 0.77 9113.75 46.23 119.34 93.11 6579.22 5783.28 "4191.74 4030.85 5815.36 136.12 0.96 9208.19 45.88 119.44 94.44 6644.76 5850.09 -4225.11 4090.09 5880.51 135.93 0.38 9302.95 45.36 119.14 94.76 6711.04 5916.62 -4258.24 4149.16 5945.43 135.74 0.59 9396.77 45.63 119.10 93.82 6776.80 5982.30 "4290.80 4207.61 6009.58 135.56 0.29 9491.36 46.22 119.02 94.59 6842.60 6049.00 -4323.81 4267.02 6074.77 135.38 0.63 j88.57 45.96 119.40 97.31 6910.09 6117.84 "4358.02 4328.21 6142.13 135.20 0.39 84.00 45.99 119.42 95.33 6976.34 6185.20 -4391.68 4387.92 6208.12 135.02 0.03 777.67 43.76 119.78 93.67 7042.71 6250.18 -4424.32 4445.38 6271.85 134.86 2.40 9874.03 43.99 120.07 96.36 7112.18 6315.91 "4457.64 4503.26 6336.40 134.71 0.32 9970.16 44.38 120.40 96.13 7181.11 6381.92 -4491.38 4561.15 6401.29 134.56 0.47 10029.02 44.29 119.75 58.86 7223.21 6422.43 -4511.99 4596.75 6441.13 134.47 0.79 10051.41 44.12 120.13 22.39 7239.26 6437.79 -4519.78 4610.27 6456.24 134.43 1.41 10147.01 44.92 120.16 95.60 7307.42 6503.82 -4553.44 4668.24 6521 .22 134.29 0.84 10237.93 45.09 119.67 90.92 7371.71 6567.10 -4585.51 4723.97 6583.52 134.15 0.42 10336.90 45.31 119.74 98.97 7441.45 6636.17 -4620.31 4784.96 6651.55 134.00 0.23 10417.15 45.45 119.86 80.25 7497.81 6692.37 -4648.70 4834.53 6706.94 133.88 0.20 10432.23 45.47 119.23 15.08 7508.39 6702.94 -4654.00 4843.88 6717.36 133.85 2.98 10529.05 45.07 119.00 96.82 7576.53 6770.46 -4687.46 4903.97 6783.90 133.71 0.45 10624.61 44.57 118.83 95.56 7644.31 6836.54 -4720.03 4962.94 6849.05 133.56 0.54 10719.19 43.87 118.61 94.58 7712.09 6901.20 -4751.73 5020.78 6912.83 133.42 0.76 10814.07 43.42 119.00 94.88 7780.75 6965.42 -4783.28 5078.16 6976.21 133.29 0.55 10907.35 43.05 118.40 93.28 7848.71 7028.06 -4813.97 5134.21 7038.07 133.16 0.59 11005.14 42.20 118.85 97.79 7920.67 7092.95 -4845.69 5192.34 7102.19 133.02 0.92 11099.17 41.58 118.49 94.03 7990.66 7154.49 -4875.81 5247.42 7163.03 132.90 0.71 11194.36 41.61 118.03 95.19 8061.85 7216.34 -4905.73 5303.08 7224.19 132.77 0.32 11288.38 41.99 117.62 94.02 8131.94 7277.57 -4934.98 5358.50 7284.75 132.64 0.50 11386.22 41.02 117.16 97.84 8205.21 7340.82 -4964.81 5416.07 7347.33 132.51 1.04 )477.60 39.84 116.89 91.38 8274.77 7398.55 -4991.74 5468.86 7404.45 132.39 1.31 ) - 573.63 38.64 116.64 96.03 8349.14 7457.65 -5019.10 5523.1 7462.97 132.26 1.26 ~ EPOCH 16 UNOCAL8 G-12RD3 )MD Incl Azim Course TVD Vertical Displacement Diaplacement Total At Dogleg Length Section (+N I -S) (+E I-W) Displacement Azimuth (ft) (°) (°) (ft) (ft) (ft) (ft) (ft) (ft) (°) (°/100') 11667.64 37.85 115.86 94.01 8422.83 7515.35 -5049.41 5573 7520.29 132.18 1.1 11756.11 38.75 115.78 88.47 8492.26 7568.48 -5073.29 5622.35 7572.92 132.06 1.02 11858.83 39.27 115.68 102.72 8572.08 7631.12 -5101.36 5680.60 7634.99 131 .92 0.51 11952.03 39.79 115.76 93.20 8643.96 7688.58 -5127.10 5734.04 7691.97 131 .80 0.56 12048.79 40.13 115.03 96.76 8718.13 7748.69 -5153.75 5790.18 7751.60 131.67 0.60 12118.97 39.01 114.42 70.18 8772.23 7791.79 -5172.45 5830.79 7794.38 131.58 1.69 12145.50 38.85 114.46 26.53 8792.86 7808.39 -5181.32 5845.02 7810.91 131.56 1.46 12241.43 41.31 115.09 95.93 8866.26 7867.96 -5207.21 5901.09 7870.06 131.43 2.60 12335.53 43.00 115.30 94.10 8936.02 7928.98 -5234.10 5958.23 7930.72 131 .30 1.80 12431.65 42.99 115.31 96.12 9006.32 7992.36 -5262.11 6017.49 7993.75 131.17 0.01 12526.50 43.02 116.05 94.85 9075.68 8055.01 -5290.15 6075.79 8056.11 131.05 0.53 12618.88 43.44 116.54 92.38 9142.99 8116.46 -5318.18 6132.52 8117.31 130.93 0.58 12715.44 43.91 117.52 96.56 9212.83 8181.41 -5348.48 6191.91 8182.06 130.82 0.85 12808.87 44.36 117.77 93.43 9279.89 8244.94 -5378.67 6249.55 8245.42 130.72 0.52 12903.69 46.90 118.51 94.82 9346.19 8311.25 -5410.64 6309.31 8311.58 130.62 2.74 12999.10 50.75 119.80 95.41 9408.99 8381.74 -5445.64 6372.00 8381.97 130.52 4.16 13095.08 53.36 120.91 95.98 9468.01 8456.33 -5483.90 6437.30 8456.47 130.43 2.87 13190.35 53.80 120.19 95.27 9524.57 8531.93 -5522.86 6503.32 8532.01 130.34 0.76 ~83.67 57.79 120.15 93.32 9577.02 8607.94 -5561.64 6570.03 8607.97 130.25 4.28 { 377.85 57.97 120.05 94.18 9627.09 8686.49 -5601.65 6639.03 8686.5 130.16 0.21 13442.53 58.18 120.17 64.68 9661.30 8740.56 -5629.19 6686.52 8740.56 130.09 0.36 13484.19 58.31 119.93 41.66 9683.22 8775.44 -5646.92 6717.19 8775.44 130.05 0.58 13574.21 58.46 120.08 90.02 9730.41 8850.91 -5685.26 6783.57 8850.93 129.97 0.22 13672.44 58.29 120.16 98.23 9781.92 8933.29 -5727.23 6855.92 8933.36 129.87 0.19 13766.90 58.26 120.10 94.46 9831.59 9012.42 -5767.56 6925.41 9012.55 129.79 0.06 13860.85 58.15 120.96 93.95 9881.06 9093.00 -5819.00 6987.44 9093.13 129.79 0.30 13952.76 57.19 120.95 91.91 9930.21 9169.67 -5858.95 7054.04 9169.88 129.71 1.04 14003.72 56.82 120.97 50.96 9957.96 9211.87 -5880.94 7090.69 9212.13 129.67 0.73 14070.00 56.30 120.97 66.28 9994.49 9266.48 -5909.40 7138.11 9266.80 129.62 0.78 U EPOCH 17 UNOCAL8 G-12RD3 MUD SUMMARY DEPTHI API fluid API E- DATE TVD WT VIS PV YP GELS loss FiI CK SOL OillWtr Pom CI Ca Stab 05/15/02 8310/6007 9.2 101 17 18 19/27/30 NC 6.2 2 7.96 86/14 1.2 26500 1.56 1587 05/16/20 8351/6045 9.25 108 23 19 23/25/28 NC 5.2 2 8.18 85/15 1.15 22000 1.50 1567 05/17/02 8973/6455 9.2 94 24 20 26/29/30 NC 4.8 2 7.0 85/15 1.2 26000 1.56 1842 05/18/02 9590/6843 9.25 117 25 19 27/30/31 NC 4.8 2 7.91 85/15 1.25 28000 1.63 1804 05/19/02 10073/7255 9.20 91 24 20 26/31/33 NC 4.6 2 7.79 85/15 1.10 26500 1.43 1754 OS/20/02 10091/7268 9.20 138 25 18 26/29/31 NC 4.6 2 7.49 85/15 1.05 26000 1.37 1738 OS/21/02 10355/7454 9.25 113 23 18 21/32/33 NC 5.2 2 9.0 86/15 1.45 31000 1.45 1654 OS/22/02 10490/7551 9.45 139 25 18 21/30/33 NC 5.2 2 8.7 84/16 1.75 32500 2.28 1555 OS/23/02 11329/8161 9.40 117 24 18 24/32/34 NC 5.0 2 9.0 87.13 1.2 31000 1.56 1565 OS/24/02 11694/8442 9.4 113 24 19 2231/33 NC 5.4 10 8.88 86/14 1.2 35000 1.56 1465 OS/25/02 11967/8662 9.40 128 26 18 24/31/34 NC 5.2 2 8.56 86/14 1.6 35000 2.08 1495 OS/26/02 12188/8825 9.45 138 23 18 20/30/31 NC 5.4 2 10.00 87/13 1.9 30000 2.47 1455 OS/27/02 12425/9002 9.4 112 24 18 19/29/32 NC 5.4 2 8.70 86/14 1.9 32000 2.47 1410 OS/28/02 12926/9358 9.40 101 25 21 25/31/33 NC 4.8 2 8.76 85/15 1.5 31000 1.95 1387 OS/29/02 13172/9517 9.70 168 28 39 40/43/44 NC 6.8 2 9.63 78/22 1.25 24000 11.04 1001 05/30/02 13172/9517 10.70 185 28 41 41/50/52 NC 2.4 2 15.98 81/19 1.1 27000 1.43 1339 05/31/02 13419/9649 10.70 116 28 36 34/46/47 NC 2.8 2 13.31 80/20 1.15 31000 1.5 1133 06/01/02 13501/9692 10.75 220 28 36 34/46/47 NC 2.8 2 13.31 80/20 1.15 31000 1.5 1094 06/02/02 13541/9713 10.75 143 30 37 37/47/49 NC 2.6 2 15.00 79/21 1.05 29000 1.37 1021 06/03/02 13829/9864 10.75 92 27 26 27/36/37 NC 2.8 2 13.73 81/19 0.90 32500 1.17 1132 06/04/02 14020/9967 10.7 87 25 22 22/34/36 NC 3.6 2 13.73 81/19 1.10 32500 1.43 1054 06/05/02 14071/9995 10.7 91 26 23 23/34/36 NC 3.2 2 13.24 82/18 1.00 32000 1.30 1121 ~ EPOCH 18 '\,~' ,,~ UNOCAL8 G-12RD3 BIT RECORD BIT SERIAL SIZE JETS DEPTH DEPTH FEET HOURS AVG AVG # # INCHES MAKE TYPE (in IN OUT TOTAL TOTAL FT/HR woe 32nds) Mill 8.510 Smith Mill 6X12 8277 8310 33 3.68 5.09 1-5k 1 JS7481 8.5 Smith MDT34SPX 6X12 8310 10092 1782 36.0 49.50 11k 2 5013156 8.5 Security FM2843 4X14 10092 10478 389 10.9 35.75 9k 3 5013157 8.5 Security FM2843 4X14 10478 11694 1216 34.7 35.04 9k 2RR 5013156 8.5 Security FM2843 4X14 11694 12186 492 19.3 25.49 13k 4 6004807 8.5 Hughes MX-20DX2DT1 3X16 12186 13501 1315 69.4 18.95 32k 5 6003505 8.5 Hughes MX-20DX2DT1 3X16 13501 14071 571 45.8 12.47 25k [;I EPOCH 19 '-/ UNOCAL8 G-12RD3 05/14/02 05/16/02 05/18/02 OS/20/02 OS/22/02 OS/24102 OS/26/02 OS/28/02 05/30/02 06/01/02 06/03/02 06/05/02 06/07/02 08000' 09000' 1 0000' 11000' 12000' 13000' 14000' 15000' Well spu :Jded 05/14/02 at 1800 hrs. K~ck orr point: õ277'. DAYS VERSESD.&PTH ~ EPOCH 20 '-'" Re: G-12RD3 BOPE Test ) ) Subject: Re: G-12RD3 BOPE Test Date: Sun, 05 May 2002 12:29:48 -0800 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: "Buster, Larry W -Alaska" <lbuster@unocaLcom> CC: AOGCC North Slope Office <aogcc_prudhoe_bay@admin.state.ak.us> ()'Jd--D>5 Larry, Your understanding is correct. Since the pool rules give a waiver to having to submit 403s for certain operations, the first paperwork I got to see was for the G-12RD3. I am aware that the Inspectors have witnessed 2 tests on Grayling and the recent performance has been good. By copy of this email, the BOP test pressure for the G-12RD3 need not be greater than 4000 psi. Good luck. Tom Maunder, PE AOGCC "Buster, Larry W -Alaska" wrote: Tom, Further to our conversation with reference to the BOPE testing requirements for the G-12RD3 Well- the following is a summary of my understanding of the testing criteria and a request for a variation in the BOPE Maximum Test Pressure. The Current Permit to Drill (AOGCC Form 401 #202-055 dated 4/4/02) requires a 5,000 psi initial BOPE and then to 4,000 psi thereafter. The calculated Maximum Anticipated Surface Pressure is stated as 3,742 psi. The reason a 5,000 psi initial test is required (and not 4,000 psi) is because it was represented this would be the first well, and therefore the first time the sack would be tested. However, we have worked the stack on both the G-7 and the G-29 wells, on which it was successfully tested to a maximum of 3,000 psi. Therefore, I respectfullv reQuest we be allowed to initially test the G-12RD3 BOPE to a maximum of 4.000 psi and operate under this criteria for the duration of the well. Thank You and Regards, Larry W. Buster Advising Drilling Engineer Unocal Alaska (907) 263-7804 - Office (907) 263-7884 - Fax (907) 351-6730 - Mob. Tom Maunder <tom maunder@admin.state.ak.us> I Sr. Petroleum Engineer I Alaska Oil and Gas Conservation Commission 10f2 5/5/02 12:45 PM @ ~ Ã ~:-e ~ F ð ~ !f1\ @ - '1 f;\ tY) . fl... J: ~ JL, ~¡ro tY) - ~~ A.IfA.SIiA. OIL AND GAS CONSERVATION COMMISSION ADMINISTRATIVE APPROVAL NO. 80.85 ) TONY KNOWLES, GOVERNOR 333 W. 7fH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: The application of Union Oil Company of California, operator of the Trading Bay Unit (TBU), to drill and complete the TBU G-12RD3 well as part of the pressure maintenance project approved by Conservation Order No. 80. Shannon W. Martin Land/Lega1 Analyst UNOCAL Corporation POBox 190247 Anchorage, AK. 99519-0247 Dear Mr. Martin: Your application dated February 21,2002 for a "Permit to Drill" TBU well G-12RD3 is proposed to recover additional oil from the Hemlock oil pool. The Alaska Oil and Gas Conservation Commission hereby authorizes the drilling and completion of the TBU G-12RD3 well pursuant to Rule 5 of Conservation Order 80. DATED at Anchorage, Alaska and dated Apri14, 2002. ~ bm~ Chair BY ORDER OF THE COMMISSION æOIL~ ~I~~ \~líì~~~~~~ .. ~\I'J.rJ:~!"\"¡"ì'~<.~ :;';''-'':;';~'1;~~ ~;!Z~ :~.< ::(:~':1;~~:;.';'~ ~ ~~ "~¿Sillt1t~~~~ ~ 1'IONCó'J\~~ ør£t Commissioner ~~il ~ E : F !Æ ~!Æ~ ~~~ AI,ASIiA. OIL AND GAS CONSERVATION COMMISSION TONY KNOWLES, GOVERNOR 333 W. -pH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Dan Williamson . Drilling Manager Unocal PO Box 196247 Anchorage AK 99519-6247 Re: Trading Bay Unit G-12RD3 Unocal Permit No: 202-055 Sur Loc: 1873' FSL and 1386' FEL, Sec. 29, T9N,R13W, SM Btmhole Loc. 1478' FSL and 5216 FEL, Sec. 34, T9N, R13W, SM Dear Mr. Williamson: Enclosed is the approved application for permit to redrill the above referenced well. The permit to redrill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Annular disposal has not been requested as part of the Permit to Drill application for Trading Bay Unit G-12RD3. Blowout prevention equipment (BOPE) must be tested in accordance with 20AAC 25035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Sincerely, ~(kU'~L/ Cammy O~éhsli Taylor- - D-" Chair . BY ORDER OF THE COMMISSION DATED this~ day of April, 2002 jjc/Enclosures cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation wlo encl. 1 a. Type of work Drill Redrill X Re-entry Deepen 2. Name of Operator Unocal 3. Address P. O. Box 196247 Anchorage, AK 99519-6247 4. Location of well at surface (Leg #2, Conductor #37) 1873' FSL and 1386' FEL Sec. 29, T9N, R13W, SM At top of productive interval (9600' tvd) 1586 FSL and 136 FEL Sec. 33, T9N, R13W, SM At total depth .1478 FSL and 5216 FEL Sec. 34, T9N, R13W, SM 12. Distance to nearest 13. Distance to nearest well property line 3058' @ 13602' (9845' tvd) N- 3400' Redoubt ST1 ) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1 b. Type of well Exploratory Stratigraphic Test Development Oil X Service Development Gas Single Zone X Multiple Zone 5. Datum Elevation (OF or KB) 10. Field and Pool 103' KB to MSL est McArthur River Field 6. Property Designation Hemlock Formation ADL-17594 ~k ~ I L-1DL k ~/~~ REVISED 7. Unit or Property Name Trading Bay Unit 8. Well Number G-12RD3 9. Approximate spud date 4/22/02 14. Number of acres in property 11. Type Bond (see 20AAC25.025) AK Statewide Oil & Gas Bond Number U 62-9269 Amount 16. To be completed for deviated wells Kickoff depth 8200 feet Maximum hole angle 44.12° 18. Casing program size Specifications Hole Casing Weight Grade Coupling 8-1/2" 7" 29 L-80 Butt KC Length 5608' $200,000 15 Proposed depth (MD and TVD) 13,608' MD Lease 3840 acres 9,849' TVD 17. Anticipated pressure (see 20 MC 25.035 (e)(2) Maximum Surface 3>'\"\6.'1 At ¡Qtal depth 9850' (TVD) Setting Depth 'tf¿~ ' Top Bottom Quantity of cement TVD MD TVD 5781' 13608' 9849' 748 sxs Class G blend MD 8000' 19. To be completed for Redrill, Re-entry and Deepen Operations Present well condition summary Total depth: measured true verical feet feet Plugs (measured) Effective Depth measured true vertical feet feet Junk (measured) Casing Structural Conductor Surface Intermediate Production 10257' 9-5/8" Window 10257' Liner 4036' 7" 700 sxs 13782' Perforation Depth: measured 12305' -12732 (intermittent) 12975'-13008', 13265'-13390' true vertical 8960'-9296',9488'-9512',9700'-9800' 20. Attachments: Filing Fee X Property Plat X BOP Sketch X Diverter Sketch X Drilling Program X Drilling Fluids Program X Time vs. Depth Plot Refraction Analysis Seabed Report 20AAC25.050 Requirements X 21. I her~~~ th~ 1. ertify.th t~71?~ ~o~~;/mBAand correct to the best of my knowledge r2 -I"] ¡. -/?)e Signed \tC).YIv\.Å~ V(/\Xv'l{)AN'Y I \. Title: Drilling Manager Date Q - ~ V t-- Commission Use Only Permit Number API Number Approval date L\ ì \ O~ See cover letter ..2 0 ¿ - oS' Ç" 50- 7.33 - .2~,y6 -~ 3 \. '--\ ',' for other requirements Conditions of approval samPle~qUired Yes Mud log required Yes Œ9) Hydrogen Sulfide measures es No Directio al Survey required ¡<¡¡;¡, No Required wo[ki(1g pressure for E 2M 3M 5M 10M 15M C7 Other: 5~OG~\ "\~\-\\Ct.\ ~O ~~Cð~ L\OOÙÇŠ\ "",\~\~Qf\+h<l.~~~¡{õf Approved by Commissioner the commission Date Form 1 0-401 Rev. 12-1-85 Original Signed By Cammy Oechsli Length 369' 602' 6013' Size 26" 17-3/4" 13-3/8" Cemented Driven 775 sxs 2525 sxs Measured Depth True Vertical Depth 369' 369' 602' 602' 6013' 4237' 7439' 10095' l\ . W . Ól~ Submit in triplicate ORIG\NAL UNOCALe RKB to TBG Head = 43.2' () L .J .J 2 3 .J 8,000' Z Z 8,200' L ~ .J .J .J 4 >< z 6 . . ~5 = HB = Sands /" ~ TD = 13,608' (9849' tvd) G-12 RD3 rev! Schematic.doc ~ ) CASING AND TUBING DETAIL SIZE 26" GRADE CONN WT 1/2" Wall 17-3/4" .312 wall Weld 13-3/8" 61 K-55 Butt 12.515 9-5/8" 47 P-110 Seal Lock 8.681 9-5/8" 40# N-80 Seal Lock 8.835 9-5/8" 43.5# N-80 Seal Lock 8.755 D V Co liar ----------------------------------------------------------------------- 9-5/8" 43.5# N-80 Seal Lock 8.755 7" (liner) 29 N-80 Tubing: 4-1/2" 12.6 L-80 3-1/2" 9.3 L-80 Butt BTC-Imp BTC-Imp Trading Bay Unit Well G-12RD3 Proposed ID MD MD TOP BTM. Surf 369' Surf. 602' Surf. 6,013' Surf 73' 73 6,252' 6,251' 6,939' 6,939' 6,941' 6,941' 8,200' (window) 8,000' 13,608' Surf 8,000' 8,000' 11,975' 6.184 3.958 2.992 JEWELRY DETAIL NO. DeDth ID Item 1 400' 2.81" Tubing Retrievable Safety Valve 2 Various Gas Lift Mandrels 3 8000' 2.992" 4-1/2" X 3-1/2" Tubing XO 4 11,900' 3.25" Baker Permanent Packer 5 11 ,940' 2.81" X-Nipple 6 11,975' 2.992" Baker Wireline Muleshoe DRAWNBY:LWB ) UNOCALe 7" Casinq Liner (8-1/2" Hole to 13,607' MD): Trading bJy Unit Grayling G-12RD3 Cement Program Cement volume based on open hole volume plus 200/0, shoe joints and annulus. The job will be designed to bring cement to the top of the liner at 8,000'. The estimated total volume is as follows: (13607' - 8200') X 0.1268 cuftlft (7" x 8-1/2") X 1.2 = 823 cuff 200' liner lap @ 0.1438 cufUff = 29 cuff 80' shoe track X 0.1845 cufUff = 15 cuff TOTAL: 823 + 29 +15 = 867 cuff or 748 sxs of Class G Cement Cementing Program G-12RD3 3/21/2002 ~ UNOCAL8 Report Date: Client: Field: Structure I Slot: Well: Borehole: UWIIAPI#: Survey Name I Date: Tort I AHD I DOlI ERD ratio: Grid Coordinate System: Location LatlLong: Location Grid N/E Y/x: Grid Convergence Angle: Grid Scale Factor: Station ID Tie-In Survey Top of Window Base Whipstock KOP Crv 5/100 End Crv Target TO Le~al Description: Surface: Tie-In: Target: BHL: G-12R03 (P6) report. xis G-12RD3 Proposed Well Profile - Geodetic Report March 7,2002 Unocal Trading Bay Unit dy Grayling / G-12 (slot 37) _1-'" stu ~~~~RD3 Feaslbl 1.,7 507332011603 G-12RD3 (P6) / March 7, 2002 163.052° I 8931.98 ft / 6.304 /0.90ï NAD27 Alaska State Planes, Zone 4, US Feet N 60,83979330, W 151.61279092 N 2502421.450 ftUS, E 212297.820 ftUS -1.40847566° 0.99999419 Schlumberger Survey I DLS Computation Method: Vertical Section Azimuth: Vertical Section Origin: TVD Reference Datum: TVD Reference Elevation: Minimum Curvature / Lubinski 121.140° N 0.000 ft, E 0.000 ft KB 99.0 ft relative to Mean Sea Level Magnetic Declination: Total Field Strength: Magnetic Dip: Declination Date: Magnetic Declination Model: North Reference: Total Corr Mag North.> True North: Local Coordinates Referenced To: 20.628° 55385.909 nT 73.523° Apri/15,2002 BGGM 2001 True North +20.628° Well Head '.............~ Grid Coordinates Geographic Coordinates MD Incl Azim TVD VSec N/.S EI.W DLS Northing Easting Latitude Longitude (ft) (°) (°) (ft) (ft) (ft) (ft) (0/100ft) (ftUS) (ftUS) 8100.00 41.00 148.50 5857.57 4936.39 -3725.84 3516.33 0.00 2498610.33 215721.48 N 60.82960024 W 151.59308885 8200.00 42.75 154.00 5932.05 4994.06 -3784.34 3548.36 4.07 2498551.06 215752.06 N 60.82944020 W 151.59290948 8212.00 44.12 152.05 5940.77 5001.07 -3791.69 3552.10 16.00 2498543.63 215755.62 N 60.82942009 W 151.59288854 8225.00 44.12 152.05 5950.10 5008.83 -3799.69 3556.34 0.00 2498535.52 215759.66 N 60.82939820 W 151.59286480 8300.00 43.39 146.73 6004.29 5054.48 -3844.30 3582.72 5.00 2498490.28 215784.94 N 60.82927615 W 151.59271707 8400.00 42.80 139.46 6077.36 5117.75 -3898.87 3623.67 5.00 2498434.72 215824.53 N 60.82912685 W 151.59248772 8500.00 42.68 132.09 6150.85 5183.32 -3947.45 3670.93 5.00 2498384.99 215870.58 N 60.82899392 W 151.59222301 8600.00 43.03 124.76 6224.19 5250.70 -3989.65 3724.16 5.00 2498341.50 215922.76 N 60.82887844 W 151.59192484 8678.14 43.63 119.13 6281.05 5304.27 -4017.98 3769.63 5.00 2498312.06 215967.52 N 60.82880091 W 151.59167013 13276.03 43.63 119.13 9609.00 8474.91 -5562.40 6540.93 0.00 2496700.00 218700.00 N 60.82457295 W 151.5761476F ---' 13607.61 43.63 119.13 9849.00 8703.57 -5673.78 6740.79 0.00 2496583.74 218897.06 N 60.82426797 W 151.57502839 Northin~ ey) rftUSl 2502421.45 2498610.33 2496700.00 2496583.74 Eastin~ eX) rftUSl 212297.82 215721.48 218700.00 218897.06 1873 FSL 1386 FEL S29 T9N R 13W SM 3427 FSL 3157 FEL S33 T9N R 13W SM 1589 FSL 136 FEL S33 T9N R13W SM 1478 FSL 5216 FEL S34 T9N R13W SM Page 1 of 1 3/7/02-1 :08 PM UNOCAL8 0- 2000 - - 0) > -0) ã)-I 0) CO 'to- 0) ocf) 0 c: 0 CO N 0) II ~ .~ 0) ~ > -....0 .c:..c ..... CO 0..4:: 0)0 00 -0) ~O) tro O)~ > .' O)'Q; 20::: I- > 0) w 4000 - 6000 - 8000 - 10000 -2000 VERTICAL SECTION VIEW Client: Unocal Well: G-12RD3 (P6) Field: Structure: Section At: Date: Schlumberger Trading Bay Unit Grayling 121.14 deg March 07, 2002 - -.-----.-----{)---.--- ----------------- Tie-In Survey 8100 MD 5858 TVD 41.00° 148.50° az 4936 departure 8200 MD 5932 TVD 42.75° 154.00° az 4994 departure ~ Base Whipstock 8212 MD 5941 TVD 44.12° 152.05° az 5001 departure KOP Crv 5/100 8225 MD 5950 TVD 44.12° 152.05° az 5009 departure ,-/ '2 -, 2000 4000 6000 8000 Vertical Section Departure at 121.14 deg from (0.0, 0.0). (1 in = 2000 feet) 0 10000 PLAN VIEW Client: Unocal Well: Field: Structure: G-12RD3 (P6) Trading Bay Unit Grayling 1 in = 2000 ft 07-Mar-2002 Schlumberger UNOCALI> Scale: Date: 8000 , ! 10000 4000 6000 , 2000 0 f -2000 -4000 True North Mag Dec ( E 20.63° ) 0 0 ~ ~' ^ ^ ^ I I- -2000 0::: 0 z -2000 KOP Crv 5/100 8225 MD 5950 TVD 44.12' 152.05' az 3556 E Tie-In Survey 8100 MD 5858 TVD 41.00' 148.50' az 3726 S 3516 E -4000 -4000 Target 13276 MD 96)9 TVD 43.63' 119.1,' az 5562 S 6541 =: 8212M) 5941TVD 44.12' 152.05' az 3792 S 3552 E I I- ::J 0 (f) -6000 V V V -6000 J . G-12 -8000 -8000 I 2000 «< WEST 10000 6000 EAST »> 8000 4000 0 -2000 -4000 ) I I ADL-17594-1,A I 20 Unocal I Forest I - ADL-17594-2,A J Unocal I Marathon I I I I - --+ -- - - _. "_._- I I I I I I I . AD~-18729-1 ~nocal Mrrathon 5 ADL118729-2,A . ilinocal - - DOLLY Forest - - - - - Î - - - - - - -- - - - 0 1.000 2,000 3.000 : , ' , ! ~ I I SCALE IN FEET 21 I) - , UNOCALO Trading Bay Unit Grayling Platform Well G.12RD3 PROPERTY PLAT ! ~ ~ ~ i ~ ¡ ~ .:J G RÄYLIN G T ADL-18730-1 I Unocal I M~rathon I ADL-18730-A : U nocal Forest I -----+------- I I . ADL- 18730-2 Unocal c 7 Forest 32 ~ II STEELHEAD íit i5 It; ~ G 12RD3 . T9N - R13W TBN - R13W ADL-17579 Unocal 6 4 Trading Bay Unit Boundary ~ -- ) UNOCALe Mill Window and Drill 8-1/2" Hole 1 MU bottom-trip whipstock with MWD. 2 RIH with one trip whipstock assembly. 3 Orient whipstock. Set whipstock @ 8200' MD. 4 Changeover well to oil base mud 5 Mill window in 9-5/8" casing. 6 Circulate bottoms up and FIT 7 POOH with setting tool. 8 LD mills and MU drilling BHA. 9 Test BOPE. 10 RIH with BHA while P/U 5" Drill Pipe. 11 Drill 8-1/2" hole (45 fph) 12 Circulate and condition mud system. 13 POOH to change bit. RIH with new bit. 14 Drill 8-1/2" hole (40 fph) 15 Circulate and condition mud system. 16 POOH to change bit. BOPE Test. RIH wI new bit. 17 Drill 8-1/2" hole ( 18 fph) 18 Circulate and condition mud system. 19 POOH to change bit. RIH with new bit. 20 Drill 8-1/2" hole (18 fph) 21 Mad Pass with L WD Tool String 22 Circulate and condition mud system. 23 POOH with BHA. 24 BHA handling. Run 7" Liner 30 RU casing crews for 7" liner 31 Change casing rams and test BOPE 32 MU and RIH with 7" liner. 33 Continue to RIH with 7" liner on 5" drillpipe. 34 Circulate and condition hole for cement. 35 Set Liner Hanger and R!U for cement job. 36 Pump cement job and set liner top packer. 37 Circulate out cement and POOH. General Procedure G-12RD3 Trading Baytnit Grayling Well G-12RD3 General Procedure 2/6/2002 2/6/2002 ) UNOCALe Clean Out Liner 38 MU 6" rock bit and clean out BHA 39 RIH to TOL while P/U 3-1/2" DP. 40 RIH to TD and clean out 41 Change well over to Completion Fluid 42 POOH Run Completion 43 Change rams, test BOPE 44 R/U Schl. RIH and set Completion Packer. RID. 44 Pull wear bushing. 45 RU to run 4-1/2"x3-1/2" gas lift completion. 46 PU, rabbit and run gas lift completion. 47 Run SCSSV, control line, and PU hanger. 48 Land hanger and test. 49 ND BOPE. 50 Install tree and test. General Procedure G-12RD3 2 Trading Ba;tnit Grayling Well G-12RD3 General Procedure 2/6/2002 2/6/2002 ~ - UNOCAL8 Schlumberger Proposed Well Profile - Geodetic Report Minimum Curvature / Lubinski 105.090° N 0.000 ft, E 0.000 ft KB 99.0 ft relative to Mean Sea Level Survey 1 DLS Computation Method: Vertical Section Azimuth: Vertical Section Origin: TVD Reference Datum: TVD Reference Elevation: December 13, 2001 Unocal Trading Bay Unit d ~~~~ling/G-12(Slot37) - - -t stu Y G-12RD3 Feaslblll Y 507332011603 G-12RD3 (P4) / December 13, 2001 173.736° / 10880.27 ft / 6.462 / 1.1 OE NAD27 Alaska State Planes, Zone 4, US Fee! N 60.83979330, W 151.61279092 N 2502421.450 nus, E 212297.820 ftUS -1.40847566° 0.99999419 Report Date: Client: Field: Structure 1 Slot: Well: Borehole: UWI/API#: Survey Name 1 Date: Tort 1 AHD 1 DDII ERD ratio: Grid Coordinate System: Location LatlLong: Location Grid N/E YIX: Grid Convergence Angle: Grid Scale Factor: 20.869° 55373.518 nT 73.515° February 27, 2001 BGGM 2001 True North +20.869° Well Head Magnetic Declination: Total Field Strength: Magnetic Dip: Declination Date: Magnetic Declination Model: North Reference: Total Corr Mag North .> True North: Local Coordinates Referenced To: .-...-. Grid Coordinates Geographic Coordinates E/.W I DLS Northing Easting Latitude Longitude (ft) (0/100ft) (ftUS) (ftUS) 3516.33 0.00 2498610.33 215721.48 N 60.82960024 W 151.59308885 3548.36 4.07 2498551.06 215752.06 N 60.82944020 W 151.59290948 3552.10 16.00 2498543.63 215755.62 N 60.82942009 W 151.59288854 3556.34 0.00 2498535.52 215759.66 N 60.82939820 W 151.59286480 3583.05 5.00 2498489.76 215785.25 N 60.82927476 W 151.59271522 3625.43 5.00 2498431.93 215826.23 N 60.82911932 W 151.59247787 3675.28 5.00 2498378.14 215874.77 N 60.82897546 W 151.59219865 3732.20 5.00 2498328.79 215930.49 N 60.82884422 W 151.59187982 3795.76 5.00 2498284.28 215992.97 N 60.82872665 W 151.59152378 3865.48 5.00 2498244.93 216061.75 N 60.82862360 W 151.5911332' '~ 3934.46 5.00 2498213.62 216129.98 N 60.82854248 W 151.59074679 8752.54 0.00 2496255.01 220901.32 N 60.82350012 W 151.56375951 A;~~ I 148.50 154.00 152.05 152.05 146.74 VSec N/.S (ft) (ft) 4365.05 -3725.84 4411.20 -3784.34 4416.73 -3791.69 4422.91 -3799.69 4460.44 -3844.81 4516.15 -3901.62 4577.97 -3954.20 4645.41 -4002.16 4717.96 -4045.12 4795.08 -4082.77 TVD (ft) 5857.57 5932.05 5940.77 5950.10 6003.71 MD Incl (ft) (°) 8100.00 41.00 8200.00 42.75 8212.00 44.12 8225.00 44.12 8300.00 44.66 8400.00 45.75 8500.00 47.24 8600.00 49.08 8700.00 51.24 8800.00 53.68 8891.82 56.13 15103.89 56.13 Station ID Tie-In Survey Top of Window Base Whipstock KOP Crv 5/100 6074.21 6143.08 6209.82 6273.91 6334.87 139.87 133.28 127.04 121.17 115.66 110.91 6387.68 4869.40 -4112.40 110.91 9850.00 10000.55 -5953.15 End Crv Target / TO Legal Description: Easting (X) rftUSl 212297.82 215721.48 220901.32 Northing (y) rftUSl 2502421.45 2498610.33 2496255.01 Surface: 1873 FSL 1386 FEL S29 T9N R13W SM Tie-In: 3427 FSL 3157 FEL S33 T9N R13W SM Target / TO / BHL: 1197 FSL 3205 FEL S34 T9N R13W SM 12/13/2001-2:44 PM Page 1 of 1 G-12R03 (P4) report.xls VERTICAL SECTION VIEW Client: Unocal Well: G-12RD3 (P4) UNOCAL8 Field: Trading Bay Unit Schlumberger Structure: Grayling Section At: 105.09 deg Date: December 13, 2001 0- ~ - ------~.~---~~- 2000 _. --------_.._------------~---------------------------------------------- ~ - 0) > -0) ã)....J 0) CO 't- 0) ocn 0 c 0 CO N 0) II ~ .~ 0) ~ > ,-,0 ..c.Q +-' CO o.~ 0)0 00 -c¡) ~(J) :eCó O)~ > .. 0)1i) 20::: I- > 0) w 4000 -- ---------- Top of Window 8200 MD 5932 TVD 42.75' 154.00' az 4411 departure Base Whipstock 8212 MD 5941 TVD 44.12' 152.05' az 4417 departure / KOP Crv 5/100 ~8225 MD 5950 TVD 44.12' 152.05' az ! 4423 departure I End Crv I 8892 MD 6388 TVD ¡ 56.13' 110.91' az 4869 departure 6000 - - ----~ -----------_._~~---~ Tle.ln Survey--------------- 8100 MD 5858 TVD 41.00' 148.50' az 4365 departure Hold Angle 56.130 8000 -- Target/TD 15104 MD 9850 TVD 56.13' 110.91' az 10001 departure 0 G-12RDi \G-1 I I 4000 6000 8000 1 0000 Vertical Section Departure at 105.09 deg from (0.0, 0.0). (1 in = 2000 feet) I I I I 2000 12000 10000 _. -2000 -- ~~-----~~ -2000 PLAN VIEW Client: Unocal Well: G-12RD3 (P4) Field: Trading Bay Unit Structure: Grayling Scale: 1 in = 2000 ft Date: 13-Dec-2001 0 2000 4000 6000 Schlumberuer ~ - UNOCAL8 8000 10000 , 0- ------------,------ True North Mag Dec ( E 20.87° ) -0 '~' ^ ^ ^ :c I- -2000 ----- ~ 0 Z ~ - --_._-_.._...~-------~-~--- -2000 Top of Window 8200 MD 5932 TVD 42.75° 154.00° az 3784 8 3548 E -4000 -- - Base Whipstock 8212MD 5941~ -. -.--.-----------.------------------.------- 44.12° 152.05° az 3792 8 3552 E End Cry ~ 8892 MD 6388 TVD ~ 56.13° 1'0.91° az 41128 3334E ------t.--- -4000 KOP Cry 5/100 8225 MD 5950 TVD 44.12° 152.05° az 3800 8 3556 E ~ ----......--.......-------..---..--.-----------"______n-___-..n \;/iO/d i ' ~i'ÞlJtf¡ ! ._-------- ..' 11 () i ---I .1Tro---r G-12Rþ2 Target I TD 15104 MD 9850 TVD ; 56.13° 110.91° az ! 59538 8753 E . :c I- :) 0 (j) -6000 -- V V V --- - -6000 .~ G-12 ~D '<;-12 -8000 - -_u_----- ----~---_._--_._---_.__.._-_.,-------- , ----_.._--_._----_._-~- -8000 -2000 0 2000 «< WEST 4000 6000 EAST »> I 8000 10000 UNOCAL8 RKB to TBG Head = 43.2' () L.. -.J -.J 2 3 -.J 8.000' Z ~ 8.200' L ~ -.J -.J -.J 4 >< z 6 . . r-----"\. 5 = HB = Sands / ~ TD = 15,103' (9850' tvd) G-12 RD3 Schematic.doc ~ ) CASING AND TUBING DETAIL SIZE 26" GRADE CONN WT 1/2" Wall 17-3/4" .312 wall Weld 13-3/8" 61 K-55 Butt 12.515 9-5/8" 47 P-110 Seal Lock 8.681 9-5/8" 40# N-80 Seal Lock 8.835 9-5/8" 43.5# N-80 Seal Lock 8.755 D V Co liar ----------------------------------------------------------------------- 9-5/8" 43.5# N-80 Seal Lock 8.755 7" (liner) 29 N-80 Tubing: 4-1/2" 12.6 L-80 3-1/2" 9.3 L-80 Butt BTC-Imp BTC-Imp ) Trading Bay Unit Well G-12RD3 Proposed ID MD MD TOP BTM. Surf 369' Surf 602' Surf 6,013' Surf 73' 73 6,252' 6,251' 6,939' 6,939' 6,941' 6,941' 8,200' (window) 8,000' 15,100' Surf 8,000' 8,000' 14,575' 6.184 3.958 2.992 JEWELRY OET AIL NO. Oeoth 10 Item 1 400' 2.81" Tubing Retrievable Safety Valve 2 Various Gas Lift Mandrels 3 8000' 2.992" 4-1/2" X 3-1/2" Tubing XO 4 14,500' 3.25" Baker Pennanent Packer 5 14,550' 2.81" X-Nipple 6 14,575' 2.992" Baker Wire line Muleshoe DRAWN BY: LWB '"" ~""to I --t I I I ~ ! I ' ! 3f' KIlL L!NE WITH , TWO .3" 5M VALVES I { - rr' - I \ , iJ) , KILL LINE FROM MUD PM? & CEMENT UNIT ..-:.~ ' '), . "",', . " '. 8 ElL I NIPPLE: , ~ ..:' ) 1 FLOWLINE " 13-5/8" 5000 PSI ANNULAR ~ --,'---¡ L-.., ~.,\ ,¡---l PIPE RAMS 13-5/8" 51v{ FlANGE DOUBLE GATE 5M BLIND RAMS I . ~ L, 13-5/8" 51.1 FlANGE r --1 4" CHOKE LINE WITH ONE REMOTE .. . ( , . - & 1 MANUAl.. 4" 5M VALVE - -l)\ , { \ ,. ~, I. I - CONNECTED TO CHOKE MANIFOLD (SEE MANIFOLD DRAWlNG) 13-5/8" 5M flANGE SINGLE GATE 5M 13-5/8" 5M FlANGE I ,,--¡ L-.., r---1 PIPE RAMS ~ ~ L- - f RISER r' I " I . . I -.- - - ... I . I J f J jl 10" 5M x 13-5/8" 5M " ADAPTER CAMERON 5M SPOOL 13-5/8" 80PE 5M STACK GRAYLING PLA.TFORM UNlON OrL COMPANY OF CALIFORNIA (dba UNOCAL) .. :... .:tJRAWN: CAC APP'D: Gsa SCALE: NONE DATE: 5/24/91 . L t I ' - - " L ' - I - " .. 'I. I I . I f .' . .,-.. ;. '.,") .-) '~l . . i I ! TO OE.~R(CK VENT ^ TO WELL a..EAN TANK i , . A' ¡ . I TO GAS BUSTER I^ I . , :4:1~ :;. I 3-1/8,,1 ~. 3-1/8" I '- ~ I AUTOMATIC CHOKE , 4-1/16" . ~ ~"~! - I 3-1/8" ! '- I . ~ . ~ IT, I : , . . . . , , , 4- tl 16" AUTOMATIC CHOKE I , I , I I , FROM CHOKE UNE I I I I .. i , I I I ! 3-1/16" 3-1/16" ^ 3-1/16" 3-1/19" VALVES. UP~EJ\JJ OF CHOKES ARE 10,000 PSI GATE lYPE VALVES DOWNSTREAU OF CHOKES ARE 5,000 PSI CATE TYPE CHO.KE MANIFOLD GRAYlING PU\TFORM UNION OIL COMPANY OF CALIFORNIA (dba UNOCAl) DRAWN: OAC APP'O: GSa SCALE: NONE DATE: 11/25/89 I MIXING PIT IS A ONE LEVEL BELOW THE ACTN£ SYSTEM TRIP TANK 45 BBLS MIXING PIT 40 BBlS r 185 BBlS 185 BBLS VOLUME PIT SUCTION PIT . I , ' \ ¡ 125 BBLS I I I i I I I , I I . I I L.":=::=':'=':=':===CENTRIFUCE l_~""==================== 67 BBLS . 240 BBLS DEGASSER D ESIL TER I SHAKER SHAKER RESERVE PIT 475 BBlS NOTE: THE SYSTEM WILL BE EQUIPPED WITH A DRILLING PIT LEVEL INDICATOR WITH AUDIO. & VISUAL WARNING DEVICES. . 1~..11(. C' 't:A!'~~ ~ EQUIPMENT LIST ~ 1) RESERVE PIT 2) DEGASSER . 3) (2) SHAt<ERS 4) PIT LEVEL INDICATOR (VISUAL & AUDIO) 5) FLUID FLOW SENSOR 6) TRIP TAN'< 7) PIT AGITATORS 8) DESILTER 9) CENTRIFUGE 10) MIXING PIT j ",-,I '~ ~ ~ , UNOCAL GRAYLING MUD PIT SCHEMATIC DRAWN BY: DAC APP'D: GSB . SCALE: NONE DATE: 11-30-89 ,-,- '''-1 'L.I.., 1- VLIC'IILIClI ~UIICI\A;; r IIC';:);:)UIIC' ) Subject:G-12RD3 Potential Surface Pressure Date: Thu, 28 Mar 2002 13:51 :55 -0800 "From: "Buster, Larry W -Alaska" <Ibuster@unocal.com> To: "Tom Maunder (E-mail)..<tom_maunder@admin.state.ak.us>. "Winton Aubert (E-mail)..<winton_aubert@admin.state.ak.us> ') Tom and Winton I have reworked the maximum downhole pressure and the maximum potential surface pressures to coincide with the requirements as outlined in AOGCC Regulation 20 AAC 25.005(c)(4)(A). I hereby submit the attached worksheet as a supporting document to the Revised Permit to Drill (Form 10-40.1) previously submitted to the Commission (date of cover letter March 22, 2002). I understand the worksheet calculating the maximum potential surface pressure originally submitted with the permit to drill application contained some inconsistencies and was difficult to understand. The intention of the attached worksheet is to present the required data and calculations in a clear and more concise manner. As you will see in the attached worksheet, the Calculated Maximum Potential Surface Pressure is 3,742 psi. Therefore, I would propose we test the BOPE to 5,000 psi. Please advise of any more information and or clarifications required herein. «Maximum Potential Surface Pressure G12RD3.doc» Regards, Larry W. Buster Advising Drilling Engineer Unocal Alaska (907) 263-7804 - Office (907) 263-7884 - Fax (907) 351-6730 - Mob. i .1 Name: Maximum Potential Surface Pressure G12RD3.doc ~Maximum Potential Surface Pressure G12RD3.doc Type: WINWORD File j..1 (application/msword) Encoding: base64 1 of 1 3/29/023:32 PM ) Grayling Platform Well G-12RD3 Maximum Potential Surface Pressure and Maximum Expected Downhole Pressure ) As required in AOGCC regulation 20 AAC 25.005(c)(4)(A) the maximum downhole pressure that may be encountered and the maximum potential surface pressure, based upon a methane gradient, shall be calculated using the following criteria: Data from existing wells drilled into the Hemlock Formation from the Grayling Platform indicate the maximum expected pore pressure will be a 9.3 ppg EMW (0.48 psi/ft). The proposed mud weight for drilling this well will be 9.8 ppg, or 0.5 ppg over the expected maximum pore pressure. The rock fracture gradient is assumed to be a 15.6 ppg EMW (0.81 psi/ft), which is supported by leak off test data as measured by Unocal within the Cook Inlet producing fields. The methane gradient will be assumed to be 0.1 psi/ft. The well TD is projected to be 9849' TVD (8-1/2" hole) coming out of a9-5/8" window at 5932' TVD. Maximum Downhole Pressure Calculation: Maximum Downhole Pressure = Well TD (TVD, ft) X Maximum Formation Pore Pressure (psi/ft) Maximum Downhole Pressure = 9,849 ft X 0.48 psi/ft Maximum Downhole Pressure = 4,727 psi Maximum Potential Suñace Pressure Calculation: Maximum Potenital Surface Pressure = Maximum Downhole Pressure - (Methane Gradient x Well TD (TVD, ft» Maximum Potential Surface Pressure = 4,727 psi - (0.1 psi/ft X 9,849 ft) Maximum Potential Surface Pressure = 4,727 psi - 985 psi Maximum Potential Suñace Pressure = 3,742 psi Supplementary Calculation to check the stress exerted upon the 9-5/8" Casing Shoe at Maxim um Potential Surface Pressure: Expected Shoe Leak Off Pressure = Shoe Depth (TVD, ft) X Fracture Gradient, psi/ft Expected Shoe Leak Off Pressure = 5,932 ft X 0.81 psi/ft = 4,805 psi Stress Exerted Upon 9-5/8" Shoe = Maximum Potential Surface Pressure + (Methane Gradient x Shoe Depth (TVD, ft» Stress Exerted Upon 9-5/8" Shoe = 3,742 psi + (0.1 psi/ft X 5,932 ft) Stress Exerted Upon 9-5/8" Shoe = 4,335 psi The Stress Exerted Upon the 9-5/8" Shoe at Maximum Potential Surface Pressure (4,335 psi) is less then the Expected Shoe Leak Off Pressure (4,805 psi). UNOCAL ALASKA CASING DESIGN SAFETY FACTORS ") WELL: G-12RD3 CASING: 9-5/8" MW @ shoe: 9.4 SPEC'S: Weight/ft: RATINGS: Burst (psi): Depth of Next Shoe (TVD): REMARKS: LOCATION: Trading Bay Unit, Cook Inlet Depth (MD): 8,200 Depth(TVD): 8.6 Frae. Press. @ shoe (E Grade: L-80 Connee . Collapse(psi): 4,750 Ten. MW @ Next Shoe: laska 5,932 15.40 BTC 1,086,000 PP @ shoe: 47 6,870 9,850 Fracture Pressure @ deep casing shoe Pore Pressure @ deep exposure Mud Weight @ deep exposure * All depths are TVD I M.A.S.P. INPUT DATA (based upon liner shoe depth, if liner set below cas' 5,932 feet = 9,850 feet = 9,850 feet = M.A.S.P.RATIONALE &. CALCULATIONS Gas Gradient I 0.10 Ipsilfoot * *(0.1 psi/ft for casing shoes@ 10,000 or less, 0.15 psilft for depth greater than 1O,000? Fracture Pressure @ Depth = Depth (ft) x Fracture Gradient (ppg) x 0.052 Fracture Pressure = I 5,932 Ifeet x Fracture Pressure = 4,750 psi Fracture Gradient A.S.P. = Fracture Pressure - {(Fracture Depth (ft) x Gas Gradient (psilft)) Fracture Gradient A.S.P. = I 4,750 . PSi miI}Jls { Fracture Gradient A.S.P. = 4,157 f psi ./ BHP A.S.P. assumes that you have 70% of the lwle filled with gas and 30% filled with mud. Pressure of Gas Column = 0.70 x Depth (ft) x Gas Gradient (psilft) Pressure of Gas Column = 0.70 Pressure of Gas Column = I 690 Ipsi Pressure of Mud Column = 0.30 x Depth (ft) x Mud Weight (p Ippg x 5,932 feet x 9,850 I feet x Pressure of Mud Colwnn = x 0.052 s~~~;~~~ 93 . 1- x ~;y~ '?; psi - I ,~) 1:¿6 Pressure of Mud Column = BHP = Depth (ft) x Fonnation Pore Pressure (ppg) x 0.052 BHP = I 9,850 I feet x BHP = 4,763 psi BHP A.s.P. = BHP - Pressure of Mud Column - Pressure of Gas Col BHP A.S.P. = I' 4,763 PSi - BHP A.S.P. = . 2,568 psi The M.A.S.P. is the greater of the Fracture Gradien .S.P. or BHP A.S.P. as calculated above. M.A.S.P. = I .' . 4,157 IPSi /~ 1,506 BURST DESIGN Assume maximwn burst load is MASP as calc ted above. Burst Safety Factor = Burst Rating divided MASP ~~~= I ~ I~/ 4,157 psi = COLLAPSE DESIGN Evacuated Depth: I 5,932 feet Collapse Pressure = Evacuat Depth x Pore Pressure behind casing x .052 = Collapse S.F. = 4,750 Ipsi/ I Pore Pressure behind casing: I. 2,653 2,653 pSI = I Depth (MD) x #/ft = I 8,200 Buoyancy Factor 7 9.4 Tension Rating erated for connection): feet x ppg M.W. = 1,086,000 TENSION DESIGN 47 #/ft = 0.858 x Air Weight = Safety Factor = Rating / Air Weight = Safety Factor = Rating! Buoyed Weight = 5,932 9,850 SHOE TEST Frac- Pres. (EMW): 15.40 Kick Tolerance: Shoe Test for 0.5 ppg Minimwn Kick Tolerance: 9.8 ppg s ppg ppg ppg 0.052 0.10 0.10 0.052 690 psi 1.65 IBurst S.F. 8.6 Ippg psi 1.79 leollapse S.F. 385,400 # Air Weight 330,510 # Buoyed Weight 2.82 S.F. in Air 3.29 S.F. in Mud 3.37 ppg 10.6 ppg EMW ) UNOCAL ALASKA CASING DESIGN SAFETY FACTORS WELL: CASING: MW @ shoe: 9.8 SPEC'S: Weight/ft: RATINGS: Burst (psi): Depth of Next Shoe (TVD): REMARKS: G-12RD3 ) LOCATION: Trading Bay Unit, Cook Depth (MD): 15,104 Depth(T 8.6 Frac. Press. @ shoe ( W): Grade: L-80 Co ection: Collapse(psi): 7,020 ension(#): MW @ Next Shoe: 9.8 Fracture Pressure @ deep casiug shoe Pore Pressure @ deep exposure Mud Weight @ deep exposure * All depths are TVD I M.A.S.P. RATIONALE & CALCULAT NS Gas Gradient 0.10 psi oot * C\ ~ *(0.1 psilftfor casing shoes @ 10,000 or less, 0.15 psilftfor depth greater than 10,000') ~ \.J 'f"n,~ 0~d Fracture Pressure @ Depth = Depth (ft) x Fracture Gradient (ppg) x 0.052 \" ~ Fracture Pressure = I 5,932 Ifeet x I 15.4 Ippg x I Fracture Pressure = 4,750 psi Fracture Gradient A.S.P. = Fracture Pressure - {(Fracture Depth (ft) x Gas Gradient (psi/ft Fracture Gradient A.S.P. = I 4,750 PSi minus { Fracture Gradient A.S.P. = 4,157 psi BHP A.S.P. assumes that you have 70% of the hole filled with gas and 30% filled wi mud. Pressure of Gas Column = 0.70 x Depth (ft) x Gas Gradie (psi/ft) Pressure of Gas Column = 0.70 Pressure of Gas Column = 690 Ii>. Pressure of Mud Column = 0.30 x Depth (ft) x Mu eight (ppg) x 0.052 Pressure of Mud Column = 0.30 9.8 Pressure of Mud Column = 1,506 BHP = Depth (ft) x Formation Pore Pressure (ppg) x 0.052 BHP = I 9,850 Ifeet x BHP = 4,763 psi BHP A.S.P. = BHP - Pressure of Mud Column - Pressur BHP A.S.P. = I 4,763 Ippsi- BHP A.S.P. = 2,568 The M.A.S.P. is the greater of the Fracture G . nt A.S.P. or BHP A.S.P. as calculated above. M.A.S.P. = 4,157 IPSi 7" PP @ shoe: 29 8,160 9,850 M.A.S.P. INPUT DATA (based upon liner shoe depth, if liner set helo 5,932 feet = 9,850 feet = 9,850 feet = 5,932 9,850 9,850 0.052 9.3 ppgx 1,506 psi - I Assume maximum burst load is MASP a alculated above. Burst Safety Factor = Burst Rating div' ed by MASP Burst S.F. = 8 60 pSi / BURST DESIGN 4,157 pSi = COLLAPSE DESIGN Evacuated Depth: 9,850 I feet Collapse Pressure = Eva ated Depth x Pore Pressure behind casing x .052 = Collapse S.F. = 7,020 psi / Pore Pressure behind casing: I. 4,405 4,405 pSI = I Depth (MD) x #/ft I 15,104 Buoyancy Factor / 9.8 Tension Rating erated for connection): feet ppg M.W. = 676,000 TENSION DESIGN 29 I#/ft = 0.852 x Air Weight = Safety Factor = Rating / Air Weight = Safety Factor = Rating/ Buoyed Weight = SHOE TEST 15.60 Frac. Pres. (EMW): Kick Tolerance: 9,850 9,850 Shoe Test for 0.5 ppg Minimum Kick Tolerance: 9.8 MW ppg I feet x I feet x feet x 0.052 et, Alaska 9,850 15.60 BTC 676,000 15.6 9.3 9.8 ppg ppg ppg I ') ( >~ I 0.052 0.10 0.10 690 psi 1.96 IBurst S.F. 8.6 ppg psi 1.59 ICollapse S.F. 438,016 # Air Weight 372,977 # Buoyed Weight 1.54 S.F. in Air 1.81 S.F. in Mud 5.80 10.3 ppg ppg EMW ) UNOCALe Trading Jy Unit Grayling G-12RD3 Cement Program 7" Casing Liner (8-1/2" Hole to 15,104' MD): Cement volume based on open hole volume plus 200/0, shoe joints and annulus. The job will be designed to bring cement to the top of the liner at 8,000'. The estimated total volume is as follows: (15104' - 8200') X 0.1268 cuft/ft (7" x 8-112") X 1.2 = 1,050 cuft 200' liner lap @ 0.1438 cuft/ft = 29 cuft 80' shoe track X 0.1845 cuftlft = 15 cuft TOTAL: 1,050 + 29 + 15 = 1,094 cuft or 943 sxs of Class G Cement Cementing Program G-12RD3 1/31/2002 UNOCAL8 ') LEAK OFF TEST PROCEDURE 2. Pull the drill string into the shoe. Rig up to observe annulus pressures. 1. Sidetrack out of the the 9-5/8" casing window, and drill 20' of new hole. Circulate and condition mud. 3. Close the pipe rams and pump down the drillpipe at a slow rate (1/4 - 1/3 BPM) if exposed formation is permeable. A non-permeable formation should be step tested to a predetermined pressure. 4. Measure the volume pumped and plot annulus pressure-vs-cumulative volume pumped. Compare annulus pressure to drill pipe pressure and confirm both are the same. Record and plot pressure versus volume pumped. The pumps should be shut down immediately upon indication of leak-off. Record the inital, shut down pressure and the pressure after 1 2, and 3 minutes. 5. Release pressure and record the volume of fluid recovered in the trip tank. The point "8" shown in the attached graph at which the plot of drill pipe pressure stops increasing equally as the volume is pumped is called the P.I.T. limit, Leak Off, or pressure integrity test limit. The leak-off pressure is calculated as follows: Leak-off (EMW);:: Mud weight in hole + P.I.T. (PSI) (0.052) X (shoe depth in TVD ft.) This equivalent mud weight should be made known to all drilling personnel to ensure it is not exceeded under any circumstances. See the drilling procedure for guidelines on expected LOT's or pressure integrity test limits for each casing shoe. SURFACE PRESS. TYPICAL PIT PLOT (psi) VOLUME PUMPED (BBlS) C '---~ SHUT -IN-TIME (MIN) Point" A" will have some variance until the system begins to pressure up. Point "8" is the leak off and is abbreviated LOT. Point "C" is known as the injection pressure and is usually dependent on rate. Point "D" is known as the fracture closure pressure and may not stabilize if penneable fonnations are exposed. NOTES: ) ') Drilling Fluids Program "$, .. Ii UNOCAL Grayling Platform Well G-12 RD Prepared by: Lee Dewees Reviewed by: Presented to: Larry Buster December 12, 2001 M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax DRilliNG FLUIDS ) ) Project Summary Well G-12RD K.O. 7" . Ii....! 8 1/2" .KeylssueNo. 3 Drill Solills M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax ey Ii. . Ii... Ii Ii Depth TVD Mud Weight Sum Days Mud System N/A 10000 9000'- 15175' 9850' Versa-Drill 9.0-9.5 15 $157500 15175' 3% KCL $1 8.6 5 9850' .~.",.,,~..ijtJII'¡lt~-o,c" ..;;~ . For sloughing coal in the 6" interval (oil mud), spot Ventrol 401. For severe problems consider increasing mud weight. . Maintain sufficient 3 RPM reading to insure adequate hole cleaning. Sweep hole as needed to avoid cuttings buildup. Pump weighted sweeps to aid in hole cleaning. Rotate and reciprocate drill string to remove cuttings beds. . Run as fine a mesh shaker screen as possible. Run centri- fuge during trips to reduce drill solids in mud. DRILLING FLUIDS ) '> Interval Summary 81/2" Well G-12RD - t ,. .It 9000' - 15715' f ~ Drilling Fluid System Versa- Drill Oil Mud Key Products Mapco 200/ Versawet / Versacoat / Versa HRP / VG-69 / Versa- mod / Lime / Calcium Chloride / MI Bar / Ventrol 401 Solidsûontrol Shale Shakers / Desilter / Centrifuge PotentiéilProblems Coal sloughing, hole cleaning, drill solids buildup Depth Interval (ft) 9000' - 15715' Plastic Yield HTHP Viscosity Point Fluid Loss OIW (cp.) (lb/100ft2) (1111/30toin) Ratio 20 - 25 18 - 22 4 - 5 cc' s 80/20 ~~ "r!T"""'--=::':'''' - ,m' 111 I ~-- ~ W1II! Mud Weight (ppg) 9.0-9.5 Gels (lb/100ft2) 15 - 30 .. ""'8..w,,- ,,- = '" 11",,,,,,.,,_... . After running and setting whipstock, dump and clean all surface pits. Displace hole volume to production. . Build 30 - 40 barrel Calcium Chloride brine spacer to pump between hole volume and oil based mud. . Displace hole to oil based mud. Insure no spacer or oil based mud is discharged. . Drill ahead, maintain low shear rate values with VG-69, Versamod, Versa HRP, and Alcomer 274. . Run centrifuge as needed to reduce solids buildup. . Pump weighted sweeps to aid in hole cleaning. . If sloughing coal becomes a problem, add 2 - 4 ppb ofVentro1401 to mud system or spot a concentrated pill of20 - 25 ppb V entro 1 401 across coal zone prior to trips. For severe coal sloughing consider raising mud weight. . Run 7" liner. . Displace well to brine after running tubing. Pump a Kleenup spacer for displacement to 3% KCL. M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax DRILLING FLUIDS ) ') Interval Summary Well G-12RD 1.-...... .11 Lost Circulation Recommended LCM Pill Formulas ProtJlems Kleyprømucts Drilling Fluid / OM Seal / SafeCarbFine, Medium, Coarse / Versa- HRP . 1..... ..~..._-~ .-&,.;=r"";.,,,,,,,,,,-,....,,""",,,,,,,,,,,~ """!'~ø~~;Ê'i:re";¡lãt'if.!;n;t~IR:~iIJ ng~t!è~.."~'~~ - '::... ,Y Volume o.f. M.ud (barrels) 30 """'in:-"~-" .. Mix II SafeCarb Fine (ppb) 10 11 SafeCarb Medium (ppb) 10 (ppb) 1/4 (ppb) 10 IIIIIIrm UIIII .. 1 ....- - ~!!~\:m::!! ~@~í'I;0Ç¡i~g;~Y'"â ~:/;¡rlÎ\~}';'flr~;~!I:~~" ¡~:'~" .. ";'f~,~f"~i;j" , ~, ~ .N...= Volume of Mud (barrels) 40 SafeCarb Medium (ppb) 15 SafeCarb Coarse (ppb) 10 (ppb) 1/2 Versa HRP Mix II (ppb) 15 ""'''''''<WY'''''''''~W''''''''''''''''Y~"-""",,,,""-'''''''w.wN'''''WN'.'' . """,ï¡II--- .. ---"'~I.'--I["'-W","," r::....::.."""'--- ".~..'f.ij~:~{.rjÎ'fJ:.""r~jë¥êrl..."~.p¡~$~$} "" Y"~. ''-'W... . ~ ^' w Ii " ....Ii~ I -~"~~Lðst Volume of Mud (barrels) 50 Mix II SafeCarb SafeCarb Medium Coarse (ppb) (ppb) (ppb) 15 20 30 - .. . LIImIIIr I Versa HRP Polymer (ppb) 1 II' ..... . Versa HRP should be added last, only after all lost circulation material has been mixed. . Ifpossible, spot pill across theft zone. Apply moderate pressure (50 - 100 psi) to squeeze pill into thief zone. M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax , DRILLING FLUIDS ') UNOCAL8 Trading ~ly Unit G-12RD3 Hazard Anaylsis A. Well G-12RD3 will be drilled with a 9.4 to 9.8 ppg maximum oil base mud. The entire well thru the Tyonic and into the Hemlock is predicted to be normally pressured with expected pore pressures of 8.6 ppg. B. The well is designed to be drilled from 9-5/8" window to the top of Hemlock with PDC bits and oil base mud which will minimize formation exposure time and thus minimize the risk of such completions as stuck BHA's due to time dependent formations. Lost circulation zones are a concern and will be dealt with by the addition of lost circulation material as required. C. From offset well data, (from other Grayling Platform Wells) there is not expected to be any H2S. However, mud loggers will be present to constantly monitor the returns for presents of H2S. Hazard Analysis G-12RD3 2/6/2002 ') ) UNOCALe Trading Bay Unit Well G-12RD3 Drilling Waste Plan G-12RD3 Drilling Waste Oil Based contaminated cuttings will be containerized and disposed of in the Bruce Platform Class II disposal well, which is currently under the process of being permitted. In the event that the Bruce Disposal Well is not ready to accept cuttings before spudding the G-12RD3 well, the cuttings will be stored in a fit for purpose SafeGuard Tank on a Unocal offshore facility. The Oil Based Mud will be re-used on a subsequent well. Drilling Waste Plan G-12RD3 2/6/2002 ) Unocal Corporation P.O. Box 196247 Anchorage, AK 99501 Telephone (907) 263-7660 ') UNOCAL8 Dan Williamson Drilling Manager Friday, March 22,2002 Alaska Oil and Gas Conservation Commission 333 West ih Avenue Anchorage, Alaska 99501 Attn: Commissioner Cammy Taylor Re: Revised Application for Permit to Drill (Form 10-401) Trading Bay Unit Grayling Platform, Well G-12RD3 Commissioner Taylor: Enclosed for your review and approval is the Revised Application for Permit to Drill (Form 10-401) the Grayling Well No. G-12RD3. A separate Sundry Application (Form 10-403) has been sent to you for the proposed abandonment of G-12RD2. We have changed the proposed bottom hole location a horizontal distance of more then 500', thus the reason for the revised permit. All other aspects of the well are the same. We are planning to sidetrack out of existing 9-5/8" casing and drill approximately 5400' of 8-112" hole with oil base mud. The oil base mud waste and cuttings will be disposed of in the Bruce Platform injection well, which is currently in the process of being permitted. Logging will be performed with LWD and a 7" liner will be ran and cemented upon reaching TD. ,/ The approximate date to begin work is April 22, 2002. If there are any questions, please contact Dan Williamson at 263-7677 or Larry Buster at 263-7804. t\~~.eref~ ~1 ~KjJ j J A ?~{I Dan Williamson Drilling Manager Unocal Alaska DW lib Enclosure FOR INQUIRIES CONTACT LOCATION WHERE INVOICES WERE f'18)ITIED :>Y<NENooR .,'\ DATE CHECK NO. 103154~) 20-FEB-02 2004736 DATE INVOICE/CREDIT MEMO NO. 19-FEB-02 :?ERMITTODRILL 70RG12RD3 VOUCHER NO. 02023000967 GROSS 100.00 DISCOUNT NET 100.00 FORM 4-28181 (REV. 11-95) PRINTED IN U.S.A. DETACH STUB BEFORE DEPOSITING CHECK I TOTAL .. 100.00 100.00 QITIBANK DELAWARE ASubsidiaryÒf Citicorp ONE PENN'S WAY NEWCASTLE; DE .19720 STATE OF ALASKA To the ALASKA' OIL & GAS order' COMMISSION' of 333. WEST 7TH AVENUE., ANCHORAGE,AK 99501 United States Ok ) TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERlPARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER {j - IZK.))3 WELL NAME CHECK 1 STANDARD LETTER DEVELOPMENT CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If api number last two (2) digits are between 60-69) / DEVELOPMENT I. ... REDIDLL J PILOT. HOLE (PH) EXPLORATION / ANNULAR~... DI. O. SAL . NO ANNUL DISPOSAL INJECTION WELL L-) YES INJECTION WELL REDRILL ANNULAR DISPOSAL THIS WELL ) ¡.3U "CLUE" The permit is for a new wellbore segment of existing well -J Permit No, API No. Production should continue to be reported as a function of the original API number stated above. In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole. must be clearly differentiated in both name (name. on permit plus PH) and API number (50 -70/80) from records, data and logs acquired for weU(name on permit). Annular disposal has n(Þt been requested. . . Annular Disposal of drilling wastes will not be approved. . . Annular Disposal of drilling wastes will not be approved. . . DISPOSAL INTO OTHER Please note that an disposal of fluids generated. . . ANNULUS L-) YES + SPACING EXCEPTION Templates are located m drive\jody\templates Enclosed is the approved application for permit to drill the above referenced well. The permit is approved .subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Companv Name) will assume the liability of any protest to the spacing exception that may occur. - 1.J:5~ WELL PERMIT CHECKLIST COMPANY tJJ1(;:;c.¿::l/ WELL NAME ~ - / 2-1e. 7::>.3 PROGRAM: Exp - Dev V Redrll V Serv - Well bore seg - Ann. disposal para req - FIELD & POOL S2D/.zD INITCLASs---::J;>Ev fOIL- GEOLAREA:>?z..D UNIT# O/ZD?6 ON/OFFSHOREtY=/-= ADMINISTRATION 1 Permit fee attached Cf) N - / ,. . / / . 2: Leas~numberappr~pri~t~.¥<~ :~~~-Ï:z~~Þ~~1 Y@--* ~I..A-ý~ ~C-1T?~ '-t-- -riz:>L 17s~:?1' 'fr~ ~~, ~þvcJl 3. Uniquewellnameandnumber.................. I ~ -rÞ ~ rlD'-IR73D. ~Á, / t/ 4. Well located in a defined pool.. . . . . . . . . . . . . . . . . N /--1 '7 ~ / L . ~ j / ¡I/ £) 5. Well located proper distance from drilling unit boundary. . . . NN'1"t?7)<"19"'~"':'t'Yo /'e---~ J/?£/~Z - /\/ r: 6. Well located proper distance from other wells.. . . . . . . . . n ("'.1 4 fJ#'. 7. Sufficient acreage available in drilling unit.. . . . . . . . . . . ZVNN'" r{ //911' a ~r ~ -.r--/: - /Y ~ 8. If deviated, is wellbore plat included.. . . . . . . . . . . . . . C::t? 9. Operator only affected party.. . . . . . . . . . . . . . . . . . ~N 10. Operator has appropriate bond in force. . . . . . . . . . . . . N 11. Permit can be issued without conservation order. . . . . . . . ~1J g~---/. 12. Pennit ca~ be issued without administrative approval.. . . . . C{'~Y' * IY"? *.?q'ð¿j3. Can permit be approved before 15-daywalt.. . . . . . . . .. ð ENGINEERING 14. Conductor string provided. . . . . . . . . . . . . . . . . . . 15. Surface casing protects all known USDWs. . . . . . . . . . . 16. CMT vol adequate to circulate on conductor & surf csg. . . . . 17. CMT vol adequate to tie-in long string to surf csg. . . . . . . . 18. CMT will cover all known productive horizons. . . . . . . . . . 19. Casing designs adequate for C, T, B & permafrost. . . . . . . 20. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . 21. If a re-drill, has a 10-403 for abandonment been approved. . . 22. Adequate wellbore separation proposed.. . . . . . . . . . . . 23. If diverter required, does it meet regulations. . . . . . . . . . 24. Drilling fluid program schematic & equip list adequate. . . . . 25. BOPEs, do they meet regulation. . . . . . . . . . . . . . . . AP,Pij. DAT~ 26. BOPE press rating appropriate; test to tf500 psig. \iJ<:¡Pr ? {Z7[ 0 L 27. Choke manifold complies w/API RP-53 (May 84). . . . . . . . 28. Work will occur without operation shutdown. . . . . . . . . . . 29. Is presence of H2S gas probable.. . . . . . . . . . . . . . . . 30. Permit can be issued w/o hydrogen sulfide measures. . . . . 31. Data presented on potential overpressure zones. . . . . . . 32. Seismic analysis of shallow gas zones. . . . . . . . . . . . . A~~R ....DjIT~ / 33. Seabed condition survey (if off-shore). . . . . . . . . . . . . J.æ .}'..?~ ¿:;¿ 34. Contact name/phone for weekly progress reports [exploratory ANNULAR DISPOSAL 35. With proper cementing records, this plan (A) will contain waste in a suitable receiving zone; . . . . . . . (B) will not contaminate freshwater; or cause drilling waste. .. to surface; (C) will not impair mechanical integrity of the well used for disposal; Y N (D) will not damage producing formation or impair recovery from a Y N pool; and (E) will not circumvent 20 AAC 25.252 or 20 AAC 25.412. Y N GEOLOGY: ENGINEERING: UIC/Annular: COMMISSION: R~ SFD- GEOLOGY APPR DATE ,¥,¥:',Z) N!/r ¥----N- S V--tt- ~N ì : ¡J ~ þ ", $ <; ~ .~ ¡ N Apf tV itJ:L L [2J'í It) ~. l!l2N ~ ~ 'ALIA ~ ~ M<"P 0 ~{ f' ç...'. ~"1 '-\ J \=>...:', ?, ~~~, \ ~ I ~ ",,-a ~ Y@ ~ :- ~J,A YN!1/j " Iy] Y N Y N Y N ¡Jo ~I'tU)N' rt s.r}9 ~; ~6 L<ßy-þ j fA ~hJ W-f{(. Commentsllnstructions: TEM WGA \JtiGJr--' COT ' DTStY3/Z7/0 L JMH G:\geology\templates\checklist.doc