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Home My WebLink About212-091CAUTION: 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 From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: North Fork Unit 23-25 (PTD# 212-091) Date:Tuesday, June 24, 2025 11:40:23 AM From: Wallace, Chris D (OGC) Sent: Tuesday, June 24, 2025 11:37 AM To: Daniel Taylor <dtaylor@hilcorp.com> Cc: Luke.Suchecki@hilcorp.com Subject: RE: North Fork Unit 23-25 (PTD# 212-091) Daniel, Looking over the history of this well/DIO 45 I see an expired Sundry 322-345 which was to convert the well from gas producer to waste disposal. I see no injection/disposal volumes. I see no MIT’s. No step rate test or other DIO required testing. For DIO 45 and DIO 45.001 I see the expiration extension to April 16, 2025, with no application for extension received before the April 16, 2025 expiration. So this has expired. Hilcorp should apply for a new DIO for this well when it has all the required 20 AAC 25.252 information ready. I see AEO 17 issued July 20, 2022 which was based on NFU 23-25 conversion. Hilcorp should review this AEO and ensure that Hilcorps planned use of NFU 23-25 meets the findings conclusions (eg Conclusion 6 about affected area) of AEO 17 and apply for a modification if warranted. AEO’s have a stringent EPA approval component. The AEO has not expired – however the basis of AEO 17 was NFU 23-25 and so there are some concerns about the validity of AEO 17 if NFU 23-25 doesn’t become a Class II disposal well. 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: Daniel Taylor <dtaylor@hilcorp.com> Sent: Thursday, June 19, 2025 8:30 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: North Fork Unit 23-25 (PTD# 212-091) is safe. Mr. Wallace, NFU 23-25 (PTD# 212-091) is the only injection well contained within DIO 45 for North Fork Unit. According to rule 20 AAC 25.252 (h)(2)(j) “If disposal or storage operations are not begun within 24 months after the approval date, the approval will expire unless an application for extension is approved by the Commission.” The AOGCC under DIO 45.001 granted Vision Energy, LLC a one-year extension to the DIO on March 18th, 2024, and it expired April 16th, 2025. In May 2025, Hilcorp took over ownership of NFU and needs a Class II injection well on lease. Would it be possible to get an extension to DIO 45 for Hilcorp to have time to evaluate all wells in North Fork Unit and get NFU 23-25 ready for service? Thank you for your consideration. Regards, Daniel Taylor, P.E. Well Integrity O: 907-777-8319 C: 907-947-8051 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis 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. 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Northern Lights Blvd - Suite 515 Anchorage, AK 99503 E&hϮϯͲϮϱ͙ϮϭϮͲϬϵϭ WĂŐĞϭŽĨϮ :HOO1DPH±1)8« :HOO6XPPDU\ &XUUHQW6WDWXV:HOOVKXWLQGXHWRQRIORZ 6FRSHRI:RUN &RQGXFWZLUHOLQHWDJZWHPSHUDWXUHORJ &RQGXFW3UHOLPLQDU\0,7QRWLI\$2*&&PLQLPXPKRXUVLQDGYDQFH &RQGXFWWXELQJSUHVVXUHWHVW 3HUIRUDWHQHZLQWHUYDO &RQGXFWIORZWHVWRIQHZLQWHUYDO 5HSHUIRUDWHH[LVWLQJLQWHUYDOV &RQGXFW6WHS5DWH7HVW &RQGXFWIROORZXSWHPSHUDWXUHORJ &RQGXFW)RUPDO0,7ZKHQRSHUDWLRQVKDYHVWDELOL]HGQRWLI\$2*&&DVEHIRUH *HQHUDO:HOO,QIRUPDWLRQ 5HVHUYRLU3UHVVXUH79' SVL#¶0'¶79' 0$63 SVL :HOOKHDG7\SH3UHVVXUH5DWLQJ 9HWFR*UD\±0:HOOKHDG$VVHPEO\ %23&RQILJXUDWLRQ 6OLFNOLQH(OLQH:/9 :HOO7\SH 3UHVHQWO\*DVFRQYHUWLQJWR:'63 (VWLPDWHG6WDUW'DWH 0LG0D\IROORZLQJLVVXHRI$(2DQG',2 1RWH',2ZDVLVVXHGRQ$SULO3XPSLQJRSHUDWLRQVPD\127FRPPHQFH XQWLOWKH$(2LVLVVXHGDVZHOO 2SHUDWLRQ3URFHGXUH 3UHVVXUHXSRQFRQWUROOLQHWRKROG6&669#¶0'RSHQ 'ULIWWXELQJDQGWDJ3%7'a¶0' 5XQVWDWLFWHPSHUDWXUHORJ 7RSRIIDQQXOXVDQGFRQGXFW0,7WRSVL&RQWDFW$2*&&PLQLPXPKRXUVLQ DGYDQFHIRUWKHRSSRUWXQLW\WRZLWQHVV 0LQLPXPSUHVVXUHUHTXLUHG¶[SVLIW SVL %UXVK%;QLSSOHSURILOHDW¶0'VHWSOXJDQGFRQGXFWWXELQJSUHVVXUH WHVWWRSVL 3HUIRUDWH=RQH$«±¶0' &RQGXFWIORZWHVWRIQHZLQWHUYDO $QDO\]HIORZWHVWGDWD&RQILUPZLWK$2*&&WKDW=RQH$LVQRQFRPPHUFLDO 5HSHUIRUDWH¶±¶DQG¶¶0' D 1HHG WR HQVXUH ZHOO LV XQGHUEDODQFHG VXIILFLHQWO\ WR LQGXFH IORZ EHIRUH FRPPHQFLQJ IORZ WHVW EMP 3HUIRUP LQLWLDO 6WDWLF %RWWRP +ROH 3UHVVXUH 6XUYH\ EHIRUH IORZ WHVW EMP 3UHVVXUH WHVW WR SVL PLQLPXP EMP SVL EMP 3UHVVXUH WHVW ZLUHOLQH OXEULFDWRU DQG SUHVVXUH FRQWURO HTXLSPHQW WR SVL EMP 3XPSLQJRSHUDWLRQVPD\127FRPPHQFHS XQWLOWKH$(2LVLVVXHGDVZHOO 188 W. Northern Lights Blvd - Suite 515 Anchorage, AK 99503 E&hϮϯͲϮϱ͙ϮϭϮͲϬϵϭ WĂŐĞϮŽĨϮ 3HUIRUP6WHS5DWH7HVWSHUDWWDFKHG(3$SURFHGXUH 3ODQRQXVLQJSURGXFHGZDWHU%DVHGRQDSHUPHDELOLW\PGDQGDPLQXWH VWDJHWLPHWKHHVWLPDWHGWRWDOYROXPHQHHGHGLVaEEOVEURNHQGRZQDVIROORZV %30 9ROXPH 7KHHVWLPDWHGJURVVSXPSLQJWLPHLVaKRXUVSOXV 5XQIROORZXSWHPSHUDWXUHORJ $IWHUDQDO\]LQJVWHSUDWHWHVWGDWDDQGWHPSHUDWXUHORJVWXUQZHOORYHUWR3URGXFWLRQ DQGFRPPHQFH&ODVV,,GLVSRVDORSHUDWLRQVDFFRUGLQJWR$2*&&'LVSRVDO,QMHFWLRQ 2UGHU :KHQRSHUDWLRQVVWDELOL]HaGD\VFRQWDFW$2*&&IRUWKHRSSRUWXQLW\WRZLWQHVV IRUPDO0,7 3HUIRUP 0,7,$ WR SVL 1 UNITED STATES ENVIRONME NTAL PROTECTION AGENCY REGION VIII 999 18th STREET - SUITE 500 DENVER, COLORADO 80202-2466 STEP-RATE TEST PROCEDURE January 12, 1999 PURPOSE: The purpose of this document is to provide a guideline for the acquisition of a Step Rate Test (SRT). These procedures are consistent with acceptable oilfield practices. Test results may be used by the Region 8 Underground Injection Control (UIC) offices to determine a Maximum Surface Injection Pressure (MSIP) to provide for the protection of the underground sources of drinking water at an injection well having mechanical integrity. Attached is a form that you may copy and use to record data from your test. Step rate test results must be documented with service company or other appropriate (acceptable) records and/or charts, and the test should be witnessed by an EPA inspector. Arrangements may be made by contacting the Region 8 UIC offices using the EPA toll-free number 1-800-227-8917 (ask for extension 6155 or 6137). STEP-RATE TEST PROCEDURE: 1) The well should be shut in long enough prior to testing such that the bottom hole pressures approximate shut-in formation pressures. If the shut-in well flows to the surface, the wellhead injection string should be equipped with a gauge and the static surface pressure read and recorded. 2) A series of successively higher injection rates are determined using guidelines below, and the elapsed time and pressure values are read and recorded for each rate and time step. Each rate step should last exactly as long as the preceding rate. If stabilized pressure values are not obtained within the rate steps suggested below, the test results may be considered as inconclusive. Formation Permeability (md)Total time per rate-step (min) 5 md 60 min 10 md 30 min 3) Suggested injection rates: 5% 10% 20% 40% Of Anticipated Maximum Injection Rate 60% 80% 100% 4) Injection rates should be controlled with a constant flow regulator that has been tested prior to use. A throttling device is not considered sufficient. 5) Flow rates should be measured with a calibrated turbine flowmeter. 2 6) Record injection rates using a chart recorder or a strip chart. 7) Measure pressures with a down hole pressure bomb. If a surface gauge is used, the test pressures must be corrected for the estimated friction loss at each particular flow rate. 8) Measure and record injection pressures with a gauge or recorder (for immediate test results). Record each time step and corresponding pressure. 9) A plot of injection rates and the corresponding stabilized pressure values should be graphically represented as a constant slope straight line to a point at which the formation fracture, or “breakdown”, pressure is exceeded. The slope of this subsequent straight line should be less than that of the before-fracture straight line (see example). 10) If the formation fracture pressure has definitively been exceeded, as evidenced by at least two injection rate-pressure combinations greater than the breakdown pressure, the injection pump can be stopped, and the line valve closed and pressure allowed to bleed-off into the injection zone. There will occur a significant instantaneous pressure drop (Instantaneous Shut-in Pressure or ISIP), after which the pressure values will level out. This ISIP value must be read and recorded. The ISIP obtained in this manner may be considered to be the minimum pressure required to hold open a fracture in this formation at this well. 11) Once the ISIP is obtained, the SRT is concluded. 12) In the event that the breakdown pressure was not obtained at the maximum test injection pressure utilized, the test results may indicate that the formation is accepting fluids without fracturing. 3 STEP RATE TEST DATA Well: Date: Operator STEP #1 Test Rate ( 5% of maximum rate) ______________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : _________ _________ _________ _________ _________ _________ _______ * * * *Pressure (psi): ________ _________ _________ _________ _________ _________ _______ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- STEP #2 Test Rate ( 10% of maximum rate) ______________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : _________ _________ _________ _________ _________ _________ _______ * * * *Pressure (psi): ________ _________ _________ _________ _________ _________ _______ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- STEP #3 Test Rate ( 20% of maximum rate) ______________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : _________ _________ _________ _________ _________ _________ _______ * * * *Pressure (psi): ________ _________ _________ _________ _________ _________ _______ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- STEP #4 Test Rate ( 40% of maximum rate) ______________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : _________ _________ _________ _________ _________ _________ _______ * * * *Pressure (psi): ________ _________ _________ _________ _________ _________ _______ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- STEP #5 Test Rate ( 60% of maximum rate) ______________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : _________ _________ _________ _________ _________ _________ _______ * * * *Pressure (psi): ________ _________ _________ _________ _________ _________ _______ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- STEP #6 Test Rate ( 80% of maximum rate) ______________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : _________ _________ _________ _________ _________ _________ _______ * * * *Pressure (psi): ________ _________ _________ _________ _________ _________ _______ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- STEP #7 Test Rate ( 100% of maximum rate) ______________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : _________ _________ _________ _________ _________ _________ _______ * * * *Pressure (psi): ________ _________ _________ _________ _________ _________ _______ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- ISIP : _________________ (psi) Test Run / Witnessed By: EXAMPLE STEP RATE TEST The following is an example of a Step-Rate Test with tabular and graphic results. The step-rate test data and graphic results of the test are on the following pages. The operator of Anywell #1 set up a SRT for the following conditions: A) Maximum anticipated injection rate was 4 bbl/min. B) Following the recommended test procedures, the operator planned on using these rates for the test: 1) 5% of 4 bbl/min = 0.2 bbl/min 2) 10% of 4 bbl/min = 0.4 bbl/min 3) 20% of 4 bbl/min = 0.8 bbl/min 4) 40% of 4 bbl/min = 1.6 bbl/min 5) 60% of 4 bbl/min = 2.4 bbl/min 6) 80% of 4 bbl/min = 3.2 bbl/min 7)100% of 4 bbl/min = 4.0 bbl/min C) The formation permeability is estimated as 100 md, therefore each step will last for 30 minutes. For this test, the injection formation broke down at approximately 1200 psi, and the ISIP was listed as 1000 psi. Because the injection formation will part at 1000 psi, the maximum injection pressure will be held to the ISIP. If the formation had not broken down at 1200 psi, the maximum allowable injection pressure would be the maximum pressure obtained during the test. EXAMPLE STEP RATE TEST DATA Well: ANYWELL #1 Date: 2/31/94 Operator Lotsa Oil Company STEP #1 Test Rate ( 5% of maximum rate) ___0.2_________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : ___0____ ____5___ ___10___ ___15___ ___20____ __25_____ __30__ * * * *Pressure (psi): ___0___ ___90____ ___95___ ___98___ ___99____ __100___ _100__ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- STEP #2 Test Rate ( 10% of maximum rate) ___0.4_________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : ___0____ ____5___ ___10___ ___15___ ___20____ __25_____ __30__ * * * *Pressure (psi): ___80__ ___170___ _185___ ___195__ ___199___ __200___ _200__ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- STEP #3 Test Rate ( 20% of maximum rate) ___0.8_________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : ___0____ ____5___ ___10___ ___15___ ___20____ __25_____ __30__ * * * *Pressure (psi): ___190__ ___325__ ___385__ __392__ __398__ __399__ __400__ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- STEP #4 Test Rate ( 40% of maximum rate) ___1.6_________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : ___0____ ____5___ ___10___ ___15___ ___20____ __25_____ __30__ * * * *Pressure (psi): ___380__ ___700__ ___790__ __792__ __795__ __798__ __802__ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- STEP #5 Test Rate ( 60% of maximum rate) ___2.4_________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : ___0____ ____5___ ___10___ ___15___ ___20____ __25_____ __30__ * * * *Pressure (psi): ___750__ ___990__ __1030__ _1090__ __1150__ ___1180_ __1201__ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- STEP #6 Test Rate ( 80% of maximum rate) ___3.2_________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : ___0____ ____5___ ___10___ ___15___ ___20____ __25_____ __30__ * * * *Pressure (psi): __1100__ __1250_ __1326__ __1370__ __1390__ __1395__ __1400_ * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- STEP #7 Test Rate ( 100% of maximum rate) ___4.0_________ (bbl/min) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), *Time (min) : ___0____ ____5___ ___10___ ___15___ ___20____ __25_____ __30__ * * * *Pressure (psi): __1350_ __1450_ __1500__ __1530__ __1570__ __1590__ __1600__ * 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They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ai a- © q_ ] Well History File Identifier Organizing(done) ❑ Two-sided ❑ Rescan Needed RES AN: OVERSIZED: NOTES: C for Items: ❑ Mas: Grayscale Items: ogs: M U P ❑ Poor Quality Originals: ❑ Other: ❑ Other: BY: AMP Date: q J if /s/ Project Proofing fVJ BY: 41121MDate: R/5—// /s/ Of Scanning Preparation Li— x 30 = 1,0 + �,(O = TOTAL PAGES /11-6, ^ _ (Count does not include cover sheet) BY: S ..Maria Date: /s/ Production Scanning Stage 1 Page Count from Scanned File: (Count does include cover sheet) g � �'7 Page Count Matches Number in Scanning Preparation: VS NO BY: 4210 Date: (8/51/4 /st144j° Stage 1 If NO in stage 1, page(s)discrepancies were found: YES NO BY: Maria Date: /s/ 7a Stage 2 Additional Well Reports: it NO TOTAL PAGES: P Digital version appended by: Meredith Michal P�\ Date: /s/ 'a Final Page Count: Stage 1 + Stage 2: TOTAL PAGES:a07 Scanning is complete at this point unless rescanning is required. ReScanned BY: Maria Date: /s/ Comments about this file: Quality Checked 7/8/2014 Well History File Cover Page_20140708.doc o 0) J acs o' o 0 f6 0 2 0 0 LL C 7 7 J C) 2 O) J p 7:Co. l op7 y a) cr0 y N h �a 0 J U -a p°_ U Z m Z w Z aa)) Z y U c �, o 0) o J 0 0) 0 E 0 m h d a0 a0 °-0 0.0 E N Z p J C .0 E J o C 0'°O a° 0 7 0 7 0 7 0 7 >. M 0 ail I c r g ° E U '� m Cs rg0 •f•t U a U a 'n a '� a rn N m a U pa re a cn a a a m E a�'i E E E c c E a) E O m - a) v m cG 00 [too oU oU co Z z g U O ° >° 0 >° 0 >° 0 o mu- 'O7 a 0 oCe ° oo`ft ° oC > oc ° F. ('n c w 2 I- 2 1- 2 1- 2 w0i= 00cn 2 a 0 2aO I-00 Hao Q o •0 c LE a) N N_ N N N N N N N_ N_ N N N _N N_ O O O O O O O O O O O O OE O Q d o N N N N N N N N N N N N N N N (? 0 rG N N N N N N N N N O) _O _O 0) Q)0 N J .-- p J � � -J E h ° c c c c c c c c c c c c c c c i 7 '- a) a) 0 a) a) a) a) a) a) a) a) a) a) a) a) w m c 00 0 a a a a a a a a a a a a a a a F.. 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Q Z F- a) 7 N O J o ai c T E CL G N a) cn a eo E U = QN La I G W N O O F_- M H • co Z N W M Y t Cacc M ° w t o 2 N Cl) x o Cl) ccQ z Q 6 a z E Q d 0 Ir E ..-- m z d C 0 rn o z �I E 1 O 1 t I •• m ° t1 a 00 B. d N a m c z o. a L0 tto m J a Q' G °° 0 Z U Q �' u H Z y U C +� C CRI O - CDO `n N y V U y '°. E a 5 a� a mo E E a 17,--, Q 0 ¢r 0 0 Page 1 of 3 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, February 12, 2013 10:31 AM q To: 'Stephen F. Hennigan' f / Y 2. / Z- O [ ( Subject: RE: Armstrong North Fork That makes more sense ... we will classify it as a shut-in Gas producer. I see it has a SSSV so there is already a barrier in the tubing string. No additional wellwork will be required then. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Stephen F. Hennigan [mailto:shennigan@peiinc.com] Sent:Tuesday, February 12, 2013 10:19 AM To: Schwartz, Guy L(DOA) Subject: RE: Armstrong North Fork Maybe I should have said something like "Shut-in for buildup" or something like that. Armstrong DOES INTEND TO TRY TO FLOW IT IN A COUPLE OF MONTHS. What do you suggest? 74aabs .5ft92,60 s- / .e.r.0420.0 Project Manager/Engineer Petroleum Engineers Inc a Hamilton Company 500 Dover Boulevard, Suite 310 I Lafayette, LA 70503 Office: 337-984-2603 Cell: 337-849-5345 From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Tuesday, February 12, 2013 1:08 PM To: Stephen F. Hennigan Subject: RE: Armstrong North Fork Steve, A BPV must be installed and downhole plug ...for long-term shut-in and suspend status. I realize the open perfs are water producing but rules are rules. Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 2/12/2013 Page 2 of 3 444-3433 (cell) From: Stephen F. Hennigan [mailto:shennioan@peiinc.com] Sent: Tuesday, February 12, 2013 9:38 AM To: Schwartz, Guy L (DOA) Subject: RE: Armstrong North Fork It is hooked up to the production system and the valves are closed. 7-de .5 /s, / . e Project Manager/Engineer Petroleum Engineers Inc a Hamilton Company 500 Dover Boulevard, Suite 310 I Lafayette, LA 70503 Office: 337-984-2603 Cell: 337-849-5345 From: Schwartz, Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent: Tuesday, February 12, 2013 12:32 PM To: Stephen F. Hennigan Cc: McMains, Stephen E (DOA) Subject: RE: Armstrong North Fork Steve, The well report doesn't specify what was done to the well to secure it. At minimum a BPV and downhole plug in tubing must be set to leave the well suspended. Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Schwartz, Guy L (DOA) Sent: Monday, February 04, 2013 8:44 AM To: 'Stephen F. Hennigan' Subject: RE: Armstrong North Fork Steve, A 10-407 should be submitted.. with the final completion shown. You will have to suspend the well properly per 20 AAC 25.110 ... It would be helpful for me to look at the current well completion before you submit a 10-407. Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) 2/12/2013 • Page 3 of 3 From: Stephen F. Hennigan [mailto:shenniqan@peiinc.com] Sent: Monday, February 04, 2013 4:00 AM To: Schwartz, Guy L(DOA) Subject: Armstrong North Fork Guy The Armstrong 23-25 did not test as expected. The well is currently shut-in while lengthy detailed evaluations are going on. Both the APD and the Sundry required the 10-407, but we want to be able to re-enter at some time and possibly finish the planned perfing, reperf or stimulate the zones. What status should we indicate on the 10-407 (ie Other-Opns shutdown)or should we use the 10-404? • ride G5 /s- / Project Manager/Engineer Petroleum Engineers Inc a Hamilton Company 500 Dover Boulevard, Suite 3101 Lafayette, LA 70503 Office: 337-984-2603 Cell: 337-849-5345 2/12/2013 Y STATE OF ALASKA • AL A OIL AND GAS CONSERVATION COM. 3ION WELL COMPLETION OR RECOMPLETION REPORT AND LOG • la.Well Status: Oil Gas'X . SPLUG 0 Other L Abandoned ❑ Suspendec e 1 b.Well Class: 20AAC 25.105 20AAC 25.110 Development Q . Exploratory ❑ GINJ ❑ WINJ❑ WAG ❑ WDSPL❑ No.of Completions: Service ❑ Stratigraphic Test ❑ 2.Operator Name: 5.Date Comp.,Susp.,or 12.Permit to Drill Number: Armstrong Cook Inlet,LLC Aband.: 1/23/2013 212 091 ' 3.Address: 6.Date Spudded: 13.API Number: 1421 Blake Street,Denver,Colorado 80202 9/16/2012 . 50-231-20037-00-00 ' 4a.Location of Well(Governmental Section): 7.Date TD Reached: 14.Well Name and Number: Surface: 648'FSL X 1481'FEL • 26 4S 14W • 10/9/2012 North Fork Unit#23-25 • Top of Productive Horizon: 8.KB(ft above MSL): 680' • 15.Field/Pool(s): 1904'FSL X 1887'FWL 25 4S 14W GL(ft above MSL): 658' • Total Depth: 9.Plug Back Depth(MD+TVD): North Fork Undefined Gas Pool 1911 FSL X 1892'FWL 25 4S 14W ,10542 9378 • 4b.Location of Well(State Base Plane Coordinates,NAD 27): 10.Total Depth(MD+ND): 16.Property Designation: Surface: x- 199,930 . y-2,121,190 Zone- 4 .10785 9621 • ' ADL 391211/ADL 2095 TPI: x- 203,327 y-2,122,330 Zone- 4 11.SSSV Depth(MD+TVD): 17.Land Use Permit: Total Depth: x- 203,319 y-2,122,309 Zone- 4 347'MD 347'ND 18.Directional Survey: Yes u No u 19.Water Depth,if Offshore: 20.Thickness of Permafrost MD/ND: (Submit electronic and printed information per 20 AAC 25.050) NA (ft MSL) NA 21.Logs Obtained(List all logs here and submit electronic and printed information per 20AAC25.071): 22.Re-drilllLateral Top Window MD/TVD: LWD-GR,RES.,DENSITY,NEUTRON,SONIC,CALIPER 23. CASING,LINER AND CEMENTING RECORD WT.PER GRADE SETTING DEPTH MD SETTING DEPTH ND HOLE SIZE CEMENTING RECORD AMOUNT CASING Ft TOP BOTTOM TOP BOTTOM PULLED 16 84 X56 0' 117' 0' 117' DRIVEN NA 10 3/4" 45.5 L80 0' 3102' 0' 2702' 13 1/2" 761sx lead @12 ppg and 200 sx tail @14.8 ppg 7 " 26 L80 0' 10716' 0' 9552' 8 3/4" 582 sx lead©12.7 ppg and 344 sx tail @ 13.5 ppg 24.Open to production or injection? Yes Q No❑ If Yes,list each 25. TUBING RECORD interval open(MD+TVD of Top&Bottom;Perforation Size and Number): SIZE DEPTH SET(MD) PACKER SET(MD/TVD) See attached Well Bore Diagram - 2 7/8" 8813' 8790 MD 7627'TVD 8829-8836'MD 7666-7673'ND 8950-8974'MD 7787-7811'TVD RECEIVED26. ACID,FRACTURE,CEMENT SQUEEZE,ETC. t;„J i ',i's DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 1 I FEB 1 12013 NA i---,e. AOGGC 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): na Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 1/8-1/22/2013 Test Period -.I.na none none various na Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(con-): Press. na na 24-Hour Rate -► 28. CORE DATA Conventional Core(s)Acquired? Yes❑ No❑✓ Sidewall Cores Acquired? Yes ❑ No❑✓ . If Yes to either question,list formations and intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (submit separate sheets with this form,if needed).Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 25.071. RBDMS FEB 121013 +Mk Form 10-407 Revised 12/2009 CONTINUED ON REVERSE Submit original only 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No If yes,list intervals and formations tested, briefly summarizing test results.Attach separate sheets to this form,if Sterling Surface needed,and submit detailed test information per 20 AAC 25.071. Beluga 1,457 1,414 Multiple Tyonek formations tested. See attached Well Bore Diagram with Tyonek 6,078 4,996 perforations. Lowest interval had show of water,no gas,no water to surface Tyonek 6000 SS Faulted except by swabbing. Upper two intervals tested together,tight,negligible amount of gas. WHP=145#overnight buildup. See attached test summary Tyonek 8500 SS 9,395 8,231 with choke sizes,well head pressure,rates and cumulative production. / Formation at total depth: Tyonek 31. List of Attachments: well test,WBS,surveys,summary rpt 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: shennigantc'Dpeiinc.com Printed Name: Edward Teng Title: Vice President-Engineering S• : • :: - �� -.. Phone: (303)623-1821 Date: 1/26/2013 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1b: Classification of Service wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection,Observation,or Other.Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI(Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift,Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 12/2009 , A RECEIVED ARMSTRONG FEB 11 2013 <<,o,4 Ia/el,, LSC ACGCC January 26, 2013 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: 10-407 for Sundry 312-403 Armstrong Cook Inlet, LLC NFU#22-25(PTD No. 212-091) Dear Ms. Foerster, Armstrong Cook Inlet, LLC hereby submits the 10-407 for completing and testing the subject well. The • initial tests on zones perforated resulted in no flow. However, the SITP has been building. The well is presently secured and shut in and suspended for additional geologic and reservoir evaluation to determine potential additional testing activity. If you have any questions or require additional information, please contact me at(303)623-1821 or Stephen Hennigan at(337)849-5345. Sincerely, 4111111,* _ice 1. 1. Edward Teng Vice President-Engineering Armstrong Cook Inlet, LLC Enclosures Cc: Stephen Hennigan—Petroleum Engineers for Armstrong Cook Inlet, LLC 1421 111(tkc,S`treet, Denver, ('(S0202 013)-623-1S21 /'h (3031-623-3019/ UV Ni Permit#: 212091 is NFU #23-25 API#: 50-231-20037-00-00 Prop.Des: ADL-391211/2095 648' FSL, 1481' FEL KB elevation: 681' (22'AGL) S33 T6N R11 W S.M. Latitude: 59*47'46.955" Longitude: 151*37'45.495" Spud: 9-16-2012 Armstrong Cook Inlet, LLC _ TD: 10-9-2012 Rig Released: 10-25-2012 Structural Pipe 16" X-56 84 ppf Top Bottom MD Surf 117' TVD Surf 117' lig IASurface Casing Baker SSSV set at 347'MD. 10-3/4" L-80 45.5ppf ‘1118\11 TopBottom MD 0' 3,102' Pollard Chem.Inj.Nipple set at 2475'MD. TVD 0' 2,702' .X 2 7/8"8rd EUE-MSurface Cement Descriptio Spacer-8.4 ppg 20 bbls-Mud Clean II Production Casing Lead 12 ppg(Yield 2.61)275 bbl761 sacks Type I Cement+10%bwoc 7" assn-80 26 ppf Top Bottom BA-90+0.005 lbs/sack Static Free+2% ' MD 0' 10,716' bwoc Calcium Chloride+0.5%bwoc EC-1 TVD 0' 9,552' +0.2%bwoc CD-32+0.1%bwoc ASA- 301+1 gals/100 sack FP-6L+2%bwoc Sodium Metasilicate+134.3%F Wate ail$Lurrt pg(Yield 1.33) Tubing 48 bbls-200 sacks Type I Cement+0.005 2 7/8" L-80 8.6 ppf lbs/sack Static Free+2%bwoc Calcium . Top Bottom Chloride+1 gals/100 sack FP-6L+56.3% MD 0' 8813' Fresh Water Displacement-8.34 ppg 3 TVD 0' 7650' bbls Fresh water follwed by: 10.1 ppg 47 bbls Mud Baker Packer set @ 8790' MD 7627'TVD K i. Perforations Measured Depth ND 8829-88 6 7666-7673 8950 74 7787-7811 ,: 10,13 10,169 8974-9005 Owens thru Production Casing Cement Description tubing BP @ M/U CMT HEAD,LOAD PLUGS IN CMT HEAD,R/U CEMENTERS PJSM W/ALL PERSONEL INVOLVED WITH CMT JOB. CMTJOB TEST LINES 3000 PSI,DROP 4-- 1: 10,130'MD w/ BTTM PLUG,PUMP 40 BBL SEAL BOND SPACER,10 PPB,582 sacks Class G 36'of cement on Cement+10%bwoc BA-90+0.0051bs/sack Static Free+2.5%bwoc BA-S6+ top. TOC - 0.4%bwoc R-3+0.5%bwoc EC-1+0.1%bwoc ASA-301+1gals/100 sack FP-6L @10,094'MD +0.5%bwocSodiumMetasilicate+104.1%Fresh Water yld 2.16 for 223 BBLS LEAD CMT @ 12.7 PPG 44 sacks Class G Cement+10%bwoc BA-90+0,005 ssackStatic +2.5%bwocBA-56+0.4%bwocR-3+0.5%bwocEC-1+ 0.1%bwoc ASA-301+1 gals/100 sack FP-6L+0.5%bwoc Sodium Metasilicate+ 81.9%Fresh Water yld 1.82 for 111 BBLS TAIL CMT @ 13.5 PPB,DROP TOP TD PBTD PLUG,PUMP 406 BBLS H2O,(DID NOT BUMP PLUG)FINAL LIFT PRESSURE 1900 10,785'MD 10,542'MD PSI. BLED OFF 3 BBLS FLOATS HOLDING,CMT IN PLACE @ 1:20 AM 9,621'TVD 9,378'TVD Well Name&Number: North Fork Unit#23-25 Lease: Kenai Loop County or Parish: Kenai Penisula Borough State: Alaska USA Perforations(MD): Perf(TVD): Country: • Angle @KOP and Depth: 5 deg @ 623'MD Angle @ Perfs: Date Completed: KOP TVD: 21' Prepared By: Craig Rang/Stephen Hennigan Last Revision Date: February 1,2013 RKB: A ARMSTRONG Coad In/al,LLC Armstrong Cook Inlet, LLC NFU #23-25 DRILLING OPERATIONS SUMMARY PTD 212-091 Sundry 312-403 Block/Sec 26 4S 14W Nabors Rig 99 08/24- Rigging up Nabors Rig 99 and awaiting the AOGCC rig inspection 09/09/12 09/09/12— Rigging up Nabors Rig 99 and awaiting the AOGCC rig inspection 09/13/2012 09/14— Armstrong accepted rig. Cont RU. AOGCC inspection. Approval to spud from AOGCC Sat, 15 09/15/2012 Sep 2012 01:31pm 9/16/2012 Fin RU. Spud 1400hrs 09/15/2012. Drill f/137'-501'. KO, drill and slide to 871'MD. • 09/17/2012 Directionally drill f/871'-2111'MD. Circ for short trip. 09/18/2012 Finish circ hole clean. Short trip to top of HWDP. Minor pulls. TIH. Directionally drill f/ 2111'-2715'MD. 09/19/2012 Drill to 3102'MD; pump30 BBI Nut Plug/HV sweep; hole seems to be gauge; no increase in cuttings w/sweep. Pump second HV sweep showing gauge hole also. Start POH to collars at 03:00. 09/20/2012 Fin POH to collars. RIH to 2900; break circ and wash last stand down; no problems, no fill. Pump HV sweep; circ and condition hole, 2 btms up. Monitor well; pump dry job, POOH to drill collars. Set back. LD BHA. 09/21/2012 RU AND RUN 10 3/4 CASING. CIRCULATE HOLE WHILE RD WFT AND RU FOR DECK, FALSE ROTARY, FLOW NPPLE; VERY FEW CUTTINGS OVER THE SHAKERS W/PUMPING 7.5 BPM 7600 TOTAL STKS. 09/22/2012 RIH W/DP; CIRC HOLE W/STAB-IN TOOL;CMT AND DISPLACE. 77bbls cmt to surface. POH W/DP; START ND DIVERTER 09/23/2012 NIPPLE DOWN DIVERTER, PICK UP BOP AND MAKE ROUGH CUT ON 10 3/4" CASING.SET DOWN STACK AND NIPPLE DOWN. PREPARE 16" AND 10 3/4" FOR STARTING HEAD. WELD OUT SAME PER PROCEDURE. 09/24/2012 ALLOW STARTING HEAD TO COOL PRIOR TO TESTING.TEST FAILED ON WELD. CLEAN AND REWELD GET-GOOD TEST.START NIPPLING UP BOPE. INSTALLED RAMS IN SNGL GATE. 09/25/2012 NIPPLE UP PROGRESSING, MIXING MUD. 09/26/2013 Fin NIPPLE UP. PICKING UP TEST TOOLS AND SETTING WEAR BUSHING. 09/27/2012 MADE UP OUR TEST TOOLS AND TESTED BOPE PER PROCEDURE 4K HI AND 250 LO, HELD ALL TEST FOR 5 MIN AND DOCUMENTED ON CHART RECORDER. RIG UP POLLARD WIRELINE AND RUN A CBL. UNABLE TO GET ALL THE WAY DOWN WITH LOGGING TOOLS. LOG OUT. 09/28/2012 MADE UP BHA AND RAN IN HOLE PICKING UP PIPE FOR CLEANOUT. PERFORM CASING TEST PLOTTING NUMBERS FOR LEAKOFF.AT 1100 PSI '0' RING FAILED IN WELLHEAD AND SO DID WELDS AROUND HEAD.AIR ARC OUT OLD WELD AND REWELD PER PROCEDURE WITH VETCO. 09/29/2012 Clean up wellhead/cellar; remove previous weld; prep and re-weld. RIH;tag bottom ;CBU before testing csg. 09/30/2012 Circulate mud until cleaned up. Pressure test casing to 3000 psi. Drill out FC, cement,shoe and 20'of new hole. Perform LOT to 14.8 ppg EMW. POH with bit and BHA. RU and run CBL. Looked good. Begin making up BHA#3. 10/01/2012 PU BHA;Test MWD and LWD for signals; RIH picking up 60 jts of DP. Drill f/3122'to 4090' . 10/02/2012 Drill/slide from 4090'to 6094'. Start dropping angle at 5680' holding azimuth at 69.5°. 10/03/2012 Drill/slide from 6092'to 7050' dropping angle to 12.77°. Circulate hole clean pumping 2 1/2 BU; shakers very clean. POH to 3708'. 10/04/2012 Finish POH; stand back BHA. RU and test BOP's. Finish BOP test on 10-4-12 at 12:30am as per Lou G. 10/05/2012 RIH; PU 69 jts of DP; slip and cut drlg line; break circulation at 5000'; RIH to 6955', wash to bottom; 600 units trip gas, some thick mud. Drill from 7050'to 7360'. 10/06/2012 Drilling from 7360'to 8340' . 10/07/2012 Drill to 8573; Sh trip to 7050';trip looked good. Drill to 8957'. 10/08/2012 Drill from 8957'to 9530; CBU and short trip to 8472'. Hole is good. Drilling from 9531'to 9840'. 10/09/2012 DrI to 10584'; CBU and short trip to 9526'; RIH picking up drill pipe.. RIH to 10488'; wash and rotate to bottom. Drill to 10785' ./ 10/10/2012 Circ hole clean; Pump around HV sweep. POH to 6510; work out of hole to 5810; Backream out of hole to 5620; POH the rest of the way. LD BHA 10/11/2012 Finish laying down BHA. RU and test BOP's. Make dummy run on 7" landing jt, lock down screws. Make up new BHA and RIH. Remove, rebuild, install and test hydraulic valve on pipe rams before exiting surface casing as per Lou Grimaldi. 10/12/2012 RIH to 10,080';wash and ream to bottom. Circulate bottoms up then pump a HV sweep around while rotating 100-115 and reciprocating 95'. Circulate until shakers cleaned up; POH laying down drill pipe. Work through tight spots at 6646-6629, 6450-6446, and 6250-6240. 10/13/2012 Backream from 6250 to 5983'; change out encoder on top drive,wrong encoder, service top drive. Pull 2 stands; backream from 5722 to 5364'. POH to the shoe. Lay down drill pipe. Pipe was over torqued while backreaming due to faulty encoder. 10/14/2012 Finish LD 5" DP; LD 5" HWDP and BHA. Examine bit and stabilizers for wear. Inventory all 4" HWDP and XO's. Change rams to 4 X 7 VBR; RU and start testing BOP" 10/15/2012 Finish TEST BOP'S. 10/16/2012 PICK UP 5" HWDP.CHANGE ELEVATORS, PICK UP 4" DP. CUT AND SLIP DRILL LINE. CHANGE OUT GRABBER BLOCKS ON TOP DRIVE. PICK UP 4" DP. 10/17/2012 CUT AND SLIPPED DRILLING LINE, PICKED UP PIPE,STOOD BACK 4", PICKED UP 4"AND POOH AND MAKE UP BHA. RIH PICKING UP 4" DRILL PIPE. 10/18/2012 FINISH P/U DRILL PIPE, RIH WASH & REAM AS NEEDED to 10740'. 10/19/2012 CIRC HOLE CLEAN, PUMP SWEEP, POH, L/D BHA, RIG UP TO RUN CSG. 10/20/2012 R/U TO RUN 7" CSG, HELD PJSM W/DRLG CREW&CSG CREW, RUN 5 JT SHOE TRACK AND TEST FLOAT EQUIP, (OK)CONTINUE IN HOLE W/CSG, CIRC B/U @ 3100' &5500'. 10/21/2012 FINISH RUN CSG, LAND CSG ON HANGER @ 10716', CIRC HOLE FOR CMT JOB, CMT 7" CSG LAY DOWN CMT EQUIP AND LANDING JT, RIG FLOOR&TOP DRIVE UP FOR DRLG. P/U 1T 4" DP, RUNNING TOOL,AND PACKOFF . C'"� p S4r ? 10/22/2012 SET PACK-OFF,TEST 5000 PSI (OK), M/U C/O ASSEMBLY, RIH TAG CMT @ 10542', PUMP HI- VIS SWEEP, LAY DOWN DRILL PIPE. 10/23/2012 LAY DOWN 4" DP, R/U E-LINE RUN BOND LOG TO 10,540', LOAD PIPE SHED W/2 7/8 TBG, TEST LOWER PIPE RAMS W/2 7/8 TESTJT. 10/24/2012 TEST CSG 4000 PSI 30MIN CHART(OK) R/U WEATHERFORD TONGS, RUN 2 7/8 PRODUCTION TBG. 10/25/2012 FINISH RUN TBG, DISPLACE W/INHIBITED 6% KCL, SET PACKER,TEST TBG,TEST ANULAS, R/D TBG TOOLS&TEST EQUIP. NIPPLE DN BOP EQUIP, MOVE PIPE SHED OUT AWAY FROM RIG. 10/26/2012 6 HRS/NIPPLE DOWN BOP AND CLEAN PITS . Release Rig to 22-35 well. Well shut in while drilling/completing 22-35 1/9/2013 PJSM. R/up lubricator/swab cup. RIH. 26 swabs, 16.5 bbl fluid.Swabbing not producing results at 3240'. R/dwn slickline, R/up eline. M/up Iub/GR/CCL.Test to 4000. M/up 15'strip guns. RIH to 8790,obstruction. Old morning rpt, bar dropped. Not recovered. Confirm w/1.84" g/ring. RIH retrieve. RIH perf 10154-10169. M/up RIH 2nd set guns. Perf 10138- 10154. POOH 1/10/2013 Confirmed all shots fired. RIH w/blind box, chk fluid level.At 3150'. R/dwn eline and R/up slick line. Make 3 swabbing runs.Top of Fluid 3600'. Monitor well. R/dwn slickline.Wait on Eline unit and crew to perf. 1/11/2013 Wait on Pollard Eline to Perf 1/12/2013 Waiting on Eline Unit and Crew 1/13/2013 PJSM. R/Up Pollard Eline. Pressure test to 4000 psi. RIH and perf 8963-8974'. POOH and R/up #2 run. RIH and perf 8950-8963'. POOH and R/up#3 run. RIH. Lost CCL/GR communication. POOH troubleshoot and repair. RIH and perf 8829-8836'. POOH, lay dwn gun strip. RIH and log perf'd interval.#3 perfs on depth.#2/#3 not visable due to noise when intensity of CCL turned up. POOH. 1/14/2013 Have Coil Tubiing Unit, Ops Cab and Combi pump on location. 1/15/2013 PJSM.Spotted BHI coil equipment and Nitrogen/Fluid pump. Nippled up BOPs and tested. Secured well and released crew. 1/16/2013 PJSM. R/up coil and RIH to 2000'to wait for N2. Pump 350 scf/min. RIH. Est fluid at 3100'. Fluid to surface at 5000'. 13.5 bbls. Cont RIH to 8800'.Stop&jet. RIH to 9400'. 36 bbls recovered. RIH to 10200'.Wrk coil below perf @ 10169'for 1 hr. 59.7 bbls recovered. POOH to surface.Shut in well w/200 psi N2 pressure.Total fluid recovered today 73.2 bbls Sample F/Bottom weighed 8.34. No gas. 1/17/2013 Rig down BJ coil and pumping equip and stage on pad.Wait on Pollard Eline. 1/18/2013 PJSM. R/up BOP and lubricator. Pressure test to 2000 psi. Good. M/up running tool w thrutubing plug, RIH, correlate, set at 10130'. POOH, R/dwn running tool, R/up dump bailer. Load 3 gal glass beads and RIH, release at 10119. POOH. R/up 30'bailer. Mix 4.2 gal 15.8 slurry w/2.41 gal H2O, chemicals. Fill bailer and RIH, release at 10119 (3 runs) POOH. Last run, no release.Junk slurry. R/dwn 1/19/2013 PJSM. R/up Pollard Eline with lubricator, centralizer, slip joint and Lead Impression Block. RIH and tag equalization tube. Bang down to close ports. POOH. R/dwn LIB tools and R/up 30' dump bailer tubes. Make 11 dump bailer runs with cement slurry and dump on top of cement from yesterday.Should give 31+ft.total. R/dwn and wait on cement. 1/20/2013 Wait on cement. Opened well to Expro at 00:00 on 14 chk.Well flowed gas to surface. Open to 32 chk. Pressure bleed to 14 psi. Shut in.after 30 min. Pressure now 40 psi. 1/21/2013 PJSM w/Pollard. R/up lubricator, straight bar and spang. RIH w/2"gage ring and tag top of cement at 10094'. POOH. R/up pressure/temp bomb and RIH, 120fpm to 8800, 60fpm to 10094. POOH, stopping at TD,tubing tail and tree hanger for data input mark. R/down, release Pollard. R/up BHI coil,combi unit and BOP's.Test all lines and equip. Release BHI. Fluid top 9255'. 1/22/2013 PJSM. Install injector on wellhead.Test lines. Pump 10.75bbl produced water into tubing followed by 2000 gal Methanol. Displace w/44.4 bbl produced water at max rate. 2.2- 2.4bpm until last 3 min. 2.7 bpm.Open well to Expro and RIH w/coil. 350scf, 70fpm to 8800. Slow to 10fpm to 10000'. Increase to 500scf, work pipe 1 hr. Inc to 750 scf. POOH. 500 scf at 8800.Total fluid recovered 95.6 bbls. Open chk and monitor till midnight. Shut in till 0600. • Open 1/23/2013 Suspend well operations on NFU 23-25. Secure well. Demob and return all associated well • testing equipment. FINAL REPORT Casing Depth Depth MW Days Size (MD) (TVD) ppg (Est) Trouble Comments Armstrong Cook Inlet 16 " 137 137' 8.5 ppg 1 North Fork 23-25 871' 867' 9.1 ppg 2 2111' 1932' 9.7 ppg 3 Centrifuge out-could not keep wt Sec 26 4s 14w down. 2715' 2413' 10.3 4 North Fork Field ppg Kenai Pn AK 2012 10 3/4" 3102' 2702' 5 3102' 2702' 6 PTD 212-091 3102' 2702' 7 Rprs on wellhead 3102' 2702' 8 3102' 2702' 9 3102' 2702' 9.5 ppg 1 0Displ w/polymer mud 3102' 2702' 11 3102' 2702' 12 3102' 2702' 13 3102' 2702' 14 3102' 2702' 9.5 ppg 15 3122' 2717' 9.4 ppg 16 4090' 3449' 9.5 ppg 17 6092' 5002' 9.7 ppg 18 7050' 5891' 9.7 ppg 19 7050' 5891' 9.7 ppg 20 7360' 6200' 9.6 ppg 21 8340' 7177' 9.6 ppg 22 8957' 7794' 9.6 ppg 23 9840' 8676' 9.5 ppg 24 7 10785' 9621' 9.6 ppg 25 x °: -- o v _ _ m (fl N (O O co CO co O V O CO O CO ' O O co V LU N � CO O) O CO CO CO CO O Y O O °O - N CO r O N O Cr r O N O O Ln r O O 00 O Cf) N O CO `- r CO M CO r V LO O • 71 °`" N. , N ,_ NLr5 r r •O r• 9 •0 0• 0 0 0• , O O• O• O• 9 •0 0 0• 0• 9 9 •0 0• 9 •0 0• 9 •CD CD N v D..-C6. co O V rn CD co N N- V CO CO O CO CO CO N CO N- 6) O LO CO I- O) O 00 O „.,,Cr, O O I. 0 N. ? 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N COO O Va) CO (? o E O its Z 0 E co Ti) U d E. co N O N- LO Z L CO V in co N- CO 3 0. 0 0 O 0 O 0 co 0 o • 411 ' 000000 0. 4: Z oCD CD NJ CO<— O CD Z r, . ti ..a f }- ./ ,., g ,J � . ,..W Y ARMSTRONG '. AIM 1 fF 1 ! i OF MP' je I" NFU 23-25 Well Test Report 1-06-13 thru 1-24-12 40 it* II 1\ ;i Ilk 1 II ,y/ I r ., WELL TESTING & COMMISSIONING Q EXPRO WELL TESTING &COMMISSIONING DISCLAIMER Expro Well Testing %MD use its best efforts tc. fi...irnish eustomers .ii,,,i'.itl-i accurate information end interpretations as a part of, and iticident to, the services provided. However, Expro cannot and does hot V''..41"''';;.i it t:!W: •;:''..;::Li ta C.j. c r correctness of such information and interpretatiocis.. lindEir .:m.-2, iystarres should any such information or interpretation be reked upon ,-:“ the '',j-,- ..i.e l';')3 s s 'f o r any decision regarding drilling, cornpietic---1 proci•-k.... .:..ton„ L-ariario, oi- any bTocedurc..-.,i ITV 0;V i;....i'..i;:. a n y ',6ii k 'CO 'r:.h C.' ..:1, .;,-;41. .1..,.... •1: ,a 0 y 60 i c;ij -,.*;.r;t6 re, '-. - (. ,:-; .:' 2 t.s C.4•Cf'Vs; c r ay .y -..A,-i.&i' td pai".ty hese cac...:uatioil:s are based on .,''.:erta. data, assumptions and app ; d mathern9ticai infitiods. inaccurate '..A.i...e: 1:.i.at:; .:.:i-ianging 'otell conditions, tolerance variations of nnc:ichanicai ccillp'Cii-r:ants,: ii. eioharii7:al malfunctions and other factors may affect these calculatons in no event will Expro be iiable for failure to .c:tbt: ariy pac1,..i!ar results or for any damages, including but no iimited fo, Jociiret, special or consequential damages, whether due to riegiigence or otherwise arising out of or in connection with such use of data, caiculations, recommendations or opinions provided by Expro. EXPRO WELL TESTING&COMMISSIONING Method of Gas Rate Measurement Measurement by Orifice Plate :- Qg = C*Sqr( Hw* Pf) where :- C = Fpb* Fb*Fg*Ftf*Ftb*Fr*Y2*Fm*Unit Conversion Factor Qg = Corrected Gas Flow Rate. C = Orifice flow constant. Hw = Differential pressure across orifice plate in inches water gauge at 60 deg.f Pf = Absolute static pressure. Fpv = Supercompressibility factor(corrected for N2, H2S and CO2 effects). Fb = Basic orifice factor. Fg = Specific gravity factor. Ftf = Flowing temperature factor. Ftb = Temperature base factor. Fpb = Pressure base factor. Fr = Reynolds number factor= 1. Y2 = Expansion factor for downstream pressure tap. Fm = Manometer factor= 1. Unit Conversion Factor = Factor changing flow rate units. We can unite Fu= Ftb*Fpb* Unit Conversion Factor. (Fu factors are given in the table for different standard conditions and flow rate units). Cl = Fu*Fg (theoretically constant during the test). C2= Fpv* Fb*Ftf*Y2 Then C=Cl *C2 Table of Fu Factors Rate of Flow units Standard conditions Cu Ft/hours Cu Ft/day M3/hour M3/day 14.73 psi /60 deg F. 1.00 24.00 0.03 0.68 760 mm Hg/0 deg C. 0.95 22.76 0.03 0.64 760 mm Hg/15 deg C. 1.00 24.01 0.03 0.68 750 mm hg/15 deg C. 1.01 24.33 0.03 0.69 96 :6 v . z o '1111 ;� Oo r ccr o(.1 O110.0.6,o2‘ ��r 10001- '., „ r0 �Or u 14 O� ,,, O(., 1 ia, Lu c H , O.o �r �r0 x �'i� IIt . 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W 2k W d 3 E a a) _ _ _ le m = co c y ,) Q 0 L -a m O d d _D C to N J C L 0) 3 3 3 c.) C L .. t L r = m Q W Q J 0 C t 0 '� O O O L v _ =.O+ 7 3 = L O to O t w' t 0 L O. fA Y � � J � LJJ 0 0 co V a >a _O a)r a)•y v � C ) O 0 X Y (O c R c � � .0 cc ca as ca O O O o = O (� 00 -, U) U) E � EU) Z6b U) mctIU) Lu -) itILL -) OOJJJJit U C Q I N 0 'n W °) H r Z 0 0 Uot. t w .c LUI— m o Zr) N C a 1-0 -NG E a zi ix ) Q LL H 11 X )U O 00000000000000„00 ‘000, 0001.001.00 0 0 0 0 0 0 0 0 0 O O M O O M O M O O M '� O D M O M O � .. M � O M O M .. .. .. H t� ti O O O ,- N M 4 6 O O t. to tb Cr; O) N R R 00 00 00 to Q) O O O r Lu M M 0 W r !• H _ Q R CC Q 7 N M N N v x ,. < v WW c C ce Y O ca LL CO a W i Y C. as v 7-c/) a O t = o 03 W J O. r 13 O m 03,_ 41 .L r —L. V = ca L L+ L O) Cf� = •i O r Ota O C _ v L 4.+ _ ♦+ C 2 — m 's O a+ >, 3 0 ..Ne V 0 cfl O Y = — y 0 0 Y J E D N oO .= Y O G> 'O O c� 3 J = N -0 L LL LL 00 t 3 '~ is i CI) o < Z Z N a) a) 0 0 p o o cn CD m w CO0 d > > > i d a > > Z -I N J Q a 03 •i , •i .0 R ca a d .L u_ Q W Q —Ip J ca — CO d L. Jw � J ca0 0- LIWWv 3333 � aV1 .y330 J d L L L d L R O = L L Z O 0 0000 0. 00 � i� UUW Q Ico m U ^ m W . m I- 7)N Z 0 L.L.ce �` m 0 W j� o co d `m s• m C co y6 Y C co WI LL F 2 LL F a III M M M rM 0 0 0 0 0 M lc 4 00 O , N M t0 W M M 0 W C Q ca to O 7 7 M N N RECEIVED NOV 2 1112012 CANRIG AOGCC Uxu.i ia<.Tron xnLru. 301 EAST 92rvK AVENUE,SUITE 2•ANCHORAGE,ALASKA 99515•(907)561-2465•FAX(907)561-2474 November 21, 2012 A1112001 Mr. Steve Davies 333 W. 7th Avenue Suite 100 Anchorage, AK 99501 Re: Final DML Color Log Prints, Digital Data and Well Reports: NFU 23-25, North Fork Unit, Kenai Borough, Alaska Dear Mr. Davies; Enclosed with this letter are the final logs, reports and digital data from the recently drilled NFU 23-25 well. The following data and corresponding number of copies is included. NFU 23-15: Description Copies Formation Log 2"=100' MD (Color Prints) 1 - Formation Log 2"=100' TV (Color Prints 1 — LWD Combo Log 2"=100' MD (Color Prints) 1 LWD Combo Log 2"=100' TVD (Color Prints) 1 Gas Ratio Log 2"=100' MD (Color Prints) 1 - Gas Ratio Log 2"=100' TVD (Color Prints) 1 Drilling Dynamics Log 2" = 100' MD (Color Prints) 1� Drilling Dynamics Log 2" = 100' TVD (Color Prints) 1 /- LAS iLAS and Final Well Data on CD ROM 4 a. Z,. 0 a.a 1 ✓ Final Well Reports 1✓ Most sincerely, Gvm:dI -imAmeal t Daniel Grunwald Alaska DML Coordinator Canrig Drilling Technology, Ltd. Received by: /4_4_ 0 ikei1/4,k G at Signature Title Date Page 1 of 6 Schwartz, Guy L (DOA) ai z -O From: Stephen F. Hennigan [shennigan@peiinc.com] Sent: Monday, October 29, 2012 5:20 AM To: Davies, Stephen F (DOA); Schwartz, Guy L (DOA); McMains, Stephen E (DOA) Subject: RE: Armstrong NFU #23-25 Nabors Rig 99 Weekly Report 10/14/2012 10/22/2012 SET PACK-OFF,TEST 5000 PSI (OK), M/U C/O ASSEMBLY, RIH TAG CMT @ 10542', PUMP HI-VIS SWEEP, LAY DOWN DRILL PIPE. 10/23/2012 LAY DOWN 4" DP, R/U E-LINE RUN BOND LOG TO 10,540', LOAD PIPE SHED W/2 7/8 TBG,TEST LOWER PIPE RAMS W/2 7/8 TESTJT. 10/24/2012 TEST CSG 4000 PSI 30MIN CHART(OK) R/U WEATHERFORD TONGS, RUN 2 7/8 PRODUCTION TBG. 10/25/2012 FINISH RUN TBG, DISPLACE W/INHIBITED 6% KCL, SET PACKER,TEST TBG,TEST ANULAS, R/D TBG TOOLS&TEST EQUIP. NIPPLE DN BOP EQUIP, MOVE PIPE SHED OUT AWAY FROM RIG. 10/26/2012 6 HRS/ NIPPLE DOWN BOP AND CLEAN PITS . Release Rig to 22-35 well. T auris Project Manager/Engineer Petroleum Engineers Inc a Hamilton Company 500 Dover Boulevard, Suite 310 I Lafayette, LA 70503 Office: 337-984-2603 Cell: 337-849-5345 From: Stephen F. Hennigan [mailto:shennigan@peiinc.com] Sent: Monday, October 22, 2012 11:44 AM To: Stephen F Davies (steve.davies@alaska.gov); Guy Schwartz (guy.schwartz@alaska.gov); Steve Mcmains (steve.mcmains@alaska.gov) Subject: RE: Armstrong NFU #23-25 Nabors Rig 99 Weekly Report 10/14/2012 10/15/2012 Finish TEST BOP'S. 10/16/2012 PICK UP 5" HWDP. CHANGE ELEVATORS, PICK UP 4" DP. CUT AND SLIP DRILL LINE. CHANGE OUT GRABBER BLOCKS ON TOP DRIVE. PICK UP 4" DP. 10/17/2012 CUT AND SLIPPED DRILLING LINE, PICKED UP PIPE, STOOD BACK 4" , PICKED UP 4" AND 10/29/2012 Page 2 of 6 POOH AND MAKE UP BHA. RIH PICKING UP 4" DRILL PIPE. 10/18/2012 FINISH P/U DRILL PIPE, RIH WASH & REAM AS NEEDED to 10740'. 10/19/2012 CIRC HOLE CLEAN, PUMP SWEEP, POH, L/D BHA, RIG UP TO RUN CSG. 10/20/2012 R/U TO RUN 7" CSG, HELD PJSM WI DRLG CREW &CSG CREW, RUN 5 JT SHOE TRACK AND TEST FLOAT EQUIP, (OK) CONTINUE IN HOLE W/CSG, CIRC B/U @ 3100' & 5500'. 10/21/2012 FINISH RUN CSG, LAND CSG ON HANGER @ 10716',CIRC HOLE FOR CMT JOB, CMT 7" CSG, LAY DOWN CMT EQUIP AND LANDING JT, RIG FLOOR&TOP DRIVE UP FOR DRLG. P/U JT 4" DP, RUNNING TOOL,AND PACKOFF . T are Project Manager/Engineer Petroleum Engineers Inc a Hamilton Company 500 Dover Boulevard, Suite 310 I Lafayette, LA 70503 Office: 337-984-2603 Cell: 337-849-5345 From: Stephen F. Hennigan [mailto:shennigan@peiinc.com] Sent: Monday, October 15, 2012 10:01 AM To: Stephen F Davies (steve.davies@alaska.gov); Guy Schwartz (quy.schwartz@alaska.gov); Steve Mcmains (steve.mcmains@alaska.gov) Subject: RE: Armstrong NFU #23-25 Nabors Rig 99 Weekly Report 10/14/2012 10/08/2012 Drill from 8957'to 9530; CBU and short trip to 8472'. Hole is good. Drilling from 9531'to 9840'. 10/09/2012 Drl to 10584'; CBU and short trip to 9526'; RIH picking up drill pipe to drill to 10,969' MD. RIH to 10488'; wash and rotate to bottom. Drill to 10785' 10/10/2012 Circ hole clean; Pump around HV sweep. POH to 6510; work out of hole to 5810; Backream out of hole to 5620; POH the rest of the way. LD BHA 10/11/2012 Finish laying down BHA. RU and test BOP's. Make dummy run on 7" landing jt, lock down screws. Make up new BHA and RIH. Remove, rebuild, install and test hydraulic valve on pipe rams before exiting surface casing as per Lou Grimaldi. 10/29/2012 Page 3 of 6 10/12/2012 RIH to 10,080';wash and ream to bottom. Circulate bottoms up then pump a HV sweep around while rotating 100-115 and reciprocating 95'. Circulate until shakers cleaned up; POH laying down drill pipe. Work through tight spots at 6646-6629, 6450-6446,and 6250-6240. 10/13/2012 Backream from 6250 to 5983'; change out encoder on top drive, wrong encoder, service top drive. Pull 2 stands; backream from 5722 to 5364'. POH to the shoe. Lay down drill pipe. Pipe was over torqued while backreaming due to faulty encoder. 10/14/2012 Finish LD 5" DP; LD 5" HWDP and BHA. Examine bit and stabilizers for wear. Inventory all 4" HWDP and XO's. Change rams to 4 X 7 VBR; RU and start testing BOP"s. Project Manager/Engineer Petroleum Engineers Inc a Hamilton Company 500 Dover Boulevard, Suite 310 ( Lafayette, LA 70503 Office: 337-984-2603 Cell: 337-849-5345 From: Stephen F. Hennigan [mailto:shennigan@peiinc.com] Sent: Monday, October 08, 2012 11:51 AM To: Stephen F Davies (steve.davies©alaska.gov); Guy Schwartz (guy.schwartz@alaska.gov); Steve Mcmains (steve.mcmains@alaska.gov) Subject: RE: Armstrong NFU #23-25 Nabors Rig 99 Weekly Report 10/07/2012 10/01/2012 PU BHA;Test MWD and LWD for signals; RIH picking up 60 jts of DP. Drill f/3122' to 4090' . 10/02/2012 Drill/slide from 4090' to 6094'. Start dropping angle at 5680' holding azimuth at 69.5°. 10/03/2012 Drill/slide from 6092' to 7050' dropping angle to 12.77°. Circulate hole clean pumping 2 1/2 BU; shakers very clean. POH to 3708'. 10/04/2012 Finish POH; stand back BHA. RU and test BOP's. Finish BOP test on 10-4-12 at 12:30am as per Lou G. 10/05/2012 RIH; PU 69 jts of DP; slip and cut drlg line; break circulation at 5000'; RIH to 6955',wash to bottom; 600 units trip gas, some thick mud. Drill from 7050' to 7360'. 10/06/2012 Drilling from 7360'to 8340' . 10/07/2012 Drill to 8573; Sh trip to 7050'; trip looked good. Drill to 8957'. Tare c.94424-or .S.P.teecevio;/-eozoteidw Project Manager/Engineer Petroleum Engineers Inc a Hamilton Company 500 Dover Boulevard, Suite 310 I Lafayette, LA 70503 Office: 337-984-2603 10/29/2012 Page 4 of 6 Cell: 337-849-5345 From: Stephen F. Hennigan [mailto:shennigan@peiinc.com] Sent: Monday, October 01, 2012 2:57 PM To: Stephen F Davies (steve.davies@alaska.gov); Guy Schwartz(guy.schwartz@alaska.gov); Steve Mcmains (steve.mcmains@alaska.qov) Subject: RE: Armstrong NFU #23-25 Nabors Rig 99 Weekly Report 09 30/2012 09/24/2012 ALLOW STARTING HEAD TO COOL PRIOR TO TESTING.TEST FAILED ON WELD. CLEAN AND REWELD GET-GOOD TEST. START NIPPLING UP BOPE. INSTALLED RAMS IN SNGL GATE. 09/25/2012 NIPPLE UP PROGRESSING, MIXING MUD. 09/26/2013 Fin NIPPLE UP. PICKING UP TEST TOOLS AND SETTING WEAR BUSHING. 09/27/2012 MADE UP OUR TEST TOOLS AND TESTED BOPE PER PROCEDURE 4K HI AND 250 LO, HELD ALL TEST FOR 5 MIN AND DOCUMENTED ON CHART RECORDER. RIG UP POLLARD WIRELINE AND RUN A CBL. UNABLE TO GET ALL THE WAY DOWN WITH LOGGING TOOLS. LOG OUT. 09/28/2012 MADE UP BHA AND RAN IN HOLE PICKING UP PIPE FOR CLEANOUT. PERFORM CASING TEST PLOTTING NUMBERS FOR LEAKOFF. AT 1100 PSI '0' RING FAILED IN WELLHEAD AND SO DID WELDS AROUND HEAD.AIR ARC OUT OLD WELD AND REWELD PER PROCEDURE WITH VETCO. 09/29/2012 Clean up wellhead/cellar; remove previous weld; prep and re-weld. RIH;tag bottom ;CBU before testing csg. 09/30/2012 Circulate mud until cleaned up. Pressure test casing to 3000 psi. Drill out FC, cement, shoe and 20' of new hole. Perform LOT to 14.8 ppg EMW. POH with bit and BHA. RU and run CBL. Looked good. Begin making up BHA#3. rA rk cam /s. .�/ Project Manager/Engineer Petroleum Engineers Inc a Hamilton Company 500 Dover Boulevard, Suite 310 I Lafayette, LA 70503 Office: 337-984-2603 Cell: 337-849-5345 From: Stephen F. Hennigan fmailto:shennigan@peiinc.coml Sent: Tuesday, September 25, 2012 8:09 AM To: Stephen F Davies (steve.davies(aalaska.gov); Guy Schwartz (quy.schwartz@alaska.00v); Steve Mcmains (steve.mcmains©alaska.gov) Subject: RE: Armstrong NFU #23-25 Nabors Rig 99 Weekly Report 09 23/2012 09/17/2012 Directionally drill f/871'-2111'MD. Circ for short trip. 10/29/2012 Page 5 of 6 09/18/2012 Finish circ hole clean. Short trip to top of HWDP. Minor pulls. TIH. Directionally drill f/2111'- 2715'M D. 09/19/2012 Drill to 3102'MD; pump30 BBI Nut Plug/HV sweep; hole seems to be gauge; no increase in cuttings w/sweep. Pump second HV sweep showing gauge hole also. Start POH to collars at 03:00. 09/20/2012 Fin POH to collars. RIH to 2900; break circ and wash last stand down; no problems, no fill. Pump HV sweep; circ and condition hole, 2 btms up. Monitor well; pump dry job, POOH to drill collars. Set back. LD BHA. 09/21/2012 RU AND RUN 10 3/4 CASING. CIRCULATE HOLE WHILE RD WFT AND RU FOR DECK, FALSE ROTARY, FLOW NPPLE; VERY FEW CUTTINGS OVER THE SHAKERS W/PUMPING 7.5 BPM 7600 TOTAL STKS. 09/22/2012 RIH W/DP; CIRC HOLE W/STAB-IN TOOL; CMT AND DISPLACE. 77bbls cmt to surface. POH W/DP; START ND DIVERTER 09/23/2012 NIPPLE DOWN DIVERTER, PICK UP BOP AND MAKE ROUGH CUT ON 10 3/4" CASING. SET DOWN STACK AND NIPPLE DOWN. PREPARE 16" AND 10 3/4" FOR STARTING HEAD. WELD OUT SAME PER PROCEDURE. T adtr Project Manager/Engineer Petroleum Engineers Inc a Hamilton Company 500 Dover Boulevard, Suite 310 I Lafayette, LA 70503 Office: 337-984-2603 Cell: 337-849-5345 From: Stephen F. Hennigan fmailto:shennigan@peiinc.coml 10/29/2012 Page6of6 Sent: Monday, September 17, 2012 9:11 AM To: Stephen F Davies (steve.davies@alaska.gov); Guy Schwartz (guy.schwartz@alaska.gov); Steve Mcmains (steve.mcmains@alaska.gov) Subject: RE: Armstrong NFU #23-25 Nabors Rig 99 Weekly Report 09/09/12—09/13/2012 - Rigging up Nabors Rig 99 and awaiting the AOGCC rig inspection 09/14—09/15/2012—Armstrong accepted rig. Cont RU. AOGCC inspection. Approval to spud from AOGCC Sat, 15 Sep 2012 01:31pm 09/16/2012—Fin RU. Spud 1400hrs 09/15/2012. Drill f/137'-501'. KO, drill and slide to 871'MD. Tart sem s. -el Project Manager/Engineer Petroleum Engineers Inc a Hamilton Company 500 Dover Boulevard, Suite 310 I Lafayette, LA 70503 Office: 337-984-2603 Cell: 337-849-5345 From: Stephen F. Hennigan f mailto:shennigan@peiinc.coml Sent: Monday, September 10, 2012 2:42 PM To: Stephen F Davies (steve.davies@alaska.gov); Guy Schwartz (qu r�.schwartz@alaska.dov); Steve Mcmains (steve.mcmainsraalaska.gov) Subject: Armstrong NFU #23-25 Nabors Rig 99 Weekly Report 08/24-09/09/12- Rigging up Nabors Rig 99 and awaiting the AOGCC rig inspection aurrr See,diew /stee%e/ .uc,.,§,..+r Project Manager/Engineer Petroleum Engineers Inc a Hamilton Company 500 Dover Boulevard, Suite 310 I Lafayette, LA 70503 Office: 337-984-2603 Cell: 337-849-5345 10/29/2012 i*! 3\ THE STATE Alaska Oil and Gas °fALASKA Conservation Commission I'if GOVERNOR SEAN PARNELL 333 West Seventh Avenue Op Q. Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Edward Teng Vice President— Engineering l Oq Armstrong Cook Tn let, T,TL 1421 Blake Street Denver, CO 80202 Re: North Fork Field, Undefined Gas Pool, North Fork Unit No. 23-25 Sundry Number: 312-403 Dear Mr. Teng: 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, /94-=-(--474' -'\___ Cathy P/Foerster Chair DATED this D day of October, 2012. Encl. A pram ED ARMSTRONG OCT 1 J 2012 Cook Inlet,LLC AOGCC A GCC October 16, 2012 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Request for Sundry Approvals to complete Armstrong Cook Inlet, LLC NFU#23-25(PTD No. 212-091) Dear Ms. Foerster, Armstrong Cook Inlet, LLC hereby applies for Sundry Approval to complete and test the subject well. The well was drilled to test the production potential of the Lower Tyonek sands near Anchor Point on the Kenai Peninsula. Total depth was reached on October 9, 2012 and the hole is presently being conditioned to run 7" production casing. Armstrong's completion prognosis calls for multiple intervals in the Tyonek to be completed using conventional thru tubing wireline guns to perforate, swab and then flow test. Additional zones of interest will be added with additional wireline perforations, swabbing and then flow testing. This will be repeated until all zones of interest are tested, then co-mingled to be put on production. A production packer is scheduled to be set @ approx. 8800' MD with 2-7/8" production tubing back to the surface. A subsurface safety valve(SSSV) is scheduled to be installed in the tubing string at 350' MD and a chemical injection nipple with dual check valves set at 2500' MD. If you have any questions or require additional information, please contact me at(303)623-1821 or Stephen Hennigan at(337) 849-5345. Sincerely, 1111 Edward Teng Vice President-Engineering Armstrong Cook Inlet, LLC Enclosures Cc: Stephen Hennigan— Petroleum Engineers for Armstrong Cook Inlet, LLC Craig Rang —All American Oilfield 1421 Blake Street, Denver, CO 80202 (303)-623-1821 Ph (303)-623-3019 Fax V ' . ti� � AO 11 STATE OF ALASKA I c 2 ALASKA OIL AND GAS CONSERVATION COMMISSION Q T 1 ZO APPLICATION FOR SUNDRY APPROVALS 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: ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Armstrong Cook Inlet,LLC Exploratory ❑ Development p - 212 091 ' 3.Address. Stratigraphic ❑ Service ❑ 6.API Number: 1421 Blake St.,Denver,CO 80202 50- 231 20037 00 00 - 7.If perforating: //. /' 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? d• -4, de4-'' / North Fork Unit No. 23-25 - Will planned perforations require a spacing exception? 't,)`i`1 '7 es ❑ No g 9.Property Designation(Lease Number): / 10.Field/Pool(): „.fri " 3`kf 'f , r /� r le_. l � / ' /9 �l � � �.% �S icy .�.Z. , V '�' -n.-I �� .1 �1.;.- �� ,, �,z� / iii <<,. � i Z- 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): 10785' 9661' Casing Length Size MD TVD Burst Collapse Structural 137' 16" 137' 137' na na Conductor Surface 3102' 10 3/4" 3102' 2702' Intermediate Production 10733' 7 " 10755' 9591' 7240 5410 Liner Perforation Depth MD(ft): Perforation Depth TVD(ft). Tubing Size: Tubing Grade. Tubing MD(ft): see attached WBD see attached 2 7/8" L80 8800 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Packer-Baker FH SSSV-Baker TE-5 Packer 8800'MD 7637'TVD SSSV 2500'MD 2240'TVD 12.Attachments: Description Summary of Proposal ❑ 13.Well Class after proposed work: /p ; Detailed Operations Program 2 BOP Sketch ❑ Exploratory/A. Li' Stratigraphic❑ Development ' Service ❑ 14.Estimated Date for 15.Well Statuafter proposed work: October 26,2012 Commencing Operations: Oil ❑ Gas 2 WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stephen Hennigan EmaiuPH shennigan@peiinc.com (337)849-5345 Printed Name Edward Teng Title Vice President-Engineering Stgnat a Aipi� /1 Phone Date —`_,, =7� (303)623-1821 October 9,2012 COMMISSION USE ONLY Conditions of approval: Notify Commission •o that a representa ive may witness Sundry Number: /jj -'.LIC )-) Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes ❑ No ❑ Subsequent Form Required: to -Y07 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: G t/ - 23 - ( R nn Submit Form and N 0 �rtrr;p l e�i�e 10/2012)Re ,,,et if a,io��val' f r 12 moot s from the date of approval. Shmii�/ �LLLJJJJ t V /�'''�� /y� , (o•LZ•1 L I Permit#: 212091 NFU #23-255 API#: 50-231-20037-00-00 Prop. Des: ADL-391211/2095 • 648' FSL, 1481' FEL KB elevation: 681' (22'AGL) S33 T6N R11 W S.M. Latitude: 59"47'46.955" Longitude: 151*37'45.495" Spud: 9-16-2012 Armstrong Cook Inlet, LLC TD: 10-9-2012 Rig Released: Structural Pipe -'L 16" X-56 84 ppf Top Bottom MD Surf 120' TVD Surf 120' I- 1� Surface Casing I' Baker SSSV set at approx.350'MD. 10-3/4" L-80 45.5ppf ' \ Top Bottom Pollard Chem.lnj.Nipple set at 2500' MD 0' ‘* TVD 0 3,102'2,702' MD. 2 7/8"8rd EUE-M Production Casing 7" L-80 26 ppf Top Bottom 1 MD 0' 10,755' TVD 0' 9,592' It \ Tubing 2 7/8" L-80 8.6 ppf Top Bottom MD 0' 8800' TVD 0' 7637' Proposed Perforations Measured Depth TVD Estimated Form. Pressure 8830 - 8836' 7667 - 7673' 3070# 8943 - 8976' 7780 -7813' 3125# _.' 9435 -9468' 8272 -8305' 3325 # 1......, J K 9547 - 9569' 8384 -8406' 3365 # i ' 9890 - 9908' 8726 -8744' 3500# 10,138 - 10,169' 8974 - 8905' 3565# Cementation of Productio [/ Surface Cement Description has not yet occurred. Spacer-8.4 ppg 20 bbls-Mud Clean II Lead Slurry-12 ppg(Yield 2.61)275 bbls-761 sacks Type I Cement+10%bwoc BA-90+0.005 lbs/sack Static Free+2%bwoc Calcium Chloride+0.5%bwoc EC-1+ 0.2%bwoc CD-32+0.1%bwoc ASA-301+1 gals/100 sack FP-6L+2% — bwoc Sodium Metasilicate+134.3%Fresh Water Tail Slurry-14.8 I ppg(Yield 1.33)48 bbls-200 sacks Type I Cement+0.005 lbs/sack IStatic Free+2%bwoc Calcium Chloride+1 gals/100 sack FP-6L+ TD PBTD 56.3%Fresh Water Displacement-8.34 ppg 3 bbls Fresh water 10,755'MD 10,591'MD follwed by: 10.1 ppg 47 bbls Mud 9,592'TVD 9,428'TVD Well Name&Number: North Fork Unit#23-25 Lease: Kenai Loop County or Parish: Kenai Penisula Borough State: Alaska Country: USA Perforations(MD): Perf(TVD): Angle @KOP and Depth: 3 deg @ 700'MD Angle @ Perfs KOP TVD: Date Completed: RKB: 21' Prepared By: Craig Rang Last Revision Date: October 11,2012 Armstrong Oil and Gas 1421 Blake Street, Denver, Colorado 80202 Well: NFU 23-25 S26-T4S—R14W Kenai Peninsula Burrough,Alaska Well History- First of two wells drilled in the 2012 drilling program on the Kenai Peninsula of Alaska. The completion prognosis calls for multiple intervals in the Tyonek to be completed using conventional thru tubing wireline guns to perforate,swab and then flow test. Additional zones of interest will be added with additional wireline perforations, swabbing and then flow testing. This will be repeated until all zones of interest are tested, then co-mingled to be put on production. Drilling commenced on September 16th,with TD of 10,785' MD drilled on October 9th, 2012. Structural casing is sixteen (16) inch drive pipe set at 120'wireline depth. The surface casing string is 10%" set at 3102'wireline depth or 2702'TVD then cemented back to surface. The production string is 7" 26# N80 set at 10,755'wireline depth. The 7 in casing is cemented with sufficient cement to cover all zones of interest for hydraulic isolation with cement back to the surface casing shoe. A production packer is scheduled to be set @ approx.8800' MD with 2-7/8" production tubing back to the surface. A subsurface safety valve (SSSV) is scheduled to be installed in the tubing string at 350' MD and a chemical injection nipple with dual check valves set at 2500' MD. Vetco will install the tree and the rig will move onto the second well. No variances are requested. North Fork Unit 23-25 Well Completion Procedure Current Status of Well: Refer to Well Bore Diagram. 7" 26#L80 production casing cemented to 10,755' MD 9591'ND(nominal ID—6.276" and drift ID—6.151"). Production packer set at 8800' MD with 2-7/8" 8.6#L80 production tubing back to surface ( nominal ID—2.259" and drift ID -2.165"). Drilling rig has run a bit and scraper from surface to PBTD and circulated out the fluid in the hole with 6% KCL water w/biocide on the back side of the production packer. Tie in all depths to Baker Hughes LWD logs dated October 9, 2012 when TD was reached. All logs will be measured from KB which is 22 feet above GL. C IgL , I''.C,,.,„c."-i Cbs.i.e . 1. Run Pollard E-line Segmented CBL/GR tied into OH logs. Evaluate cement bond. If bond good, continue with step 2,otherwise prepare to squeeze cement(supplemental procedure). 2. Rig up Pollard Wireline slickline unit with swab cups suitable for 2-7/8"-8.6#L80 tubing. Formation gradient is expected to be .40 PSI/FT x 9000 FT.ND=3600 psi. Proposed Perforations Measured Depth TVD Estimated Form. Pressure 8830 - 8836' 7667 - 7673' 3070# 8943 -8976' 7780 - 7813' 3125# 9435 -9468' 8272 - 8305' 3325 # 9547 -9569' 8384 - 8406' 3365 # 9890 -9908' 8726 - 8744' 3500 # 10,138 - 10,169' 8974 - 8905' 3565# 3. Swab 2-7/8"tubing down to sufficient depth to maintain 1000#- 1200#underbalance of formation pressure. Example: 6% KCL completion fluid weight(8.7#)x.052 =0.4524 psi/ft. gradient. Expected pressure from bottom interval is 3565#which requires a vertical hydrostatic column of 3565#/0.4524 psi/ft=7880 feet. We want to reduce the hydrostatic column by 1000—1200#which is the equivalent of 2200—2650 vertical feet of completion fluid. Therefore we only need 5680—6130 vertical feet of fluid column. Perforations are at 8905'ND —6130'ND=2775'ND which equates to 3200' MD on the directional. Swab the 2-7/8"tubing down to 3200' MD. 4. Rig up wireline to perforate first interval of interest. Pressure test lubricator and wireline BOP to 1.5 times the maximum anticipated shut in pressure. (Example MASP= 3000#x 1.5=4500 psi). Maintain the 4500#of pressure for 15 minutes with no more than 50#loss. If pressure loss is greater than 50#, determine leak, repair and retest until results are satisfactory. 5. Tie wireline perforating guns into OH logs using gun GR and CCL. Perforate using 2"4 spf,0 degree phasing deep penetrating through tubing guns from 10,138 MD to 10,169'MD. Use magnetic de-centralizer to pull guns against 7" casing after exiting tubing tail. 6. Attempt to flow well through Expro flow back equipment and tanks. Monitor fluid level in tanks. In the event,well will not flow, proceed with step 7. 7. Rig up Pollard Wireline slickline unit and proceed to swab 2 7/8" inch tubing. Monitor fluid level to determine fluid entry. Continue to swab well until conclusive fluid or gas entry is determined. If gas entry into well, continue to next interval beginning at step 4 after testing the interval. 8. In the event of a fluid entry, rig up Pollard Wireline to set a bridge plug within 50 feet of the top of the interval making water. Use a gun GR and CCL tied into the CBL for depth control 9. Dump cement on top of plug based upon plug recommendations versus/depth/deviation. 10. Continue perforating intervals of interest as in Step 6. 11. Flow test each interval. 12. Once all intervals of interest have been shot and tested, well will be turned over to production group. 13. Place well onto production ' `(row -�, —64`4) i‘ort-t--•. /0—LI Z-( Page 1 of 1 Schwartz, Guy L (DOA) From: Regg, James B (DOA) Sent: Sunday, October 21, 2012 3:40 PM 011) To: Companyman 09,1 Cc: Pete Berga; Pete Dickinson; Schwartz, Guy L (DOA) Subject: Re: NFU 23-25 Completion Should perform weekly BOPE test prior to running CBL to be in compliance. Companyman <companyman@allamericanoilfield.com> wrote: Mr. Regg, We have gotten our 7" casing to bottom and cemented. We are currently making a clean out run and will be testing our casing this evening.After casing test we will come out laying down drill pipe and run our CBL.This will take us till around midnight the the 22nd or into the morning early hours of the 23rd After CBL we plan to test 2 7/8" rams and run completion string. My question to you sir is this acceptable as we are due to test BOP's again tomorrow the 22nd Thank You Al Allen L. Lunda/Jim Rickel DSM's Armstrong Oil and Gas 907-301-6065/Cell 907-865-9930/Work 10/22/2012 oF423 pit zzizoc, O Regg, James B (DOA) From: Brooks, Phoebe L (DOA) Sent: Friday, September 28, 2012 3:04 PM To: Tiedemann, Brian Cc: Regg, James B (DOA) Subject: RE: Nabors 99Ac Corrected BOP Test Form 9-26-12 Attachments: Nabors 99AC 09-26-12 Revised.xls Brian, Attached is a revised report for Nabors 99AC 09-26-12. All blank fields now reflect 0"NA", formatting was corrected,the total number of failures now reflect 4, and remarks regarding the failures have been added. I also added the new rig#to the report. Please update your copy. Thank you, Phoebe Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 From: Tiedemann, Brian [mailto:Brian.Tiedemann@nabors.com] Sent: Friday, September 28, 2012 11:16 AM To: Brooks, Phoebe L (DOA); DOA AOGCC Prudhoe Bay Subject: Nabors 99Ac Corrected BOP Test Form 9-26-12 Brian Tiedemann "Bones" Nabors Alaska Drilling 99AC Office 907-865-9931 Cell 509-386-0654 ******************************* NABORS EMAIL NOTICE - This transmission may be strictly confidential. If you are not the intended recipient of this message, you may not disclose, print, copy, or disseminate this information. If you have received this in error, please reply and notify the sender(only) and delete the message. Unauthorized interception of this e-mail is a violation of federal criminal law. This communication does not reflect an intention by the sender or the sender's principal to conduct a transaction or make any agreement by electronic means. Nothing contained in this message or in any attachment shall satisfy the requirements for a writing, and nothing contained herein shall constitute a contract or electronic signature under the Electronic Signatures in Global and National Commerce Act, any version of the Uniform Electronic Transactions Act, or any other statute governing electronic transactions. i STATE OF ALASKA /1,VAkiv/ 01/25/10 OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: iim.regg@alaska.gov doa.aogcc.prudhoe.bay(a.alaska.gov phoebe.brooks@alaska.gov alaska.gov Contractor: Nabors Rig No.: 99AC DATE: 9/26/12 Rig Rep.: Tiedemann/Sullivan Rig Phone: 907 865 9931 Rig Fax: n/a Operator: Armstrong Op. Phone: 907 865 9930 Op. Fax: n/a Rep.: Driskill/Lunda E-Mail companyman@allamericanoilfield.com Well Name: NFU 23-25 PTD# 2120910 Operation: DrIg: x Workover: Explor.: Test: Initial: x Weekly: Bi-Weekly Test Pressure: Rams: 250/4000 Annular: 250/2500 Valves: 250/4000 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.: P Well Sign P Upper Kelly 1 FP , Housekeeping: P Drl. 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" GK FP - Pit Level Indicators P P #1 Rams 1 5" P Flow Indicator P P #2 Rams 1 Blinds FP - Meth Gas Detector P P #3 Rams 1 2 7/8"x 5" P H2S Gas Detector P P #4 Rams 0 NA MS Misc NA 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 FP - Kill Line Valves 2 3-1/8 P Check Valve 0 NA ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure 3100 P CHOKE MANIFOLD: Pressure After Closure 1500 P Quantity Test Result 200 psi Attained 37 P No. Valves 13 P Full Pressure Attained 137 P Manual Chokes 1 P Blind Switch Covers: All stations Yes Hydraulic Chokes 1 P Nitgn. Bottles (avg): 2425 CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 4 Test Time: 10.0 Hours Repair or replacement of equipment will be made within days. Notify the North Slope Inspector 659-3607, follow with written confirmation to Supervisor at: jim.regg@alaska.gov Remarks: Tested with 5"test jt. Cycled Annular, Blinds, Upper IBOP, and choke side HCR to get passing tests 1 24 HOUR NOTICE GIVEN YES X NO Waived By Jim Regg Date 9/22/12 Time 8:55 Witness Test start 10:00 Finish 20:00 PLB 01/25/10 2012-0926 BOP Nabors99AC NFU 23-25 as- Regg, sRegg, James B (DOA) P7 Z-tz-c 0 From: Regg, James B (DOA) Sent: Friday, September 28, 2012 10:23 AM9 Z6((7,V To: 'Companyman' Cc: Brooks, Phoebe L (DOA) Subject: RE: BOP Test 9-26-2012 Thank you for the test report and charts. Couple issues after reviewing test charts: - Annular-chart indicates high pressure on initial attempt never stabilized, repressured and held ok; if that is accurate, result should be FP - Blind ram -same concern as Annular; FP? - Upper Hydraulic IBOP, HCR Choke—appears to be numerous attempts to get a high pressure test; FP for both components? We need sizes for choke and kill line valves, and HCRs. Jim Regg AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 From: Companyman [mailto:companyman@allamericanoilfield.com] Sent: Thursday, September 27, 2012 9:43 PM To: Regg, James B (DOA); doa.aogcc.pruhoe.bay@alaska.gov Subject: BOP Test 9-26-2012 Larry Driskill/Allen Lunda DSM'S/Armstrong Oil &Gas Work—907-865-9930 Cell—907-598-1650 1 klS 91 1 Zt u�1 i o :i2 ".4**14 4 itt r��Fo. /...°001° .1.0imsrmws__,...,, u.61. ..F. '-1 Z rr: �; ►4�.0. ice'• 0 �/'' / Oa sem.. . 4 `�.• •iiiiiiiivisinallie 114,4411W10 00 /�� :00......0 000 ��...�►'�. SIS400. 0000 4,4.4.._ Alik-v,,,,, „146,•1‘ laakl) =_,..E.=1,14. 4*- 44,NIAllsa. 4) 1,.*N‘-`§x.., 1100 Williriii7=111INIMENwrium,a14110.11,4#111' ,4410,44000etotiotriak-• 4 ,.. . .", ,,,,0*„.„1.,,,,,„ , N , __ , _.... likw , , ,,, ...., 411111.-- 0 00.a!mai,...mingisaissis7•0111* \, vs \ 0, '*' , ''\ . 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' • :7,,Ntt )''‘''Cil'' .Cs 1 C) v) v) N. '•.., . ' it\ 9J i N kb ili •-•„,j,.. \''t. °' 1...., *it - ')•-,\ u Q 1 "C) "....„V • if ,.i. raPRINT DISTRIBUTION LIST BAKER HUGHES COMPANY Armstrong Cook Inlet, LLC INTERMEDIATE FINAL Yes (mandatory) WELL NAME NFU#23-25 RUN NUMBER (mandatory) "` FIELD North Fork Unit BH SALESMAN Woods,Jim (mandatory) (mandatory) COUNTY Kenai Peninsula Borough BH DISTRICT Alaska (mandatory) (mandatory) STATE Alaska PAGE OF (mandatory) LOG DATE: September,2012 TODAYS DATE: 11/9/20121 (mandatory) DISTRIBUTION LIST AUTHORIZED BY: Colby VanDenburg (mandatory) 1 HAS CLIENT BEEN INVOICED FOR ADDITIONAL PRINTS? NA COMPANY CD (FIELD FINAL digital/ ADDRESS(FEDEX WILL NOT DELIVER TO P.O.BOX) LOGS LOGS image) FILM PERSON ATTENTION #OF PRINTS #01- PMN I #OF COPIES #OF COPIES 1 Armstrong Cook Inlet, LLC 2 2 Attn: Colby VanDenburg 1421 Blake Street Denver, CO 80202 303 623 3019 2 GMT Exploration Comp 2 1 ATTN: Phil Wood 1560 Broadway Suite 800 Denver, Colorado 80202 Phone: (720) 946-3032 3 Dale Resources, LLC I 2 I 1 ATTN: Kyle Thompson 2100 Ross Avenue Suite 1870 -- Dallas, TX 75201 Phone: (817)451-5353 4 Nerd Gas Company, LLC I 2 I 1 ATTN: Edie Hardy P.O. Box 3003 1701 East"E" Street Casper, Wyoming 82602 Phone: (307) 234-0583 5 Alaska Oil &Gas Conservation Commission 1 1 ATTN: Steve Davies ^ 333 W 7th Ave aced�S�q Suite 100 Anchorage, AK 99501 TOTALS FOR THIS PAGE: 0 9 6 0 0 0— TOTALS FOR ALL PAGES: 0 9 6 0 0 0--- Regg, James B (DOA) From: Companyman [companyman@allamericanoilfield.com] Sent: Sunday, September 16, 2012 7:54 AM To: Regg, James B (DOA) d�/ �1'6/6 Subject: BOP CERTIFICTION CARDS Attachments: ALLEN LUNDA-COMPANY MAN.pdf; BRIAN TIEDEMEN-PUSHER.pdf; JIM BROWN-CO MAN.pdf; KELLY COZBY-PUSHER.pdf; KENNY SULLIVAN-TOOLPUSHER.pdf; MATT VANHOOSE-DRILLER-TOURPUSHER.pdf; MICHAEL REES-DRILLER AND ROBERT COYNE- DRILLER.pdf; RALPH LANGHAM-DRILLER.pdf; TOBY BORDELON- TOURPUSHER.pdf Jim, Here are the BOP certifications for crews currently working on Nabors 99. Allen Lunda/Jim Brown DSM/Armstrong Oil &Gas Work—907-865-9930 Cell—907-301-6065 £(. 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"5+.. f9G..:04,rrl.Y.."7TIf..•R.'.F!.0.1-4.1..24T.T.� .-ff Wiz'= :.f I9 k/1.4.1... `...,,C.,,../..,...,,,,..1.1,0,4.4 <i - I ' -KJ:8n4NY`TS.'-ice'"S. P/ 3'F-.,,,::a.rtm .. sear ,Y4544ZRZ. -14 `V.t, Y ar..r._ r.a. - Fs?3sTi1... -EiSlla73P� �w. s`��y.., l': 'Yfir,-_,.Fak" Ct_�.,�"cz -n' x[.a (.41 [au' UAL., Eirr , SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMMISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 Edward Teng FAx (907)276-7542 Vice President - Engineering Armstrong Cook Inlet, LLC 1421 Blake Street Denver, CO 80202 Re: North Fork Field, Undefined Gas Pool, North Fork Unit No, 23-25 Armstrong Cook Inlet, LLC Permit No: 212-091 Surface Location: 648' FSL, 1481' FEL, SEC. 26, 4S, 14W, SM Bottomhole Location: 1911' FSL, 1892' FWL, SEC. 25, 4S, 14W, SM Dear Mr. Teng: Enclosed is the approved application for permit to drill the above referenced development well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce is contingent upon issuance of a conservation order approving a spacing exception. Armstrong Cook Inlet, LLC assumes the liability of any protest to the spacing exception that may occur. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P Foerster Chair DATED this / day of July, 2012. cc: Department of Fish 8s Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o end. (via e-mail) r STATE OF ALASKA • AL ;A OIL AND GAS CONSERVATION COMMS )N +/1'°1/ PERMIT TO DRILL 20 AAC 25.005 1a.Type of Work: lb.Proposed Well Class: Development-Oil H Service- Winj H Single Zone H lc.Specify if well is proposed for: Drill E, Redrill ❑ Stratigraphic Test n Development-Gas Service-Supply ❑ Multiple Zone ❑✓ Coalbed Gas ❑ Gas Hydrates ❑ Re-entry ❑ Exploratory(Gas) f I Sr'Service- WAG ❑ Service-Disp ❑ Shale Gas ❑ 2.Operator Name. s',0V 5. Bond: Blanket ❑ Single Well EI,Le 11.Well Name and Number: Armstrong Cook Inlet,LLC Bond No. 585 551 lit//I., North Fork Unit No.23-25 3.Address: 6.Proposed Depth: 12.Field/Pool(s): - 1421 Blake St.,Denver,CO 80202 MD: 10,473 • TVD: • 9,300 ,_.„-_,..6,4 Y'-° 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): North Fork 0 Surface: • 648'FSL&1481'FEL 26 4S 14W . SM ADL-391211/2095 �A ?-1 i L- Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1911'FSL&1892'FWL 25 4S 14W SM 20-Jul-12 • Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 1911'FSL&1892'FWL 25 4S 14W SM 648 FSL 1481 FEL 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elev above MSL: 679 feet 15.Distance to Nearest Well Open Surface: x- 199 931 • y 2,121,190 • Zone- 4 GL Elev above MSL: 658 feet to Same Pool: na 16.Deviated wells: Kickoff depth: 500 feet 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) �L_ 7/c'/z- Maximum Hole Angle: 41.25 degrees Downhole: y-351 Surface: ;. `/LL 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 0 16 0.5 x56 Welded R3 0 0 120 120 Driven 13 1/2 10 3/4 45.50 N/L 80 BTC R3 0 0 3,100 2,700 750sx Lead @ 12ppg+240sx Tail @ 14.8ppg ✓ 8 3/4 7 26.00 N/L 80 BTC-M _ R3 0 0 10,473 9,300 250sx Lead©12.7ppg+280sx Tail @ 13.8ppg V 0 0 0.00 0 0 R3 0 0 0 0 sx Lead @ ppg+sx Tail @ ppg 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): Effect. Depth MD(ft): Effect. Depth TVD(ft): Junk(measured): Casing Length Size Cement Volume MD R E C E I VE r Conductor/Structural Surface JUL 0 2 201 ' Intermediate Production 1\OG CC Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 20. Attachments: Property Plat E BOP Sketch 0 Drilling Program 2 Time v.Depth Plot RI Shallow Hazard Analysis[i] Diverter Sketch 0 Seabed Report Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements❑✓ 21. Verbal Approval: Commission Representative: Date 6/7/12 22. I hereby certify that the foregoing is true and correct. Contact Stephen Hennigan 337 849 5345 Printed Name Edward Teng Title Vice President-Engineering Signature Phone (303)623-1821 DateC�µ��/28/ D( - Commission Use OnlyZ2 Permit to DrillAPI Number: , • - Permit Approv See cover letter for other Number: 2_ f / 50-"71-7/-- Z( 57-(;C)--0 Date: 1 \\ \\(1,- • requirements. Conditions of approval: If box is checked mavp�not be used to explore for,test,or produce coalbed m thane,gas hydrates,or gas contained ir❑ales. Other: ,a� -(QOC Ps Sof /e S t rieSS«- ` Samples req'd: Yes❑ No Mud log rec Yes❑ No 44 2 S- $ - A r,,,,.,4/,J. -res-e- 6n... 1 H2S measures: Yes Ell No Dr Directional svy reef Yes❑ No -' i ( S( � 1.44.4- 479,4-s' 6 C---in S S IR-% (.4.,r'1w av ctLr.e.„i ari,le__t•-i' `L, le-$4-. CY"'4.- r 0"4;(. APPROVED BY THE COMMISSION DATE: -7-14,-/z_ ,COMMISSIONER I 7•1(1L Form 10-401(Revised 7/2009) This permit is valid for 24 months from the date of approval(20 AAC 25.005(g)) Submit in Duplicate ORIGINAL 0,7„...0,7„... A ARMSTRONG Cook lnlet. LLC • June 28, 2012 RECEIVED Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission J U L 0 2 20.;l 333 West 7th Avenue, Suite 100 AOGCC Anchorage, AK 99501 RE: Application for Permit to Drill—Armstrong Cook Inlet, LLC—NFU#23-25 Dear Ms. Foerster, Armstrong Cook Inlet, LLC hereby applies for a Permit to Drill an onshore gas exploration well near Anchor Point on the Kenai Peninsula. Armstrong plans to spud the well in August, 2012. Armstrong plans on using the Nabors Rig 99 for the drilling of this well. If the well test results are sufficiently encouraging, the well will be placed on long-term production. Please find attached information as required by 20 AAC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill 2) Plats showing the surface location of the well 3) Aerial map 4) Proposed Wellbore Diagram 5) Plan Plot 6) Drilling Time vs. Depth Plot 7) Program Details with calculations 8) Cementing Program Summary 9) Directional Plans 10)Wellhead diagram 11)Diagrams and Descriptions of the BOP Equipment to be used 12)Proposed Solids handling 1421 Blake Street,Denver,CO 80202 (303)-623-1821 Ph (303)-623-3019 Fax Page 2 Following are Armstrong's designated contacts for reporting responsibilities to the Commission: 1) Completion Report(20 AAC 25.070) - Stephen Hennigan, (337)-849-5345 2) Geologic Data and Logs (20 AAC 25.071) - Colby VanDenburg, (303)-623-1821 If you have any questions or require additional information,please contact one of the following: Stephen Hennigan 337-849-5345 Edward Teng 303-623-1821 Colby Vandenburg 303-623-1821 Thank you. Sincerely, AwAp- Edward Teng Vice President-Engineering Armstrong Cook Inlet, LLC Enclosures Cc: Colby Vandenburg—G&G Stephen Hennigan—Petroleum Engineers for Armstrong Cook Inlet, LLC A ARMSTRONG (bed/n/cz LL(' Armstrong Cook Inlet, LLC () Exploration North Fork Unit # 23-25 NF Unit Block/Sec 26 4S 14W North Fork 0 0 Alaska Ser#.: , USDW: ' Prepared By: Armstrong Cook Inlet, LLC 0 PETROLEUM ENGINEERS and Petroleum Engineers, Inc (337) 984-2603 __ 477 V Armstrong Cook Inlet, LLC 0 North Fork Unit #23-25 Block/Sec 26 4S 14W North Fork 0 0 Alaska Ser#.:211 ???? ',1 G&HOLE SIZE USDW:' Est Rkb 20' Air Gap 0' Wtr.Dpth 8.3 8.6 9.8 100'pen i 201 /.5#x56 Welded Drive Sz» 16 " ROP/Gas log Cond/Drive to TD. 8.3 8.8 14.0 Mud Logging 3100' 45.5#N/L 80 BTC 13 1/2" 2700' 10 3/4" 2700' casing I 6500' Tgt 9300' TD Mud Logging: Manned: 2 sx every 10',0'to TD 5S'60 MD Est TOC 9.0 10.0 16.5 Quad LWD 10497' 1126#N/L80 BTC-M 8 3/4" 9300' Bicenter/UR" 7 " r 0 o � jjjiILIlIi!!IIj r ■■■■■■■■■OM■■■■■■ .� O „ ■■■■r - ■■mi ■■■■ ■■ ■■ ■■■■1 ■■■■■■■■■■■■ 1i!IiII1IIIINIII 1111 ,s 'g • 0 ■U ■■■■■■■r■■■ ■■ Z - Q U III 111111111111111 ■ ■■■■ 1 .tii ■ ■ ■■■■ ■■■■ ■ 0 0 0 0 0 O o 0 O 0 O 0 0 0 0 0 0 0 0 O o 0 N O 8 000 O aiu) r r `u;dea L Armstrong Cook Inlet, LLC 0 North Fork Unit #23-25 Block/Sec 26 4S 14W North Fork 0 0 Alaska Ser#.:211 ???? Time vs Depth Casing Size& Depth 0 ;J lr V -- Days vs MD —TVD vs Days V Prod Csg/Inr 1,000 2,000 3,000 4000 5.000 6.000 — 7,000 8.000 -- 9.000 1 0.000 11,000 12,000 0 5 10 15 20 25 30 's 'o 1 Emergency response Information 1.1 Directions to Location Method Directions Air Latitude: 59°47'46.956"N Longitude: 151°37'45.476"W NAD 27 Directions from Kenai •Start out going north on Main St toward Highland Ave.travel 0.1 mi •Take the 2nd right onto Kenai Spur Hwy.Kenai Spur Hwy is just past Frontage Rd travel 0.7 mi •Turn right onto Bridge Access Rd.Bridge Access Rd is 0.1 miles past Spur View Dr travel 3.3 •Turn right onto Kalifornsky Beach Rd.travel 16.2 mi Ground •Turn right onto Sterling Hwy/AK-1/I-A1.Sterling Hwy is 0.2 miles past Heine Berger Ln travel 45.7 mi •Turn left onto N Fork Rd.N Fork Rd is just past Williams Way travel 8.4 mi •Turn Right on Epic rd.travel 120' •Pad on right hand side of road 35315 North Fork Road Anchor Point,Alaska 99556 1.2 Rig Contact Numbers(Tentative depending on rig and communications available at time of MIRU)) Rig Phone List Cell#'s Co.Man: See below Tool Pusher: Mud Engr: Directional: Expediter: Rig Fax: CM Backup: See below TP Backup: 1.3 Emergency Response Contact Numbers Company Contact Numbers Position Office Cell Larry Driskill Co Man (907)598-1650 Larry MacAlester Co Man (907)240-6244 Tool Pusher: Pete Berga Superintendent (573)201-3861 Response Service Location Contact Phone Ambulance Homer,AK Front desk (907)235-8121 Fire Anchor Point,AK Station (907)235-6700 (907)399-1482 Homer,AK (907)235-3155 Hospital Homer,AK South Peninsula (907)235-8101 Police Homer,AK Front desk (907)283-7879 (907)235-3150 Anchor Point,AK Alaska State (907)235-8239 Spill&Contamination Alaska Alaska State Spill Reporting Refer to Facility chart National Response Center Oil/Toxic Spills,etc (800)424-8802 Coast Guard (800)479-5555 AOGCC (907)793-1226 — e1K 5' (907)279-1433 Main Single Point (866)942-6564 1.4 Company Emergency Response Name Position Office Mobile Ed Teng Vice Pres.-Engineering (303)981-9957 Steve Hennigan • Drilling Engineer (337)849-5345 Pete Dickinson Operation Manager (907)230-6541 Pete Berga Superintendent (573)201-3861 Drilling Supervisor Drilling Supervisor Prepared by Stephen F.Henniganq 6/29/2012 Page 5 2 Regulatory Agency Contacts by phone or email Agency Office M-F (8AM-5PM) Contact 24 hr AOGCC (907)793-1236 Inspection Supervisor(Jim Regg) See Industry Guidance 10-01 doa.aogcc.orudhoe.bav@alaska.gov 3 Regulatory Compliance Regulation New Requirement 20 AAC 25 BOP testing every 7 days 24hr notice required 4 Drilling Program Summary 4.1 General Well data Name North Fork Unit#23-25 Lease/Lic ADL-391211/2095 Surface Lcn 648'FSL&1481'FEL 26 4S 14W WBS Code Sit/Pad Exstg pad Field North Fork () Spud Date(est) 07/20/12 KB(above MSL) 679 County/Prov Kenai API No. GL(above MSL) 658 State AK Permit No. Perm Datum KB Total MD 10,473 Well Class Exploration WD na Total TVD 9,300 Drlg Contractor Nabors Alaska USDW <+-3000' Rig Name Rig 99 4.2 Working Interest Owners Company Working Interest Address Primary Phone Fax Armstrong Operator Cook Inlet, 1421 Blake St.,Denver,CO 80202 (303)623-1821 LLC Prepared by Stephen F.Henniganq 6/29/2012 Page 6 4.3 Geologic Program Summary NAD 27 NAD 83 NFU 23-25 WELL NF J 4'2199530. N:21229447% E 1334956 13C -ATITJOE:574746-9565 N LONGITUDE -151-3745.4764"W LATITUDE 974744.754-V NAD27 ASP ZC E 4 LONGITUDE -t 51'3 53.244"W ELEV.657.8 NAVD38 NA RASP ZONE 4 F2EV.657.8'N•110,106E NAD 27;Alaska Zone 4 X Co-ord. Y Co-ord. Surface Location Co-ordinates 199,931 2,121,190 Bottom Hole Location co-ordinates 203,338 2,122,345 Pore Pressure Targets M.D.(ft) T.V.D.(ft) X Co-ord. Y Co-ord. (ppg)est Tgt 7697.42 6500 203,338 2,122,345 8.4 • TD 10497.42 9300 203,338 2,122,345 9 4.4 Formation Evaluation Summary LWD OH WL LOGGING OH TESTING/CORE MUD LOGGING FULL MUDLOGGING NONE NONE NONE CREW SURFACE TO TD GR, RES SURFACE CP TO 5700'MD NONE NONE GR, RES, DEN, NEUT, SONIC(P&S) Possible NMR 5700'MD TO TD NONE NONE F V V Prepared by Stephen F.Henniganq 6/29/2012 Page 7 4.5 Summary of Potential Drilling Hazards Hazard Event Depth Discussion Precautions /interval Wildcat Well ALL Monitor all paramters for exploratory well Balling Surface Maintain high gpm/rpm to keep bit/BHA clean Perform aditional circulating times Boulders/rocks/sand Surface Control penetration,add Icm,high vis sweeps Monitor for loss of rtns Possible depleted zones Intm Wells off of same pad had no issues. Monitor for loss of rtns and differential sticking. Discontinuity of formations minimizes potential. Monitor for connections in hole. Circulate hole High drill gas Intm Wells off of Same pad had no issues. clean to clear wellbore of gas before proceeding. Be sure degassing eqpmt is operating property prior to spud. Potential Hazards Statement To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the drillers dog house. The man on the brake,driller or relief driller is responsible for shutting the well in BOPE or diverter as applicable as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC inspector. This well's primary objective is gas and no oil sands are expected to be encountered. No H2S is anticipated. Gas sands MAY be encountered from±3000'TVD to total depth of the well. These sands will run from slightly depleted to normal pressure. The drilling mud system will be properly weighted to control control the pressure of all sands and lost circulation materials will be available on location if required. Prepared by Stephen F.Henniganq 6/29/2012 Page 8 4.6 Drilling Program Summary 4.6 General Summary Well Name North Fork Unit #23-25 Permit to Drill No. Location Surface: 648'FSL&1481'FEL 26 4S 14W Top of Productive Horizon:1911'FSL&1892'FWL 25 4S 14W Bottom Hole: 1911'FSL&1892'FWL 25 4S 14W Planned TD MD: 10,473 TVD: 9,300 Directional Plan As per program Well Summary A 16"conductor will be driven/drilled to±120'and a cellar will be constructed and installed. Using water-based mud,approximately 500'MD of 13-'/"hole will be drilled as a straight hole prior to kicking off and drilling directionally to the first casing point at±2700'TVD where 10-%"surface casing will be set and cemented to surface. Then a 8 3/4"hole will be directionally drilled to a planned TD of 10473'/9300'MD/TVD. If electric logs indicate zones that are encouraging, 7"production casing will be set and cemented. Then the well will be tested,completed,and then suspended for production hook-up. The entire production hole will be drilled in the Beluga and Tyonek Formations,which contain coal beds of varying thickness.The well will be drilled using PDC bits.These bits exhibit a reverse drilling break upon encountering coals,allowing time for these bits to work the coals as they distress and swell. Based upon the near offsets, gas cut mud may occur. Therefore there will be close monitoring and more circulation of mud to insure proper conditions for progressing. Based on offsetting well information,there are no shallow gas or H2S risks anticipated for this well. KEY DEPTHS Start Depth Seat Depth Interval Hole Size MD TVD MD TVD Drive/Structural Driven 0 0 120 120 NO Conductor Surface 13 1/2" 0 0 3100 2700 Intm/Prod 8 3/4" 0 0 10497 9300 Pore Pressure/Mud Program The well will be drilled to TD using water-base mud with a weight of 9.3 to 9.9 ppg in the production hole section and adjusted as necessary while drilling to TD. Mud Logging - Gas monitoring will be provided in the surface hole. Basic mud logging services will be provided from the surface casing depth to TD. Services will consist of cuttings description and construction of a lithology log.The mud loggers will tie their well monitoring system into a PVT system to help monitor fluid levels and system gains/losses. Logging Program Electric logging(either LWD or/and open hole)will be performed cat each casing depth. If hydrocarbons are indicated to be potentially economic,then the testing phase will begin after casing is run at TD. ---. .7,.a � /ta / /__ i BOP Testing lJ ( 7/t0•/L BOP testing will be conducted at least every seven days. AOGCC Field Inspectors will be notified 24 hours in advance of spud and all diverted BOP Tests. It will be noted on drilling report and on IADGYsTieet whether the test was witnessed by the AOGCC inspector or waived. Waste Disposal All solid waste,including drill cuttings,will be disposed of in a nearby permitted facility Excess mud and fluids will be disposed of as permitted. Completion/Well Testing After the production casing/liner is run,it will be cleaned out and tested. A completion/test string and packer will be run. Each potential zone will be perfed, tested,and then isolated. Following the tests,zones to be produced will be identified and then put to completion. Prepared by Stephen F.Henniganq 6/29/2012 Page 9 4.7 Casing program Summary Start Depth Seat Depth Seat Depth Casing Interval Hole Size MD TVD MD TVD Size Wt(Ib/ft) Grade Conn Burst Collapse Tension Drive/ Driven 0 0 120 120 16 0.5 x56 Welded N/A N/A N/A Structural NO Conductor Surface 13 1/2" 0 0 3100 2700 • 10.75 45.5 N/L 80 BTC 4230 2470 845 Intm/Prod 8 3/4" 0 0 10497 9300 7 26 N/L 80 BTC-M 7240 5410 604 Buck on float equipment @ yard MU casing to optimum torque 4.8 Calculation of Maximum Anticipate Pressures(MASP and MADP) Note: In this program,MASP for each hole section is defined as the pore pressure(in psi)at the next casing point(or TD)less a gas column to surface. The MADP is defined as the maximum pp WITHOUT a gas gradient. Gas gradient is assumed to be 0.1 psi/ft. 13 1/2" Hole Section-estimated pore pressure of 8.3 ppg emw This hole section will be drilled to depth with a diverter only(no BOP's)and-±8.7-9.1 ppg mw. While MASP will equal the formation pore pressure at the next shoe,less a gas gradient to surface,it cannot be shut in,only diverted. Calculations: MASP(pp)=((PP ppge)x.052 x TVD)-(gg x TVD) MASPi13 112')= 2700'TVD x((8.3ppge".052)-0.1 psi/ft) 895 psi MADP=((PP ppg)x.052 x TVD) MADP= 2700'TVD x(8.8ppg`0.052) 1236 psi 8 3/4" Hole Section—estimated MAXIMUM pore pressure of 9 ppg emw This hole section will be drilled to TD with BOP's and related equipment installed and tested and with a 9.3-9.9 ppg mud weight. Based on available offset information the most likely maximum pore pressure is anticipated to be<8.6 ppg EMW. c Calculations: MASP(pp)=((PP ppg)x.052 x TVD)-(gg x TVD) �� MASP= 9300'TVD x((9ppge".052)-0.1 psi/ft) 3422 psi MADP=((PP ppge)x.052 x TVD) MADP= 9300'TVD x(9ppg"0.052) 4352 psi Prepared by Stephen F.Henniganq 6/29/2012 Page 10 4.9 Casing Design and Calculations ✓ Note: In this program,MASP for each hole section is defined as the pore pressure(in psi)at the next casing point(or TD)less a gas column to surface. Gas gradient is assumed to be 0.1 psi/ft. MADP is defined as the maximum pore pressure in the hole section. ' Start Depth Seat Depth Casing Interval Hole Size MD TVD MD TVD Size Wt(lb/ft) Grade Conn Burst Collapse Tension Drive! Driven 0 0 120 120 16 0.5 x56 Welded N/A N/A N/A Structural NO Conductor Surface 13.5 0 0 3100 2700 10.75 45.5 N/L 80 BTC 4230 2470 845 Intm/Prod 8.75 0 0 10497 9300 7 26 N/L 80 BTC-M 7240 5410 604 • =minimum of body and connection strengths RECOMMENDED Casing Design Factors BURST(from internal pressure) 1.1 COLLAPSE(from external pressure) 1 TENSILE(joint body and connection)strength 1.6 1 I Prepared by Stephen F.Henniganq 6/29/2012 Page 11 BURST REQUIREMENTS 10 3/4" Surface 8 3/4" Hole Section—estimated pore pressure of 9 ppg emw This hole section will be drilled to 9300'TVD with BOP's and related equipment installed and tested and with a 9.3-9.9 ppg mud weight. Based on available offset information the most likely maximum pore pressure is anticipated to be 8.6 ppg EMW. Estimated fracture gradient(FG)at the 10'/." shoe is 14.5 ppg emw and safety factor(SF)of.5 ppg emw. from above MASP= 9300'TVD x((9ppge".052)-0.1 psi/ft) 3422 psi MADP= 9300'TVD x(9ppg*0.052) 4352 psi MASP(fg)=((FG+SF ppg)x.052 x TVD)-(gg x TVD) MASP Csg Design= 2700'TVD x((14ppge+.5 ppge)-0.1 psi/ft) 1766 psi Burst Stress= MASP Csg Design is used since in case of a kick in excess of 1766 psi,shoe would break down. Design Factor Burst Strength/Burst Stress= 4230/1765.8 2.40 SF 7 " Intm/Prod Since this is a production design,MASP of 3422 psi is used for highest pp. Design Factor Burst Strength/Burst Stress= 7240/3422.4 2.12 SF L� Prepared by Stephen F.Henniganq 6/29/2012 Page 12 COLLAPSE REQUIREMENTS Use an external pressure that the casing could possibly be put under. One design methodology uses pore pressure at the casing shoe with a gas gradient internally. 10 3/4" Surface External Pore Pressure less gas gradient MASP(pp)=((PP ppge)x.052 x TVD)-(gg x TVD) MASP(13 1/2")= 2700'TVD x((8.3ppge*.052)-0.1 psi/ft) 895.32 psi Design Factor Collapse Rating/Collapse stress= 2470/895.32 2.76 SF 7 Intm/Prod External Pore Pressure less gas gradient MASP(pp)=((PP ppg)x.052 x TVD)-(gg x TVD) MASP= 9300'TVD x((9ppge".052)-0.1 psi/ft) 3422 psi Design Factor Collapse Rating/Collapse stress= 5410/3422.4 1.58 SF TENSILE REQUIREMENTS Tension is usually defined as the body or connection tensile strength(whichever is least)compared to the buoyed weight of casing in mud when run. Buoyed weight is defined as weight in air minus the weight of displaced fluid that it is run in. Buoyed weight formula=MD*Csg Wt(Ib/ft)*(1-mw/ 65.45)where 65.5 is the avg wt per cu ft of iron in air. 10 3/4" Surface Buoyed weight= 3100'MD x 45.5 ppf"(1-8.8ppg/65.45) 122086 pounds Design Factor= tensile strength/buoyed wt = 845000/122086 6.92 SF 7 " lntm/Prod Buoyed weight= 10497 MD x 26 ppf (1-10ppg/65.45) 231223 pounds Design Factor= tensile strength/buoyed wt = 604000/231223 2.61 SF Prepared by Stephen F.Henniganq 6/29/2012 Page 13 4.10 Casing Test Pressure Calculations Casing test pressures are based on the maximum of MASP or 50%of the BOP ram rating In this well,formation pressure is assumed to be the backup. See Casing design and MAWP calculations. BOP PROGRAM,Test Pressures and Casing Test Pressures MASP= Maximum Anticiapted Surface Pressure(psi) MHDP= Maximum Anticipated Downhole Pressure(psi)@ TD Casing Size Casing Equipment Test Pressure Low/ High 16" Structural Casing© 120 ' 21-1/4" 2000 Di',erter Function Test 70%of Burst N/A Test Pressure Function Test NO Conductor i 70%of Burst: Test Pressure. 10.75" Surface Casing @ 3100' (1) 13-5/8" 5000 Annular 250/ 2500 70%of Burst 2961 Min.(2) 13-5/8" 5000 Pipe Rams 250/ 4000 Test Pressure 3000 (1) 13-5/8" 5000 Blind Rams 250/ 4000 MASP 3422 MADP 4352 MASP Casing Design 1766 7 " Production @ 10497 ' (1)Will not drill out Annular 250/ 2500 { 70%of Burst 5068 Min.(2)Will not drill out Pipe Rams 250/ 4000 V Recommended Test Pressure 2900 (1)Will not drill out Blind Rams 250/ 4000 Test Pressure 4000 MASP 3422 MADP 4352 MASP Casing Design 3422 • • BOP Test Pressures for Completion 7 " Production (1) Annular 250/ 2500 • 70%of Burst 5068 Min.(2) Pipe Rams 250/ 4000 Test Pressure 4000 (1) Blind Rams 250/ 4000 Prepared by Stephen F.Henniganq 6/29/2012 Page 14 t 4.11 Blowout prevention Equipment Details,Testing and General Procedures SEE ATTACHED DRAWINGS Testing: Onsite supervisor will verify all pressure tests. All tests are to be recorded on the IADC and DDR reports. ALL are to be charted. AOGCC to verify BOP tests(24 hr notice) Casing Test BOPS Test Casing Casing Size(MADP(psi) MASP(psi) Pressure Test Fluid 250 psi Pressure Density Size&Rating Low/high (psi) (lb/gal) (psi) Surface 10 3/4" 4,352 3,422 3000 8.8 (1)13 5/8"5M annular 2500 (1)13-5/8"5M pipe ram 4000 (1)13-5/8"5M blind ram (1)13-5/8"5M drilling spool w/3—1/8"5M outlets (1)13-5/8"5M pipe ram lntm/Prod 7 " 4,352 3,422 4000 10 (1)13 5/8"5M annular 2500 (1)13-5/8"5M pipe ram 4000 (1)13-5/8"5M blind ram (1)13-5/8"5M drilling spool w/3—1/8"5M outlets For (1)13-5/8"5M pipe ram COMPLETION 7 " 4,352 3,422 4,000 8.6 (1)13 5/8"5M annular 2500 (1)13-5/8"5M pipe ram 4000 (1)13-5/8"5M blind ram (1)13-5/8"5M drilling spool w/3—1/8"5M outlets (1)13-5/8"5M pipe ram 4.11a The choke manifold will be rated 3 1/8"x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also on the location is a poor-boy gas buster and a vacuum type degasser. Flow sensors will be installed in the flowline and the mud pits will have a PVT system. All data will be available to the driller, company men and key individuals. 4.11b Function Testing: Function on each tour. Report test on daily drilling report(DDR). Prepared by Stephen F.Henniganq 6/29/2012 Page 15 4.12 Wellhead Equipment Summary Component Description BASEPLATE KIT24 OD X 14 ID X 1.50 THK W/6 NUMBER 1 GUSSETS.W/JWO 2-1/2 GROUT Casing Head SLOTS.F/13-5/8 CSGHD HSG.WG,SH2-LWR,11 5M X 10-3/4 SOW W/ORING.W/2 2-1/16 5M FPO,6A-PU-M-1-2 CSGHGR.WGSH2.11 X 7 23.0 Casing Hanger -26.0 LC BOX BTM X 7.375-4 ACME LH PIN TOP,MIN BORE 6.276,6A-PU-AA-1-2 TBGHGR.WG.T-M40-CCL,11 X 2-7/8 EU BTM AND Tubing Hgr TOP,W/2-112 HBPV THD AND TWO 01-ICV PORTS.4130 80K6A-LU-DD-NL-1-2 Tree 5k-TBD USE SPACER SPOOL AS NECESSARY SEE ATTACHED DRAWING 114449 WC Prepared by Stephen F.Henniganq 6/29/2012 Page 16 U d a, Om w • 40.T 0 U7 ffC 0 CA V..-.- C C j�r j� O MMM :- ,s,J N 1] O ---f'7 Ln H m v C p a h 0 C N w Y W N. 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M MMM o'). . p') J N N N N N NO N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N NO N N N N N N N N N N N N N N Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z?Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z Z N mM V CO V m C)CD O i'i00)l'7 CDN M 0)N V NN v NNV V IOi)N CO CD T CD CD CD CD CD CO CO CD CCO MMM CDM CD CD CD CD CD GD CD CD CD CC CD CC CD CD N N n M N V M M M V M M M M n N M V M r r M M ONO M N V V V V V V V V V V V V V V V V V V V v V V V v v V V V V V V V V N V NVO V O M N N N N V M C)CD O N V M M O M V C)M N M M 0 O o C))6 iO 6 C)M)M NNN)C)NCO N M N C)N M C)N M M N N N M N f1 C)NMN)N M C)NMO M N N M N M M N M M N M M N C)C)NMO N M N N NMN)CD M M M M M M M M M D vvvv vVVV VvVVVvvvvvvvvvvvvvvVevvVVv VVvvavvvvvvvvVVV--Va -VVVVVvvvvv d 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 M O)M M M T T M T T 0 0)0 0)0 0 0 0)0 N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N NO N N N N N N N N N N N N N N N N N N C) N er O M M M M N M N M M, M N M O V M O N O N M M N N O N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N M V NOM��N V ND�MN7(nom V NNMMODMMMM�V tD�NMMONt)aNNN)A NC))n NMN N[)N()NO NNDN NNl)C)C) )Nn NNONn Nn Nn Nn N.NNN)NN OM0MMOCMNNNGCNGMO MNN NNCNrMS O=NNOO MM V V 0 V ��V V "' NM MNp 0)00a000�NN MMO NMNMNM M ffC')CC')!lC') llC')f(C')CC')CMMM llC')C') C7 t")t`7 lfN��f ZN MMTMMM 00000 N NNNNNNNMM M MM N N N N N N N N N N N N N N N N N N N N N N IN N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N .J N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N'.N N N N N O N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N M n.-N M M r N M M n 0 M M M O M N o M C V r M r O Np M O r N N N N N n N N N N n N n n N N r N N r r N N M n N N N N N N m NM NO)V MMN ND OSMN M'-Mr M M Nt)M N MM NO rM W w NOM Nh N CG 0 N7 NC)W O M O V 3 N r N V< NN NG N+)CG O)r NIM NO M CG M M C)M M C)M M M MMMM CD CD CD CD W CD CD CD C)M M MMMMM M N M V O NO M M C) M M O N NNN N NO o V n O M N N M N M M M M M M M M M M M M M MMMM C'C NO C')MMMMMMMM M.M MMM M E 0 0)O O N N NN M M V N N N M NN NN M M M NM 0 0 M M N N N N N M M M`c2) MM M M M MM M M M MM 22222 MMMM M M M M M M M M 222 C'.32 M M 22222 MMMM 0uNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNpNNNNNNNNNNNNNNNNN M M M M M M M M M M M M r M N O N N M N O n M N N M V 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O O 0 0 0 0 0 0 0 0 0 0 0 0 0 MMn NON V MN 0MMC)NNrNC)MNC vOM- NONNn NM V 00000000000000 SO O 0000000000000 A N M M N N O) C)O M O 0 0)N O)O M g M NG N')NO M V O 0)r N C') NN)M M CD M m CD CD M CD CO M M M M M M M M M M M M M M M M CO co M co CD M •-•-• M V N M M M NO r M M r r r M M M M n n n r n n n r r n n M M M M M M r n n n n W NNNNNNNNNNNNNNNN NN N'0)MMM MMMM NNN)M SM C')C'))NM+)NM+)NM+)M NM+)C'))CM7 NM+)M NM+)CM7 CM9 NM')CM7M CM)MM CM7MMMMM M NM+)MM MM M NM')M L« O MN M M N N MM N O Or MM N 6 M VM M N N M M NM V C))M N O M N N N N N N N N NM MN N N N N N '70V M NNMMM MOO M Np M M MMM 0 0MM M MMN N M 6 6 M M M M M M M M M M M D MMM MMMMM M M M CD CD M cd MNM M 0`" OaG0NvN0mCSNN NMNNDnMOONNMMMMMMMMMMMMMMMMMMMMMMMMMMMMMMMMMMM Z� MNMoNVrM MVMMM000 NNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNN MnNMMMMMMMMM NM E M N M NO M O M M N M M M O N M v M o M M e�N M M N V O O M o M M M M M M M M M M M M M M M M M M CD M M M CD M M M M M O 2 ° M M M n M 7 N V M CD N N1)M N OCD V N ND aD V 0)0 CD. r 0 O NO N Na)N N N N N lN)N 0 N N N N N N N N N NN)N N C)NA NO Nn NA Niy 0 w c« N N M M MM M CCpp Va�M Va�0) .-O CD CD O a O)N NG N O)N N N M C)N C7 M N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N o 0 E� N M O M N M O CD N M O M M M O_C M N V M N N 0 0 0 0 0 0 0 0 0 0 0 0 0 0_0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0_0 0 0 0 0 -LL N M M M M MMM07MMM M M MM V V V V V V V V V V V CON N NCONNNNNNNMMMMCDMMCO)C N NNN N N N NN M M M MCVDC0 CD M n M N M O M M N M M M 0 N M M C)M M V C M M N V O 0p M M M M M M C)M M M M M M M M M M M M M M M M M M M M M o NSM MCr� V CMNC N)N.-000 V NM M V C 0M.-NM ONSNCNCNSNCNCCNCNN NNNCNOCN NN NCNNO0 NN0MMM M M 0)V.-O0MO V MN MrMNNNMMN N')MNNONONNNNNNNNNNNNNNN NNN NNNN NNNNNN r M O M N M O_C)N 0)o M M M O M M N v M N N O o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 S ' M r M M M 0 N M V V N N M M M M M O N M V N M n M M 0 N M V V N N M N M M O N M V N M M M M O N M V N M r M M 0 N M M M M M M V V V V V V V V V V V V V V N N N N N NO N N N N M M M M M M M M M M M M N N N N N N N r N N M M M M M M M M M M M M M M r N M N N n n r n n N N n r r r r r r N r N r n n n n r r N n N n N n N N N N n N N N r N r r r M N M n r r r N n N r N r N r n r .-. M M M M M M M M M M M M M M M M M M M M M M M M w M M w M M M M M MMMMMM M M M M M M M M M M M M MMM MMMM M M M M w M M omm MSNDNONMDNONMD)CCCCDCDMSSMCDCDCSSSMCCDCCCCCCC CCCCD000CCCD ONp)000C)CCDCCC))NON))NDCCC 0 O_ .. NNNNNNNNNNNN C- NNNNNONNO) NO)MM07chMMS0)008p 888888888888888888888888888888 M n N M M N N Nh M r N M C V V V V V V V V V V V V V M M M M M N N N N N '-air-66,-.66666666666666666666666666666666 C pp p p 208080000000008888„ ON 888888888888.188888888888 O o 0 0 0 0 0 0 o Y o Y o 0 o 0 o 0 0 0 0 0 0. O 0 0 0 0 0 0 0 0 0 0 o N o p 0 0 0 p o 6 o 0 0 o O o O O O o o O n O r o O o o g g g S S S S S S S S S S S S S o 0 0 0 O r 2= 00000000000m0 000 O0000000000000MOM0000 VVVvv MMCMSMMMSMpnrrrrNnrNnNMCp MM0TM00MM0)0OoOOOOVCCCCCCCM TCMn n M0DDMD DDD000 4.13 Directional Program Summary Well is to be drilled as a directional hole. Surveys will be taken per AOGCC regulations or more frequently as needed. Inclinatio Comments MD n Azimuth TVD Grid East Grid North DSS Build Rate Turn Rate Vert Sect [ft] [°] [°] [ft] [US ft] [US ft] [°/100ft] [°/100ft] [°/100ft] [ft] Est.RTE: 21' 0.00 0.00 69.87 0.00 199930.76 2121189.62 0.00 0.00 0.00 0.00 KOP • 500.00 0.00 69.87 500.00 199930.76 2121189.62 0.00 0.00 0.00 0.00 End of Build 1874.85 41.25 69.87 1759.15 200379.54 2121341.73 3.00 3.00 0.00 473.85 Csg Pt 3100.00 41.25 69.87 2680.32 201144.51 2121601.02 0.00 0.00 0.00 1281.58 Begin Angle D 5535.14 41.25 ' 69.87 4511.28 202665.00 2122116.38 0.00 0.00 0.00 2887.04 End of Drop 7597.42 0.00 69.87 6400.00 203338.17 2122344.55 2.00 -2.00 0.00 3597.82 Target 7697.42 0.00 69.87 6500.00 203338.17 2122344.55 0.00 0.00 0.00 3597.82 TD 10497.42 • 0.00 69.87 • 9300.00 203338.17 2122344.55 0.00 0.00 0.00 3597.82 Plots Well Profile AArmstrong Cook Inlet, LLC ��t� F. FM NN 4125111110011115 ARMSTRONG Far. ...Falk UN RINIZil Ws .r NFO41n NYE iNT[I GM S..NAe31I TU A1WwIYM .SP.Zeno US 1 Wow.ow.am mlwonosa��M• .n MSWows 13.I11TE1 • ,E I RTES m YeFn SN t..1 MSM Soo*T.e eN✓.. 114.1 won sea"memo 1.1.mw S.N.F...3Si 0NY Dep..e mm� .wr.nme renmN nmlwu.m Sr c.w.o...o"''..1: 2....a E05'bp(II) EIC YCNO/C.R ' 00.M00 OIat 110.12123TO#1,0271, OS..412 NRR}]S IN023106.0.12 W 1 .10 a ,, End YPW 89113.Cap S.la. TOT 0 g Na01 F.023.25 3 Est RTE 31' RTE.31 NOP 300,10111 40 of 005E 'b 9624111CaO500 5 1 ....1150 C� .- 3 ao-nmE Em,005/CqR 10 CaMq a.mFUFY ...133..1W.0.027)OSF.12. TOSS WV.25 TO940W?):06Fe12. G,Sn Lao E000 0 O O E100 i0 .O Vertical Section(fl) "•."'-,•' Prepared by Stephen F.Henniganq 6/29/2012 Page 17 AArmstrong Cook Inlet, LLC 1p Location: Cook Inlet,Alaska(Kenai Peninsula) Slot: North Fork#22-35 BAKER Field: North Fork Well: NFU#22-35 HUGHES ARMSTRONG Facility: North Fork Unit(NAD27) Wellbore: NFU#22-35 Oil C-Gas.Inc Plot reference wellpat is NFU#22-35 Version#4 True vertical depths are referenced to Nabors 99(RTE) Grid System:NAD27 I TM Alaska SP,Zone 4(5004),US feet Measured depths are referenced to Nabors 99(RTE) North Reference:True north Nabors 99(RTE)to Mean Sea Level:678.35 feet Scale:True distance Mean Sea Level to Mud line(At Slot:North Fork#22-35):0 feet Depths are in feet Coordinates are in feet referenced to Slot Created by:jonethoh on 11-Jul-12 �„_,�� Easting(ft) -500 -450 -400 -350 -300 -250 -200 -150 -100 -50 0 50 100 150 I I I I I I I I I I I I I I North Fork North Fork North Fork o North Fork �25 #34-26 #32-35 #14-25 15^04 #23-25 7 _ #2� yo Ap 50- 1050 ^� , - 50 1650 North Fork FU #14-25 750 1950 #22-35 North Fork North Fork 2250 Est RTE:21' #33-35 #42-35 0 2850 750 750 750 -, 0 3450 1050 1350 4050 1050 4650 1050 ' -50- 5250 50 5850 1350 1650 6450 1350 -100— —-100 7060 f`2 7350 1 c 7650 1 -150— 1650 ' -150 7950 1350 1950- 8250 8550 -200- 8850 1650 -200 N -250— --250 1950 E Z -300— —-300 a c a L c r to 0 2 1650 -350— --350 1950 End of Build -400- --400 y tI t 2250 t -450- kt --450 500- 9 --500 r✓ -550- —-550 1950 2250 -600— —-600 2550 650- --650 h N -700- ,LR' ` # --700 J 4 u.'1 1 I I 1 2 1 1 1 1 IZ I 1 I I -500 -450 -400 -350 -300 -250 -200 -150 -100 -50 0 50 100 150 Scale 1 inch-10011 Easting(ft) Spider A Armstrong Cook Inlet, LLC so:...ktice Coca kW.A3SA.1,keea mita; Fielo North Fork ..cc 'kill i-m.a 1..-.3.. Weft tfl e 1245 BAKER \l\ It 0 Fsolity North Fat Unt iNAL1271 i'Vesore 'fl a*:-.15. HUGHES \I( N 6 Pat•ettera ae sue,s WI,r2-3.5,e.sita al Tr. ___dem,:re•Vrercea n Viors 4 CM N.Y. 3ea 3,-...•s•::- - ,2:1.3 31,Zan,MO,v3 tat Men.na welts re'Orel=lc P, '051 On WM Ore,ze--..e•,... .„. Moon'CO On n Oar Sea Lfte"CC tet Scar'Ns 3 ssrs War Its Leve 0 MA et.4tSce Neer eve s35 3 tat DefOnmem•er :oraeales roe r tettereenel n SAE Corer a'Sec:*'WS II.40i — • • I I I ir I •I 47° 4r 10 .I I T T ,....71; I - I' 7 mo .. kyr Fm 012-3.t - tax Nem hart 114-25 timed Nat Fat*23-2.1 soli ken sX-X Tymet 4+ KO. 431,FM*13-35 -A . ON NOT rtfla24-3 "KIT FOR 812-35 ................./.‹...-----1111 Not FUlt 1111-35 KO. ',f 1.'"----, - IOC : i " i ' ';4+ ----t- "I "- On' KO. , 42XC . aX - -.A, ' , , ,.),t,\4\,> so. zee 211\ • 0- XII - o ' ' WI -0:0. in .-11:0 403- / IS "7 . " : .4(0 -co- tameT -ice «0- .. . ,,L. i t i i • 1 1- ' 1 4.co ace :co •tko -on 416 .1 ..:. ..1. ' .." o' ..t) .1. .:., See attached directional program for more details 4.14 Directional Surveying Summary Downhole realtime surveying tool. Magnetic Interval MD(ft) MWD/LWD Multi Gyro Multi Clog Other Remarks Drive/Structural 0 120 NO Conductor 120 Surface 3100 x Intm/Prod 3100 10497 x Prepared by Stephen F.Henniganq 6/29/2012 Page 18 4.15-4.16 Drilling Fluids Program Summary and Specifications Mud Progran Drive 16"pipe to 120'.Build Spud Mud&d','I, ' 5 Casin Fluid Type: Spud Mud-Lower Fluid loss after 200•'_,.° Fluid .ro.-rtiesliste. below....___,,. I Depth Mud Wt. Funnel PV Yield Point Gels pH API FL HTHP FL Chloride SLDS (MD) vise 10 sec/10 min .5/U -OOUr ppg sec/q[ cp Ibf/100 ft2 lbf/100 ft2 m ic m.g/I %/VOL 0'-3,100'± 8.8-9.5 60-100 15-24 30+ 20/35 8.0-9.0 <18 N/A <-5000 <7 1 Pre-hydrate all Bentonite additions.Mix&pump prehydrated gel slurry in case of pea-gravel&massive sands,add Gelex to sweeps for added viscosity. 2 Run all available solids control equipment for maximum solids control. 3 Reduce fluid loss with additions of PolyPac Supreme UL prior to reaching 2000' 4 pH should be controlled with Caustic and/or Soda Ash 5 Add 2-513pb MIX II to mud system if seapage losses become a problem. 6 Maintain low gravity solid at<8%with dilution and solids control. Mud Progran Drill 8.75"to 11017/MD/.Set 7"Casio.' Fluid Type: KlaShield with 6%KCL Fluid properties listed below: Depth Mud Wt. Funnel PV Yield Point Gels pH API FL HTHP FL Chloride SLDS Vise 10 sec/10 min 250`F ppg sec/qt cp Ibf/100112 1b1/100 ft2 cc cc mg/I %NOL 3,100-10497' AMIN 40-50 1o.ic 12-18 10-14 9-9.5 7.00 N/A 28k-32k <6 1 Drill out 10.75"casing shoe with previous mud and displace to new KlaShield while drilling shoe before FIT The WBM should be maintained with KCI, Flowzan and PolyPac with sweeps as needed for additional hole cleaning.Maintain 2 concentrations of KlaStop for inhibition. Prior to drilling cement,pretreat the mud system with.25 ppb Sodium Bicarbonate to minimize effects of cement 3 contamination. 4 Begin adding Asphasol and Resinex as coal are drilled,coal stringers will be drilled thru this section. 5 Add MIX II and sized SafeCarb(20,40,250)to the mud for seepage(<15 bph). 6 Run solids control equipment continuously to maintain low gravity solids below 6%. 7 Lower yield point/gel strengths prior to logging,running casing,and cementing. I Note: Production casing plug will be bumped with water. I Prepared by Stephen F.Henniganq 6/29/2012 Page 19 4.17 Solids Control Equipment Interval Shaker Desander Desilter Mud Cleaner Centrifuge Cuttings Cuttings Zero Discharge Comments Dryer Injection Closed Loop System,Full Containment, 0-Total Depth x x run shakers with finest screens possible Item Equipment Specifications (typical but may not be exact depending on rig) (quality,design type,brand,model,flow capacity,etc.) Shaker 2-Brandt King Cobra Degasser Demco style Vacuum Desander N/A Desilter N/A Mud Cleaner N/A Centrifuge N/a Cuttings Dryer N/A Cuttings Injection N/A Zero Discharge N/A Best Practices: Have vacuum trucks pull fluids from trough above the cuttings tank to more efficiently pull fluids for disposal.This minimizes water added to the solids to suspend for pick up by the trucks,thus minimizing total volume to be disposed of. Cuttings will be Prepared by Stephen F.Henniganq 6/29/2012 Page 20 4.18 Cement Program Summary(Brief vendor prog is attached) Cementing Summary #VALUE Surface I Size: 10.75 " Setting Depth: 3100 ft. Annular Volume(No Washout): 1151.59 cu.ft. Lead SlurLy Density: 12 ppg Yield: 2.62 cu.ft/sx No.Sxs: 750 Specifications: Type I Desired Top of Cement: 0 ft. r 5 i` 1 Tail Slurry Density: 14.8 ppg Yield: 1.34 cu.ft./sx No.Sxs: 240 Specifications: I 8 Hour Compressive Strength of Tail Slurry: 1000+ psi Total Volume: 2286.6 cu.ft. Desired Top of Cement: 2760 ft. 990 Intim Prod.Casing I Size: 7 Setting Depth: 10497 ft. Annular Volume(No Washout): 750.90 cu.ft. Lead Slur] Density: 12.7 ppg Yield: 2.18 Cu.ft./sx No.Sxs: 250 Specifications: G Desired Top of Cement: 5500 ft. Tail Slurry Density: 13.8 ppg Yield: 1.85 Cu.ft./Sx No.Sxs: 280412% Specifications: G Desired Top of Cement: 8055 ft. Total Volume: 1063 cu.ft. 8 Hour Compressive Strength of Tail Slurry: 1000+ psi 530 #VALUE' Como encs. See r,eirient prognosis fur uetaiis arta spa er spec,dlcatiorrb. Haual cement volume pumpea win oe determined by elog caliper and other parameters. V Prepared by Stephen F.Henniganq 6/29/2012 Page 21 4.19 Bit Summary NO. Size Model Type Surface Hole 1 13 1/2" GTX-C1 or similar tooth Intm/Prod 2 8 3/4" HCD504ZX or similar PDC Prepared by Stephen F.Henniganq 6/29/2012 Page 22 4.20 Casing Test,FIT,Lot procedure Perform Casing Test(CIT) -the pressure to which the casing should be tested should be 300-400 psi above the expected surface pressure needed for the leak off test.It is NOT necessary to retest to the APD casing test pressure. 1.GIH and clean out to the top of the float collar for casing test. 2.Circulate and condition mud until shaker is free of cuttings and mud weight in is within +/-0.1 ppg of weight out for several consecutive measurements. 3.Rig up,pressure test and check for leaks.Make sure air is purged from the system. 4.Pumping down the drillpipe,break circulation with cementing unit(or low vol/high press pump). 5.Close annular BOP or pipe rams. 6.Pump down drilloioe at 1/2 bpm.Do not exceed this rate and maintain constant rate as well as possible.Record pressure at each 1/2 bbl increment pumped. NOTE: Larger than 11 3/4"use.75-1 bpm,11 3/4-9 5/8 use.75-.5 bpm-plot should be tgreater than 45° 7.Continue until the test pressure(as described above)is reached.Do not exceed test pressure. Stop pump and shut in valve. 8.Monitor and record shut in pressure;hold for at least 5 minutes,or as specified.Troubleshoot problems if desired test pressure cannot be obtained. 9.Release pressure and record volume of fluid recovered during flow back. 10.Input recorded pressures and corresponding volumes on the Casing Test section of ✓ the"CSG-FIT"worksheet(in the yellow shaded area).This is the minimum volume line G for the subsequent leak off test. Enter flow back when pressure is released. Prepared by Stephen F.Henniganq 6/29/2012 Page 23 Perform Formation Test(LOT.FIT.etcl -enter all the header information for the well,rig,casing size,shoe depth,mud weight,date and your name at the top of the form on the"CSG-FIT"worksheet. 1.Drill shoe track and+20'of new formation. POOH into the casing shoe.Circulate and condition mud until shaker is free of cuttings and mud weight in is within+/-0.1 ppg of weight out for several consecutive measurements. 2.Rig up lines,pressure test and check for leaks.Make sure air is purged from the system. 3.Pumping down the drillpipe,break circulation with cementing unit(or low vol/high press pump). 4.Close annular BOP or pipe rams. 5.SLOWLY pump down drillpipe and maintain constant rate as well as possible.Required rate may vary,but first attempt should be at 1/2 bpm(OR same rate as casing test). Record pressure at each 1/2 bbl increment pumped and plot on the FORM INTEG.TEST(FIT)section of the"CSG-FIT'worksheet(in the blue shaded area). This will require teamwork among at least two,but better with three individuals.If the FORM INTEG.TEST(FIT) plot curves BELOW the Maximum Volume Line,stop and bleed off pressure then re-run the test at a higher pump rate(suggest 1/4 bpm higher). Note-also have someone record casing pressure from the choke manifold at the same--bbl increments. If these pressures differ from the drillpipe recorded pressures by more than 10%,notify the office. 6.Continue until leak off(fracture initiation)is detected as indicated by a change in the rate of pressure increase. This is determined by the leak off test chart and observation of the pressure behavior.Once leak off indications are noted continue to puma at constant rate to confirm.If the pressure resumes a constant rate of increase, continue pumping and watch for subsequent leak off indications.If the rate of pressure increase continues to decline,continue pumping for 3 more_bbl increments to insure fracture has occurred(a noticable pressure drop should be evident).If a sudden pressure drop occurs,stop pumping immediately. 7.Record instantaneous shut in pressure(ISIP). �, Monitor and record shut in pressure every minute for at least 10 minutes. See#11 below 8.Release pressure and record volume of fluid recovered during flow back. 9.If the measured leak off pressure is less than the predicted leak off,then a cement channel may exist.Whenever a cement channel is suspected,the LOT should be repeated for confirmation.If a channel exists there should be little or no improvement seen. LOT or FIT or PIT (In EMW)=pressure(psi)/.052/casing shoe depth('TVD) +current mud weight(ppg) 10.If the Leak Off plot falls between the Minimum and Maximum Volume Lines,this is a good leak off plot.Pick the point on the curve where the line begins to break over(the rate of pressure increase has changed from a straight line).This is the leak off value.On a"jug"test,there is no bend.PPG equivalents are calculated on the right. 11.Input recorded pressures and corresponding volumes on the FORM INTEG.TEST(FIT)section of the"CSG-FIT" worksheet. Values should initially fall between the Maximum volume line and the Csg Test line. 12.Input recorded shut in pressures and corresponding times on the Shut In Pressure(ISIP)section of the "CSG-FIT'worksheet(in the yellow shaded area). This is indicated by ISIP and incremental time @ the bottom of FORM INTEG.TEST(FIT)section. Prepared by Stephen F.Henniganq 6/29/2012 Page 24 ARMSTRONG COOK INLET LLC. North Fork Unit #23-25 Cementing 10-3/4" Surface Casing: 1. Prior to cementing casing: • Check cement lab test for sufficient pumping time, free water and fluid loss. • Discuss job with cementer, check calculations and additives. • Verify cementing lines(chicksans, flexhose, etc.)are made up ready to go. • Confirm Stab-In collar placement is correct and drill pipe nipple matches Stab-In collar.,, • Drift Casing prior to running. • Assure extra hoses are available for water and mud. Cement the casing as follows: Immediately prior to shutting the pumps down record and report the pump pressure ON A RATE/TIME/PRESSURE basis +5-10 minutes. Hold pressure for 1 minute. Bleed pressure down to 0 psi.and pull out of tool. Load wiper plug into drill pipe and pump with rig with total displacement plus 5 bbls. to clean drill pipe. Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Spacer: 24 BBL Mud Clean II Lead: 760 sx Type I Cement+Additives 12.00ppg Excess 100% Over calculated volume or 20%over caliper volume Tail: 200 sx Type I Cement+Additives 14.8 ppg Excess 100% Over calculated volume or 20%over caliper volume Displacement Spacer: 5 BBL Use Fresh Water Displacement Mud: 294 BBL 8.8 ppg WBM - 299 bbl.total displacement Estimated Top Lead Surface of Cement Tail 2,760 ft PROPERTIES LEAD TAIL Weight 12.0 14.80 ppg Yield 2.62 1.34 Water 15.13 6.34 Pump time 5:35 2:31 Water loss N/A N/A Free water N/A N/A Comp. Strength 8 hours 106 500 12 hours 224 743 24 hours 423 1198 48 hours 661 Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. 2. After cementing, record the following: etc- • Time cement in place. • Pressure used to displace. • RATE/TIME/PRESSURE after slowing down in anticipation of bumping plug. • Amount of barrels pumped behind cement. • Amount of barrels bled back to check floats. • When and if returns were lost while cementing. • Amount of cement(in barrels) circulated to surface. Cementing 7" Production Casing: 1. Prior to cementing casing: • Check cement lab test for sufficient pumping time, free water and fluid loss. • Discuss job with cementer, check calculations and additives. • Verify cementing lines(chicksans, flexhose, etc.)are made up ready to go. • Verify that wiper plugs are loaded in cementing plug assembly. • Drift casing prior to run. • Assure extra hoses are available for water and mud. Cement the casino as follows: Bump the plug with 500 psi over circulating pressure. Immediately prior to shutting the pumps down record and report the pump pressure ON A RATE/TIME/PRESSURE basis +5-10 minutes. Hold pressure for 5 minutes. Release the pressure and confirm the floats are holding. Do not over displace by more than half of the shoe volume. Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Spacer: 40 BBL 10.0 ppg Seal bond Spacer Drop bottom plug Lead: 264 sx Class"G"+Additives Excess 50% Over calculated volume or 20%over caliper volume Tail: 300 sx Class"G"+Additives Excess 50% Over calculated volume or 20%over caliper volume Drop top plug Displacement Spacer: 5 BBL Fresh water to drop Top Rubber Plug Displacement Mud: 400 BBL Fresh Water or KCL Brine. Estimated Top Lead 5,500' of Cement Tail 8,055' PROPERTIES LEAD TAIL Weight 12.7 13.8 ppg Yield 2.18 1.85 Water 11.84 9.31 Pump time 4-5 hrs 4-5 hrs Water loss <50 <50 Free water 0 0 Comp. Strength 8 hours 100 —500 24 hours 524 1034 48 hours 1011 1772 Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. 2. After cementing, record the following: • Time cement in place. • Pressure used to displace. • RATE/TIME/PRESSURE after slowing down in anticipation of bumping plug. • Amount of barrels pumped behind cement. • Amount of barrels bled back to check floats. • When and if returns were lost while cementing. WELL DATA ANNULAR GEOMETRY ANNULAR I.D. DEPTH(ft) (in) MEASURED TRUE VERTICAL 16000 CASING 120 120 13 500 HOLE 3 100 2 700 SUSPENDED PIPES DIAMETER (in) WEIGHT DEPT tt) O.D. 1.0, (Iuslft) MEASURED I TRUE VERTICAL 10 750 9 950 I 45 5 I 3 100 2 700 Float/Landing Collar set @ 3.060 ft Mud Density 8 30 ppg Est Static Temp, 85 ` F Est. Circ. Temp. 82 ' F VOLUME CALCULATIONS 120 ft 0.5969 gia with, 0% excess = 71 6 1 2 040 ft x, 0.3637 dm 11b, 100% exceu = 1920.4 j 340 ft . 0.3637 with. 100% exctu = 247.3.j V 40 ft 0.5400 0% gicCtaa = 21.6 cif(insid@ pipe) TOTAL SLURRY VOLUME = 2261.0d 403 Itia WELL DATA ANNULAR GEOMETRY ANNULAR.LI), DEPTHjft) (in) MEASURED TRUE VERTICAL 9.950 CASING 0044"10) 3.100 I 2.700 8.750 HOLE ( 10,473 9.300 SUSPENDED PIPES DIAM.t;,,,.LR (in) WEIGHT QEF TH(ft) Q,D, L.D. (lbsift) MEASURED I TRUE VERTICAL 7.000 6.276 j 2,3 I 10 473 9 300 • Float/Landing Collar set Q 10,433 it Mud Density 9.00 p g Eat,Static Temp., 157 °F Est.Circ. Temp. 124 °F VOLUME CALCULATIONS 2,555 f1, x, 0.1503 WI with 50% excess = 576.2 cf 2,41811, a, 0.1503 cial witb, 50% excess = 545.2 s 40 I, x, 0.2148 S with, 0% excess = 8.6 d( 1 pipe) TOTAL SLURRY VOLUME = 1130.0 s 201 kk --� 150 6..,.. Ul C.4 . A ARMSTRONG CnnA hde/.LLC DRILLING OPERATIONS SUMMARY North Fork 23-25 Start Depth Seat Depth Casing Interval Hole Size MD TVD MD TVD Size Wt(1,_b/ft) Grade Conn Burst Collapse Tension* Drivel Structural Driven 0 0 120 120 16 (0.5i" x56 Welded N/A N/A N/A NO Conductor Surface 13.5 0 0 3100 2700 10.75 45.5 N/L 80 BTC 4230 2470 845 Intm/Prod 8.75 0 0 10497 9300 7 26 N/L 80 BTC-M 7240 5410 604 =minimum of body and connection strengths Note 1: AOGCC MUST be notified approximately 48 hrs prior to the rig being ready for inspection to comply with the "AOGCC Ring Inspections Focus 11-19-10". Note 2: AOGCC MUST be notified 24 hrs prior to each diverter function and BOPe test. Conductor: 1. Drill/Drive 16" conductor to +/- 120ft. RKB. RD conductor rig. 2. MIRU Nabors Rig 99. 3. Install starting head 16" SLC x 21 'A", 2M flange. 4. Nipple up 21 '/4", 2M diverter, 16" diverter valve and 16" diverter line. 5. Function test diverter and diverter valve. (AOGCC 24 hr notice) 6. Build spud mud. 7. Install mud logging. 8. Inspect bha equipment. Surface: 1. PU 4" drill pipe, bit and DIRECTIONAL BHA per bit/directional proposal. Set up WEEKLY STATUS Report for the Commission. 2. Drill w/ low rpm, gpm until stabilizers have exited drive pipe. Run max gpm, rotary, etc as allowed. 3. Continue to directionally drill a 13 '/2' hole to ±3100' MD/2700' TVD short tripping and 'I pumping sweeps as considered necessary. At hole section TD, pump a HIGH VIS sweep and circulate the hole clean. 4. Short trip. Circulate hole clean. Repeat. 5. Condition mud to lower YP and gels. Monitor pill lag and mud log lag times to aid in adjusting cement volumes for hole washout. 6. Prep for excess mud, cement, rinse water, etc disposal. 7. Calculate landing equipment to have proper space out with top of landing jt ±4-6' above rotary. Run 10 3/" surface casing as follows Baker-Locking the shoe track: a) Shoe b) Sting-in collar — C'r� w/ r:lcpr�. c) Casing With centralizers placed as follows: d) 2 bow-springs with stop collars in center of bottom 2 jts e) Centralizers across the bottom 2 couplings f) 1 centralizer across the coupling of every third jt g) NO CENTRALIZER INSIDE CONDUCTOR AS CASING NEEDS TO BE CENTERED IN ROTARY h) ESTIMATED TOTAL centralizers=±35 w/2 stop collars 8. Perform a running tag. Reciprocate casing. Circulate and condition mud at a rate not to exceed the AV around the collars while drilling. 9. RU cementing head and lines. Test to 500/5000psi. Cement 10 3/" casing PER cementing proposal with an inner string, cut off cementing when cement reaches c,ic surface, dump 2-5 bbls on top of sting-in collar. Circulate clean. Cement volumes are presently designed with 100% excess. Adjust as necessary to allow for cement returns to surface. 10. ND Diverter. Cut off 10 3/" casing. Prep to install mud loggers per logging program. Instruct same re dry ditch samples for AOGCC. 11. Install 10 3/4' slip lock connection X 11" 5M flanged multibowl wellhead. Test to 50%of casing collapse or 1600 psi whichever is greater. 12. NU adapter spool. NU 13 5/8" 5M BOPs. Test BOPs and choke manifold to 300/4000 60 P psi, hydril to 300/2500 psi. (AOGCC 24 hr notice) le sl' If AOGCC approves, casing may be tested here while testing BOPe. That is, pull test plug and perform casing test under the blinds. Test casing to 3000 psi. NOTE: If AOGCC does not approve of casing test under blinds then test before drilling out float equipment. NOTE: (BOPe MUST be tested every 7 days during the remainder of the well. AOGCC must be notified at least 24 hours before) NOTE: Maintain good communications with regulatory. Communicate with 061- the inspector every couple of days just to let them know what is going on. 7 13. Set wear bushing. Run CBL. su.,fciC_ Ccs' Production: ✓ 1. PU 8 3/4" PDC bit and directional BHA w/ LWD. Drill out float equipment and at least 20' of new formation. Circulate hole clean. 2. Contact AOGCC. Test shoe to LEAK OFF on a chart. Email results. Estimated Leak Off EMW is 16.5 ppg emw. If test is less, discuss with office. A minimum of 13.5 is acceptable. 3. Drill ahead per directional plan. 4. Continue to directionally drill to ±9300'TVD / 10497' MD as per program, short tripping and pumping HIGH VIS sweeps as required. MINIMUM flow rate should be 500gpm. Higher if possible. 5. At hole section TD, pump a HIGH VIS sweep and circulate the hole clean. Make wiper trip. Again pump a sweep and circulate hole clean. Make sure pump is at MAX rate. Hole will require more than just circulating bottoms up. POOH. 6. TIH. Condition hole as before. Condition mud to lower YP and gels. Monitor pill lag and mud log lag times to aid in adjusting cement volumes for hole washout and compare to log value (LWD). 7. TOOH. Pull wear bushing. Install test plug. Close blind rams. 8. Change out pipe ram with 7" casing rams in upper rm. Run test joint and test casing ram to 250G3603-psi. .4„ 7•jo.a- goov f5.: 9. Calculate space out and prep as per previous. Run casing as follows Baker-Locking the shoe track: Ensun,.„ X- J1 ros v ' - c,„ iq V a) Shoe b) 2 jts casing ./4.. z�� c) Collar d) casing With centralizers placed as follows: e) 3 bow-springs with stop collars in the centers of bottom 3 jts f) Centralizers across the bottom 3 couplings g) 1 centralizer across the coupling of every third jt for the next ±3600' casing (±30) but will be adjusted across potentially productive zones h) 1 centralizer across the coupling of every third jt to±5000' (±15) i) ESTIMATED TOTAL centralizers= 41 w/3 stop collars 10. Run and cement 7" casing per cementing procedure while rotating and/or reciprocating. Land hanger. Cement volumes are presently designed for±5500' of fill (TOC ±5000'MD) with 40% excess. Adjust as necessary to insure top of cement to +-5000'. 11. Back out landing joint. Install packoff and test to 5000 psi. Change out casing rams ✓ with pipe rams. Run test plug and test BOPs to 300/4000 psi, hydril to 300/2500 psi. (AOGCC 24 hr notice) If AOGCC approves, casing may be tested here while testing BOPe. 12. Set wear bushing. 13. Clean out and test casing to 4000 psi adjusted for mud wt in use at test. POOH. ( 0.0 14. Run CBL. n` Well Test/Completion: 1. Detailed Procedure will be provided with a completion/well test sundry. N P) 2. Rig down and move out drilling rig. 616) GE GE OiI & Gas I• 47.7" 0 LO )) lmn I I POW 0 30_2 O i O' 2-9/16"5M - O IS•: V101 2-9/16"5M -f plit , 1 ar ir.m) , ) . ( 7 JI 11.4" Aft 2-9/16"5M 7.1_ 2-9/16"5M O I� f I 458" efr. 2-9/16"5M o 123.5" \ O --All MIMI I/ 11"5M 171 r . i _ uVv - l� 1 ❑ i v-----� 28.5'tof L 19.0" C ih, - ''' ". i Aq 719,A ' C a r ar !Y�■• i 1 5M ' J'— _, v 1-13/16"10M I1 run _ 4 L1..13 III 25.1"tot. 4. A. 28.0" el. T 141 �Ii 17>'41 1- 4I41 Ic -110 2-1/16"5M 24"O.D.Base Plate 10-3/4"Casing _ 7-"518"Casing .7,1 r' S,•-,). 2.7/8"Tubing — 1/4"Control Line This drawing is the property of GE Oil&Gas Pressure Control LP and is considered confidential.Unless otherwise approved in writing, BUCCANEER ALASKA neither it nor its contents may be used,copied,transmitted or reproduced except for the sole purpose of GE Oil&Gas Pressure Control LP. ARMSTRONG COOK INLET 10-3/4" x 7-5/8" x 2-7/8" 5M SH2/LRC2 Wellhead Assembly DRAWN VJK 24MAY12 APPRV KN 24MAY12 With T-M40-CCL Tubing Hanger and M40-CCLAdapter Flange FOR REFERENCE ONLY DRAWING NO. AE21797-B 0 I' II II mo Hi OMNI z — a — COm ,o. — •oC]oE i --0.. viiia I nri ;RI C C W O a ^o Cod 0IC C- --- - -- W N y ♦ r " E 7 E I C O � o 0 0 11 Z C..0 �oC�oC� la, cn r . 1-7- Tivr-7 y my r 3,41 _t . °° "< vC1n x 0 ' O I.. 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OAD ``,NN\\\,1 I \ NORTH FO_ Rf - ---- - -- ' -s -._OF A�,�S,�t 4O �— 00 RAN Y N 2121143.9950 s (7..' �' .-5J �, CP-1 E 1340068 0700 * .49 TH A -. N 2121137.2190 ELEV 666 OTOw 1 • E 133s7oa.stoo EDGE OF R.O.W• __ \ /�� 00 0 �� ELEV 656,§,x_ • - --- ., x/ her OHE ------ a°/4F— 660 oHE I c2,-. STAN A. McLANE : .e ... 4,:r,. ,:' ; 653655 POST METER ��PANELPOST J' �, ,r,, 4637-5 .. �1 s % bS5 6 0 m4 FFD'•../19/12-.•' y, 4� " m - �p�/ X X — — /i r ''FESS I ON►� `� copiex 6 °, a m q, �'� �51 Tract'I,18 6�9 GATE' ° X( II' c so1 ° I I 34-26 WELL 32-35 WELL 14-25 WELL 1481' __ __-- ,---a— (70'N . DRILLING PAD NFU 23-25 WELL X N:2120944.7801-LI E:1339956.180 m LATITUDE: 59°47'44.754"N i LONGITUDE: -151°37'53.244"W • NAD83 ASP ZONE 4 ELEV. 658.9'NAVD88 C, 0 i HE— W Tract 19 3. J 0 I North Fork Acres Subd. No. 2 �� ( o f 8'CHAINLINKFENCE ico 2 X X X 6S2SSS 4,6o — I n0 O (; 66p `\ 665 b, — —- CJ \ b TOP OF BERN U111 --___\NT-- .._ . 1 i„ \ 03 ---66 j._____________, LLL 1.1 I ��66U N 2120261.15 Section 26,TO4S,R14W,S.M.,AK. _ ! — E• 1341421.67 I S26 S25 S35 S36 c NOTES 1-BASIS OF HORIZONTAL COORDINATES ARE ALASKA STATE PLANE NAD 83 ZONE 4 EPOCH 2003 DETERMINED BY AN NGS OPUS SOLUTION FROM CORS N OR T H BASE STATIONS"KENS",-TSEA"AND"KOD5"OBSERVED DEC.13,20070N NF1 3 112"ALUM.CAP SET N:2121137.137 E.1339704.633 ELEV.656.69 '4III1I II 2)BASIS OF ELEVATION IS NGS BENCHMARK N86 TT0195 ELEV 18084 FT NAVD88 DATUM. 0 SCALE 3)SOUTHEAST CORNER SEC.26 COORDINATES DETERMINED FROM DIRECT 100200 1 ) I I SURVEY TIE TO THE TO EXISTING BLM SECTION CORNER TIE PER HM91-57 FEET AND NOT THE PROTRACTED SECTION CORNER VALUES. \ / PROJECT REV[SKIN 1 ARMSTRONG COOK INLET, LLC NORTH FORK 23-25 WELL °ATE 6/1912 700 17TH STREET DENVER,CO802021 AS-STAKED SURFACE LOCATION DIAGRAM 40) DRAWN BY B� SCALE 1'=109 NAD83 PROJECT NO 12023 ENGINEERING I MAPPING I SURVEYING I TESTING SOON NO • /, Consult-Icy Inc P 0 BOX 46e SOL°OTNA AK 99569 LOCATION \-�.(#��R•�i}!Aj VOICE (9071203-4219 FAX F9071273.3265 SW 1/4 SE 1/4 SHLET EMAIL SAMCIANE@MCLMSECG COM S26 T4S R14W SEWARD MERIDIAN, ALASKA 1 OF 1 co ` EDGE OF R.O.W. ```NA\\lk%11 NORTH FORK RSA` — .:� �� OF.A4 II1�� _ _— ��J��- CP-2 P J (O — ---� ----lob' RAN N 2121143.9960 = \i •� ,I CP-1 l oO EE LEV 666.07 ow * 49 TH A 1 *,0 • N2121137.2190Of E 13397046100 EDGE OF R.O.V11 /J/�/�'I'.'/ ELEV6566g, - - > '� �l/� / �- ,4, g OHE a BHE 66p oHE j m -•.STAN A. McLANE :1 f• b55_�C.METER ��PANEi POrs ----_�.� ct • ,717:— �; 653 POST —660 ,I o, 4637—S 4'— .�/i f.55 x �� ; I,RI IF�Pe6•-•.5/16/12..•••' �� X I1 ESSIONA(-L �. 1. P �`- 1 56 CONEX f 1 11%%NAN,� 1/;;' 6 Cra, N m .,1 Tract 18 6S I (c. 9 GATE , , \ I • / m I ! 34-26 WELL 32-35WELL 14-25WELL • -- 1-1 481 –�` ci co x 1 ' f DRILLING PAD NFU 23-25 WELL x N:2121189.62 : , –1 E:199930.76 1.11 LATITUDE: 59°47'46.9566"N I' cl(,a LONGITUDE: -151°37'45.4764"W • NAD27 ASP ZONE 4 • '' ELEV. 658.9' NAVD88 ,►� HE--- LM Tract 19 o J 1. North Fork Acres Subd. No. 2 �� I o 0 8'CHAINLINK FENCE Z x — - x — x Ell x Q i 652 65c % --�_ • 2 Q v �cn �f�; 0 665 0 6 ,` 6 \ b� TOP OF BER IV 49 CO 66S I II 1 '_� 66U ._ ___ 1 I LLQ l N 2120261.15 Section 26,T04S,R14W,S.M.,AK. — — — — E 1341421.67 S26 S25 S35 S36 r NOTES E I I BASIS OF HORIZONTAL COORDINATES ARE ALASKA STATE PLANE NAD 83 ZONE 4 EPOCH 2003 DETERMINED BY AN NGS OPUS SOLUTION FROM CORS NORTH BASE STATIONS"KEN5","TSEA"AND"KODS"OBSERVED DEC.13.2007 ON NF1 3 1/2"ALUM.CAP SET N 2121137.137 E:1339704 533 ELEV 656.69' • '1111111':11111111' 2)BASIS OF ELEVATION IS NGS BENCHMARK N86 TT0195 ELEV 18084 FT NAVD88 DATUM. SCALE 3)SOUTHEAST CORNER SEC.26 COORDINATES DETERMINED FROM DIRECT 0 100 200 SURVEY TIE TO THE TO EXISTING ELM SECTION CORNER TIE PER HM9157 1 I FEET AND NOT THE PROTRACTED SECTION CORNER VALUES ) PROJECT REVISION 1 ARMSTRONG COOK INLET, LLC NORTH FORK 23-25 WELL DATE 6,19(12 70017TH STREET#1400 AS-STAKED SURFACE LOCATION DIAGRAM DRAWN BY. 808 DENVER,CO 80202 NAD27 FOR INFORMATIONAL PURPOSES SCALE 1-1W' ONLY PROJECT NO 123023 ENGINEERING f MAPPING I SURVEYING(TESTING BOOK NO - ConsuEEirg Inc P 0 BOX 468 SOIDOTNA AK 99669 LOCAT ICN Mci.ANC VOICE 1967,263.216 FAX (9071263-3265 SW 1/4 SE 1/4 SHEET EMAIL SAMCLANE@MCLANECGCOM S26 T4S R14W SEWARD MERIDIAN, ALASKA of 1 Exception Plats (Previously applied for exception) CD J R ,..!1 M17 CD ;h^, Y u • m' c c 1etIiiipwP UVw - ''. 41„421 0 Q N M 8 r J C a N CO X to o� • a. N • M O N \ M M n co a CO NW \in a ..Z OI Z ^4'4� 0.1 �..... "13 Q < 7 M N LL J Z ain� r- in M M N, 1871' <1'.p. 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I E On-• --'Q) - 0 v,01 00 0 0 01 0 o C(n zC") zCo\o ;z2 09. rr� r �0 n,w t �r''aw -ni�Ui O— -C) CJI =-- C) z a C) z s: ` f0, - ------.:77 4 A 0o of . . m � G � _r i 33 �l3 „ rU I_ -0_ _I moves '0 � Z II a o O o i R1 1 AZZr. w `/ \/ w RI Cti r��r/ _ � If I l' H = ME" 8 p !_ `4111 A — Pr Armstrong Cook Inlet, LLC BALKERLocation: Cook Inlet,Alaska(Kenai Peninsula) Slot: North Fork#23-25 Fi : NFU#23-25 HUGHESARMSTRONG Facility: North Fork Unit(NAD27) Wellborld: North Fork e: NFU#23-25 Oil&Gas.Inc Plot reference wellpath is NFU#23-25 Version#3 True vertical depths are referenced to Nabors 99(RTE) Grid System:NAD27/TM Alaska SP,Zone 4(5004),US feet Measured depths are referenced to Nabors 99(RTE) North Reference:True north Nabors 99(RTE)to Mean Sea Level:682.83 feet Scale:True distance Mean Sea Level to Mud line(At Slot:North Fork#23-25):0 feet Depths are in feet Coordinates are in feet referenced to Slot Created by:jonethoh on 11-Jul-12 Traveling Cylinder: Map North All depths are Measured Depths on Reference Wellpath 0' 330• 30• 100/1 12011 300' 60' OM 4011 2702 / i. .•, • .•, �. 4On Al Boa rport 6 z 120' i j reorc / reek ��. 210• 150' Y. aFJ;J 100... 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Q W H W I M } ~Z zaW w r~ 20 <OJ•Z Q I i'' W J x2 XJ m D' wa uh mcgLLE�� 9 W a W / S.9 Ow aRp Y OJ O U w ❑ m m a Q U w O � 99 Page 1 of 3 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, July 10, 2012 4:15 PM To: 'Stephen F. Hennigan' Cc: 'Edward Teng'; Davies, Stephen F (DOA) Subject: RE: North Fork 23-25 (PTD 212-091) Got it... thanks. Just send me the diverter sketch as soon as you can. Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Stephen F. Hennigan [mailto:shennigan@peiinc.com] Sent: Tuesday, July 10, 2012 3:57 PM To: Schwartz, Guy L(DOA) Cc: 'Edward Teng'; Davies, Stephen F(DOA) Subject: RE: North Fork 23-25 (PTD 212-091) Guy See responses below. Tlk s, a,€,, �s .el 0 u of Aeo• Project Manager/Engineer 500 Dover Boulevard, Suite 310 ( Lafayette, LA 70503 w: 337-984-2603 a: 337-849-5345 x Description: Description: Description: Description:pei_logo-OUTLOOK Hamilton Confidentiality Notice: The information transmitted is intended only for the person(s) or entity to which it is addressed. It may contain confidential and/or privileged information or material. Any review, retransmission, dissemination to other use of, or taking of any action in reliance upon this information by persons or entities other than the intended recipient is prohibited. If you received this in error, please contact the sender and delete the material from any computer. From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent:Tuesday, July 10, 2012 6:02 PM To: Stephen Hennigan Cc: Edward Teng; Davies, Stephen F (DOA) 7/10/2012 Page 2 of 3 Subject: North Fork 23-25 (PTD 212-091) Steve, Couple of comments on the PTD... 1) Need expected formation tops and depths. ESTIMATED HORIZONS MD ND Sterling 0 0 Beluga 1450 1411 Tyonek 6039 4953 Ty 4900* 6190 5083 Ty 5600* 6929 5764 Tyonek Red 7233 6062 Ty 6000* 7339 6167 North Fault 7450 6277 Ty 6800* 7661 6488 Ty 7200* 8064 6891 Ty 7800* 8672 7499 Ty 8000* 8784 7611 Ty 8100* 8892 7719 Tyonek Blue 9152 7979 Ty 8500* 9267 8093 Ty 9200* 10079 8906 TD 10473 9300 2) Diverter line sketch layout on the drilling pad. We have already discussed this and will get the sketch finished. We are diverting away from the wells. Will get the sketch to you tomorrow/Thurs 3) On production section procedure (step#8) the 7" rams need to be tested to 4000 psi (instead of 3000 psi) - changed 4) Please clarify your MASP and Max pore pressure shown on box 17 of the 401 application. (On Page 10 of your application the calculations indicate a MASP of 3422 psi and a max pore pressure of 4352 psi using 9 ppg EMW and TVD of 9300 ft) I emailed you about this earlier—it is 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 4352 Surface: 3422 5) What will be your Ram configuration for the first BOP test? (VBR range or pipe ram sizes for each ram body) The chart you gave doesn't list this. BOP sketch with sizes is attached Regards, 7/10/2012 . Page 3 of 3 • Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) 7/10/2012 Page 1 of 1 Schwartz, Guy L (DOA) From: Colby VanDenburg [colby@armstrongoilandgas.com] Sent: Tuesday, July 10, 2012 2:14 PM To: Schwartz, Guy L (DOA); Davies, Stephen F (DOA) Cc: Edward Teng Subject: Armstrong North Fork Unit 23-25 Steve, We have discussed the well classification for this year's drilling program at North Fork,and we're comfortable with the designation of'Development Well'for the NFU 23-25. Please let me know if we need to make changes to the APD or if you can handle it internally. We will make sure to stay consistent with any subsequent APD filings. Sorry for the confusion. Colby VanDenburg Geologist Armstrong Oil and Gas 1421 Blake Street Denver, CO 80202 (303) 623-1821 7/10/2012 Page 1 of 1 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, July 10, 2012 1:40 PM To: 'Edward Teng' Cc: Davies, Stephen F (DOA) Subject: RE: APD for Armstrong North Fork Unit#23-25 Ed, I am reviewing the PTD application today... will give you an assessment tomorrow on any issues I see. Also, as we discussed please forward a discussion on the exploration status request for this well to Steve and myself. Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Edward Teng [mailto:edteng@armstrongoilandgas.com] Sent: Tuesday, July 10, 2012 1:17 PM To: Schwartz, Guy L (DOA) Subject: APD for Armstrong North Fork Unit #23-25 Hello Guy: It was nice talking with you a while ago. Per our conversation, I understood that you have received our NFU#23-25 APD package and you do not expect any issues and estimated that we should have the APD in a couple of weeks. We need this estimation in order to finalize the rig contract and construct our time table for the drilling operation. It will be greatly appreciated if you would please reply to my email as to if my understanding is correct. We will be filing the second well NF#22-35 in a couple of days. Thank you and best regards, Ed Teng VP- Engineering Armstrong Cook Inlet, LLC 1421 Blake Street Denver, CO 80202 (303)-623-1821 Ph (303)-623-3019 Fax (303)-981-9957 Cell 7/10/2012 OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. TRANSMITTAL LETTER CHECKLIST WELL NAME a/c/ 2� PTD# 2— r Development Service Exploratory Strati ra hic Test g P Non-Conventional Well FIELD: / a -7/ POOL: �c7✓'/K �'7 (.._ gc/e7 �C ---- Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in Permit No. , API No. 50- - - API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approv .�__ . -ct to full compliance with 20 AAC EXCEPTION 25.055. Approva o •roduc- /in'ect is contingent upon issuance of a conservation : .-r approving a spacing exception. Yi4L ':/eassumes the liability of any protest to !'f spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev:9/09/2011 0 0 a O (n 'Ok (r 30 w o m pCO • n. N 0) N co N 0) 0 O ?3 N O N O lD Oo 0 •• N N N �-I co co co W CO CO Ca (a CO CO N.) N N N N.) N.) 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To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. North Fork Unit #23-25 North Fork Unit #23-25 Kenai Borough, Alaska September 15 to October 9, 2012 Provided by: Approved by: Colby VanDenburg Compiled by: James Foradas Tollef Winslow Eric Andrews Dylan Muller Distribution Date: November 15, 2012 T.D. Date: October 21, 2012 North Fork Unit #23-25 2 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT & CREW................................................................................................3 1.1 Equipment Summary......................................................................................................................3 1.2 Crew................................................................................................................................................3 2 GENERAL WELL DETAILS...................................................................................................................4 2.1 Well Objectives...............................................................................................................................4 2.2 Well Resume ..................................................................................................................................4 2.3 Hole Data........................................................................................................................................5 3 GEOLOGICAL DATA.............................................................................................................................6 3.1 Formation Tops...............................................................................................................................6 3.2 Lithology Review.............................................................................................................................7 3.2.1 STERLING FORMATION........................................................................................................7 3.2.2 BELUGA FORMATION ...........................................................................................................9 3.2.3 TYONEK FORMATION.........................................................................................................10 3.3 Sampling Program/Sample Description........................................................................................12 4 DRILLING DATA..................................................................................................................................13 4.1 Daily Activity Summary.................................................................................................................13 4.2 Surveys.........................................................................................................................................18 4.3 Bit Record.....................................................................................................................................21 4.4 Mud Record ..................................................................................................................................22 4.5 Drilling Progress Chart..................................................................................................................24 5 DAILY REPORTS ................................................................................................................................25 Enclosures 2”/100’ Formation Log (MD/TVD) 2”/100’ LWD Combo Log (MD/TVD) 2”/100’ Gas Ratio Log (MD/TVD) 2”/100’ Drilling Dynamics Log (MD/TVD) Final Data CD North Fork Unit #23-25 3 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type / Position Total Downtime Comments Computer – Drill Floor Monitor Azonix 0 Computer – Pit Monitor Azonix 0 Computer for Company Man Rigwatch Remote (HP Compaq) 0 Computer for Tool Pusher Rigwatch Remote (HP Compaq) 0 Computers for Mudloggers (2) Mudlogging, Rigwatch Master, and Rigwatch Remote (all HP Compaq) 0 Ditch gas QGM gas trap (mounted in possum belly) and flame ionization total gas & chromatography. 0 Hook Load / Weight on bit Drilling Line Sensor on Dead Man 0 Mud Flow In (derived from pump output and rate) 0 Mud Flow Out Flow line sensor 0 Pit Volumes, Pit Gain/Loss Float sensors 0 Pump Pressure Standpipe transducer 0 Pump Stroke Counters (2) Digital micro switches 0 Rate of Penetration (derived from block height) 0 RPM feed from Canrig top drive 0 Torque feed from Canrig top drive 0 1.2 Crew Mud Logging Unit Type: Arctic Mud Logging Unit Number: ML057 Logging Geologists Years *1 Days *2 Sample Catchers Days Technician Days James Foradas 5 35 Dickey Hudgins 3 Steve Forrest 3 Tollef Winslow 4 35 Howard Lamp 6 Dylan Muller 2 43 Eric Andrews 1 47 *1 Years experience as Mudlogger *2 Days at wellsite between rig up and rig down of logging unit. North Fork Unit #23-25 4 2 GENERAL WELL DETAILS 2.1 Well Objectives The objective of NORTH FORK UNIT #32-35 is to drill and log a combination gas and oil exploratory well in the North Fork Unit, with a minimum of hole problems or other concerns. 2.2 Well Resume Operator: Armstrong Oil and Gas, Inc. Well Name: NFU 23-25 Field: North Fork Unit County: Kenai Peninsula Borough State: Alaska Company Representatives: Larry Driskill, Al Lunda, Jim Brown Location: Surface Coordinates 647.54’ FSL -1482.78’ FEL, Sec 26 T4S R14W SM X=1999929.76, Y=2121189.58 Rotary Table Elevation 662.28’ AMSL Classification: Exploratory API #: 50-231-20037-00-00 Permit #: 212-091 Activity Code: AFE # ACILLC 0503 2012 Rig Name / Type: Nabors Alaska 99E / Arctic Triple Spud Date September 15, 2012 Total Depth Date: October 9, 2012 Total Depth 10785’ Primary Targets Tyonek Primary Target Depths Multiple, Unknown Discovery Zones Total Depth Formation: Tyonek Completion Status: 7” OD 6.28” ID casing set at 10,715’ LWD-MWD Services. Baker Hughes Inteq Directional Drilling Baker Hughes Inteq Wireline Logging Services None Drilling Fluids Service MI Swaco Logging Geologists: James Foradas, Tollef Winslow, Dylan Muller, Eric Andrews Sample Catchers: Dickey Hudgins North Fork Unit #23-25 5 2.3 Hole Data Maximum Depth Shoe Depth Hole Section MD (ft) TVD (ft) TD Form. Mud Weight (ppg) Dev. (o inc) Casing (dia ”) MD (ft) TVD (ft) LOT (ppg) Conductor 120’ 120’ N/A N/A N/A 16 120’ 120’ NA 13½” 3102’ 2703’ Beluga 10.15 39.91 10¾ 3102’ 2703’ 9 ” 3122’ 2718’ Beluga 9.5 39.91 N/A N/A N/A 15.4 8¾” 10785’ 9621’ Tyonek 9.6 1.63 6.28 10715’ 9261’ N/A North Fork Unit #23-25 6 3 GEOLOGICAL DATA 3.1 Formation Tops Prognosed Depth (ft) Actual Depth (ft) Zone or Horizon MD TVD TVD SS MD TVD TVD SS 13½" Surface Borehole: Sterling 0 0 Surface Surface Surface Surface First Gas 709 709 -30 796 794 -115 Beluga 1450 1411 -732 1457 1414 -735 8¾" Production Borehole: Tyonek 6039 4953 -4274 6078 4996 -4317 Ty 4900 6190 5083 -4404 6244 5137 -4458 Ty 5600 6929 5764 -5085 7012 5855 -5176 Tyonek Red 7233 6062 -5383 7328 6166 -5487 Ty 6000 7339 6167 -5488 Faulted North Fault 7450 6277 -5598 7426 6263 -5584 Ty 6800 7661 6488 -5809 7803 6640 -5961 Ty 7200 8064 6891 -6212 8223 7059 -6380 Ty 7800 8672 7499 -6820 8828 7664 -6985 Ty 8000 8784 7611 -6932 8931 7767 -7088 Ty 8100 8892 7719 -7040 9030 7866 -7187 Tyonek Blue 9152 7979 -7300 9280 8116 -7437 Ty 8500 9267 8093 -7414 9397 8234 -7555 Ty 9200 10079 8906 -8227 10137 8973 -8294 TD 10473 9300 -8621 10785 9621 -8942 Horizons, Zones, and Depths provided by the Armstrong Geologist. North Fork Unit #23-25 7 3.2 Lithology Review 3.2.1 STERLING FORMATION (0' MD /O’ TVDSS to 1457’ MD /-735 TVDSS) Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 347.62 0.00 102.41 49.22 0.00 6.75 Gas Peaks Depth(MD) TG C1 C2 C3 iC4 nC4 iC5 nC5 1164 42 15322 137 25 1466 163 36496 654 23 1518 140 420 56 97 Gas is generally low in the Sterling formation, with the first gas in the Sterling predicted at 709’ MD. By 787’ MD background gas had risen above 1 unit (200ppm). Generally background gas remained low throughout the interval averaging 11.3 units with mud weights between 8.7 at spud and 9.3 ppg at the top of the underlying Beluga. However, a strong gas show was detected in sandstone between 1460 and 1540’ MD. This show with peaks in the range of 140 to 160 units is apparently associated with methane migration from coal beds in the basal Sterling formation just above the top of the underlying Beluga contact. This show is summarized in a separate Show Report (#1) appended to this document. For the purposes of this report the formations in surface hole are described as a whole. The rocks in this interval are composed of claystone, siltstone, tuffaceous siltstone, coal, carbonaceous shales, unconsolidated sands, sandstone, and tuffaceous sandstone. Claystone is present higher in the interval and often intergrades with siltstones. One such intergrade was described at 690' - 820' MD. This claystone/siltstone intergrade was described as medium gray to medium dark gray in color; with clumpy and slightly gelatinous consistency; malleable and slightly elastic tenacity; irregular to earthy fracture; massive cuttings habit; earthy luster, with individual grains ranging from metallic to dull/earthy luster. Granular to silty texture; massive structure, and abundant imbedded sand grains common. Generally, claystone is present in the Sterling in this well only as a minor component of more abundant siltstone. As a result, clay and claystone in the Sterling was more commonly described as a component of siltstone samples described below. Siltstone (including coarse claystone, and tuffaceous siltstone) is present throughout the interval in varying quantities. These rocks are often difficult to differentiate due to difficulties in resolving such fine grains macroscopically at 30x magnification or less. In several areas the siltstone intergrades with finer clays and claystone and is described as clay/siltstone or as above as claystone/siltstone. One example of a typical clay-silt intergrade is a clay/siltstone stone sample obtained high in the interval between 210' and 240' MD. It was medium dark gray in color; soft with pulverulent tenacity. It exhibited irregular blocky fracture; massive cuttings habit; earthy luster; silty texture; and massive structure. As typical of most siltstone in this interval it was interbedded with sand, thin sandstone and coal. North Fork Unit #23-25 8 A more typical siltstone from this interval is described in a sample from 1310' - 1350' MD. It was medium gray in color; soft; poorly indurated and pulverulent to malleable; and exhibited irregular and earthy fracturing; massive cuttings habit; earthy and slightly resinous luster; gritty texture; and massive Structure. It is interbedded with abundant subangular lower fine to lower medium sand composed of 70% quartz, and coal. Tuffaceous siltstone was described in the Sterling in several places in this well. The best examples of tuffaceous siltstone were described in samples from 1250' to 1310' MD. The tuffaceous siltstone grades to claystone and was medium gray to medium dark gray in color; clumpy and gelatinous; very soft; poorly indurated; malleable and sectile; with irregular fracture; massive cuttings habit; earthy and occasionally greasy luster; gritty to silty texture; and massive structure. Abundant cuttings from interbedded lignitic coal and carbonaceous shale, and grains from interbedded unconsolidated sand were also present in the sample. Sands in this section are common, and generally appear as thin stringers in other rocks, but may also represent easily friable grain supported sandstones (see below). A sand sampled between 510' - 570' was medium to light gray with buff hues in color, and upper medium to coarse grained. Grains exhibited low sphericity, ranged from angular to subrounded and were moderate to well sorted. The sands were composed predominantly of (80%) clear, translucent, white and gray quartz, but also contained common red and dark gray igneous rock, glauconite and clay mineral grains along with grains composed of fragments of buff to tan colored older coarse sandstones. Impact abrasions, grinding and polishing are common surface features in this sand. There were no hydrocarbon indicators in the sands of the Sterling formation. Sandstone cuttings appear rarely in this section, and only toward the bottom. A sandstone sampled at approximately 1460' - 1530' was medium gray to grayish black; upper very fine to lower medium grained, and moderately to well sorted. Clasts are subrounded to subangular; spherical with some subprismoidal and moderately well sorted. Rocks are mostly unconsolidated with some moderately sorted friable rocks; and grain supported. Sandstones are grain supported; texturally submature, compositionally very mature; interbedded lignitic coal and carbonaceous shale there were no hydrocarbon indicators in these rocks bu. These sandstones are interbedded with thin coals and carbonaceous shale. Textural and compositional maturity increased with depth. In the basal section of the Sterling formation there was a gas show (see also Show Report #1, appended). All rocks in this interval were also non- calcareous. North Fork Unit #23-25 9 3.2.2 BELUGA FORMATION (1457' MD /-735’ TVDSS to 6078’ MD /-4317’ TVDSS) Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 410.67 0.00 99.88 271.00 0.00 52.08 Gas Peaks Depth(MD) TG C1 C2 C3 iC4 nC4 iC5 nC5 1488 121 36307 585 9 2141 171 47608 965 23 15 2569 271 40448 645 29 3387 181 24120 367 3869 143 33004 497 4386 148 40069 832 16 4777 208 27498 730 18 5674 124 25376 360 48 Gas is generally low to moderate in the Beluga formation. Generally background gas remained low throughout the interval averaging 51.6 units with mud weights between 9.3 and 10.6 ppg and varied throughout the drilling of the Beluga. Chromatography detected primarily methane (C1) and ethane (C2), with traces of propane (C3) associated with these peaks. Subsequent review of traces of butane and pentane recorded on the log were attributed to noise caused by oil-based mud additives (e.g. Kla-stop ®), added mainly to reduce torque. There is a general depositional cycle which progresses with depth of coals/carbonaceous shale to clay siltstone sand/sandstone. This cycle is repeated throughout the formation. Coal/carbonaceous shales are black with brownish hues; brittle; blocky to planar with some sub conchoidal fracture; coarse cuttings over shaker; platy to flaky cuttings habit; dull to resinous luster; smooth and matte textures; laminar to thin banded structure; fracture consistent with more developed coals; interbedded with sand/sandstone, siltstone, and carbonaceous shale; some gassing observed in coals. Clay was mostly light to medium gray with brownish hues; clumpy to stiff; dense to pulverulent; amorphous to blocky fracture; massive to wedgelike cuttings habit; dull luster; smooth to clayey textures; some denser specimens exhibit laminae; soft cuttings impregnated with sand; interbedded with sandstone, carbonaceous shale and thin stringers of coal. Tuffaceous siltstone and siltstone is generally medium dark gray to dark gray; soft to very soft; moderately to poorly indurated; malleable to pulverulent; earthy fracturing; massive cuttings habit; earthy and slightly sparkly luster; silty to slightly gritty texture; massive and slightly laminous structuring; interbedded lignitic coal and some interbedded sand grains. The main difference between the siltstone and tuffaceous siltstone is the tuffaceous material. Sand and sandstones are generally medium gray to dark gray; fine to very fine grains; moderate sphericity; subrounded to subangular grains; very well to well sorted; unconsolidated; texturally very mature; compositionally very mature; quartz grains transparent to translucent; some occasionally frosted; fine to coarse cuttings; texturally and compositionally mature based on texture, composition and sorting. North Fork Unit #23-25 10 3.2.3 TYONEK FORMATION (6078’ MD /-4317’ TVDSS TO 10785’ MD /-8942TVDSS ) Depth (ft MD) Drill Rate (ft/hr) Total Gas (units) Tyonek Member or Interval Top Base Maximum Minimum Average Maximum Minimum Average Tyonek Top to Ty4900 6078 6243 207.50 16.56 115.19 187.73 13.11 36.89 Ty4900 6244 7011 278.25 0.00 107.01 394.09 12.79 53.53 Ty5600 7012 7327 169.04 7.14 47.48 163.53 0.00 31.13 Tyonek Red & Ty6000 7328 7802 182.30 0.00 64.36 513.23 0.00 81.32 Ty6800 7803 8222 172.28 7.00 58.38 422.75 5.20 57.41 Ty7200 8223 8827 164.43 0.00 56.39 291.19 0.00 37.39 Ty7800 8828 8930 97.69 8.44 40.56 174.69 10.22 33.09 Ty8000 8931 9029 172.32 9.81 57.23 229.93 5.39 43.01 Ty8100 9030 9279 155.90 10.50 76.09 123.34 11.48 33.08 Tyonek Blue 9280 9396 132.21 13.24 87.48 227.61 13.48 72.09 Ty8500 9397 10136 220.40 5.36 70.61 751.44 0.00 42.72 Ty9200 to TD 10137 10785 185.45 0.00 69.77 718.27 1.07 73.51 Tyonek Top to TD 6078 10785 278.25 0.00 72.67 751.44 0.00 52.28 Gas Peaks Depth(MD) TG C1 C2 C3 iC4 nC4 iC5 nC5 6106 187 75644 1029 33 6349 394 80808 1225 7166 163 59279 1956 7737 513 42555 1536 7824 422 40360 1383 8520 291 35548 1037 8891 174 34752 763 50 181 86 8990 229 37204 886 65 9164 123 75760 2041 9388 227 44828 1587 74 10103 751 37311 1406 112 10324 718 40308 1732 157 Gas in the Tyonek formation was generally slightly higher than it was in the Beluga formation, and much higher than it was in the Sterling formation. The highest peaks occurred in the Ty850 and Ty9200 members though the interval including the Ty4900, Tyonek Red, Ty6000, North Fault, and Ty6800 all produced gas shows of over 300 units. The Tyonek formation average gas overall was 52.28 units, ranging between 31 and 81 units, with the highest in the Tyonek Red-Ty6000 interval. Many of the gas North Fork Unit #23-25 11 peaks, were attributed to coal bed methane as determined by spot samples that produced cuttings of coal many of which were offgassing. However, several gassy sandstones and tuffaceous sandstones were also detected, and are described in show reports appended to this manuscript. Chromatography at regular intervals in the Tyonek indicated that gas in this interval is dominated by the light fraction, with methane, ethane and traces of propane being common in gas chromatography samples. Heavier butane and propane were much rarer, and tests for sample fluorescence when they were detected proved negative, suggesting oil is negligible in these rocks. In addition, the traces of butane logged in some intervals correlated with periods when mud oil-water ratios were as high as 5-6 percent. This, and Pixler plots in gas show reports indicating dry gas and condensate, suggests contamination by mud additives as the likely reason for the presence of butane as opposed to natural oil. Tuffaceous sandstone was a typical gas producer in much of the Tyonek, along with methane rich coals. A typical example of the sandstone was described in the Ty8500 member between 9410' and 9530' MD. It was light olive gray to olive gray; lower very fine to lower medium; very prismoidal; angular, some subangular; grains resemble broken glass shards; easily friable to unconsolidated, occasional slightly firm; grain to matrix supported; abundant tuff, some coal flakes, sometimes almost silty very poor to sometimes poor porosity; pale orange pink, white, and translucent quartz composition; thin structure; dark banding from interbedded thin to laminar stringers of black carbonaceous shale with common pyrite laminae, and medium to dark gray shaly to gritty siltstone; compositionally and texturally mature; intergrading and interbedded with more thin siltstone, carbonaceous shale, and coal stringers beyond 9490' MD. This rock was associated with Show Report #8 and produced dry gas. For the purposes of this report the lithology of the Tyonek formation is described as a whole. The rocks in this interval are composed of sand, sandstone, siltstone, tuffaceous sandstone and siltstone, carbonaceous shale, and coal. All of these rocks are thinly bedded and frequently intergrading with varying amounts of the others immediately above and below them. Occasionally thin layers or laminae of volcanic ash that is light yellowish brown in color and exhibits waxy luster is also present. There is a general depositional cycle which progresses with depth of coals and carbonaceous shale underlain by clay, siltstone, and sand/sandstone. This cycle is repeated throughout the formation. A typical sequence follows, sometimes tuffaceous, at other times not. Coal which is black to brownish black; hard to firm; brittle to tough tenacity, pulverulent when more shaly; conchoidal and splintery fracture flaky to massive; greasy to vitreous luster, earthy for the shalier; smooth to silty texture; thick to laminae structure; mild offgassing. The tuffaceous sandstone is light to medium olive gray; lower very fine to lower medium grains; spherical; angular to subangular, occasional round; moderately sorted; easily friable to sometimes firm; tuff matrix supported; texturally submature to immature; compositionally immature; abundant coal flake inclusions and intermixed/ interbedded siltstone/tuffaceous silt. A siltstone / tuffaceous siltstone which is medium olive; very soft to moderately firm; moderate to poor induration; tough and dense to crumbly and crunchy tenacity; irregular and some planar fracturing; massive to platy, some tabular cutting habit; earthy and dull and sometimes micro-sparkling luster; silty to very gritty and granular texture, sometimes very sandy with inclusions of sand grains; massive structure; occasional veins of coal and sometimes carbonaceous shale and flakes of coal 10/10 to 1/2 mm thick cuttings are dark gray to dark brown. Tuffaceous sandstone light to medium olive gray, greenish black; lower very fine to upper fine grains; very spherical to prismoidal; well rounded to subrounded; easily friable, cuttings with higher carbonaceous content are slightly to moderately firm; tuff matrix supported; texturally moderately mature, and compositionally submature. Coal flakes are common, as are micro coal stringers 1/10-1/4 mm thick. North Fork Unit #23-25 12 3.3 Sampling Program/Sample Description SAMPLE MANIFEST : ARMSTRONG COOK INLET LLC NFU 23-25: BOXED WASHED & DRIED SAMPLES TOTAL 2 SETS of 9 BOXES Operator: Armstrong Oil and Gas, Inc. Well Name: NFU 32-35 Field: North Fork Unit County: Kenai Borough State: Alaska Company Representatives: Larry Driskill, Jim Brown, Allan Lunda Location: Surface Coordinates 647.54’ FSL, 1482.78’ FEL, Sec 26 T4S R14W SM X=1999929.76, Y=2121189.58 , Zone 4, ASBPCS Classification: Exploratory API #: 50-231-20037-00-00 Permit #: 212-091 Activity Code: AFE # ACILLC 0503 2012 Rig Name / Type: Nabors Alaska 99E / Arctic Triple Total Depth 10785’ Total Depth Formation: Tyonek Total Depth Date: October 9, 2012 Logging Geologists: James Foradas, Tollef Winslow, Dylan Muller, Eric Andrews Sample Catchers: Dickey Hudgins Set Type and Purpose Interval Frequency Distribution A Washed and Dried Reference Samples 120’ – 8910’ 8910’ – 10785’ 30’ Intervals 10’ Intervals Att: Colby VanDenburg Armstrong Oil and Gas 1421 Blake Street Denver, Colorado 80202 B Washed and Dried Reference Samples 120’ – 8910’ 8910’ – 10785’ 30’ Intervals 10’ Intervals Att: Howard Okland AOGCC 333 W. 7 th Ave., Suite 100 Anchorage, Alaska 99501 BOX INTERVALS : 120’ - 1440’; 1400’ - 3000’; 3000’ - 4980’; 4980’ - 6720’; 6720’ - 8460’; 8460’ - 9260’; 9260’ - 9850’; 9260’ – 9850’; 9850’ – 10400’; 10400’ – 10785’; (2 Sets, 18 Boxes Total, 4 bundles) North Fork Unit #23-25 13 4 DRILLING DATA 4.1 Daily Activity Summary 9/15/2012: P/U Drill pipe; P/U HWDP; rack back pipe in derrick; troubleshoot TM-80; P/U BHA and bit; orientate BHA; C&C hole; Test High Pressure lines, check connections, valves air boots for leaks; test Standpipe manifold to 3000psi, no leaks; C&C; tagged bottom at 137', Commenced rotary drilling at 1400 hrs slides as directed by DD; currently drilling ahead at 601' MD. 9/16/2012: Drilled ahead from 601' MD to 1846' MD. 9/17/2012: Drilled ahead from 1846' to 2111' MD; short trip to 650' MD; Trip gas 76u; TIH to 2015'; washdown from 2015' to 2111'; C&C, 95u gas; commenced rotary drilling; currently drilling ahead. 9/18/2012: Drilled ahead from 2505' to 2920' MD; C&C and service Mud Pump#2; Drill to 2999' MD service Mud Pump#2; drilled to Surface Casing Point TD at 3102' MD, TD at 11:45hrs; currently circulating bottoms up. 9/19/2012: C&C pump two 30 bbl nut plug/hi-vis sweeps, 46u max gas; TOOH from 3102' to 173' MD; TIH from 173’ to 3202'; C&C; CBU 45u max gas; monitor well- static, pump dry job; POOH from 3102’ to 143’ MD; L/D BHA; L/D collars; downtime-hoisting/lifting repair coupling on skate since 23:00 hrs. 9/20/2012: Downtime-hoisting/lifting broken coupling on gear; L/D BHA; R/U snatch block to pull BHA into shed using tuggers; L/D MDW tools, bit motor, stabilizer. Rig up/down to run casing; R/U casing tools, slips elevators, P/U sling; R/U fill up line off of stand pipe; run 10 3/4" 45.50 lb casing to 3102' MD, max casing trip gas 6u; Circulate and condition rig up to circulate; Install circulating swedge and high psi mud lines. 9/21/2012: C&C; CBU x 2, max gas 13u; rig up flow nipple, false bowl, slips, plate, hose for running drill pipe in 10 ¾” casing; TIH with 31 stands of 5" drill pipe making top drive connections; make up head pin on 31st stand and rack back; TIH M/U pump in sub and rack back, pick up next stand and run in, pick up pump in stand and run in, sting in at 3057' MD; C&C stage up pumps to 7 bbl/min, 46% flow no losses; pre job for cementing; mix the spacer, line up to Baker primary cementing; 2500psi test on lines- all good; pump 20bbl 8.4ppg spacer; pump 260bbl 12ppg lead cement; pump 48bbl 14.8ppg tail cement; pump 49bbl mud to displace; unsting and pump 5bbl h20; cement in place at 1830hrs; rig down cementer lines; TOOH, pull 2 stands, C&C pump wiper plug and 700 strokes to clear drill pipe; RIH 1 stand and remove pump; TOOH currently at 1915'MD. 9/22/2012: TOOH and rack back from 1900' MD; remove centralizers; B/O stinger; L/D BHA; clear drill floor of Baker’s & Schlumberger’s tools and equipment; Nipple U/D diverter system and remove diverter lines; Nipple down flowlines & hole fill lines, pump cellar out to its; cut flow line nipple & turn riser; R/U bridge cranes to hydrill; Nipple U/D diverter system; Nipple down B/O nut/studs from surface tee to wellhead; have welder cut flow line x to pick diverter up through bushings; welder make ruff cut on casing, cut joint 22.15'; remove knife valve from diverter "T"; remove DS cellar door, remove diverter flow line; remove bolts from annular and remove annular from cellar; remove diverter “T"; remove starter head. North Fork Unit #23-25 14 Daily Activity Summary, con’t. 9/23/2012: Prepare cellar and wellhead; stage wellhead to pick. Prep cellar & welder cut conductor per Vetco rep; continue to clean mud pits. C/O liners in mud pumps; install wellheads; welder cut casing and dress cut. P/U, orient and set wellhead on conductor per Vetco rep. Welder heat and weld wellhead to conductor; Cleaned rig/platform let wellhead/conductor cool slow; clean/organize parts/tools throughout rig; stage MI Swaco super choke and test pump in place to plumb in; prepare cellar and wellhead; test wellhead seals/weld to 1500 psi, No test, weld leaked; cleaning rig/platform continued cleaning/organizing throughout rig; continued installing 5.5" liners in mud pump; prepared cellar and wellhead welder re-heat and re-weld wellhead to conductor; continued cleaning rig and prepping stack for installation; test welds to 1600 psi for 15 min, good test, R/B-21.37' and N/U BOPs begin installing spool, single gates; change rams, install 2 7/8"x5" variable rams in single gate; N/U BOPs lift and install mud cross. 9/24/2012: Nipple up BOPs; torque mud cross spool. P/U & flange up manual & HCR kill valves to mud cross; stage & P/U Hydril with blocks; flange up Hydril to double gates; R/U bridge cranes & pick double gates and Hydril and flange up to mud cross; change rams; open upper ram doors to verify doors open up fully. Door don’t open far enough to change rams; nipple U/D BOPs B/O lower mud cross bolts and move mud cross one hole; turn stack one hole to line up ram doors; change rams; install blind rams in center gate, install 5"x 7" variables in top gate; N/D BOPs; N/D and turn adapter; N/U BOPs install single gate; N/D BOPs turn mud cross. 9/25/2012: Nipple up BOPs P/U & turn double gates/hydrill; set on mud cross & flange up same; change rams open blind/upper ram doors; install ram in double gates ensuring rams can be installed properly; install blind ram, tighten blind ram doors; nipple up BOPs flange up & M/U manual/HCR choke valves; nipple up BOPs P/U & M/U choke hose; nipple up bops torque BOP components to specs; P/U & M/U kill lines; change rams install 5" rams in top gate; nipple up BOPs install flow line riser, take down riser cut off 3 1/2" and reinstall; nipple up BOPs tighten all connections to specs; install blind flange on choke- tighten all flanges; nipple up BOPs hook up hydraulics to HCR's, put on turn buckles to center stack . 9/26/12: Nipple up BOPs; M/U flow lines; raise and M/U pitcher nipple; tighten choke manifold; M/U Koomey lines to bag and lower rams on stack; P/U test tools; P/U & M/U 5" test joint, port sub; TIH with dart. Function test rams and HCR; set test plug per Vetco; P/U test tools blow air through choke manifold and choke/kill lines, to verify no plugs; fluid pack choke manifold, lines and stack, shell test; no leaks; test BOPs 250psi-low 4000psi-high; 2500psi-bag. Hold test for 5min per test. Recorded on chart; waved by state man Jeff Jones; test BOPs 250 psi low 4000 psi high test, 2500; psi annular, all pass, witness waived by Jeff Jones, witnessed by Brian Tiedemann and Larry Driskill; ID test tool blow down choke and kill, pull test plug and install wear ring; cased hole logs pre job with wire liners; rig up wire liners; cased hole logs start in hole with casing log. 9/27/12: Cased hole logs; perform CMT bond log on E-line from 2086'-tag to 1850' 1 pass; log to surface per Pollard E-line reps; R/D E-line tools and equipment; prep floor to P/U BHA; pick up BHA #2; M/U 9 7/8" bit X/O ,3 HWDP, jars, 17 HWDP per baker /DD; pick up drill pipe; P/U 5" D/P from shed; RIH to 2046'; downtime- draw works re-spool drilling line; trouble shoot skate; P/U drill pipe from 2046' to 2999'; TIH wash down last 80' 45 Strokes at 100 psi; tag float collar @ 3055' 100 up, 75 down 85 ROT; circulate and condition 180 SPM 550 psi 60% returns; displace to water base KLA-shield; pressure test casing shoe; attempt to test casing; reach 1101 psi and weld on wellhead broke, bleed off all psi and clean out cellar. 9/28/12: Prepare cellar and wellhead; drain/prep cellar for welder to heat and re-weld wellhead to conductor per Vetco procedures; prepare cellar and wellhead; Nabors welder air ark old weld and heat re-weld wellhead to conductor pipe; wrap wellhead with insulation for slow cool down, per procedure; clean & organize rig/platform; organize and prep yard to spot shop; move existing diverter lines for room to park vehicles; grind off old weld on wellhead; redress and re-weld; build 160bbls 9.5ppg mud; load BHA in shed and stage tools on floor; cut composite grating to cover holes in upper degasser room; clean and organize on rig. North Fork Unit #23-25 15 Daily Activity Summary, con’t. 9/29/12: Wrap Wellhead with Insulation & let weld cool down slow. C/O Air boot to flowline. Circ & Condition P/U std & RIH T/3055'Circ 2 B/U till 9.4 ppg Mud Wt In/Out. Pressure Test Casing/Shoe test 10 3/4 casing T/3000 psi; Retest CSG hold. Same parameters. Good Test. B/D Kill lines. Line mud system up to Drill. D/O shoe track float, shoe. F/3055' T/3066' @ 477 GPM180 spm 500 psi. D/O, cement, shoe + 20' New hole T/3122'. Circ & Condition mud, 24u max gas; Formation Integrity Test(FIT) L.O.T 15.4 ppg EMW. POOH. L/D BHA. Case hole logs R/U Loggers. P/U tools. Bad electrical connection. 9/30/12: Cased hole logs; RIH with Pollard E-Line to CMT; bond log F/3060' T/Surface; R/D E-line equip; P/U BHA PJSM; P/U BHA #3 per Baker/DD reps; P/U BHA test & verity Baker sound tracktool is working; PJSM. Load nuke/source per Baker/DD reps. P/U BHA cont P/U DC 1 std HWPD & Jar. Perform S.H.T. @ 425 gpm 875 psi. P/U HWDP F/DRK T/855'. P/U DP P/U 5" DP T/1589' Proper Displacement. RIH T/3053'. Reaming/Washing sync smart iron, wash Dn F/3053' T/3122'. Rotary Drilling F/3122' T/3660'. 10/1/12: Screen Up on both shakers to Mesh 230 in order to help control the drill solids. Mix a Lub Pill with Lube 776 and Lotorq to help reduce torque issues. Rotary Drilling Ahead F/3660' T/4610'. Back ream every std. Continue Rotary Drilling Ahead F/4610' T/5614'. 10/2/12: Rotary Drilling DRLG ahead F/5614' T/7051'. Circulate & Condition hole clean. Circ 2 btms up. POOH flow check Well=Static. POOH F/7051' to surface to Test BOP. 10/3/12: POOH F/5614' T/3991' pulling tight 25-75K over/drag. Working through tight spots F/5,480' T/3970'. Reaming/washing BROOH T/3712' pump OOH T/3100'- shoe. POOH monitor hole 10 min, static, slug pipe. POOH T/855' - BHA/HWDP. L/D BHA. P/U Test Tools Pull wear ring. R/U TIW, ported sub, Test Jt F/Flushing Stack. Flush stack with water. Set Test plug. M/U test Jt. Fill Stack. Fill choke manifold with water (15bbls). Purge air F/system. Kill line plugged off, remove line/blockage. body test-4000 psi. Test BOPs 250/4000 psi. Witnessed by Lou Grimaldi. 10/4/12: Test BOP; test blind rams & manual choke valve on manifold; 250/4000 psi 5 min per; Charted & Witness by state man Lou Grimaldi; L/D Test tool R/D & L/D test JY & testing equip; B/D lines; P/U BHA; PU DP & RIH to 3,144' with proper hole fill; circ & condition at 400gpm while cut & slip drill line; RIH fill pipe every 2000'; Cut Drilling line slip n cut 50'. Set and test floor and crown saver. Condition mud while slipping and cutting the drill line. 400 GPM 900 psi. RIH T/6945'. Reaming/Washing wash DN F/6945' T/7050' Circ out trip gas 600 units. Rotary Drilling F/7050' T/7157' 10/5/12: Drilled ahead from 7157’ to 8105’. 10/6/12: Rotary Drilling from 8105' to 8,573' MD; ROP 40-100 FPH; 500 GPM;TQ 20-25K. Circ. & Condition X 1.5 BU up, max gas 78u.POOH from 8573' to 7036'; RIH to 8477'; Wash/Rot DN to 8573'; Rotary Drilling from 8573' to 8597'; Drills-BOP ETC notice flow increase and pit gain; Shut down pumps; Check Well=Flowing due to air in DP Shut in Well from Kill Well; Rotarty Drilling from 8597' to 8800'. 10/7/12: Rotary Drilling from 8,800' to 8,956', when torque maxed at 25K, determined Torque was caused by top drive limiter switch, fixed issue & torque dropped to 12-15K; Continued Rotary Drilling from 8956' to 95321'; C&C till shakers clean; CBU + 1/2 BU at 500gpm, 2150 psi; Flow check well. Wiper trip from 9531' to 8477', no tight spots, proper hole fill, Wiper Gas 12u; RIH to 9436', Wash/Ream down last stand to 9531', trip gas 33u; Commenced rotary drilling from 9531'; currently drilling at 9627'. 10/8/12: Drilled from 9627' to 10,584' @ 500 gpm; Circ. and Condition until shakers clean; CBU, max gas 29u; Monitor Well, POOH to 9526', max trip gas 20u; currently RIH at 10,070'. North Fork Unit #23-25 16 Daily Activity Summary, con’t. 10/9/12: RIH from 10,070' to 10,584'; drill to 10,785' (TD), 9,621' TVD; Circ. & Condition; CBU, bottoms up cuttings sample retrieved at 06:58, max gas 11 units; pump 23 bbls Hi-Vis sweep to surface; pump dry job & POOH from 10,775' to 5,807'; encounter tight spots: from 6,510' to 6,480', and from 6,390' to 6,360' overpull 30-50K; start backreaming from 6,145' to 5,807'; C/O washed out bleeder value on standpipe manifold; Circ. & Condition, max gas 23 units; pump 30 bbls Hi-Vis sweep; POOH on elevators, pulling tight; BROOH from 5800' to 5624'; POOH on elevators from 5624' T/5152'; pump slug out; continue POOH, currently at 4674'. 10/10/12: TOOH from 4674 to128; Up weight =60 Down weight=50; monitor well at shoe; L/D BHA remove nuke sources, plug into MWD; L/D sound track, stop sub, pony, motor; P/U test tools; P/U test joint; suck out stack; rinse stack; pull wear ring; set test plug; R/U test joint; fill system with water and purge air; test BOPs (AOGCC waived right to witness) 250/4000psi (annular-2500psi), 5 min each; record on chart; test all equipment with 5" test joint; koomey draw down start-3100psi, closing-1500psi , 200psi-36 seconds, final-138 seconds; test gas alarms; L/D test tool; pull test plug; drain stack; rinse bowl; R/U/D to run casing; dummy run 7"hanger per Vetco rep; function all lock down screws on wellhead (all screws functioned, but very tight); L/D test tool; set wear ring; L/D test joint; service rig: service top drive, crown sheaves, blocks, draw works; P/U BHA JSM; P/U Cleanout BHA. 10/11/12 : Tripped to bottom; washed down the last 900' due to tight hole; At bottom, circulated and conditioned mud; Pumped a high vis (Flowzan) sweep and circulated 2x bottom's up; Sweep returned 740 strokes late, bringing large (1-1.5")pieces of coal ahead of it; Pumped a slug and started coming out of the hole laying down pipe; At report time, pullingout of hole. 10/12/12: POOH laying down drill pipe from 8,070' MD to 5,973' MD; pull tight; begin back reaming out of hole; Back ream sections 6,635-6,604 and 6,250-5,983' at 250 gpm, 85RPM; Begin tripping out; LD pipe at 5,973 - ~5,616'; Still having problems; back ream as needed; standing back pipe; At report time, reaming out. 10/13/12: Lay Down 5" DP; Lay Down BHA; Cleaned rig; conditioned mud in pits; working on gunlines in pit #3. 10/14/12: Change rams. Rig up and test BOP's. 10/15/12: Continue testing BOP's; Rig down test equipment; Pick up 20 joints of Heavy weight drill pipe; Pick up 4" drill pipe while running in hole to 2,977'. TOH; racking back 4" drill pipe stands to 569'; Pick up 4" drill pipe while running in hole to 2,579' when pipe skate broke; Cut and slip drilling line while repairing skate. 10/16/12: Downtime-Powered catwalk lose drive coupling on skate drum & motor; Service top Drive; install gripper blocks & guides; pull up Drill Pipe 4" 14# Drill Pipe from 2579' to 3140'; POOH from 3140' to 2425'; Cut Drill Line; cut & slip drilling line; POOH F/2425' T/1069'; pull up Drill Pipe from Shed to 3224'; POOH with 4" Drill Pipe from 3224' to 569'; POOH Change elevators to 5" stand back 5" heavy weight drill pipe; Cleaning rig/platform; clear & clean rig floor; pull up BHA; Latch Up Collar Stand. 10/17/12 : Pull up BHA; Make up BHA; RIH from 1500' to 3505’; Circ & Condition 5400 strokes; RIH from 3505' to 4928'; fill pipe & circulate; Continue RIH to 5,077'; break circulate @ 3,214 strokes; Circulate 1 x Bottom Ups @ 6320 strokes; Continue to RIH to 6428' tight; Ream to 6443'; continue in hole; wash & ream tight spot, 6583' T/6630'; POOH-short trip from 6630' to 5397' & Back to 6920' continue to RIH. North Fork Unit #23-25 17 Daily Activity Summary, con’t. 10/18/1 2: RIH from 6920' to 8900'; Reamed from 8130' to 8200'; washed down from 8220' to 8270'; RIH from 8900' to 10735'; washed down & up 14000 strokes; Circulate & Condition Pump; High-Vis Sweep with Flowzan @ 168 SPM; POOH from 10735' to 8926'; Pulled 5 stands wet; pumped a slug; continued to POOH from 8926'; wipe tight spots; monitor well static; continued to POOH to 2620'; work on elevators; camera; blow down top drive; continue to POOH to 832'; lay down BHA. 10/19/12: Completed laying down BHA; R/U stabbing board; removed wear bushing; R/D bales & R/U Casing hands; HSM with Casing tongs; M/U 5 Joint shoe track bakerlok; fill & check float; Good; Continued RIH with 7" Casing from 204' Filling each joint centralisers as per casing tally; Monitoring returns; Circulate 1 Bottoms @ 3066'; 100 spm; 264 gpm; 550 psi; Continued RIH with 7" Casing to 4074'; filling pipe on the way in. 10/20/12: Bottom Up; 10772 strokes; R/U cementer equip; HSM with cementer; Drop BTM plug pump 5 bbls H2O; shut in PSI Test to 3000 PSI; bleed off PSI; continued with cement Job; pump 40 BBLs seal bond spr @ 10 ppg; mix weight & pump 223 BBLs Continued Running Casing from 4074' to 5500'; top off every 10 Joints; Circulate 2 bottoms up; 7 BPM 400 psi; Continued Running Casing from 10169' to 10689' with no problems; Run Casing Landing Jt; Remove spiders & bell guide; land hanger @ 10716'; Circulated hole clean; stage up pumps to 6 BPM; Circulate lead @ 12.7ppg; Pump Tail cmt @ 13.5 ppg Drop top plug pump 403 bbls 10/21/12: Finish cementing; Canrig released at 06:30 hrs. North Fork Unit #23-25 18 4.2 Surveys Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (ft) Dogleg Rate (o/100ft) 20 0 114.71 20 0 0 0 0 177 1.16 114.71 176.99 -0.66 1.44 1.13 0.74 267 1.33 113.02 266.97 -1.45 3.23 2.53 0.19 356 0.81 94.99 355.95 -1.91 4.81 3.86 0.69 446 1.22 104.22 445.94 -2.2 6.37 5.23 0.49 535 2.22 81.13 534.9 -2.17 8.99 7.7 1.35 623 5.1 74.68 622.71 -0.87 14.45 13.27 3.3 714 7.87 68.21 713.12 2.51 24.14 23.53 3.14 810 10.62 69.12 807.86 8.1 38.51 38.95 2.87 905 13.23 70.34 900.81 14.88 56.93 58.57 2.76 1000 16.18 69.4 992.68 23.2 79.56 82.69 3.12 1096 18.77 69.82 1084.25 33.23 106.58 111.51 2.7 1193 21.61 69.92 1175.28 44.75 138.01 144.98 2.93 1289 24.28 70 1263.67 57.57 173.17 182.41 2.78 1385 27.01 70.19 1350.21 71.71 212.23 223.95 2.85 1480 29.51 70.25 1433.88 86.93 254.56 268.93 2.63 1576 32.3 69.25 1516.24 104.01 300.8 318.23 2.95 1671 34.69 69.81 1595.46 122.34 349.92 370.65 2.54 1767 37.44 69.99 1673.05 141.76 402.99 427.16 2.87 1863 38.37 70.07 1748.8 161.9 458.42 486.14 0.97 1959 38.67 70.11 1823.91 182.26 514.63 545.92 0.31 2055 39.43 69.29 1898.46 203.25 571.36 606.4 0.96 2152 39.61 69.3 1973.29 225.07 629.09 668.12 0.19 2246 39.85 69.79 2045.58 246.06 685.39 728.2 0.42 2342 40.1 70.05 2119.15 267.24 743.31 789.88 0.31 2438 40.46 70.08 2192.38 288.4 801.66 851.95 0.38 2534 39.3 69.23 2266.05 309.8 859.37 913.5 1.34 2629 39.48 69.13 2339.47 331.22 915.72 973.78 0.2 2725 39.77 69.3 2413.42 352.95 972.97 1035 0.32 2821 39.94 69.6 2487.11 374.54 1030.57 1096.52 0.27 2917 40.12 69.31 2560.62 396.21 1088.39 1158.26 0.27 3013 39.75 70.11 2634.23 417.59 1146.19 1219.89 0.66 3045 39.91 70.15 2658.8 424.55 1165.46 1240.38 0.51 3183 39.24 69.49 2765.17 454.88 1247.99 1328.3 0.57 3277 40.19 70.02 2837.48 475.66 1304.34 1388.36 1.07 3372 40.64 70.02 2909.81 496.7 1362.22 1449.95 0.47 3466 40.6 69.65 2981.16 517.8 1419.67 1511.15 0.26 North Fork Unit #23-25 19 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (ft) Dogleg Rate (o/100ft) 3560 40.41 69.46 3052.63 539.13 1476.88 1572.2 0.24 3653 40.44 69.22 3123.43 560.4 1533.3 1632.5 0.17 3748 40.44 69.08 3195.73 582.34 1590.89 1694.12 0.1 3843 40.12 70.81 3268.21 603.4 1648.58 1755.54 1.22 3937 40.2 70.23 3340.05 623.62 1705.73 1816.15 0.41 4030 40.32 70.59 3411.02 643.77 1762.35 1876.25 0.28 4123 40.21 70.28 3481.99 663.89 1818.99 1936.36 0.25 4217 40.07 70.15 3553.85 684.41 1876.01 1996.95 0.17 4312 40.08 69.79 3626.54 705.35 1933.47 2058.11 0.24 4406 39.95 69.64 3698.53 726.31 1990.17 2118.56 0.17 4502 39.76 69.81 3772.23 747.63 2047.88 2180.08 0.23 4597 39.54 69.93 3845.37 768.49 2104.79 2240.7 0.25 4694 40.14 69.79 3919.85 789.89 2163.13 2302.84 0.63 4788 40.74 69.55 3991.4 811.07 2220.31 2363.81 0.66 4884 40.7 69.51 4064.16 832.97 2278.98 2426.44 0.05 4979 40.21 69.38 4136.44 854.61 2336.7 2488.07 0.52 5076 39.94 69.35 4210.67 876.62 2395.14 2550.52 0.28 5172 39.61 69.14 4284.45 898.39 2452.57 2611.93 0.37 5268 40.61 69.66 4357.87 920.14 2510.46 2673.78 1.1 5364 40.21 69.26 4430.97 941.98 2568.74 2736.01 0.5 5459 39.9 69.51 4503.68 963.5 2625.96 2797.14 0.37 5555 39.54 69.27 4577.52 985.1 2683.38 2858.49 0.41 5652 39.03 69.15 4652.6 1006.9 2740.8 2919.9 0.53 5746 36.89 70.16 4726.71 1027.01 2795 2977.72 2.37 5843 36.44 70.26 4804.52 1046.62 2849.51 3035.64 0.47 5938 35.76 70.31 4881.28 1065.5 2902.2 3091.61 0.72 6035 34.71 70.14 4960.5 1084.44 2954.86 3147.57 1.09 6129 32.62 68.99 5038.74 1102.61 3003.69 3199.67 2.32 6226 30.46 69.51 5121.4 1120.6 3051.13 3250.4 2.24 6321 27.77 70.21 5204.39 1136.52 3094.52 3296.62 2.85 6417 24.99 70.18 5290.39 1150.97 3134.65 3339.27 2.9 6512 22.45 69.44 5377.35 1164.15 3170.52 3377.49 2.69 6609 20.38 69.75 5467.65 1176.5 3203.71 3412.9 2.14 6705 18.14 68.44 5558.27 1187.78 3233.29 3444.56 2.38 6800 16.24 71.09 5649.03 1197.52 3259.62 3472.63 2.16 6896 14.23 72.95 5741.65 1205.33 3283.6 3497.83 2.15 6992 12.77 70.44 5835 1212.34 3304.88 3520.23 1.64 7079 11.39 68.93 5920.07 1218.65 3321.96 3538.43 1.63 7175 9.85 68.21 6014.42 1225.11 3338.43 3556.12 1.61 North Fork Unit #23-25 20 Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Latitude (ft) N(+), S(-) Departure (ft) E(+), W(-) Vertical Section (ft) Dogleg Rate (o/100ft) 7270 8.45 69.98 6108.21 1230.51 3352.53 3571.22 1.5 7367 6.73 72.03 6204.36 1234.71 3364.63 3584.03 1.79 7462 4.73 72.4 6298.88 1237.61 3373.66 3593.5 2.11 7560 2.67 76.77 6396.67 1239.35 3379.74 3599.81 2.12 7654 0.43 167.48 6490.63 1239.51 3381.95 3601.94 2.88 7750 0.73 192.58 6586.63 1238.56 3381.89 3601.56 0.4 7846 0.98 194.9 6682.62 1237.17 3381.55 3600.76 0.26 7941 1.04 206.63 6777.6 1235.61 3380.95 3599.66 0.23 8036 0.48 231.27 6872.59 1234.59 3380.25 3598.66 0.67 8132 0.57 211.3 6968.59 1233.93 3379.69 3597.9 0.21 8228 0.12 283.12 7064.59 1233.55 3379.35 3597.44 0.57 8323 0.37 244.14 7159.59 1233.44 3378.97 3597.06 0.3 8419 0.43 231.17 7255.58 1233.08 3378.41 3596.41 0.11 8515 0.59 237.21 7351.58 1232.58 3377.72 3595.58 0.18 8611 0.75 235.29 7447.57 1231.96 3376.79 3594.49 0.17 8707 0.66 224.19 7543.57 1231.2 3375.88 3593.39 0.17 8802 0.89 231.92 7638.56 1230.36 3374.92 3592.19 0.27 8898 1.04 227.24 7734.54 1229.3 3373.7 3590.68 0.18 8994 1.21 223.67 7830.53 1227.98 3372.36 3588.96 0.19 9090 0.87 236.96 7926.51 1226.85 3371.04 3587.34 0.43 9186 0.56 245.18 8022.5 1226.26 3370.01 3586.17 0.34 9283 0.84 225.35 8119.49 1225.56 3369.07 3585.05 0.38 9378 0.71 190.62 8214.49 1224.49 3368.47 3584.11 0.5 9473 0.86 180.61 8309.48 1223.2 3368.35 3583.56 0.21 9570 0.95 187.84 8406.47 1221.67 3368.23 3582.92 0.15 9664 0.4 242.66 8500.46 1220.75 3367.84 3582.23 0.84 9760 0.42 237.19 8596.46 1220.41 3367.24 3581.56 0.05 9857 0.65 236.68 8693.45 1219.91 3366.48 3580.67 0.24 9952 0.85 226.39 8788.44 1219.13 3365.52 3579.5 0.25 10048 0.84 232.56 8884.43 1218.21 3364.45 3578.18 0.1 10145 1 217.35 8981.42 1217.1 3363.37 3576.79 0.3 10241 1.16 202.18 9077.4 1215.54 3362.5 3575.43 0.34 10336 1.26 194.56 9172.38 1213.64 3361.87 3574.18 0.2 10432 1.3 191.24 9268.36 1211.55 3361.39 3573.02 0.09 10526 1.2 184.76 9362.34 1209.52 3361.1 3572.05 0.18 10621 1.49 183.86 9457.31 1207.3 3360.94 3571.13 0.31 10717 1.63 174.03 9553.28 1204.69 3361 3570.29 0.31 10785 1.63 174.03 9621.25 1202.77 3361.2 3569.81 0 No r t h F o r k U n i t # 2 3 - 2 5 21 4. 3 B i t R e c o r d BI T NO . SI Z E TY P E S / N JE T S / TF A IN O U T F T H R S AV E RO P CONDITION 1 1 3 ½ ” H T C M X L - 1 X 5 1 9 6 6 6 4 1x 1 4 , 3 x 1 6 0. 7 3 9 4 13 7 ’ 3 1 0 2 ’ 2 9 6 5 ’ 5 3 . 6 0 55 . 4 1 - 1 - W T - A - E - 1 - C T - T D 2 9 ” H T C T G X A 9 7 1 5 0 8 5 6 5 4 3x 2 0 0. 9 2 0 4 31 0 2 ’ 3 1 2 2 ’ 20 ’ 0 . 5 4 0 . 0 1 - 1 - N O - A - E - I - N O - B H A 3 8 ¾ ” H C C Q D 5 0 5 F X 7 1 2 8 4 1 6 7x 1 4 1. 0 5 2 3 31 0 2 ’ 7 0 5 1 ’ 3 4 2 9 ’ 3 6 . 8 1 0 7 . 4 1- 1 - B F - N - X - I - N O - H R 4 8 ¾ ” H C C Q D 5 0 6 X 7 1 3 3 7 1 9 6x 1 4 0. 9 0 2 0 70 5 1 ’ 1 0 7 8 5 ’ 37 3 4 ’ 71 . 5 5 1 . 4 1 - 1 - W T - A - X - I - C T - T D No r t h F o r k U n i t # 2 3 - 2 5 22 4. 4 M u d R e c o r d Co n t r a c t o r : B a k e r H u g h e s D r i l l i n g F l u i d s Mu d T y p e : G e l S p u d M u d 1 7 8 ’ – 3 2 2 5 ’ ; T E R R A - M A X S y s t e m 3 2 2 5 ’ – 1 2 0 7 0 ’ Da t e D e p t h MW (p p g ) VI S (s / q t ) PV Y P G e l s FL (c c ) FC So l s (% ) O/ W Ra t i o Sd (% ) MB T p H Cl (ml/l) Ca (ml/l) 9/ 1 5 / 1 2 4 7 5 8 . 9 6 5 1 0 1 3 9 / 1 7 / 2 1 - - 5 . 0 0 / 9 5 . 0 . 7 5 1 7 . 5 9 . 8 - - 9/ 1 6 / 1 2 1 7 0 0 9 . 5 6 2 1 8 2 2 1 1 / 2 8 / 3 7 - - 8 . 0 0 / 9 2 . 0 1 .0 2 3 . 7 5 9 . 5 - - 9/ 1 7 / 1 2 2 4 3 3 1 0 . 1 5 6 1 5 9 4 / 2 1 / 3 5 9 . 5 3 1 6 . 0 0 / 8 4 . 0 . 7 5 2 5 . 0 9 . 0 3 5 0 1 1 0 9/ 1 8 / 1 2 3 0 5 6 1 0 . 2 4 7 4 1 1 1 / 2 / 4 1 0 . 2 2 1 3 . 5 0 / 8 7 . 0 .2 5 2 0 . 0 8 . 8 4 5 0 6 0 9/ 1 9 / 1 2 3 1 0 2 1 0 . 1 4 1 7 9 3 / 4 / 6 9 . 5 2 1 3 . 0 0 / 8 7 . 0 . 2 5 2 2 . 5 8 . 7 4 0 0 6 0 9/ 2 0 / 1 2 3 1 0 2 1 0 . 2 4 2 9 1 0 3 / 5 / 7 9 . 5 2 1 3 . 5 0 / 8 7 . 0 . 25 2 2 . 5 8 . 7 4 0 0 6 0 9/ 2 1 / 1 2 3 1 0 2 1 0 . 6 4 2 1 0 7 3 / 5 / 7 9 . 5 2 1 6 . 5 0 / 8 4 . 2 5 2 2 . 5 8 . 7 4 0 0 5 0 9/ 2 2 / 1 2 3 1 0 2 10 . 6 4 3 1 0 8 3 / 5 / 6 9 . 5 2 1 6 . 5 0 / 8 4 . 2 5 2 0 . 0 8 . 6 4 0 0 50 9/ 2 3 / 1 2 3 1 0 2 1 0 . 6 4 5 1 1 8 3 / 5 / 6 9 . 5 2 1 6 . 5 0 / 8 4 . 2 5 2 0 . 0 8 . 6 4 0 0 5 0 9/ 2 4 / 1 2 3 1 0 2 1 0 . 6 4 6 1 2 9 4 / 5 / 6 9 . 4 2 1 6 . 0 0 / 8 4 . 2 5 2 0 . 0 8 . 6 4 2 0 5 0 9/ 2 5 / 1 2 3 1 0 2 1 0 . 6 4 6 1 3 8 4 / 5 / 6 9 . 4 2 1 6 . 0 0 / 8 4 . 2 5 2 0 . 0 8 . 6 4 2 0 5 0 9/ 2 6 / 1 2 3 1 0 2 1 0 . 6 4 6 1 3 7 4 / 5 / 6 9 . 4 2 1 6 . 0 0 / 8 4 . 2 5 2 0 . 0 8 . 5 4 2 0 5 0 9/ 2 7 / 1 2 3 1 0 2 9 . 5 4 5 9 1 4 4 / 9 / 1 2 7 . 3 1 7 . 0 0 / 9 3 - - 9.2 30000 - 9/ 2 8 / 1 2 3 1 0 2 9 . 5 4 7 9 1 6 5 / 1 0 / 1 3 7 . 3 1 7 . 0 0 / 9 3 - - 9 . 1 3 1 0 0 0 - 9/ 2 9 / 1 2 3 1 2 2 9 . 3 6 2 1 3 1 9 6 / 1 0 / 1 5 6 1 7 . 2 0 / 9 3 - - 10.2 34000 120 9/ 3 0 / 1 2 3 6 6 0 9 . 5 6 5 1 0 1 9 4 / 1 0 / 1 4 7 1 8 . 7 0 / 9 0 - - 9.9 26000 40 10 / 1 / 1 2 5 6 1 4 9 . 8 5 2 1 3 2 0 6 / 1 0 / 1 5 7 . 9 1 1 1 0 / 8 7 . 1 - 9 . 4 2 4 0 0 0 4 0 10 / 2 / 1 2 7 0 5 1 9 . 8 4 8 1 1 1 5 4 / 6 / 9 6 1 1 1 . 3 0 / 8 6 . 2 1 2 .5 9 . 4 2 4 0 0 0 8 0 10 / 3 / 1 2 7 0 5 1 9 . 6 5 7 1 3 1 7 4 / 7 / 1 0 4 . 8 1 9 . 4 0 / 8 9 . 1 12 . 5 9 . 9 3 7 0 0 0 8 0 10 / 4 / 1 2 7 1 5 7 9 . 7 6 0 1 7 1 9 5 / 9 / 1 5 4 . 1 1 1 0 . 2 0 / 8 8 . 1 1 2 . 5 9 . 8 3 0 0 0 0 8 0 10 / 5 / 1 2 8 0 9 3 9 . 6 5 7 1 7 1 9 4 / 5 / 8 4 . 4 1 9 . 5 0 / 8 7 . 1 1 2. 5 9 . 5 2 6 0 0 0 6 0 10 / 6 / 1 2 8 7 7 6 9 . 6 6 2 1 7 1 5 4 / 5 / 6 4 . 3 1 9 . 8 0 / 8 6 . 1 1 5 9 . 5 3 1 0 0 0 4 0 10 / 7 / 1 2 9 5 9 4 9 . 7 4 4 1 7 8 2 / 3 / 4 4 . 9 1 1 4 . 0 4 / 8 2 . 1 1 7. 5 9 . 1 2 8 0 0 0 4 0 Ab b r e v i a t i o n s : MW = M u d W e i g h t V I S = F u n n e l V i s c o s i t y P V = P l a s t i c V i s c o s i t y Y P = Y i e l d P o i n t G e l s = G e l S t r e n g t h F L = W a t e r o r F i l t r a t e L o s s FC = F i l t e r C a k e O / W = O i l t o W a t e r r a t i o S o l s = S o l i d s S d = S a n d c o n t e n t M B T = M e t h y l e n e B l u e A l , P m = A l k a l i n i t y , M u d p H = A c i d i t y / B a s i c i t y C l = C h l o r i d e s C a = H a r d ne s s C a l c i u m n r = N o t R e c o r d e d No r t h F o r k U n i t # 2 3 - 2 5 23 Co n t r a c t o r : B a k e r H u g h e s D r i l l i n g F l u i d s Mu d T y p e : G e l S p u d M u d 1 7 8 ’ – 3 2 2 5 ’ ; T E R R A - M A X Sy s t e m 3 2 2 5 ’ – 1 2 0 7 0 ’ Da t e D e p t h MW (p p g ) VI S (s / q t ) PV Y P G e l s FL (c c ) FC So l s (% ) O/ W Ra t i o Sd (% ) MB T p H Cl (ml/l) Ca (ml/l) 10 / 8 / 1 2 1 0 5 8 4 9 . 6 4 6 1 5 1 3 3 / 4 / 5 4 . 9 1 1 1 3 / 8 4 . 1 1 5 9 . 1 26000 60 10 / 9 / 1 2 1 0 7 8 5 9 . 5 5 4 1 6 1 7 3 / 4 / 5 4 . 3 1 1 1 . 5 3 / 8 4 . 1 5 1 5 9 . 5 26000 60 10 / 1 0 / 1 2 1 0 7 8 5 9 . 5 5 3 1 3 1 2 3 / 4 / 6 4 . 5 1 8 . 0 4 / 8 9 . 1 1 5 9 . 5 27500 60 10 / 1 1 / 1 2 1 0 7 8 5 9 . 7 5 4 1 4 1 2 3 / 5 / 6 4 . 1 1 9 4 / 8 8 . 1 1 5 9 . 6 2 7 5 0 0 6 0 10 / 1 2 / 1 2 1 0 7 8 5 9 . 8 5 6 1 5 1 1 3 / 4 / 7 4 . 3 1 1 0 4 / 8 7 . 1 16 . 2 5 9 . 7 2 9 5 0 0 6 0 10 / 1 3 / 1 2 1 0 7 8 5 9 . 7 5 7 1 3 1 0 3 / 4 / 6 4 . 1 1 1 0 4 / 8 7 . 1 15 9 . 7 2 7 0 0 0 6 0 10 / 1 4 / 1 2 1 0 7 8 5 9 . 4 5 4 1 1 1 0 2 / 3 / 4 4 . 1 1 8 4 / 8 9 - 1 2 .5 1 0 . 3 2 6 5 0 0 4 0 10 / 1 5 / 1 2 1 0 7 8 5 9 . 4 5 2 1 1 8 2 / 3 / 4 4 1 8 4 / 8 9 - 1 2 . 5 10.3 26000 40 10 / 1 6 / 1 2 1 0 7 8 5 9 . 4 5 6 1 2 1 0 2 / 3 / 4 4 1 8 4 / 8 9 - 1 2 . 5 1 0 . 3 2 6 0 0 0 4 0 10 / 1 7 / 1 2 1 0 7 8 5 9 . 6 5 8 1 4 8 2 / 3 / 4 4 . 1 1 9 3 / 8 8 - 1 5 10.1 25500 40 10 / 1 8 / 1 2 1 0 7 8 5 9 . 6 5 7 1 4 7 2 / 3 / 4 4 1 9 3 / 8 8 - 1 5 1 0 .1 26000 40 10 / 1 9 / 1 2 1 0 7 8 5 9 . 6 6 5 1 7 1 5 3 / 4 / 5 4 1 9 3 / 8 8 - 1 5 1 0 26500 60 10 / 2 0 / 1 2 1 0 7 8 5 9 . 7 5 7 1 4 7 2 / 3 / 4 4 1 1 0 . 2 3 / 8 7 - 1 5 1 0 . 1 2 6 0 0 0 6 0 10 / 2 1 / 1 2 1 0 7 8 5 9 . 7 7 5 1 8 1 2 3 / 4 / 5 4 1 1 0 . 2 3 / 8 7 - 1 5 1 0 . 1 2 5 5 0 0 6 0 Ab b r e v i a t i o n s : MW = M u d W e i g h t V I S = F u n n e l V i s c o s i t y P V = P l a s t i c V i s c o s i t y Y P = Y i e l d P o i n t G e l s = G e l S t r e n g t h F L = W a t e r o r F i l t r a t e L o s s FC = F i l t e r C a k e O / W = O i l t o W a t e r r a t i o S o l s = S o l i d s S d = S a n d c o n t e n t M B T = M e t h y l e n e B l u e A l , P m = A l k a l i n i t y , M u d p H = A c i d i t y / B a s i c i t y C l = C h l o r i d e s C a = H a r d ne s s C a l c i u m n r = N o t R e c o r d e d No r t h F o r k U n i t # 2 3 - 2 5 24 4. 5 D r i l l i n g P r o g r e s s C h a r t D A Y S V E R S U S D E P T H 0 1 0 0 0 2 0 0 0 3 0 0 0 4 0 0 0 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 1 0 0 0 0 1 1 0 0 0 1 2 0 0 0 1 0 / 1 2 / 2 0 1 0 1 0 / 1 3 / 2 0 1 0 1 0 / 1 4 / 2 0 1 0 1 0 / 1 5 / 2 0 1 0 1 0 / 1 6 / 2 0 1 0 1 0 / 1 7 / 2 0 1 0 1 0 / 1 8 / 2 0 1 0 1 0 / 1 9 / 2 0 1 0 1 0 / 2 0 / 2 0 1 0 1 0 / 2 1 / 2 0 1 0 1 0 / 2 2 / 2 0 1 0 1 0 / 2 3 / 2 0 1 0 1 0 / 2 4 / 2 0 1 0 1 0 / 2 5 / 2 0 1 0 1 0 / 2 6 / 2 0 1 0 1 0 / 2 7 / 2 0 1 0 1 0 / 2 8 / 2 0 1 0 1 0 / 2 9 / 2 0 1 0 1 0 / 3 0 / 2 0 1 0 1 0 / 3 1 / 2 0 1 0 1 1 / 1 / 2 0 1 0 1 1 / 2 / 2 0 1 0 1 1 / 3 / 2 0 1 0 1 1 / 4 / 2 0 1 0 1 1 / 5 / 2 0 1 0 1 1 / 6 / 2 0 1 0 1 1 / 7 / 2 0 1 0 1 1 / 8 / 2 0 1 0 1 1 / 9 / 2 0 1 0 1 1 / 1 0 / 2 0 1 0 1 1 / 1 1 / 2 0 1 0 1 1 / 1 2 / 2 0 1 0 1 1 / 1 3 / 2 0 1 0 1 1 / 1 4 / 2 0 1 0 1 1 / 1 5 / 2 0 1 0 1 1 / 1 6 / 2 0 1 0 1 1 / 1 7 / 2 0 1 0 1 1 / 1 8 / 2 0 1 0 1 1 / 1 9 / 2 0 1 0 1 1 / 2 0 / 2 0 1 0 11/21/2010 11/22/2010 11/2 3 /2 0 1 0 11/2 4 /2 0 1 0 11/25/2010 11/26/2010 11/2 7 /2 0 1 0 11/2 8 /2 0 1 0 D A T E D E P T H ( F T ) 12 1/4" Hole 8 1/2" Hole 6 1/8" Hole N F U 3 2 - 3 5 25 5 DAILY REPORTS