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HomeMy WebLinkAbout214-199Guhl, Meredith D (CED) From: Caltagirone, Peter (DNR) Sent: Tuesday, October 8, 2019 12:52 PM To: Beckham, James B (DNR); Guhl, Meredith D (CED) Subject: RE: Armstrong Decisions Meredith, checked yesterday and again today, with both Courtview and Department of Law. So far, nothing filed or served. I'd say it's ok to proceed at this point. Warm regards, Peter Peter 1. Caltagirone, Esq. Senior Legal & Policy Advisor State of Alaska, Department of Natural Resources Commissioner's Office 907.269.8431 Peter.caltaeirone@alaska.eov From: Caltagirone, Peter (DNR) <peter.caltagirone@alaska.gov> Sent: Monday, October 7, 2019 10:25 AM To: Beckham, James B (DNR) <jim.beckham@alaska.gov>; Guhl, Meredith D (CED) <meredith.guhl@alaska.gov> Subject: RE: Armstrong Decisions Meredith —thanks for the follow up and for checking before disclosing! I am checking with Department of Law to make sure nothing has been filed / served. Will hope to get back to you either today or tomorrow and let you know. Peter Peter J. Caltagirone, Esq. Senior Legal & Policy Advisor State of Alaska, Department of Natural Resources Commissioner's Office 907.269.8431 Peter.ca Itagi rone Caa laska.gov From: Beckham, James B (DNR) <jim.beckham(caalaska.eov> Sent: Monday, October 7, 2019 8:19 AM To: Guhl, Meredith D (CED) <meredith.guhl@alaska-Rov> Cc: Caltagirone, Peter (DNR) <peter.caltagirone0alaska.zov> Subject: RE: Armstrong Decisions Good morning Meredith, I am sure CPAI is ringing your fone off the hook for this data. I have not rcvd anything with respect to the decision on appeal for those wells. Just in case the Commissioner's office has, I have included Peter on this response. Jim James B. Beckham Acting Director State of Alaska Department of Natural Resources Division of Oil and Gas 550 W. 7" Avenue, Suite 1100 Anchorage AK 99501-3510 Direct: 907.269.8775 Cell: 907.310.6025 CONFIDENTIALITYNOTICE. This e-mail message, including any attachments, contains information from the State of Alaska, Department of Natural Resources (DNR) 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 DNR is aware of the error in sending it to you, please contact Jim Beckham at (907) 269.8775 or iim.beckharn0alaska ¢ov. From: Guhl, Meredith D (CED) <meredith.euhl alaska.eov> Sent: Monday, October 7, 2019 8:16 AM To: Beckham, James B (DNR) <lim.beckhann alaska.eov> Subject: RE: Armstrong Decisions Good Morning Jim, Has Armstrong appeal the decisions regarding Qugruk 301, 7, and 8? If not, I have data requestors eagerly awaiting a look at the data. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhIPalaska ¢ov Direct: (907) 793-1235 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($). 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 Meredith Guhl at 907-793-1235 or meredith.guhlc@alaska.gov. From: Beckham, James B (DNR) <jim.beckham�alaska.eov> Sent: Friday, September 6, 2019 11:19 AM To: Clifton, Sean C (DNR) <sean.clifton(aalaska.eov>; Ptacin, John M (LAW) <john.otacinCn�alaska.aov>; Frank, Kevin 1 (DNR) <kevin.frankCnlalaska.eov>; Gk , Meredith D (CED) <meredith.¢uhlCalalasl� ov> Subject: Fwd: Armstrong Decisions Fyi Sent from my Samsung Galaxy smartphone. -------- Original message -------- From: "Caltagirone, Peter (DNR)' <peter.caltasironegalaska.gov> Date: 9/6/19 11:52 (GMT -08:00) To: "Beckham, James B (DNR)' <jim.beckhamC@alaska.eov> Subject: Armstrong Decisions Jim — You may have been blind copied, but if you not here you go. Peter J. Caltagirone, Esq. Senior Legal & Policy Advisor State of Alaska, Department of Natural Resources Commissioner's Office 907.269.8431 peter.caltagirone@alaska.gov THE STATE 01ALASKA GOVERNOR MICHAEL J. DUNLEAVY Mr. Ed Kerr Vice President Armstrong Energy, LLC 1421 Blake Street Denver, CO 80202 ed(@.arrnstrongoilandgas.com Department of Natural Resources OFFICE OF THE COMMISSIONER 550 West 7m Avenue, Suite 1400 Anchorage, AK 99501-3561 Main: 907.269-8431 Fax: 907-269-8918 September 6, 2019 VIA E-MAIL AND U.S. CERTIFIED MAIL RE: September 25, 2017 Appeal regarding Qugruk 8 and Qugruk 301 Well Data Confidentiality Dear Mr. Kerr: The following is the final decision of the Department of Natural Resources ("DNR") regarding Armstrong Energy, LLC's ("Armstrong") appeal (the "Appeal") of the December 16, 2016 decision of the DNR Division of Oil & Gas designating data and information from the Qugruk 8 and 301 wells as eligible for public release (the "Decision"). Commissioner Com A. Feige voluntarily recused herself from the adjudication of this Appeal. This Appeal is adjudicated by Deputy Commissioner Sara Longan. After a review of the Appeal and administrative record, the Appeal is denied. The Decision is hereby affirmed, in full, and incorporated herein by reference. This decision is the final administrative order and decision of DNR for the purpose of an appeal to the Superior Court. An appellant affected by this final administrative order and decision may appeal to the Superior Court within 30 days in accordance with the Alaska Rules of Court and to the extent permitted by applicable law. Sincerely, Dr. Sara W. Longan Deputy Commissioner Cc: Corri A. Feige, Commissioner. Peter J. Caltagirone, Esq., Senior Legal & Policy Advisor. James Beckham, Acting Director, DNR Division of Oil & Gas. THE STATE 01ALASKA GOVERNOR BILL WALKER September 29, 2017 Mr. Ed Kerr Armstrong Energy, LLC 1421 Black Street Denver, CO 80202 ed narmstrongoiland as.com Dear Mr. Kerr; Department of Natural Resources ( OMMISSIONEW5 OFFICE 550VV 7"'41400 Anchorage, AK 99501 Main: 907 269.8431 Fa.: 907.269.8918 I received your letter dated September 21, 2017 appealing the September 20, 2017 decision by the director of the Division of Oil and Gas to terminate the extended confidentiality covering data and information from the Qugruk 8 and Qugruk 301 exploratory wells. The purpose of this letter is to acknowledge that your appeal was timely filed under DNR's appeal regulation, 11 AAC 02.040. I will consider your appeal based on the merits of the arguments you have raised. While your appeal is under consideration, the decision under question is stayed pursuant to 11 AAC 02.060. Sincer rew T. Ma �r 10/3/ Commissioner cc: Cathy Foerster, AOGCC A ARMSTRONG Ener&n•, LLC September 21, 2017 Commissioner Andy Mack Department of Natural Resources Division of Oil and Gas 550 West 7s' Ave., Suite 1100 Anchorage, AK 99501 Re: Qugruk 8 and Qugruk 301 Well Data Commissioner Mack: DEPARTMENT OF NATURAL RESOURCES SEP 2 5 2017 COMMISSIONER'S OFFICE ANCHORAGE On September 20, 2017, I received a letter from the Director of the Division of Oil and Gas re: Confidentiality for Qugruk 8 and Qugruk 301 well data ("Well Data"). Armstrong Energy, LLC ("AE") requests a stay of the Director's decision (the "Decision") in said letter. Further AE hereby appeals the decision of said letter as well. The letter states that the status of the "unleased lands" had changed due to restoration of the lands to "leased status" from an acceptance of certain conditions in your decision on August 1, 2017 (the "Commissioner's Decision") related to the previously unleased lands. The Commissioner's Decision requires certain work commitments to be fulfilled by May 31, 2018 ("2018 Well Commitment") or the leases must be voluntarily surrendered resulting in the lands being unleased due to non-performance and eligible for the next annual North Slope Areawide Sale. Given the 2018 Well Commitment is required to actually perpetuate the leases in question, AE respectfully requests that the Decision be reconsidered and that the Well Data continue to be held confidential until such time as the 2018 Well Commitment is drilled and the requirement is perfected. I am happy to discuss tos with you at your convenience. Yours trul Director 1421 Blake Street Denver, CO 80202 p 303.623.1821 f 303.623.3019 THE STATE °fALASKA GOVERNOR BILL WALKER CERTIFIED MAIL # 7017 0190 0001 0521 3238 RETURN RECEIPT REQUESTED September 20, 2017 Mr. Ed Kerr Director Armstrong Energy, LLC 1421 Blake Street Denver, CO 80202 Dear Mr. Kerr: Department of Natural Resources RECEIVED SEP 2 5 2017 AOGICC DIVISION OF OIL AND GAS 550W.7-^ Avenue, Suite 1100 Anchorage, AK 99501 Main: 907.269.8800 Fax: 907.269.8939 Through my decision of Mav 15, 2017, the Division of Oil and Gas granted extended confidentiality for the well reports and information from the Qugruk 8 and Qugruk 301 exploratory wells. That decision was premised on significance of the well data to nearby unleased lands in the former Tofkat Unit. Those lands were then considered unleased because of Commissioner Mack's February 17, 2017 decision that denied the Colville River Unit 5th expansion application. The Alaska Oil and Gas Conservation Commission was notified of my decision and postponed the wells' release pending resolution of the operator's ensuing request for reconsideration by Commissioner Mack. In an August 1, 2017 decision, Commissioner Mack reaffirmed his denial of the 5'h Expansion of the Colville River Unit, with specific modifications under which he would approve the expansion. Those conditions were subsequently accepted, thereby restoring the nearby lands in the former Tofkat Unit to leased status and negating the statutory and regulatory eligibility for extended confidentiality. The period for timely appeals of the Colville River Unit 5th Expansion decision has now expired. As a result, the Qugruk 8 and Qugruk 301 wells are no longer eligible for extended confidentiality, and consistent with my May 15, 2017 decision, the extension formerly applied to both wells will now terminate. A person affected by this decision may appeal it in accordance with 11 AAC 02. Any appeal must be received within 20 calendar days after the date of "issuance" of this decision, as defined in 11 AAC 02.040(c) and (d) and may be mailed or delivered to Andrew T. Mack Commissioner, Department of Natural Resources, 550 W. 7th Avenue, Suite 1400, Anchorage, Alaska 99501; faxed to (907) 269-8918, or sent via electronic mail to dnr.appeals@alaska.gov. This decision takes effect immediately. An eligible person must first appeal this decision in accordance with 11 AAC 02 before appealing this decision to Superior Cour. A copy of 11 AAC 02 may be obtained from any regional information office of the Department of Natural Resources. Sincerely, CL" I ,)-LL, Chantal Walsh Director cc: Hollis French, Chair, Alaska Oil and Gas Conservation Commission May 15, 2017 THE STATE °fALASKA GOVERNOR BILL WALKER Mr. Ed Ken Director Armstrong Energy, LLC 1421 Blake Street Denver, CO 80202 Dear Mr. Kerr: Department of Natural Resources DIVISION OF OIL AND GAS 550 W.7" Avenue, Suite 1100 Anchorage, AK 99501 Main: 907.269.8800 Fax: 907.269.8939 The Division of Oil and Gas has received your letter requesting extended confidentiality for the well data from the Qugruk 8 and Qugruk 301 exploratory wells. The Alaska Oil and Gas Conservation Commission has been advised of your request and has noted that without extended confidentiality, the wells would become eligible for release on May 25, 2017. Because there are no unleased lands within a three-mile radius of the bottom -hole location of the Qugruk 8 or Qugruk 301 wells, the confidentiality period may be extended if the owner of the well makes a sufficient showing that the well data contain significant information relating to the valuation of unleased land beyond the three-mile radius (11 AAC 83.153(a)). I have examined the confidential supporting geological, geophysical, and engineering data Armstrong provided, and find that it provides information that would impact how potential bidders would value nearby acreage in a future lease sale. Thus, Armstrong has made a sufficient showing that the information from the Qugruk 8 and Qugruk 301 wells relates significantly to the valuation of potentially unleased lands, specifically acreage that was formerly included in the Tofkat Unit. This acreage includes 15 leases that have expired, but are also subject to an application to expand the Colville River Unit. DNR may grant a unit application that includes leases that expire while the application is pending. Allen v. Alaska Oil and Gas Conservation Commission, 1 P.3d 699, 702-03 (Alaska 2000) (AOGCC could grant unit retroactive to date of application even though leases expired while application pending). The application to expand the Colville River Unit with this acreage is currently denied, but on reconsideration by the Commissioner. Thus, the leases are currently expired and not subject to a lease, but if the Commissioner reverses himself and grants the expansion, the acreage could become leased in the future. Accordingly, Armstrong's request for extended confidentiality is granted. This extension for each well shall terminate upon notice from the Division that the well is no longer eligible for extended confidentiality under 11 AAC 83.153. If the Commissioner grants the Colville River Unit expansion, it will likely impact Armstrong's eligibility for extended confidentiality. A person affected by this decision may appeal it in accordance with I 1 AAC 02. Any appeal must be received within 20 calendar days after the date of "issuance" of this decision, as defined in 11 AAC 02.040(c) and (d) and may be mailed or delivered to Andrew T. Mack Commissioner, Department of Natural Resources, 550 W. 7th Avenue, Suite 1400, Anchorage, Alaska 99501; faxed to (907) 269-8918, or sent via electronic mail to dnr.appeals@alaska.gov. This decision takes effect immediately. An eligible person must first appeal this decision in accordance with 11 AAC 02 before appealing this decision to Superior Court. A copy of I 1 AAC 02 may be obtained from any regional information office of the Department of Natural Resources. Sincerely, Chantal Walsh Director cc: Cathy Foerster, Chair, Alaska Oil and Gas Conservation Commission Guhl, Meredith D (DOA) From: Decker, Paul L (DNR) Sent: Tuesday, May 2, 2017 1:37 PM To: Guhl, Meredith D (DOA) Cc: Bettis, Patricia K (DOA); Davies, Stephen F (DOA) Subject: RE: Qugruk 301, PTD 214-199, Due for release 5/25/2017 Hi Meredith, Yes, in their role as operator, Armstrong has requested extended confidentiality on Qugruk 301. The Division of Oil and Gas is weighing its decision, which is complicated by the unstable lease status of lands in the vicinity. -Paul From: Guhl, Meredith D (DOA) Sent: Tuesday, May 2, 2017 9:04 AM To: Decker, Paul L (DNR) <paul.decker@alaska.gov> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov>; Davies, Stephen F (DOA) <steve.davies@alaska.gov> Subject: Qugruk 301, PTD 214-199, Due for release 5/25/2017 Hello Paul, Has extended confidentiality been requested for Qugruk 301, PTD 214-199, completed April 25, 2015? The data and well history is due for release after May 25, 2017. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.aov Direct: (907) 793-1235 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 Meredith GuhI at 907-793-1235 or meredith.zuhl@alaska.eov. 0L46r.cK- 30 P71)N Z14 (`i to Regg, James B (DOA) From: quick, michael (ext) <michael.quick@servexternos.repsol.com> Sent: Thursday, July 30, 2015 10:57 AM I ', c 'f / To: Schwartz, Guy L (DOA); Regg, James B (DOA); Bettis, Patricia K (DOA) Cc: ysa, rick (ext); JONES, ROBERT; dial, amanda (ext); HOLTON-VICE, REBECCA; flynn, tim (ext) Subject: Repsol Well Cellar Photos - 2014-2015 Season Attachments: Repsol Q301 conductor mound 7-6-15.JPG; Repsol Q8 conductor mound 7-6-15.JPG; Repsol Q9 conductor mound 7-6-15.JPG Mr. Regg / Mr. Schwartz / Ms. Bettis— Attached are cellar/conductor area photos from our summer clean up work for Repsol's three 2014-2015 exploration wells: Qugruk 8 well, PTD 214-200 Qugruk 9A well, PTD 215-061 Qugru < 301 we , PTD 214-1 We are planning agency area flights on 8/13/2015 with the DNR. I will submit a notice to the AOGCC inspectors via the web form of this upcoming inspection date, but wanted to provide you with the attached photos as well. Please let us know if you have any questions. Regards, Mike Michael Quick Alaska D&C Operations Team Lead Repsol E&P USA, Inc. 3800 Centerpoint Dr. Suite 400 Anchorage, AK 99503 Tel.: 907 375 6933 / Cel: 907 317 2969 mich ael.c u ick0servexternos. repsol. com REPJ"GL 7M. M JlL-- MLL 7M. M JlL-- REWOL June 2, 2015 T0: AOGCC (Alaska Oil and Gas Conservation Commission) Makana Bender/ Meredith Guhl 333 West 7'" Avenue, Suite 100 Anchorage, Alaska 99501 RE: Repsol E&P USA Inc. Lorenzo Villalobos/Juan Aluja ialuiaWareosol.com FAX83 442-1773 2455 Technology Forest So evard The Woodlands, TX, 77381 Dear Makana/Meredith 21 41 99 Repsol E&P USA Inc. 2455 Technology Forest Boulevard The Woodlands, Texas 77381 WCW JUN 1 0 2015 In the data listed below, Repsol Alaska is hereby submitting the technical information for the well Qugruk 301 (API: 50-103- 20700-00-00; PTD: 214.199) following the instructions of the regulation 20 AAC 25071 of the Alaska Oil and Gas Conservation Commission (AOGCC). 4 CDs; = CD#1 containing Halliburton's Mudlogging final deliveries. • CD#2 containing Schlumberger's LWD final deliveries. 111 CD#3 containing Schlumberger's Wireline Logging final deliveries. • 93 6 CD#4 containing Miscellaneous Well Data Required by AOGCC.• Paper Copies: Mudlogging final plots LWD final plots. Wireline Logging final plots Miscellaneous Well Data Extension Reauests for following analysis/studies: Isotubes analysis DST Fluid Samples See attachment for complete inventory of deliverables. Please acknowledge receipt by signing and returning a copy of the transmittal letter (by postal mail, email or fax) to the attention of Repsol, Lorenzo Villalobos/Juan Aluja, 2455 Technology Forest Boulevard the Woodlands Texas 77381. Date OC LJ CC: Roberta Camuffo "MV REPWOL Z' 41 99 Repsol E&P 1.15A Inc. 2455 Technology Forest Boulevard The woodlands, Texas, 77381 Data Submittal Extension Request Makana Bender/MeredithGuhl RECEIVED AOGCC (Alaska Oil and Gas Conservation Commission) 333 West 7th Avenue, Suite 100 JUN 1 0 701,5 Anchorage, AK 99501 907-793-1225 AOGCC REFERENCE: Qugruk-301(API: SO -103-20700.00-00; PTO: 214-199) Information: DST Fluid Samples As of May 2015, Qugruk-301 DST Fluid samples are not ready for submission. With this letter, Repsol is requesting an official Extension for the corresponding submission. The following analyses are planned to be performed in the Weatherford laboratory, Houston, TX: • Single -stage flash • Constant composit on expansion • Differential liberation • Separator test • Viscosity measurements The estimated time for the submission of these data will be: September 2016. Jansen Dantas de Oliveira will be responsible for the updated status of the mentioned studies. Please confirm that the extension is approved by signing in the space provided below and returning one (1) copy of this letter to the undersigned. Sincerely yours, n n a, a Oliveira Re rvoir engineer Ja nsen.da ntas@ repsol.com 832-442-1412 Extension to September 2016 is approved this 2_5 day of 2015. By AOGCC REPWOL 214199 Repsol E&P USA Inc. 2455 Technology Forest Boulevard The Woodlands, Texas, 77381 Data Submittal Extension Request Makana Bender/Meredith Guhl AOGCC (Alaska oil and Gas Conservation Commission) ����` vL� 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1225 JUN 10 2015 AOQQQ REFERENCE: Qugruk-301 (API: 50-103-20700-00-00; PTD: 214-199) Information: Isotubes Analyses As of May 2015, the Qugruk 301 Isotubes analyses are not ready for submission. With this letter Repsol is requesting an official Extension for the corresponding submission. The laboratory has not defined a date for the Isotubes analyses yet. However, we are planning to perform the following analyses: Isotopic / Compositional Carbon isotope Hydrogen isotope The estimated time for the submission of these data will be: April 2016. Please confirm that the extension Is approved by signing In the space provided below and returning one (1) copy of this letter to the undersigned. Sincerely yours, Juan Aluja eo oglcal Operations Manager jalujav@repsol.com (832) 442 0553 Extension to April 2016 is approved this day of 2015. By AO C REC�I'VED MAY 15 2015 AOGCC AW REPlOL May 5, 2015 Alaska Oil and Gas Conservation Commission 333 West 7fl' Avenue, Suite 100 Anchorage, AK 99501 RE: 10-407 Well Completion Report: Repsol Qugruk 301 PTD 214-199 Dear Commissioner: Repsol hereby submits the 10-407 Well Completion Report for the permanent abandonment of Qugruk 301, permit to drill 214-199. Qugruk 301 was spudded 2/18/2015, and a total depth of 7,531' MD / 4145' TVD was reached on 3/17/2015. Final wellbore abandonment was completed on 4/25/2015. Pertinent information attached to this report includes the following: 1. Form 10-407 Well Completion Report 2. As Built 3. Final Wellbore Schematic 4. Daily Operations Summary 5. Final Directional Survey Report & Plots 6. Casing and Cementing Reports 7. Detailed Test Information 8. Photo of Abandonment Marker 9. Photo of Dirt Mound Additional Geological information will be submitted separately. The AOGCC is requested to treat as confidential all information included. If you have any questions or require additional information, please contact myself at 832- 442-1618, or Mike Quick at 907-375-6933. Sincerely, 0) Bob Jones Drilling Manager Repsol USA NO LONGER CONFIDENTIAL OCT 0 8 2019 STATE OF ALASKA ( ALASKA OIL ANn r;ACZ cnniQrIQVATlnnl rnKAKAIC RECEIVED MAY 15 2015 VVIVIV WELL COMPLETION OR RECOMPLETION REPORT'A lei. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑� Suspended❑ lb. Well Class: 20AAC 25.105 20AAC 25.110 GINJ ❑ o. of WINJ ❑ WAGE] WDSPL ❑ No. C 2. Operator Name: 6. Date Comp., Susp., or Repsol USA Abend.: 4/25/2015 3. Address: 7. Date Spudded: Development E]Exploratory ❑J I Service ❑ Stratigraphic Test ❑ 14. Permit to Drill Number / Sundry: 214-199/3i5y1/7 3/S -2c) 15. API Number: 3800 Centerpoint Dr. Suite 400, Anchorage, AK 99503 2/18/2015 50-103.207-00-00 , 4a. Location of Well (Governmental Section): Surface: 1728' FEL, 1813' FSL, Sec. 6, TI IN, R6E, UM Top of Productive Interval: 1731' FEL, 2517' FSL, Sec. 6, T11 N, R6E, UM 8. Date TD Reached: 3/17/2015 16. Well Name and Number: Ougruk 301 9. KB (ft above MSL): ,2TST, T. Field / Pool(s): GL (ft above MSL): 17 Wildcat - Total Depth: 600' FEL, 454' FSL, Sec. 31, T12N, R6E, UM 10. Plug Back Depth MD/TVD: 18. Property Designation: 0 ADL 391445, 391455 4b. Location 6f Well (State Base Plane Coordinates, NAD 27): Surface: '�\ x- 412954 y- 5972299 Zone- 4 TPI: x- 412956 y- 5973002 Zone- 4 Total Depth: x- 414112 y- 5976205 Zone- 4 11. Total Depth MD/TVD: 7531' MD / 4145' TVD - 19. Land Use Permit: LAS 28269 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: 1090' MD / 1090' TVD 5. Directional or Inclination Survey: Yes E(attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) Ti. Re-drillyLateral Top Window MD/TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, clipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary GR, Res, Density, Neutron, IPWD/APWD, DHECD, LIST 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 20" 131# J-55 0 103 0 103 26" 6 cubic yards N/A 13-3/8" 68# L-80 0 2107 0 2107 16" Lead -450 sx/Tail-318 sx N/A 9-5/8" 47# L-80 0 5241 0 4185 12.25" Stagel-326 sx/Stage2.463 sx N/A 4-1/2" 12.75# L-80 4553 7495 4063 4148 6.5" None N/A 24. Open to production or injection? Yes No 25. TUBING RECORD If Yes, list each interval open (MD/TVD of Top a..d Bottom; Perforation Size and Number):S.� Q.alf! �._+ ,.,,._,$,._,_., SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Un -cemented liner: Top = 5 / 4185' TVD } Bottom = / 41 TVD (� Was hydraulic fracturing used during completion? Yes No Per 20 AAC 25.283 (i)(2) attach electronic and printed information ( I_, - DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 5241'- 7531' MD 7,291 Bbls Guar/Borate X-linked fluid w/ 755,000lbs 16.20 resin coated proppant 27. PRODUCTION TEST Date First Production: 3/28/2015 900 Method of Operation (Flowing, gas lift, etc.): Date of Test: 4/1/2015 Hours Tested: 255.5 Production for Test Period Oil -Bbl: 24844 Gas -MCF: 7.17 Water -Bbl: 0 Choke Size: 16-128 / 64" Gas -Oil Ratio: N/R Flow Tubing Press. 429 psi Casinq Press: Calculated 24 -Hour Rate --Jo� Oil -Bbl: 2333 Gas -MCF: 0.673 Water -Bbl: 0 Oil Gravity -API (corr): 30.4' Form 10-471 �vls gjig0j� b .�5. ilS GUN I INUED UN PAGE 2 -- VV11 Submit ORIGINAL 0 RBD1 1 1 2015 8. CORE DATA Conventional Core(s� Yes ❑ No Q Sidewall Cores: Yes ❑ No Q Yes, list formations and intervals cored (MD/TVD, : dTo), and summarize ldhology and presence of oil, or water (submit separate pages with this form, needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results 20 AAC 25.071. per 9. 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. Phone: 832442-1618 Date: 5/7/2015 ennafrost - Top 0 0 Attach separate pages to this form, if needed, and submit detailed test ennafrost - Base 1090 1090 information, including reports, per 20 AAC 25.071. Schrader Bluff 930 930 r'1___Upper On March 27, 2015, a 6 stage fracture treatment was performed in the 0-301 MCU/Lower Schrader Bluff 2023 2023 horizontal lateral. The 6 frac stages were equally spaced over 2240' of the 4 - Lower Schrader Bluff MFS 2223 PP43 1/2" uncemented liner. 755,000 lbs of resin coated 16-20 Carbobond Lite ISP Tuluvak 2455 2454 was placed in the formation with 7,291 Bbls of x -linked Guar/Borate fluid. Nanushuk 4042 3814 Following a 16 hour shut-in, the well was opened to the choke manifold at 08:46 on the 28th with a shut -in tubing pressure of 147 psi. Coiled tubing (CT) was then used to inject N2 at various depths for lift assistance. First oil was observed at 14:30 on the 28th and by 10:30 on the 29th the water cut was 48%. At that point the N2 assist was terminated and the CT was pulled out of the hole. The well was then produced with variable choke settings between 32/64" and 60164" until 14:00 on the 31st at which time it was shut-in at the choke due to storage limitations and phase 3 conditions. At the time of shut-in, the well had produced 5,035 Bbls of crude, 2.07 MMscf of gas and enation at total depth: Nanushuk recovered 2,454 Bbls of frac fluid. At 19:00 on the 1st of April the well was put back on production and tested for 255.5 hours with fixed choke sizes ranging from 16/64" to 128/64" with an average FTP of 429 psi. During the test the well produced 24,844 Bbls of 30.4" crude with 7.17 MMscf of 0.67 sg gas and recovered an additional 642 Bbls of seawater based frac fluid. On April 12th at 11:00 the well was shut-in downhole for 53.5 hours to perform a pressure build-up test. Following the PBU the well was produced for an additional 9 hours on a 32/64" fixed choke before terminating the test. A total of 30,418 BUS of crude, 9.41 MMscf of gas and 3,096 Bbls of recovered frac fluid were Final Schematic, Daily Operations Summary, Deviation Survey & Pfots, As Built, Flowback Report, Well Cap and Mound Photos to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, ical report, production or well test results, per 20 AAC 25.070. ( certify that the foregoing is true and correct to the best of my knowledge. Contact: Mio Qui 07-317-2969 Email: robert.jones@repsol.com d Name: Lob J Title: Drilling Manager ignatu Phone: 832442-1618 Date: 5/7/2015 General: )kis form and the required attachments provide a complete and concise record for each well drilled 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. All laboratory analytical Item 1a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water-Altemating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records 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, 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. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, 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. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2015 Submit ORIGINAL Only Qugruk 301 Final Schematic 26" Hole �i 20" 131# J-55 Conductor @ 101' MD I: I I: 'I Bridge Plug @ 280' MD I" I with cement to surface. f I I' I f a I:: I 1� 16 " Hole 10.4 1 pp9 I. KWF .I I" I 13-3/8" 68# L-80 Casing 210T MD Bridge Plug @ 2207' MD with 22 bbls (107sx/300ft) cmt on top. " Intermediate Stage 2: Stage tool @ 3,008' MD 12-1/." Hole 10.4 pp `,�--- TOC @ 3,810' MD CONFIDENTIAL NO LONGER CONFIDENTIAL OCT 0 8 2019 KWF � 9-5/8" 47# L-80 Casing @ 5,241' MD / ` 4,185' TVD 4w REPlOL Rig 105 RKB: 20' Q-301 Elevation w/ Pad Thickness: 17' KB to MSL: 37' Bull Nose Guide Shoe 7,495' MD EZSV @ 4503' MD;{ Squeeze 48.5 bbls Class ` --- ---- ___ ____ __ ____ I� —TD@7,531'MDI G cmt below. L==- 4,145' TVD With 22 bbls (107sx/ 300ft) cmt on top. Expandable Liner 4 1/2" 12.6# L-80 TC -ll 6 1/2" Hanger w/ Seals Un -cemented Liner Hole @ 4,553' MD / 4,063' TVD Prepared By D. Ross /A. Dial GRAPHIC SCALE o mo 1,a 1 inon -120 It r �$ VA PAD ( / J SURVEYOR'S CERTIFICATE I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING IN WE STATE OFALALU AND THATTMS CERTIFIGTION IS LIMBED TO THE WELL CONDUCTOR LOCATION ONLY. ALL OTHER INFORMATION SHOWN IS APPROAWM GEOGRAPHIC COORDINATES PRE NAD 83 �E( 9� GUG,UK80 j / ,4 o L ,2 7 A 0 ¢ 9. CONDUCTOR LOCATION NA083ASPZOW4 LAT=7020'01.86' N LONG=150'42'33.47 W Y = 5,972.047.28 X 1,552,986.76 0D27ASP20NE4 LAT=7020'03.01' N LONC�150'42'22.19" W Y = 5,972,299.03 X = 412,953.93 NAD27 U ZONE B METERS LAT=7020'03.01' N LONG 151742P22.19" W Y - 7,807,204.73 X - 360,867.61 PRIMARY LOCATION LOCATED WITHIN PROTRACTED SEC 6. TIM R6E, U.M. 1813' F.S.L. 1728' F.E.L. SURFACE ELEVATION TOP OF TUNDRA ELEVATION 16'm TOP OF ICE ELEVATION = 17't NOTES' 1. ELEVATONS SHOWN ARE NAVD 88 PER GECID 2012A DERNfD FROM CPS OBSERVATION. lL0[Ml QUGRUK NO. 301 RIG PAD IA T LOQkT SECnON 8, T1DIN FEE, UALwre0,/20120,5 "�''1"=,20'"1°:nA A°"0 MUOR1Ol Tw -. „, ,..,.�N.. REPlOL oRANNG m�Tonnwo FIGURE 1 OF 1 1. Qugruk 301 Daily Operations Summary API: 50-103-20700-00-00 Permit #: 214-199 Rig: Nabors 105 CONFIDENTIAL Date and Footage Drilled as of 24:00 hours. Activity REPlOL 14 February 2015 Continue Rig Up. Perform tests on PVT, Koomey & Diverter— all tests good. 0' Tests witnessed by AOGCC Rep, Chuck Scheve. 15 February 2015 Continue Rig Up. 0' 16 February 2015 Continue Rig Up. 0' 17 February 2015 Continue Rig Up. Replace knife valve. Retest diverter system — good test (knife 0' valve opened in 17 seconds, annular closed in 34 seconds). Witness waived by AOGCC Rep, Jim Regg. 18 February 2015 TD: 225'; Mud Weight: 9.8ppg; Viscosity: 80; Pick up Cleanout BHA, tag 805' cement @ 98'. Spud well @ 03:00hrs 2/18/2015. Drill from 98' to 225'. POOH with cleanout BHA. PU BHA #2 with LWD/MWD tools. Drill from 225'to 903'. 19 February 2015 TD: 2115'; Mud Weight: 10.Oppg; Viscosity: 90; Drill from 903' to 1225', max 1212' gas 7650u. Drill from 1225' to 1318', max gas 9510u. Drill from 1318' to 2115' (TD), max gas 230u. CBU, flow check — well static. POOH with BHA, no tight spots. LD BHA. 20 February 2015 TD: 2115'; Mud Weight: 10.0ppg; Viscosity: 90; Finish LD BHA. RU to run 0' casing. Run 13-3/8" 68# L-80 BTC surface csg to 1360'. 21 February 2015 TD: 2115'; Mud Weight: 10.Oppg; Viscosity: 90; Finish running 13-3/8" 68# L-80 0' BTC casing, shoe depth @ 2107' MD. RD casing running equipment. RIH with �( stinger on 5" drillpipe. Sting in to stab -in float collar. Circulate BU. RU cement equipment and test lines to 2000 psi. Mix and pump 450 sx (240 bbls) of 10.7ppg Permafrost L lead cement, get 60 bbl of lead cement to surface, lose returns. Reduce rate and pump additional 47 bbls, no returns. Mix and pump 318 sx (72.3 bbls) of 15.8ppg Class G cement with minimal returns, floats held. RD cement equipment. '%G e Ifo' ( it b---�` 22 February 2015 TD: 2115'; Mud Weight: 10.Oppg; Viscosity: 65; CBU to flush inner string. 0' Displace Spud mud with 10.4ppg MOBM. POOH with inner string. Begin ND diverter system. 23 February 2015 TD: 2115'; Mud Weight: 10.4ppg; Viscosity: 93; Finish ND diverter system. RIH 0' with 1" grout string and tag existing cement at 40'. Perform 13-3/8" too mob. mix and pumped 6 bbls (7.7 sx) Permafrost cement (had returns at surface at 4.3 bbl pumped). Collected wet and dry samples as per AOGCC request by Bob Noble. Verbal approval for top job granted by AOGCC rep, Jim Regg. 24 February 2015 TD: 2115'; Mud Weight: 10.4ppg; Viscosity: 93; Nipple up wellhead. Nipple up 0' BOPE. 25 February 2015 TD: 2115'; Mud Weight: 10.4ppg; Viscosity: 93; Continue nipple up BOPS. 0' 26 February 2015 TD: 2115'; Mud Weight: 10.4ppg; Viscosity: 78; Continue nipple up BOPE. 0' Function test rams & choke. BOPE tests 250 psi low and 5000 psi high, completed 11 of 13 tests —good. BOPE Test witnessed by AOGCC Rep, John Crisp. 27 February 2015 TD: 2115'; Mud Weight: 10.4ppg; Viscosity: 78; Repaired IBOP & valve #8, 0' retested same 250 psi low and 5000 psi high — good. Rigged down BOPE test equipment. PU 12-1/4" directional BHA. 28 February 2015 TD: 2115'; Mud Weight: 10.4ppg; Viscosity: 78; Continue PU 12-1/4" 0' directional BHA and TIH to 1946'. Circulate while waiting on weather. 1 March 2015 TD: 2145'; Mud Weight: 10.4ppg; Viscosity: 100; Continued circulating while 30' waiting on weather. TIH and tag float collar. Test casing to 2500 psi for 30 minutes — good. Drilled cement, float collar, shoe track and rat hole to 2115'. Drill 30' new formation from 2115' to 2145' MD. 2 March 2015 TD: 3477'; Mud Weight: 10.4ppg; Viscosity: 73; Perform LOT to 13.7 PPR EMW. 1332' TIH to 2145'. Drill from 2145'to 3477' MD, max gas 926 u. 3 March 2015 TD: 4148'; Mud Weight: 10.4ppg; Viscosity: 73; Continue drilling from 3477' to 671' 3670' MD/3557' TVD (41 deg inclination). Circulate. POOH to 2041', no tight spots. TIH to 3477'. Drill from 3477' to 4148' MD, max gas 810 u. Circulate while waiting on weather. 4 March 2015 TD: 4927'; Mud Weight: 10.4ppg; Viscosity: 73; Continue circulating while 779' waiting on weather. Drill from 4148' to 4927' MD, max gas 1337 u. 5 March 2015 TD: 5248'; Mud Weight: 10.4ppg; Viscosity: 80; Continue drilling from 4927' to 321' 5248' MD/4185' TVD (TD — 90 deg inclination). Circulate. POOH to 3477', no tight spots. TIH to 5248'. Circulate BU. POOH to 4730'. 6 March 2015 TD: 5248'; Mud Weight: 10.4ppg; Viscosity: 98; Continue POOH with BHA and 0' lay down same. Retrieve wear bushing — no damage or excessive wear noted. Installed 9-5/8" casing rams, tested 250 psi low / 3500 psi high — good. Rig up casing running equipment. Approval received for BOPE test extension from AOGCC Rep, Jim Regg. 7 March 2015 TD: 5248'; Mud Weight: 10.4ppg; Viscosity: 148; Continue rigging up casing 0' running equipment. Run 9-5/8" 47# L80 casing to 4565' MD, full returns throughout. 8 March 2015 TD: 5248'; Mud Weight: 10.4ppg; Viscosity: 113; Continue running 9-5/8" 47# 0' r L80 casing, land casing with shoe depth of 5235' MD. Rig up cementing (S equipment. Pump Stage 1: 60 bbls 11.Oppg Spacer, followed by 89 bbls (326sx) '14.0 ppg Class G cement, displaced with 155 bbls 10.4 ppg MOBM, 20 bbls 11.0 ppg Spacer, and 204 bbls 10.4ppg MOBM, with full returns. Plug did not bump, floats held. ETOL at 4000' MD. Open Stage tool at 3008' MD. Circulate through stage tool while WOC. Witness of upcoming BOPE test waived by AOGCC Rep, Matthew Herrera. 9 March 2015 TD: 5248'; Mud Weight: 10.4ppg; Viscosity: 98; Continue circulate while WOC. 0' Pump Stage 2: Pump 60 bbls 11.0 ppg Spacer, followed by 187 bbls (463 sx) of 12.2 ppg Type I/II Cement, displaced with 226.7 bbls of 10.4ppg MOBM, with full returns. Closed stage tool. ETOC at 300' MD, RD cementing equipment. RU to test BOPE. 10 March 2015 TD: 5248'; Mud Weight: 10.4ppg; Viscosity: 90; Finish RU to test BOPE. Test 0' BOPE, 250 psi low / 5000 psi high — 6 of 16 tests complete. 11 March 2015 TD: 5248'; Mud Weight: 10.4ppg; Viscosity: 88; Continue to test BOPE. Test 0' BOPE, 250 psi low / 5000 psi high —16 of 16 tests complete. 12 March 2015 TD: 5248'; Mud Weight: 10.4ppg; Viscosity: 90; Rig down BOPE test 0' equipment. PU 8-1/2" bit and cleanout BHA. RIH to 2686'. Test 4" and 5" safety valves. POOH to 2000' and hang off from test plug. Retest BOPE (Tests 12 through 15), 250 psi / 5000 psi high (annular 2500 psi high) — tests good. Rig down BOPE test equipment. 13 March 2015 TD: 5248'; Mud Weight: 9.3ppg; Viscosity: 99; TIH with cleanout BHA to 3008' 0' MD. Drill out stage tool. Continue to TIH to 5010' MD, tag cement. Displace mud from 10.4 ppg MOBM to 9.3 ppg MOBM. Test 9-5/8" casing to 4500 psi for 30 min — good. 14 March 2015 TD: 5278'; Mud Weight: 9.3ppg; Viscosity: 95; Drill out shoe track and rat hole 30' to 5248' MD. Drill 30' of new formation with 8-1/2" hole from 5248' to 5278' MD. Conduct FIT test to 12.0 ppg EMW —good. POOH and lay down BHA. RU wireline. 15 March 2015 TD: 5278'; Mud Weight: 9.3ppg; Viscosity: 99; RIH with USIT cement 0' evaluation log. TOC at 3810' MD. RD wireline. PU 6-1/2" bit and MWD/LWD BHA. RIH to 5230' MD. 16 March 2015 TD: 6880'; Mud Weight: 9.3ppg; Viscosity: 97; Wash from 5230' to 5278' MD. 1602' Drill from 5278' to 6880' MD, average gas 300u. 17 March 2015 TD: 7531'; Mud Weight: 9.3ppg; Viscosity: 95; Continue to drill from 6880' to 651' 7531' MD / 4146' TVD (TD of horizontal, 91 degree inclination), max gas 517u. T;D Circulate and condition mud, flow check. Wiper trip from 7531' to 5169' MD, circulate. Flow check. TIH to 7531' MD, no tight spots. POOH from 7531' to 5815' MD. 18 March 2015 TD: 7531'; Mud Weight: 9.3ppg; Viscosity: 110; Continue to POOH from 5815' 0' MD, lay down BHA. PU/MU 6-1/2" cleanout BHA (z -bit) and TIH to 5235' MD. Hang off from test plug. RU BOPE test equipment. Test BOPE 250 psi / 5000 psi high (annular 2500 psi high) —8 of 18 tests good. Witness of BOPE test waived by AOGCC rep, John Crisp, however timing allowed him to witness. 19 March 2015 TD: 7531'; Mud Weight: 9.3ppg; Viscosity: 110; Continue to test BOPE 250 psi 0' / 5000 psi high (annular 2500 psi high) —18 of 18 tests good. RD BOPE test equipment. CBU at 5235' MD. TIN from 5235' to 7531' MD. Displace lateral from 9.3ppg MOBM to 9.4ppg completion fluid. 20 March 2015 TD: 7531'; Mud Weight: 9.4ppg; POOH to 4604' MD. Displace from 4604' to 0' surface with 9.4ppg completion fluid. POOH to surface and lay down cleanout BHA. PU liner hanger. RU casing equipment. RIH with 4-1/2" 12.75# L80 TCII liner to 1127'. Pressure test liner to 2000 psi for 10 mins — good. Continue RIH with 4-1/2" lower completion to 2032' MD. Stimulation and Completion Sundry 315-147 Approved by AOGCC Rep, Cathy Forester. 21 March 2015 TD: 7531'; Mud Weight: 9.4ppg; Continue RIH with 4-1/2" lower completion 0 and liner hanger on 5" drill pipe to 7531' MD (TD), no losses. Drop ball and pressure up liner to 2000psi —good. Drop liner setting ball and pressure up, liner hanger set depth at 4553' MD / 4063' TVD Pressure test 9-5/R" cecina and 4-1/2" liner, 250psi low / 3900 psi high — good. POOH with 5" drill pipe. 22 March 2015 TD: 7531'; Mud Weight: 9.4ppg; Continue POOH with 5" drill pipe and liner 0 setting tool. Installed 3-1/2" casing rams, tested 250 psi low / 3500 psi high — y good. AOGCC witness of ram test waived. RU Casing equipment. RIH with 3- 1/2" 9.4# TCII tubing and seal assembly to 1219' MD. 23 March 2015 TD: 7531'; Mud Weight: 9.4ppg; Pressure test tubing to 4500 psi —good. 0 Continue RIH with 3-1/2" 9.4# TCII tubing to sealbore, pressure test tubing to 4500 psi @ 1219', 3679', and 4508' —good. 24 March 2015 TD: 7531'; Mud Weight: 9.4ppg; Space out and land tubing hanger. Pressure 0 test hanger to 5000 psi — good. Pressure test annulus to 2500 psi — good. Set BPV and ND BOPE. 25 March 2015 TD: 7531'; Mud Weight: 9.4ppg; NU IN Frac tree, test to 7000 psi – good. RU 0 Frac equipment. RU Coiled Tubing Unit and BOP. RU testing equipment. 26 March 2015 TD: 7531'; Mud Weight: 9.4ppg; Test coiled tubing BOPE, 250 psi low / 3500 0 psi high – good. AOGCC Rep, Matthew Herrera, waived witness for BOP test. Perform DFIT. Pump Mini -frac, 57 bbls of linear gel and 184 bbls of cross- ,f) linked gel at 30 bpm. Evaluate data. C-y'W � 27 March 2015 TD: 7531'; Mud Weight: 9.4ppg; Viscosity: 130; Perform 6 stage frac. Pumped a -Y'a'- 0 total of 755,000 lbs of proppant. Frac performed successfully. 28 March 2015 TD: 7531'; Mud Weight: 9.4ppg; Viscosity: 130; Open well and flow test. RIH 0 with coiled tubing and begin N2 lift assist. 29 March 2015 TD: 7531'; Mud Weight: 9.4ppg; Viscosity: 130; Continue flow test with N2 lift 0 assist. POOH with Coiled tubing and rig down same. 30 March 2015 TD: 7531'; Mud Weight: 9.4ppg; Viscosity: 115; Continue flow test. 0 31 March 2015 TD: 7531'; Mud Weight: 9.4ppg; Viscosity: 130; Continue flow test. Shut in well 0 and monitor pressures. 1 April 2015 TD: 7531'; Mud Weight: 9.4ppg; Viscosity: 126; Continue to monitor shut in 0 pressures. Open well and continue flow test. 2 April 2015 TD: 7531'; Continue flow test. 0 3 April 2015 TO: 7531'; Continue flow test. 0 4 April 2015 TD: 7531'; Continue flow test. 0 5 April 2015 TD: 7531'; Continue flow test. 0 6 April 2015 TD: 7531'; Continue flow test. 0 7 April 2015 TD: 7531'; Continue flow test. 0 8 April 2015 TD: 7531'; Continue flow test. 0 9 April 2015 TD: 7531'; Continue flow test. 10 April 2015 TD: 7531'; Continue flow test. 11 April 2015 TD: 7531'; Continue flow test. 12 April 2015 TD: 7531'; Continue flow test. Shut in well — monitor pressures. 13 April 2015 TD: 7531'; Well shut in — monitor pressures. 14 April 2015 TD: 7531'; shut in —monitor pressures. Open select -tester valve. Continue 0 flow test. 15 April 2015 TD: 7531'; Shut in well. RU for well kill operations. Kill well with 160 bbls of 0 9.4ppg KWF. Flow check— static. Close well at flow cross and HCR. RD CTU, BOP, and riser. Blow down production system with nitrogen. Flow check— static. Bleed off 3-1/2" x 9-5/8" annulus pressure. Close select -tester valve. Install BPV. ND Frac tree and remove tubing bonnet. Install test dart in tubing and NU BOPE. Witness of upcoming BOPE test waived by AOGCC Rep, Matthew Herrera. 16 April 2015 TD: 7531'; Mud Weight: 9.4ppg; Viscosity: 153; Continue NU BOPE. RU BOPE 0 test equipment. Test BOPE 250 psi / 5000 psi high (annular 2500 psi high) — good. RD BOP test equipment. MU 3-1/2" tubing landingjoint. Unsting seal assembly from seal bore. Displace SFMOBM with 280 bbls of 9.4 ppg MOBM. Flow check — losing 20 bph. Sting back into sealbore. Pump (2) LCM pills, check for losses after each. Losses reduced to 8.4 bph. 17 April 2015 TD: 4503'; Mud Weight: 10.4ppg; Viscosity: 153; Pump 3`d LCM pill, check for 0 losses — maintaining 8.3 bph. POOH with 3-1/2" completion string with losses. reducing to 4 bph. PU 9-5/8" cement retainer and TIH on 3-1/2" tubing. Set cement retainer at 4503' MD. Set down with 10K lbs to confirm set. 18 April 2015 TD: 4203'; Mud Weight: 10.4ppg; Viscosity: 157; RU cementing equipment. 0 Establish injection rate at 3 bpm. Mix and pump 15 bbls of Tuned Spacer at 11.5 ppg; 234 sx (48 bbls) of 15.8 ppg Class G cement followed by 2 bbls of `.) Tuned Spacer at 11.5 ppg and 39 bbls 10.4 ppg MOBM. Un -sting from retainer and circulate 10.4 ppg MOBM displacing the 9.4 ppg SFMOBM. Mix and pump CM 17.5 bbls of Tuned Spacer at 11.5 ppg; 107 sx (22 bbls/300') of 15.8 ppg Class G cement, followed by 2.5 bbis of Tuned Spacer at 11.5 ppg and 36 bbls of 10.4 C ppg MOBM. POOH to 3900'. Pressure test to 1500 psi for 30 min,— good, witnessed by AOGCC rep, Matt Herrera. POOH. 19 April 2015 TD: 0'; Mud Weight: 10.4ppg; Viscosity: 160; PU 9-5/8" bridge plug and set at 0 2207'. Set down with 10K lbs to verify set. Mix and pump 17.5 bbis of Tuned Spacer at 11.5 ppg followed by 22 bbls (107 sx/300') of 15.8 ppg Class G cement on top of bridge plug. POOH. PU 9-5/8" bridge plug and set at 280'. Set down with 10K lbs to verify set. Mix and pump 15 bbls of Tuned Spacer at 11.5 ppg followed by 18.3 bbls of 15.8 ppg Class G cement on top of bridge plug. Spacer and 2 bbls cement to surface. POOH. 20 April 2015 TD: 0'; RD cement equipment. ND BOPE & wellhead. Begin Demob. 21 April 2015 TD: 0'; Cut off wellhead. Top off cement in casing stubs. Continue demob. 22 April 2015 TD: 0'; Continue demob. 0 23 April 2015 TD: 0'; Continue demob. AOGCC inspection planned for April 25 for approval 0 to weld on 20" cap. 24 April 2015 TD: 0'; Continue demob. 25 April 2015 TD: 0'; Continue demob. AOGCC Rep, Bob Noble, inspected cement and stubs / 0 and approved installation of well abandonment marker. P&A marker cap welded in place, cellar removed, hole backfilled and mounded. 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P1^^ s1ffi1 0 il0 5181$ 1116 0 ^ b 0 N p O S y �l d Q tE 3a4mR RA�� �2Rs9 g000 •3 I 89 nR£RR RRkn ey �g�g� 3m yyNyyNN saaaa .oaa $ a«ar'a as �aaa am w A a os.'�oe�we aava a.a. o= a ;:-$ R rm1 waRm m8im8. rc 3 b E s' T E ££ ti iK 0 P g e� a�a"s y mee "oo ' �RRR���RRRR oo o'o'o o'o'o oo mm"dao 8a�' RRRRRRRRRRR 53222'?42'22 „ mrn�� o' ooaoo ow' P AAR �si mi =doeoeo3 °�30 u e m' rtymy�1O�'m �N ml yyNyyNN saaaa .oaa $ a«ar'a as �aaa am w A a os.'�oe�we aava a.a. o= a ;:-$ R rm1 waRm m8im8. rc 3 b E s' T E ££ ti iK 0 P yyNyyNN saaaa .oaa $ a«ar'a as �aaa am w A a os.'�oe�we aava a.a. o= a ;:-$ R rm1 waRm m8im8. rc 3 b E s' T E ££ ti iK Scmmherger Repsol BeleM1e4: Wall: FeNI: StNdMR: Qugruk-301 Qugruk-301 Qugruk Qugruk-301 d..irva Npnu..r.nuu,. t.ae„ .0 o< BaaMAla dP'80. u. 1.,. ..ad�O N,rtta,yliiNOnV Ge anv. 9q5 6bF.I TgnFNI 1VORal. R—"..dam W ." M. c0 1RMY II .a Ta.,1. 1 ]laa,le.WWf Be.Wl afI.Q I.. ..ft:pu9rux.Wl anent -3750 -000 -2250 -1500 -750 0 750 1500 2250 5250 5250 Ougmk 3A 45W 4500 ougmk-301(P 6)update Ougmk-3 1 current 37W 37550 3000 Pgm '.. mlad.paN 3U50 acaal elaW'.i NaaOEmill] 2250 22W G59 ID vO a1 'adt W •rv.11&Wrt Ik1JBt E=]N BW21D a2a,. St. 1s00 .pro " 1500 750 750 "'ac 07.2+drv0 axslro am2115MD2115ry IF.25 E=10 Od'Otl11B R'ss a5 E-10 0 0 ognx> -750 ap.xu -050 aP..n. �anrw• Qugmk 3 500 -1500 -3750 -000 -2250 -1500 -750 0 750 1500 2250 M(R)Scale= 1:1030(R) Schlumherger Repsol Borehole: Well: Field: Structure: Qugruk-301 Qugruk-301 Qugruk Qugruk-301 eriry aa4anal enmym "I '-E ae Biey fYm, brie d.Ja F«I MYeWemaue ]oy op: Bear u. rs enrb Ibul � m., a6m b: @grvnuf iyppl, wnynwgemm«M84 MBMe: I� fa: 1... 9. ..WNMW'� -850 0 850 1]00 2550 3400 4250 850 1]00 2550 34W 4250 z 5100 5950 6800 xsl m ausaovlsiw Ob]'M IRAIz'v A vuc aescem.p Ougmk-301(P1 )u Ougmk-301 cu n .IW ]YD Ngnb�bd Y pD]'u %a1 Mp 11K Tq -850 0 850 1700 2550 3400 4250 Vertical Section (1t) A im = 20° Scale = 1:1010(1Q Origin = ONI-S, OEI-W r1 50 700 550 400 date 250 100 350 WO Repsol CASING & CEMENTING REPORT Well No./ PTD If Ougruk 301 / 214-199 Date County Alaska State Alaska Supv. CASING RECORD - Surface casina TO 2115' MD /2115' TVD Shoe Depth: 2107' MD /210T TVD PBTD N/A 1 -May -15 Csg Wt. On Hook Cag Wt. On Sips: _ Fluid Description: Liner hanger Into(Make/M. Liner hanger test pressure: Centralizer Placement Type Float Collar: Type of Shoe: Stab -in Float No. His to Run: 30.5 Float Casing Crew: GBR pud Mud / PV=21 YP=16 uner top Pecker?: Yes X No centralizere on every joint from 1917 to 1678', every 3rd joint to 155' (.FMFNTINr RFPnRT Prefluah (Spacer) Casing (Or Liner) Datail Setting Depths No. of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe 133/8 BTC Halliburton 1.80 2,107.00 2,105.20 2 jts 133/8 68 L-80 BTC 84.83 2,105.20 2,020.37 F. Collar 133/8 BTC Halliburton 2.39 2,020.37 2,017.98 45 Its 133/8 68 L-80 BTC Type: 1,989.98 2,017.98 28.00 L Hanger Vetco 2.27 28.00 25.73 landin jt FOP (psi): Pump used for disp: Cement pumps Vetco 25.73 25.73 0.00 X No N Returns during job 100&0 Cement returns to surface? _Yes X Yea No Spacerretums? X Yes No Vol to Sud: 60 bbl cmt Cement In Place At 22:05 D_ate: 2/2112015 Estimated TOC: 40' Method Used To Determine TOC: TOC was tagged w1h 1 inch tubing at 40' before lop job was performed. Prefluah (Spacer) Totals Type: Density (ppg) 2,107.00 Lead Slurry Csg Wt. On Hook Cag Wt. On Sips: _ Fluid Description: Liner hanger Into(Make/M. Liner hanger test pressure: Centralizer Placement Type Float Collar: Type of Shoe: Stab -in Float No. His to Run: 30.5 Float Casing Crew: GBR pud Mud / PV=21 YP=16 uner top Pecker?: Yes X No centralizere on every joint from 1917 to 1678', every 3rd joint to 155' (.FMFNTINr RFPnRT Prefluah (Spacer) Type: Tuned Spacer III Density (ppg) 11 Volume pumped (BBLs) 80 Lead! Slurry Type: Permafrost Yield(Ft3/sack): 4.33 Density (ppg) 10.7 ppg Volume (BBLa/sacks): 230 bible 12% sacks Mixing/ Pumping Rate bpm): 4.5 Tail Slurry Type: Mitsubishi Class G Yield (FrYsil 1.16 a Density (ppg) 15.7 ppg Volume (BBLslsacks): 65.9 bbls/ 318 sacks Mixing / Pumping Rate (bpm): 3.7 m Post Flush (Spacer) a Type: Density(ppg) Rate(bpm): Volume: u Displacement: Type: Fresh Water Density (ppg) 8.33 Rate(bpm): 4.5 Volume (actual /calculated): 35.4 FOP (psi): Pump used for disp: Cement pumps Plug Bumped? X Yea No Bump press 590 Casing Rotated? _Yea X No Reciprocated? X No N Returns during job 100&0 Cement returns to surface? _Yes X Yea No Spacerretums? X Yes No Vol to Sud: 60 bbl cmt Cement In Place At 22:05 D_ate: 2/2112015 Estimated TOC: 40' Method Used To Determine TOC: TOC was tagged w1h 1 inch tubing at 40' before lop job was performed. Prefluah (Spacer) Type: Density (ppg) Volume pumped (681.$) Lead Slurry Type: Yield (Ft&sack): Density (ppg) Volume (BBLs/sacks): Mixing / Pumping Rate (bpm): Tail Slurry Type: Yield(Ft3/sack): w a Density (ppg) Volume (BBI s/sacka): Mixing / Pumping Rate (bpm): 0 Post Flush (Spacer) Type: Density (ppg) Rate (bpm): Volume: w N Displacement: Type: Density (ppg) Rata (bpm): Volume (actual / calculated): FOP (psi): Pump used for disp: Plug Bumped? No Bump press Casing Rotated? _Yes _No Reciprocated? —Yes _Yes —No % Returns during job Cement returns tosurface? _Yea No Spacer relums?_ _ Yes_ No Voito Sud: Cement In Place At Date: Estimated TOC: Method Used To Determine TOC: Well Nol PTO County Repsol CASING & CEMENTING REPORT Ougrek301/214-199 Data Alaska State Alaska Supv. CASING RECORD - Intermediate carina TO 5246'MD/4/85'TVD Shoe Depth: 5241' MD/ 4185' WD Q 54 PBTD: N/A -May-15 Csg Wt. On Hook Type Float Collar: Float No. He to Run: 36.5 COB WL On Slips: Type of Shoe: Float Casing Crew: GOR Fluid Description: f 0.4 ppg MOBM 1 PV = 34 YP -16 Uner hanger info (MakeMtodd): Liner top Pecker?: _Yes X No Lift, hanger test pressure: Centralizer Placement 1/g loom 5241'-2348'. Mile from 2100'-154'. Type: Tuned Spacer 111 Density(cog) 11 Volume pumped (BBLs) Lied Slurry Type: Mitsubishi Class G Density (ppg) 14 Volume (BBLs/sacks): Tail Slurry Typs: Density (Mg) Volume (BBLs/secini local Flush (Spacer) Yield 1. 89bb1 /326saclo,Mixing/ Pumping Rate(bpm): Yleld (Ft3/sack): Type: Water Density (ppg) 83 Rate (bpm): 4 Volume: Displace m roll Type: MOBM Density(ppg) MA Rate (bpm): 4 Volume(actual/cak:ulated): FCP (psi): 568 Pump used for dsp: rig pumps Plug Bunetl? _Yes X No Casing Rotated? _Yes X No Reciprocated? X Yes _No % Returns during job m Caent retuns to surface? Yes X No Spacer returns?_ Yes X No Vol to Sud: _ Cement In Plass At: 10:80 Date: 3/82015 Estimated TOC: _ IWM Used To Determine TOC: USIT ran on wireline Type: Tuned Spacer III Density (ppg) 11 Volume pumped (BBLs) Lead Slurry Type: Standard TWO dl Yield Density(pPg) 12.2 Volume (BBLsha,loi 187 blots Tell Slurry –� Typs: Yield Density(ppg) Volume (BBLshacks): Post Flush(Spacer) Bump press Mixing y Pumping Rate (bPm): J 60 60 Type: Water Density (pi 8.3 Rate (bpm): Volume: 5 bbls Displacement: Type: MOSM Density(ppg) 10.4 Rate bpm): 2.5 Volume (actual /caloulated): 2261bb1a FCP (psi): _Pump used for disp: rig pumps Plug Bumped? X Yes _No Bump press 245( Casing Rotated? _Yes X No Reciprocated? _Yes X No % Return during lob 100 Cement returns to surface? Yes X No Spacer mVa tums? X s —No Vol to Surf: WA Cement In Place At: 6:00 Data: 3/9/2015 Estimated TOC: 20' MD (Method Used To Deterntine TOC: TOC tagged after wellhead cutoff. Cement topped off for abandonment. , Remarks: Casing (Or Liner) Detail Selling Depths No. of Jts. Size WL Grade THD Make Length Bottom Top Shoe 9-5/8 BTC -M Halliburton 1.65 5,241.00 5,239.35 2 jts 9-5/8 47 L-80 BTC -M 81.67 5,239.35 5,157.68 F. Collar 9-5/8 BTC -M Halliburton 1.29 5,157.68 5,156.39 lit 9-5/8 47 L-80 BTC -M 40.86 5,156.39 5,115.53 Baffle collar BTC -NI Halliburton 1.29 5,115.53 5,114.24 53 jts 9-5/8 47 L-80 BTC -M 2,095.66 5,114.24 3,018.58 Stage collar 9-5/8 BTC -M Halliburton 3.74 3,018.58 3,014.84 75 jts 9-5/8 47 L-80 BTC -M 2,991.23 3,014.84 23.61 hanger BTC -M Vetco 4.08 23.61 19.53 lantling j[ Vetco 19.53 19.53 0.00 Totals 5,241.00 Csg Wt. On Hook Type Float Collar: Float No. He to Run: 36.5 COB WL On Slips: Type of Shoe: Float Casing Crew: GOR Fluid Description: f 0.4 ppg MOBM 1 PV = 34 YP -16 Uner hanger info (MakeMtodd): Liner top Pecker?: _Yes X No Lift, hanger test pressure: Centralizer Placement 1/g loom 5241'-2348'. Mile from 2100'-154'. Type: Tuned Spacer 111 Density(cog) 11 Volume pumped (BBLs) Lied Slurry Type: Mitsubishi Class G Density (ppg) 14 Volume (BBLs/sacks): Tail Slurry Typs: Density (Mg) Volume (BBLs/secini local Flush (Spacer) Yield 1. 89bb1 /326saclo,Mixing/ Pumping Rate(bpm): Yleld (Ft3/sack): Type: Water Density (ppg) 83 Rate (bpm): 4 Volume: Displace m roll Type: MOBM Density(ppg) MA Rate (bpm): 4 Volume(actual/cak:ulated): FCP (psi): 568 Pump used for dsp: rig pumps Plug Bunetl? _Yes X No Casing Rotated? _Yes X No Reciprocated? X Yes _No % Returns during job m Caent retuns to surface? Yes X No Spacer returns?_ Yes X No Vol to Sud: _ Cement In Plass At: 10:80 Date: 3/82015 Estimated TOC: _ IWM Used To Determine TOC: USIT ran on wireline Type: Tuned Spacer III Density (ppg) 11 Volume pumped (BBLs) Lead Slurry Type: Standard TWO dl Yield Density(pPg) 12.2 Volume (BBLsha,loi 187 blots Tell Slurry –� Typs: Yield Density(ppg) Volume (BBLshacks): Post Flush(Spacer) Bump press Mixing y Pumping Rate (bPm): J 60 60 Type: Water Density (pi 8.3 Rate (bpm): Volume: 5 bbls Displacement: Type: MOSM Density(ppg) 10.4 Rate bpm): 2.5 Volume (actual /caloulated): 2261bb1a FCP (psi): _Pump used for disp: rig pumps Plug Bumped? X Yes _No Bump press 245( Casing Rotated? _Yes X No Reciprocated? _Yes X No % Return during lob 100 Cement returns to surface? Yes X No Spacer mVa tums? X s —No Vol to Surf: WA Cement In Place At: 6:00 Data: 3/9/2015 Estimated TOC: 20' MD (Method Used To Deterntine TOC: TOC tagged after wellhead cutoff. Cement topped off for abandonment. , Remarks: Repsol CASING & CEMENTING REPORT Well Nol PTD q Ougruk 301 / 214-199 Date County Nasky Slate Alaska SUP, CASING RECORD- Liner TO 7531-MD/4145'WD Shoe Depth: T495'AID /414?'WD PSTD: Csg Wt. On Hook Csg Wt. On Slips: Fluid Description: liner hanger Into (Makell4c Dner hanger test pressure: Central Placement: WA Type: WA Lead! Slurry Grade Type Float Collar. Type of Shoe: 3900 Type: WA Density (ppg) Volume (BBLWsacks): Tell Slurry Type: WA Density(ppg) Volume (BBLWsacks): Poet Flush (Spacer) I -May -15 No. Hire to Ru: 27 Casing Crew GSR =20 Liner top Packer?: X Yea No (ppg) Volume pumped (BBLs) Yield (FWwck): Mining / Pumping Rate (bpm): Yield (Maack): Type: N/A Density(ppg) Rate (bpm): Displacement: Type: Density (ppg) Rate _ Volume (actual /calculated): FOP (psi): _Pump used for disp_Plug Bumped? _Yes _No Casing Rotated? _Yes No Reciprocated? _Yes _No %Seems during jo Cement rely ms losurface? _ Vas _No Spacer returns?_Yes _No Vol to Sud: _ Cement In Place At: Date: Estimated TOC: _ IMethod Used To Determine TOC: Volume: Bump press Type: Density (ppg) Volume pumped (BBLs) Lead Slurry _ Type: YeW (FWsack): Density (ppg) Volume (BBLskur ks): Mixing / Pumping Rate (bpm): Tell Slurry Type: Yield(FIZ/sack): DensM(ppg) Volums(BBLWsa<ks): Milting/ Pumping Rate(bpm): Post Flush (Spacer) Type: Water Density (ppg) Rate (bpm): Volume: Displacement: Type: Density(Ppg) Rate(bpm): _Volume (xWai/calculated): FOP (puri): Pump used for disp rig pumps _ Plug Bumped? Bump press Casing Rotated? _Yes No Reciprocated? _Yes _No Yen No % Returns during job Cement returns to surface? _Yes No Spacerreturns? Yes No Volt.Sud: Cement In Place At: Date: Estimated TOC: Method Used To Detentlne TOC: Remarks: LOWER COMPLETION TALLY Qugruk 301 AS BUILT Customer Repsol Field Exploration Company Reps David Ross Casing Liner SIZE WEIGHT GRADE I THREAD DEPTH 9.625 47 L80 BTC 5241.00 SIZE WEIGHT GRADE THREAD ID 4.5 12.6 L-80 TC -II 3.96 - Lease Qugruk SIZE WEIGHT GRADE THREAD ID REPlOI Mudwelght 9.4 Mud Type SFMOBF Drill Pipe#1 5 19.5 5-135 4-1/2" IF 4.28 Prepared By David Ross Cumm. Assy Stage Stage Jt# PJt# OD ID Length Depth Description Length Length Length # 7494.06 = Bottom Of Shoe 7531 0.00 - d s 4.933 N/A 1.00 7493.06 4-1/2" 12.6# TC -II Bull Nose Guide Shoe 1.00 < it 4.936 3.935 4.08 7488.98 4-1/2" 12.6#TC-II Perforated Pup it. 5.08 1 5.570 3.956 1.11 7487.87 4-1/2" 12.75# L80 EOE Box x 12.6# TC -11 Pin 6.19 5.870 3.880 2.83 7485.04 4-1/2" Mirage Plug 12.75#, L-80 EOE Box x Pin 9.02 2 3 5.009 5.012 3.952 3.964 1.10 12.26 7483.94 7471.68 4-1/2" 13.5# API -LC 8Rd Box x 4-1/2" 12.75 # EOE Pin 4-1/2" 13.5# API -LC 8Rd Bax x Pin 10.12 22.38 DFIT 5.018 3.880 1.52 7470.16 4-1/2" Shut -Off Collar 13.5#, L-80 8Rd Box x Pin 23.90 4 4.935 3.940 12.01 7458.15 4-1/21112.6# TC -11 Box x 4-1/2" 13.5 # 8Rd Pin 35.91 5 4.936 3.936 7.83 7450.32 4-1/2" 12.6# TC -11 Box x Pin 43.74 _ 5.604 3.960 3.34 7446.98 4-1/2"Rapid Start Initiator Sleeve 12.6#, L-80 TC -II Box x Pin 47.08 5.604 3.954 3.20 7443.78 4-1/2"Rapid Start Initiator Sleeve 12.6#, L-80 TC -II Bax x Pin 50.28 6 4.937 3.925 7.79 7435.99 4-1/2" 12.6# TC -II Box x Pin 58.07 1 4.940 3.958 31.92 7404.07 4-1/2" 12.6# L80 TC -11 LinerJt 89.99 4.940 3.904 18.98 7385.09 4-1/2" 12.6# L80 TC -11 Pin 108.97 - 5.824 3.904 1 16.48 7368.61 5.85 OD Oil Swellable Packer Element 125.45 4.940 3.904 1 4.86 7363.75 4-1/2" 12.6# L80 TC -11 Box 130.31 2 4.940 3.958 30.60 7333.15 4-1/2" 12.6# L80 TC -11 LinerJt 160.91 3 4.940 3.958 31.88 7301.27 4-1/2" 12.6# 180 TC -11 LinerJt 192.79 4.929 3.924 9.98 7291.29 4-1/2" 12.6# L80 TSH 521 Box x TC -II Pin 202.77 _? a 5.541 3.924 12.03 7279.26 External 05 Tracer Carrier 1-3 ROS 1270 214.80 31.70 ° 8 4.726 3.924 9.69 7269.57 4-1/2" 12.6# L80 TC -11 Box x TSH 521 Pin 224.49 4 4.940 3.958 32.04 7237.53 4-1/2" 12.6# 1.80 TC -II Liner It 256.53 5 4.940 3.958 31.69 7205.84 4-1/2" 12.6# L80 TC -11 LinerJt 288.22 9 4.935 3.945 9.80 7196.04 4-1/2" 12.6# TC -II Box x Pin 298.02 1 5.601 1.868 2.53 7193.51 EX Frac Sleeve w/ 1.868" Ball Seat, 6 Shear Screws 300.55 347.79 10 4.952 3.940 9.81 7183.70 4-1/2"12.6#TC-11 Box Pin 310.36 6 4.940 3.958 31.57 7152.13 4-1/2" 12.6# L80 TC -II Liner It 341.93 7 4.940 3.958 31.73 7120.40 4-1/21112.6# L80 TC -II LinerJt 373.66 S 3 11 4.921 5.531 3.921 3.921 9.99 12.04 7110.41 7098.37 4-1/2" 12.6# L80 TSH 521 Box x TC -II Pin External OS Tracer Carrier 1-2 ROS 1269 383.65 395.69 31.73 012 4.734 3.921 9.70 7088.67 4-1/2" 12.6# LSO TC -II Box x TSH 521 Pin 405.39 y n 13 4.928 3.927 9.99 7078.68 4-1/2" 12.6# L80 TSH 521 Box x TC -II Pin 415.38 ;. a v 5.521 3.927 12.70 7065.98 Internal OS Tracer Carrier 1-1 ROS 1268 428.08 32.38 l ° 14 4.735 3.927 9.69 7056.29 4-1/2" 12.6# L80 TC -II Box x TSH 521 Pin 437.77 4.940 3.921 18.99 7037.30 4-1/2" 12.6# L80 TC -11 Pin 456.76 5.829 3.921 16.49 7020.81 5.85 OD Oil Swellable Packer Element 473.25 8 4.940 4.940 3.921 3.958 4.90 31.64 7015.92 6984.28 4-1/2" 12.6# L80 TC -11 Box 4-1/2" 12.6# L80 TC -11 LinerJt 478.15 509.79 9 4.940 3.958 31.28 6953.00 4-1/2" 12.6# L80 TC -II LinerJt 541.07 `i 15 4.927 3.924 9.98 6943.02 4-1/2" 12.6# 180 TSH 521 Box x TC -II Pin 551.05 cad & 16 5.541 4.739 3.924 3.924 12.04 9.69 6930.98 6921.29 External OS Tracer Carrier 2-3 ROS 1273 4-1/2" 12.6# L80 TC -11 Boxx TSH 521 Pin 563.09 572.78 31.71 10 4.940 3.958 31.23 6890.06 4-1/2" 12.6# L80 TC -II Liner It 604.01 11 4.940 3.958 31.24 6858.82 4-1/2" 12.6# L80 TC -11 LinerJt 635.25 17 4.923 3.958 9.85 6848.97 4-1/2" 12.64 AB TC -II Pup It. 645.10 5.598 1.916 2.54 0846.43 EX Frac Sleeve w/1.916" Ball Seat, 6 Shear 5,.. -Ns 647.64 346.33 18 4.933 3.948 9.85 6836.58 4-1/2" 12.6# AB TC -II Pup It. 65249 - 12 4.940 3.958 31.52 6805.06 4-1/2" 12.6# L80 TC -II Liner It 689.01 13 4.940 3.958 31.32 6773.74 4-1/2" 12.6# L80 TC -II Liner It 720.33 19 4.927 3.934 9.98 6763.76 4-1/2" 12.6# L80 TSH 521 Box x TC -II Pin 730.31 0: A S d 5.542 3.934 12.03 6751.73 External OS Tracer Carrier 2-2 ROS 1272 742.34 31.70 ' R 20 4.940 3.934 9.69 6742.04 4-1/2" 12.6# L80 TC -II Box x TSH 521 Pin 752.03 A 21 4.927 3.923 9.97 6732.07 4-1/2" 12.6# L80 TSH 521 Box x TC -11 Pin 762.00 0 a. 7 R; 3 5.544 3.923 12.44 6719.63 Internal OS Tracer Carrier 2-1 ROB 1271 774.44 32.10 22 4.730 3.923 9.69 6709.94 4-1/2" 12.6# L80 TC -11 Box x TSH 521 Pin 784.13 4.940 3.911 18.96 6690.98 4-1/2" 12.6# L80 TC -11 Pin 803.09 5.829 3.911 16.49 6674.49 5.85 OD Oil Swellable Packer Element 819.58 • , 4.940 3.911 4.92 6669.57 4-1/2" 12.6# L80 TC -11 Box 824.50 14 4.940 3.958 31.48 6638.09 4-1/2" 12.6# L80 TC -II Liner Jt 855.98 15 4.940 3.958 31.46 6606.63 4-1/2" 12.6# L80 TC -II Liner It 887.44 23 4.928 3.921 9.98 6596.65 4-1/2" 12.6# L80 TSH 521 Box x TC -11 Pin 897.42 ay 5.544 3.921 12.03 6584.62 Externa105 Tracer Carrier 3-3 R051276 909.45 31.70 ° 24 4.730 3.921 9.69 6574.93 41/2" 12.6# L80 TC -11 Box x TSH 521 Pin 919.14 16 4.940 3.958 31.76 6543.17 4-1/2" 12.6# L80 TC -II Liner It 950.90 17 4.940 3.958 31.21 6511.96 4-1/2" 12.6# L80 TC -11 Liner It 982.11 25 4.926 3.945 9.74 6502.22 4-1/2" 12.6# AB TC -II Pup It. 991.85 5.602 1.965 2.53 6499.69 EX Frac Sleeve w/ 1.965" Ball Seat, 6 Shear Screws 994.38 332.63 26 4.934 3.438 9.84 6489.85 4-1/2" 12.6# AB TC -II Pup It. 1004.22 18 4.940 3.958 31.52 6458.33 4-1/2" 12.6# L80 TC -11 Liner Jt 1035.74 19 4.940 3.958 31.61 6426.72 4-1/2" 12.6# L80 TC -11 Liner It 1067.35 y s 27 4.926 3.932 9.98 6416.74 4-1/2" 12.6# L80 TSH 521 Box x TC -II Pin 1077.33 3. g'" 5.527 3.932 12.04 6404.70 External OS Tracer Carrier 3-2 ROS 1275 1089.37 31.70 28 4.727 3.932 9.68 6395.02 4-1/2" 12.6# L80 TC -11 Box x TSH 521 Pin 1099.05 z9 4.929 3.919 9.98 6385.04 4-1/2" 12.6# L80 TSH 521 Box x TC -II Pin 1109.03 3.R 3 5.530 3.919 12.70 6372.34 Internal OS Tracer Carrier 3-1 ROS 1274 1121.73 32.37 ' R 30 4.730 3.919 9.69 6362.65 4-1/2" 12.6# LBO TC -II Box x TSH 521 Pin 1131.42 _ 4.940 3.914 4.30 6358.35 4-1/2" 12.6# L80 TC -11 Pin 1135.72 5.835 1 3.914 16.48 6341.87 5.85 OD Oil Swellable Packer Element 1152.20 r 4.940 3.914 19.57 6322.30 4-1/2" 12.6# L80 TC -11 Box 1171.77 20 4.940 3.958 31.01 6291.29 4-1/2" 12.6# L80 TC -11 Liner Jt 1202.78 21 1 4.940 3.958 31.73 6259.56 4-1/2" 12.6# L80 TC -11 Liner It 1234.51 31 4.932 3.927 9.98 6249.58 4-1/2" 12.6# L80 TSH 521 Box x TC -II Pin 1244.49 S 2 g d 5.538 3.927 12.01 6237.57 External OS Tracer Carrier 4-3 ROS 1279 1256.50 R 32 4.727 3.927 9.70 6227.87 4-1/2" 12.6# L80 TC -II Box x TSH 521 Pin 1266.20 22 4.940 3.958 31.64 6196.23 4-1/2"12.6#L80 TC -11 Liner It 1297.84 23 4.940 3.958 30.95 6165.28 4-1/2" 12.6# L80 TC -11 Liner It 1328.79 _ 33 4.932 3.940 9.78 6155.50 4-1/2" 12.6# AB TC -II Pup It. 1338.57 5.621 2.015 2.53 6152.97 EX Frac Sleeve w/ 2.015" Ball Seat, 6 Shear Screws 1341.10 345.79 34 4.938 3.942 9.89 6143.08 4-1/2" 12.6# AB TC -II Pup It. 1350.99 24 4.940 3.958 30.31 6112.77 4-1/2" 12.6# L80 TC -11 Liner It 1381.30 25 4.940 3.958 31.84 6080.93 4-1/2" 12.6# L80 TC -11 Liner Jt 1413.14 y 35 4.929 3.929 9.98 6070.95 4-1/2" 12.6# L80 TSH 521 Box x TC -II Pin 1423.12 d 5.548 3.929 12.02 6058.93 External OS Tracer Carrier 4-2 ROS 1278 1435.14 31.69 ' R 36 4.726 3.929 9.69 6049.24 4-1/2" 12.6# L80 TC -II Box x TSH 521 Pin 1444.83 y n 37 4.928 3.923 9.98 6039.26 4-1/2" 12.6# L80 TSH 521 Box x TC -II Pin 1454.81 0 & 5.538 3.923 12.67 6026.59 Internal OS Tracer Carrier 4-1 ROS1277 1467.48 32.34 ' R 38 4.731 3.923 9.69 6016.90 4-1/2" 12.6# L80 TC -II Box x TSH 521 Pin 1477.17 4.940 3.949 4.34 6012.56 4-1/2" 12.6# L80 TC -11 Pin 1481.51 5.848 3.949 16.49 5996.07 5.85 OD Oil Swellable Packer Element 1498.00 4.940 3.949 19.57 5976.50 4-1/2" 12.6# L80 TC -11 Box 1517.57 26 4.940 3.958 28.47 5948.03 4-1/2" 12.6# L80 TC -II Liner It 1546.04 27 4.940 3.958 31.54 5916.49 4-1/2" 12.6# L80 TC -II Li n e r It 1577.58 y1 39 4.929 3.932 9.98 5906.51 4-1/2" 12.6# L80 TSH 521 Box x TC -II Pin 1587.56 & 5.550 3.932 12.02 5894.49 External OS Tracer Carrier 5-3 BOB 1282 1599.58 31.69 R 40 4.726 3.932 9.69 5884.80 4-1/2" 12.6# L80 TC -II Box x TSH 521 Pin 1609.27 28 4.940 3.958 31.12 5853.68 4-1/2" 12.6# L80 TC -II Liner It 1640.39 29 4.940 3.958 31.40 5822.28 4-1/2" 12.6# L80 TC -11 Liner It 1671.79 41 4.927 3.939 9.82 1 5812.46 4-1/2" 12.6# AB TC -II Pup It. 1681.61 5 2869.66 :hed Seal Bore 13.5# Vamtop Box x Pin 5.607 2.066 2.52 i809.94 EX Frac Sleeve w/ 2.066" Ball Seat, 6 Shear'- .,vs 1684.13 343.68 30 42 4.934 4.940 3.939 3.958 9.80 31.50 5800.14 5768.64 4-1/2" 12.6# AB TC -II Pup It. 4-1/2"12.6#L80 TC -11 Liner It 1693.93 1725.43 31 4.940 3.958 31.37 5737.27 4-1/2" 12.6# L80 TC -11 Liner It 1756.80 y 43 4.927 3.926 9.98 5727.29 4-1/2" 12.6# L80 TSH 521 Box x TC -II Pin 1766.78 3 °; 3 ° 44 5.541 4.726 3.926 3.926 12.11 9.69 5715.18 5705.49 External OS Tracer Carrier 5-2 ROS 1281 4-1/2" 12.6# L80 TC -II Box x TSH 521 Pin 1778.89 31.78 1788.58 - 45 4.925 3.917 9.98 5695.51 4-1/2" 12.6# L80 TSH 521 Box x TC -11 Pin 1798.56 a 3 5.534 3.917 12.62 5682.89 Internal OS Tracer Carrier 5-1 ROS 1280 1811.18 32.27 46 4.732 4.940 5.838 3.917 3.942 3.942 9.67 4.34 16.49 5673.22 5668.88 5652.39 4-1/2" 12.6# L80 TC -11 Box x TSH 521 Pin 4-1/21112.6# LBO TC -II Pin 5.85 OD Oil Swellable Packer Element 1820.85 1825.19 1841.68 32 4.940 4.940 3.942 3.958 19.57 31.90 5632.82 5600.92 4-1/2" 12.6# L80 TC -11 Box 4-1/2" 12.6# L80 TC -11 Liner It 1861.25 1893.15 33 4.940 3.958 31.93 5568.99 4-1/2" 12.6# L80 TC -11 Liner It 1925.08 47 4.927 5.553 3.927 3.958 9.98 12.09 5559.01 5546.92 4-1/2" 12.6# L80 TSH 521 Box x TC -II Pin External OS Tracer Carrier 6-3 ROS 1285 1935.06 1947.15 31.76 48 4.728 3.958 9.69 5537.23 4-1/2" 12.6# L80 TC -11 Box x TSH 521 Pin 1956.84 34 4.940 3.958 29.73 5507.50 4-1/2" 12.6# L80 TC -11 Liner Jt 1986.57 6 35 4.940 3.958 31.34 5476.16 4-1/2" 12.6# L80 TC -11 Liner It 2017.91 346.06 49 4.937 3.940 9.78 5466.38 4-1/2" 12.6# AB TC -11 Pup Jt. - 5.594 2.118 2.54 5463.84 EX Frac Sleeve w/ 2.118" Ball Seat, 6 Shear Screws 2027.69 2030.23 50 4.934 3.936 9.82 5454.02 4-1/2" 12.6# AS TC -11 Pup It. 2040.05 36 4.940 3.958 31.90 5422.12 4-1/2" 12.6# L80 TC -11 Liner Jt 2071.95 37 4.940 3.958 31.28 5390.84 4-1/2" 12.6# L80 TC -11 Liner It 2103.23 y A c5.547 51 4.928 3.924 3.924 9.98 12.10 5380.86 5368.76 4-1/2" 12.6# L80 TSH 521 Box x TC -11 Pin External OS Tracer Carrier 6-2 ROS 1284 2113.21 2125.31 E 52 53 4.730 4.927 3.924 3.926 9.69 9.98 5359.07 5349.09 4-1/2" 12.6# L80 TC -11 Box x TSH 521 Pin 4-1/2" 12.6# L80 TSH 521 Box x TC -11 Pin 2135.00 2144.98 : ' 54 5.536 4.729 4.940 5.827 3.926 3.926 3.923 3.923 12.66 9.69 3.92 16.45 5336.43 5326.74 5322.82 5306.37 Internal OS Tracer Carrier 6-1 ROS 1283 4-1/2" 12.6# L80 TC -11 Box x TSH 521 Pin 4-1/2" 12.6# L80 TC -11 Pin 5.85 OD Oil Swellable Packer Element 2157.64 2167.33 2171.25 2187.70 4.940 3.923 19.17 5287.20 4-1/2" 12.6# L80 TC -11 Box 2206.87 38 4.940 3.958 31.68 5255.52 4-1/2" 12.6# L80 TC -11 Liner It 2238.55 39 4.940 3.958 31.67 5223.85 4-1/2" 12.6# L80 TC -11 Liner Jt 2270.22 40 4.940 3.958 31.53 5192.32 4-1/2" 12.6# L80 TC -11 Liner It 2301.75 41 4.940 3.958 29.87 5162.45 4-1/2" 12.6# L80 TC -11 Liner Jt 2331.62 42 4.940 3.958 32.06 5130.39 4-1/2"12.6#L80 TC -11 Liner It 2363.68 43 4.940 3.958 30.74 5099.65 4-1/2" 12.6# L80 TC -11 Liner It 2394.42 44 4.940 3.958 29.67 5069.98 4-1/2" 12.6# LSO TC -11 Liner Jt 2424.09 45 4.940 3.958 31.28 5038.70 4-1/2" 12.6# L80 TC -11 Liner It 2455.37 46 4.940 3.958 31.05 5007.65 4-1/2" 12.6# L80 TC -11 Liner It 2486.42 47 4.940 3.958 31.11 4976.54 4-1/2" 12.6# L80 TC -11 Liner Jt 2517.53 48 4.940 3.958 32.00 4944.54 4-1/2" 12.6# L80 TC -11 Liner Jt 2549.53 49 4.940 3.958 31.02 4913.52 4-1/2" 12.6# L80 TC -11 Liner Jt 2580.55 50 4.940 3.958 29.76 4883.76 4-1/2" 12.6# L80 TC -11 Liner Jt 2610.31 51 4.940 3.958 31.23 4852.53 4-1/2" 12.6# L80 TC -11 Liner It 2641.54 52 4.940 3.958 31.41 4821.12 4-1/2" 12.6# L80 TC -11 Liner It 2672.95 53 4.940 3.958 31.60 4789.52 4-1/2" 12.6# L80 TC -11 Liner Jt 2704.55 54 4.940 3.958 31.50 4758.02 4-1/2" 12.6# L80 TC -11 Liner It 2736.05 55 4.940 3.958 30.48 4727.54 4-1/2" 12.6# LBO TC -11 Liner Jt 2766.53 56 4.940 3.958 30.96 4696.58 4-1/2" 12.6# L80 TC -11 Liner It 2797.49 57 4.940 3.958 30.81 4665.77 4-1/2" 12.6# LBO TC -11 Liner It 2828.30 58 4.940 3.958 31.90 4633.87 4-1/2" 12.6# L80 TC -11 Liner It 2860.20 55 1 4.940 1 3.958 1 9.46 1 4624.41 5.000 7.610 9.91 8.325 12.6# TC -II Pin x 13.5# Vamtop Box 2869.66 :hed Seal Bore 13.5# Vamtop Box x Pin 2879.38 ;hed Seal Bore 13.5# Vamtop Box x Pin 2889.11 n# Adapter 4.5" 13.5 Vamtop Pin x 7" 26# TSH 563 Box 2891.85 N� 0 -so( 2141 q�jG> Regg, James B (DOA) From: Noble, Robert C (DOA) Sent: Thursday, April 30, 2015 10:36 AM To: Regg, James B (DOA) Cc: Hill, Johnnie W (DOA) Subject: FW: Q-301 Attachments: Q301 dirt mound.JPG; Q9 Dirt mound.JPG; Q8 dirt mounds.JPG Jim I ask Repsol to send me pictures of their mounds for their wells this year and this is what I received. Bob Noble AOGCC 333 W. 7th Ave. Ste. 100 Anch AK. 99501 Cell 907-299-1362 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 Bob Noble at 907-299-1362 or bob.noble@alaska.gov From: PROVECHO GONZALEZ, MARIA[ma !Ito:maria.provecho@repsol.com] Sent: Thursday, April 30, 2015 6:57 AM To: Noble, Robert C (DOA) Subject: RE: Q-301 Morning Bob, Please find attached the dirt mound pictures. Regards Maria Provecho Gonzalez` Drilling Engineer REPIOL 1 0 4 1 �. Ili MEMORANDUM TO: Jim Regg P. I. Supervisor State of Alaska Alaska Oil and Gas Conservation Commission 4IZ�I'� DATE FROM: Bob Noble SUBJECT: Petroleum Inspector 4/25/15 Surface Abandonment Qugruk 301 Repsol USA PTD #214-199 4/25/15: 1 traveled out to Repsol's Q-301 drill site and met with Repsol Rep. Carlos Cretsinger. I looked over his cut-off and found all strings of pipe to be full of good hard cement and to be cut off about 12 feet below tundra level. The marker plate is 3/8" thick and had all the correct names and numbers on it. I told Jack Haney he could weld the marker plate on and cover it up. Attachments: Photos (3) 2015-0425—Surface. Abandon Qugruk-301_bn.docx Page 1 of 3 Surface Abandonment — Qugruk 301 (PTD 2141990) Photos by AOGCC Inspector B. Noble 4/25/2015 2015-0425_Surface_Abandon_Qugruk-301_bn.docx Page 2 of 3 Casings cut off; cement to surface Qugruk 301 marker plate 2015-0425_Surface_Abandon_Qugruk-301 _bn.docx Page 3 of 3 Qugruk 301 marker plate installed MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg 4(0,311s P.I. Supervisor F I FROM: Matt Herrera Petroleum Inspector Section: 6 Township: 11 Lease No.: ADLO391455 Drilling Rig: Nabors 105E - Rig Elevation: Operator Rep.: Carlos Cretsinger Plugging Data: Type Plug (bottom up) Bottom of 103 ft 2107 ft 5241 ft MD 7527 ft MD 4503 ft MD 4200 ft MD Type Plug CasinglTubing Data: Open Hole Conductor: 20" 0. D. Shoe@ Surface: 13 3/8" - 0. D. Shoe@ Intermediate: 95/8" - O.D. Shoe@ Production: Feet 0. D. Shoe@ Liner: 4.5 0. D. Shoe@ Tubing: 0. D. Tail@ Plugging Data: Type Plug (bottom up) Bottom of 103 ft 2107 ft 5241 ft MD 7527 ft MD 4503 ft MD 4200 ft MD Type Plug Founded on: Verified? Open Hole Bottom Drillpipe tag Perforation Bridge plug Wireline tag Annulus Balanced C.T. Tag Casing Stub Retainer No Surface Cul@ Feet Summary: DATE: 04/18/15 SUBJECT: Plug & Abandonement Quguruk #301 Repsol Nabors 105E PTD 2141990; Sundry 315-207 Range: 6E - Meridian: Umiat Total Depth: 7531 It MD (4146 ft TVD) Casino Removal Casing Cut@ Feet Casing Cut@ Feet Casing Cut@ Feet Casing Cut@ Feet Casing Cut@ Feet Casing Cul@ Feet T.O.C. Mud Weight Pressure erified? above plug Test Traveled out to Nabors 105E rig got up with Co. Man and went over P&A procedure for Q-301. Verified retainer depth and cement below and above retainer and mud weight above plug. Witnessed pressure test. Made recommendations for further AOGCC witness of remaining steps of procedure and final cement verification and cut off and plate installation. Operator will keep AOGCC updated on progress. Rev.:5/28/00 by L.R.G. 2015-0418_Plug_ Verification_Qugruk-301_mh.xlsx 4/23/2015 THE STATE °fALASKA GOVERNOR BILL WALKER Bill Hardham Operations Manager Repsol USA 3800 Centerpoint Drive, Suite 400 Anchorage, AK 99503 Re: Wildcat Field, Wildcat Pool, Qugruk 301 Sundry Number: 315-207 Dear Mr. Hardham: Alaska Oil and Gas Conservation Commission 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov altF-(�q Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this / day of April, 2015 Encl. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS RZITiV_TWlM1.111 RECEIVED APR 0 7 2015 ,AOGCC 1. Type of Request: Abandon E ' Plug for Redrill ❑ Perforate New Pod ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforete ❑ Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ I Other. 2. Operator Name: 4. Current Well Class:5. Permit to Drill Number: REPSOL USA - Exploratory Q ' Development El Stratigraphic ❑ Service ❑ 214-199 3. Address: 6. API Number: 3800 Centerpoint Dr. Suite 400, Anchorage, AK, 99503 50-103-20700-00-00 r 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? N/A Qugruk 301 - Will planned perforations require a spacing exception? Yes ❑ No ❑ 9. Property Designation (Lease Number): 10. Fie1d/Pool(s): ADL 391445, 391455 Wildcat it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): I Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 7531' 4146' - 7531' _ 4146' N/A WA Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 20" 103' 103' Surface 2087' 13-3/8" 2107' 2107' 5020 2260 Intermediate 5221' 9-5/8" 5241' 4185' 6870 4760 Production Liner 2974' 4-1/2" 7527' 4146' 8440 7500 Perforation Depth MD (ft): Pedoration Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): N/A N/A N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Expandable Liner Hanger 4553' MD / 4063' TVD 1 12. Attachments: Description Summary of Proposal ❑✓ 13. Well Class after proposed work: Detailed Operations Program F±1 BOP Sketch ❑ Exploratory ❑✓ • Stratigraphic ❑ Development ❑ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 4/10/2015 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ WINJ ❑ GINJ ❑ WAG ❑ Abandoned El - 16. Verbal Approval: Date: Commission Representative: GSTOR ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Michael Quick 907-375-6933 Email nnichaBLOUICk@seryeXIBfDOS.r@DSDI.COrrf Printed Name Bill Hardham Title Operations Manager Signature Phone 907-375-6917 Date l^l✓1 vr-- COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity i[tt� BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance V jug+ uz Other: 2016 l r_ Spacing Exception Required? Yes ❑ No L✓ Subsequent Form Required: l p–yd7 APPROVED BY / �— Approved by: COMMISSIONER THE COMMISSION Date: 4 V / V Rat 6+ A` )✓IYJ `thsfrS e/.�A5 Submit Form and Form 10-4Q3 (Revised 10/2012) i 1 i I for 12 months from tb date, of approvah Attachments in Duplicate RBDMS \�tJ'' APR - 9 2015 , `���6 m6 yV `115, RECEIVED April 6, 2015 APR 0 7 2015 AOGCC Alaska Oil and Gas Conservation Commission 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 RE: 10-403 Sundry for Permanent Abandonment: Repsol Qugruk 301 PTD 214-199 Dear Commissioner: Repsol hereby submits an Application for Sundry Approvals for the permanent abandonment of Qugruk 301, permit to drill 214-199. Qugruk 301 was spudded 2/18/2015, and a total depth of 7,531' was reached on 3/17/2015. The well was completed and well testing commenced on 3/28/15 under Approved Sundry 315-147. The abandonment procedure is attached with the form 10-403 sundry application. The horizontal section of the well was completed with an un -cemented liner. The abandonment procedure takes this into account, and Repsol plans to follow 20 AAC 25.112 (g)(1) for tagging requirements, by placing weight on all plugs. Pertinent information attached to this application includes the following: 1. Form 10-403 Application for Sundry Approvals — 2 copies 2. Abandonment Procedure 3. Current Wellbore Schematic 4. Proposed Abandonment Wellbore Schematic The AOGCC is requested to treat as confidential all information included. If you have any questions or require additional information, please contact Bob Jones, Drilling Manager at 832-442-1618, myself at 907-375-6917, or the technical contacts contained in the following pages. Sincerely, Bill Hardham Operations Manager Repsol USA REPSOL USA Qugruk 301 P&A Procedure (PTD 214-199) 1. Notify AOGCC 48 hours prior to commencing abandonment operations. 2. Post approved 10-403 Sundry notice on location. 3. Pick up 9-5/8" cement retainer and RIH on tubing. 4. Set cement retainer at +/- 4503' MD. Pick up and set down 5,000 lbs on retainer to verify set 5. Rig up cementers and test lines to 4000 psi. P! #�' 6. Sting into retainer, hold 500 psi on 9-5/8" casing, establikh injection rate below retainer, mix and pump 14 bbls of 15.8 ppg Class G Cement and squeeze 8 bbls below retainer. „ 7. Un -sting from retainer and spot 6 bbls (80') of 15.8 ppg class G cement on top of retainer. 8. Pull up 3 stands and pump wiper ball and circulate to clean tubing. r she 9. Pressure test casing and retainer to 1500 psi for 30 min, record on chart. w 10. Displace well with 10.4 ppg Kill Weight fluid. POOH. 11. Pick up 9-5/8" bridge plug and RIH on tubing. 12. Set bridge plug at 2207' MD. P4"�- if Z -- 13. i 13. Pull up and set down 5000 lbs on bridge plug to verify set. 14. Rig up cementers and test lines to 4000 psi. 15. Mix and spot 15 bbls (200') of 15.8 ppg class G cement on top of bridge plug. 16. Pull up 3 stands and pump wiper ball and circulate to clean tubing. POOH. 17. Pick up 9-5/8" bridge plug and RIH on tubing. 18. Set bridge plug at 280' MD. eU'a 3 19. Pull up and set down 5000 lbs on bridge plug to verify set. 20. Rig up cementers and test lines to 4000 psi. 21. Mix and spot 18.3 bbls (250') of 15.8 ppg class G cement on top of bridge plug bringing cement to just above the bottom of the cellar. POOH. WOC. 22. Nipple down BOP and cut off wellhead. 23. R/D and move off drilling rig. 24. Cut off all casing strings (20", 13-3/8", 9-5/8") at least 3 feet below original ground level. Note: Notify AQGCC in<oector to witness casing cut off. 25. Take ttos of cut off casing stubs - cement must be to surface in all annulus. 26. Weld a 20" cap onto the casing stub with the required well identification information. 27. Take photos of the welded 20" cap. 28. Remove cellar. Take photos to show cut off is 3 feet below original ground level. 29. Back fill cellar hole. Take photo of mound. Zv 4 4c Z5�'• "" Qugruk 301 Proposed P&A Schematic CONFIDENTIAL Bridge Plug @ 2207' MD I with 15 bbls cmt on top. Intermediate Stage 2: Stage tool @ 3,008' MD 12-/4" Hole 10.4 pp ` — TOC @ 3,810' MD KWF > 9-5/8" 47# L-80 Casing @ 5,241' MD I 4,185' TVD EZSV @ 4503' MD Squeeze 8 bbls Class G ` ---- cmt below. ~--- With 6 bbls Class G cmt on top. Expandable Liner Hanger w/ Seals @ 4,553' MD 14,063- TVD ---- – ---- ---- it -- V/2" 12.6# L-80 TC -II 6 1/2" Un -cemented Liner Hole lqw REPfOL Rig 105 RKB: 20' Q-301 Elevation w/ Pad Thickness: 17' KB to MSL: 37' Bull Nose Guide Shoe @ 7,495' MD TD @ 7,531' MD I 4,145' TVD Prepared By D. Ross/ A. Dial 3-31-15 Qugruk 301 Current Schematic CONFIDENTIAL 26" Hole 20"131#JS5 Conductor@ RERML 103'MD/TVD i i i 3 "X Rig 105 RKB: 20' Profile Q-5 Elevation w/ Pad Thickness: 17' Chemical injection sub KB t0 MSL: 37' �.- 16" Hole 0 — :i I i :i Acoustic Repeaters i �- — 13-318" 68# L-80 Casing @ 2107' MD ti 3-%" 9.3# L-80 Tubing wli Intermediate Stage 2: Stage tool @ 3,008' MD �12-M." Hole Ruplurc Circulation Valve TD @ 7,531' MD I Annular Pressure 4.145' TVD Cycled Test Valve Oil Activated (2) Ouarh SRO 95/6" 47# L-80 Casing Swell Packers est Gauges @5,241 MD14,185-TVD Redundant Hydraulic Shut OH -`♦ For. Valves Cellar (2) Sapphire SRO ::. ` Bull Nose ___ _________ ________ @7,496'de -- -_-- _' E) �17,495'MD Real Time SRO Gauge --- DHSampleCarrierwl191 ._ _ ------ _� __ ___ 400.c sample lubes perforated Tubing Tesler Valve p.p Ezpandabie Liner Hanger tN Seals Internal 08 ExternalOSFrao ng Disaptlslug 61/2"ROIs Teat Plu g @4,55T MD/4,063-TVD chemical Tracer Subs Chemical sleeves Tracer Subs 411," 12.6# L-80 TC4I Un -cemented Liner prepared By D. Ross 3-10-15 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.180(8)(C) RECEIVED E _EIVED V 52-b MAR 2 5 2015 AOC0C Geological Sample Manifest Operator: Repsol E&P USA, Inc. Date: 17 -Mar -2015 Well Name: Qugruk 301 Prepared By: Beverly Hur Location: North Slope, AK Received By: Repsol Geologist Set Owner Box Weight Quantity Of Box (lbs.) Containers (bags, ars etc. Type Sampling Frequency Sampling interval Enclosed Shipping Address 1 of 11 16.00 16 2110' to 2590' CGG Services US 2 of 11 16.00 16 2590T to 3070' 3 of 11 16.00 16 3070 to 3550' 4 of 11 18.00 18 355D'to4D90' Ann: Jennifer Koerth 5 of 11 16.00 16 409W to 4570' 3311 South US Hwy 77 6 o 11 19.00 19 4570'to 5140' 1 Repsol Unwashed Wet 30' Schulenburg, TX 78956 7 of 11 15.00 15 S140'to 5580' Phone: 979-562-2777 8 of 11 21.00 21 5580' to 6210' 9 of 11 17.00 17 6210' to 6720' 10 of 11 19.00 19 6720'to 7290' 11 of 11 8.00 8 7290' to 7531' 1 of 4 4.00 34 2110'to 3130' 2 of 4 5.00 37 3 of 4 6.00 49 3130'to 4240' 3 Repsol Washed and Dried 30' 4240'ro 5670' 4 of 4 8.00 62 5670'to 7531' 1 of 4 32.00 20 1900' to 3610' 2of4 32.00 20 3610'to 5430' 4 Repsol Geochemical Can in Isolars 90, 3 of 28.80 18 5410'to 7030' 4 of 4 9.60 6 7030'to 7531' 1 of 6 7.00 25 1990'to 3970' 1990' to 4690' at 90' 2 of 6 7.00 25 4DS0'to 5340' 5 Repsol 3 of 6 7.00 25 Gas Samples in IsoTubesa intervals and 4720'to 7531' at 30' intervals & 5170'to 5800' 4 of 6 7.00 25 5834'to 6550' 5 of 6 7.00 25 6580'to 7280' selected peaks 6 of 6 4.00 9 7300'to 7531' 1 6 Repsol 1 of 1 20.00 12 Mud Samples / Mud Additives Spud, Int. & Production Mud & Additives 0'- 7531' 1 of 5 8.00 35 2110'to 4690' at 30' 2110'to 3160' 2 of 8.00 35 intervals, 30'intervals 3160'to 4210' Meredith Guhl, Petroleum Geologist Assistant Alaska nil 7 AOGCC 3of5 9.00 50 Washed and Dried from 4690'to 5250' 4210'to 5030' and Gas conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 4 of 5 8.00 26 and at 30' intervals 503W to 5970' 907-793-1235 from 5250' to 7531'. 5 of 5 9.00 52 5970' to 7531' Total Boxes: 25 non hazardous and 6 hazardous Total Weight: 409lbs Hazardous goods Intermediate and Production Inventory Qugruk 301, Repsol TD 09:33:00 D3/07/2015 Washed and Dried Sample Manifest Shipped To: Address: Operator: Repsol E&P USA Inc. gON# 10F 5 Meredith Guhl Alaska Oil and Gas Conservation Commission Attn: Meredith Guhl 33 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1235 Well Name: Qugruk 301 Location: North Slope , AK Date: 3/17/2015 Set % Box Box Weight ( lbs.) Quantity Of Containers (bags, jars, etc.) Type Sampling Frequency Sampling Interval Enclosed 1 of 5 8.0 35.0 Washed and Dried 30' 2,110'to 3160' 2 of 5 8.0 35.0 30' 3160' to 4210' 3 of 5 9.0 50.0 30' and 10' 4210' to 5030' 4 of 5 8.0 26.0 30' and 10' 5030' to 5970' 5 of 5 9.0 52.0 10' 7300' to 7351' NOTES: In Box 1 of 5: Washed and Dried samples were collected at 30 ft. intervals from 2,110'-3160'. RECEIVED MAR 2 5 2015 AOGCC MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Reggj2Q9q DATE: March 20, 2015 P. I. Supervisor FROM: John Crisp, SUBJECT: BOPE Test Procedures Petroleum Inspector Nabors 105E Qugruk 301 PTD 2141990 Repsol March 18, 2015: Repsol representatives from Nabors 105E (Qutgruk 301) contacted me while I was on Doyon 1 (Qugruk 8 initial BOPE test) to make certain I was aware that they would be ready for their weekly BOPE test (after they pulled the wear bushing and set the test plug "in string". Explanation of "in string" is that they have a dummy clean out BHA with approximately 5,000 ft of drill string hanging from the wear bushing setting tool that is also used for a test plug after it is turned upside down from bushing tool. The Repsol representative for Qugruk 301 had contacted me earlier to request less than 48 hour notice for BOPE test — they wanted to test while out of the hole instead of hanging off their drill string. I absolutely realized the issue of hang off instead of testing while out of the hole and gladly granted the request. Repsol's management subsequently decided it would be best practice to go ahead and hang off the drill string and set the test plug with the drill string at the casing shoe. Ordinarily that would be good practice for well control but in the case of Qugruk 301 — with the severely side- loaded well head due to the Nabors 105E being off center +/- 7 -inches — this approach posed hazards that were not in my opinion worth the risk with a quiescent well. The severely side -loaded well head is being addressed per AOGCC sundry and not the reason for this report but it was the reason I wanted to witness the wear bushing pulled and the test plug set. The wear bushing was pulled and test plug was being run in hole to the well head when I asked how the mineral oil- based drilling mud would be cleared from the stack to allow the stack to be tested with fresh water. Nabors personnel stated that mineral oil-based drilling mud had been used previously to test BOP's and the intention was to test the BOP stack and choke manifold with the drilling mud that had been left in the choke manifold for freeze protection. I made Repsol and Nabors personnel on Nabors 105E aware that testing with drilling mud was never allowed by AOGCC and the BOP stack and choke BOPE test was successful with minimal failures 2015-0320_Nabors 106E_BOP_test_procedure_ test_fluid_ic.docx Page 1 of 3 manifold must be excavated of all mineral oil-based drilling mud (which included drilled solids, weight material, viscosifiers and loss circulation material) prior to testing; all BOPE function -pressure tests would be conducted with water. The annulus valve was then opened to drain the stack and the choke manifold was blown down with air to the stack. The drilling mud was so thick it took several minutes to drain the stack thru a 2" annulus valve. Rig Personnel stated that the previous weekly test dated 3/12/15 which took a reported 64.5 hours had been conducted with mineral oil-based drilling mud. Those statements are not verified and I do not know how the previous weekly test on Nabors 105E was conducted since it was not witnessed by AOGCC. The initial AOGCC witnessed test on all 3 rigs working this winter for Repsol (Nabors 105E; Nabors 99AC; Doyon 1) were witnessed by AOGCC Inspectors and confirmed to be performed with fresh water as test fluid. Personnel stated to me that Repsol's and Nabors' Field Superintendents made the decision to performance -test the BOPE with drilling mud. Personnel also stated that a rig consultant said that an AOGCC representative had given the go- ahead to test with drilling mud in the past. They offered no specifics (well; Inspector; rig; date). There are issues with drilling rigs working on ice pads in the Arctic that rigs elsewhere do not have to deal with (e.g., rig enclosed spaces maintained too hot causing drilling pad to melt underneath mats and cellar thawing issues). Sometimes it is just luck with the weather that makes testing with fresh water difficult. Temperature swings from 15 above to 40 below are common these days and if a test has to occur when it is 40 below the difficulty testing with water increases dramatically. Sometimes even the most experienced arctic rig hand can't blow down equipment fast enough to keep it from freezing. Hearsay and statements made by wellsite and rig personnel about testing with mineral oil-based drilling mud can be nearly impossible to validate without witnessing the test. Perhaps more difficult is proving an operator's intent to skew BOPE performance test results by attempting to mask leaks or falsify a pressure test. This report is not intended to point fingers but there is credible information — including direct observation — that warrant discussion with Repsol to make sure their test procedures — specifically the fluid used for BOPE performance testing — is consistent with AOGCC regulation and good oilfield practices (such as established by API RP 53). AOGCC Field Inspectors generally work independent with a delegated decision- making authority supported by the Inspection Supervisor. Requiring operators and contractors to change procedures to comply with regulatory requirements or best oilfield practice (absent specific regulation) can add to the stress of normal operations and even create a hostile work environment. In the case of Nabors 2015-0320_Nabors106E BOP test_procedure_ test_fluidJc.docx Page 2 of 3 105E at Qugruk 301 on 3/18/2015 the Operator did not hesitate to comply with my request (drain stack; test with fresh water). After testing began and concerns were discussed with everyone involved with testing Nabors 105E personnel became aware that it is not the intent of the AOGCC Inspector to cause hardship or cost time but it is in everyone's best interest to always perform all tasks in full compliance with regulations, API RP's and best practices. The operator should be discussing test fluids, thaw concerns, etc., with AOGCC at the permit application — and at least before commencing operations — rather than waiting until it is time to perform the BOPE performance test. Summary: My opinion is that without question the BOPE test conducted on Nabors 105E Qugruk 301 witnessed 3/18 - 3/19/2015 would have been performed with drilling mud in the stack and choke manifold if this test were not witnessed. Based on discussions, it appears the practice of testing with drilling mud has occurred previously this winter on Repsol's rigs drilling the Qugruk exploration wells. I recommend all of the rigs working for Repsol be provided guidance about appropriate fluid for testing BOPE — the regulations require use of a noncompressible fluid, AOGCC has applied API RP53 interpreting the term noncompressible fluid to mean fresh water for all rigs in Alaska. Attachments: None Non -Confidential 2015-0320_Nabors106E_BOP_test_procedure test fluid_jc.docx Page 3 of 3 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg�,,,� S�ISI15 P. I. Supervisor 1 FROM: John Crisp, Petroleum Inspector DATE: March 20, 2015 SUBJECT: BOPE Test Procedures Nabors 105E Qugruk 301 PTD 2141990 - Repsol March 18, 2015: Repsol representatives from Nabors 105E (Qugruk 301) contacted me while I was on Doyon 1 (Qugruk 8 initial BOPE test') to make certain I was aware that they would be ready for their weekly BOPE test (after they pulled the wear bushing and set the test plug "in string". Explanation of "in string" is that they have a dummy clean out BHA with approximately 5,000 ft of drill string hanging from the wear bushing setting tool that is also used for a test plug after it is turned upside down from bushing tool. The Repsol representative for Qugruk 301 had contacted me earlier to request less than 48 hour notice for BOPE test — they wanted to test while out of the hole instead of hanging off their drill string. I absolutely realized the issue of hang off instead of testing while out of the hole and gladly granted the request. Repsol's management subsequently decided it would be best practice to go ahead and hang off the drill string and set the test plug with the drill string at the casing shoe. Ordinarily that would be good practice for well control but in the case of Qugruk 301 —with the severely side- loaded well head due to the Nabors 105E being off center +/- 7 -inches — this approach posed hazards that were not in my opinion worth the risk with a quiescent well. The severely side -loaded well head is being addressed per AOGCC sundry and not the reason for this report but it was the reason I wanted to witness the wear bushing pulled and the test plug set. The wear bushing was pulled and test plug was being run in hole to the well head when I asked how the mineral oil- based drilling mud would be cleared from the stack to allow the stack to be tested with fresh water. Nabors personnel stated that mineral oil-based drilling mud had been used previously to test BOP's and the intention was to test the BOP stack and choke manifnW ,kith_,_ the he drilling mud that had been left in the choke manifold for freeze protection. I made Repsol and Nabors personnel on Nabors 105E aware that testing with drilling mud was never allowed by AOGCC and the BOP stack and choke ' BOPE test was successful with minimal failures 2015-0318_BOPE_Nabors 106E_test_fluids j c.docx Page I of 3 VA 105E at Qugruk 301 on 3/18/2015 the Operator did not hesitate to comply with my request (drain stack; test with fresh water). After testing began and concerns were discussed with everyone involved with testing Nabors 105E personnel became aware at it is not the intent of the AOGCC Inspector to cause hardship or cost time but it is in everyone's best interest to always pe orm all tasks in full compliance with regulations, API RP's and best practices. The operator should be discussing test fluids, thaw concerns, etc., with AOGCC at the permit application — and at least before commencing operations — rather than waiting until it is time to perform the BOPE performance test. Summary: My opinion is that without question the ROPE test conducted on Nabors 105E Qugruk 301 witnessed 3/18 - 3/19/2015 would have been performed with drilling mud in the stack and choke manifold if this test were not witnessed. Based on discussions, it appears the practice of testing with drilling mud has occurred previously this winter on Repsol's rigs drilling the Qugruk exploration wells. I recommend all of the rigs working for Repsol be provided guidance about appropriate fluid for testing BOPE — the regulations require use of a noncompressible fluid, AOGCC has applied API RP53 interpreting the term noncompressible fluid to mean fresh water for all rigs in Alaska. Attachments: None Non -Confidential 2015-0318—BOPE—Nabors 106E_test_fluids jc.docx Page 3 of 3 THE STATE °fALASKA GOVERNOR BILL WALKER Bill Hardham Operations Manager Repsol USA 3800 Centerpoint Drive, Suite 400 Anchorage, AK 99503 Re: Wildcat Field, Wildcat Pool, Qugruk 301 Sundry Number: 315-147 Dear Mr. Hardham: Alaska Oil and Gas Conservation Commission 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 wvvW.aogcc.ala5ka.g0v aIV Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P oerster Chair DATED this y of March, 2015 Encl. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVE® MAR 16 2015 AOGCC vi 1. Type of Request: Abandon ❑ Plug for Reddl) ❑ Perforate New Pod ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension ❑ Operations Shutdown❑ .- " Re-enter Susp. Well 1,.,Stimulate❑✓ After Casing Other: Co..,tf/ca t, 111/ t 2. Operator Name: 4. Current Well Class: 5. Permit to Dnli Number: 1- F1 REPSOL USA Exploratory ❑✓ . Development ❑ Stratigraphic El Service El 214-199, 3. Address: 6. API Number: 3800 Centerpoint Dr. Suite 400, Anchorage, AK, 99503 50-103-20700-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Qugruk 301, Will planned perforations require a spacing exception? Yes ❑ No .❑ 9. Property Designation (Lease Number): 10. Field/Pool(s): 391445, 391455 Wildcat it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 7531'(est) 4187'(est) 7,523'(est) 4187'(est) N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 20" 101' 101' 3,060 1,500 Surface 2087' 13-3/8" 2107' 2107' 5,020 2,260 Intermediate 5215' 9-5/8" 5235' 4187' 6,865 4,750 Production Liner 4-1/2" 7,531' (est) 4,187' 81440 7,500 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): N/A N/A 3-1/2" L-80 I 4,666'(est) Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 7" Champ IV Service Packer, No SSSV Packer 7,540' MD / 6,628' TVD (esq 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑� • Stratigraphic ❑ Development ❑ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 3/17/2015 Oil❑ Gas ❑ WDSPL ❑ Suspended ❑ WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ 16. Verbal Approval: Date: Commission Representative: GSTOR ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Michael Quick Email michael.0uick@ S2rveXf2rDOS.rBDS01.COrll Printed Name gill Hartlham Title Operations Manager Signature Phone Date �1 907-375-6917 3/16/2015 COMMISSION USE ONLY Conditions of approval: NollCommission so that a f�elpresentative may witness � Sundry Number: 3 � � ^ \ �� c �� ��^c.� �ttTc✓'ri.( /L� Ctd' °i'r4-c, l ''�-t "'�� P, Plug Integrity❑BOP Test Mechanical Integrity E]�grity Test ❑ Location Clearance Other: POSJ,. T /7� 6t 1 ref t),rcA 1� *,L FrMCFOL'us Ck4"'_4C0..Q � DiSGIowre Reg(S{i, Www. '�i CAL'.iS.Or� Plus o at re�vle�i•�7v✓G�S �d 20AAC2ssR83 -�• Strr� ek-Q . i�? f1�oV/c�/r%y// Y1/at //� Spacing Exception Required? Yes ❑ No L✓] Subsequent Form Required: C/07 (6 • "�� �- l Q — APPROVED BY Approved by COMMISSIONER THE COMMISSION Date: 3 —/C( 1 s - 2i - 18 S yq 3 1 tS submit Form and Form 10-403 ( vised 10/2012) U,Hd1aUc1dNAiLo, 12 montqs from the dale of approval. Attachments in Duplicate Msc MAR 2 0 10' March 16, 2015 Alaska Oil and Gas Conservation Commission 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 RE: 10-403 Sundry for Well Stimulation and Well Testing Operations: Repsol Qugruk 301 PTD 214-199 Dear Commissioner: RECEIVED MAR 16 2015 .4 AOGCC 1— REPlOL Repsol hereby submits an Application for Sundry Approvals for the completion, stimulation and well testing operations in Qugruk 301, permit to drill 214-199. Qugruk 301 was spudded 2/18/2015, and the estimated total depth of 7,531' should be reached on 3/17/2015. The completion, stimulation and testing procedure is attached with the form 10-403 sundry application. Pertinent information attached to this application includes the following: 1. Form 10-403 Application for Sundry Approvals 2. Completion, Stimulation and Well Testing Procedure 3. Stakeholder Notification Affidavit and Offset Well Data 4. Proposed Completion Schematic 5. Casing and Tubing Design Cases 6. Frac Tree Diagram 7. Produced Fluid Plan 8. Well Testing Surface Equipment Layouts The AOGCC is requested to treat as confidential all information included. If you have any questions or require additional information, please contact Bob Jones, Drilling Manager at 832-442-1618, myself at 907-375-6917, or the technical contacts contained in the following pages. Sincerely, Bill Hardham Operations Manager Repsol USA qI QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL Additional Information Attachment � r�Completion 8 Well Test Summary • Perform dummy BHA run to TD at 7,531'. • Hang off the dummy BHA and perform an AOGCC BOP Test per PTD. • Displace OH & production casing to SFMOBF, POOH. • P/U and run the +/- 2,600', 4-1/2" liner assembly. • Set the hanger and test the liner top and liner to 250 psi for 5 mins and 4,000 psi for 30 min. • Release from the liner hanger and POOH w/ the DP and liner setting tool. • P/U and TIH with 3-1/2" test string, test the tubing to 4,500 psi for 10 mins every 1,000'. • Land the tubing hanger and test the seals to 250 psi for 5 mins and 5,000 psi for 10 mins. • Test the 3-1/2" tubing and 4-1/2" liner to 250 psi and 4,000 psi for 10 mins. • N/D the BOPs and N/U the 10K 4-1/6" frac tree. • Test the hanger x adapter void to 250 psi for 5 mins and 5,000 psi for 10 mins. • Test the frac tree to 250 psi for 5 mins and 7,000 psi for 10 mins. • R/U the 4-1/16" CT riser and BOP and test to 250 psi for 5 mins and 3,500 psi for 10 min. • R/U the CTU, and remaining well test lines to the tree and test the system to 250 psi for 5 mins and 3,500 psi for 10 mins. • Perform an AOGCC BOP test on the CT BOP to 3,500 psi. • R/U the 4" 1002 frac line to the tree and P/T same to 7,000 psi for 10 mins. • Open the well and pressure up the tubing and liner to open the hydraulic toe sleeve. • Perform a DFIT test. • Analyze DFIT and finalize frac design. • Pump frac stages 1-6 with a maximum allowable surface treating pressure of 6,000 psi while holding 2,000 psi on the annulus. . " C Perform CT fill clean out operations if required. • Shut-in the well for a minimum of 6 hours to allow the crosslinked fluid time to break and the RC proppant to bond. • Open the well and flow back frac fluid w/ N2 lift assist. • Perform a multi -rate flow test. • Close the DH test valve and perform a BU test. • Open the DH test valve and perform a final flow test to recover oil soluble tracer samples. Bullhead kill weight SFMOBF down tubing & flow check well .-*Ie • {�� 4 , RIH with slick -line and install a PX plug. • N/D the frac tree and N/U the BOPs. a TBPv • Perform an AOGCC BOP test. • ( `N ') RIH with slick -line and retrieve the PX plug, R/D slick -line. • Pull the upper completion string and UD the jewelry and rack back the tubing. • Prepare for abandonment operations. Page 1 of 5 QUGRUK-301 Completion & Well Test 10-403 Sundry Information RERfO[ Planned Completion Pressure Testing Operations As per the AOGCC regulation 20 AAC 25.238 (b) & (c)(2), the tubing and intermediate casing will be tested to 110% of the maximum anticipated differential pressure. As presented in section 8.3 the intermediate casing was pressure tested to 4,500 psi successfully on 3-13-15. The maximum differential pressure anticipated on the intermediate casing based on a 0.45 psi/ft pore pressure gradient is 3,103 psi. Therefore, the intermediate casing was tested to 145% of the maximum anticipated differential pressure. As per the completion program the 3-1/2" production tubing will be tested to 4,500 psi with 9.4 ppg completion fluid while tripping in the hole. Based on a maximum annulus pressure of 2,000 psi applied to the annulus during the hydraulic fracture treatment, the maximum anticipated differential pressure on the tubing will be 6,000 psi (MASP) — 2,000 psi = 4,000 psi. Therefore the proposed test pressure of 4,500 psi will be 112% of the maximum anticipated differential pressure. c"' Additional pressure testing information can be found in the above Completion & Well Test Summary. 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Stn OD Xflo, 4MJOOM7 151 vm cos �.14 225n 10 X6,70 M0 M3 40 teng8F10137MG IO TSI WWW 5 OD -101017'105 -. 7 r, Tri 12248510 564 0, '4 iJ,Ik1 32182-04 A 'Z� a449IL4 A 34lAT64 4Jf/: Q.W B,SaatA]3mxY -- 3-102' wAHJnng am S'ce :,55.24 A Page 5 of 5 5380 2280 &d3 450707 5000 2250 lag 454156 7000 2250 200 4545.58 7.a30 3500 lass 4545.58 7800 2250 200 4558.18 5000 22250 208 456018 3887 2992 8200 4582.25 5000 2250 2.00 %2426 5000 2250 402 462626 5030 22.50 5.00 463028 5000 2250 208 463528 3958 1648 633736 465184 !65]84 REPSOL E&P USA USA ALASKA REP,.IOL QUORUK 30 1 COMPLETION & WELL TEST 10-403 Sundry Information J QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPIOL Table of Contents 1. Completion Overview................................................................................................4 2. Completion Summary ................................................................................................5 3. Well Information........................................................................................................7 3.1. Basic Well Data..................................................................................................7 3.2. Reservoir Data....................................................................................................7 4. Operations Sequence & Time Estimate....................................................................8 5. Stakeholder Notification Affidavit...............................................................................9 5.1. Offset Well Locations........................................................................................10 5.2. Offset Well Trajectories....................................................................................11 5.3. Offset Wellbore Distances from Q-301.............................................................13 5.4. Offset Well Mechanical Condition.....................................................................13 6. Offset Water Well & Fresh Water Aquifer Identification...........................................16 7. Casing & Cementing Information............................................................................17 7.1. Detailed Casing & Tubing Information..............................................................17 7.2. Casing Cementing Job Report..........................................................................18 7.3. 9-5/8 Intermediate Casing Cement Evaluation Logs........................................21 8. Pressure Test Information.......................................................................................22 8.1. Surface Casing Pressure Test Chart................................................................22 8.2. Intermediate Casing Pressure Test Chart........................................................22 9. Wellbore, Wellhead and Frac Tree Information.......................................................23 9.1. Q-301 Proposed Completion Schematic..........................................................23 9.2. Wellhead and 10K Frac Tree Drawing..............................................................24 10. Target Fracture & Confining Zone Information.....................................................25 10.1. Depths, Thickness' & Estimated Fracture Pressures....................................25 10.2. Lithologic Zone Descriptions.........................................................................25 11. Geological Fault Information................................................................................32 11.1. Nanushuk Coherence Fault Map...................................................................32 12. Proposed Hydraulic Fracturing Program..............................................................33 12.1. Proposed Pump Schedule.............................................................................33 Page 2 of 43 ®OUGRUK-301 Completion & Well Test 10-403 Sundry Information REP., 12.2. Maximum Anticipated Treating Pressures.....................................................34 12.3. WellCat Stress Analysis................................................................................35 12.4. Formation Mechanical Properties and Stress Model.....................................38 12.5. Estimated Fracture Geometry.......................................................................39 12.6. Fluid Description & Chemical Disclosure.......................................................40 13. Proposed Clean -Up and Well Test Program........................................................41 Page 3 of 43 J .� QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPIOL 11 1. Completion Overview The Qugruk-301 well was the first operation to begin drilling for Repsol on the North Slope during the 2014-15 Exploration season. The well is intended to build on the positive results of the Qugruk-3, Qugruk-3A and Qugruk-7 wellbores, drilled during Repsol's 2013 and 2014 winter campaigns. Qugruk-7, located about 4 miles north of the planned Qugruk-301 location, successfully tested the presence and productivity of the Nanushuk sands. Qugruk-3 results confirmed the good quality of the Nanushuk reservoir.. A single 0-301 wellbore has been planned to penetrate +/ 2,200' of the Nanushuk sands at 900. 2,000' of the lateral will be used for formation evaluation purposes leaving the remaining 200' of rathole for operational requirements. The 0-301 wellbore is planned to reach a total depth of 7,531' MD / 4,187' TVD. A total of 35 days including 6 contingency days have been estimated to install the completion, perform the fracturing and well test operations, and de -complete the well in preparation for abandonment. Following the completion and testing operations an additional five days have been allocated to abandon the well and lay down the rig prior to demobilization. The actual time available for these operations could be more or less than the allocated time and will ultimately be controlled by the operational efficiency achieved and the planned end of drilling operations date of April 15, 2015. The well ice pad is located 19 miles into the Colville Delta by ice road from Conoco Phillips DS2M drilling pad. The DS2M pad is approximately 50 miles by gravel road from Deadhorse, AK. Repsol's Qugruk area operations will be logistically supported from Deadhorse, AK, and Anchorage, AK. Flight services will be provided from Anchorage, AK, and Fairbanks, AK, to an Ice Runway located 7 miles East from the Qugruk-301 location. The health and safety of all personnel involved in the execution of this program, as well as the protection of the environment in which the operations take place, are of overriding importance at all times. It is of the utmost importance that all staff involved in the execution of this program remain vigilant with respect to the completeness and correctness of all associated plans, procedures, and instructions, and where required, verify their correct understanding thereof, especially where the safety of the rig, its crews and the environment are concerned. Page 4 of 43 J MW QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPlOL 2. Completion Summary The Qugruk-301 completion design has been based on meeting the primary objective of evaluating the flow performance of a horizontal well with multiple hydraulic fracture stimulations in tlLNanushuk A & B horizons. The results of the evaluation will be used to estimate the productivity of the proposed Nanushuk development wells. The design incorporates performing —a -six stage hydraulic fracture treatment in a +/- 2,200' horizontal wellbore with an orientation parallel to the main Nanushuk fault system and depositional trend (NNE -SSW). Due to the uncertainties involved, the completion has been designed to minimize the amount of time required to move from the rig operations to the stimulation and testing operations. An un- cemented liner with oil activated swell packers for zonal isolation will be used to facilitate a six stage hydraulic fracture treatment intended to maximize the fracture to wellbore communication and provide optimum productivity from a conductive fracture network. The procedure will include the pumping of a Diagnostic Fracture Injection Test (DFIT) prior to the fracturing treatments from which the data will be analyzed to determine the formation Closure Stress and possibly the reservoir pressure and kH. The derived values for these key modeling parameters will then be used to optimize the hydraulic fracture designs. The upper completion string will be equipped with a permanent gauge that will transmit real time bottomhole pressure data to surface via an encased conductor line. In addition to the real-time gauges the upper completion will have two additional carriers equipped with surface read out (SRO) gauges which can be polled via acoustic signal to provide downhole BHP and temperature data on demand. In addition to the downhole pressure surveillance, the upper completion will also incorporate a downhole sample carrier and corresponding acoustically triggered sample tubes that will be used to collect oil samples for PVT analysis during the flow test period. A tubing string test valve will be installed in the string in order to provide a method of pressure testing the tubing string while tripping in the hole. An annular pressure cycled test valve will also be installed in the string to provide a downhole shut-in point at the start of the build-up phase or any time a downhole shut-in is required. The upper completion string will also have a chemical injection sub installed with a 3/8" injection line run to surface to provide an injection point for thermodynamic hydrate inhibitor during the cleanup and well test phases. A 10K psi frac tree will be installed under the rig floor after landing the upper completion which will enable the fracturing treatments to be performed without the need to move the rig off the Page 5 of 43 qW OUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL hole in addition to eliminating the need for a tree isolation device. The frac tree design will also allow for the rig up of coiled tubing or wireline on the rig floor without the need to rig down the frac treatment lines. The surface well testing equipment will be tied into the flow cross on the tree allowing for a rapid transition between the fracturing and well test operations. Page 6 of 43 QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL 3. Well Information 3.1. Basic Well Data Well Number: Qugruk-301 Well Type: Oil Producer Final Depth: 7,531' MD / 4,180' TVD AFE Number: NS 14 004 WBS Number: SA41.43.E1501 Permit to Drill Number: 214-199 API Number: 50-103-20700-00 Estimated Completion Start Date: March 15, 2015 Rig Name: Nabors 105 Pad Elevation: 17' Estimated RKB-MSL: 20' Surface Co-ordinates: 1,728' FEL, 1813' FSL, SEC 6, T11N, R6E, UM KOP: 2,300' TD Co-ordinates: 298' FEL, 423' FSL, SEC 31, T12N, R6E, UM TD MD 7,531' TD TVD 4,187' Maximum Inclination 900 3.2. Reservoir Data Reservoir Name: Nanushuk Estimated Reservoir Pressure: 1 8F0-19.0 P-si Reservoir Pressure Gradient: 0.44 - 0.47 psi/ft Estimated Reservoir Temperature: 110°F Estimated PWF: 800 — 1,700 psi Crude API Gravity: 30-320' Estimated Bubble Point Pressure: 1,600 psi H2S Content: 0% CO2 Content: 0.02% Estimated Production Rate: 600-2000 BOPD Reservoir Depth: 7,531' MD, 4,180' TVD Page 7 of 43 - _F 1W QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPlOL 4. Operations Sequence & Time Estimate P10 P50 P90 Page 8 of 43 Days Days Days 1 Perform Dummy BHA Run 0.7 0.8 0.9 2 Displace OH & Production Casing to SFMOBF 0.2 0.2 0.3 3 P/U and Run 4-1/2" Liner 1.5 1.7 2.1 4 Set Hanger 0.2 0.2 0.2 5 Test Liner Top, Release from hanger 0.2 0.2 0.2 6 POOH w/ DP and Liner Tool 0.5 0.6 0.7 7 BOP Test 0.5 0.5 0.6 8 P/U and TIH with DST string 1.4 1.6 2.0 9 Land DST string and test seals and tubing N 3 hQ"(J 0.5 0.5 0.6 10 N/D BOPs and N/U Tree and CT Riser and Test Same 0.6 0.7 0.8 11 R/U CTU, Frac and Well Test lines to Tree and P/T same 2.3 2.5 3.1 12 Pressure up tubing and liner to open the hydraulic toe sleeve 0.0 0.0 0.1 13 Perform DFIT test 0.04 0.04 0.05 14 Analyze DFIT and Finalize Frac Design 0.5 0.5 0.6 15 Pump Frac Stage 1 0.04 0.04 0.05 16 (CONTINGENCY) CT Fill Clean Out 0.9 1.0 1.3 17 Drop ball and pump Frac Stage 2 0.04 0.04 0.05 18 (CONTINGENCY) CT Fill Clean Out 0.9 1.0 1.3 19 Drop ball and pump Frac Stage 3 0.04 0.04 0.05 20 (CONTINGENCY) CT Fill Clean Out 0.9 1.0 1.3 21 Drop ball and pump Frac Stage 4 0.04 0.04 0.05 22 (CONTINGENCY) CT Fill Clean Out 0.9 1.0 1.3 23 Drop ball and pump Frac Stage 5 0.04 0.04 0.05 24 (CONTINGENCY) CT Fill Clean Out 0.9 1.0 1.3 25 Drop ball and pump Frac Stage 6 0.04 0.04 0.05 26 (CONTINGENCY) CT Fill Clean Out 0.9 1.0 1.3 27 Open well and flow back Frac Fluid w/ N2 Lift Assist 1.8 2.0 2.5 28 Flow Test Well 4.5 5.0 6.3 29 Flow Test Continued 4.5 5.0 6.3 30 Close Test Valve and perform BU Test 4.5 5.0 6.3 31 Bullhead kill weight SFMOBF down tubing & flow check well 0.3 0.1 0.2 32 (CONTINGENCY) RIH with slick -line and install PX plug 0.3 0.3 0.4 33 N/D the Frac Tree and N/U the BOPS 0.5 0.6 0.7 34 BOP Test 0.4 0.4 0.5 35 (CONTINGENCY) RIH with slick -line and retrieve PX plug, R/D slick -line 0.3 0.3 0.4 36 Pull DST string and L/D jewelry and rack back tubing 0.5 0.6 0.7 Totals w/ Contingencies 31.4 35.5 43.4 Page 8 of 43 QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL 5. Stakeholder Notification Affidavit AFFIDAVIT OF ROBERT P. IOLNES STATE OF TEXAS COUNTY OF MONTGOMERY 1, Robert P. Jones, being first duly sworn ander oath, suite: I am the Drillinp Manager, Onshore Drilling, USA for REPSOL E&P USA INC (" Repsol'j, a corporation duly organized and existing under the General Corporation Law of the State ofDelaware. 2. 1 am over twenty one (21) years of age. The matters discussed in this affidavit arc true and correct to the best of my knowledge. 3. Repsol has made the notices required by and in compliance with the requirements of Title 20 of the Alaska Administrative Code, Chapter25, Section 283(axl ). Further Affiant sayeth not. RO NES SUBSCRIBED AND SWORN to before me this104%day of Mardi 2015, �,. ALEXANDER tOggtS NMNY 'UbiS alma Dl "s My rom 5W 1 2015 �k lit nsCeRlEgr 1$ 2016 Offset Well Location Information Public in and for the Star of Texas ° �ffsS Printed Name of Notary Page 9 of 43 QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL 5.1. Offset Well Locations As per the plat below the only offset well within a half mile radius of the Qugruk-301 wellbore are the Qugruk-3 and Qugruk-3A wellbores that were drilled and permanently abandoned during the 2012-2013 Repsol exploration campaign. Qugruk 3 & 3A Surface Location NAD27 Alaska State Plane, Zone 04, US Ft Latitude N 70 20 2.216 Northing: 5972219.00 ft US Grid Conversion -0.666- Longitude W 150 42 24.436 Easting: 412876.00 ft US Scale Factor 0.99990862 Page 10 of 43 QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOI 5.2. Offset Well Trajectories Qugruk-3 & Qugruk-3A -,11110 .3CC' -2000 -1000 1000 ?:00 500 400 300 fi Z F O 2MO 0 0 13 4000 300 -200 -1000 0 1000 200 <<< W 3e le = 1:10DOM) E "• Page 11 of 43 5011='. 40011 aacc mon 1000 0 -1000 �w QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL Qugruk-3 & Qugruk-3A usr ac F Z5 MIX 3000 7500 8000 4500 -3000 -1500 0 1500 Vertical Section (R) Azim = 172.14• Soak = 1:1500(h) Origin = 0 WS. 0 EI -V Page 12 of 43 acus 1500 I 3000 4500 7500 `9070 3000 QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOI 5.3. Offset Wellbore Distances from 0-301 Due to the fact the maximum predicted fracture height resulting from the proposed Qugruk-301 fracture stimulation treatments will be 214' (4,120'-4,334' TVD), the distances from the Qugruk- 301 intermediate casing shoe have been calculated and presented below at the 4,000' TVD and 4,500' TVD intersection points for reference purposes. Distance from the 0-301 9-5/8" Casing Shoe, 5,235' MD, 4,185' TVD To 0-3 Intersection at 4,000' TVD - 2,331' To 0-3A Intersection at 4,000' TVD - 1,380' Intersection at 4,500' TVD - 2,519' Intersection at 4,500' TVD - 1,133' 5.4. Offset Well Mechanical Condition The Qugruk-3 and Qugruk-3A wellbores were permanently abandoned during Repsol's 2012- 2013 exploration campaign as per the approved 10-403 abandonment sundries; 313-151 and 313-184 respectively. The following final well schematics submitted to the state show the two offset wellbores are effectively isolated with cement across the target Nanushuk interval as well as the other hydrocarbon bearing reservoirs. The table below shows the relationship between the cement placed in the Qugruk-3 and Qugruk-3A wellbores in relationship to identified top of the Nanushuk sands in the Qugruk-301 wellbore and the estimated bottom of the Nanushuk sands. The table also shows the predicted upper and lower fracture propagation heights and predicted fracture half-length for the proposed Qugruk-301 fracture stimulation treatments that will be performed. Based on the Nanushuk coherence fault map and the orientation of the principal faults in the area, it is assumed that the maximum horizontal principal stress in the Nanushuk horizon will be equivalent to the wellbore azimuth and therefore longitudinal fracture propagation is anticipated in the six stage fracture stimulation treatment. All six of the fracture stimulation stages will be identical in size and therefore the predicted height and length propagation. As per the tentative 4-1/2" production liner tally the 6"' and closest frac sleeve to the Q -3A wellbore will be positioned at 5,518' MD, 283' from the 9-5/8" intermediate casing shoe. Therefore, from the table presented in section 6.3, the closest frac sleeve will be located +/- 1,500' away from the Q -3A wellbore in the zone of interest. Based on the predicted orientation and fracture half length, the tip of the fracture propagated in the 6`h stage should terminate at 5,335' MD close to the 9-5/8" production casing shoe, assuming the fracture initiates in the close proximity of the frac sleeve. ,. Offset Wellbore Isolation Reference Top & Bottom of Nanushuk Sand 4,096' - 4,341 TVD" 245' Cement Plug in 0-3 3,502' - 4,600' TVD 1092' Cement Plug in Q -3A 3,959' — 4,327' TVD 368' Predicted Max Frac Height in Q-301 @ Initiation Pt. 4,120'— 4,334' TVD 214' @ 160' from Initiation Pt. 4,158' - 4,240' TVD 82' Predicted Propped Frac Half Length @ Initiation Pt. 182' Page 13 of 43 QUGRUK-301 Completion & Well Test 10-403 Sundry Information REP -ML Qugruk 3 Schematic Rig 7ES RKB: 29' -3 Elevation: 17' RKB to MSL 46' 1080' Permafrost Base 13-3/8" Casing cemented to Surface ; w/53 bbls cement returns at surface (pumped 830 bbls (1680 sx) ASLO lead and 80 bbls (397 sx) Class G tail) 2250' Upper Cretaceous MFS 2462' Tuluvak/Seabee 3815' Nanushuk 5010' Torok 6292' HRZ 6527 Kuparuk C 6733' Alpine 6980' Nuiqsut Tag @ 2708' 108 bbls 17.0 ppg Class G Tag @ 3502' 100 bbls 17.0 ppg Class G 115 bbls 15.8 ppg Class G 10.4 ppg KWM Tag @ 6852' 120 bbls 15.8 ppg Class G Page 14 of 43 �— 26" Hole 20" 131# J-55 Casing @ 113' MD 16" Hole 13-3/8" 68# L-80 BTC -4— Casing @ 2120' MD 12-1/4" Hole 19° Inclination TO @ 7500' MD / 7234'TVD ® QUGRUK-301 Completion & Well Test 10-403 Sundry Information RERPOL Qugruk 3A Schematic Rig 7ES RKB: 29' Q-3 Elevation: 17' RKB to MSL 46' 3817' Nanushuk 4955' Torok 6316' HRZ 6538' Kup C 6724' AI ine Q° Q 2 / 1 26" Hole-- ► 42 bbls 15.7 ppg Permafrost curt 20"131# J55� 13-318" CIBP @ +/- 280' 16" Hole 10 12.1 ppg KWM 37.5 bbls 15.8 ppg 13-318" 68# L-80 BTC Class G Casing @ 2120' MD --' ' - 12.1 ppg 13-318" Retainer KWM @+/-2060'MD 73 bbls 15.8 ppg '" " KOP @ 2708' MD Class G Build to 58 degrees and held to TD 12.1 ppg jKWM OT �6 .2Q�J P p 6952' Nuiclsul' Nh G G R TD @ Calc TOC 10546' MD / @ 8003' 7205' TVD ' 8-1/2" Hole Fish: 5-7/8" bit, 2000ft 4-W'Tubing, 640ft 5" HWDP, 1500ft 5" drill pipe Page 15 of 43 A 1 QUGRUK-301 Completion & Well Test 10-403 Sundry Information RERrQL 6. Offset Water Well & Fresh Water Aquifer Identification Permafrost ranges 1000-1100 ft thick within a 1/2 mile radius of the Q-301 wellbore. Subsurface data shows that there are no underground sources of drinking water/aquifers (typically found up to 400 ft depth) in the vicinity of this well. Based on the absence of water wells or fresh water aquifers within a 1/2 mile radius of the Q-301 wellbore, it is Repsol E&P USA Inc. belief that we are exempt from complying with regulation 20 AAC 25.238 (a)(4). \ N Base Permafrost Map Page 16 of 43 A qw OUGRUK-301 Completion & Well Test 10-403 Sundry Information REPXGL 7. Casing & Cementing Information 7.1. Detailed Casing & Tubing Information Tubular and Annular Capacity Data: Tubing size (inch) Hole I.D. (inch) Capacity (Bbls/ft) Capacity (cu ft/ft) Annulus Capacity (Bbls/ft) Capacity (cu Wit) 3-1/2 9.3 2.992 Size Depth Wt. 0.0613 0.3442 I.D. Drift Hole Section Size 4-1/2" 12.75 L-80 TC -11 8,440 7,500 Grade Connection (inch) (ft) (Ib/ft) (inch) (inch) (inch) Surface 2,107' MD 16" 13-3/8" 68 L-80 BTC 12.415 12.259 (Actual) 2,107' TVD Production 5,235' MD Casing 12-1/4" 9-518" 47 L-80 BTC 8.681 8.525 4,187 TVD (Actual) Production +/- 7,531 MD Liner 6-1/2" 4-1/2" 12.75 L-89 TC -II 3.958" 3.833" +/- 4,187' TVD (Planned) Tubular and Annular Capacity Data: Tubing size (inch) Weight (lb/ft) I.D. (inch) Capacity (Bbls/ft) Capacity (cu ft/ft) Annulus Capacity (Bbls/ft) Capacity (cu Wit) 3-1/2 9.3 2.992 0.0087 0.0488 3 -'/2 x 9-5/8" 0.0613 0.3442 Tubing and Liner Mechanical Properties: Weight Internal Collapse Tensile Body Tensile Conn. OD (inches) Grade Connection (Ibfft) Yield (psi) (1000 lbs) 11000 lbs) (psi) 3-1/2 9.3 L-80 TC -11 10,160 ✓ 10,530 207 207 4-1/2" 12.75 L-80 TC -11 8,440 7,500 288 288 Page 17 of 43 _ ,A 4 QUGRUK-301 Completion & Well Test 10-403 Sundry Information REWOL 7.2. Casing Cementing Job Report 7.2.1. Surface Casing Cement Job Report The 13-3/8" surface casing was cemented with Permafrost L and Class G cement. The job began with 80 bbls of 11.0 ppg spacer being pumped followed by 230 bbls of 10.7 ppg Permafrost L cement when cement returns were noted at surface. 60 bbls of cement had returned to surface when returns were lost. An additional 57 bbls of cement was pumped at a slower rate attempting to regain circulation without success. A total of 65.9 bbls (318 sx) of 15.8 ppg Class G tail was then pumped without returns. The plug bumped and floats held. A 1" pipe was used to tag top of cement in the annulus at 40ft from surface. A top job was performed (with AOGCC approval), requiring 6 bbls of 11.0 ppg Permafrost L to bring cement to surface. Cement Type Volume Pumped Density Lead Permafrost L 347 bbls / 450 sx 10.7ppg✓ Tail Class G 65.9 bbls / 318 sx 15.8 ppg✓ Top Job Permafrost L 4.3 bbls 11.0 ppg✓ The surface casing pressure test to 2500 psi was charted and successful, followed by a 13.7 ppg LOT at 2145' MD / TVD. Lead Cement Job Log 1titN b i'A. o._u. 34;C.W. YUE Page 18 of 43 kA< OUGRUK-301 Completion & Well Test 10-403 Sundry Information REPlOt Tail Cement Job Log 7.2.2. Intermediate Casing Job Report The intermediate casing cement job was completed in 2 stages. The first stage began with pumping 60 bbls of 11.0 ppg spacer, followed by 89 bbls of 14.0 ppg Class G cement, full returns throughout. The plug did not bump but floats were checked and held. The stage tool at 3008' MD was opened and circulation established while WOC. The second stage started with 60 bbls of 11.0 ppg spacer, followed by 187 bbls of 12.2 ppg Type 1/11 cement, full returns throughout with no cement to surface. The plug bumped and the stage tool was closed. Cement Type Volume Pumped Density Stage 1 Class G 89 bbis / 326 sx 14.0 ppq✓ Stage 2 1 Type 1/11 187 bbls / 463 sx 12.2 ppg Page 19 of 43 REPtOL 3 OUGRUK-301 Completion & Well Test 10-403 Sundry Information Daily Drilling Report Time Breakdown for 9-5/8" Intermediate Casing Cement Job OPERATION SUMMAR, ! Flom To Our. Phase AC1W Op, Tme Operatlm diner 9m (W Code Clew 6:00 9:00 3.00 INTI 04 05A P CIRC BOTTOMS UPAT 5232. B/U GAS 60 UNITS. MUD CHECK WHILE CIRCULATING AT 5232: MW 10 41N 110.4 OUT - PV 331 YP 15 900 10:00 1.)0 INTI 04 13A P LAND 9Ji/8 CASING ON LANDING COLLAR. RID CASING RUNNING TOOLS. PAJ 185K 50160K 10:D0 12:00 2.00 INTI 04 01E P MOVED CEMENT HEADS UP TO RIG FLOOR. LOADED HEADS AND STACKED DUAL HEADS ONTO CASING. MAJ CIRC HOSE TO CEMENT HEADS. TRANSFER MUD FOM PITS TO VAC TRUCK WHILE RAJ HEAD. /2:DD 15:30 3.50 INTI D4 D5A P CIRC WITH RIG PUMPS AT 2 BPM WHILE CONT RAJ FOR CEMENT JOB AND CLEANING RIG FLOOR. NO LOSSES. BUILD SPACER WHILE CIRC. 15:30 19:00 3.50 INT1 04 12A P PERFORM FIRST STAGE CMT JOB- \ \l PRESSURE TEST CEMENT LINES TO 3700PSL PUMP 60 BBLS OF 11.0 PPG TUNE SPACER AT 3 BPM. DROP BOTTOM PLUG. MIX AND PUMP 326SX OF 14.0 PPG CLASS G DMT SLURRY (89 BELS; 498 CUFT, 60 BELS MIX WATER) AT 3 BPM. DROP TOP PLUG. DISPLACE CEMENT IN PLACE WITH HALL18URTON UNIT. PUMPED 5 BELS WATER FOLLOWED BY 149 BELS 104 PPG MOBM FOLLOWED BY 20 BBL 11.0 PPG SPACER FOLLOWED BY 204 BBLS OF 104 PPG MOBM (TOTAL OF 378 BBLS). DISPLACED AT 34 BPM DID NOT BUMP PLUG. BLED OFF PRESSURE. FLOATS HELD. IS 8815 BACK TO DISPLACEMENT TANKS. 'CEMENT IN PLACE AT 19:00• UNABLE TO SHIFT OPEN STAGE TOOL WE TO NOT BUMPING PLUG FULL RETURNS FOR ENTIRE CEMENT JOB. 1900 2000 1.00 INT1 D4 12A P DROPPED HALUBURTON STAGE TOOL SHIFTING DEVICE LET FREE FALLFOR 20 MIN. PRESSURED UP WITH HALLIBURTON UNITAT 050 BPM. STAGE TOOL SHIFTED OPEN AFTER PUMPING 12S BELS WITH 500 PSI, 20:00 21:00 1.00 INTI 04 05A P CIRCULATED THROUGH STAGE TOOL USING HALLIBURTON UNIT WITH 10.4 PPG M08M AT 4 BPM. OBSERVED SPACER CONTAMINATED MUD RETURNING TO SURFACE -30 88LS EARLY. OPENED SHAKER BYPASS AND DUMPED 116 BBLS OF CONTAMINATED MUD SAW NO EVIDENCE OF CNITTO SURFACE. 21A0 OW 3.00 INTI 04 05A P CONT CIRC THROUGH STAGE TOOL WITH RIG PUMPS AT 48PM WHILE ALLOWING CEMENT TO SET. WASHED OUT THE CEMENT UNIT. NO LOSSES OBSERVED. 000 1:00 1 W INTI 04 12A P STOPPED PUMPING AND LOADED THE PLUGS IN DOUBLE CEMENT HEADS. 1:00 3:00 2.00 INTI 04 OSA P CONT CIRC THROUGH STAGE TOOL WITH RIG PUMPS AT 4 BPM WHILE ALLOWING CEMENT TO SET. HHD PRE JOB SAFETY MEETING WITH HALLIBURTON AND NABORS PERSONNEL NO LOSSES OBSERVED. 390 6:00 3.00 INr1 04 D5A P PERFORM SECOND STAGE CEMENT JOB_ PRESSURE TEST CEMENT LINES TO 2500 PSI. PUMP 60 BELS OF 11.0 PPG TUNE SPACER AT 3 BPM. DROP BOTTOM PLUG. MIX AND PUMP 463SX OF 12.2 PPG TYPE 112 CMT SLURRY (187 SBLS; 1049 CUFT, 162 BBLS MIX WATER) AT 3 BPM. DROP TOP PLUG. DISPLACE CEMENT IN PLACE WITH HALLIBURTON UNIT. PUMPED 5 BBLS WATER FOLLOWED BY 220 BBLS 10.4 PPG MOBM. BUMPED PLUG. PRESSURED UP TO 2450 PSI AND SHIFTED TOOL TO CLOSE POSITION. BLED BACK 4.5 BBLS TO DISPLACEMENT TANKS. DUMPED 143 BBLS OF SPACER I CEMENT CONTAMINATED MUD. NOTED SPACER BACK TO SURFACE -50 BELS EARLY. "CMT IN PLACE AT 06:00 FULL RETURNS FOR ENTIRE CEMENT JOB. '-NOTE: 164 BBLS MOBM TO GSA` Page 20 of 43 -- _IV "IV QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPTOL First Stage Cement Job Log Second Stage Cement Job Log I❑ADOIS '):J01 2 STAGE II T-Rf0,[DJVE 1morn ISDA01 7.3. 9-5/8 Intermediate Casing Cement Evaluation Logs The USIT log shows a top of cement at approximately 3810' MD. ST JRSAV 3 0 ECC F IR N_#r�RF 7�V -'RF CLUE X CRM kORMX RF HAV RF RV,;IRAN RF HNO rT� """%-- AZEC _VRA RIF ERA RF tHMN RF Page 21 of 43 A 4W OUGRUK-301 Completion & Well Test 10-403 Sundry Information REWOL 8. Pressure Test Information 8.1. Surface Casing Pressure Test Chart As per the approved permit to drill 214-199 the 13-3/8" surface casing was pressure tested to 2,500 psi on 3-1-2015. The results of the pressure test are shown on the graph below. M :y'8 CSG 14vssiPe Zest 0:101 3411201. 8.2. Intermediate Casing Pressure Test Chart As per the approved permit to drill 214-199, it is stated that the 9-5/8" intermediate casing will be pressure tested to 3,500 psi for 30 minutes. Due to completion considerations the intermediate casing was tested to 4,500 psi with 9.3 ppg MOBM on the 3-13-2015 (the BOPE was tested to 5,000 psi prior to casing test). The results of the pressure test are shown on the graph below. RF PSOI 0C311 9 62h CASING TFST &35:18 PM B:1.,. PM 9 V8:3811.1 935:18 PM 9:/1:58 PM 958:38 PM IQ15:19 PM G*,*Tun. Page 22 of 43 J9W Maxi ��19W Mri aro ro 11H1:IXW 12WAYIPM 1111.CCVM 11:3RWVM UASMM IWINI'M 1:LS=PM 1:3M YM 145W PM I9JI.0 PM YISW PM I:iPJYI I'M Panel Lnw 8.2. Intermediate Casing Pressure Test Chart As per the approved permit to drill 214-199, it is stated that the 9-5/8" intermediate casing will be pressure tested to 3,500 psi for 30 minutes. Due to completion considerations the intermediate casing was tested to 4,500 psi with 9.3 ppg MOBM on the 3-13-2015 (the BOPE was tested to 5,000 psi prior to casing test). The results of the pressure test are shown on the graph below. RF PSOI 0C311 9 62h CASING TFST &35:18 PM B:1.,. PM 9 V8:3811.1 935:18 PM 9:/1:58 PM 958:38 PM IQ15:19 PM G*,*Tun. Page 22 of 43 OUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL 9. Wellbore, Wellhead and Frac Tree Information 9.1.0-301 Proposed Completion Schematic 26" Hole i 20"131#J-55 Conductor ::i +1-100'MDI TVD 1 i i i 3 `'A' % PKKIe 1 X Chemi.al Injection Sub .:!+— 16"Hole jAcoustic Repeaters .-- 13-3/8" 68# L-80 Casing @ +1-2107' MD - VA" 9.3# L-80 Tubing Rig 105 RKB: 20' 0-5 Elevation w/ Pad Thickness: 17' KB to MSL: 37' Intermediate Stage 2: Stage tool @+I-3,000' MD � 3�r� /12-'L" Hole IJr� ipture Circulation Valve Annular Pressure Cycled Test Valva (2)Guads SRO 8-6/8" 474 L-80 Casing I., I.,,,,ve /@+1- 5,235 MD +I. 4,148'TVDSS (2)Sapphire SRO/ ` Test Gauges Real Time SRO Gauge DH Sample Center .11 400 cc sample tubes Expandable Linerl Hanger w/Seals Interne It 06 cal +1.4,600 KID +I-4,051-TVDSS Trseer Subs Page 23 of 43 External OS Chemi.al Tracer Subs To @ +/- 7,531' MD Oil Activated +/-4,110 TVDSS 5.11 Packers Reduntlant Hydmuli. Shut oO Free Valla Collar Fra. 61/2" Hole I T, Sleeves 4 %" 12.6# L-80 TC -II Un -cemented Liner BUIINoa. Guide Shoe A A QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPlOL 9.2. Wellhead and 10K Frac Tree Drawing Page 24 of 43 q QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL 10. Target Fracture & Confining Zone Information 10.1. Depths, Thickness' & Estimated Fracture Pressures * The Q-301 intermediate casing point will land at 90° in the Nanushuk sand stone and the production hole will maintain 90°-91° through the target. 10.2. Lithologic Zone Descriptions General Description of the Nanushuk Formation The Nanushuk Formation is a thick accumulation of shallow marine, deltaic and fluvial deposits and is the up -dip equivalent of the deeper water Torok Formation. The Nanushuk is often highly laminated and comprised of fine-grained sandstones, siltstones, and shale. It can contain lithic- clasts from various sedimentary and metamorphic sources. Distributary channel and mouth bar deposits comprise major sand packages in the Nanushuk Formation. Interdistributary sands are very fine-grained and interbedded with silt and bay -fill shales. Fluvial channel sands are generally fine to medium -grained, display cross and trough bedding and have conglomeratic bases. The Nanushuk sands were deposited during the highstand systems tract. The formation of interest that will be tested in the Qugruk 301 well is the Nanushuk 3, which is one of the proximal shallower stratigraphic sequences that can be found in the upper part of the Nanushuk-Torok package. It is expected to have fine grained sandstones interbedded with siltstones and some shale. The lower 40 ft of this formation becomes siltier, and is not considered part of the reservoir, but part of the confining zone below. The prograding sequences are overlain by a transgressive zone comprised of shales and siltstones with some scattered very fine grained sandstones, constituting a seal for the Nanushuk 3 sandstones. Page 25 of 43 FORMATION NAME DEPTH THICKNESS EST. FRAC PRESSURE(psi) TVD MD TVD MD Tuluvak 2454 2455 391 400 1786 Confining Zone Seabee 2845 2855 969 1187 2138 Confining Zone Nanushuk Fm Top 3814 4042 282 589 2925 Reservoir Nanushuk 3 Sandstone 4096 4631 245 245` 3318 Confining Zone Torok Top 4341 1 1557 1 3227 * The Q-301 intermediate casing point will land at 90° in the Nanushuk sand stone and the production hole will maintain 90°-91° through the target. 10.2. Lithologic Zone Descriptions General Description of the Nanushuk Formation The Nanushuk Formation is a thick accumulation of shallow marine, deltaic and fluvial deposits and is the up -dip equivalent of the deeper water Torok Formation. The Nanushuk is often highly laminated and comprised of fine-grained sandstones, siltstones, and shale. It can contain lithic- clasts from various sedimentary and metamorphic sources. Distributary channel and mouth bar deposits comprise major sand packages in the Nanushuk Formation. Interdistributary sands are very fine-grained and interbedded with silt and bay -fill shales. Fluvial channel sands are generally fine to medium -grained, display cross and trough bedding and have conglomeratic bases. The Nanushuk sands were deposited during the highstand systems tract. The formation of interest that will be tested in the Qugruk 301 well is the Nanushuk 3, which is one of the proximal shallower stratigraphic sequences that can be found in the upper part of the Nanushuk-Torok package. It is expected to have fine grained sandstones interbedded with siltstones and some shale. The lower 40 ft of this formation becomes siltier, and is not considered part of the reservoir, but part of the confining zone below. The prograding sequences are overlain by a transgressive zone comprised of shales and siltstones with some scattered very fine grained sandstones, constituting a seal for the Nanushuk 3 sandstones. Page 25 of 43 I 4W OUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL This sequence is overlain by the Tuluvak/ Seabee formation, a younger sequence with similar lithological characteristics to the Nanushuk-Torok pair. Accordingly, the Seabee is immediately overlying the Nanushuk formation, creating a good seal for the Nanushuk reservoir, as this formation gets shalier towards its base, with more than 800 ft of thickness in our area. The Nanushuk Formation transitions at its base into the Torok Formation, which is the deep water distal equivalent in age to the Nanushuk. It consists of turbiditic siltstones and shales deposited slopeward of the shallow marine shelf. The thickness from the base of the Nanushuk 3 package to the next possible reservoir, the basin floor fans deposited to the base of the shelf slope, is greater than 1500 ft in this area. Formation descriptions in more detail can be found below. Notice the increasing amount of siltstones, claystones and shales toward the base of each package. All of them are present in the Qugruk-3 well, the closest offset well for Qugruk 301, drilled in 2013. • Tuluvak / Seabee Sandstone/Sandy Siltstone - Light gray to olive gray, occasionally medium gray, very fine lower to very fine upper, well sorted, sub angular to sub round, very argillaceous, clay matrix supported with specks of organic detritus, Quartz with minor weathered Feldspar, light green and black lithics. Siltstone/Silty Claystone - Light gray to olive gray with common medium gray and rare medium brownish gray hues, firm to crumbly, sectile to plastic when clayey and while hydrated, tabular to rounded, , massive, occasionally grading to Silty Sandstone, more commonly grading to a Silty Claystone, clay matrix with common detritus, scattered carbonaceous material and rare carbonaceous -rich thin laminations, trace dark gray to black lithic grains as well as rare green hued lithic grains, very rare Glauconite, very rare very fine Pyrite, trace micro -micas. Siltstone/Silty Claystone/Sandstone - Siltstone is Medium gray to medium olive gray, firm to crumbly, moderately dense, tabular to occasionally platy cuttings, dull to earthy luster with trace sparkles, silty to gritty texture, common carbonaceous flakes and micas, trace lithics, non - calcareous. Claystone is slightly darker gray as compared to siltstone and overall firmer, more sectile when hydrated s compared to crumbly as seen in Siltstone cuttings, platy with weak planar fractures, commonly grading to/from Silty Claystone and Siltstone. Sandstone is grading from Silty Sandstone, light to medium gray, very fine overall, sub angular to sub round, Page 26 of 43 WEPXOL-.i QUGRUK-301 Completion & Well Test 10-403 Sundry Information R moderate to poorly sorted, clayey to silty matrix with common very fine lithics, dominantly Quartz composition, Claystone/ Siltstone - Claystone is medium gray to grayish brown, firm to soft when hydrated, tabular to platy, dull to earthy common waxy luster, smooth to clayey texture, very rare faint laminations, irregular to occasional platy fracture, weakly fissile overall, trace micas. Siltstone - Light gray to olive gray with common medium gray and rare medium brownish gray hues, firm to crumbly, tabular to rounded, massive, rarely grading to Silty Sandstone, common micas, carbonaceous material and fine lithic grains. Siltstone/Claystone/Tuff - Siltstone is medium dark gray to light gray, occasionally a grayish brown hue, soft to crumbly, pasty to mushy when hydrated, amorphous to sub round cuttings, silty to gritty texture with a clayey matrix, common black carbonaceous flakes, common to local abundant micas, rare carbonaceous thin laminations. Claystone is medium gray to dark grey, soft to firm, sectile to mushy, generally cuttings are deformed from bit with occasional sub -platy cuttings, sub planar fracture, smooth to clayey texture, earthy to dull luster, very rare micas, scatter slight darker gray and slightly denser clay -shale cuttings in samples. Calcareous Tuff is off white to white with scattered translucent white calcite, dominantly, soft and mushy amorphous cuttings with occasional sub round cuttings, trace fine <1mm clean crystalized calcite in samples and in mushy tuff cuttings, very dull mineral fluorescence, moderate reaction to very strong reaction with HCI dependent on the amount of crystalized calcite in cuttings. Siltstone/Claystone - Siltstone is medium gray to dark gray, occasionally light gray with a mottled appearance, easily friable to firm, sub round to sub tabular cuttings, common to locally abundant carbonaceous flakes, trace thin laminations, occasionally grading to a very fine grained friable silty sandstone, dominantly Quartz with minor Feldspar, light green and black lithic clasts, and Mica, trace disseminated Pyrite. Claystone is medium gray to dark gray, soft and mushy to slightly firm, sub blocky cuttings when firm, otherwise amorphous from bit action and hydration, locally common partings along thin laminations, common micas and scattered very fine lithic grains. Claystone is gradational to the Siltstone as described above. Siltstone/Silty Shale/Claystone/Tuff - Siltstone is medium gray to dark gray, occasionally light to medium gray with a mottled appearance, easily friable to firm, sub blocky cuttings with rounded edges to occasional sub tabular cuttings, gritty texture, common to locally abundant specks and flakes of carbonaceous material and occasional very fine sand, trace thin laminations, occasionally grading to a very fine grained friable silty sandstone with bedding defined by Page 27 of 43 QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPWOL organic debris alignment, dominantly Quartz with minor Feldspar, black lithic clasts, and Mica, trace disseminated Pyrite, grades to and interbedded with Claystone and/or weakly fissile Shale. Trace to occasional cuttings of Tuff are light gray to light bluish gray, soft to firm, bentonitic, generally smooth and pasty when white, the light bluish gray fraction is firm with a waxy luster. Siltstone/Silty Shale/Claystone/Calcareous Tuff — Siltstone is medium gray to dark gray, occasionally light to medium gray with a mottled appearance, easily friable to firm, sub blocky cuttings with rounded edges to occasional sub tabular cuttings, gritty texture, common to locally abundant specks and flakes of carbonaceous material and rare very fine sand, trace thin laminations increasing to common with depth through interval, rare beds of very fine grained friable silty sandstone with bedding defined by organic debris alignment, dominantly Quartz with minor Feldspar, black lithic clasts, and Mica, rare disseminated Pyrite, grades to and interbedded with Claystone and/or weakly fissile Shale. Trace to occasional cuttings of Tuff are light gray to light bluish gray, soft to firm, bentonitic, generally smooth and pasty when white, the light bluish gray fraction is firm with a waxy luster. There are trace cuttings of Calcareous Tuff that are typically more brittle than other Tuff cuttings and exhibit a slow to vigorous reaction with HCI. The tuffs tend to be associated with elevated peaks on the gamma tool. • Nanushuk Siltstone/Silty Shale/Claystone — Samples appear substantially the same as above. Siltstone is medium gray to dark gray, occasionally light to medium gray with a mottled appearance, easily friable to hydrated and mushy, sub blocky cuttings with rounded edges to mushy and amorphous, gritty to clayey texture, common to locally abundant specks and flakes of carbonaceous material and occasional very fine sand, trace thin laminations, rare grading to a very fine grained easily friable silty sandstone, dominantly very argillaceous Quartz silt, with minor black lithic clasts, and Mica, grades to and interbedded with Claystone and/or weakly fissile Shale. Sandstone/ Silty Sandstone/ Claystone — Noticeable increase in Sandstone in the 4200' sample. Medium gray to light gray to brownish gray with occasional tan hues, Quartz with common lithics, carbonaceous material, and minor Feldspar and Pyrite, lower very fine to lower fine grains, rare loose medium to lower coarse Pyrite and Carbonaceous material, fair to local well Page 28 of 43 1W QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPXOL sorting, sub angular to sub rounded, moderate to low sphericity, easily friable to moderately hard, dominantly grain supported with silty to clayey matrix, scattered cuttings with calcareous cement, cemented cuttings are very tight and have low porosity, the friable grain supported cuttings have moderate porosity overall, carbonaceous material is generally flaky to block -like with occasional carbonaceous — rich layers, Pyrite is the second most common accessory and is present in the Sandstones as very fine crystals and as loose coarse grains and is generally weathered, round, and nodular, trace clear to translucent to silver to occasionally brown micro - mica flakes. Claystones are typically grading to and from Silty Claystone/Siltstone and are medium gray to dark gray, occasionally light to medium gray, easily friable to firm, sub blocky cuttings with rounded edges to rare tabular cuttings, gritty texture, scattered to locally abundant carbonaceous material and flakes occasionally detritus and carbonaceous material is aligned indicating bedding structure, there are few weak laminations visible in the Claystone cuttings, however most Claystone cuttings are very easily hydrated and deformed by the bit, occasional the Shale -like cuttings are weakly fissile. Siltstone/Silty Shale/Claystone — Siltstone is medium to dark gray and occasionally very dark gray, soft to slightly firm, sub platy to sub tabular cuttings, mostly crumbly but occasionally with planar fracture, very high clay content, clays are easily hydrated and most cuttings become mushy and pasty, sometimes grading to a fine Silty Sandstone, trace carbonaceous material throughout most siltstones and locally very abundant. Siltstones are commonly grading to a Silty Shale/ Silty Claystone, the Silty Claystones are typically nearly identical to the Siltstones, however they are much smoother and less gritty as well as exhibit slightly more well defined planar fractures, Silty Shale is more dense and hydrates less as compared to the Siltstones and Claystones, it is typically weakly fissile and commonly exhibits planar fracturing, the Silty Shale is typically slightly darker gray in color as compared to the Claystone. Trace to very rare amounts of gray to bluish gray, crumbly to moderately dense, slightly calcareous tuffs throughout this interval, though never very abundant. Claystone/Siltstone — Overall samples are becoming much more clayey and less sandy, Claystones and Siltstones are both medium to medium dark gray with occasional brownish gray hues, Claystones are soft to slightly firm, most cuttings are re -hydrated and soft to mushy, samples consist of upwards of 50% clayey and mushy clumps and nodules, Claystones are variably grading to Siltstones, overall massive with no distinct structural features beyond poor fissility and occasional fine laminations, extremely rare moderate dense to firm Clayey Shale Page 29 of 43 QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPIOL present in samples, Siltstones are very crumbly and much more friable as compared to Claystones, Pyrite as well as Carbonaceous material and very fine micas are present in most Siltstone cuttings. • Torok Sandstone/Siltstone/Claystone - Sandstone is medium brownish gray to light brownish gray with medium gray and dark gray hues, especially when more clay rich, very fine upper to silt, very argillaceous overall, moderately well sorted, sub rounded to round, moderate sphericity, silty matrix support with occasional grain support beds, mainly matrix and silica cementing but some cuttings show calcite cementing, easily friable to firm, poor intergranular visual porosity dependent on clays occluding poor spaces, dominantly Quartz with minor Feldspar, specks of black lithic clasts, and trace light green lithics, occasional very thin discontinuous laminations of organic debris, and occasional pulses of loose Pyrite in samples, faint spotty dull yellow sample fluorescence, The Siltstone and Claystones remain similar to above with a medium to dark gray with brownish gray hues. Samples are readily hydrated with abundant free clay in them. When intact, the Claystones are soft and rarely slightly firm, sub blocky to sub platy, matte to silty texture. As noted above, in samples the Claystone and Siltstone are gradational to each other with little preserved bedding feature, however a sub -planar fracture and occasional fine laminations indicates they are Shales and Silty Shales in-situ. There are a few cuttings of firm Silty Shale in samples. One firm cutting was observed with a contact between the Sandstone and Claystone clearly visible, supporting the inferred thinly alternating sand -silt -clay bedded structure at depth. The sandy cuttings are more common at the upper half of the interval, and diminish with depth through the interval. Note pulse of white bentonitic Tuff Sandstone/Siltstone/Claystone/Silty Shale - Sandstone is medium brownish gray to light brownish gray overall, very fine upper to fine lower, well sorted, sub rounded, moderate sphericity, less argillaceous than above described interval with more grain supported beds, but still abundant matrix, firm friable to easily friable, silica and matrix cemented, fair to poor estimated intergranular porosity, mostly Quartz sand with minor Feldspar, black lithics, micromicas, specks and flakes of carbonaceous material, Pyrite, and trace of silt to very fine size Glauconite, no sample or cut fluorescence. The Siltstone fraction has increased relative to the Claystone over this interval overall, and is more preserved and firm than previous. Siltstones are medium to brownish gray, sub blocky to sub tabular, silty to finely gritty texture, firm to Page 30 of 43 1W QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPTOL crumbly, less readily hydrated, and represent an intermediate gradation between the sandy or clayey end members. The Claystone is hydrated and sticky, but occasional cuttings show thin laminations indicative of Shale and Silty Shale at depth before destruction by the bit and hydration by the mud and sampling process Shale/Claystone — Very dark gray to brownish gray mostly soft to mushy with occasional firm cuttings, most Shale cuttings are very hydrated, very rare darker gray to almost black cuttings are more dense, there are abundant carbonaceous thin laminations in most of the Shale cuttings with very tight layers of silty Claystone or dark gray clay between them, most cuttings are dull to earthy, sometimes with a sub resinous to matte as a result of abundant organic material, overall there are abundant layers present in most Shale cuttings and the cuttings easily separate at these laminations. Sandstone/Siltstone — Light brownish gray to medium gray, lower very fine to lower fine with common coarse silt grains, round to sub -rounded and occasional sub -angular grains, moderate to strong sphericity, dominantly matrix supported with clayey to silty matrix, occasional grain supported cuttings, rare weakly calcareous cemented cuttings, very easily friable to rarely firm, moderate overall porosity, fair to moderate sorting local well sorted, grains are almost entirely Quartz and other siliceous material, trace amounts of Feldspar, Carbonaceous material, Pyrite, and micas, very dull orange to yellow, spotty <5% sample fluorescence, very rare staining, slow milky white to yellowish cut fluorescence in very few cuttings, overall the shows and oil indicators are very weak. Claystone/Siltstone/ Tuff — Medium dark gray to light brownish gray with occasional olive hues, Claystones are typically silty and grading to a Silty Shale, soft to friable and crumbly easily, still hydrating easily, abundant very thin laminations, commonly with various amounts of carbonaceous and organic material present in the laminations, occasionally silty and grinding to a clayey matrix Siltstone, cuttings are tabular to blocky with irregular to planar fractures, dull to earthy with local resinous lusters, smooth the gritty and silty, trace fine micas and occasional Pyrite, Trace white to light gray Tuff scattered in samples, Tuff is slightly calcareous, hydrates easily and is moderately expansive, ashy to pasty texture in washed samples, very rarely blocky and firm to friable. Shale — Medium dark gray to dark brownish gray occasionally grayish black, soft to easily friable occasionally firm, tabular to platy cuttings, very well developed laminations and very fissile, the Page 31 of 43 eav QUGRUK-301 Completion & Well Test 10-403 Sundry Information RERfOL layers separate very easily with slight touch from the sample probe, very organic overall, composed of alternating very thin layers of organic/carbonaceous material and silty to clayey layers, earthy to sub resinous luster, silty to gritty texture, locally slightly coarser silt to very fine sandy layers, rare white to light gray to slightly bluish gray tuff interbedded with the shale. 11. Geological Fault Information According to the seismic information available, and the interpretation provided by the Alaska Exploration group, no faults were identified within the one half mile radius of Qugruk-301 trajectory. 11.1. Nanushuk Coherence Fault Map The Coherence map in the image below shows the main faults in this area at the depth of the reservoir, with a main NE -SW orientation. Page 32 of 43 a QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPlOL The seismic section below shows that no fault or fracture is expected to be transected by the well path. .9. „� ,,,, o b 12. Proposed Hydraulic Fracturing Program 12.1. Proposed Pump Schedule 7 N.i, u,i l uk -1,1 .-T 7 QugrukJ01 The Q-301 fracture stimulation treatment will be comprised of g:iZ equally sized stages requiring 45,000 gals of Halliburton's DeltaFrac 140 (Guar /Borate) fluid and 126,000 lbs of 16-20 CarboBond Lite proppant. In addition to the pump schedule below the 1"five stages will require a 10 bbl crosslinked spacer as well as a 30 Bbl linear gel spacer for the respective ball drop operation. The final stage will require a 54 Bbl linear gel displacement. Slurry Clean Y� ant Conc „�- 190 Volume (ppa) Rate Proppant Pump Time Stage(M-Gal) ♦SO:TL :.� - .. End BPM(M-Lbs) Min S 6.000 6.000 0.00 0.00 30.0 0.0 4.762 2 4.205 4.110 0.50 0.50 30.0 f 3.337 3 4.410 4.215 1.00 1.00 30.0 ro i +{_ 4 1 6.823 6.246 2.00 2.00 1 30.0 12.5 1 5.415 5 7.235 6.355 1 .9. „� ,,,, o b 12. Proposed Hydraulic Fracturing Program 12.1. Proposed Pump Schedule 7 N.i, u,i l uk -1,1 .-T 7 QugrukJ01 The Q-301 fracture stimulation treatment will be comprised of g:iZ equally sized stages requiring 45,000 gals of Halliburton's DeltaFrac 140 (Guar /Borate) fluid and 126,000 lbs of 16-20 CarboBond Lite proppant. In addition to the pump schedule below the 1"five stages will require a 10 bbl crosslinked spacer as well as a 30 Bbl linear gel spacer for the respective ball drop operation. The final stage will require a 54 Bbl linear gel displacement. Page 33 of 43 Slurry Clean Pro ant Conc Volume Volume (ppa) Rate Proppant Pump Time Stage(M-Gal) (M -Gal) Start End BPM(M-Lbs) Min 1 6.000 6.000 0.00 0.00 30.0 0.0 4.762 2 4.205 4.110 0.50 0.50 30.0 2.1 3.337 3 4.410 4.215 1.00 1.00 30.0 4.2 3.500 4 1 6.823 6.246 2.00 2.00 1 30.0 12.5 1 5.415 5 7.235 6.355 1 3.00 3.00 30.0 19.1 5.742 6 8.293 7.000 4.00 4.00 30.0 28.0 6.582 7 8.616 7.000 5.00 5.00 30.0 35.0 6.838 8 5.401 4.229 1 6.00 6.00 30.0 25.4 4.287 Totals 50.983 45.155 126.30 40.46 Page 33 of 43 OUGRUK-301 Completion & Well Test 10-403 Sundry Information REPXOL 12.2. Maximum Anticipated Treating Pressures The chart below shows the anticipated treating pressures corresponding to the proposed pump schedule in Section 13.1. The maximum surface treating pressure predicted by the NSI StimPlan Full 3D fracture modeling software is 3,512 psi with a corresponding maximum bottomhole treating pressure of 4,101 psi. These pressures are based on pumping the stimulation treatment to completion. The maximum allowable surface treating pressure for the treatment will be 6,000 psi which will allow for the potential of a premature screenout. A pressure relief valve (PRV) set to 6,000 psi will be installed on the main treating line to ensure this value is not exceeded. An additional PRV set to 2,500 psi will be installed on the tubing x casing annulus to prevent an overpressure event should there be a mechanical failure downhole. In the event a premature screenout occurs with a 11.4 ppg slurry in the wellbore, the maximum bottomhole differential pressure calculated from the WeIICat stress analysis simulator would be 5,991 psi 35/Z�s- n lio% Page 34 of 43 Bottum Predicted Surface Pn A qW QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPSOL 12.3. WeIICat Stress Analysis The Landmark "WeIICat" stress simulator was used to analyze the stresses on the 9-5/8" intermediate casing, the 4-1/2" production Liner and the 3-1/2" production tubing based on the loads associated with performing the proposed fracture stimulation treatments in addition to the loads associated with a premature screenout. The following design limits graphs and tables indicate that the resultant Triaxial, Axial, Burst and Collapse stresses applied during the fracturing and potential screenout operations are all above the minimum design factor limits. Design lm1Bs - 9 5G' h1emediate Casoic Secnpn 1 -OD 95J0"- Wel nn 14] ono nnr Gado 1. So 0 Conn w I 1 --FF--c OD Weight Grade Connection 10000 ' Fmc 80 471b/ft 8000 - ID DRIFTID sum 11.100 Tnenai 1250 Tensmn 1600 Collapse psi Axial Lbf 8.681 8.625 4000 4750 1065789 Co. pmss ion t 000 Depth MD 2000 _.. ._..� y. Triaxial oho. Compressan 1 300 FSO 0 Burst 2.669 1.10 -2000 FSO None -4000 100+ 1.00 18-5250 F, FSO Go1laDse 1 000 _- --- Axial -sono 2400 FSO None Note'. Limps am apprxnmata Load Case Descripti -8000 -1200000 -1000000 -800000 -800000 -400000 -200000 0 200000 400000 800000 800000 1000000 Mei Fome obo Minimum Safety Factor (Abs) Under Load Conditions 35/8" Production Casing Casing OD Weight Grade Connection R2 9-5/8" 471b/ft L-80 BTC -M ID DRIFTID Burst psi Collapse psi Axial Lbf 8.681 8.625 6865.5 4750 1065789 Min SF DF Depth MD Load Case Flag Triaxial 2.566 1.25 5075-5099 FSO N Burst 2.669 1.10 5231-5250 FSO None Collapse 100+ 1.00 18-5250 F, FSO None Axial 6.136 1.60 2400 FSO None Nomenclature Load Case Descripti Load Case Details FSO Frac Screen Out 6000 psi Tbg., 2500 psi Csg. 11.4 ppg slurry to surface F Frac 3500psi Tbg., 2500 psi Csg. 11.4 ppg slurry to surface Nomenclature N Flag Description Negative Bending DF=Design Factor Min SF= Minimum safety Factor Above the Design Factor Page 35 of 43 4w QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL Minimum Safety Factor (Abs) Under Load CCondiiitions 4.1/2' Production Liner Casing Fra[ Weight 8000 _ Burst 1100_Tnaeal 1250—Tension 1600 'Fret, 50 41/2" moo L-80 .:. - ..... ,. ID 4000 Burst psi Collapse psi Axial Lbf 3.958 3.833 Compression 1.800 7500 moo Min SF DF Depth MD 6 Fla Triaxial 1.445 1.25 2000 FSO N Burst -4000 1. ... _ None Collapse 100+ 1.00 5000-7531 F, FSO None Axial 4.641 1.60 5100 8000 1 None Collapse 1.000 Load Case Desai ti note: Limits are approximate FSO 10000 -300000 .225000 -150000 -75000 0 75000 150000 225000 300000 375000 450000 5250M Atlal Force (10) Minimum Safety Factor (Abs) Under Load CCondiiitions 4.1/2' Production Liner Casing OD Weight Grade Connection R2 41/2" 12.75 L-80 TC -II ID DRIFT ID Burst psi Collapse psi Axial Lbf 3.958 3.833 8440 7500 288040 Min SF DF Depth MD Load Case Fla Triaxial 1.445 1.25 5060-5200 FSO N Burst 1.407 1.10 5000-7531 FSO None Collapse 100+ 1.00 5000-7531 F, FSO None Axial 4.641 1.60 5100 FSO None Nomenclature Load Case Desai ti Load Case Details FSO FracScreenout 6000 psi Tb., Pore pressure in OH, 11.4 gslurry to surface F Fac 3500si Tbg., 2500 psi Cs. 11.4 ppg slung to surface Nomenclature N Fla Descri tion Ne alive Bending DF=Design Factor Min SF= Minimum safety Factor Above the Design Factor Page 36 of 43 OUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL Desyn Llmll4 - 3-11T Produc m1Tubino _Sedmn 1 - W3 11 Wc,9019300ppf _Glade L-80 I Minimum Safety Factor (Abs) Under Load Conditions 3-1/2' Production Tubing Casing • Frac Weight Grade Connection Frac s0 3-1/2' 12000 L-80 - . . ID DRIFTID Burst psi Connecow Burst 1 100 Tnaua11250 Tenson 1 600 —' — Axial Lbf 9000 - — — 10530 207220 Min SF DF Depth MD 000 3000- Fla Triaxial 1.34 1.25 0- U . ,.::-._.. ..._compression 1600 �.,._•--• Burst 2.57 1.10 4922-5000 FSO None 3000 11.42 1.005000 - F -6000 �. .... r 5000 9000 M / Load Case Descripti Load Case Details Collapse 1000 F 12000 -- - PT Pressure Test 6000 psi Tbg., Pore pressure in OH, 11.4pp Note Limilsarea roommate FlagDescription ative Bending Outer Wall SF Compression 15000- -200000 -160000 -120000 -80000 -40000 0 40000 80000 120000 160000 200000 240000 Mal Force Von Minimum Safety Factor (Abs) Under Load Conditions 3-1/2' Production Tubing Casing OD Weight Grade Connection R2 3-1/2' 9.3 L-80 TC -II ID DRIFTID Burst psi Collapse psi Axial Lbf 2.992 2.867 10160 10530 207220 Min SF DF Depth MD Load Case Fla Triaxial 1.34 1.25 5000 FSO D,N Burst 2.57 1.10 4922-5000 FSO None Collapse 11.42 1.005000 F None Axial 1.70 1.60 5000 FSO M Nomenclature Load Case Descripti Load Case Details F Frac 6000 psi Tbg., 2500 psi Csg. 11.4 ppg slurry to surface PT Pressure Test 6000 psi Tbg., Pore pressure in OH, 11.4pp slur to surface Nomenclature NNe D M FlagDescription ative Bending Outer Wall SF Compression DF=Design Factor Min SF= Minimum safety Factor Above the Design Factor Page 37 of 43 .i QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL 12.4. Formation Mechanical Properties and Stress Model A mechanical properties and in-situ stress model was generated using the log module in the NSI StimPlan Fully 3D Fracture Design Simulator. The model was built utilizing the wireline log data including the processed di -pole sonic data obtained from the offset Qugruk-3 wellbore. The mechanical properties and stress logs generated from the di -pole sonic data indicate that there are minimal stress contrasts above and below, as well as within the +/- 250' of the targeted Nanushuk A&B sands. The input and synthesized log curves for the zone of interest generated by the StimPlan software can be seen in the figure below. �.� Tj Calculated Stress and Mechanical Properties Curves Generated by the NSI StimPlan Log Module Page 38 of 43 i � QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPlOL 12.5. Estimated Fracture Geometry Based on a proposed single stage pump schedule utilizing 45,000 gallons of 25 ppt Guar/Borate crosslinked fluid and 125,000 lbs of 16-20 curable resin coated intermediate strength proppant with a maximum proppant concentration of 6 ppa, the StimPlan model indicates a fracture will be induced with an effective height to length aspect ratio of 0.58 (213' H , 3661) WD ft 40W 4100 41W 4200 42W 4" 43W 44W 44W SV . The following table shows the main output parameters pertaining to a single stage treatment as per the proposed pump schedule in section 13.1. Calculated Results E-StimPlan Fully 3D Pumping Schedule - 25# DF140 , 126K CBL, 30 BPM Frac 1 Perforations : 7100.00-7400.00 ft MD / 4185.00-4185.00 ft TVD HALF LENGTH: 183.8 Propped length (ft) 181.0 PRESSURE: Max Net Pressure (psi) 481.9 Final Net Pressure (psi) 459.7 Maximum Surface Pressure (psi) 3512.4 Maximum Hydraulic Horsepower 2565 TIME: Max Exposure to Form. Temp. (min) 35.5 Time to Close 43.6 RATE: Fluid Loss Rate during pad (BPM) 8.68 EFFICIENCY: At end of pumping schedule 0.45 PROPPANT: Average In Situ Conc.(Ib/ftA2) 1.99 Average Conductivity (md-ft) 3636.7 HEIGHT: Max Fracture Height (ft) 214.5 WIDTH: Avg width at end of pumping (in) 0.61 Page 39 of 43 .6 QUGRUK-301 Completion & Well Test 10-403 Sundry Information REWOL 12.6. Fluid Description & Chemical Disclosure The following chemical disclosure table has been presented as per the 20 AAC 25.238 (a)(12)(C) requirement and is based on the use of 6,706 Bbls of seawater as the base fluid requirement for the entire six stage fracture stimulation treatment. Out of the 6,706 Bbls, only 6,502 Bbls will contain the Crosslinker BC -140. The base volume for the Carbobond 16-20 proppant and Carbobond LCTA low temperature activator is 5,592 Bbls. The Cla-Web Clay - Stabilizer is a proprietary Halliburton additive and therefore the C.A.S. #s for the active ingredients have not been included. If additional information pertaining to the Cla-Web additive is required, please contact; Denise Tuck — Halliburton 3000 N Sam Houston Pkwy E Houston, Texas 77032 (281) 871-6226 Page 40 of 43 Chemical Disclosure Halliburton Fmc Operations Ougruk401 Trade Na.OYsrY:l&me krgrMlm6F CAS.• Naxco.wetron OenellY®20"C (iWr l080GMe) Mex cone wtr . WN (%Ma.) Expacfi0 T6Y1Wa WM Mex(Iba) Max l'4Yesc) 10 225 ppl Q26% 614 gaMm 6144 BC 140 CIOe6lNklf4ae.nNrNmrcr3nne lMUAe 3687 O.ISe weGMtl Iloml ttt131 �e 1843 0.06% Il geMru CmeexG MA 9.16 0.15 W 0,0018% 42 be 42 ooI BE8 Wc4rkNe 2Mnn?WkolbFroPere6MIY�IW%1 42 OOOY6 AryabetleGmME 126 1.00 Mt 0.0080% 2az Its 282 0012% oaw.o Braek. INi¢MYUEryne01 ) PoIT64a 84 0.004% Mly f.4a Gential Remvnry' 9.16 IAO gat 0.107% 282 W.j 25M 0.10% CW -Web Cl,S.Maer nymppieglmwemt<bmlxr U Prapr4ury' 1548 0064% WGJB Gel 12.25 25.68 M1 35M T,dl be 7011 0292% x LvaOsrecwtl� 16.0 1A0 Mt 00117% 282 W 262 0olm GPTIFL6ll OeyM 9neWr amelGOlmxl lIIlaO 262 0012% COwin Slo.PMr6rf%1 tapeea7 zB O.wl% IJIpeRah CanteeU NM 7.53 1.00 W 0.012% M b6 28z 0.012% BMail6e ) 189 eM% IYSN •. - pununHpnsOe2Po1 w14zGa 84 O.aw% Losuna00B SurM.-I brlm`L6MSrc4i s4 f21a7e7n 14 OMI% xrPMrM�pdYt 14 OI101% f $,4TmxatnenrclG.b no a OM01% Mlpaaw+fntlY�1 21.68 BAO M 70% BW,WO Ite 800000 33221% Car ndlstc PSM em4G,n R 694r¢.6N ]MMD 31560% vlstlMrotlelrybrvpSlN 40068 1861% MrgeSne+cnrAa4 7A2 2.00 gpl 0.174x Oro De 3465 o.1]4x Loris eX Neiu�l etWf61 2091 0.t04A G2atantl LCTA �tyunCNm'ol rrc Akde§.CiMMemMry.eWgYletlltMOF) NIS3d08 2081 0.104% P }Irvbmypallmll xSueasO ]0 o.M% Page 40 of 43 4W QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL 13. Proposed Clean -Up and Well Test Program Expro Americas, LLC has been selected and secured to provide the well testing equipment and services on Qugruk-301. 6,600 Bbls (5,280 Bbls useable) of gauge and storage capacity has been arranged for the Qugruk-301 location primarily based on the uncertainty of weather and the potential for delays in hauling test fluids from the location. A HAZID workshop was conducted in January of 2015 following which a formal Well Test Design program was prepared including a P&ID of the system. A detailed flare simulation analysis was also developed based on the anticipated flow rates that will be encountered. The following Q-301 site plan and process flow diagram show the positioning of the well test equipment and tank battery in addition to the flow process from the well through the system. Due to the fact frac balls will be used to shift the hydraulic frac sleeves in the production liner during the execution of the fracturing treatment, a ball catcher has been included in the Ilowback system to catch any returning frac balls. A sand trap has also been included into the system to capture any proppant that may return in the well effluent during the cleanup and test phase prior to the effluent passing to the 3 phase separator. The liquid phase (water & oil) will be transferred from the separator to the four 400 Bbl vertical gauge tanks were the water and oil will be measured and later the separated oil transferred to the ten 500 Bbl storage tanks. All resultant gas will pass from the separator to the vertical scrubber and later to the flare stack where it will be flared Any proppant that accumulates in the sand trap will be blown down to the sparge tank where the proppant and resultant fluids will be staged for disposal. well Meaa SeparWa Oram bS ,.Tank r---> ReLef W ReWTook PaM SLxk lvlol Qugruk-301 Well Test Process Flow Diagram Bau Cal leer 'Wb T�aa Ct,Ne ManldE DIesM FrN Meaer re Leg n AM... � WM We EMum SeparWa Oram bS ,.Tank r---> ReLef W ReWTook PaM SLxk lvlol nao re Leg WM We EMum SW" Ta VVV Relei auwaer v�xsaMa -- -- -.>Ta OADMM Manibb ✓ REPSOLDUGRUK3OI PFD DMI01-NM5 I OF, Page 41 of 43 QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL Qugruk-301 Site Plan An agreement has been executed between Repsol E&P USA Inc. and ConocoPhillips Alaska Inc. (CPAI) to transfer all produced crude oil to the CPAI KRU hydrocarbon recycle facility. Standards have been agreed upon pertaining to the quality of the oil that will be accepted at the hydrocarbon recycle and strict adherence to the standards will be implanted prior to transporting any crude oil off of the Q-301 location. All other well effluents will be transported the BP Class 2 disposal well on DS 4 in the Prudhoe Bay field as per the waste management processed flow diagram below. Repsol will store produced oil in onsite tankage during the production testing operation. Prior to loading the produced oil, the tank will be strapped, the truck loaded, and the tank will be re - strapped to verify the volume transferred into the truck. The custody transfer of the produced oil will take place upon delivery to CPAI. Page 42 of 43 —F QUGRUK-301 Completion & Well Test 10-403 Sundry Information REPJOL FLARE TRUIXTRANSNIr. Q 301 WELL/RIG PAD 0 WELL SEPARATOR PRESS. TEST P�DCESSiN' RU;.tP neovvoxes- © o Puswre Tanxc o � �� � as PcoaraloN 0.vrzooeAwau and j sNerarzroon I gni, , "T _._.I fieO,r xor Fa0c' .�� • PeturneE to BifO'a ocerFay bn ror c«roco Fnnnc° ix¢mowmsvosac smnaeme�:o cuasuvrtuz KUPARUKCPF-1 BP GRIND &INJECT BAROIDFACILITYAT FACILITY AT DRILL SITE PRUDKOE BAY sea Fiqurc ao.., snexz.yzy Page 43 of 43 cuss. RP PAD 3 FACILITY AT DRILL SITE 6 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Thursday, March 19, 2015 1:50 PM To: quick, michael (ext)' Cc: Bettis, Patricia K (DOA); Wallace, Chris D (DOA); ross, david (ext); Q301 DSM; dial, amanda (ext);'Regg, James B (DOA) (im.regg@alaska.gov)' Subject: RE: Q -301 frac sundry (PTD 214-199) (sundry 315-147) Mike, You have verbal approval to run the 4 %" Tbg completion as proposed in your sundry application. You also may rig up the 4'/:" Vetco Frac tree/riser but if the tree requires any lateral force to align through the rig floor you will need to contact the AOGCC. Repsol will need to propose a Frac tree rig up plan plus a risk assessment for our review and approval. You may not start the actual fracture stimulation operations until the sundry is approved. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC(, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guy.schwartz@alaska.gov). From: quick, michael (ext) [mailto:michael.quick@servexternos.repsol.com] Sent: Thursday, March 19, 2015 1:32 PM To: Schwartz, Guy L (DOA) Cc: Bettis, Patricia K (DOA); Wallace, Chris D (DOA); ross, david (ext); Q301 DSM; dial, amanda (ext) Subject: RE: Q -301 frac sundry (PTD 214-199) Mr. Schwartz — As we discussed, Repsol is requesting verbal approval to run the 4-1/2" completion liner assembly in the Qugruk 301 well, PTD 214-199, Nabors rig 105, per the Sundry procedure. The well has been drilled to TD, and we plan to start running the liner tonight (3/19). a�,�cEl�r�,F ISzu�: As to your question on the rig being off center from the well; our Repsol DSM and Completions Supervisor have looked at the rig and at this time, we do not expect to have to pull the frac tree or 4-1/2" tubing riser for alignment. For the well testing operations, only a 4-1/2" riser will be coming through the rig floor. The rig is +/-4.5" off center (to the back of the off drillers side). Nabors had to pull the BOP stack slightly for alignment of the drip pan that is immovable. The rig flow line riser was ran through the rig floor without issue. We have had no issues running or retrieving the wear bushing, and the wear bushing has shown no sign of wear. Please let me know if I can provide further information on this Sundry request. Regards, Mike From: quick, michael (ext) Sent: Wednesday, March 18, 2015 10:14 AM To: 'Schwartz, Guy L (DOA)' Cc: Bettis, Patricia K (DOA); Wallace, Chris D (DOA); ross, david (ext) Subject: RE: Q -301 frac sundry (PTD 214-199) Mr. Schwartz — Attached please find the Additional Information requested for this sundry application per below. Let me know if there are additional questions on this sundry. Best regards, Mike Michael Quick Alaska D&C Operations Team Lead Repsol E&P USA, Inc. 3800 Centerpoint Dr. Suite 400 _ Anchorage, AK 99503 Tel.: 907 375 6933 / Cel: 907 317 2969 michael. auick(&sewexternos.reosol com REPYOL From: Schwartz, Guy L (DOA) (mai Ito: guy. schwartz(dbalaska.00v] Sent: Monday, March 16, 2015 3:33 PM To: quick, michael (ext) Cc: Bettis, Patricia K (DOA); Wallace, Chris D (DOA) Subject: Q -301 frac sundry (PTD 214-199) Mike, For Q-301 frac sundry need a step by step completion running summary. Should include how IA and tubing are going to be tested and to what pressure. Tubing needs to be tested to 110% of the max stimulation pressure. How much pressure are you holding on the IA during frac? Procedure states PRV for IA will be set at 2500 psi. A detail diagram of the DST string. Good job on the cementing details... Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office Schwartz, Guy L (DOA) From: quick, michael (ext) <michael.quick@servexternos.repsol.com> Sent: Wednesday, March 18,201S 10:14 AM To: Schwartz, Guy L (DOA) Cc: Bettis, Patricia K (DOA); Wallace, Chris D (DOA); ross, david (ext) Subject: RE: Q -301 frac sundry (PTD 214-199) Attachments: Repsol Q301 Completion Sundry Attachment.pdf Mr. Schwartz— Attached please find the Additional Information requested for this sundry application per below. Let me know if there are additional questions on this sundry. Best regards, Mike Michael Quick Alaska D&C Operations Team Lead Repsol E&P USA, Inc. 3800 Centerpoint Dr. Suite 400 Anchorage, AK 99503 _ Tel.: 907 375 6933 / Cel: 907 317 2969 michael.quicker-servexternos.repsol com REWOL From: Schwartz, Guy L (DOA)[mailto:guv.schwartz(&alaska.gov] Sent: Monday, March 16, 2015 3:33 PM To: quick, michael (ext) Cc: Bettis, Patricia K (DOA); Wallace, Chris D (DOA) Subject: Q -301 frac sundry (PTD 214-199) Mike, For Q-301 frac sundry need a step by step completion running summary. Should include how IA and tubing are going to be tested and to what pressure. Tubing needs to be tested to 110% of the max stimulation pressure. How much pressure are you holding on the IA during frac? Procedure states PRV for IA will be set at 2500 psi. (1i 2, ! j P" r A detail diagram of the DST string. Good job on the cementing details... Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office THE STATE GOVERNOR BILI. WALKER Robert Jones Drilling Manager Repsol USA 3800 Centerpoint Drive, Suite 400 Anchorage, AK 99503 Re: Wildcat, Qugruk 301 Sundry Number: 315-109 Dear Mr. Jones: Alaska Oil and Gas Conservation Commission a(Lt-M 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax 907276.7542 www.aogcc.claska.gov Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, at y P. oerster Chair, C mmissioner DATED this Zfday of March, 2015 Encl. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 9n AAC 75 9Rn RECEIVED FEB 2 6 2015 ,AOGCC 1. Type of Request Abandon ❑ Plug for Recml ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend J Plug Perforatorre ❑ Perforate _] Put Tubing ❑ Time Extension _.I Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ Alter Casing I] Other Surface Too Job2 2. Operator Name. 4. Current Wes Class 5. Pa t to Drill Number REPSOL USA Exp1 mlory Q - Development ❑ StretigraphicSarvica ❑ ❑ 214-190 3. Address. 6. API Number 3800 CeMerpoinl Dr. Suite 400, Anchorage, AK, 89503 50.103.207000600 7. If perforating S. Well Nene and Number What Regulation or Co servation Order governs welt spacing in this pool? N/A Ouyruk 301 Wit planned perforations requ ra a spacing exception? Yea 0 No +] 0. Property Designation (Lease Number) 10, FheldrPool(s). AOL 391445 391455 1 Wildcat 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft). Total Depen TVD (ft). EtTechve Depth MD (ft). Effective Depth TVD (ft). Plugs (measured). Junk (meawed). 2115' 2115' 210T 210T WA WA Casing Length Stam MO TVO Buret Cogepw Stru Wral Conductor BO' 20" 103' 103• surface 208T 13-3/6' 210T 110T 5020 2260 Intermediate Production Liner Perforation Depth MD (ft). Perforation Depth TVD (ft) Tubing; Sim. Tubing Grade Tubing MO (ft) N/A J WA WA WA WA Packers and SSSV Type Packem and SSSV MD (ft) and TVD (R). N/A N/A . 12. Attachments. Description Summary of Proposal Q 13. Wes Class after proposed work Detailed Operations Program ❑ BOP Sketch ❑ Exploratory Q , Straegaphic ❑ Development ❑ Service ❑ 14. Estimated Date for 15. Well Status after proposed work. Commencing Operations: 2/2312015 On leGas � ❑ WINJ ❑ GINJ ❑ r WDSPL ❑ Suspended �J WAG ❑ Abandoned 16. Verbal Approval: Data W3=5 Commission Reprasentutiva Jim Ron GSTOR ❑ SPLUG ❑ 17.1 hereby certify that the foregoing is true and contact to to beet of my knowledge, Contact Michael Quick 807-3758933 Email TtchaN.gLndc�s8ry9at@m48 roDSol. Wrti Printed Name risk Rhe Dnl6ng Manager Signature / Phone 8324421618 Date 2/25/2015 COMMISSION USE ONLY Conditions of approva, Nally Commission so that a representative may witness Sundry Number CI Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Lowson Clearance u Other Spacing Expptbn Required? Yea ❑ No © Subsequent Form Required f O — y 01 (�`^ +� Wr A / 1-2 APPROVED BY APprond by: 41 _ COMMISSIONER THE COMMISSION Date 3-2—i5 rwimtwoa (aevlwa 1brz012) l A roved 44/IS Submit Form and pp application Is valid for 12 months from the dots of approval. Attachments In Dupkate y1J ORIGINAL/111 R RBDM$l M,il 2015 Qugruk 301 Daily Operations Summary REP -FOL API: 50-103-20700-00-00 Permit #: 214-199 Rig: Nabors 105 CONFIDENTIAL Date and Footage Drilled as of 24:00 hours. Activity 21 February 2015 Finish running 13-3/8" casing, shoe depth @ 2107' MD. RD casing running 0' equipment. RIH with stinger on 5" drillpipe. Sting in to stab -in float collar. Circulate BU. RU cement equipment and test lines to 2000 psi. Mix and pump 450 sx (240 bbls) of 10.7ppg Permafrost L lead cement, get 60bbl of lead cement to surface, lose returns. Reduce rate and pump additional 47 bbls, no returns. Mix and pump 318 sx (72.3 bbls) of 15.8ppg Class G cement with minimal returns, floats held. RD cement equipment. 23 February 2015 RIH with 1" grout string and tag existing cement at 40'. Perform 13-3/8" top 0' job, mix and pumped 6 bbls (7.7 sx) Permafrost cement (had returns at surface at 4.3 bbl pumped). Collected wet and dry samples as per AOGCC request by Bob Noble. Verbal approval for top job granted by AOGCC rep, Jim Regg. ZW-iga - 15 20 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.180(8)([) 212515- azar ous goods Geological Sample Manifest Operator: Repsol E&P USA, Inc. Date: 20 -Feb -2015 Well Name: Qugruk 301 Prepared By: Location: North Slope, AK Received By: Repsol Geologist Box Weight Quantity Of Set Owner Box (lbs) Containers (bags, Type Sampling Frequency Sampling Interval Enclosed Shipping Address ars etc. 3 Repsol 1 of 2 3.7 35 Washed and Dried 30' 100'-130'to 1,120-1,150' CGG Services US 2 of 3.2 32 1,150'-1,180'to 2,080'-2,110' Attn: Jennifer Koerth 3311 South US H 77 1 Repsol Unwashed Wet 30' 100'-130'to 430'-460' 2of7 21.0 92 460'490'to 700'-730' Schulenburg, TX 956 3 of 22.1 8 730'-760'to 940'-970' Phone: 976-562-2777 4 of 7 21.7 10 970'-1,000'to 1,240'-1,270' 5 of 7 20.4 1 8 1,270'-1,300'to 1,480'-1,510- 6 of 7 20.3 1 9 1,510'-1,540'to 1,750'-1,780' 7 of 7 12.5 11 1,780"-1,810'to 2,080'-2,110' 4 Repsol 1 of 1 40.5 20 Geochemical Can in 91 100'-130't01,810'-1,900' 5 Repsol 1 of 1 6.1 25 Gas Samples in 90' &Selected peaks 190'-1,900' IsoTubes' 6 Repsol p loft 2.3 2 Mud Samples/ Spud Mud 0'-2,110- Mud Additives 1 of 3.1 35 100'-130'to 1,830-1,900' Meredith Guhl, Petroleum Geologist Assistant Alaska Oil 7 AOGCC Washed and Dried 30' and Gas Conservation Commission 2 of 3.6 32 1,150'-1,180'to2,080'-2,110' 333 West 7th Avenue, Suite 100 Anchorage, AK Total Boxes: 16 non hazardous and 2 hazardous 99501 Total Weight: H d 208 lbs. azar ous goods 21 L1-199 1,57-0 Washed and Dried Cutting Samples„_ Shipped To: Address: Operator: Repsol Well Name Ougruk 301 Meredith Guhl, Petroleum Geologist Location: North Slope, AK Assistant Alaska Oil and Gas Conservation BOX#1 OF 2 Date: 2/20/2015 Meredith Guhl Commission 333 W 7th Avenue, Suite 100 SET: 7 Anchorage, AK 99501 Quantity Of Box Box Weight (lbs.) Containers (bags, Type Sampling Sampling Interval Enclosed jars, etc) Frequency 1 of 2 3.1 35 Washed and dried 1 cuttings 30 ft 100'-130' to 1120'-1150' 2 of 2 1 3.6 32 1150'-1180' to 2080'-2110' Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Friday, January 30, 2015 10:43 AM To: 'quick, michael (ext)' Cc: dial, amanda (ext) Subject: RE: Repsol Qugruk 301, PTD 214-199 Mike, 60 -foot sample intervals is satisfactory to AOGCC. Have a great weekend, too. Patricia From: quick, michael (ext) [mailto:michael.quick@servexternos.repsol.com] Sent: Friday, January 30, 2015 10:33 AM To: Bettis, Patricia K (DOA) Cc: dial, amanda (ext) Subject: Repsol Qugruk 301, PTD 214-199 Hello Patricia— Following up our conversation on Qugruk 301, PTD 214-199, we will be drilling a +/- 2,200' horizontal section in the primary reservoir. We would like to provide the AOGCC cuttings samples at 60 foot intervals, rather than the 10 foot interval in target zones as the approved cover letter states. Please let us know if this is satisfactory to the AOGCC. Best regards and have a good weekend! Mike Michael Quick Alaska D&C Operations Team Lead Repsol E&P USA, Inc. 3800 Centerpoint Dr. Suite 400 ` Anchorage, AK 99503 - Tel.: 907 375 6933 / Cel: 907 317 2969 411111111F michael.auick(a)sewexternos.reosol.com REPlOI THE STATE GOVERNOR BILL WALKER Bill Hardham Asset Manager Repsol USA 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: Wildcat Field, Wildcat Pool, Qugruk 301 Alaska Oil and Cas Conservation Commission Repsol USA Permit No: 214-199 Surface Location: 1728' FEL, 1813' FSL, SEC. 6, TI IN, R6E, UM Bottomhole Location: 298' FEL, 423' FSL, SEC. 31, T12N, R6E, UM Dear Mr. Hardham: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.olasko.gov Enclosed is the approved application for permit to drill the above referenced exploration well. Expected reservoir pressure of Tuluvak is 10.4 ppg EMW. Repsol plans to drill the interval using 10.4 ppg mud. If gas shows are significant within the Tuluvak, Repsol will have sufficient products on the rig to weight up the mud system as needed to control gas influx. All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or approvals 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 AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. A weekly status report is required from the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the AOGCC's internal use. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC 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 an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, 10)4647 4v'— Cathy P oerster Chair DATED this O'd—ay of January, 2015. STATE OF ALASKA A( :A OIL AND GAS CONSERVATION COMMI( )N PERMIT TO DRILL 20 AAC 25.005 DEC 04 2014 AOGCC la. Type of Work: 1b. Proposed Well Class: Development - Oil Lj Service - Winj Single Zone ❑ 1c. Specify if well is proposed for: Drill Q • Lateral ❑ Stratigraphic Test ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone 2] • Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory F±1 • Service - WAG ❑ Service - Disp ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q Single Well 11. Well Name and Number: REPSOL USA Bond No. :ao�a7)5 82986788 -tb Qugruk 301 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Dr. Suite 400, Anchorage, AK, 99503 MD: 7531', TVD: 4180' . Wildcat 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): iq Surface: 1728' FEL, 1813' FSL, Sec. 6, T11 N, R6E, UM ' ADL 391445 3 y fysS Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1274' FEL, 2231' `NL, Sec. 6, T11 N, R6E, UM LAS 28269 1/15/2015 Total Depth: 9. Acres in Property: q2 ?N13 14. Distance to Nearest Property: 298' FEL, 423' FSL, Sec. 31, T12N, R6E, UM - acres iR 3166 ft 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 3o 2Crfeet 15. Distance to Nearest Well Open Surface: x- 412954 y- 5972299 Zone- 4 , GL Elevation above MSL: 10' feet to Same Pool: WA 16. Deviated wells: Kickoff depth: 2300 feet " 17. Maximum Anticipated PressurN in psig (see 20 AAC 25.035) Maximum Hole Angle: 90 degrees Downhole: -2266 -psi j % y t� Surface: 1547 psi - 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight .Grade I Coupling I Length MD TVD MD TVD (including stage data) 26" 20' 131 If J-55 PEB 80 0' 0' 100' 100' 138 sx Permafrost type L cement 16" 133/8" 68# L-80 BTC 2090 0' 0' 2090' 2090' 1406 sx Perm Lead, 316 sx Class G Tail 12-1/4" 9-5/8" 47# L-80 BTC 5250 0' 0' 5250' 4180' 1 Stage 1: 671 sx; Stage 2: 472 sx ---- ---- ---- ---- ---- 5250' 4180' 7351' 4180' JOH Section 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 TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Property Plat ❑' BOP Sketch Drilling Program ❑ Time v. Depth Plot ID Shallow Hazard Analysis0 Diverter Sketch Seabed Report ❑ Drilling Fluid Program ❑� 20 AAC 25.050 requirements❑ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and correct. Contact Michael Quick 907-375-6933 Email miChael.0uick@servexternos.rensol.com Printed Name Bill Hardham Title Asset Manager Signature Phone 907-375-6917 Date 12/4/2014 Commission Use Only Permit to Dri API Number: ),'0 Permit Approval / 1 See cover letter for other Number: — 50- 103- Date: ,Cj requirements. Conditions of approval : If box is checked, not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained ii/nn sha : —well �may Other: k 3 Soa �,s,; 6a Y' / f � Samples req'd: Yes Q No❑ Mud log req'd:V, ❑o TSHzS / Cyd measures: Yes 0 Nor❑ Directional svy req'o:� ❑o Inclination [�o Yes ❑ No -only svy req'o:❑s Spacing exception regrdLUv d: _ C'O Q- (,e�r,,,�r•eaQ .Lrr Ce ...�(�t-,soh L Y/•w bath �,¢re-YI'st� APPROVED BY 1-5 Approved by: COMMISSIONER THE COMMISSION Date: ORIGINAL �'�815 lof Form 10.401 (Revised 10/2012) This permit is valid for 24 months from the date of approval (20 AAC 25.005(g)) Submit Form and Attachments in Duplicate REP.roc REPSOL USA Application for Permit to Drill Qugruk 301 North Slope, AK December 2014 December 4, 2014 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Application for Permit to Drill: Repsol Qugruk 301 Dear Commissioner: Repsol hereby applies for a Permit to Drill an onshore exploratory well on the North Slope. The well, called Qugruk 301, will be located approximately 200 ft Northeast of the previously drilled Qugruk 3. Repsol plans to spud the Qugruk 301 approximately January 15, 2015. Ice road/pad construction equipment has already begun prepacking ice road and ice pad alignments. Upon receipt of all necessary permits and approvals the construction of the ice road will begin and end with the construction of the ice drilling pad. Upon completion of the ice drilling pad, Nabors' Rig 105AC will be transported to location and the well will be drilled to TD. A DST is Vannl d for this well. It is understood that Repsol will submit and receive an approved stimulation/DST sundry from AOGCC prior to completion work being initiated. After the drilling, completion and test is complete, the well will be permanently abandoned and the drilling rig will be demobilized to Deadhorse. Pertinent information attached to this application includes the following: 1. Form 10-401 Application for Permit to Drill — 2 copies 2. Well Prognosis and discussion of operational considerations 3. Location Plat and Drill Pad Layouts 4. Days vs. Depth Drilling Curve 5. Drilling Procedure 6. Wellbore Schematic 7. Directional Plan 8. Pressure information including pore pressure, mud weight and fracture gradient curves, maximum anticipated surface pressure calculations, FIT and LOT procedures, and casing properties and design factors. 9. Drilling Area Risks 10. Diverter, BOP and Choke manifold schematics and Wellhead Description 11. Cement Program 12. Drilling Fluid Program 13. Shallow Hazard Report Page 2 The AOGCC is requested to treat as confidential all information included in the Application for Permit to Drill as information in these documents is drawn from research and data proprietary to Repsol. If you have any questions or require additional information, please contact Bob Jones, Drilling Manager at 832-442-1618, myself at 907-375-6917, or the technical contacts contained in the following pages. ��S11inncerely, W,4 Bill Hardham Operations Manager Repsol USA REPSOL USA Qugruk 301 Overview and Timetable Repsol intends to conduct an exploration drilling program on leases operated by Repsol during the winter 2014 - 2015 drilling season. The drilling program will include activities beginning during the summer of 2014 and ending during the summer of 2015 including: • Conducting a field program during June through September to obtain engineering and environmental data to define ice road routes and ice pad locations. Specific activities include ground surveys for onshore ice roads and pads, lake surveys to determine locations and availability of water for ice road / pad construction and operational uses, and archaeological and cultural resource investigations. • Monitoring soil temperatures with thermistor strings placed along ice road routes in September and pre -packing the ice road alignment for ice roads via tundra -approved vehicle in November to December as permitted by ADNR and the NSB. • Construction of three rig ice pads and one main camp pad will be located in the Colville River Delta in which three exploratory wells will be drilled (Qugruk 301, Qugruk 8, and Qugruk 9). An ice pad will be constructed off of Mustang Pad for staging construction and drilling operations in December or January as permitted by ADNR and the NSB. • Construction of approximately 35 miles of onshore ice roads in December and January as permitted by ADNR and the NSB for transporting drilling rigs and equipment for drilling operations. • Conduct the exploration drilling operations during January to April at three separate locations using three separate drilling rigs. The wells are being drilled primarily to assess oil reserves within leases operated by Repsol. • Demobilize all equipment from the ice pad and clean up the sites and ice roads during April to early May. • Conduct summer clean up operations during July to August 2015. Operational Considerations Permafrost Based on offset wells and seismic data, the permafrost is assumed to be present from the surface to approximately 1040' SSTVD. Gas hydrate problems were encountered in only one of the offset wells so it is not anticipated to present any drilling difficulties. Surface Casin¢ Shoe Depth The on-site Repsol geologist will pick the MCU lithology change. This is prognoses to be at a depth of 2015' TVD/MD. The surface hole TD will be +/- 75' past this point. If the MCU has not been identified by 2115' MD/TVD then drilling operations will be shut down pending a re-evaluation of the setting point with the on-site geologist and the Repsol Drilling Superintendent. The planned setting depth for the 13-3/8" surface casing is 2090' TVD located deep enough to isolate the permafrost section, shallow gravels and unconsolidated sediments and provide adequate integrity at the casing shoe to accommodate future mud weights. The first expected hydrocarbon bearing sand is the Tuluvak Sand (Tuluvak_FM) at +/- 2,455' TVD. Lost Circulation and Sloughing Shales Some of the wells in this general region encountered sloughing shales below the HRZ and lost circulation in and near their target horizons. The Qugruk 301 target formation is above the HRZ and sloughing shales is a low risk. Lost circulation is considered a medium risk due to the potential for drilling induced losses which is being mitigated by close monitoring of ECD and good hole cleaning practices. The Qugruk 301 mud program and well design has been designed to take these potential problems into account. Pressures Anticipated pore pressures are derived primarily from the histories of offsetting wells in conjunction with a pore pressure analysis. As shown on the attached pore pressure plot and maximum anticipated surface pressure (MASP) calculations, the highest expected pressure is at 4,180 feet TVD and is 1,965 psi (0.47 psi/ft = 9.0 ppg EMW) and will result in a maximum pressure, with a full column of gas, of 1,547 psi, but due to formation breakdown, will result in a maximum pressure at the surface of 1,312 psi (see included calculations). A 5,000 psi working pressure BOP and wellhead system will, therefore, be used on this well. Shallow Hazard Review Abnormally pressured shallow gas is not anticipated in the surface hole interval of Qugruk 301 due to the planned surface casing depth and the close proximity of Qugruk 3 which did not 7 i Lost Circulation and Sloughing Shales Some of the wells in this general region encountered sloughing shales below the HRZ and lost circulation in and near their target horizons. The Qugruk 301 target formation is above the HRZ and sloughing shales is a low risk. Lost circulation is considered a medium risk due to the potential for drilling induced losses which is being mitigated by close monitoring of ECD and good hole cleaning practices. The Qugruk 301 mud program and well design has been designed to take these potential problems into account. Pressures Anticipated pore pressures are derived primarily from the histories of offsetting wells in conjunction with a pore pressure analysis. As shown on the attached pore pressure plot and maximum anticipated surface pressure (MASP) calculations, the highest expected pressure is at 4,180 feet TVD and is 1,965 psi (0.47 psi/ft = 9.0 ppg EMW) and will result in a maximum pressure, with a full column of gas, of 1,547 psi, but due to formation breakdown, will result in a maximum pressure at the surface of 1,312 psi (see included calculations). A 5,000 psi working pressure BOP and wellhead system will, therefore, be used on this well. Shallow Hazard Review Abnormally pressured shallow gas is not anticipated in the surface hole interval of Qugruk 301 due to the planned surface casing depth and the close proximity of Qugruk 3 which did not encounter any abnormally pressured shallow gas. The following plot can be used as a reference for the planned mud weights compared to the expected pore pressure and fracture gradients. Qugruk 301 PP&FG curves MW (PPB) 8 9 10 11 17 1 14 15 16 , 0 1 1 1 I I 1 1 500 I I 1 1 I 1000 I Bau of Permafrost 1 I i 1 I 1 1500 1 1 I 1 1 I 1 2000 - 1 G sJ�ra 5 ,1 F II n I W Tuluvak C 2500 I I , I I I 1 1 , 1 I I 3000 ; I r I 1 I ! I ! I ! 1 1 3500 1 ! 1 I i F 1 ! 1 ! !—FG min 4000 - — PP max ' � • t I _ Nanushuk ----Planned MW Min MWWnat Piaaaea Planned MW Max anPange 4500 A gas influx on an offset well was experienced at a depth of 2,500' TVD on Well Fiord #2. Mud weight was 9.2 when the event occurred, BOP'S were in place and the well was killed with 9.4 ppg. The mud weight was increased to 9.7 ppg and no other problems were encountered. A well control event occurred on Qugruk #2 while drilling with 9.2 ppg mud at 2,523' MD. The design of Qugruk 301 has the surface casing set above the Tuluvak and mud weight in excess of 10.2 ppg will be used to drill the 12-1/4" section. The attached "Qugruk 301 Shallow Hazard Report" is submitted in accordance with 20 AAC 25.061 (a). This report concludes: (1) the Q301 location is situated in side a low amplitude zone in the P-wave reflectivity volume. This is due to the undershooting caused by the surface obstacles during the acquisition. This low amplitude zone can cover the amplitude anomalies caused by shallow gas; (2) the proposed location is situated less than 300 feet from the Qugruk 3 well. The well Qugruk 3 did not have any important shallow hazard event during the drilling; and (3) the Qugruk 3 total gas log indicates above background gas count intervals at 282 ms, 608 ms, and 935 ms (1405 ft, 2530 ft, and 3745 ft approximately). Drilling Within Annular Blowout Preventer Limitations The highest pressure expected above the surface casing setting depth (0.452 psi/ft pressure gradient at 2090' TVD less a 0.1 psi/ft gas gradient) is 746 psi; which is within the 2,000 psi working pressure rating of the diverter. Below the surface casing, BOPS will be used. BOP System and BOPE Testing E * The BOP system of Nabors Rig 105A'Cis rated at 5,000 psi working pressure and is described in the BOPE section of this application. Since the calculated maximum anticipated surface pressure in this well is 1,547 psi, it is planned to routinely test all BOPE to3�4 p except the annular BOP which will be tested to 50% of its rated working pressure (-2500 psi) BOPE will be tested eve_ ry 7 days per 20 ACC 25.035. �a psi 3� psi Well Deviation The Qugruk 301 will be drilled to horizontal in the intermediate hole section at — 3deg/100ft. Directional control will be monitored via MWD in all hole sections. H2S None of the offsetting wells encountered measurable amounts of H2S in the intervals to be drilled, and it is not expect that drilling the Qugruk 301 well will encounter measurable amounts of H2S. However, the drilling rig will be wired with operating sensors, enhanced by additional sensors tied into the mud logging system, to continuously monitor for the presence of H2S. Drilling Waste Handling The surface hole waste water-based drilling mud from the well will be temporarily stored within a bermed storage cell in tanks prior to haul off to G&I; while the drill cuttings will be temporarily stored within a bermed storage area in "shale bin" containers. Cuttings will be hauled to an approved disposal facility for processing and disposal. Diagrams are included with this application that shows the ice pad layouts with the proposed location of the storage cells. All intermediate/production oil based drill cuttings will be sent to an open top tank from the rig. Super suckers will be used to load oil soaked cuttings and be delivered via Spine road to BP's G&I facility at Pad 3. Both will be disposed of per the agreement between BP and Repsol. Every load will be manifested in the Red Book by the mud engineer on location. Additional Information Additional information on operations such as formation tops, logging, mud logging, etc. can be found on the attached Qugruk 301 Well Prognosis. Certified Location Plat An as -built location plat, certified by a Registered Land Surveyor, will be submitted shortly after construction of the drilling location is completed and the conductor pipe is set. Contacts The contacts within Repsol for information are: Reporting and Technical Information: Michael Quick 907-375-6933 or Amanda Dial 907-375-6932 Geological Data and Logs: Sofia Soriano 832-442-1476 REPSOL USA Qugruk 301 Well Prognosis Surface Location: 1728' FEL, 1813' FSL, Sec. 6, TI IN, R6E, UM Target Location: 1274' FEL, 2231' FNL, Sec. 6, TI IN, R6E, UM Bottomhole Location: 298' FEL, 423' FSL, Sec. 31, T12N, R6E, UM Elevation: Planned TD: Formation Tops: Cores: Planned Logs: Ground Level 10' AMSL Drill Floor (DF) 20' AGL 7531' MD / 4180' TVD TODs Base Permafrost MCU Upper Cret. MFS Tuluvak Nanushuk Fm Depth (TVD) 1070' 2015' 2225' 2455' 3813' No core is currently planned for this well. ' Surface Hole (16"): LWD only: Gamma Ray / Resistivity Intermediate Hole (12-1/4"): LWD: Gamma Ray / Resistivity, Density / Neutron Production Hole (6-1/8"): LWD: Gamma Ray / Resistivity, Density / Neutron Wireline: No wireline is currently planned for this well. Mud Logging: i Mud Logging will be in operation from the base of the conductor casing to well TD. Services will include sample collection; plotting of ROP, lithology, and drilling parameters; show description; gas analysis of cuttings; and gas chromatography. Samples will be collected every 30' from the surface to TD, and every 5' in zones of interest. Collect Isotubes from any gas shows. The wellsite Geologist will adjust the interval or sampling rates as required. Nolen: Legend: • M; N REPSol E6Y usRIXC. ces01983 : Q LEASES BY OTHERS 20142015 Proposed SHL 0 5001,000 2,000 ad.esexnoM¶on NIONPM aLGMYRNN mnla."PS&DI lane OFee! Nasb +FIP35oo+ Q REPSOL LFASE 2014-2015 Proposed Ice Road Route 0 250 500 1,000 W E LEASES BYOTNERS IN VICINITY OF REPSOL IUSfeft) 0M¢t¢6 SURFACE LOCATION QUGRUK-301 A REJUGL __.._ _ .... NW N / (5 Wt50Ix93.xT646• 36 31 32 33 TI N LLM TI IN U.M. p5FD J GSv 4 y/ / l� �1�'./`) 0•°,y�ba+r, �r°g0 nuc UK 30 �7 /' \ �/ / J /� .\\ iz�csT e.8 9 GRAPHIC SCALE c �\ / c \ 5� �7 / / � N]0'2W03.6x35" K D COryInAnM Wl5VQ75.2005• ® 13/ D.181 6 1"= 1 MILE 1 inch = 100 It / / ^� / 13 15_.1 !� CONDUCTOR LOCATION r / NAce3 ASP zolaa N LONG0.42'33.47" W Y = 5.972.04] X = 1,552,987 NAD2]ASPZOIE4 { LAT=70'20'03.01" N I \ \ gOg LONG=150'42'22.18" W X- 412.9549 45 / .y6 , 4/ NAD2]UI ZONE METERS O LAT=70'20'03.01" N LONG=150'42'22.18" W ^ pj Y = ].80],205 WtWYx'aaA9xx• ( �>s \ X = 360.868 PRIMARY LOCATION LOCATED MTHIN PROTRACTED 03 /SEC 6, T11N. R6E, U.M. J — 1813' F.S.L. j 1728' F.E.L. S\ ♦ / N70' TO. � � �wt3o•4x'3446ea• �.� / 1 i NOTES: 1. ELEVATIONS SHOWN ARE NAW 88 PER GEOID 2012A DERIVED FROM GPS OBSERVATION. GEOGRAPHIC COORDINATES ARE NAD 03 I£GEND��iq QUGRUK NO. 301 — mxoucron vmr¢ �oc..na . i AS STAKED WELL DN T ® LOCATEDWITIN — _ ia"mN aw.mc rurvv[ � SECTION E. Ti1N, R6E,6E, U.M. 9. U"h 08/26/2014 1•=100' cx6U. KWA"°Pa9 MJO REWOL P Almev.° �► m.. muec+a+ wsmro_ owi Tor°Uwc FIGURE 1 OF i N I Qugruk 301 Drilling Procedure 1. MIRU Nabors rig 105AC. (A 26" hole will be angered to +/- 80' with 20" conductor casing set and cemented prior to rig moving on location.) ✓ 2. Nipple up diverter and function test. Notify regulatory agencies 24 hours prior to test. 3. Pick up BHA and drill 16" vertical hole to the surface casing point of +/- 2090' MD/TVD. Run and utilize MWD and LWD tools throughout this hole section to monitor hole angle and to ensure hole remains vertical, as well as collect logging data. 4. Condition hole for casing. POOH. 5. Run 13-3/8", 68#, L-80 BTC casing. 6. RIH with drill pipe and stab -in to tool and pump cement until good cement returns reach surface, using lightweight permafrost cement lead slurry followed by high strength Class G tail slurry per cementing program. e21666-, /- I'`-rs 7. Nipple down diverter and nipple up BOPE. Test BOPE 250/25001psi- Notify regulatory agencies 24 hours prior to test. 8. Make up 12-1/4" drilling BHA and RIH to the top of the 13-3/8" float equipment. Pressure test the casing to 2,500 psi for 30 minutes. Record the pressure test and send the results to Anchorage office. 9. Displace spud mud to mineral oil based mud. 10. Drill the float equipment and 20' of new hole. Perform FIT to 123 nog EM , Record the results and send to the Anchorage office. 11. Drill a 12-1/4" hole and begin build of -3 degrees /100 feet to 90 degrees. Run LWD logging tools in the drill string as required for formation data gathering. 12. Land build at +/- 5250'/ 4150' TVDSS. Condition the hole for casing. POOH. 13. Pull wear bushing, run 9-5/8" 47#, L-80 BTC casing. 14. Cement 9-5/8" casing in 2 stages (Stage 1: 5250'MD to 3500'MD, Stage 2: 3000'MD to surface) 15. Trip in hole with 8 1/2" bit, drill stage tool, drill out stage tool and TIH to top of float equipment. 16. Tag top of float collar, test casing to 3500 psi for 30 min. 17. Drill shoe track and 20 feet of new ho e, pe ori rm FIT to 12.0 W, POOH. 18. Trip in hole with 6-1/8" bit, and drill 6-1/8" hole holding -90 degrees to TD of horizontal at +/- 7531' MD / 4150' TVDSS. n19. Condition the hole for completion. POOH. Repsol will submit and receive an approved stimulation/DST 10-403 Sundry from AOGCC prior to completion work being initiated. (I L . 7 `� a120. Run 4-1/2" open hole completion and tieback sting. 4oH-- 1. Perform cased hole test. M22. POOH with 3-1/2" tubing and lay down seal assembly. Repsol will submit and receive an approved P&A 10-403 Sundry prior to commencing P&A operations. 23. RIH with cement retainer to 5250' MD (just above liner top packer), squeeze below, and leave 200 ft cement on top. 24. RIH with bridge plug, set @ 2300' MD and leave 400 ft of cement on top. 25. RIH with bridge plug, set at 280' MD and leave cement on top bringing cement to surface. 26. RDMO. Qugruk 301 Drilling Schematic PRELIMINARY (Nabors Rig 105AC) II 26" Hole 1 20" 131#J-66 Conductor +1.100' MD / TVD I I I I I I I 16" Hole I I l l I I I I I I I I I t-- 13-3/8" 68# L-80 BTC Casing (a� +/- 2090' MD / -2060' TVDSS G �y I 12-%" Hole CONFIDENTIAL REP-fOL Rig 105 RKB: 20' Q-301 Elevation w/ Pad Thickness: 10' KB to MSL: 30' Intermediate Stage 2: Stage tool @ 3000' MD , , , :. _ TD @ +l- 7631' MD / -4160' TVDSS �. .:. ______________________ 6118"Hole 9.6/8" 47# L-80 Casing @ +/-6260' MD 14160' TVDSS Revised A.Dial 10-06-14 C;g J_ RFPJOL Qugruk-301 (P12) Proposal Caetl®lia Report (W PIM) O A69W61 6Mmr ri oa7 6vn01Otla 101 fl fl ry Ilfl ve tlq MI EN Lry AST 10 lNlp. 91mW room MS W 4.JW 4� W 4W0. SWOW 5%9 W SUJ W M]W 59pm SOW'RwlumnlLue sa m5wlea on4�:Ma moll oo.n ������yy owelMUEla W Stil�I w n. 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M. w o..3nU3 91y30R ta 38)415 ]9141N 41 a1 mN% 3010319) 3w4.6 A143sA sn.1DW 414ASII 41KWA S91S.W.A 41a80..w Y14A.]0 1 OB A]Sm331 141583) A]S1Wel Sn%.0 U4a0.W 59)6)3. 41469411w .23 W1vnv . 1".SnMno 45Rm ��t6 9144145 .1P11 Drilling Office 2.7.1043.0 Qugruk\Qugruk-301\Qugruk-301\Qugruk-301\Qugruk-301(P9) 111620142:33PM Page l of9 nan�ra�naa+ "nm+f��4 Q•3 Qugruk 301 Pressure Calculations and Drilling Risks Maximum Anticipated Surface Pressure: The maximum anticipated surface pressure (MASP) for this well will be the higher of the formation pore pressure (less a full gas column to the surface) at TD or the formation fracture pressure at the last casing shoe (less a full gas column to the surface). The MASP expected in the 12-1/4" hole section is 1,547 psi at a depth of 4,180' TVD (or 0.47 psi/ft less 0.1 psi/ft gas gradient). Predicted fracture gradient data for this area based on offset log data, at 2,090' TVD, the depth of the 13-3/8" casing shoe, is 0.728 psi/ft (14.0 ppg). Complete evacuation of the wellbore, except for a 0.1 psi/ft gas gradient, is assumed. 12-1/4" Hole Section — 2,090' to 4,180' MASP (pore pressure) _ (4180 ft)(0.47 — 0.1) = 1,547 psi MASP (form. breakdown) _ (2090 ft)(0.728 — 0.1) = 1,312 psi Therefore, MASP in the 12-1/4" hole section is 1,547 psi and the 5,000 psi BOPE system to be used will be adequate. Horizontal Hole The maximum anticipated surface pressure (MASP) for this well will be the lesser of the formation pore pressure (less a full gas column to the surface) at TD or the formation fracture pressure at the last casing shoe (less a full gas column to the surface). The MASP expected in the 6 1/8" hole section is 1,547 psi at a depth of 4,180' TVD (or 0.47 psi/ft less 0.1 psi/ft gas gradient). Predicted fracture gradient data for this area based on seismic interpretation and offset 5: data, at 4,180' TVD, the depth of the 9-5/8" casing shoe, is 0.77 psi/ft (14.8 ppg). Complete Ict t �' evacuation of the wellbore, except for a 0.1 psi/ft gas gradient, is assumed. 17 ?464 6-1/8" Hole Section — 4,180' TVD MASP (pore pressure) _ (4180 ft)(0.47 — 0.1) = 1,547 psi MASP (form. breakdown) _ (4180 ft)(0.77 — 0.1) = 2,800 psi Therefore, MASP in the 6-1/8" hole section is 1,547 psi and the 5,000 psi BOPE system to be used will be adequate. Well Proximity Risk: The nearest wellbore to the planned wellbore of the Qugruk 301, is the plugged and abandoned Qugruk 3 well located approximately 200 ft southwest. The surface hole will be closely monitored for verticality and the build to horizontal is directed away from the Qugruk 3 wellbores minimizing the risk of intersection. Drilling Area Risks: 16" Surface Hole—13-3/8" Casing Interval EVENT RISK LEVEL Mitigation Broach of Conductor Low Monitor cellar continuously during drilling interval. Gas Hydrates Low If observed: control drill, reduce pump rates, reduce drilling fluid temperatures, additions of Lecithin. Gravel/Sand Sloughing to Moderate Increase mud weight/viscosity, pump high viscosity sweeps. +/- 500' Moderate Monitor fill on connections. Hole Swabbing / Tight hole Low Circulate hole clean prior to trip. Proper hole fill utilizing trip on Tris Low sheets, pumping out of hole as needed. Possible Thaw Bulb / Low Watch return viscosity for signs of thinning. Increased mud Water Flow Low weight/viscosity weight/viscosityas needed. Lost Circulation Low Mitigation by good hole cleaning practices. Reduce mud weight if possible. If losses occur, reduce pump rates and Excessive Washout Moderate lower mud theology, use LCM material. Abnormal Gas Zone Moderate Mitigation by not drilling past known hydrocarbon bearing Pressure Moderate reservoirs in the surface hole section. Keep Mud weight at or above 10 ppg below permafrost. 12-1/4" Intermediate Hole — EVENT RISK LEVEL Mitigation Lost Circulation Moderate Monitor hole cleaning efficiency. Mitigation by good hole cleaning practices. Reduce mud weight if possible. If losses occur, reduce pump rates and lower mud rheology, use LCM material. Hole Swabbing / Tight hole Moderate Circulate hole clean prior to trip. Proper hole fill utilizing trip on Tris sheets, pumping out of hole as needed. Differential Sticking Low Periodic wiper trips as needed for hole conditions. Do not leave pipe static for extended periods. Directional Difficulties Low Optimum hole geometry for directional drilling. Use of Rotary steerable system when possible. 2-D profile (no chane from initial direction). Excessive Washout Moderate Inhibitive drilling fluid system. Limit wash/reaming through known interval. ECD Management Moderate Constant monitoring of ECD while in hole by multiple parties for consistency. Derived ECD limits for each hole section. Clear action plan if ECD limits are exceeded. 6-1/8" Production Hole — EVENT RISK LEVEL Mitigation Lost Circulation Moderate Monitor hole cleaning efficiency. Mitigation by good hole cleaning practices. Reduce mud weight if possible. If losses occur, reduce pump rates and lower mud rheology, use LCM material. Hole Swabbing / Tight hole Moderate Circulate hole clean prior to trip. Proper hole fill utilizing trip on Tris sheets, pumping out of hole as needed. Differential Sticking Low Periodic wiper trips as needed for hole conditions. Do not leave pipe static for extended periods. ECD Management Moderate Constant monitoring of ECD while in hole by multiple parties for consistency. Derived ECD limits for each hole section. Clear action plan if ECD limits are exceeded. Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Note that the terms used in these procedures are defined as follows: Formation Integrity Test (FIT): Formation is tested to a pre -determined equivalent mud weight. Leak -Off Test (LOT): Pressure is exerted against the formation until fluid begins to discernibly pump away. Pressure at which this first occurs is the leak off point. Open Hole LOTS (OH LOTS): Leak -off tests performed with open hole from the casing shoe to some point above the target reservoir. Generally done when leak -off is required but could not be achieved just below the casing shoe; or where weaker formations are suspected above the target reservoir but below the casing shoe, and assurance is required of being able to support estimated mud weight. Procedure for FIT: 1. Drill 20' of new hole below the casing shoe. 2. Circulate the hole to establish a uniform mud density throughout the system. Pull back up into the shoe. 3. Close the BOP (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 barrel per minute. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) versus drillpipe pressure until the appropriate surface pressure is achieved for the FIT at the shoe. 6. Shut down at the required surface pressure. Hold for a minimum of 10 minutes or until the pressure stabilizes. Record time versus pressure in one -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measure are required. Formation integrity tests are conducted on all casing shoes with the exception of some surface casing situations. Where annular disposal pumping is planned on a well, the formation below the surface shoe is taken to leak -off. This ensures that future disposal fluids can be pumped away without risk of damage to the surface shoe. If two attempts at establishing a leak -off at the shoe are unsuccessful, then an open hole LOT is performed. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with a FIT. BOP Control System The blowout preventer stack is a Shaffer 13 5/8" x 5000 psi annular preventer, a 13 5/8" x 5000 psi double gate ram type preventer fitted with blind rams in the bottom and 2 7/8" x 5" variable rams in the top and a Shaffer 13 5/8" x 5000 psi single gate ram preventer fitted with 2 7/8" x 5" variable ram block. The BOPE control system on Nabors Rig 105AC is a 6 station, 165 gallon -220 gallon reservoir. Ten 15 gallon bottles, four nitrogen as backup. One manual master control station with six controls located on the main unit, one six station control panel located on drillers station. Equipped with 1 electric and 2 air pumps with emergency power. All PLC controlled. The choke manifold is a 3 1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a handheld adjustable choke. Wellhead Description An exploration wellhead system has been selected for this well, consisting of a diverter system and a 5M rated wellhead assembly. The diverter system is attached to the 20" conductor with an overshot adapter that allows full bore access to the 20" conductor. The rig's diverter tee, knife gate and annular is then attached to the diverter system. The 13 3/8" casing is suspended with a fluted mandrel hanger in a landing ring that is part of the diverter system. If a top cement job is required, wash pipe will be attempted to be run through the ball valve seat at the base of the conductor. Tubing to pass through the ports on the top of the hanger will be available if access through the ball valve is not possible. Once cementing is complete, the diverter system is removed and a 5M wellhead system is installed on the 13 3/8" mandrel hanger. The connection between the wellhead system and the mandrel hanger is pressure tested to 1200psi. The 9-5/8" casing is suspended with a fluted mandrel hanger, and the 13 3/8" x 9 5/8" annulus is secured with a packoff that is installed from the rig floor without the need to remove the BOP stack. This packoff is tested to 5M upon installation. The wellhead system has been designed to be completely removed after the well has been drilled and prepared for abandonment. Qugruk 301 Cementing Program 13-3/8" Surface Casing (set at 2090',16" hole) PreFlush / Spacer: 80 bbl 11.0 ppg Tuned Spacer III Lead Slurry: Top of slurry: Surface Permafrost type L cement, 10.7 ppg density 225% excess across Permafrost, 80' to 1070' 40% excess below Permafrost from 1070' to 1590' Yield: 4.33 cu ft/sk Volume: 313 bbls (406 sx) including excess Tail Slurry: Top of slurry: 1590' Premium class G cement, 15.8 ppg density 40% excess for 500' of annulus volume + 80' shoe track Yield: 1.16 cu ft/sk Volume: 65 bbls (316 sx) including excess & Shoe track 9-5/8" Intermediate Casine (set at 5250', 12-1/4" hole) PreFlush / Spacer: 60 bbl 10.4 ppg Tuned Spacer III Stage 1: Top of slurry: 3600' MD Premium class G cement, 15.8 ppg density 40% excess from 5250'— 3500' MD Yield: 1.15 cu ft/sk Volume: 138 bbls (671 sx) including excess & shoe track Stage 2: Top of slurry: 0' MD ✓ +u sLLrt" Stage Tool: 3000' MD Premium class G cement, 12.0 ppg density 40% excess for 3000'-2090' MD, plus 2090' inside previous casing Yield: 2.48 cu ft/sk Volume: 208 bbls (472 sx) including excess Calculation & Casing Design Factors Ougruk 301 Colville River Delta WELL: Ougruk301 FIELD: Exploration DATE: 18 -Nov -14 DESIGN BY: A. Dial Equivalent MW W TD: 0.47 psVft TENSION MINIMUM COLLAPSE COLLAPSE WEIGHT TOPOF STRENGTH PRESS® RESIST. MINIMUM DESCRIPTION W/O BF SECTION TENSION WORST CASE BOTTOM w/o TENSION WORST CASE MASP YIELD WORST CASE SECTION CASING: BOTTOM TOP LENGTH WT. GRADE THREAD LBS LBS 1000 LBS SF TENSION"' PSI' Ell SF COLL. PSI"' Pyl SF BURST 1 13.375' 2,090 0 2090 68 L-80 Butt 142,120 142,120 1556 10.95 982 2,260 2.30 746 5,020 6.73 TVD 2,090 0 2 9.625" 5,250 0 5250 47 L-80 Bull 246,750 246,750 1086 4.40 1,965 4,750 2.42 1,547 6,870 4.44 TVD 4,180 0 Collapse pressure is calculated; Normal Pressure Fluid Gradient for external stress (.47 psi/ft) and the casing evacuated for the internal stress (.1 psiNt) See attached sheet for calculation of MASP "' The SF Tension calulation assumes a fully evacuated wellbore with no effects from buoyancy. a (— /- — ELEV. +15'-8 1 15'-2 1/4" 12'-10 1/2" 10' CELLAR 6" MATTING BOARD ELEV. +0'-6" ESTIMATED CELLAR INVERT ELEV.-10'-0" - 10' - CELLAR I WELL CENTER 2'-9 3/4° BOP ASSEMBLY SHOWN T311" -5K STACK ASSEMBLY CENTERLINE 16" DIVERTER ELEV. +2'-2 5/8"" 1'-8 5/8" EXISTING GRADE ---_-------� ---- ELEV._ 0'-0""- NABORS ALASKA RIG 10SE T3 11" 10K STACK ASSEMBLY DIVERTER PLACEMENT POSITION tmgg Fl mcwa ANsbosAh" ='. �-, iasc ° n n• v; mw -aur vex aeu,w a,rauxcc RIG FLOOR KELLY BUSHING ELEVATION I ELEV. +20'-6 1/2" I I i I I BOTTOM OF CRANE RAIL BEAMS ELEV. +15'-8 1/4" i I i - 20'-6 1/2" 15'-2 1/4" I CENTERLINE 16" DIVERTER ELEV. +2'-2 5/8" 6" MATTING BOARD—'— 11p�1 1'-8 5/8" EXISTING GRADE ELEV. +0'-6" - - — - �JI _ r ELEV 0'-0" -- ——_—__-- 2 5/8" I j 6" MATTING BOARD I � i ii I wwmx�il 10' CELLAR j ✓ j I NABORS ALASKA RIO 705E ii I I ii DIVERTER BOP REFERENCE ESTIMATED CELLAR INVERT I; I ;I SUBSTRUCTURE CELLAR ELEVATION � ELEV.—10'-0" � I L I � I I L -, h CELLAR I x�cvs.v� � rosr WELL,I.a�aoa� r,r.w� aiLw acaiwx s,.xAvil a we we wam m ww sl-I/,• eov .suaslAucnmc CENTER lu.we , x rt sv A..sm ,z,um, BLACK HANDLE-NORMALLY CLOSED WHITE HANDLE - NORMALLY OPEN TO FLARE LINE TO 8 GASBUSTER 3 33 34 2 VIEW VIEW 27 1 5 6 CC 4 BB 35 -7 23 24 25 26 28 9 VIEW 19AA 22 PRESSUR 29 21 GUAGE 18 O 10 32 FROM WELLHEAD ® 20 17 30 16 15 X14 11 31 12 VIEW VIEW VIEW AA CC BB 13 PLAN ELEVATIONS NOTES: ORIGINAL DRAWING BY PVS. EDITED BY MJG TO FIT FIELD ARRANGEMENT. Scale: Date: N.T.S JULY 052007 Description: -- �JIII';�°° 3-1116" 10,000# NACE Dr nby: RAVI MANI DWG# NDR#105 TRIM CHOKE & KILL MANIFOLD SYSTEM dpi Checked REV by: 00 PACIFIC VALVE SERVICES INC. m uc ' °" rm ro xvr or xn i a r �E wmT g9C1NR4ETOBW owwn ao eM ioxcEorNir row+soE oEW89ni AMTMq TNtltn 9HVfE0.n � SIVIFXn 9x164 NmL mmL -OdBN/m.-xm�/W. -I�m BBL - MBm/N PlacwxaEroaM +z cw+milRE P P IP +r r P � % • r 'S 5 P 1P i r % f �+ f P ISPSI RIPN� g oarL.�E tl Q a�PN +P LO - f % VIL r MXP +z -�mL xAx%R •xxxx I+dl�m - Px/x mam �®uL mae� �E % - RBBL/IX. % - PPL/M. LEGEND -1MBBL/N O PUMP KEY YW PMRR O WRFAFLYVH4E N 3 Y P1.NI%Wlin Ylli/P%S P3-MIXnIW RIn M%518 OroBT.WOPP£WfIIOIO ��I 641PVKY£ ✓V %-fJ WAxER11i RPX%6%B x-1N%Fi1LLNVItSX%IY] �m xRPW WPX VALVe' I -'—p vi-wxmlfWEianwwl+s X%6[s % sucr%x vuvevnm eXLlaxiurxumwsPu O f Pumce9uxP i{ArRE r roxuuxE ttMunmx00%xA /� oAMPerFn V� BLLL VNVE bl S. AGIIRi(M1 OEIXINffA wowxvn O aow Xrvmw —► a°n"w'.'".�0°`'5.71, ��a �""`^+X�.r.a A"b, "W, o PWOWVNVE a .1.9.EPXOEIOX� • 6e. uaaFa 49W]_]PA NABJRS ALtSAA RIC/ICbE� 9JCImNSGEPH Q xw srsrcM sc/%wr�c 96T B& ACiNE SFSRY 9J/WOB A JA ISSUEp � /o W He LLC A �.' Br u15wm%« � MI A NB IOY.OJOi b 1 4w REPYOL HALLIBURTON DRILLING FLUIDS PROGRAM Operator: Repsol USA Well Name: Qugruk-301 Location: Alaska Version 2.0 Prepared by Mr. Derek Rader Technical Professional derek.rader@halliburton.com Office -907-275-2626 Cell -907.351-3772 HALLIBURTON Baron Author/Owner Approver Approvers Name: Derek Rader Chris MacKinnon Amanda Dial Title: Tech Professional Operations lead ODE Date: November 24, 2014 Signature- HALLIBURTON Baron 1- ^"JMUnYnM t3 �Y I'�`Iri REWOL Qugruk-301 ver. 2.0 Prudhoe Bay AK / U.S.A. Halliburton appreciates the opportunity to present this proposal and looks forward to being of service to you. Program Briefing Enclosed is our recommended procedure for Drilling Fluid Services in the referenced well. The information in this proposal includes well data, calculations, material requirements, and cost estimates. This proposal is based on information from our field personnel, customer information and previous services in the area. Halliburton appreciates the opportunity to present this proposal for your consideration and we look forward to being of service to you. Our Services for your well will be coordinated through the Service Center listed below. If you require any additional information or additional designs, please feel free to contact myself or our field representatives listed below. Prepared and Submitted by: SERVICE CENTER: OPERATIONS LEADER: TECHNICAL PROFESSIONAL: PHONE NUMBER: Mud Proeram Distribution Derek Rader Technical Professional Anchorage, Alaska Chris MacKinnon Derek Rader 907.275.2626 Name Position Document Version Date Amanda Dial Repsol ODE 2.0 11124/2014 Chris Mackinnon Halliburton Ops Leader 2.0 11124/2014 The table above will serve as a record of distribution control for the approved program, both hard copy and electronic copies shall be logged into the above table. Proeram Amendment and MOC Record Version.# Date Author Description MOC Document number The table above will serve as a record or amendments submitted for the well. The Management of Change (MOC) process most be touowea tor cnanges mane to the drilling fluids program after the spud date. HALLIBUnYnM ea, -o d — REP10L Qugruk-301 ver. 2.0 Prudhoe Bay AK / U.S.A. Table of Contents 1.0 Program Briefing 1.1 Well Data 1.2 Well Data Provided by Repsol 1.3 Baroid Project Support Team 2.0 Well Design 2.1 Well Objectives 2.2 Well Design Summary 3.0 Interval Discussions 3.1 16" Surface Interval 100' – 2,090' MD 3.1.1 Fluid Summary Breakdown: AQUAGEL/Freshwater Spud Mud 3.1.2 Interval Operation Summary 3.1.3 Hazards/Concems 3.1.4 Formation Tops/Pore Pressures 3.1.5 Target Properties/System Formulation 3.1.6 Suggested ROP/Pump Rates 3.2 12 1/a" Intermediate Interval 2,090' –5,250' MD 3.2.1 Fluid Summary Breakdown: ENVIROMUL MOBM 3.2.2 Interval Operation Summary 3.2.3 Hazards/Concerns 3.2.4 Formation Tops/Pore Pressures 3.2.5 Target Properties/System Formulation 3.2.6 Suggested ROP/Pump Rates 3.3 6118" Production Interval 5,250' – 7,531 ' MD 3.3.1 Fluid Summary Breakdown: ENVIROMUL MOBM 3.3.2 Interval Operation Summary 3.3.3 Hazards/Concerns 3.3.4 Target Properties/System Formulation 3.3.5 Suggested ROP/Pump Rates 4.0 SCE Recommendations 5.0 Estimated Fluid and Drill Solid Disposal Volumes 6.0 Total Well Cost 7.0 Apoendices 7.1 Surface Interval Hydraulics 7.2 Intermediate Interval Hydraulics 7.3 Production Interval Hydraulics 7.4 Lost Circulation Material Decision Trees HAkL.LIBLlRIrM V Bar-olxl REPlOL Qugruk-301 ver. 2.0 Prudhoe Bay AK / U.S.A. 1.0 Program Briefine 1.1 Well Data Operator Repsol USA Well No. Qugruk-301 FieldBlock Colville River Delta PBU Location Alaska/ U.S.A Well Type Exploration Max. Well Inclination 90 Maximum Expected Mud Density 10.4 ppg Estimated Daus 71 Anticipated BHST at Total Depth of well 125'F 1.2 Well Data provided by Repsol Data Provided Document Identifier Date Received Used in Preparation of this Program Y/N Halliburton Approver Scope of work u ruk-301 ver 2 10/10/14 Y Derek Rader Technical Professional Derek Rader (907) 351-3772 Scope Chane Documentation No Scope Chan es to date derekxader@hallibunon.com 1.3 Baroid Project Support Team Title Name Cell Number Office Number Home Number Email address Technical Professional Derek Rader (907) 351-3772 (907) 275-2626 (907) 622-9510 derekxader@hallibunon.com Operations Leader Chris Mackinnon (907) 227-5045 (907) 275-2617 (907) 227-5045 chris.niackinnon@Halliburton.com Lead Mud Eng. Lead Mud Eng. Night Mud Eng. Night Mud Eng. Stock-poim Manager John Jessup/Brent Edmunds (907) 943-1028 (907) 6.59-2422 Jahn Jessun@Halliburton.com Brent Edmunds@?Halliburton.com HALL.launTON Gar-oict — REPlOL Qugruk-301 ver. 2.0 Prudhoe Bay AK / U.S.A. 2.0 Well Design 2.1 Well Objectives The following mud program was prepared for an exploration well in the Colville River Delta, Alaska. A 20" conductor will be driven/drilled in place to +/- 100' RKB and cemented. A 16" surface hole will be drilled utilizing a freshwater AQUAGEL based spud mud vertically to —2,090' MD where 13 3/8" casing will be set/cemented at depth. An ENVIROMUL MOBM drilling fluid will be used for the intermediate hole section. This 12 t/a" section will be drilled to 5,250' MD where 9 5/8" casing will be set/cemented at depth. A 6 1/8" hole section will be drilled horizontally using the same MOBM fluid system to a TD of 7,53 P MD. After drilling, a DST will be performed and Qugmk 301 will move into completion operations. The well will be spudded using a conventional bentonite spud mud weighted to 9.8 ppg. The MW will be allowed to rise to 10.0 ppg by the base of the permafrost (+/- 1,070' TVD) with the additions of BARACARB 25/50 or barite/drill solids. Our primary focus areas for surface hole drilling will be adequate MW for well control and sufficient viscosity for hole cleaning. Background LCM consisting of 3-5 ppb BARACARB 25/50 will be used through the surface section to reduce lost circulation potential. The 12'/a" hole section will be drilled using an ENVIROMUL MOBM fluid with a MW of 10.4 ppg. Before drilling, a spacer train will be pumped to reduce contamination between fluid systems. Additions of BAROTROL PLUS and BAROBLOK will be made for shale stabilization. Walnut can be added at 3-5 ppb as background LCM to help prevent bit balling caused by sticky clays. The same MOBM fluid formulation with a reduced MW (9.3-9.5 ppg) will be used while drilling the 6 1/8" production interval. DFG 5.7 will be run at a minimum of every 12 hrs while drilling using real time ROP, RPM and pump rates to monitor hole cleaning. 2.2 Well Design Summary Hole Size Casinglrubing TD (ft) TVD (ft) Inc. (deg) Feet Drilled Mud System Mud Density Interval (in) Size (in) Max (n) (Ppg) Name 16' 133/8" 2,090' 2,090' 0 2,090' Bentonite 9.8-10.0 Surface Spud Mud 12 114" 95/8" 5,250' 4,180' 90 3,160' MOBM 10.4 Intermediate 61/8" NA 7,531' 4,180' 90 2,281' MOBM 9.3-9.5 Production H^LLIBLJRTON 3.0 Interval Discussions 3.1 16" Surface Interval 100' — 2,090' MD 3.1.1 Fluid Summary Breakdown: AQUAGEL/Freshwater Spud Mud - .moi REPlOI Qugruk-301 ver. 2.0 Pr11dho BavAK! .A. Drilling Fluid System 9.8-10.0 ppg AQUAGEUFreshwaler Spud Mud Products Required Soda Ash, AQUAGEL, Caustic soda, BARACARB, BAROID 41, PAC L, DRIL-N-SLIDE and CON DET Recommended Solids Control Shakers: Begin with -80 mesh screens, screen up as now rates and solids allow. Centrifuge: Run as necessary to balance LGS and necessary MW. Sloughing Gravel Maintain viscosity to carry gravel out of Potential Problems Solutions wellbore Utilize CON DET/DRIL-N-SLIDE to Heavy Clay Intervals minimize shaker blinding from clay. Interval Objectives Maintain Well Control. Run and cement the 13 3/8" casing. Restricted Products None 3.1.2 Interval Operation Summary • Have the rig or Baroid mud plant mix - 600 bbls 9.8 ppg Spud Mud and deliver to the wellsite. • Ensure rig pits and lines are clean prior to offloading any new mud from trucks. • Drill ahead maintaining all product concentrations while adding dilution mud or cold lake water. • Begin drilling with 9.8 ppg MW and allow drill solids and BARACARB to increase the MW to 10.0 ppg by the base of Permafrost (+/- 1,070' TVD). Use Barite if necessary to maintain adequate MW. • Run background BARACARB 25/50 at 3-5 ppb for bridging to minimize lost circulation events through the unconsolidated formations seen in Prudhoe Bay surface hole sections. • Additions of CON DET/DRIL-N-SLIDE can be made to reduce bit balling/shaker blinding when penetrating high -clay content sections. • Maximize the usage of all solids control equipment, screen up when possible and run the centrifuge to reduce LGS and maintain MW. • Utilize cold lake water for rig site dilution fluid. • Maintain >500 gpm pump rate while drilling ahead. Utilize DFG 5.7 for real-time modeling of hole cleaning abilities. Adjust fluid rheology, pipe rotation (RPM) and ROP based on the ability to clean the hole. • A full mud check is required before tripping to confirm fluid properties. • In preparation for running the 13 3/8" casing, ensure the native solids (LGS) content are < 10%. • Check with cementers to target a YP while circulating the casing on bottom. Use Desco CF to obtain the desired YP. 3.1.3 Hazards/Concerns • Follow all REPSOL-Halliburton processes and Procedures • Truck Usage Volumes - Track the truck utilization volumes using the Repsol Waste Management spreadsheet. CH2Mhil1 trucks are maximized at 90% of their carrying capacity for every load hauled, and less when heavy fluids are hauled. Attempt to load Vac trucks and Super Suckers to their 90% maximum volume, always taking rig time into account while anticipating trucking wait times. Keep into account downtime of trucks during transport to and from the rig. Give logistics dispatchers >24 hours advance notice prior to jobs requiring multiple trucks on location. • Hole Cleaning - Run DFG 5.7 a minimum of every 12 hrs while drilling to monitor hole cleaning capabilities using real dme ROP, RPM and pump rates. The continual loading of drill solids into the mud system will change the rheological properties of the mud. Utilize all solids control equipment. Be prepared to dilute by means of water or whole mud to diminish the effects of the drill solids. • Lost Returns - Losses are not expected through this surface hole section, although a full complement of LCM contingency products will be available on location should losses occur. If losses do occur refer to the attached WBM LCM Tree. HALLIBU'FITOIV REP-rOL Qugruk-301 ver. 2.0 Prudhoe Bnv AK / U.S.A. • Well Control —Rig hands and Mud Engineers shall constantly be aware of mud density measurements, trip volumes and pit volumes to ensure good well control practices are followed. MWDs and Mud Engineers will track ECDs daily. If ECDs rise l ppb over clean hole calculated ECD documentation is required in the daily mud report. • Shallow Gas Potential — o A gas influx on an offset well was experienced at a depth of 2500' TVD on Well Fiord #2. Mud weight was 9.2 ppg when the event occurred, BOP'S were in place and the well was killed with a 9.4 ppg fluid. The mud weight was increased to 9.7 ppg and no other problems were encountered. o A well control event occurred on Qugruk #2 while drilling with 9.2 ppg mud at 2523' MD. The design of this well has the surface casing being set above the Tuluvak and a MW of 10.4 ppg while drilling the Intermediate section. 3.1.4 Formation Tops/Pore Pressures Formation Estimated Formation To DSS Expected Pore Pressure MW ) Prince Creek GL 8.6 Upper Schrader Bluff 850 8.6 BPRF 1,040 8.7 Middle Schrader Bluff 1,607 8.8 MCU Lower Schrader Bluff 1,985 8.8 3.1.5 Target Properties/System Formulation: AQUAGEL/Freshwater Spud Mud Fluid Target Properties MD (ft) Mud Weight Funnel Vis YP pH API MBT 25 ppb ( ) (ser/ t) BARACARB 25-50 3-5 ppb Background (mq 70 ppb (9.8 ppg) 100'-2,090' 9.8-10.0 85-275 25-65 >9.0 <14.0 20-25 System Formulation Product Concentration Cold Lake Water 0.94 bbl Soda ash 0.15 ppb AQUAGEL 25 ppb Caustic soda 0.1 ppb (9.0-10.0 pH) BARACARB 25-50 3-5 ppb Background BAROID 41 70 ppb (9.8 ppg) PAC -L As needed to reduce API wl DRIL-N-SLIDE/CONDET PREMIX As needed for sticky Clay 3.1.6 Suggested ROP/Pump Rates Pump rate and drill string rotation should be optimized through the real-time use of the DFG software for the actual ROP while drilling. The table below highlights the maximum ROP recommendations above which hole cleaning will become an issue in this interval. Maximum Acceptable ROP in fph at Specified GPM and RPM GPM500 550 600 80-r m 100 110 125 100 -rpm 100 1 110 125 120 rpm 100 1 110 125 Calculated using 4% maximum cuttings load. NAlkL.LIB VP1T0N earoiel q4W REP-fOL Qugruk-301 ver. 2.0 Prudhoe Calculated ECD's @ 600 GPM and 100 RPM Depth (MD) Mud wt. (ppg) Clean hole ECD Max ECD(4.0%cuttings load) 500' 9.8 10.0 10.4 1,000' 10.0 10.2 10.6 1,500' 10.0 10.2 10.6 2000' 10.0 10.1 10.6 2,090' 10.0 10.1 10.6 Rheology and pump rate are critical factors in cleaning this vertical wellbore. Consider the following practices if hole cleaning becomes an issue: • Hole cleaning sweeps (change flow regime of base mud by using thicker rheology for increased carrying capacity). • Connection practices - employing extended gpm, rpm and back reaming, prior to the connection. 3.2 12 r/4" Intermediate Interval 2,090'— 5,250' MD 3.2.1 Fluid Summary Breakdown: ENVIROMUL MOBM Drilling Fluid System 10.4 pp NVIROMUL MOBM Main Products LVT 210,INVERMUL NT,E7 MUL NT,GELTONE V, Lime, DURATONL" HT ,Calcium Chloride. BAROID 41, BARABLOK, BARATROL PLUS Recommended Solids Control Shakers: 165+ mesh screens, screen up as solids loading on screens diminishes Centrifuge: As necessary to balance MW and LGS buildup Bad displacement Maximize pump rate and pipe rotation, use spacers Potential Problems Solutions Lost Circulation Have excess LCM products available on location Sticky Clay Walnut to alleviate bit balling and shaker blinding Interval Objectives Drill 12'/<<" hole to 5,250' MD. Run and cement the 9 5/8" casing. Restricted Products None 3.2.2 Interval Operation Summary • Clean and flush all surface equipment, pits and lines before receiving any ENVIROMUL MOBM. • Displace well to ENVIROMUL MOBM system: Spacer Formulations: • Pump 50 bbl of 10.4 ppg brine treated to a >40 YP with BARAZAN D PLUS. • Pump 25 bbl of the MOBM treated with GELTONE to a YP > 40. • Chase spacers with the ENVIROMUL MOBM mud system. Displacement: • Monitor pump strokes to obtain correct displacement. • Maintain maximum pump rates. • Have the bit on bottom as the oil mud exits the bit. HALLIBUM7C3r4 Baroid MW REPWOL Qugruk-301 ver. 2.0 Prudhoe • Reciprocate the drill string by one joint every 15 minutes. • Rotate the pipe during the actual displacement (>60 RPM). • Do not shut down the pumps during the displacement. • Use an E.S. meter at the flow line to determine when the fluid is water free enough to start taking the returns back into the system. An ES of 200-400 should be sufficient to indicate when displacement is complete. A retort should also be run at this time to confirm fluid quality. • Shut down pumps and clean possum belly and any troughs which were used to transport water base fluid. • Drill ahead maintaining all product concentrations while adding dilution fluid. • Maintain a NAP water ratio between 75/25 and 85/15 while drilling. • Add 3-5 ppb Walnut as background LCM/bit scouring method to help prevent bit balling caused by sticky clays. Utilize the circ sub to spot LCM if needed. If LCM pills are greater than 35 ppb check with MWD before pumping. • Maximize the usage of all solids control equipment, screen up where possible and run the centrifuge to minimize LGS and maintain correct MW. • Add BAROTROL PLUS and BARABLOK for shale stabilization. • Utilize LVT 200 for rig site dilution if LGS begin to rise above the recommended <6.5%. • Maintain 500 gpm pump rate while drilling ahead. Utilize DFG 5.7 while drilling for real-time modeling of hole cleaning abilities. Adjust fluid rheology, pipe rotation (RPM) and ROP based on the ability to clean the hole. • A full mud check is required before tripping to confirm fluid properties. • Should lubricants be required, add 1-2% NXS-Lube. Call town prior to going over 2%. • Check with cementem to target a YP while circulating the casing on bottom. 3.2.3 Hazards/Concerns • Follow all REPSOL-Halliburton processes and Procedures • Truck Usage Volumes - Track the truck utilization volumes using the Repsol Waste Management spreadsheet. CH2Mhill trucks are maximized at 90% of their carrying capacity for every load hauled, and less when heavy fluids are hauled. Attempt to load Vac trucks and Super Suckers to their 90% maximum volume, always taking rig time into account while anticipating trucking wait times. Keep into account downtime of trucks during transport to and from the rig. Give logistics dispatchers >24 hours advance notice prior to jobs requiring multiple trucks on location. • Hole Cleaning — Run DFG 5.7 a minimum of every 12 hrs while drilling to monitor hole cleaning capabilities using real time ROP, RPM and pump rates. The continual loading of drill solids into the mud system will change the rheological properties of the mud. Utilize all solids control equipment. Be prepared to dilute by means of LVT or whole mud to diminish the effects of the drill solids. Utilize real-time PWD for hole cleaning and sweep recommendations. • Lost Returns —A full complement of LCM contingency products will be available on location should losses occur. If losses do occur refer to the attached MOBM LCM tree. • Well Control —Rig hands and Mud Engineers both, shall constantly be aware of mud density measurements, trip volumes and pit volumes to ensure good well control practices are followed. MWDs and Mud Engineers will track ECDs daily. If ECDs rise above I ppb over clean hole calculated ECD documentation is required in the daily mud report. 3.2.4 Formation Tops/Pore Pressures Formation Estimated Formation To (TVDSS) Expected Pore Pressure (EMW ) Lower Schrader Bluff 2,195 8.8 Tuluvak 2,425 10.4 Nanushuk 3,783 8.9 Nanushuk Target 4,070 9.0 HALLIBURTCN L3 avoid REPJ'OL Qugruk-301 ver. 2.0 Prudhoe Bay AK / U.S.A. 3.2.5 Target Properties/System Formulation: 80/20 ENVIROMUL MOBM Fluid Target Properties MD Mud Weight Viscosity PV YP HTHP WPS ES EZ MUL NT ( PPg) GELTONE V 6-10 ppb Lime 7 ppb DURATONE HT 2 ppb 2,090'-5,250' 144 50-80 20-37 15-22 <5 250-270K >580 While Tripping 10.4 50-70 20-37 15-20 <5 250-270K >580 If hole conditions require deviation from the above ustea properties prior approvai uum tuwu „ System Formulation Product Concentration LVT 0.662 bbl Water .172 bbl INVERMUL NT 4 ppb EZ MUL NT 4 ppb GELTONE V 6-10 ppb Lime 7 ppb DURATONE HT 2 ppb Calcium Chloride 21 ppb BAROID 41 10.4ppg (as needed) BARABLOK 2 ppb BAROTROLPLUS 4 ppb 3.2.6 Suggested ROP/Pump Rates Pump rate and drill string rotation should be optimized through the real-time use of the DFG software for the actual ROP while drilling. The table below highlights the maximum ROP recommendations above which hole cleaning will become an issue in this interval. Maximum Acceptable ROP in fph at Specified GPM and RPM CPM 450 1 500 1 550 80 -rpm 100 110 120 100-r m 110 120 130 120 r m 115 125 140 Calculated using 3% maximum cuttings loaa Calculated ECD's @ 550 GPM and 100 RPM Depth (MD) Mud wt. (ppg) Clean hole ECD Max ECD(3.0%cuttings load) 2,500' 10.4 10.5 10.8 3,5001 10.4 10.5 10.9 4,5001 10.4 10.6 10.9 5,250' 10.4 10.6 10.9 Rheology and pump rate are critical factors in cleaning this horizontal wellbore. Consider the following practices if hole cleaning becomes an issue: • Extended periods of circulation (with maximum pump rate). • Hole cleaning sweeps (change flow regime of base mud by using thicker rheology for increased carrying capacity). • Connection practices - employing extended gpm, rpm and back reaming, prior to the connection. 10 H^L_UBUNYMM Baroid REWOL Qugruk-301 ver. 2.0 Prudhoe Bay AK / U.S.A. 3.3 61/8" Production Interval 5,250' - 7,531' MD 3.3.1 Fluid Summary Breakdown: ENVIROMUL MOBM Drilling Fluid System 9.3-9.5 ppg ENVIROMUL MOBM LVT 200,INVERMUL NT,EZ MUL NT,GELTONE V, Lime, DURATONE HT, Calcium Chloride. Main Products BAROID 41, BARABLOK ,BAROTROL PLUS Shakers: 165+ mesh screens, screen up as solids loading on screens diminishes Recommended Solids Control Centrifuge: As necessary to balance MW and LGS buildup Lost Circulation Have excess LCM products available on location Potential Problems Sticky Clay Solutions Walnut to alleviate bit balling and Shaker blinding Interval Objectives Drill 6 1/8" hole to TD at 7,531' MD. Run DST and P&A. Restricted Products None 3.3.2 Interval Operation Summary • After cementing the 9 5/8" casing, optimize the use of rig equipment and the Baroid Mud Plant to reduce the mud weight from 10.4 to 9.3 ppg. Whole mud dilution may be necessary. • Displace and isolate the 10.4 ppg MOBM from the well. Cut this fluid to 9.3 ppg and incorporate into the active system while drilling. • Drill ahead maintaining all product concentrations while adding dilution fluid. • Maintain a NAP water ratio between 75/25 and 85/15 while drilling. • Add 3-5 ppb Walnut as background LCM/bit scouring method to help prevent bit balling caused by sticky clays. Utilize the circ sub to spot LCM if needed. If LCM pills are greater than 35 ppb check with MWD before pumping. • Maximize the usage of all solids control equipment, screen up where possible and run the centrifuge to minimize LGS and maintain correct MW. • Add BAROTROL PLUS and BARABLOK for shale stabilization. • Utilize LVT 200 for rig site dilution if LGS begin to rise above the recommended <6.5%. • Maintain 250-280 gpm pump rate while drilling ahead. Utilize DFG 5.7 while drilling for real-time modeling of hole cleaning abilities. Adjust fluid rheology, pipe rotation (RPM) and ROP based on the ability to clean the hole. • A full mud check is required before tripping to confirm fluid properties. • Should lubricants be required, add I-2% NXS-Lube. Call town prior to going over 2%. • Check with cementers to target a YP before P&A operations. 3.3.3 Hazards/Concerns • Follow all REPSOL-Halliburton processes and Procedures • Truck Usage Volumes - Track the truck utilization volumes using the Repsol Waste Management spreadsheet. CH2Mhill trucks are maximized at 90% of their carrying capacity for every load hauled, and less when heavy fluids are hauled. Attempt to load Vac trucks and Super Suckers to their 90% maximum volume, always taking rig time into account while anticipating trucking wait times. Keep into account downtime of trucks during transport to and from the rig. Give logistics dispatchers >24 hours advance notice prior to jobs requiring multiple trucks on location. • Hole Cleaning — Run DFG 5.7 a minimum of every 12 hrs while drilling to monitor hole cleaning capabilities using real time ROP, RPM and pump rates. The continual loading of drill solids into the mud system will change the rheological properties of the mud. Utilize all solids control equipment. Be prepared to dilute by means of LVT or whole mud to diminish the effects of the drill solids. Utilize real-time PWD for hole cleaning and sweep recommendations. 11 HALLIBUFiTO1V REPWOL Qugruk-301 ver. 2.0 Prudhoe Bav AK / U.S.A. • Lost Returns —A full complement of LCM contingency products will be available on location should losses occur. If losses do occur refer to the attached MOBM LCM Tree. • Well Control -Rig hands and Mud Engineers both, shall constantly be aware of mud density measurements, trip volumes and pit volumes to ensure good well control practices are followed. MWDs and Mud Engineers will track ECDs daily. If ECDs rise above 1 ppb over calculated clean hole ECD documentation is required in the daily mud report. 3.3.4 Target Properties/System Formulation: 80/20 ENVIROMUL MOBM Fluid Target Properties MD Mud Weight (PPg) viscosity PV YP HTHP WPS PS 5,250'-7,531' 9.3-9.5 50-80 15-30 15-22 <5 250-270K >580 While Tripping 9.3-9.5 50-70 15-30 15-20 <5 250-270K >580 If hole conditions require deviation from the above listed properties prior approval from town is needed. System Formulation Product Concentration LVT 0.662 bbl Water .172 bbI INVERMUL NT 4 ppb EZ MUL NT 4 ppb GELTONE V 6-10 ppb Lime 7 ppb DURATONE HT 2 ppb Calcium Chloride 21 ppb BAROID 41 9.3 ppg (as needed) BARABLOK 2 ppb BAROTROLPLUS 4 ppb 3.3.5 Suggested ROP/Pump Rates Pump rate and drill string rotation should be optimized through the real-time use of the DFG software for the actual ROP while drilling. The table below highlights the maximum ROP recommendations above which hole cleaning will become an issue in this interval. Maximum Acceptable ROP in fph at Specified GPM and RPM GPNI 200 25U 2So 80-r m 120 155 175 100 -rpm 140 175 200 120 rm 150 1% 220 Calculated using 2.5% maximum cuttings load Calculated ECD's C 280 GPM and 100 RPM Depth (MD) Mud wt. (ppg) Clean hole ECD Max ECD(2.5%cuttings load) 5,500' 9.3 10.0 10.2 6,500' 9.4 10.4 10.7 7,500' 9.5 10.9 11.2 12 HA A-laumTON _ A ear -o cl MW REPWOL Qugruk-301 ver. 2.0 Prudhoe Bay AK / U.S.A. Rheology and pump rate are critical factors in cleaning this slant wellbore. Consider the following practices if hole cleaning becomes an issue: • Extended periods of circulation (with maximum pump rate). • Hole cleaning sweeps (change flow regime of base mud by using thicker rheology for increased carrying capacity). • Connection practices - employing extended gpm, rpm and back reaming, prior to the connection. 4.0 SCE Recommendations Shakers • Multiple, High -G, linear motion shale shakers are recommended in order to maximize the system solids control removal efficiency. Run all available solids control equipment to prevent solids build-up. • All shale shakers should be "screened up' with finer mesh screens whenever possible without the loss of any drilling fluid off the end of the shakers. • The shale shakers should be continuously monitored for the proper distribution of drilling fluid across the screens to fully utilize the entire surface area of the screens. The drilling fluid should cover +3/4 of the entire screen length. • Damaged screens should be promptly changed and noted on the daily mud report screen usage column. • If near size particle blinding occurs, an attempt should be made to "screen -up" to alleviate this problem. If "screening -up" does not solve this situation, then coarser mesh screens must be installed until past this formation. • Sticky clays and heavy oils are prevalent in Prudhoe Bay surface holes and shallow intermediate hole sections. Use DRIL-N-SLIDE on surface hole section and LVT on intermediate and production hole sections to remedy the screen blinding seen while drilling sticky clay and heavy oil formations. • Make sure all needed screens are on location prior to drilling operations. Centrifuge • While drilling ahead, maintain LGS content and MW through use of the centrifuge. 5.0 Estimated Fluid and Drill Solid Disposal Volumes 16' Surface Interval: AQUAGEIAFresh Water Spud Mud Surface Fluid P10 P50 P90 Initial Build 550 550 550 Dilution 2090 2570 3050 Total 2640 3120 3600 Dilution rates for the 16' surface interval are calculated at 1.2% (P-10), 1.6% (P-50) and 2.01X (P-90) with 25% washout. Su ace Drill Solids P10 P50 P90 Cuttings Volume 520 650 1040 Wetting Fluid 520 975 2080 Total 1040 1625 3120 Cuttings volume estimates based off gauge hole (P-10), 1.25% (P-50) and 2.0% (P-90). Wetting fluid estimates based off LU% (P-10), 1.5% (P -5n) and 2.0% (P-90). 13 HAL L I B U RTO IVI ea, Ord 12'/4' Intermediate Interval: ENVIROMUL MOBM _ J REPlOL Qugruk-301 ver. 2.0 Pr tdho Bav AK / .S.A. Intermediate Fluid PIO P50 P90 Initial Build 863 863 863 Dilution 1157 1297 1436 Total 2020 2160 2299 Dilution rates for the 12,25" intenuediate interval are calculated at 0.45%(P-10), 455% (P-50) and 0.65% (P-90) with t5% washout. Intermediate Drill Solids P10 P50 P90 Cuttings Volume 461 576 922 Wetting Fluid 461 576 922 Total 922 1152 1844 Cuttings volume estimates based off gage hole (P-10), 1.25% (P-50) and 2.0% (P-90). Wetting Fluid estimated at a 1:1 ratio with cuttings. 61/8" Production Interval: ENVIROMUL MOBM Production Fluid P10 P50 P90 Initial Build 300 300 300 Dilution 286 364 441 Total 586 664 741 Dilution rates for the 6 1/8" production interval are calculated at 0.25% (P-10), 0.35%, (P-50) and 0.45% (P-90) with 10% washout. Production Drill Solids NO P50 P90 Cuttings Volume 83 91 125 Wetting Fluid 83 91 125 Total 166 182 250 Cuttings volume estimates based off gauge hole (P-10), 1.1% (P-50) and 1.5% (P-90). Wetting Fluid estimated at a 1:1 ratio with cuttings. 6.0 Total Well Cost P10 P50 P90 Surface Intermediate Production Total Fluid Cost Total Well Cost I6! HALLIBIJFtTO1V _ 8araicl _ REPO[ Qugruk-301 ver. 2.0 7.0 Appendices 7.1 16" Surface Interval Hydraulics at 2,090' MD E— DFG 58 Dn11Fhean® !�LS?Tttl0_ .fA CMR, Toni sooezc�e En no '- Z Cuw"L. T.W 9t AvpyaV MaFMpF ECO WWEon psi Ix «m mn"+n n iwe� n^r Simulation Data: Mud Weight = 10.0 ppg, Flow Rate = 600 gpm/14.3 bpm, ROP =125 ft/hr, Max Clean Hole ECD = 10.2 ppg, Max ECD with 4% cuttings load = 10.6 ppg, Max Clean Hole ECD at casing shoe = 10.1 ppg, Max ECD with 4% cuttings load at the casing shoe = 10.6 ppg, Size of DP used = 5". 15 HALLlBUI1TON _ -� Ba, Old REPrOL Qugruk-301 ver. 2.0 7.2 12 t/a" Intermediate Interval Hydraulics at 5,250' MD � C)n G•:m, DFG 61 DIMheed® nor i`.cW oam rrw cmvp fl�l W %@ tYIA Mr -1 ttl.0 nRA MC�10)A I ?4 fL 1- , o .v a vo wv ZGNnY Lwtl T.v.rvY re � PWq.V 's INY.YNY !GO 'MYY01. 1x1 Ix�el IIYnIN M Ivrvl IYI Simulation Data: Mud Weight= 10.4 ppg, Flow Rate= 550 gpm/13.1 bpm, ROP = 130 ft/hr, Max Clean Hole ECD = 10.6 ppg, Max ECD with 3% cuttings load= 10.9 ppg, Max Clean Hole ECD at casing shoe = 10.5 ppg, Max ECD with 3% cuttings load at the casing shoe = 10.9 ppg, Size of DP used = 5". CeMY (uP,O.odl i )6Sx Cu6n95f 16 1-IALLIBUfaTON _ ;, t3aroid _ REPYO! Qugruk•301 ver. 2.0 Prudhoe 7.3 61/8" Production Interval Hydraulics at 7,531' MD iancur om. o zammaww� .a �N h Tempm)W Av v MM) "-I DFG 68 DFNWNRM enol. 1' 24naoaTw flOP. N.04Tt 3.18Ai Lu4,rp Ell QAOn90o0tW In XW MG�,p]OflWHm FKm/ Simulation Data: Mud Weight = 9.5 ppg, Flow Rate = 280 gpm/6.7 bpm, ROP = 200 ft/hr, Max Clean Hole ECD = 10.9 ppg, Max ECD with 2.5% cuttings load =11.2 ppg, Max Clean Hole ECD at casing shoe = 10.0 ppg, Max ECD with 2.5% cuttings load at the casing shoe = 10.3 ppg, Size of DP used = 5" and 4". 17 HAtLLimunyON Baroid _ REPJOL Qugruk-301 ver. 2.0 Prudhoe Bay AK / U.S.A. 7.4 Lost Circulation Decision Trees Losses Lost Circulation Decision Tree f/ WBM Hole Section Partial Seepage tAcrossFatultilc 20.60 bbllhr5.20 bbllhr Static StaticStaticL!f! tatic Treat Active System Treat Active System with 5 sxlhr Barofibre with 10 sxmr 60-1 154200 bbl/hr Static Drill Across Fault BAROFIBRE DrilDrill Across Fault Contact Dnlling Engineer or Engineer Lo se m115 as namic 100 ppb LCMANud Pill: on call bbl/hr Losses ve 20 ppb Baroseal F Contact Drilling Engineer 20 ppb Baroseal M bbl/hr 30 pop Barofibre or Engineer on call. DdllAhead Drill Ahead 20 ppb WallnutM No 10 ppb Wallnut F No Increase Treatment to POOH, PN dumb iron BHA 5 sx/hr Barofibre 70 ppb LCWMud Pill: 5 sxlhr Baracarb 50 Contact Drilling Engineer or 20 ppb Baroseal F Consider Engineer pot Call". Consider spotting EZ 20 ppb Baroseal M SQUEEZE or GUNK pill. 20 ppb Barofibre ynamc 10 ppb WallnutM Consider spoiling EZ Losses < 15 Yes SQUEEZE piIVGUNK Squeeze bbllhr � cemenUplugback contingency Drill Ahead No 10 ppb Baroseal FI \ bblmr\Y, 10 ppb Baroseal M 10 ppb Barofibre M 1) Drill across fault or loss zone 1.5.2.0 times the length of the throw Contact Drilling g before spotting LCM pills. Engineer or Engineer 2) Circ Sub should be run in BHA to spot pills V°Partial Loss" cases on call to determine if or above are anticipated prior to drilling, to allow the spoiling or LCM —Yes 0�vn additional LCM pills. 3) LCM pill volume = 300-607 cdunn based upon actual hole treatments are to be diameter. Ahead made. 4) PRIOR TOANY LCM PILL, APPROPRIATE DISCUSSIONS AT THE RIG SITE MUST BE MADE TO MINIMIZE THE POTENTIAL No FOR PLUGGING THE DRILL STRING. CONTACT THE MWD ENGINEER FOR SIZING AND PPB MAXIMUM QUANTITIES Proceed to'Partial I ALLOWABLE THROUGH BHA. Losses' Pill M HAL_LIBURTON Losses Seepage 5.20 bbl/hr Static with 5 sxlhr Baraaarb 501150 LoSseS < 15 Yes bbVhr No Drill Ahead Increase Treatment io 10 sxPor Baraarb 501 150 20 ppb LCMIMud Pill: 20 bills base mud 10 ppb Baraarb 50 10 ppb Baraarb 150 bbllhr Drill Ahead No Proceed to'Partial Lasses' Pill REPVOL Qugruk-301 ver. 2.0 Prudhoe Bay AK y U.S.A. Lost Circulation Decision Tree f/MOBM Hole Sections 2060 bbl/hr Static T Yt Drill No 20 bbls Base mud 10 ppb Baraarb 25 20 ppb Baraarb 50 20 ppb Baraarb 150 Losses < \ bbl/hr Contact the Engineer on all to determine if additional LCM treatments are to be made Severe 60.200 bbl/hr Static 60150 bbl/hr Static 1 1150-200 100 ppb LCMIMud Pill: Contact Drilling Enginee 20 ppb Baroseal f or Engineer on call. 20 ppb Bamcarb 50 Consider drill ahead wl 30 ppb Barofibre 20 ppb SteeiSeal seawater 10 ppb Baracarb 150 Contact Drilling Engineer or Engineer "On Call". Consider drill ahead wf seawater WN Total > 200 bbl/hr Static I Drill Across Fault I Contact Drilling Engineer or Engineer on call without returns must approve any steps past PARTIAL losses. across fault or loss zone l.5- 2.0 times the length of the afore sporting LCM pills. sub should be run in BHA to spot pills if'Partial Loss cases or are anticipated prior to drilling to allow the spotting of LCM I LCM pill volume= 300'-000' column based upon actual hole IOR TO ANY LCM PILL, APPROPRIATE DISCUSSIONS AT RIG MUST BE MADE TO MINIMIZE THE POTENTIAL FOR ;GING THE DRILL STRING, HA'LLIBUF1TiON _,-,�� REPWOL Qugruk-301 ver. 2.0 Pr dhae Bav Testine at the Wellsite • During normal drilling operations one complete mud check should be run every 6 hours. This is a total of four complete checks made over a 24 hour period. Timing for mud checks and cost cut off should begin at 12:01 am each day. Unusual circumstances and/or non circulating periods should dictate deviations from this schedule. • All rheological properties (ie. 6 speed readings, LSRV and gel strengths, including 30 minute gels) will be taken at the standard 120 ° F unless otherwise specified. Routine Samuline Mud samples (I QT) should be sent in any time the need arises, ie. hole problems or lubricant problems. Samples of the mud plant built fluids will be tested prior to shipment to the rig site and saved until the well is completed. Samples must be logged on appropriate sample tracking form. Samples of new mud delivered to the rig site will be checked for weight and rheology at a minimum prior to offloading into the rig pits. HSE at the Wellsite Health • All rig personnel should have access to current/up to date SDS sheets and PPE required by SDS sheets for every drilling fluid product on location. An SDS book must be retained in the rig pits, and Mud Lab. These books will be maintained by the onsite mud engineer. Additionally quick reference PPE charts for specific products will be posted in the rig pits and the mud lab. These charts are by no means an SDS replacement. Always read and adhere to the SDS sheet prior to handling any drilling fluid products. • Rig Crew Pretour meetings are a good platform to discuss upcoming product mixes and HSE requirements. Environment • Ensure all sack products stored outside are shielded from the arctic weather with plastic or a box. • Do not store single sacks outside of a box. • Attempt to use all opened, partial sacks. • Proper planning for necessary products in the pits will diminish the "Hurry up" factor. Properly planned events create less opportunity for mishaps. 20 HALLIBunymN Garolcl _ REPlOL Qugruk-301 ver. 2.0 Prudhoe Bay AK / U.S.A. NFPA Ratinas Product Name Aldacide G 1 tl Reactivity 0 PPE respimmr. rubber gloves, robber aprom chemical goMks. face sbield Aquagel 0 0 0 Respirator, coveralls, work gloves safety glasses BARABLOCK '1 0 Dust -mist respirator. coveralls, work gloves, safety glasses Bancarb Bangor 700 1 1 0 2, 0 0 mveralls. work gloves. safety glasses robbe,iross, chemical goggles, mveralls BeruDef run Hp 1 0 0 mvenik, tubber gloves, robber apron, chemical goggles B..Klean BDFSl5 I 1 1 0 0 0 respinwr. robber gloves, robber aprom chembal goggks face shield dust mask, mvmnlls, work glove, safety glams Baraaev D o 0 dust mask, or.lis, s.rk gloves, safety glassu BarmmoN 11 0 0 mveralls, work gloves, safety glasses Barafibro 0 0 ':.:. .. ,...: 0 mvenik work gloves, safety Sksses Baroid I 0 0 dust mask, mveralls, work glues, safety Glasses Boreaeal u 0 coveralh. so gloves. safety glasses Ruotml Plus 1 0 0 dust mask, mveralls, work glow. safety gloms BDF499 0 - 0 robber gloves. mbkou apron, chemical goggles, face shield Bicarbonate of audit 0 0 _ 0 roveralla, work gloves, safay glasses CALCIUM CHLORIDE ; I n 0 dust mist respinwr,.veralk, work gloves. dug proofgoggks Carbon.. Caustic Soda 0 ll 0 0 mveralls. cork gbva,. safety glasses respinwr, robber gbva, rubber apron chemical goggks, face shield CFS -520 Citric Ackl Anhrd.nc I I u 0 - 0 0 coveralls. rubber g1.1.,fib1gr aprom safety goggles respiraw, muter glove, robber apron. chenu<al goggle, have shield Des. CF lagan LT 0 0 0 0 J 0 ouvro.fis. work glove, safety glages coveralls, work glovessafety glasses DdI-N-Slide 0 0 0 mveralls, work gloves, safety gksses DURATONE HT I u 0 NIOSH certified respinwr, mvemlls, work glove, safety Slams EPMudlube I I 0 rubber gloves, chemical goggles,.vemlls EZ MUL NT 0 Organic vapor respirator, impervious rubber gloves, rubber apron, chemical goggles, face shield GELTONEV Geovks %TL "1 0 0 0 NIOSH certified respirator. glove, safety glasus, coveralls dust mask, gloves, safety Slows INVERMUL NT e 0 organic vapor respirator, impervious mbbergloves.robberapwn, chotau,al goggles, face shield Mica nor I 0 0 coveralls. work gbve,safetyslages LIME n 0 dust mist mpiraror(95%),goggles, tubber apron. impervious rubber glove, ohemicalgoggles LVT-200 o 0 organic vapor respirator, coveralls, work gbves, wfety &Issas N-Drfi HT. 0 0 0 .vetalls, work gbva, safety glasses No -S.6 0 0 dust k. coveralls. void gloves, safety glasses N -Vis o t n 0 mvenik, work gloves, safety glasses NRS -Luba I 0 robber gloves. safety glasses. coveralls Sodium Bromide 0 0 dust rmsk, mveralls work gloves, safety glasses Sodium Chloride a 0 0 0 dug mask, coveralls, work gloves, aufety glasses Steel Seal "1 0 0 e.veralls, work gloves, safgygiasses Stick -Less 20 0 dust nmsk.veralls. work gloves. rarety glasses Well-NutM 0 eoverall, ..As glove, safety gloves 21 AW REPVOL Alaska North Slope Qugruk-301 Shallow Hazard Report December 2014 G ✓IYiE i*UA 25 1 Y. p 1j OF Ib n ffI � 4 % i 8 F s JI f fi D g eG00 Ill 289 3Y000 356W0 33ee00 360000 36)000 3tl3o00 3S600o 3[eNe 330000 313000 �. _ ..._ Geophysics Upstream Repsol Services Company Geophysics Department 2001 Timberloch Place, Suite 3000 The Woodlands, TX 77380 Phone: 281-297-1000 Fax: 281-297-1778 TABLE OF CONTENTS PROJECT LIMITATIONS.. 1. Purpose and Scope .................. 2. Seismic Conditioning and AVO Inversion ............ 4. Seismic Amplitude Analysis ................................. 5. Well Correlation ..... 6. Gas Hydrates ............................. 7. Conclusions ...................................... 1 Qugruk-301 Final SSHH REP-rOL REP"L PROJECT LIMITATIONS This document was prepared by the Seismic Attributes group, commissioned by Alaska Exploration Team. The report is the result of an interpretation that is not infallible, based on all the provided data; including but not limited to seismic, well, and geological interpretations. The views expressed in this report are based on the best estimates of the Seismic Attributes group at the time of publication. The Seismic Attributes group cannot guarantee the accuracy of this report or data contents for any purpose, as the result is limited by the quality, amount, and distribution of the input data. i7 Qugruk-301 Final SSHH REP"L 1. Purpose and Scope The goal of this study is to provide a pre -drill shallow hazard screening of the Qugruk-301 location that is situated in the North Slope, Alaska. The shallow hazards analysis is focus on the prediction of free shallow gas and gas hydrates. This analysis is based on the P-wave reflectivity that was generated from the Tabasco North 3D pre -stack seismic data. The seismic data is integrated to the available well log information to better understand the possible distribution of the potential drilling hazard zones. Figure 1.1 shows the location map of the studied area. Figure 1.1: Tabasco North 3D and Qugruk-301 location. 3 Qugruk-301 Final SSHH REP-rOL Executive Summary The seismic amplitudes of the Tabasco North 3D P-wave reflectivity volume were analyzed. After a detailed amplitude examination, it was found a series of anomalous high and low vertical amplitude bands around the Qugruk-301 (Q301) location. To verify the relation between the seismic amplitudes and the surface conditions, amplitude extractions on four horizons was performed from 430 ms to 610 ms (1895 ft. to 2515 ft. approximately). The result of the amplitude analysis shows that the seismic amplitude bands correlate with surface obstacles and undershooting areas. Consequently, the Tabasco 3D around the Q301 location is not reliable for shallow hazard analysis. The Q301 location is situated inside one of the low amplitude bands in the P-wave reflectivity volume. This low amplitude zone can affect the seismic anomalies caused by shallow gas. However, the location Q301 is placed less than 300 feet from the Qugruk-3 (Q3) well. Hence, the Q301 location should have the same shallow overburden lithology than the Q3. The well Q3 did not have any important shallow hazard event during its drilling operation. The total gas indicates above background gas intervals at 282 ms, 608 ms and 935 ms (1405 ft., 2530 ft. and 3745 ft. approximately). These levels will be taken in to consideration during the drilling operation of the well Q301. 4 Qugruk-301 Final SSHH REPVOL 2. Seismic Conditioning and AVO Inversion The goal of seismic pre -stack data conditioning is to generate the best possible set of seismic data for amplitude analysis. The data conditioning workflow included: 1. PSDM Gathers depth to time conversion 2. Radon 3. Trim Statics 4. Band Pass Filter (5-10-50-60) AVO inversion was performed to produce two key AVO attribute volumes. The first volume, Rp or P- wave reflectivity, this AVO attribute is equivalent to the normal incidence (RO) volume produced by the Intercept/Gradient (RO/G) AVO inversion. The second volume is the Rs or S -wave reflectivity. Both volumes were produced using the two term Fatti equation (Fatti, 1994). The physical interpretation of Rp and Rs is that they represent the zero -offset P-wave and S -wave reflectivity, respectively. These attributes are computed using a least squares fit to the amplitudes as a function of angle, using the first two terms of the equation: RPP(0) = C,Rp +C2Rs The incidence angles were calculated from the interval seismic velocity volume and they were restricted to 35 degrees. Figure 3.1 xline 207 P-wave reflectivity volumes. 5 Qugruk-301 Final SSHH ili 6. Gas Hydrates Permafrost are sediments that are frozen more than two consecutive years. Within the permafrost the gas is part of the crystalline structure of the gas hydrates. Bellow the permafrost exists a transition interval where frozen sands can be found. The sands within the transition zone can be frozen depending on the basin heat flow and climate variations. In the well Colville River -1 (Figure 6.1) the base of the permafrost is observed at 1050 feet and the base of the transition interval about 1400 feet deep. It is important to determine the thickness of the permafrost because gas is liberated from the melted sands during the drilling operations. The permafrost can also act as a seal for the free gas migrated from deeper layers. Assuming an average permafrost thickness of 1400 ft the base of — permafrost is located at 230 ms Figure 6.1: Example of permafrost at the well Colville River -1 =l permafrost eiocq; , t: @GC f: sec .� Base of Permafrost Base of Transition Zone As mentioned, it is importatnt to know the depth of base of the permafrost to predict the gas hydrates stability zone. Unfortuanetely, the permafrost does not produce an observable seismic reflector in the studied area. Figure 6.2 shows the map of the base of the permafrost generated from well data; the base of the permafros is situated at 1040 feet depth at the Q301 location. Assuming a transition zone of 350 ft, we can expect to find gas hydrates from surface to 1390 ft aproximately. 12 Qugruk-301 Final SSHH REPXOL Figure 6.2: Base of the permafrost map from well log data. The shape of the permafrost is complex with several high and low areas. 13 Qugruk-301 Final SSHH REPWOL 7. Conclusions • Q301 location is situated inside a low amplitude zone in the P-wave reflectivity volume. This is due to the undershooting caused by the surface obstacles during the acquisition. This low amplitude zone can cover the amplitude anomalies caused by shallow gas. • The proposed location is situated less than 300 feet from the Q3 well. The well Q3 did not have any important shallow hazard event during the drilling. • The Q3 total gas log indicates above background gas count intervals at 282 ms, 608 ms and 935 ms (1405 ft, 2530 ft and 3745 ft approximately). 14 Qugruk-301 Final SSHH i ee _�ja�= � e �e • •1�_ a v + Ma L ' c - IN ■ x■ C■ G■ • I Le 21-1/4 2.000 PSI 6B el 7' 6 F1 I I I I I I I I %9-5/8 G TOOL LANDING SUB —13-3/8' FLUTED MANDREL HANGER 20"OVERSHOT —2" LP 11.12" 84.76" B WA r 5 5 J (8) uoi»aS 1e01IJaA .00'OZ 2 (a 71 00'0'N:U ao•o) aa¢Id uoiAaS I¢011YaA Isva tu) !STA (j)) u01172S 1904J9A <00'OZ 75� (3 7) 00'0 'N 3J 00'0) aueld uolpa5leDIyah 1SV3 (4) 1S3M 0 x izz z 0 A S OO LO, -DIIIIII .,74.I�� ■, ■ 21-1/0 2,000 PSI 68 13-3/1 (11) U0Ij73S 190109^ c00'OZ ,2 (3 3) 00'0'N 34 00'0) aUeld UUiyaS leDlyap 1SV3 (l}) 1S3M (4) UOQ3aS IGNIJOA 000'02 * (3 7) 00'0'N )J 00'0) aueld uoiya5 1e31yaq 1S`d3 OJ) 1S3M Bettis, Patricia K (DOA) From: quick, michael (ext) <michael.quick@servexternos.repsol.com> Sent: Wednesday, December 24, 2014 10:36 AM To: Bettis, Patricia K (DOA) Cc: dial, amanda (ext) Subject: RE: Qugruk-301 Permit to Drill Application Hello Patricia — The Repsol subsurface team has generated the pore pressure prediction curves based off of offset data, including the pore pressure measurement we obtained on the Qugruk 1 well in the Tuluvak Sand at 9.8 ppg EMW. They have development the minimum and maximum pore pressure curve shown in the PTD application, and at the Qugruk 301 location the Tuluvak is at a slightly shallower TVD than the Qugruk 1, thereby increasing the equivalent maximum mud weight to 10.4 ppg for the same pore pressure. To correct the statement in the Halliburton mud program, it would be accurate to state "the expected reservoir pressure of the Tuluvak sandstone ranges from 8.8 ppg to a maximum of 10.4 ppg EMW". The Qugruk 3 well, drilled by Repsol 2 seasons ago, is less than 200 feet away from the planned Qugruk 301 well. The Qugruk 3 well drilled the Tuluvak interval with a 10.2 ppg mud weight and we saw very little gas from this interval, and expect to see very little in the planned Qugruk 301 well. However, it is our program on all wells, to control drill the Tuluvak interval at +/-50 ft/hr to monitor potential gas shows from this sand. If gas shows are significant, we will have sufficient products on the rig to weight up the mud system as needed. Standard orders to monitor the well at every connection and preform flow checks prior to any short trip will be in place as well. Mud weight control is very important for the Tuluvak interval, but also for the Nanushuk interval that has shown mud losses at 11.5 ppg EMW (Mud weight plus ECD) on offset wells, so we are cautious to not have an artificially high mud weight that could also induce mud losses. As you noted, the Tuluvak interval is below surface casing, so appropriate BOPE will be installed and tested prior to drilling the interval. Please let me know if you have any additional questions. Best regards and Happy Holidays! Mike Michael Quick Alaska D&C Operations Team Lead Repsol E&P USA, Inc. 3800 Centerpoint Dr. Suite 400 Anchorage, AK 99503 Tel.: 907 375 6933 1 Cel: 907 317 2969 michael auickro)seNexternos reosol com REPlOL From: Bettis, Patricia K (DOA) [mai Ito: patricia. bettis@alaska.gov] Sent: Tuesday, December 23, 2014 2:49 PM To: quick, michael (ext) Subject: Qugruk-301 Permit to Drill Application Good afternoon Mike, Page 9 of the Haltiburton "Drilling Fluids Program" states that the expected reservoir pressure of the Tuluvak sandstone to be 10.4 ppg EMW. The well will be drilled using 10.4 ppg mud below the surface casing. If higher pressures are encountered within the Tuluvak, how will Repsol mitigate potential gas influx? Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or Patricia bettis@alaska.eov. FIELD: TRANSMITTAL LETTER CHECKLIST WELL NAME: r)lnCfj� Sol PTD: c2lY _ l i � Development —Service ✓ Exploratory _ Stratigraphic Test —Non -Conventional POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL The permit is for a new wellbore segment of existing well Permit (If last two digits No. API No. 50 - in API number are Production should continue to be reported as a function of the original between 60-69) API number stated above. In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name Pilot Hole L PH) and API number (50-_-_---- ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce / inject is contingent upon issuance of a Spacing Exception conservation order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements / Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, ✓ composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 4/2014 E Geologic Commissioner: Date: --� - --- Public Commissioner Well Name: QUaRUK 301 Program EXP Well bore a e seg PTD#:2141990 Company .REPS L E P USA, INC. Initial Class/Type seg _EXPAND, _- GeoArea 890_ Unit _ _ __ _ On/Off Shore On Annular pw Administration 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0391445, Surf Loc & Top Prod Interv; ADL0391455,. TD 3 Unique well name and number Yes _ Qugruk 301 - 4 Well located in a defined pool No Exploratory well 5 Well located proper distance from drilling unit. boundary Yes 6 Well located proper distance from other wells. Yes 7 .Sufficient acreage available in drilling unit. Yes 8 If deviated, is wellbore plat. included Yes 9 Operator only affected party _ Yes - Wellbore will be more than 500' from a lease line where ownership. or landownership changes. 10 Operator has appropriate bond in force Yes Bond No. 22032715 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval Yes _ PKB 12/23/2014 13 Can permit be approved before 15 -day wait Yes 14 Well located within area and. strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4. mile area of review identified (For service well only). _ _ NA_ 16 Pre -produced injector; duration of pre -production less than 3 months (For service well only) NA 17 Nonconven. gas conforms to AS31,05.0300A.A),0.2.A-D) NA 18 Conductor string provided _ Yes _ - 20" conductor set at 100 ft and cemented in place. Engineering 19 Surface casing protects all. known USDWs Yes _ No Aquifers.. North slope.. 20 CMT vol adequate to circulate on conductor & surf csg _ - Yes _ using stab in collar to ensure 13 3/8" surface casing is fully cemented. 21 CMT vol adequate to tie-in long string to surf csg Yes 9 5/8" casing will be cemented back. to surface.. Using stage collar at 3000 R md. 22 CMT will cover all knownproductivehorizons Yes - _ Planning on horizontal lateral in the Nanushuk Fm. _ Will set liner and do possible DST. 23 Casing designs adequate for C, T, B &. permafrost Yes - BTC calculations provided. Safety margins are adequate. 24 Adequate tankage or reserve pit _ Yes Rig has steel pits,.. waste to be transported t BP G & I. offsite. 25 If a re -drill, has a 10-403 for abandonment been approved NA - Exploration well. 26 Adequatewellbore separation proposed... Yes Q-3 surface location is 300. It away. 27 If diverter required, does it meet regulations.. Yes Rig has 16" diverter..- Layout of line is provided. Appr Date 28 Drilling fluid program schematic .& equip list adequate _ Yes - Max formation pressure= 1964.psi .(9.0 ppg EMW) Tulavik zone may be 10.4 ppg EMW GLS 1/2/2015 28 BOPEs, do they meet regulation _ Yes _ N105 has 5000 psi 11" T3 BOPE 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP =1547 psi Will test BOPE to 3500 psi. 31 Choke manifold complies w/API. RP -53 (May 84)- - Yes 32 Work will occur without operation shutdown..... - Yes Need sundry approval to complete and test well. 33 Is presence of H2S gas probable _ _ _ No... _ _ H2S not expected. Rig has sensors and alarms. 34 Mechanicalcondition of wells within AOR verified (For. service well only) _ _ .. NA Geology 35 Permit can be issued w/o hydrogen sulfide measures No Exploratory well, H2S measures. required. Expected reservoir pressure of Nanushuk is 9.0 ppg EMW; 36 Data presented on potential overpressure zones Yes _ Will be drilled using 9.8 to 10.4. ppg mud.. Surf csg w/ be set above Tuluvak as (potential gas sand w/ est. Appr Date 37 Seismic analysis of shallow gas. zones _ Yes 10_.4 ppg. EMW); M.W. below surf csg 10.4 ppg; potential gas hydrates to approx 1400' MD; M.W. at or above 10. PKB 12/23/2014 38 Seabed condition survey (if off -shore) NA - ppg bA Permafrost; Q301 located within low amplitude zone that correlates w/ surf obstacles ([fiver &lakes); 39 Contact name/phone for weekly. progress reports [exploratory only] Yes _. Q301 surf location <300' from Q3. 03 did not encounter any shallow hazard. --Mike Quick (907) 375,6933. E Geologic Commissioner: Date: Engineering o ssioner: Date Public Commissioner Date Sundry approval required for completion , stimulation and Flowback operations. GLS 1p�-s / d T (.L5 44=9 -1,12 -Is X4=9 - 1,13 -Is 1)ar-A HALLIOURTON Repsol E & P Qugruk 301 Intervals 1-6 Nanashuk A & B Formation Harrison Bay County, AK API: 50-103-20700 Prepared for: David Ross March 27, 20/5 Prb 2l `t - i Sales Order# 90224YS42 Stimulation Treatment RECEIVED Post Job Report 25# Delta 140 Prepared By: - Baltusch & Van Zyl Marcos Adan & Michael Osborn Nanook Crew AUG 2 6 2015 AOGCC No LONGER CONF[r)ENilgLv OCT a 8 201,9 Notice: Although the information contained in this report is based on sound engineering practices, the copyright owner(s) does (do) not accept any responsibility whatsoever, in negligence or otherwise, for any loss or damage arising from the possession or use of the report whether in terms of correctness or otherwise. The application, therefore, by the user of this report or any part thereof, is solely at the user's own risk. HALLIBURTON I Entunvamsn[ Table of Contents Section Paee(s) Wellbore Information 3 Actual Design 4-5 Interval Summary 6 -11 Well Summary u Interval 1 Plots 23-18 Interval 2 Plots 19-21 Interval Plots 22-24 Interval 4 Plots 25-27 Interval 5 Plots 28-36 Interval 6 Plots 31-33 Comments5ummary 34 Planned Design 35-36 Repsol E P - Qugruk 301 TOC Meal Toe CuatOmer Hbladb. type NYLLI®LIPTON °y+�:��.• I 5.011 -kers Me. W.. 1pap 3/27/2015 6000 RepeOl E&P PoDD&ipn Narashuk N&B tease Qugruk 301 be, 56103-20100 Date aM T.mpanture Ma rOP 2300 j( Temp,Gn4iem rypo0fr) 1.20 A VM 4150fr eXST)•q 110 TMa1 M0 ],496 ft SleeveS17 u— /pI�M Trn4neMTuhuldrz MOTbp MDBtm Tubular Burst Sue GratlUOexriptipn Nc(gal/ftl V4Wme(gaQ ye IRI 11it) 1006) pre101160 l 3F12ti L-80 0.3652 0 4610 1,684 18160 .5"12.6a L30 0.6392 4610 7,494 1,843 8,440 OiHereMial ]494 3.52] 56.3 61.3 66.6 218 T3 aM T.mpanture Ma rOP 2300 j( Temp,Gn4iem rypo0fr) 1.20 A VM 4150fr eXST)•q 110 TMa1 M0 ],496 ft SleeveS17 u— /pI�M Repsol E P - Qugruk 301 Wellbore Information ye ianep OispUremeM tO T¢p Slttve/Per((gap wiM3h/peffW sO 1006) To Btm p Eanep Ball Drop Time Hat MM) 1 Ball Nit Tim¢ 1XR:MM) ISV Drop 61 I 13V SIOw DO¢T Ebl ( 1 Sur Nit 16611 Early (6611 Seat 1pA) P¢i)(bpm) Rate atsM1ik Pmppant COm..@ Sleeve1 OiHereMial 5 2355 25]] 2296 3018 3239 3460824 56.3 61.3 66.6 218 T3 5,464 5424 5,810 5.820 6,153 6,163 6,500 6,530 6,842 6,857 2,192 ],202 63:54.WPM S 4 2 1 3:58:09 PM 7,230 7,281 2,321 3:0]WpM 3:11:00 PM 5,930 5.966 60%9.] 3:20:COPM 2:26:00 PM 4,603 4,645 4,220 1:33 W PM 140 WPM 3,285 3,332 3,411 1246:00 PM 12:52:WPM 2,956 2,006 2p85 1111W M1 12:0100 PM 480 532 683 .10.9 40.4 -54.2 34.819205118 -120.6 38W 1R6 2,]45 20]2 23]5 ±ak'�'ntial 1125 1 5 12.5 301 120 197 0.415 0.504 0.003 OCD2 0.001 DOD 3,16] 3,2T 305 Repsol E P - Qugruk 301 Wellbore Information CVSIOMEP Reptl EBp A% $G]p310Mp LN BFO (I!/Bal) 4,200 LAT ]p,3N1R1 101 105 IE45E punk 901 SALES OMER WO4110E Malll®URTON BNSTN) n LONG -150.]031692 1.00 0.15 iplMpllON Mn6B ppiE 3/E]/IS 3.03 Maa Prbsure 1psil 6,260 6,264 1Wtl A00ltives Ory AdEI(ee.s 1$S20 11RW LW Prop Slurry Design Oean A2ual Clevn Aqual Uean GlwlateE Slwry prop UlculMt Prop Cly Web LosmyWD RC -VO Cx W-LTC4 WC 36 GSW 30 Opt,No-11 eF6 iIwI"e I Stage MIE Stage P pant Cons R.W Volume Volume Volume Volume z. Total (Yrgnp zuhmm oaflwer PropPmrvno� [e rou elww. .0 Repsol E P - Qugruk 301 Actual Design 4 25N Pe Frx]M Pro ant Wdtl "uid QrboEor 16/20 LN 30 4,200 A221 101 105 4,2W 4,077 103 1.02 235 300 25.00 O.S. 1.00 0.15 20 203 DOOF-140 %o ant Wen FIM CarbuBond 16/20 3.03 30 6,260 6,264 ]d9 163 1$S20 11RW LW I'm 2.25 2.0325M 0.50 LW .Is 25 MOeMaimc lop Wo ant Wen MW Urbo&M 26/20 3.00 30 6,340 6,379 352 173 19020 1],500 LW 1.02 2.25 2.W 25.03 0. 1.03 0.15 26 25ND.X F.I. PMI,nl Udlen Wd GrbGB nd 16/20 4.00 30 7000 7043 168 199 28 27500 LOD 1.00 2.25 2.03 2580 0.50 1.0 0.15 2] $SNDeRaFlac140 p ant Wen FW,d 6rboSond 16/20 b.W 30 ]OW 7 50 168 206 35W 34 W LW I'm 235 2.W 25= 0.50 100 0.35 $8 2500 Delta Frac lop p am Udm Raid UNo0anG 16/20 6.W 30 4250 4612 110 140 25,500 SSSW l.m 1M 2.15 2.00 25.0 0.50 l.m 0.15 29 25ND06Fp c140 30 4M 05 17 IJ 1.03 1,00 215 25.W 050 LW 0.15 30 25i WetersrxG Spacer&ealt dap 30 L250 3,269 30 30 1.0 Im 2500 050 1.00 0.15 31 25N DNbfrx 140 D"Pllamment 30 2$50 2,399 57 57 103 100 235 2500 0.50 IW 0.15 32 354 Deltarrac 140 Ip-, i$ 610 219 ] J l.m Im 225 25N 050 lm 0.15 33 2500 Deltarrac 140 pad 30 3,103 3,121 17 77 100 ]W 2.25 2500 0.50 Iw 0.15 34 254 Deltarrac 140 1p ant W- Mid ObWnd 16no 0.50 30 9120 4,168 99 ON 2,060 Imo lm ]W 2.25 2R0 25.00 R. 100 0.15 35 $500 D,ft,P-l4O 1 Ara antUden Fluid 6r BonE1 0 I lm 30 1 42W 42S0 101 106 4200 4103 1.00 iw 2.$5 2.00 2503 O.m lm On 36 254 .11.1- 1. Pro anc Wen Ruid QIWW.d 16/20 2.00 30 1 6.260 fi398 352 1% 1$520 12,100 lm ].m 2$5 20Y 2500 0.50 lm 015 31 2500 DAOF-140 ftI.1 laden RuW QN WM 16AG 3.00 30 w 6 385 152 173 19,020 IRMO IW 1.00 22S 2.03 25.00 0.50 lm 0.15 38 254UMNw140 Pm ant Uden Fluid Oibkndl O aW 30 7000 7,093 169 2m 28100 27,500 1.W 1.W 235 200 25030.50 1:22 0.15 39 2540 WrA 110 Pro and Udm FRW ur Bond ISM SW 30 ]0.V 7,.11 167 167 205 35. 346W L l m L25 200 25 03 0.50 122 0.15 40 251 neltaFrtt 140 pro ant Ud-nuW ..I nd ISM 6.03 30 4 W 4512 107 l37 25303 16,00 LW 1.W 2.25 2.00 2503 0.50 1. 0.15 41 250 DNcarrac 140 30 420 467 ]1 111.03 LW 225 25. 0.50 I. 0.15 d$ 2.500 Wate tF ra[6 Sp actt &gall Orpp 30 3,$50 1,2 fiE 30 30 l.m ].W 25.. 050 1. 0.15 43 250 DeWBac 140 Ospfamnent 30 zoo 2,100 50 W LW I.W 2.25 3s.W 0.50 1w 0.15 44 2590ell rroc 140 32 610 494 12 12 LW Lm 2.25 25.03 O W ]W 0.15 45 2540eltafrae 140 Im 30 33$0 3413 81 lu I.W 1,00 $.25 25.03 0.50 SW 0.15 4fi 25E N1.1-140 Pro ant Wen IWO Grbo8ond 16 0 O.W 30 4330 4330 98 101 20613 2,030 l.m I.m L25 203 25.03 0.50 1m 015 Repsol E P - Qugruk 301 Actual Design 4 euSTOMER PepMF& Ma 5aip oreu as.(I6/Pal) LAT ur.1M1 UWSE 6e8rvk3p1 MuSSORDER 1.1111.1 XPLL1809TON � ��_ ems, 21 LONG .l T16169E FOPMAM ukA86 DRIE 3/2]/15 Man Pramumlapll WrI Treatment Interval Sbge Number HUN .5 bn Surge Dea<rlpmm Proppent NacRption %<p C. (ppp Slurry late pea Designmean VOIVme ( Aauu- Volume 9p1f grn Imbe Volume (bpl/ bh lamd Volume, Volume (66f hop Total (16x1 bkuT.ml Pmp Tmal I6)f Eh -Web prymmml (qpF) amD o8r140 lI.... YBOlb qm poyl ale a(pp(/m (ppV brbogan Ok eal.vry pm Nam) WG -36 ow Ory MJrtrv6 GBWdO ppOflpAl 1.1 (ppf) BE6 heal 391.3 55 2Sp 0e8aFx 1J0 DB 4rement 145.6 2913 30 Laos 1901 as 45 sue, 79453 100 1.00 335 Ph,kal Malarial Volume Pumped 3500 0.50 L00 D 7910 56 2512 190 Sam PhWiral Mmedal Volume Imeante 5% SE 610 699 1] V .E% 43% I'm 1.W 2.25 13] 2500 0.50 100 015 912 57 25WwCNtaFl.p-x 1. Pad ]% .5% 1 30 3570 3,624 86 86 LW LM 225 2500 050 100 0.35 mm 56 250 Mlbirac la0 Pra and ad". CeraoBond 16/20 0.50 30 4,120 3485 83 85 2060 1%O 100 1M 2025 ECp 2500 0.50 100 0.15 �Q m 59 2Sp 0eltaha<140 Pro ant laden au. bNa8ond 16/20 LM 30 8200 4174 99 Me 4,200 3,900 IM 1.M 2.25 2.00 25.00 0.50 1.M 015 60 250 NII.Fmc 140 Pu ant Udm Fluitl CeNOWnd 16120 3.00 30 6,260 6301 350 164 12,520 121M IM 1.M 2.25 2.00 2500 0.50 1.M 015 a �n� 61 258 Wltafrx 140 busWom Laden Fluty OubOPond 1620 3.M 30 6340 63" 152 1]3 19020 18500 100 100125 200 25.00 0.50 100 015 ® 62 25u)uItalmc NO Pro and Udm nu. UNOBand i6/20 4,M 30 ]bM fi9)9 366 397 28000 2>FN 1.00 LM 325 2.0] ESM 0.50 L. 015 63 251 peltafrac 140 Pro mUden Fluty brbaW0 M 16 SM 30 7,=6966 166 2W 35MO 34 1M SM 225 2M 2500 0.50 3.00 0.15 64 25tl DeIbBFrac 140m ant Uden Fluty Cam.ftM 16/20 6.00 30 4,250 4273 I0E in 25500 20 .SM I.M 1 W 2 25 2 00 2500 O.SO 300 Ms 65 25tlD b Fwc 140 Suar., 30 420 995 24 U 1.00 SM 2.25 25Po 0.50 1Po 66 ESp WaterfracG Spxer&Ball pOp 30 1.250 369 9 9 100 100 2500 u.So 100 6] 25p 0 ImFec lop Oblwerment 30 1.596 1546 31 37 LOD 1.M 2.25 25.M 0.00 I.M 68 259 Debar -140 ]2 630 59] 34 14 I.M 100 2.25 as.M 0.50 1.00 69 259 Dralfrec 140 Pad 30 3).b 3564 65 85 1.00 1M 235 25M O.M im 4GAS be 70 259 DelmFrac 14D Proant Uden Fluid Carboam. l6/20 0.50 30 4,120 4MB 97 100 2,060 3500 1M 1.M 225 200 25.00 0.00 1.M y• 'r,' 73 259 DellaFrac 14D P ant Udeu Huid OAmBond 16/20 1.M 30 4,200 4298 l0E 101 42M SM 1.M IM 325 300 E5M 0.50 1.M' p2222pF ]E 259 Dlkafrac 140 ho ant Ude. Mid UrboBond 26/20 2.M 30 6260 6,221 148 162 ]2520 1900 1.M LM 2.25 20o 2S.M 0.50 1.00 All .d8® 73 ESp DrAWFrac140 am ant ad- nmd bNOB0nd 16/20 3.M 30 6,340 6,275 149 170 19,020 19 IN 1M 2.25 200 ]5.00 0.50 1.M )4 358 DNbirao 140 Promom U. fluid Urbobnd l6 E0 q.[0 30 ) 6968 166 196 28,M0 28 iM LM 2.25 200 5500 0.50 1.00 75 2540N1apx 240 hen enc Udm fluid Carb.Bond l6/E0 SIM 30 )MO ] 75 Am 20) 351MO 36,100 LPo 1.00 235 200 25.M ON 1.M O.Ea 76 258 pMain<140 Pm ant Uden iluld U2obntl 16 E0 6.M 30 4150 185)5 42 SE4 255M 83 LM IM 2.25 200 25.00 QSO 1.00 O.IS )] 358WdWiFrmG Fluab 30 2355 2548 61 61 1.M 1.00 25.00 0.50 IM 0.15 EB Wf-200 Slwcln 2600 1.680 40 40 proppanlrype Camien Tmalpba) GI<ulamd Tatal(ru) Taket Tea,"ba) cl-oMrd 16/20 157.BM J55,- J55,0.tl •' 1Fs numhers fw propMnt dre 2ehenJiom wf(wore mlcu2p4nru bpuam munlpM w.ipbks •'prpPPdntu hilledl Weight Ticket troluma9 Repsol E P - Qugruk 301 Actual Design c -Web Law Of D 84140 CaLW LTC4 WG -36 GBWdp Optako.11 B66 (sell fee) (sea faM) fuel fabs (1051 INUM DeOp Material Volume 2913 391.3 639.5 4)00 7.2819 145.6 2913 4ba M1ual Dealgn Mated.1 ueWme 31].8 31].8 688.0 sue, 79453 158.9 3128 376 Ph,kal Malarial Volume Pumped 31a 340 )26 515 7910 140 310 54 PhWiral Mmedal Volume Imeante 5% ]% 6% 2% 6% -]2% .E% 43% WumModm Volume PumPad 2912 N9 13] q)9 za918 t50 321 912 MIrWaotram Volume DlNan<e A% ]% ]% .5% 1 2% 1% Repsol E P -Qugruk 301 Interval Summary 6 Interval Summary Qugruk 301 - Nanashuk A & 8 - Interval 1 Interval Summary Date: 3/27/2015 Start Time: 11:07:00 AM End Time: 12:52:00 PM Initial Rate (Breakdown): 9.1 bpm Initial Pressure (Breakdown): 1980 psi Max Rate: 30.2 bpm Max Pressure: 4813 psi Max Pressure (SLF): 4813 psi Average Rate: 29.9 bpm Average Pressure: 3886 psi Average Pad ROC Gauge Pressure: 3512 psi Average ROC Gauge Pressure: 3744 psi Max Annulus Pressure: 2257 psi Max Bottomhole Pressure: 4057 psi Average Visc: 17 CP Average Temp: 113 F Average pH: 8.3 ISIP: 1076 psi Initial Fracture Gradient: 0.705 psfft 5 min: 1028 psi 10 min: 1013 psi 15 min: 1005 psi Proppant Summary CarboBond 16/20 Pumped 106,500 lbs Calculated Proppant Pumped" : 106,500 lbs Proppant in Formation: 106,500 lbs Fluid Summary (by fluid description) 25# WaterFrac G Volume 4,920 gal 117 bbls 25# DeltaFrac 140 Volume 61,902 gal 1,474 bills LVT-200 Volume 4,998 gal 119 bbls Treatment Volume: 71,820 gal 1,710 bbls Total Fluid Volume: 71,820 gal 1,710 bbls Interval Status: Completed Comments: Pumped DFIT and watched well for several hours. Decided to then pump 120 bbl Engineer: Saltrusch & Van Zyl crosslinked minifrac. Could not get crosslinked sample to the van, even though it was Treater: Michael Osborn crossed for the majority of the load stage. Ended up pumping 180 bbls of crosslinked Supervisor: Marcos Adan 'rom software calculations based on multiple variables. i ticket volumes. Customer Rep: David Ross Repsol E P -Qugruk 301 Interval Summary 6 Qugruk 301 - Nanashuk A & 8 - Interval 2 Interval Summary Date: 3/27/2015 Start Time: 12:52:00 PM 112,050 End Time: 1:35:00 PM Max Rate: 30.0 bpm Max Pressure: 4146 psi Max Pressure (SLF): 3979 psi Average Rate: 29.9 bpm Average Pressure: 3145 psi Average Pad ROC Gauge Pressure: 3644 psi Average ROC Gauge Pressure: 3741 psi Max Annulus Pressure: 2310 psi Max Bottomhole Pressure: 4110 psi Average Visc: 17 cP Average Temp: 113 F Average pH: 8.3 Proppant Summary CarboBond 16/20 Pumped 112,050 lbs Calculated Proppant Pumped' : 112,050 lbs Proppant in Formation: 112,050 lbs Fluid Summary (by fluid description) 25# WaterFrac G Volume 1,269 gal 30 bbls 25# DeltaFrac 140 Volume 47,096 gal 1,121 bbls LVT-200 Volume 0 gal 0 bbls Treatment Volume: 48,365 gal 1,152 bbls Total Fluid Volume: 48,365 gal 1,152 bbls Interval Status: Completed Lone 2 Ball hit 55 bbls late with a pressure differential of 995 psi. Higher proppant Engineer. Baltrusch & Van Zyl concentrations were approximately .5 ppg light: which was discovered towards the end of Treater: Michael Osborn the job. Supervisor.. Marcos Adan 'Values for prappant are taken from software calculations based on multiple variables. Proppant is billed oft of weight ticket volumes. Customer Rep: David Ross Repsol E P - Qugruk 301 Interval Summary 7 WJFr,Milii:' W 4FZM Date: 3/ZI/2015 Start Time: 1:35:00 PM End Time: 2:26:00 PM Max Rate: 30.6 bpm Max Pressure: 4285 psi Max Pressure (SLF): 3897 psi Average Rate: 30.0 bpm Average Pressure: 3094 psi Average Pad ROC Gauge Pressure: 3475 psi Average ROC Gauge Pressure: 3605 psi Max Annulus Pressure: 2214 psi Max Bottomhole Pressure: 3656 psi Average Vise: 17 cP Average Temp: 114 F Average pH: 8.3 Proppant Summary CarboBond 16/20 Pumped 114,650 lbs Calculated Proppant Pumped' : 114,650 lbs Proppant in Formation: 114,650 lbs Fluid Summary (by fluid description) 25# WaterFrac G Volume 1,262 gal 25# DeltaFrac 140 Volume 46,193 gal LVT-200 Volume 0 gal Treatment Volume: Total Fluid Volume: Interval Status: 47,455 gal 47,455 gal Completed 30 bbls 1,100 bbls 0 bbls 1,130 bbls 1,130 bbls um not see call action on zone 3; original estimation or seat was Dail pumper coming engineer. Baltrusch & Van Zyl offline. Estimated that ball set while rate was increasing and chose a point there. Higher Treater. Michael Osborn sand concentrations were approximately .5 ppg light; which was discovered towards the Supervisor. Marcos Adan end of the job. 'Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes. Customer Rep: David Ross Repsol E P - Qugruk 301 Interval Summary 8 - Nanashuk A 8 B - Date: 3/27/2015 Start Time: 2:26:00 PM End Time: 3:11:00 PM Max Rate: 30.1 bpm Max Pressure: 4292 psi Max Pressure (SLF): 4048 psi Average Rate: 29.8 bpm Average Pressure: 3289 psi Average Pad ROC Gauge Pressure: 3464 psi Average ROC Gauge Pressure: 3560 psi Max Annulus Pressure: 2065 psi Max Bottomhole Pressure: 3837 psi Average Visc: 17 CP Average Temp: 114 F Average pH: 8.3 gal Proppant Summary CarboBond 16/20 Pumped 115,600 lbs Calculated Proppant Pumped' : 115,600 lbs Proppant in Formation: 115,600 lbs Fluid Summary (by fluid description) 25# WaterFrac G Volume 1,222 gal 29 bb/s 25# DeltaFrac 140 Volume 46,065 gal 1,097 bbls LVT-200 Volume 0 gal 0 bbls Treatment Volume: 47,287 gal 1,126 bb/s Total Fluid Volume: 47,287 gal 1,126 bills Interval Status: Completed nit 5U Dots late virm a pressure differential or 425 psi. Upper Sand concentral approximately .25 ppg light: which was discovered towards the end of the job. for proppanl are taken from software calculations based on multiple variables. I is billed off of weight ticket volumes. Treater: Michael Osborn Supervisor: Marcos Adan Ross Repsol E P - Qugruk 301 Interval Summary 9 - Nanashuk A & 8 - Interval Summary Date: 3/27/2015 Start Time: 3:11:00 PM End Time: 3:58:00 PM Max Rate: 31.0 bpm Max Pressure: 3566 psi Max Pressure (SLF): 3490 psi Average Rate: 29.8 bpm Average Pressure: 2974 psi Average Pad ROC Gauge Pressure: 3287 psi Average ROC Gauge Pressure: 3475 psi Max Annulus Pressure: 2203 psi Max Bottomhole Pressure: 3705 psi Average Visc: 17 cp Average Temp: 115 F Average pH: 8.3 gal Proppant Summary CarboBond 16/20 Pumped 118,000 lbs Treater.' Michael Osborn Calculated Proppant Pumped' : 118,000 lbs Proppant is billed off of weight ticket volumes. Customer Rep: David Ross Proppant in Formation: 118,000 lbs Fluid Summary (by fluid description) 25# WaterFrac G Volume 369 gal 9 bbls 25# DeltaFrac 140 Volume 45,760 gal 1,090 bbls LVT-200 Volume 0 gal 0 bbls Treatment Volume: 46,129 gal 1,098 bbls Total Fluid Volume: 46,129 gal 1,098 bbls Interval Status: Completed frau O nit iu Dols late with a pressure allterential Of b41 psi. Higher proppant Engineer.Baltmsch & Van Zyl concentrations were a bit light on sand. Treater.' Michael Osborn Supervisor: Marcos Adan 'Values for proppanl are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes. Customer Rep: David Ross Repsol E P-Qugruk 301 Interval Summary 10 Qugruk 301 - Nanashuk A 8 8 - Interval 6 Interval Summary Date: 3/27/2015 Start Time: 3:58:00 PM End Time: 5:00:00 PM Max Rate: 30.5 bpm Max Pressure: 4347 psi Max Pressure (SLF): 4347 psi Average Rate: 29.8 bpm Average Pressure: 3386 psi Average Pad ROC Gauge Pressure: 3132 psi Average ROC Gauge Pressure: 3333 psi Max Annulus Pressure: 2129 psi Max Bottomhole Pressure: 3503 psi Average Visc: 17 cP Average Temp: 115 F Average pH: 8.3 ISDP: 912 psi Final Fracture Gradient: 0.666 psi/tt 5 min: 886 psi 10 min: 879 psi 15 min: 872 psi Proppant Summary CarboBond 16/20 Pumped 188,200 lbs Calculated Proppant Pumped* : 188,200 lbs Proppant in Formation: 188,200 lbs Fluid Summary (by fluid description) 25# WaterFrac G Volume 2,548 gal 61 bbls 25# DeltaFrac 140 Volume 59,207 gal 1,410 bbls LVT-200 Volume 1,680 gal 40 bbls Treatment Volume: 63,435 gal 1,510 bills Total Fluid Volume: 63,435 gal 1,510 bbls Interval Status: Completed Comments: Ball 6 hit 15 bbls late with a pressure differential of -211 psi. Got a sand divot while trying Engineer. Baltrusch & Van Zyl to swap movers; did not continue job. Extra proppant had been delivered to location and Treater. Michael Osborn put in the movers; left approximately 45000 lbs of proppant in the mover. Supervisor: Marcos Adan 'Values for proppam are taken from software calculations based on multiple variables. Proppant is billed off of weight ficket volumes. Customer Rep.' David Ross Repsol E P - Qugruk 301 Interval Summary 11 customer Repsol 8&P Famnation Nanasbuk A & B tease Qugruk 301 HALL113URTON AN 50.103-20Jo0 Date March 27. 2015 Stage Summaries Planned Recorded "• PmppaM iz billed ham WeigMTickat volumes Repsol F P - Qugruk 301 Well Summary 12 Average Max a ESp WterFa<6 De ESN ItaFm 140 c LVT�20p Total Fluid roppa CarboBlbt 16/20 To Total Pmppant Interval Pressure Adte Visc Tem pH Pressure 0.ate gal bbl gal bbl al bbl gal bbl lbs lbs 1 3886 29.9 1] 113 8.3 4813 30.2 4,920 ill 61,902 1.4]4 4,998 119 ]1,820 1,710 306,So0 106,500 2 3145 29.9 1] 113 8.3 4146 30.0 12fi9 30 4),096 1,121 0 0 48,365 1152 112,050 112,050 3 3094 30.0 1J 114 8.3 4285 30.6 1,262 30 46,193 1,100 0 0 4),455 1,130 114,650 114,650 4 3289 29.8 1] 134 8.3 4292 30.1 1,222 29 46,065 1,097 0 0 4),28) 1US 115,600 115,600 5 2974 29.8 17 115 8.3 3566 31.0 369 9 45,760 1,090 0 0 46,129 1,098 118,W0 118,000 6 3386 29.8 17 115 8.3 4347 30.5 2,548 61 59.2oJ 1,410 1,680 b 63,435 1,510 18$200 188;200 Planned Recorded "• PmppaM iz billed ham WeigMTickat volumes Repsol F P - Qugruk 301 Well Summary 12 Zone I DFIT Treatment Plot Treating Pressure (prig) A Annulus Pressure (psi) A Slurry Rate (bpm) B Slurry Proppant Cone (Ib/gal) C BH Proppant Cone (lb/gal) C Actual Bottomhole Pr (psi) A Actual Bottomhole Temp ff) E C E 13:30 13:40 13:50 14:00 14:10 3/26/2015 3/26/2015 700 100 Repsol E P - Qugruk 301 Interval 1 Plots 13 A B Zone 1 Mini Frac Treatment Plot Treating Pressure (prig) A Annulus Pressure (psi) A Slurry Rate (bpm) B Slurry Proppant Cone (lb/gal) C BH Proppant Cone (lb/gal) C Actual Bottomhole Pr (psi) A Actual Bottomhole Temn (OM F. C 22:20 22:25 2230 22:35 22:40 22:45 3/26/2011 Time lnbnols E 1000 700 We Repsol E P - Qugruk 301 Interval 1 Plots 14 n Zone 1 Treatment Plot Treating Pressure (prig) A Annulus Pressure (psi) A Slurry Rate (bpm) B Slurry Proppant Cone (lb/gal) C BH Proppant Cone (lb/gal) C Actual Bottomhole Pr (psi) A Actual Bottomhole Temp (°F) E Le 11:20 11:40 12:00 12:20 12:40 3/27/2015 3/27/2015 Titre E 1000 KI Repsol E P - Qugruk 301 Interval 1 Plots 15 Zone 1 Chemical Plot DFIT & MiniFrac WG -36 Conc (Ib/Mgal)— A LO8URF-300- Conc (gal/Mgal) B CLA-Web Conc (gal/Mgal) B BC -140 Conc (gal/Mgal) B CarboBond LTCA Conc (gal/Mgal)B Optiflo II Conc (Ib/Mgal) B A u -I w, 19:3u 20:00 20:30 21:00 21:30 22:00 22:30 3/26/2015 3/26/2015 Time Customer: REPSOL E&P USA INC Job Date: 26 -Mar -2015 Sales Order#: 902241142 Well Description: Qugruk 301 Uw* 50-103-20700 Repsol E P- Qugruk 301 Interval l Plots 16 Zone 1 Chemical Plot WG -36 Conc (Ib/Mgal) A LOSURF-300D Conc (gal/Mgal) B CLA-Web Conc (gal/Mgal) B BC -140 Conc (gal/Mgal) B A CarboBond LTCA Conc (gal/Mgal) B Optiflo II Conc (Ib/Mgal) B 0 11:20 11:40 12:00 12:20 12:40 3/27/2015 3/27/2015 Time Customer: REPSOL E&P USA INC Job Date: 26 -Mar -2015 Sales Order#: 902241142 Well Description: Qugruk 301 UM: 50-103-20700 Repsol E P - Qugruk 301 Interval 1 Plots 17 Zone 1 Net Pressure Plot Net Gauge BH Pres (psi) A Time NetPr BPC Slope —BH Proppant Conc (Ib/gal) B U1295.55 129.2 0.185 -2.700 A Slope of Net Pressure (psi/min) C B Customer: REPSOL E&P USA INC Well Description: Qugruk301 Time (min) Job Date: 26 -Mar -2015 U WI: 50-103-20700 Sales Order#: 902241142 Repsol E P - Qugruk.301 Interval 1 Plots 19 A B 1 Zone 2 Treatment Plot Treating Pressure (psig) A Annulus Pressure (psi) A Slurry Rate (bpm) B Slurry Proppant Cone (lb/gal) C BH Proppant Cone (lb/gal) C Actual Bottomhole Pr (psi) A Actual Bottomhole Temp (°F) E Ce 13:00 13:10 13:20 13:30 3/27/2015 3/27/2015 Time E 1000 900 800 700 600 500 400 300 200 100 0 Repsol E P - Qugruk 301 Interval 2 Plots 19 Zone 2 Chemical Plot WG -36 Conc (Ib/Mgal) A LOSURF-300D Conc (g: CLA-Web Conc (gal/Mgal) B BC -140 Conc (gal/Mgal) CarboBond LTCA Conc (gal/Mgal) B Optiflo II Conc (Ib/Mgal) A A 12:50 13:00 13:10 13:20 13:30 3/27/2015 3/27/2015 Time Customer: REPSOL E&P USA INC Job Date: 26 -Mar -2015 Sales Order#: 902241142 Well Description: Qugruk301 UWI: 50-103-20700 Repsol E P - Qugruk 301 Interval 2 Plots 20 Zone 2 Net [��B,H Net Gauge BH Pres (psi) A Proppant Conc (Ib/gal) B A Sope of Net Pressure (psi/min) C Pressure Plot Time NetPr BPC Slope 1295.55 128.7 0.185 -2.953 B Time (min) Customer: REPSOL E&P USA INC Job Date: 26 -Mar -2015 Sales Order#: 902241142 Well Description: Qugruk301 UW1, 50-103-20700 Repsol E P - Qugruk 301 Interval 2 Plots 21 A 100 0 Zone 3 Treatment Plot Treating Pressure (psig) A Annulus Pressure (psi) A Slurry Rate (bpm) B Slurry Proppant Conc (Ib/gal) C BH Proppant Conc (lb/gal) C Actual Bottomhole Pr (psi) A Actual Bottomhole Temp (°F) E C 13:40 13:50 14:00 14:10 14:20 3/27/2015 3/27/2015 Time E 1000 700 200 100 Repsol E P - Qugruk 301 Interval 3 Plots 22 U Zone 3 Chemical Plot WG -36 Conc (Ib/Mgal) A LOSURF-300D Conc (gal/Mgal) B CLA-Web Conc (gal/Mgal) B BC -140 Conc (gal/MgaI)B CarboBond LTCA Conc (gal/Mgal) B Optiflo II Conc (Ib/Mgal) B W 13:40 13:50 14:00 14:10 14:20 3/27/2015 3/27/2015 Time Customer: REPSOL E&P USA INC Job Date: 26 -Mar -2015 Sales Order#: 902241142 Well Description: Qugruk301 UWI: 50-103-20700 Repsol E P - Qugruk 301 Interval 3 Plots 23 Zone 3 Net Pressure Plot —Net Gauge BH Pres (psi) A Time NetPr BPC Slope —BH Proppant Conc (Ib/gal) B _1', 1295.55 128.1 0.185 -3.297 A Slope of Net Pressure (psi/min) C B Time (min) Customer: REPSOL E&P USA INC Job Date: 26 -Mar -2015 Sales Order#: 902241142 Well Description: Qugruk301 UN: 50-103-20700 Repsol E P - Qugruk 301 Interval 3 Plots 24 A B 10007 121 '111 1 111 9111IE<! 111 1 1.11 21 000- 0- 1 Zone 4 Treatment Plot Treating Pressure (psig) Annulus Pressure (psi) Slurry Rate (bpm) Slurry Proppant Conc (lb/gal) BH Proppant Conc (lb/gal) Actual Bottomhole Pr (psi) Actual Bottomhole Temp (°F) A A B C C A E I I I I P- 14:30 14:40 14:50 3/27/2015 Time 15:00 15:10 3/27@015 C E 20 1000 18 900 16 800 14 700 12 600 10 500 8 400 6 300 4 200 2 100 D 0 Repsol E P - Qugruk 301 Interval 4 Plots 25 Zone 4 Chemical Plot WG -36 Cone (Ib/Mgal) A LOSURF-300D Conc (gal/Mgal) B CLA-Web Cone (gal/Mgal) B BC -140 Conc (gal/MgaI)B CarboBond LTCA Cone (gal/Mgal) B Optiflo II Cone (Ib/Mgal) B 0 Q 14:30 1440 14:50 1500 15:10 3/27/2015 3/27/2015 Time Customer: REPSOL E&P USA INC Job Date: 26 -Mar -2015 Sales Order#: 902241142 Weil Description: Qugruk301 UVN: 50-103-20700 Repsol E P - Qugruk 301 Interval 4 Plots 26 Zone 4 Net Pressure Plot Net Gauge BH Pres (psi) A Time NetPr BPC Slope —BH Proppant Conc (Ib/gal) B 1295.55 124.9 0.185 -2.214 A Slope of Net Pressure (psi/min) C B Time (min) Customer REPSOL E&P USA INC Job Date: 26 -Mar -2015 Sales Order#: 902241142 Well Description: Qugruk301 UWI: 50-103-20700 0 8 6 4 2 0 Repsol E P - Qugruk 301 Interval 4 Plots 27 0 O Zone 5 Treatment Plot Treating Pressure (psig) A Annulus Pressure (psi) A Slurry Rate (bpm) B Slurry Proppant Conc (lb/gal) C BH Proppant Conc (lb/gal) C Actual Bottomhole Pr (psi) A Actual Bottomhole Temp (°F) E C 15:10 1520 15:30 15:40 15:50 3/27/2015 3/27/2015 Time E 1000 700 M• Repsol E P - Qugruk 301 Interval 5 Plots 28 vvw-ib conc po/uaga0 CLA-Web Conc (gal/Mgal) CarboBond LTCA Conc (gal/Mgal) U Zone 5 Chemical Plot B BC -140 Conc (gal/Mgal) B Optiflo II Conc (Ib/Mgal) IV 15:10 15:20 15:30 15:40 15:50 16:00 3/27/2015 3/27/2015 Time Customer: REPSOL E&P USA INC Job Date: 26 -Mar -2015 Sales Order #: 902241142 Well Description: Qugruk 301 UWI: 50-103-20700 Repsol E P - Qugruk 301 Interval 5 Plots 29 Zone 5 Net Pressure Plot —Net Gauge BH Pres (psi) A Time NetPr BPC Slope — BH Proppant Conc (Ib/gal) B 1 1295.55 124.3 0.185 -2.493 A Slope of Net Pressure (psi/min) C B Time (min) Customer: REPSOL E&P USA INC Job Date: 26 -Mar -2015 Sales Order#: 902241142 Well Description: Qugruk 301 UWI: 50-103-20700 Repsol E P - Qugruk 301 Interval 5 Plots 30 A 1001 Zone 6 Treatment Plot Treating Pressure (psig) A Annulus Pressure (psi) A Slurry Rate (bpm) B Slurry Proppant Cone (lb/gal) C BH Proppant Cone (lb/gal) C Actual Bottomhole Pr (psi) A M C E x1000 16:00 16:10 1620 16:30 16:40 16:50 17:00 17:10 17:20 3/27/2015 3/27/2015 Time 700 100 Repsol E P - Qugruk 301 Interval 6 Plots 31 Zone 6 Chemical Plot CLA-Web Conc (gal/Mgal) B BC -140 Conc (gal/Mgal) B CarboBond LTCA Conc (gal/Mgal) B Optiflo II Conc (Ib/Mgal) B A 16:00 16:10 16:20 16:30 1640 16:50 17:00 3/27/2015 Time 3/27/2015 Customer: REPSOL E&P USA INC Job Date: 26 -Mar -2015 I Sales Order* 902241142 Well Description: Qugruk 301 UW: 50-103-20700 Repsol E P - Qugruk 301 Interval 6 Plots 32 1 Zone 6 Net Pressure Plot Net Gauge BH Pres (psi) A Time NetPr BPC Slope —BH Proppant Conc (Ib/gal) B 01 935.55 130.0 0.185 -0.434 A Slope of Net Pressure (psi/min) C 1 10 Time (min) Customer: REPSOL E&P USAINC Job Date: 26 -Mar -2015 Sales Order#: 902241142 Well Description: Qugruk 301 UWI: 50-103-20700 Repsol E P - Qugruk 301 Interval 6 Plots 33 xepml tl-Qalk 305 Wmmennsummary Pumped DFIT and watched well for several hour. Decided to then pump 110 bbl crosslinked minifrac. Could not get crosslir l ed sample to the van, even though It was crossed for the majority of the load stage. Ended up InterealI pumping 180 bills ofcrosslinked fluid. Attempted to pump LW at the end of flush; but lost rate and it Fluctuated some before coming offline. During main frac, did not see initial sleeve shift; shut down to inspect. Completed Comments p 8 pp HPr Pp 8 P PP PPrpxi Y, PP8 8 Resumed pumping and saw it shift Pro ant was not showing operlY swapped to the inline densometer; which read closer. Higher ro ant concentrations werea mates 5 light; which was discoveredAs Zone 2 Ball hlt55 bblslate with a pressurediferentlal of995 psi. Higher proppant concentrations were approximately.5 ppg light; which was discovered towards the end of the job. Imperial 2 Completed Comments Did not see ball action on zone 3; original estimation of seat was ball pumper coming offline. Estimated that ball set while rate was increasing and chose a point there. Higher sand concentrations were approximately .5 Irtereal3 not light; which was discovered towards the end of the job. Completed Comments Ball a hit 50 hiss late with a pressure differential of 825 psi. Upper sand concentrations were apprmssmately.25 ppg light which was discovered towards the end of the job. Interval/ Completed Comments Ball 5 hit 10 bbls late with a pressure differential of 601 psi. Higher proppant concentrations were a bit light on sand. Intervals Completed Comments xepml tl-Qalk 305 Wmmennsummary CUSTOMER Repsol E&P API 54103-20100 BED ObIVI) 850 LAT 11250 30 30 0:01:00 0:01:00 1.00 1.00 LEASE Qugmk 301 SALES ORDER 9022411@ 0.50 BNST('F) 110 LONG -:^NALLIOURYON � w 30 2,480 59 FORMATION Nanas6uk A & B DATE 3/27/35 Max Pressure(psi) 60D0 1.00 I 25.00 Liquid Additives 1.00 0:15 Dry Additives 254 DeltaFrac 140 5 acer Prop Slurry Clean Clean Slurry Prop Stage Interval Cla-Web Losurr-MODII BC -140 CarboBond-LTCA WG -36 GBW-30 Opfflo41 BEL Treatment Stage Fluid Stage Proppant C,nc Rate I I Volume Volume Volume Total Time Time dv mnual wdawam Omdmer rmPArl:eam. Ga ereaxa Nvker cxo Interval Number DeaCdpdm Description Description (009) (bpm) (gal) (bb0 (bbl) (Ib4J (hh:mmss) (hh:mmss) _ (9ptf (9P0 l9P0 (900 (PPf) (roti (PPO !Pial i� 3o 18 254WaterFracG Spacer&Ball Drpp 30 11250 30 30 0:01:00 0:01:00 1.00 1.00 25.OD 0.50 100 39 254 DeltaFrac 140 Dls lace.,,! 30 2,480 59 59 0:01:58 0:42:28 1.00 1.00 25.00 0.50 1.00 0:15 20 254 DeltaFrac 140 5 acer 12 610 15 15 0:01:13 0:40:30 1.00 1.00 25.00 0.50 1.00 0.15 21 254 DeltaFrac 140 Pad 30 2,900 69 69 0:02:18 0:39:1] 1.00 1.00 25.00 0.50 1.00 0.15 22 254 DeltaFrac 140 Proppant Laden Fluid Carbo8ond 16/20E4.00 30 4,120 98 100 2,060 0:03:21 0:36:59 100 1.00 2.00 25.00 0.50 1.00 0.15 23 250 DeltaFrac 140 P roppant Laden Fluid CarboBond 16L20 30 4,200 100 105 4,200 0:03:29 0:33.38 1.00 1.00 N2.25 2.00 25.00 0.50 1.00 0.15 24 254 DeltaFrac 140 Pro ant Laden Fluid Caftli.nd 1620 30 6,260 149 163 12,520 0:05:25 0:30:09 1.00 1.00 2.00 25.00 0.50 1.00 0.15 25 254 DeltaFrac 140 Propant Laden Fluid C,,WBond 16/20 30 6,340 151 172 19,020 0:05:43 0:24:44 1.00 1.00 2.00 25.00 0.50 1.00 0.15 26 254 DeltaFrac 140 Pro ant Laden Fluitl CarboBond 16/20 30 ],000 167 197 28,000 0:06:34 0:19:01 1.00 1.00 2.00 25.00 (SO 100 0.15 2] 254 DeltaFrac 140 Pro ant Laden Fluid CarboBO,d 16/20 30 )000 16] 205 3S 00 0:06:49 0:12:2] 100 1.00 2.00 25.00 0.50 1.00 0.15 28 254 DeltaFrac 140 Pro pant Laden Fluid CarboBand 16/20 30 4,250 101 129 25,500 0:04:18 0:05:3] 1.00 1.00 2.25 2.00 25.00 0.50 1.0 0.15 29 2W Dxel aFrac 140 Sacer 30 420 10 10 0:00:20 0:01:20 1.00 1.00 2.25 25.00 0.50 1.00 0.15 30 2"WaterFracG Spacer&Ball Oro, 30 1,250 30 30 0:01:00 0:01:00 1.00 1.00 25.00 0.50 1.00 0.15 31 254 DeltaFrac 140 Displacement 30 2,250 54 54 0:01:4) 0:42:26 1.00 1.00 2.25 2500 0.50 1.00 0.15 32 254 DehaFrac 160 Sacer 12 610 15 15 0:01:13 0:40:39 -I'm 1.00 2.25 25.00 0.50 1.00 0.15 33 254 DeltaFrac 140 Pad 30 3,100 74 74 0:02:28 0:39:2] 1.00 1.00 2.25 25.00 0.50 1.00 OAS 34 254 DeltaFrac 140 Pr.,,.t Laden Fluid Carb,B„d 1620 0.50 30 4,120 98 100 2060 0:03:21 0:36:59 1.00 1.00 225 2.00 25.00 0.50 100 0.15 35 254 DeltaFrac 140 Pro nt Laden Fluid Caftisond 16/20 1.00 30 4,200 100 105 4,200 0:03:29 0:33:38 1.00 1.00 2.25 2.00 25.00 0.50 1.00 0.15 36 254 DeltaFrac 140 Pro ant Laden Fluid CarboBond 16/20 2.00 30 6,260 149 163 12,520 0:05:25 0:30:09 1.00 1.00 2.25 2.00 25.00 0.50 1.00 0.15 37 254De1taFrac 140 Pro nt Laden Fluid CarboBand 1620 300 30 6,340 151 172 19,020 0:05:43 0:24;4 1.00 1.00 2.25 2.00 25.00 0.50 1.00 0.15 1.00 Repsol E P - Qugruk 301 Planned Design 35 CUSTOMER Repsol E&P LEASE Ougrvk 301 FORMATION Nanashuk A&0 API 50-103.207W RFD(Ib/gal) 858 SALES ORDER 902241142 BHST(4) 110 LONG d HALLIBILIRTON DATE 3/1 / 5 MaxPrIl (p i) 5000 I liauid Additives DryAdditives 1 I I Proppant Type Tmal(Ibs) CarboBontl 16/20 ]5],800 R9tYDU1 CL -Web LosuA-3000 BC -14O CarboBontl-LTC: WG -36 GBW-30 OptiFlo-ll BEfi (901) (al) (gm) (gal) lbs lbs I lbs I lbs Initial Design Material V.1adual 291.3 1 291.3 1 629.5 1 470.0 17,291.91 145.6 1 291.3 1 40.8 Max Additive Rale Min Additive Rate Cl. -Web LPsud-3000BC-140 CarboB.md-LTC: WG -36 Prop Slurry Clean Clean Slurry Prop Stage interval as-weo Losup-ww ps.-ora u�womm-u... ..,.-�r. 2.8 1 2.5 1 31.5 1.3 1.3 Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time Time Oar Wmml wdaaam acssliµer PAP Aaivamr Gra weaker maw Nooee Treatment Stage (bbp (Iba) @h:mm:as) (Mr..ff) (pot) (Wal (got) (got) (pP0 (Part) (PPt) (PPt) Interval Number Description Description Description (Mg) (bpm) (gal) (6611 3,570 85 85 0:02:50 0:39:49 1.00 1.00 2.25 25 00 0.50 100 0.15 57 2511 DeltaFrac 140 Pad 30 air 58 25a DeltaFrac 140 Pro nt Dden Fluid CarboBpnd 16/20 0.50 30 4,120 98 100 2,060 0:03:21 0:36:59 1.00 1.00 225 200 25.00 050 1.00 0.15 'a 'n 59 25g DeltaFrac 140 pro Pant Laden Fluid CarboBontl 1620 1.00 30 4,200 100 105 4,200 0:03:29 0:33:38 IN 1.00 2.25 2.00 25.00 0.50 1.00 0.15 �Qu 60 25g DeltaFrac 140 Pro ant Laden Fluid CarboBond 16/20 2.00 30 6,260 149 163 12,520 0:05:25 0:30:09 1.00 1.00 2.25 2.00 25.00 0.50 1.00 0.15 Z 25o DeltaFrac 140 Pro nt Laden Fluid CarboBond 1620 3.00 30 6,340 151 172 19,020 0:05:3 0:24.4 1.00 1.00 2.25 2.00 2500 0.50 1.00 0.15 �xc _lar 61 25a DeltaFrac 140 Propant Laden Fluid Carboil 36/20 4.00 30 7,000 167 197 28000 0:06:34 0:19:01 1.00 1.110 225 2.00 25.00 0.50 1.00 0.15 62 63 25110eltaFmc 140 Pro ant Laden Flurd CarwBond 16/20 5.00 30 J000 167 205 35,000 0:06:49 0:12:27 1.00 1.00 2.25 2.00 2500 0.50 1.00 0.15 64 2511 DeltaFrac 140 Pro ant Laden Fluid CarboBond 1620 6.00 30 41250 101 129 25,500 0:04:18 0:05:37 1.00 3A0 2.25 200 25.00 0.50 SAO 0.15 Spacer 30 420 30 10 0:00:20 0:01:20 1.00 1.00 2.25 25 DO 0.50 1.00 0.15 65 ZSa DehaFrac 140 30 30 0:01:00 0:01:00 1.00 1.00 25.00 0.50 3.00 0.15 66 25k waterFracG Spacer&Ball Drop 30 1,250 67 2511 DeltaFrac 140 Displacement 30 L596 38 38 0:01:16 0:3:00 1.00 1.00 2.25 25100 0.50 1.00 0.15 68 250 DeltaFrac 140 Spacer 12 610 15 15 0:01:13 DAL44 1.00 1.00 2.25 25.00 0.5B 1.00 0.15 69 2W DehaFrac 140 Pad 30 3,780 90 90 0:03:00 0:40:32 1.W 1.00 2.2S 25.00 0.50 1.00 0.15 m 70 2SI1 DeltaFrac 140 Pro ant Laden Fluid Carbo fond 36/20 0.50 30 4,120 98 100 2060 0:03:21 0:37:32 1.00 1.00 2.25 2.00 25.00 0.50 1.00 0.15 x, rov mQr 71 2511 DeltaFrac 140 Proant Orion Fluid CarboBond 16/20 1.00 30 4,200 100 105 200 003:29 0:34:11 1.00 1.00 2.25 2.00 25.00 0.50 100 0.1` 2 n 72 2511 DekaFrac 140 Propont Laden Fluid CarboBond 16 20 2.00 30 fi 260 149 163 12 520 0:0525 0:30:42 1.00 1.00 2.25 2.00 2500 0.50 1.00 0.. Fluid CarboBond16/20 3.00 30 6340 151 172 19 20 0:05:43 0:25:17 1.00 1.00 2.25 2.00 25.00 O.SD 1.08 O.1S cid J3 ]4 25h De1GFrac 140 2511 DeltaFrac 140 Pro nt Laden vto ant Laden Flultl CarboBontl 16/20 4.00 30 7000 167 19] 28000 00634 0:19:33 1.00 1.00 2.25 2.00 25.00 0.50 100 0.15 75 2W DeBafra<IQ Pro ant Latlen Fluitl CarboBpnd 1620 5.00 30 7,000 167 205 35,000 0:06:49 0:12:59 1.00 1.00 2.25 ?0 25.00 0.50 1.00 11.15 76 25a DehdHac 340 Proppant Laden Fluid CarbpBontl 16/20 6.08 30 4250 101 129 25,500 0:04:18 0:06:10 1.00 1.00 2.25 2.80 25.00 DSO 1.08 0.15 77 'Be WaterfracG Flush 30 355 56 56 0:01:52 0:01:52 1.00 1.00 25.00 0.58 1.00 0.15 78 LVF -200 Shut -In 11,680 •n�nn�r 40 nua 40 ♦arc icl 0.fN1 dPR1n Proppant Type Tmal(Ibs) CarboBontl 16/20 ]5],800 R9tYDU1 CL -Web LosuA-3000 BC -14O CarboBontl-LTC: WG -36 GBW-30 OptiFlo-ll BEfi (901) (al) (gm) (gal) lbs lbs I lbs I lbs Initial Design Material V.1adual 291.3 1 291.3 1 629.5 1 470.0 17,291.91 145.6 1 291.3 1 40.8 Max Additive Rale Min Additive Rate Cl. -Web LPsud-3000BC-140 CarboB.md-LTC: WG -36 GBW-30 Cool BE -6 ( Pm) (Pm (Pm) (Pm) 'm Ppm PPm PPm 1.3 13 2.8 1 2.5 1 31.5 1.3 1.3 O2 0.4 0.4 0.9 1 0.8 1 10.5 0.2 0.4 0.1 Repsol E P - Qugruk 301 Planned Design 36 Date: 24-Mar-2015 Well Name: Qugruk 301 Company: Repsol E&P USA Inc. API Number: 50-103-20700-00-00 AFE Number: NS_14_004 Field: North Slope Rig: Nabors 105AC Drilling & Measurements 6411 A Street Anchorage AK 99518 Tel (907) 273-1700 Fax (907) 561-8317 Date: 24-Mar-2015 Well Name: Qugruk 301 Company: Repsol E&P US Inc. API Number: 50-103-20700-00-00 AFE Number: NS_14_004 Location: N 412954 ft US, E 5972299 ft Field: North Slope Rig: Nabors 105AC Drilling and Measurements Field Support: Operations Manager, Ankur Prakash Field Service Manager, Joseph Leblanc Drilling and Measurements Field Crew: Cell Manager, Milena Kalimullina Kyle Antonini Cell Engineer, Caitlin Schnitzer Jeff Ryan “CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035 (a)(8)(c).” SERVICES PROVIDED Services Services Dates Depth Intervals Directional Survey Service 18-Feb-15 to 18-Mar-15 179 ft to 7,531 ft VISION* Resistivity (Resistivity, Gamma Ray) 18-Feb-15 to 18-Mar-15 179 ft to 7,531 ft VISION* Service (Density, Porosity, Caliper) 27-Feb-15 to 18-Mar-15 1,978 ft to 7,531 ft Sonic* Service (Compressional and Shear Slowness) 27-Feb-15 to 18-Mar-15 1,978 ft to 7,531 ft OPERATING STATISTICS Total MWD Pumping Time: 165 hours Total LWD Pumping Time: 165 hours Total MWD Time Below Rotary: 291 hours Total LWD Time Below Rotary: 291 hours Total MWD Depth Interval: 7495 ft Total LWD Depth Interval: 7315 feet Total MWD Runs: 3 Total LWD Runs: 3 JOB PERFORMANCE Directional The final MWD survey point of Qugruk 301 was located at 7,494.91 feet with an inclination of 90.93 degrees and an azimuth of 18.89 degrees. This direction and inclination was projected from the final survey point to TD, which resulted in the following bottom hole coordinates. Measured Depth: 7531 ft True Vertical Depth: 4146.46 ft Displacement at Azimuth: 4064.75 ft at 18.89 deg Formation Evaluation 16 inch Section: The Surface Hole Section was drilled out of the 20 inch conductor casing from 98 ft MD to 2115 ft MD in one run. Directional Measurements, Gamma Ray, and Resistivity were provided in Real Time and Recorded Mode. Annular pressure, temperature, ECD, and ESD measurements were provided in Recorded Mode only. The BHA was composed of a Motor, arcVISION* 825, and TeleScope 825 and a milled tooth bit. The formation was evaluated while drilling, with arcVISION* measuring Gamma Ray and Resistivity, in Real Time and Recorded Mode. Directional measurements were provided by TeleScope, while the Motor performed steering operations. 12.25 inch Intermediate Section: The intermediate section was drilled from 2,115 ft MD to 5,248 ft MD in one run. The BHA for the run was composed of PD Xceed* 900, arcVISION* 825, SonicScope 825, TeleScope*825, and Slick adnVISION* 825. Gamma Ray, Resistivity and ECD were measured by the arcVISION* and supplied in both Real-Time and Recorded Mode. Downhole annular pressure and temperature were also provided in Real-Time and Recorded Mode from the arcVISION* tool. Directional measurements were provided by TeleScope, and the TeleScope also provided continuous inclination and surveys to ensure the well was drilled according to the plan. AdnVISION* was used to measure density and porosity, and the SonicScope was used for compressional and shear slowness of the formation. Compressional data was delivered in Real Time and Recorded Mode, while shear was delivered in Recorded Mode only. 6.5 inch Production Section: The Production Section was drilled in one LWD runs from a depth of 5,278 ft MD to 7,531 ft MD. Directional Measurements, Gamma Ray, Resistivity, ECD, Density, Porosity, Caliper, and Slowness were provided in Real Time and Recorded Mode. The production BHA was composed of a PowerDrive, Impulse*, VPWD*, SonicScope*, adnVISION* and a PDC bit. Resistivity, Gamma Ray, Density, Porosity and Caliper data, as well as ECD and annular temperature and pressure measurements were supplied by Impulse*, adnVISION* and VPWD tools in Real-Time and Recorded Mode. Directional Measurements were provided by the Impulse*. SonicScope was used for compressional and shear This run reached the Well Total Depth of 7,531 ft MD. Innovation The Schlumberger MWD team was successfully able to demodulate real-time data at a rate of 3 bits per second during all sections of the well, up to and including the point of TD at 7,531 ft MD. To guarantee good data density with lower data rates, we would like to encourage the use of Orion* compression in real time for all runs. It is especially useful and recommended if ever Real-Time density images are to be provided. With down-hole situations like irregular washouts, these would be very useful. Schlumberger Oilfield Services – Drilling & Measurements appreciates the opportunity to provide Repsol E&P USA Inc. with MWD and LWD services. Sincerely, Caitlin Schnitzer MWD/LWD Engineer Schlumberger Drilling & Measurements Company: Repsol Well Name: Qugruk 301 Field: North Slope API Number: 50-103-20700-00 Rig: Nabors 105 Date: 18-Mar-2015 eTrace: 14AKA0170 Well Data Section 1 Well Summary and Lessons Learned Section 2 BHA Sheets Section 3 Slide Sheets Section 4 Directional Surveys Section 5 Directional Plots Section 6 KPIs Section 7 MWD Depth Control Reports Section 8 Table of Contents Well Data Section 1 Qugruk 301 Repsol Qugruk 301 Exploration Qugruk 301 North Slope AFE # MWD / LWD Company eTrace Job # Field Rig Nabors 105 14AKA0170 NS_14_004 Schlumberger D&MDirectional Drilling Company Schlumberger D&M General Well Information Location Well Name Client Well Type API #50-103-20700-00 22-Mar-15 20-Mar-15 DD Personnel 13-Jan-15 98 ft 7,531 ft 7,531 ft Mud Company Start Depth Halliburton 37.00 ft 98 ft 18-Mar-15MWD / LWD 2nd DDs Lead MWD Personnel Lead DD 2nd MWDs A Uuemaa J Pickering B Ferguson M.Kalimullina/K. Antonini Whipstock/Window Survey Corrections Mag. Decl. Date Miscellaneous Information Nanushuk Proposed Azimuth Magnetic Declination Formation Targets 20.00° 18.596° 1-Feb-15 N/A Tool Pushers Kevin Dover Company Men C. Schnitzer Adam Sallee Carlos Cretsinger/Jackie McKinlye Sidney Self/David Dunbar Drlg Engineer Company Men CommentsStart Depth End Date Tool Pushers Steve Robison Size & Weight Top Bottom 20" 131 lb Surface 13 3/8" 68 lb 9 5/8" 47 lb 98 ft Surface 5,241 ft Surface 2,107 ft 06-Mar-15 End Depth 8.5" 6.5" 12-Mar-15 Clean Out Run + 30' 5,248 ft 15-Mar-15 5,278 ft14-Mar-15 End Depth 18-Mar-155,278 ft Casing / Liner Program Mud Program Type Start Depth 17-Feb-15 Well - Total Days 2,115 ft 5,248 ft Hole Size 12.25" 27-Feb-15 16" Drilled Hole Sizes 98 ft17-Feb-15 20-Feb-15 2,115 ft Start Date 98 ft 2,115 ft 2,115 ft 7,531 ft 17-Feb-15 09:20 18-Mar-15 09:30TD @ Date Time 29.01 Days Start @ Date Time 7,531 ft SOBM Spud Mud RKB Elevation Start DateService 98 ft 22-Mar-15 End Date Drilling & Measurements - Services Provided 7,531 ft MWD Personnel 98 ft13-Jan-15 End Depth Comments 7,531 ft Directional Drilling 17-Feb-15 Section 2 Well Summary and Lessons Learned Qugruk 301 BHA Run Summaries & Lessons Learned Well: Qugruk 301 Client: Repsol Rig: Nabors 105 Job Number: 14AKA0170 DD’s: Andrey Uuemaa, Jeff Pickering, Barry Ferguson The directional objective of the well was to drill 16” surface hole vertically to ~ 2090’. The 12 ¼” intermediate hole was planned to kick off at 2295’ MD at 335° azimuth and build to 15° inclination with 3.3 °/100’ to avoid Xceed RSS tool’s Zone of Exclusion; continue building to horizontal and turning to 20 deg azimuth with 3.1 °/100’ curve to a 9-5/8” casing point at 5250’ MD, 4187’ TVD (4150’ TVDSS). The 6 ½” lateral section was planned to TD of 7531’ MD. 16” Surface Hole BHA 1 and 2 (98’- 2115’ MD / 98’- 2115’ TVD) Drilling Run The objective of the run was to drill vertical hole to TD from below the 20” conductor. This objective was accomplished. The maximum inclination for the run was 1.37°. BHA was made up in two stages. BHA 1: first only Bit, Motor and 15 7/8” Stabilizer went below rotary table, tagged bottom at 98’ MD and drilled two stands of HWDP down to 225’ MD, enough to fit the rest of the BHA. BHA 2: Bit and motor stayed below rotary table, picked up ARC & TeleScope, stand of NMDCs and jars. RIH, took first survey at the bottom of Conductor pipe – surveys were required every stand because of Qugruk 3/3A well proximity. No MWD signal problems were observed. Average ROP in permafrost was 150-200 ft/hr, below permafrost base – 80-150 ft/hr. Occasional hard drilling was observed between 742’-935’ MD and 1700’-2000’ MD, when ROP dropped to as low as 10-15 ft/hr. After TD at 2115’ MD pulled right out of hole – no significant over pull was noticed – no wiper trip was performed. Motor drained well with no bearing play once TART. Finished surface interval 25.75' from original plan with a 1.15 OSF. See final BHA and steering sheet for further details. 12 1/4” Intermediate Hole BHA 3 (2115’- 5248’ MD / 2115’- 4185’ TVD) Drilling Run Objective of the run was to directionally drill a 3D intermediate curve section. Kick off was at approximately 2145’ MD and landing point was at approximately 5250’ MD with 90° inclination and 20° azimuth. Run issues; Depth FL Temp MW PV YP Oil/Water GPM ROP Act SPP Mod SPP Act ECD Mod ECD 461 58 9.8 22 25 628 150 1134 1426 11 10.06 785 53 9.95 32 31 624 100 1336 1645 10.98 10.3 1990 68 10 16 37 621 110 1320 2043 10.64 10.46 2115 10 22 28 568 90 1255 1681 10.9 10.45Surface • While making up the bit, the rotary bushing bowl was not deep enough to use a standard bit breaker to make up a 12-1/4” PDC bit. A modified Hycalog bit breaker had to be used, Rig waited 3.5 hours for Bit breaker to arrive. • ID of the jar was too small (2.25” ID) to drop the 8” well commander ball (2.5” OD). Flex subs had large enough ID (2.813 ID) but later found out the mandrel of jar did not. Run in the hole after making up BHA, shallow hole test at 1,950’. Wait on weather for 15 hours after shallow hole test. Test casing, drill shoe track plus 30’, pull back and perform Leak Off Test. Continue drilling to 3,667’ and circulate bottoms up for wiper trip. Intermittent erratic torque and stick slip but no issues maintaining tool face with Xceed tool. Inclination built to 40 degrees and turned to 5.7 degree azimuth prior to short trip. No real issue with wiper trip in or out. Back on bottom after wiper trip, circulate bottom up prior to going back to drilling. Drill from 3,667’ to 4,530’ 80 to 125 RPM and 8-10 Klbs WOB. Lost power to the rig floor multiple times causing loss of recorded surface parameters. Erratic torque and stick slip continue but no issues steering with Xceed tool. Spent 6-1/2 hours waiting on weather this section. Drill from 4,530 to 4,860’ with increased stick slip. Increase RPM to 140 RPM, increase steering ratio up to 90% as yield dropped from 6.0°/100’ to 4.8°/100’. Drill ahead from 4,860’ to TD at 5,248’. Maintained RPM at 140 RPM with sporadic stick slip and high torque but no problems steering with Xceed and yield back up to to 5.5°/100’. Run Summary Run was started 25.75 feet from plan in roughly the opposite direction due to surface section walk. The trend throughout the run was a formation push to the right. Landed at 5248’, 90° inclination and 19.5° azimuth. Finished 1.74’ above plan and 30.81’ right of plan. Overall the Xceed averaged between 5.5°/100’ to 6.5°/100’ yield rates. Low flow kit was utilized on the Xceed900 and steered successfully down to 580 GPM with medium to high stickslip. Surface torque was similarly intermittent with periods of high torque fluctuations (3 – 15 ft.lbf) followed by periods of stable torque values. Lubricants and bit selection for any future BHA may improve downhole torque and stick slip issues encountered from 4,000’ to 4,900’. 8 1/2” Clean Out Run BHA 4 (5248’- 5278’ MD / 4185’- 4185’ TVD) Drilling Run The objectives of this Run were: 1) Drill out the DV Tool bomb, perform Casing test. 2) Drill out float, cement and shoe track. Depth FL Temp MW PV YP Oil/Water GPM ROP Act SPP Mod SPP Act ECD Mod ECD 2135 73 10.4 36 14 78.4/21.6 505 100 1165 1126 10.86 10.95 2566 80 10.4 32 12 78.8/21.2 596 60 1510 1574 10.94 10.9 3382 92 10.4 31 13 79.4/20.6 599 110 1603 1722 10.84 10.85 3669 94 10.5 33 13 79.3/20.7 599 130 1676 1823 10.92 11 3746 92 10.4 32 14 79.7/20.3 599 100 1680 1820 10.88 10.95 3988 94 10.5 30 13 79.5/20.5 599 75 1720 1833 10.74 10.9 4084 96 10.4 31 13 80.5/19.5 596 40 1649 1832 10.77 10.8 4430 98 10.5 31 13 81.1/18.9 605 70 1771 1966 10.88 10.9 4834 108 10.5 36 14 81.4/18.6 612 55 1814 2134 10.87 10.86 5248 110 10.4 30 15 83.1/16.9 602 80 1800 2060 10.85 10.9Intermediate 3) Drill 30’ of new formation and perform FIT. Run in hole to 3,012’ with dumb iron assembly and VM3 milltooth bit and stage pumps up to 350 GPM. Drill stage tool and bomb used for opening stage tool with 350 GPM, 20K WOB, and 40 RPM in ~3 hours. Casing was successfully tested with Cement pumping unit @ 4500 psi. Run in hole to 5,012’, drill out cement, plugs, landing collar, float collar, and shoe with 400 GPM, 40-50 RPM, and 20-25 Klbs WOB. Drilling shoe track tool approximately 3 hours. Drill rathole and 30 ft of new formation in 1 hour, 15 Klbs WOB and 50 RPM. Confirmed depth for casing shoe @ 5241’ was 6’ deeper than expected. Performed FIT with Cement pumping unit @ 2600 psi (12 ppg). Pull out of hole to pick up lateral BHA. 6 1/2” Production Hole BHA 5 (5278’- 7531’ MD / 4185’- 4146’ TVD) Drilling Run The objectives of the Run was to drill lateral production section maintaining 91° inclination and an azimuth as close to 20° as possible until TD @ 7531' MD/4149' TVD. Restrictor size of 22/32 was installed into PowerDrive to operate in flow range 230-280 gpm. Shallow Hole Test was performed at 1600’ MD, demodulation problems were observed; 12Hz/6bps real-time configuration was changed to slower 12Hz/3bps by downlinking to Impulse. No signal problems were observed after that. On initial drill out 45’ surveys were taken to establish trend of BHA and counter any walk tendencies. ROP averaged in range of 100-130 ft/hr, ECD was closely monitored and was kept in range of 10.3-10.8 ppg. BHA held azimuth (~20 deg) well while in inclination hold at 90.4° and 90.9° inclination. Surveys had to be DMAG corrected due to issues in the Impulse tool; surveys after 7200' were affected by a solar storm, and no GMAG correction was applied. Survey stations 7227’ and 7495’ were retaken after wiper trip when the solar storm activity had decreased in intensity. From 6,300’ to TD backreamed full stands as a precaution at 40 RPM and 270 GPM. Reached TD 2.80’ above and 10.60’ right of plan. Once azimuth was lined up at 20° and 91° inclination, Inclination hold no correction was used for last 1500 feet of the section with minimal to no steering percentage required from the PowerDrive. BHA had neutral tendencies. PowerDrive was downlinked to 0°/0% at the end of the run. 6 1/2” Clean Out Run BHA 6 Reaming Run Performed BOP test, Run in hole with no issues, circulated at 300 gpm on bottom through BHA, pull out to shoe, circulated at 200 gpm inside casing through BHA, Pull out of hole. Lessons Learned • Picking up 12-1/4” bit on Nabors 105 requires a modification to the bit breaker. This rig doesn’t have a bit breaker bottom that fits into the bushing; it only has a square inset for the bit breaker that clamps around the bit. The bit set down too deep into the bowl of the bushings causing the bit to bottom out in the bushings. This led to the bit breaker not sitting securely into the bushing. • Xceed performed well with low flow kits at 580 GPM. Availability of low flow kits is extremely limited and requirements need to be identified early in the planning process. Expect 6.5 DLS from Xceed with 100% steering ratio. • Xceed BHA had strong right hand walk tendency. Depth FL Temp MW PV YP Oil/Water GPM ROP Act SPP Mod SPP Act ECD Mod ECD 5951 75 9.3 27 15 83.1/16.9 267 140 2040 2221 10.24 10.4 6734 84 9.35 30 18 83.1/16.9 273 100 2204 2437 10.61 10.75 7531 95 9.35 29 19 83.1/16.9 285 90 2364 2730 10.58 11.05Producti • Could not decode signal with 12 hz 6 bits in the 6-1/2” hole, had to down link to 12 hz 3 BPS. Mud pumps only have one small pulsation dampener that is shared for both pumps and create larger harmonics. • Smooth wellbore is important for Wireline logs and completion. Large targets to allow getting behind, left, right, or high. If plan is 3 DLS then that is max, shoot for 2.5 and get behind. • Weatherford likes to run the 6-1/4” jar because you pull more and hit harder than the 6-1/2” and 7-1/2” jars. The only problem is the ID is 2-1/4”, if you use the 6-1/4” on a 12-1/4” run and well commander, you have to use a 7” well commander. The 8-1/4” well commander ball will not pass through the jars. • Very limited space in pipe sheds, only 5’ area long enough to load batteries. Need to coordinate closely with all (Rig crew, tool Pusher, and Company Man) to make sure they know we need 12 hour minimum in that 5’ space as it is used when anything is loaded to skate to bring up to the rig floor. Trying to load batteries while picking up drill pipe is not going to happen. Get tools out early so they can be loaded or preferred would be to load batteries prior to sending to rig. • Weatherford built two sets of lift subs, one set with 4” tubes for 4” elevators and one set with 5” tubes for 5” elevators. This was purely to increase efficiency by not having to change elevators. • DD’s wrote up detailed BHA pick up procedures to streamline BHA handling and improve efficiency by informing and aligning all personnel. Post Well Modeling 0 500 1000 1500 2000 2500 3000 2000 3000 4000 5000 6000 7000 8000 Q-301 Stand Pipe Pressure Act SPP Mod SPP 10 10.2 10.4 10.6 10.8 11 11.2 11.4 11.6 11.8 12 2000 3000 4000 5000 6000 7000 8000 Q-301 ECD Act ECD Mod ECD Date: 24-Mar-2015 Well Name: Qugruk 301 Company: Repsol E&P US Inc. API Number: 50-103-20700-00-00 AFE Number: NS_14_004 Location: N 412954 ft US, E 5972299 ft Field: North Slope Rig: Nabors 105AC Drilling and Measurements Field Support: Operations Manager, Ankur Prakash Field Service Manager, Joseph Leblanc Drilling and Measurements Field Crew: Cell Manager, Milena Kalimullina Kyle Antonini Cell Engineer, Caitlin Schnitzer Jeff Ryan “CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035 (a)(8)(c).” SERVICES PROVIDED Services Services Dates Depth Intervals Directional Survey Service 18-Feb-15 to 18-Mar-15 179 ft to 7,531 ft VISION* Resistivity (Resistivity, Gamma Ray) 18-Feb-15 to 18-Mar-15 179 ft to 7,531 ft VISION* Service (Density, Porosity, Caliper) 27-Feb-15 to 18-Mar-15 1,978 ft to 7,531 ft Sonic* Service (Compressional and Shear Slowness) 27-Feb-15 to 18-Mar-15 1,978 ft to 7,531 ft OPERATING STATISTICS Total MWD Pumping Time: 165 hours Total LWD Pumping Time: 165 hours Total MWD Time Below Rotary: 291 hours Total LWD Time Below Rotary: 291 hours Total MWD Depth Interval: 7495 ft Total LWD Depth Interval: 7315 feet Total MWD Runs: 3 Total LWD Runs: 3 JOB PERFORMANCE Directional The final MWD survey point of Qugruk 301 was located at 7,494.91 feet with an inclination of 90.93 degrees and an azimuth of 18.89 degrees. This direction and inclination was projected from the final survey point to TD, which resulted in the following bottom hole coordinates. Measured Depth: 7531 ft True Vertical Depth: 4146.46 ft Displacement at Azimuth: 4064.75 ft at 18.89 deg Formation Evaluation 16 inch Section: The Surface Hole Section was drilled out of the 20 inch conductor casing from 98 ft MD to 2115 ft MD in one run. Directional Measurements, Gamma Ray, and Resistivity were provided in Real Time and Recorded Mode. Annular pressure, temperature, ECD, and ESD measurements were provided in Recorded Mode only. The BHA was composed of a Motor, arcVISION* 825, and TeleScope 825 and a milled tooth bit. The formation was evaluated while drilling, with arcVISION* measuring Gamma Ray and Resistivity, in Real Time and Recorded Mode. Directional measurements were provided by TeleScope, while the Motor performed steering operations. 12.25 inch Intermediate Section: The intermediate section was drilled from 2,115 ft MD to 5,248 ft MD in one run. The BHA for the run was composed of PD Xceed* 900, arcVISION* 825, SonicScope 825, TeleScope*825, and Slick adnVISION* 825. Gamma Ray, Resistivity and ECD were measured by the arcVISION* and supplied in both Real-Time and Recorded Mode. Downhole annular pressure and temperature were also provided in Real-Time and Recorded Mode from the arcVISION* tool. Directional measurements were provided by TeleScope, and the TeleScope also provided continuous inclination and surveys to ensure the well was drilled according to the plan. AdnVISION* was used to measure density and porosity, and the SonicScope was used for compressional and shear slowness of the formation. Compressional data was delivered in Real Time and Recorded Mode, while shear was delivered in Recorded Mode only. 6.5 inch Production Section: The Production Section was drilled in one LWD runs from a depth of 5,278 ft MD to 7,531 ft MD. Directional Measurements, Gamma Ray, Resistivity, ECD, Density, Porosity, Caliper, and Slowness were provided in Real Time and Recorded Mode. The production BHA was composed of a PowerDrive, Impulse*, VPWD*, SonicScope*, adnVISION* and a PDC bit. Resistivity, Gamma Ray, Density, Porosity and Caliper data, as well as ECD and annular temperature and pressure measurements were supplied by Impulse*, adnVISION* and VPWD tools in Real-Time and Recorded Mode. Directional Measurements were provided by the Impulse*. SonicScope was used for compressional and shear This run reached the Well Total Depth of 7,531 ft MD. Innovation The Schlumberger MWD team was successfully able to demodulate real-time data at a rate of 3 bits per second during all sections of the well, up to and including the point of TD at 7,531 ft MD. To guarantee good data density with lower data rates, we would like to encourage the use of Orion* compression in real time for all runs. It is especially useful and recommended if ever Real-Time density images are to be provided. With down-hole situations like irregular washouts, these would be very useful. Schlumberger Oilfield Services – Drilling & Measurements appreciates the opportunity to provide Repsol E&P USA Inc. with MWD and LWD services. Sincerely, Caitlin Schnitzer MWD/LWD Engineer Schlumberger Drilling & Measurements Section 3 BHA Sheets Qugruk 301 Date In 17-Feb-15 Date Out Hole Size 16 Time In 5:00 Time Out Hole Sect Surface Depth In 98 Depth Out 225 Bha Type Motor TVD In 98 TVD Out 225 Hrs BRT 25.0 Drlg Hrs 1.4 Drlg Ft Avg ROP 88.2 Slide Hrs 0.0 Slide Ft Slide ROP 1,000.0 Rot Hrs 1.4 Rot Ft Rot ROP 88.2 Pump Hrs 3.0 Rotate % Slide %0 1 R/S 7/8 Rotor Jet NO Incl In N/A Az In N/A Bit>Srvy 71.92 1243 Stages 4.0 Bearing Mud Incl Out N/A Az Out N/A T/F Corr 91.8 8 3/8 Rev/Gal 0.166 ABH Setting 1.15 Avg Dls N/A Max Dls N/A Plan Dls N/A Spud Mud Mud Wt 9.95 Sand %1 RPM 40 GPM 500 SPP On 600 82 °F FV-PV-YP 58-32-31 Solids %7.8 Dlg TQ 3.0 WOB 10 SPP Off 200 Vendor S/N OD ID Stab OD F.N. Length Cum Length In / Out FN OD Hughes 5233591 16 3.75 1.45 1.45 Bit # TFA=0.942 SLB 1243 8.38 12.13 29.35 30.80 Stabil Drill SD603876 8.31 2.88 15.88 2.44 8.04 38.84 Nabors KP16794 8.13 2.88 1.56 3.59 42.43 Nabors HWDP (6 jts)5.00 3.00 1.53 182.72 225.15 Tool Hrs. In Hrs. Out Dry Wt 16,295 IADC #135 Motor 0.0 3.0 Wt Above Jars Footage 127 0.0 1.4 Wt Below Jars Hrs 1.4 Buoy Wt 13,825 k Revs 11 k Inclination 1 Grade Bit To Buoy+Incl Wt 13,824 Comment 2 3 4 6 5/8 Reg Pin 5 1 1 6:00 Well Qugruk 301 RepsolCustomer Job #14AKA0170 18-Feb-15 BHA # 0NS_14_004 A. Uuemaa/B. Ferguson 100Carlos Cretsinger Nabors 105 127 North Slope AFE # DD's Co. Men Field 127 Rig PDM Size PDM Run # PDM Ser# Top Conn Description Mud Type BHT Item Bottom Conn 16" VM-3 Milltooth Bit 3x18, 1x16 6 5/8 Reg Pin 15 7/8" NM Stabilizer A8007840XP 6 5/8 Reg Box 6 5/8 Reg Box 0-0-WT-A-E/E/E-IN-NO-TD Why POOH / Comments BHA WeightBHA and Run Objective BHA and Run Results Bit Data PU complete Surface Hole BHA Successful run. Drill 2 stands of HWDP with no tools, POOH to PU complete BHA Drill 225 ft to fit all the BHA 6 5/8 Reg Box 4 1/2 IF Box HWDP (6 jts) Steel XO Sub 6 5/8 Reg Pin 4 1/2 IF Pin 4 1/2 IF Box Date In 18-Feb-15 Date Out Hole Size 16 Time In 6:00 Time Out Hole Sect Surface Depth In 225 Depth Out 2,115 Bha Type Motor TVD In 225 TVD Out 2,115 Hrs BRT 44.0 Drlg Hrs 18.8 Drlg Ft Avg ROP 100.5 Slide Hrs 0.0 Slide Ft Slide ROP 1.0 Rot Hrs 18.8 Rot Ft Rot ROP 100.5 Pump Hrs 26.3 Rotate % Slide %0 2 R/S 7/8 Rotor Jet NO Incl In 0.00 Az In 0.01 Bit>Srvy 71.92 1243 Stages 4.0 Bearing Mud Incl Out 0.63 Az Out 137.93 T/F Corr 91.8 8 3/8 Rev/Gal 0.166 ABH Setting 1.15 Avg Dls 0.2 Max Dls 0.6 Plan Dls 0.0 Spud Mud Mud Wt 9.95 Sand %1 RPM 65 GPM 630 SPP On 1500 82 °F FV-PV-YP 58-32-31 Solids %7.8 Dlg TQ 7.0 WOB 25 SPP Off 1280 Vendor S/N OD ID Stab OD F.N. Length Cum Length In / Out FN OD Hughes 5233591 16 3.75 1.45 1.45 Bit # TFA=0.942 SLB 1243 8.38 12.13 29.35 30.80 Stabil Drill SD603876 8.31 2.88 15.88 2.44 8.04 38.84 SLB ZL2958 8.19 3.00 4.81 20.98 59.82 SLB E1166 8.25 4.25 27.33 87.15 Stabil Drill SD603875 3.31 2.88 15.88 2.47 8.02 95.17 Stabil Drill SD43896 8.13 2.88 30.07 125.24 Stabil Drill SD49977 8.13 2.88 29.60 154.84 Stabil Drill SD39435 8.13 2.88 29.12 183.96 Nabors KP16794 8.13 2.88 1.56 3.59 187.55 Nabors HWDP (9 jts)5.00 3.00 1.53 275.59 463.14 Dailey 1766-0566 6.25 2.69 1.15 31.28 494.42 Nabors HWDP (5 jts)5.00 3.00 1.53 153.27 647.69 Tool Hrs. In Hrs. Out Dry Wt 53,360 IADC #135 Motor 0.0 26.3 Wt Above Jars 7,664 Footage 1,890 0.0 18.8 Wt Below Jars 43,663 Hrs 18.8 Jars 0.0 26.3 Buoy Wt 45,273 k Revs 191 k 0.0 18.8 Inclination 1 Grade Bit To Buoy+Incl Wt 45,270 Comment Customer Repsol 2:00 Well Qugruk 301 BHA #2 Job #14AKA0170 20-Feb-15 1,890 Co. Men Carlos Cretsinger 100 Field North Slope Rig Nabors 105 1,890 AFE # NS_14_004 0 PDM Run # PDM Ser# PDM Size Mud Type BHT Item Description DD's A. Uuemaa/B. Ferguson Bottom Conn Top Conn 1 16" VM-3 Milltooth Bit 3x18, 1x16 6 5/8 Reg Pin 2 A8007840XP 6 5/8 Reg Box 6 5/8 Reg Box 4 ARC-8 6 5/8 Reg Pin 6 5/8 Reg Box 3 15 7/8" NM Stabilizer 6 5/8 Reg Pin 6 5/8 FH Box 6 15 7/8" NM Stabilizer 6 5/8 Reg Pin 6 5/8 Reg Box 5 TeleScope 825 6 5/8 FH Pin 6 5/8 Reg Box 8 8" NMDC 6 5/8 Reg Pin 6 5/8 Reg Box 7 8" NMDC 6 5/8 Reg Pin 6 5/8 Reg Box 4 1/2 IF Box 11 HWDP (9 jts)4 1/2 IF Pin 6 5/8 Reg Box 10 Steel XO Sub 6 5/8 Reg Pin 9 8" NMDC 6 5/8 Reg Pin 4 1/2 IF Box 12 Hydraulic Drilling Jar 4 1/2 IF Pin 4 1/2 IF Box 4 1/2 IF Box13HWDP (5 jts)4 1/2 IF Pin BHA and Run Objective Drill Surface Hole to Casing point BHA Weight Bit Data 1-1-WT-A-E/E/E-IN-NO-TD to bit (ft): Res=48.57, GR=48.74 Expected DLS were less than 1°/100ft. BHA and Run Results Successful run. No sliding. Low S&V. Hard stringers from 742 ft - 935 ft; 1700 ft - 2000 ft. Why POOH / Comments Surface Section TD Date In 27-Feb-15 Date Out Hole Size 12 1/4 Time In 21:30 Time Out Hole Sect Intermediate Depth In 2,115 Depth Out 5,248 Bha Type RSS TVD In 2,115 TVD Out 4,185 Hrs BRT 159.5 Drlg Hrs 47.5 Drlg Ft Avg ROP 65.9 Slide Hrs 0.0 Slide Ft Slide ROP 0.0 Rot Hrs 47.5 Rot Ft Rot ROP 65.9 Pump Hrs 93.5 Rotate % Slide %0 R/S Rotor Jet Incl In 0.63 Az In 137.93 Bit>Srvy 95.38 Stages Bearing Incl Out 88.40 Az Out 18.26 T/F Corr 91.8 Rev/Gal ABH Setting Avg Dls 3.3 Max Dls 5.2 Plan Dls 3.3 SOBM Mud Wt 10.4 Sand %1 RPM 140 GPM 620 SPP On 1750 131 °F FV-PV-YP 76/32/14 Solids %13 Dlg TQ 9.0 WOB 10 SPP Off 1750 Vendor S/N OD ID Stab OD F.N. Length Cum Length In / Out FN OD NOV (Hycalog)E171034 12.25 3.25 0.93 0.93 Bit # TFA=0.796 SLB DN9-286 9.06 6.75 12.13 0.93 28.32 29.25 SLB E7648 8.44 3.00 18.69 47.94 SLB 8991 8.38 4.25 12.00 4.60 34.04 81.98 SLB E1904 8.63 4.25 27.30 109.28 SLB 47516 8.38 4.13 22.13 131.41 Stabil Drill SD43896 8.13 2.88 30.07 161.48 Stabil Drill SD49977 8.13 2.88 29.60 191.08 Stabil Drill SD39435 8.13 2.88 29.12 220.20 Stabil Drill SD106956 8.13 2.75 2.88 223.08 Mi Swaco B2000804 8.25 3.00 14.76 237.84 Nabors KP16794 8.13 2.88 1.56 3.59 241.43 Nabors HWDP (9 jts)5.00 3.00 1.53 275.59 517.02 Dailey 1622-0006 6.25 2.75 1.69 32.40 549.42 Nabors HWDP (5 jts)5.00 3.00 1.53 153.27 702.69 Tool Hrs. In Hrs. Out Dry Wt 59,758 IADC # RSS 0.0 93.5 Wt Above Jars 7,664 Footage 3,133 0.0 47.6 Wt Below Jars 49,988 Hrs 47.5 Jars 93.5 Buoy Wt 50,291 k Revs 399 k 47.5 Inclination 88 Grade Bit To Buoy+Incl Wt 1,404 Comment Customer Repsol 13:00 Well Qugruk 301 BHA #3 Job #14AKA0170 06-Mar-15 3,133 Co. Men Carlos Cretsinger/Sidney Self 100 Field North Slope Rig Nabors 105 3,133 AFE # NS_14_004 0 PDM Run # PDM Ser# PDM Size Mud Type BHT Item Description DD's J. Pickering/B. Ferguson Bottom Conn Top Conn 1 12.25" SKH519M PDC 3x14, 2x15 6 5.8 Reg Pin 2 PD Xceed 900 6 5/8 Reg Box 6 5/8 FH Box 4 SonicScope 6 5/8 FH Pin 6 5/8 FH Box 3 ARC-8 6 5/8 FH Pin 6 5/8 FH Box 6 ADN-8 6 5/8 FH Pin 6 5/8 Reg Box 5 TeleScope 825 6 5/8 FH Pin 6 5/8 FH Box 8 8" NMDC 6 5/8 Reg Pin 6 5/8 Reg Box 7 8" NMDC 6 5/8 Reg Pin 6 5/8 Reg Box 6 5/8 Reg Box 11 8'' Well Commander 6 5/8 Reg Pin 6 5/8 Reg Box 10 8" Float Sub 6 5/8 Reg Pin 9 8" NMDC 6 5/8 Reg Pin 6 5/8 Reg Box 12 Steel XO Sub 6 5/8 Reg Pin 4 1/2 IF Box 4 1/2 IF Box 14 Hydraulic Drilling Jar 4 1/2 IF Pin 13 HWDP (9 jts)4 1/2 IF Pin 4 1/2 IF Box 4 1/2 IF Box15HWDP (5 jts)4 1/2 IF Pin BHA and Run Objective Drill curve section to Casing point BHA Weight Bit Data 1-2-CT-A-X-I-WT-TD RSS D&I/APWD/Res/GR/Sonic/MVC/D&I/Den/Neu-17.6/34.7/37.2/68.7/92.1/95 Drill 3D-curve section to Casing pointExpected DLS were 3.3°/100ft. BHA and Run Results Successful run. Landed 1.74 ft high. Why POOH / Comments Intermediate Section TD / Casing Point Date In 12-Mar-15 Date Out Hole Size 8 1/2 Time In 1:00 Time Out Hole Sect Intermediate Depth In 5,248 Depth Out 5,278 Bha Type Dumb Iron TVD In 4,185 TVD Out 4,185 Hrs BRT 65.0 Drlg Hrs 0.5 Drlg Ft Avg ROP 60.0 Slide Hrs 0.0 Slide Ft Slide ROP 0.0 Rot Hrs 0.5 Rot Ft Rot ROP 60.0 Pump Hrs 10.0 Rotate % Slide %0 R/S Rotor Jet Incl In 88.40 Az In 18.26 Bit>Srvy N/A Stages Bearing Incl Out 88.40 Az Out 18.26 T/F Corr N/A Rev/Gal Rubber Avg Dls N/A Max Dls N/A Plan Dls N/A SOBM Mud Wt 9.3 Sand %1 RPM 50 GPM 400 SPP On 1200 N/A FV-PV-YP 95-26-15 Solids %9.2 Dlg TQ 7.5 WOB 15 SPP Off 1180 Vendor S/N OD ID Stab OD F.N. Length Cum Length In / Out FN OD Hughes 5251184 8.50 2.25 0.8 0.8 VM-3 Bit # 3 TFA= 0.942 Stabil Drill SD21746 6.81 8.38 3.32 6.47 7.27 Nabors HWDP (9 jts)5.00 3.00 1.53 275.59 282.86 Dailey 1622-0006 6.25 2.75 1.69 32.40 315.26 Nabors HWDP (5 jts)5.00 3.00 1.53 153.27 468.53 Knight Oil Tools KP16789 6.50 2.63 1.56 3.64 472.17 Nabors 69 Jts 4" DP 3.88 3.25 2214.19 2686.36 Knight Oil Tools KP166787 6.50 2.63 2.00 3.64 2690.00 Tool Hrs. In Hrs. Out Dry Wt 59,323 IADC # Jars 93.5 103.5 Wt Above Jars 42,790 Footage 30 47.5 48.0 Wt Below Jars 14,427 Hrs 0.5 Buoy Wt 50,919 k Revs 1 k Inclination 90 Grade Bit To Buoy+Incl Wt 0 CommentDumb iron assembly Expected DLS is N/A. BHA and Run Results All objectives met Why POOH / Comments Run objectives met/Wireline run to follow BHA and Run Objective Drill out the DV Tool bomb. Casing test. Drill out float, cement and shoe track. Drill 30 ft of new formation and perform FIT. BHA Weight Bit Data 1-1-WT-A-E-I-NO-TD 4 1/2 IF Box8Crossover Sub XT39 Pin 7 4" Drill Pipe (69 joints)XT39 Pin XT39 Box 6 Crossover Sub 4 1/2 IF Pin XT39 Box 5 HWDP (5 jts)4 1/2 IF Pin 4 1/2 IF Box 4 4 1/2 IF Box Hydraulic Drilling Jar 4 1/2 IF Pin 3 HWDP (9 jts)4 1/2 IF Pin 4 1/2 IF Box 3x18, 1x16 4 1/2 Reg Pin 2 8 3/8" Near Bit Stabilizer 4 1/2 IF Pin 4 1/2 Reg Box Bottom Conn Top Conn 1 8 1/2" Milltooth Bit PDM Run # PDM Ser# PDM Size Mud Type BHT Item Description DD's Jeff Pickering, Andrey Uuemaa 30 Co. Men Sidney Self, Jackie McKinley 100 Field North Slope Rig Nabors 105 30 AFE # NS_14_004 0 Customer Repsol 18:00 Well Qugruk 301 BHA #4 Job #14AKA0170 14-Mar-15 Date In 15-Mar-15 Date Out Hole Size 6 1/2 Time In 11:00 Time Out Hole Sect Production Depth In 5,278 Depth Out 7,531 Bha Type RSS TVD In 4,185 TVD Out 4,146 Hrs BRT 70.5 Drlg Hrs 21.3 Drlg Ft Avg ROP 106.0 Slide Hrs 0.0 Slide Ft Slide ROP 1.0 Rot Hrs 21.2 Rot Ft Rot ROP 106.1 Pump Hrs 42.7 Rotate % Slide %0 R/S Rotor Jet Incl In 88.40 Az In 18.26 Bit>Srvy 34.13 Stages Bearing Incl Out 90.93 Az Out 18.89 T/F Corr N/A Rev/Gal ABH Setting Avg Dls 0.9 Max Dls 2.0 Plan Dls 1.0 SOBM Mud Wt 9.3 Sand %N/A RPM 110 GPM 277 SPP On 2260 124 °F FV-PV-YP 95-28-17 Solids %9.5 Dlg TQ 8.0 WOB 8 SPP Off 2240 Vendor S/N OD ID Stab OD F.N. Length Cum Length In / Out FN OD NOV (Hycalog)A210931 6.50 1.50 0.63 0.63 Bit # TFA=0.796 SLB 56524 5.00 2.25 6.38 1.81 21.84 22.47 SLB G9092 4.81 2.25 2.06 33.79 56.26 SLB 130 4.88 2.25 1.69 14.81 71.07 SLB G3063 5.00 2.25 5.88 3.89 31.43 102.50 SLB AF65 5.00 5.63 1.49 25.15 127.65 Stabil Drill SD54189 4.81 2.31 4.41 30.86 158.51 Stabil Drill SD109733 4.81 2.25 3.18 161.69 Mi-Swaco B2008026 5.00 2.25 1.43 10.58 172.27 Dailey 14201588 5.13 2.25 2.25 29.40 201.67 Nabors 4" HWDP (2 Jts)4.00 2.63 60.63 262.30 Nabors 69 Jts 4" DP 3.88 3.25 2214.19 2476.49 Knight Oil Tools KP166787 6.50 2.63 2.00 3.64 2480.13 Tool Hrs. In Hrs. Out Dry Wt 43,227 IADC #M332 RSS 0.0 42.7 Wt Above Jars 34,945 Footage 2,253 0.0 21.3 Wt Below Jars 8,282 Hrs 21.3 Jars 0.0 42.7 Buoy Wt 37,103 k Revs 140 k 0.0 21.3 Inclination 91 Grade Bit To Buoy+Incl Wt -648 Comment Customer Repsol 9:30 Well Qugruk 301 BHA #5 Job #14AKA0170 18-Mar-15 2,253 Co. Men Carlos Cretsinger/Sidney Self 100 Field North Slope Rig Nabors 105 2,253 AFE # NS_14_004 0 PDM Run # PDM Ser# PDM Size Mud Type BHT Item Description DD's J. Pickering/A Uuemaa Bottom Conn Top Conn 1 6 1/2" SKH513M PDC 3x10, 2x9 3 1/2 Reg Pin 2 4 3/4" PD X6 3 1/2 Reg Box 3 1/2 IF Pin 4 VPWD 3 1/2 IF Box NC35 Pin 3 ImPulse NC35 Box 3 1/2 IF Pin 6 ADN-4 3 1/2 IF Box 3 1/2 IF Box 5 SonicScope 3 1/2 IF Box 3 1/2 IF Pin 8 4 3/4" Float Sub 3 1/2 IF Pin 3 1/2 IF Box 7 4 3/4" NM Flex Collar 3 1/2 IF Pin 3 1/2 IF Box 3 1/2 IF Box 11 4" HWDP XT39 Pin 3 1/2 IF Box 10 Hydraulic Drilling Jar XT39 Pin 9 5" Well Commander + Ball Catcher 3 1/2 IF Pin XT39 Box 12 4" Drill Pipe (69 joints)XT39 Pin XT39 Box 4 1/2 IF Box13Crossover Sub XT39 Pin BHA and Run Objective Drill lateral production section BHA Weight Bit Data were moderately balled up on surface, 2 broken cutters on shoulder of bit.1-1-BU-A-X-I-BT-TD RSS D&I/Res/D&I/GR/IPWD/APWD/Sonic/Den/Neu-7.35/28.9/34.1/36.1/59.5/6 maintaining 91 inclination and 20 azimuth until TD @ 7531' MD, 4519' TVD. BHA and Run Results - Results: BHA held azimuth (~20°) well while in inclination hold at 90.4° and 90.9° inclination. Surveys had to be DMAG corrected, surveys after 7200' were affected by a solar storm, no GMAG correction was applied. Survey stations 7227 and 7495 were retaken after wiper trip when the solar storm had decreased in intensity. Bit and stablizers were moderately balled up on surface, 2 broken cutters on shoulder of bit. Why POOH / Comments TD, Bit and stablizers Date In 18-Mar-15 Date Out Hole Size 6 1/2 Time In 9:30 Time Out Hole Sect Production Depth In 7,531 Depth Out 7,531 Bha Type Dumb Iron TVD In 4,146 TVD Out 4,146 Hrs BRT 50.5 Drlg Hrs 0.0 Drlg Ft Avg ROP Slide Hrs 0.0 Slide Ft Slide ROP 0.0 Rot Hrs 0.0 Rot Ft Rot ROP 0.0 Pump Hrs 10.0 Rotate % Slide % R/S Rotor Jet Incl In Az In Bit>Srvy N/A Stages Bearing Incl Out Az Out T/F Corr N/A Rev/Gal Rubber Avg Dls N/A Max Dls N/A Plan Dls N/A SOBM Mud Wt 9.4 Sand %NA RPM 0 GPM 200 SPP On 800 124 °F FV-PV-YP 105-28-20 Solids %9.5 Dlg TQ 0.0 WOB N/A SPP Off 800 Vendor S/N OD ID Stab OD F.N. Length Cum Length In / Out FN OD StabilDrill SD801933 5.75 2.75 2.77 2.77 Bit #5 TFA=0.614 Stabil Drill SD14759 4.75 2.25 6.38 2.92 5.92 8.69 Nabors 4" Drill Collars (2 Jts)4.75 2.25 61.23 69.92 Stabil Drill SD21031 4.75 2.25 6.38 2.31 5.56 75.48 Nabors 4" Drill Collar (1 Jt)4.75 2.25 29.91 105.39 Mi-Swaco B2008026 5.00 2.25 1.43 10.58 115.97 Dailey 14201588 5.13 2.25 2.25 29.40 145.37 Nabors 4" HWDP (2 Jts)4.00 2.63 60.63 206.00 Nabors 69 Jts 4" DP 3.88 3.25 2214.19 2420.19 Knight Oil Tools KP166787 6.50 2.63 2.00 3.64 2423.83 Tool Hrs. In Hrs. Out Dry Wt 35,995 IADC # Jars 42.7 52.7 Wt Above Jars 34,945 Footage 21.3 21.3 Wt Below Jars 1,050 Hrs 0.0 Buoy Wt 30,841 k Revs Inclination 90 Grade Bit To Buoy+Incl Wt 0 CommentN/A BHA and Run Results Hung off, tested BOP, ran to bottom and circulated, TOH to 4570, circulated at liner hanger depth. Why POOH / Comments Run liner. BHA and Run Objective Clean out run.BHA Weight Bit Data Bullnose bit - no wear. 4 1/2 IF Box XT39 Box 10 Crossover Sub XT39 Pin XT39 Box 9 4" Drill Pipe (69 joints)XT39 Pin 8 4" HWDP XT39 Pin 7 Hydraulic Drilling Jar XT39 Pin 3 1/2 IF Box 6 5" Well Commander + Ball Catcher 3 1/2 IF Pin 3 1/2 IF Box 5 4.75" Drill Collar 3 1/2 IF Pin 3 1/2 IF Box 4 3 1/2 IF Box 6 3/8" NM Stabilzer 3 1/2 IF Pin 3 4.75" Drill Collars 3 1/2 IF Pin 3 1/2 IF Box Type: Bullnose , 2x20 3 1/2 Reg Pin 2 6 3/8" Near Bit Stabilizer (BFF)3 1/2 Reg Box 3 1/2 IF Box Bottom Conn Top Conn 1 5 3/4" Z Bit PDM Run # PDM Ser# PDM Size Mud Type BHT Item Description DD's J Pickering A Uuemaa 0 Co. Men Carlos Crestinger, Jackie McKinley Field North Slope Rig Nabors 105 AFE # NS_14_004 0 Customer Repsol 12:00 Well Qugruk 301 BHA #6 Job #14AKA0170 20-Mar-15 Section 4 Slide Sheets Qugruk 301 Q-301 16in Surface BHA Steering SheetLocationCasing Shoe (ft)BHA Run1ClientCasing Size (in) Depth in (ft)98.00Depth out (ft)2115.00Date In20.18RigCasing WT (lbm/ft)Incl in (deg)0.16Incl out (deg)0.63Date TD29.27FieldMud TypeAzmth in (deg)54.29Azm out (deg)137.93Date out64.25WellEnd MW (lbm/gal)Client Rep 1 Lead DDBoreholeHole Size (in)Client Rep 2 2nd DDBIT INFORMATIONS/N IADC In Row Out Row Dull Char Location Bearings Gauge Other Reason PulledTYPE Jets (1/32 inIN0 0 NO A E/E/E IN NOManuf/Model Name TFA (in2) Out1 1 WT A E/E/E IN NODate Start Time End Time MD From MD To TF Mode Operation Mode WOB SRPM Torque FlowSPP On BotSPP Off BotDiff Press PU WeightSlack Off WeighRotating HKLDSvy MD Incl Azmth DLS Commentdd-mmm-yy ft ft 1000 lbf c/min 1000 ft.lbf gal/min psi psi psi 1000 lbf 1000 lbf 1000 lbf ft deg deg deg/100ft18-Feb-15 03:03 03:32 98.00 132.00 Magnetic Rotating 10.0 40 5.0 500 500.0 200.0 300.0 101.08 0.17 54.29 0.21Drill Down 1 x HWDP03:54 04:47 132.00 225.00 Magnetic Rotating 10.0 50 5.0 530 600.0 200.0 400.0 55.00 55.00 55.00 204.00 0.50 161.08 0.56Drill Down 1 x HWDP10:00 10:40 225.00 279.00 Magnetic Rotating 15.0 65 4.0 463 630.0 530.0 100.0Fix Pump 210:55 11:53 279.00 371.00 Magnetic Rotating 20.0 65 5.0 463 630.0 530.0 100.0 293.45 0.72 153.93 0.2612:10 12:35 371.00 400.00 Magnetic Rotating 20.0 65 5.0 463 630.0 530.0 100.0 55.00 55.00 55.00 389.15 0.65 157.17 0.0812:40 12:58 400.00 463.00 Magnetic Rotating 20.0 80 6.0 600 1200.0 1080.0 120.0 58.00 54.00 53.00Fix Pump Problems16:50 17:50 463.00 555.00 Magnetic Rotating 22.0 40 4.5 550 1280.0 1140.0 140.0 59.00 57.00 58.00 478.11 0.80 165.50 0.21MW 9.8, Vis 6818:50 19:50 555.00 648.00 Magnetic Rotating 20.0 50 5.0 630 1250.0 975.0 275.0 64.00 62.00 60.00 575.60 1.00 169.67 0.22Slow Pump Rates20:05 21:04 648.00 742.00 Magnetic Rotating 20.0 50 5.0 630 1300.0 1000.0 300.0 66.00 68.00 68.00 667.64 0.96 142.79 0.50MW 9.9, Vis 7721:17 22:40 742.00 837.00 Magnetic Rotating 20.0 50 7.0 625 1310.0 1160.0 150.0 71.00 70.00 70.00 765.90 1.04 168.22 0.45Hard Stringers22:50 00:14 837.00 935.00 Magnetic Rotating 25.0 40 9.0 625 1310.0 1160.0 150.0 72.00 70.00 70.00 862.02 1.17 178.95 0.25Pump Sweep, Hard Stringers19-Feb-15 00:28 01:20 935.00 1031.00 Magnetic Rotating 25.0 50 5.0 630 1375.0 1200.0 175.0 70.00 75.00 72.00 958.99 1.27 172.02 0.1801:35 02:25 1031.00 1128.00 Magnetic Rotating 25.0 50 5.0 630 1375.0 1200.0 175.0 72.00 72.00 74.00 1046.84 1.37 164.63 0.2202:35 03:45 1128.00 1223.00 Magnetic Rotating 25.0 40 7.0 625 1420.0 1220.0 200.0 75.00 75.00 73.00 1140.25 1.17 158.48 0.26Max Gas 3000, Flow Check04:40 05:30 1223.00 1319.00 Magnetic Rotating 25.0 40 7.0 620 1310.0 1160.0 150.0 75.00 75.00 76.00 1239.79 0.86 161.23 0.32Change Screens, Max Gas 900005:40 06:20 1319.00 1413.00 Magnetic Rotating 25.0 40 7.0 620 1310.0 1160.0 150.0 75.00 75.00 76.00 1337.01 0.75 156.37 0.1306:30 07:05 1413.00 1509.00 Magnetic Rotating 25.0 40 7.0 620 1460.0 1200.0 260.0 76.00 80.00 80.00 1431.83 0.60 157.77 0.1607:15 07:50 1509.00 1605.00 Magnetic Rotating 25.0 40 6.0 620 1450.0 1200.0 250.0 84.00 84.00 84.00 1527.15 0.53 152.72 0.0908:00 08:40 1605.00 1701.00 Magnetic Rotating 25.0 40 7.0 620 1460.0 1240.0 220.0 85.00 85.00 85.00 1625.64 0.51 136.72 0.1509:00 09:36 1701.00 1797.00 Magnetic Rotating 20.0 40 7.0 620 1460.0 1240.0 220.0 87.00 87.00 87.00 1721.70 0.52 140.27 0.03MW in/out: 10/10; Vis 7009:50 11:26 1797.00 1893.00 Magnetic Rotating 30.0 65 7.0 620 1500.0 1280.0 220.0 87.00 85.00 86.00 1816.07 0.43 154.77 0.16Possible Bit balling @ 185711:35 12:49 1893.00 1988.00 Magnetic Rotating 30.0 65 8.0 620 1540.0 1280.0 260.0 88.00 84.00 86.00 1912.27 0.55 141.09 0.1713:04 15:05 1988.00 2084.00 Magnetic Rotating 10.0 65 4.0 620 1380.0 1280.0 100.0 90.00 89.00 89.00 2040.60 0.63 137.93 0.18Control drill 30-50 ft/hr15:20 15:55 2084.00 2115.00 Magnetic Rotating 30.0 80 4.0 620 1560.0 1300.0 260.0 90.00 88.00 89.00Min10.0 40 4.0 463 500.0 200.0 100.0 55.00 54.00 53.00 0.17 54.29 0.03Average21.8 52 5.9 590 1218.3 1019.4 199.0 74.00 73.57 73.62 0.77 151.70 0.23Max30.0 80 9.0 630 1560.0 1300.0 400.0 90.00 89.00 89.00 1.37 178.95 0.56DIRECTIONAL DRILLING PERFORMANCE SUMMARYFootage % DrillRotating2017.00 100%Drilling2017.00 100%AKA N/A Q-301 16in Surface BHABit Run #Repsol N/A2/17/2015Drilling HoursNabors 105 N/A2/19/2015Pumping HoursQugruk WBM2/20/2015BRT HoursQugruk-301 9.8 - 10 Carlos Cretsinger Andrey UuemaaQugruk-301 16.00 Jackie McKinley Barry FergusonObjectives: To drill surface hole to ~ 2095 ft MD with Repsol Geology picking the confirmed casing depth. Maintaining vertical throughout this interval and keeping inclination as per Repsol's request. Results: Aim achieved for the run. No sliding was done throughout this interval as per client request. Finished 25.75' from original plan. 82.33' from Q-3A well with a 1.15 OSF. Trend in rotary for azimuth was between 150 - 175 deg for the entire run. All stabilizers in gauge, motor drained well with no bearing play.Bit Properties & Grading5233591 135Milled Tooth Bit 3x18, 1x16N/ABaker Hughes 0.942Section TDDrill ModeComments Q-301 12.25in Intermediate BHA Steering SheetLocation Casing Sho BHA Run2Client Casing SizeDepth in (ft2115.00Depth out (5428.00Date In47.54Rig Casing WT Incl in (deg0.63Incl out (de89.40Date TD93.47Field Mud TypeAzmth in (d137.93Azmth out 18.26Date out158.08Well End MW (lb Client Rep 1 Lead DDBorehole Hole Size (inClient Rep 2 2nd DDBIT INFORMATIONS/N IADC In Row Out Row Dull Char Location Bearings Gauge Other Reason PulledTYPE Jets (1/32 inIN0 0 NO A X IN NOManuf/Model Name TFA (in2) Out1 2 CT A X IN WTDate TF Angle Start Time End Time MD From MD To TF Mode WOB SRPM Torque FlowSPP On BotPU WeightSlack Off WeighRotating HKLDSvy MD Incl Azmth DLS Commentdd-mmm-yy deg ft ft 1000 lbf c/min 1000 ft.lbf gal/min psi 1000 lbf 1000 lbf 1000 lbf ft deg deg deg/100ft1-Mar-15 18:25 21:30 2115.00 2145.00 Magnetic5.0 60 5.0 505 1150.0 94.00 94.00 94.00 2134.84 0.68 125.71 0.16Drill Float/Shoe Track/30' new formation2-Mar-15 05:35 06:25 2145.00 2234.00 Magnetic10.0 80 6.0 590 1500.0 105.00 98.00 100.00 2229.81 1.57 356.44 2.18DL MWD for Exceed, TF 336, 50% SR06:44 07:43 2234.00 2328.00 Magnetic10.0 80 7.0 590 1500.0 105.00 98.00 100.00 2326.55 3.96 347.80 2.50DL TF 324, 40% SR, Formation Push R08:00 08:33 2328.00 2424.00 Magnetic 5.0 80 5.0 590 1520.0 106.00 102.00 100.00 2422.49 6.61 349.41 2.77DL HS (GTF)08:55 09:50 2424.00 2477.00 Gravity 2.0 80 5.0 590 1530.0 106.00 102.00 100.00ROP < 50 ft/hr, Circ out Gas10:10 11:00 2477.00 2522.00 Gravity 2.0 80 5.0 590 1500.0 106.00 105.00 100.00 2517.50 8.10 350.12 1.57DL 50% SR, Dec TF 12 deg, Formation 11:20 12:00 2522.00 2617.00 Gravity 8.0 80 4.0 590 1520.0 108.00 106.00 106.00 2614.06 10.26 348.56 2.2512:40 13:10 2617.00 2680.00 Gravity 8.0 80 5.0 590 1530.0 108.00 106.00 106.00Dec TF 6 deg, Formation Push R, Circ out 13:25 13:40 2680.00 2712.00 Gravity 8.0 80 5.0 590 1530.0 108.00 107.00 106.00 2709.78 13.17 345.16 3.1213:55 14:35 2712.00 2807.00 Gravity 8.0 80 6.0 590 1550.0 112.00 108.00 110.00 2804.63 16.08 342.53 3.15DL 40% SR14:50 15:50 2807.00 2902.00 Gravity 8.0 80 5.0 590 1525.0 108.00 105.00 106.00 2901.61 17.91 340.74 1.9616:07 16:47 2902.00 2999.00 Gravity 8.0 80 6.0 590 1590.0 109.00 108.00 106.00 2997.48 19.73 339.75 1.93DL 50% SR, Inc TF 12 deg17:09 18:12 2999.00 3095.00 Gravity 8.0 80 6.0 590 1600.0 115.00 107.00 107.00 3092.02 22.55 340.76 3.01DL TF 12 deg, 60% SR, Inc TF 6 deg18:31 19:48 3095.00 3191.00 Gravity 8.0 80 6.0 590 1605.0 115.00 107.00 107.00 3187.55 25.12 341.87 2.73DL TF 24 deg20:05 21:20 3191.00 3287.00 Gravity 8.0 80 6.0 590 1610.0 116.00 107.00 108.00 3282.26 27.93 349.26 4.57DL TF 36 deg, 70%SR, 48 deg, 80%SR21:42 22:50 3287.00 3382.00 Gravity 8.0 100 6.0 595 1620.0 116.00 108.00 109.00 3377.30 30.28 353.59 3.32DL TF 60 deg, DL TF 24 deg, 60% SR23:15 00:05 3382.00 3477.00 Gravity 7.0 120 6.0 600 1650.0 117.00 109.00 110.00 3472.92 33.68 357.52 4.17DL SR 80%3-Mar-15 00:20 01:15 3477.00 3573.00 Gravity 7.0 120 6.0 600 1670.0 117.00 110.00 111.00 3568.99 37.42 3.22 5.20DL TF 36 deg, 70% SR01:35 02:35 3573.00 3668.00 Gravity 7.0 120 7.0 600 1690.0 120.00 110.00 113.00 3664.95 40.71 5.93 3.86DL 80% SR10:12 11:45 3668.00 3757.00 Gravity 8.0 120 6.0 600 1690.0 121.00 110.00 114.00Lost Rig Floor Power12:12 13:43 3757.00 3859.00 Gravity 8.0 120 7.0 600 1700.0 118.00 110.00 114.00 3857.14 47.05 13.29 3.61DL 70% SR14:15 16:00 3859.00 3956.00 Gravity 7.0 125 8.0 600 1700.0 120.00 110.00 113.00 3953.49 50.44 15.35 3.87DL TF 24 deg16:20 19:12 3956.00 4050.00 Gravity 9.0 125 11.0 600 1710.0 120.00 108.00 112.00 4047.39 52.60 17.05 2.70DL 50% SR, Hard Formation20:00 22:18 4050.00 4147.00 Gravity 10.0 120 12.0 600 1700.0 120.00 106.00 111.00 4143.67 55.77 17.03 3.29DL TF 6 deg, 70% SR, Hard Formation4-Mar-15 05:05 08:15 4147.00 4242.00 Gravity 9.0 120 8.0 600 1750.0 124.00 106.00 111.00 4238.08 59.17 17.82 3.67Lost Rig Floor Power x 3, DL 50% SR08:25 10:12 4242.00 4338.00 Gravity 8.0 120 8.0 600 1750.0 125.00 104.00 111.00 4333.22 61.70 19.48 3.06DL TF HS, 70% and 80% SR10:28 11:50 4338.00 4434.00 Gravity 9.0 120 8.0 600 1770.0 125.00 100.00 112.00 4429.08 64.83 18.45 3.40DL 60% SR12:02 13:34 4434.00 4529.00 Gravity 10.0 120 9.0 600 1790.0 116.00 107.00 109.00 4526.18 67.83 18.20 3.1013:55 15:55 4529.00 4625.00 Gravity 7.0 140 9.0 600 1790.0 114.00 108.00 109.00 4621.74 69.81 19.43 2.39DL 50% to 100% SR, TF Dec 6 deg16:23 17:57 4625.00 4721.00 Gravity 12.0 140 7.0 600 1800.0 125.00 95.00 107.00 4717.52 74.11 20.08 4.54DL 60% to 80% SR, ROP Index to 418:17 20:16 4721.00 4817.00 Gravity 5.0 140 12.0 600 1800.0 127.00 93.00 109.00 4813.13 76.52 18.46 3.01TF Dec 6 deg, SR 80%21:10 23:20 4817.00 4912.00 Gravity 4.0 140 13.0 600 1815.0 125.00 96.00 109.00 4911.01 80.54 19.78 4.31DL 90% SR23:40 02:20 4912.00 5008.00 Gravity 5.0 140 13.0 600 1795.0 122.00 98.00 108.00 5007.05 84.22 17.96 4.27AKA 2107.00 Q-301 12.25in Intermediate BHABit Run #Repsol 13.38 2/27/2015Drilling HoursNabors 105 68.00 3/5/2015Pumping HoursQugruk MOBM 3/6/2015BRT HoursQugruk-301 10.40 Sidney Self Barry FergusonQugruk-301 12.25 David Dunbar Jeff PickeringBit Properties & GradingE171034PDC 2x15, 3x14N/ANOV (Hycalog) 0.796TD 5-Mar-15 02:55 05:10 5008.00 5105.00 Gravity 6.0 140 12.0 600 1810.0 125.00 90.00 106.00 5102.59 86.86 17.33 2.84DL 70% to 65% SR05:30 06:40 5105.00 5195.00 Gravity 8.0 140 14.0 600 1825.0 123.00 75.00 105.00 5150.48 88.40 18.26 3.76DL 70% SR, HIA (89.2 Inc) - off btm07:02 07:10 5195.00 5199.00 Gravity 8.0 140 14.0 600 1825.0 123.00 75.00 105.0007:40 07:50 5199.00 5203.00 Gravity 8.0 140 14.0 600 1825.0 123.00 75.00 105.0008:20 09:05 5203.00 5247.00 Gravity 8.0 140 14.0 600 1825.0 123.00 75.00 105.00DL Inc Inc 0.5 + 0.2 (90.0 Inc) off btm09:48 09:50 5247.00 5248.00 Gravity 8.0 140 14.0 600 1825.0 123.00 75.00 105.00 5248.00 90.00 19.50 2.085248 survey - projection to bitMin2.0 60 4.0 505 1150.0 94.00 75.00 94.00 0.68 3.22 0.16Average7.5 109 8.2 594 1663.7 116.23 100.33 107.15 43.20 160.18 3.10Max12.0 140 14.0 600 1825.0 127.00 110.00 114.00 90.00 357.52 5.20DIRECTIONAL DRILLING PERFORMANCE SUMMARYFootage % DrillRotating3313.00 100%Drilling3313.00 100%Objective: To directionally drill 3D intermediate curve section. Kick off at ~ 2145 ft MD and land at ~ 5250 ft MD with 90 deg inclination and 20 deg azimuth. Results: Started run 25 ft, 180 deg opposite of plan from surface section. Trend through out run was formation push right for tendency. Getting back to plan with formation tendency made it challenging to steer away from ZOE. Landed at 5248 ft, 90 deg inclination and 19.5 degree azimuth. Finished 1.74 ft above plan and 30.81 ft right of plan. TF control was problematic at times due to excessive stickslip thus the Xceed steering ratio had to be increased to compensate. At 90% SR yielded ~ 4 deg/100 ft. Stabilizer placement and bit selection for any future BHA may improve downhole torque and stickslip issues.Drill ModeComments Q-301 8.5in Clean Out BHA Steering SheetLocation Casing Sho BHA Run3Client Casing SizeDepth in (ft5248.00Depth out (5278.00Date In0.50Rig Casing WT (Incl in (deg89.40Incl out (de89.40Date TD11.50Field Mud TypeAzmth in (d18.26Azmth out 18.26Date out63.25Well End MW (lbmClient Rep 1 Lead DDBorehole Hole Size (inClient Rep 2 2nd DDBIT INFORMATIONS/N IADC In Row Out Row Dull Char Location Bearings Gauge Other Reason PulledTYPE Jets (1/32 inIN00NOAEIN NOManuf/Model Name TFA (in2) Out11WTAEIN NODate Start Time End Time MD From MD To TF Mode WOB SRPM Torque FlowSPP On BotPU WeightSlack Off WeighRotating HKLDComment Svy MD InclAzmth DLSdd-mmm-yy ft ft 1000 lbfc/min 1000 ft.lbfgal/min psi 1000 lbf1000 lbf1000 lbfft deg deg deg/100ft14-Mar-15 03:30 04:00 5248.00 5278.00 Gravity 15.0 50 7.5 400 1200.0 95.00 90.00 93.00(5248' survey is projecton to bit)5248.00 90.00 19.50 2.08Min15.0 50 7.5 400 1200.0 95.00 90.00 93.00 90.00 19.50 2.08Average15.0 50 7.5 400 1200.0 95.00 90.00 93.00 90.00 19.50 2.08Max15.0 50 7.5 400 1200.0 95.00 90.00 93.00 90.00 19.50 2.08DIRECTIONAL DRILLING PERFORMANCE SUMMARYFootage Hrs % DrillDrilling30.00 0.50 100%30.00 0.50 100%Objectives: Drill out the DV Tool bomb. Casing test. Drill out float, cement and shoe track. Drill 30 ft of new formation and perform FIT. Results: Drilled out the DV tool bomb, RIH. Displaced mud, performed CIT @ 4500 psi. Drilled out shoe track. Drilled 30 ft of new formation, performed FIT to 12 ppg equivalent.Bit Properties & Grading5251184Mill Tooth 1x16, 3x18Hughes/VM-3 0.942TDDrill ModeCommentsQugruk-301 9.30 Sidney Self Jeff PickeringQugruk-301 8.50 Jackie McKinleyAndrey UuemaaNabors 105 47.003/14/2015 4:00Pumping HoursQugruk SOBM3/14/2015 17:15BRT HoursAKA 5241.00 Q-301 8.5in Clean Out BHABit Run #Repsol 9.633/12/2015 2:00Drilling Hours Q-301 6.5in Production BHA Steering SheetLocation Casing Sho BHA Run4Client Casing SizeDepth in (ft5278.00Depth out (7531.00Date In21.25Rig Casing WT Incl in (deg89.40Incl out (de90.93Date TD42.71Field Mud TypeAzmth in (d18.26Azmth out 18.89Date out69.10Well End MW (lb Client Rep 1 Lead DDBorehole Hole Size (inClient Rep 2 2nd DDBIT INFORMATIONS/N IADC In Row Out Row Dull Char Location Bearings Gauge Other Reason PulledTYPE Jets (1/32 inIN0 0 NO A X IN NOManuf/Model Name TFA (in2) Out1 1 BU A X IN BTDate Start Time End Time MD From MD To TF Mode WOB SRPM Torque FlowSPP On BotPU WeightSlack Off WeighRotating HKLDComment Svy MD Incl Azmth DLSdd-mmm-yy ft ft 1000 lbf c/min 1000 ft.lbf gal/min psi 1000 lbf 1000 lbf 1000 lbf ft deg deg deg/100ft16-Mar-15 00:25 01:15 5278.00 5351.00 Gravity 5.0 80 6.0 268 2020.0 95.00 90.00 93.00DL 2-17; IH=90.45312.94 90.65 19.74 1.2301:30 02:01 5351.00 5395.00 Gravity 5.0 80 6.0 268 2020.0 95.00 90.00 93.00DL 2-20; IH=90.4, 12.5% left5359.69 90.76 18.96 1.6802:30 03:00 5395.00 5446.00 Gravity 5.0 80 6.0 268 2020.0 95.00 90.00 93.00DL 2-17; IH=90.4, NO TURN5408.85 90.45 18.43 1.2503:30 04:00 5446.00 5490.00 Gravity 5.0 100 6.0 268 2050.0 100.00 95.00 94.00DL 2-18 x 2; IH=90.4 25% right5453.17 90.41 17.91 1.1804:25 04:55 5490.00 5541.00 Gravity 5.0 100 6.0 268 2050.0 100.00 95.00 94.00 5504.94 90.72 18.57 1.4107:00 07:30 5541.00 5588.00 Gravity 5.0 100 6.0 268 2050.0 100.00 95.00 94.00 5553.25 90.48 19.22 1.4308:00 08:20 5588.00 5637.00 Gravity 5.0 100 6.0 268 2050.0 104.00 96.00 95.00DL IH More Left (90.4, 12.5% right)5600.80 90.79 19.40 0.7508:50 09:15 5637.00 5692.00 Gravity 5.0 100 6.0 268 2050.0 105.00 96.00 95.00DL IH No Correcton (90.4)5654.47 90.72 19.23 0.3409:30 09:50 5692.00 5733.00 Gravity 8.0 110 7.0 268 2050.0 105.00 96.00 95.00DL IH More Ring (12.5% right)5696.41 90.38 19.06 0.9110:00 10:15 5733.00 5767.00 Gravity 8.0 110 7.0 268 2050.0 105.00 96.00 95.0010:20 10:45 5767.00 5828.00 Gravity 3.0 110 6.0 268 2020.0 105.00 96.00 95.00DL Nudge 1/2 degree (90.9)5792.46 90.99 20.21 1.3610:55 11:35 5828.00 5924.00 Gravity 4.0 110 7.0 268 2050.0 105.00 96.00 95.00 5888.06 91.27 20.09 0.3211:45 12:30 5924.00 6019.00 Gravity 4.0 100 7.0 268 2050.0 105.00 96.00 95.00DL IH No correction (90.9)5985.60 91.27 20.49 0.4112:45 13:40 6019.00 6115.00 Gravity 5.0 100 7.0 268 2055.0 110.00 94.00 97.00 6078.80 90.99 19.75 0.8513:50 14:50 6115.00 6211.00 Gravity 7.0 110 8.0 272 2200.0 113.00 96.00 97.00 6173.33 91.06 19.90 0.1815:00 15:50 6211.00 6307.00 Gravity 7.0 110 8.0 272 2200.0 113.00 96.00 97.00 6267.70 90.96 20.07 0.2116:00 17:15 6307.00 6402.00 Gravity 5.0 110 7.0 272 2200.0 113.00 96.00 97.00 6362.80 91.13 19.65 0.4817:25 18:35 6402.00 6498.00 Gravity 5.0 110 7.0 272 2200.0 115.00 96.00 98.00 6460.51 90.93 19.84 0.2818:45 19:56 6498.00 6594.00 Gravity 5.0 110 7.0 272 2200.0 115.00 96.00 98.00 6557.05 90.93 19.37 0.4920:11 21:20 6594.00 6689.00 Gravity 5.0 110 7.0 272 2200.0 115.00 86.00 98.00 6651.66 91.17 19.14 0.3521:35 22:40 6689.00 6785.00 Gravity 6.0 110 7.0 272 2210.0 115.00 86.00 98.00 6746.17 91.30 19.38 0.2922:55 23:55 6785.00 6881.00 Gravity 6.0 110 7.0 272 2210.0 121.00 81.00 94.00 6843.67 91.07 21.11 1.7917-Mar-15 00:12 01:27 6881.00 6976.00 Gravity 6.0 110 7.0 272 2210.0 121.00 81.00 94.00 6938.05 91.24 19.57 1.6401:35 02:45 6976.00 7073.00 Gravity 6.0 110 7.0 272 2210.0 115.00 88.00 95.00 7035.52 91.10 20.34 0.8002:52 04:00 7073.00 7168.00 Gravity 6.0 110 7.0 272 2210.0 115.00 88.00 95.00 7131.48 90.93 20.07 0.3304:08 05:20 7168.00 7264.00 Gravity 6.0 110 7.0 272 2210.0 115.00 88.00 95.00 7227.03 91.03 19.78 0.3205:45 06:55 7264.00 7359.00 Gravity 7.0 110 9.0 272 2210.0 105.00 90.00 100.00 7321.66 91.20 17.11 2.8307:05 08:15 7359.00 7455.00 Gravity 9.0 110 10.0 272 2250.0 107.00 90.00 100.00 7417.21 90.96 18.25 1.2208:25 09:30 7455.00 7531.00 Gravity 3.0 120 8.0 285 2400.0 108.00 90.00 100.00 DL @ TD (PD 0/0, MWD Record Mode rate fast)7531.00 90.93 18.89 0.00Min3.0 80 6.0 268 2020.0 95.00 81.00 93.00 90.38 17.11 0.00Average5.6 105 7.0 271 2134.7 108.10 92.03 95.83 90.92 19.41 0.87Max9.0 120 10.0 285 2400.0 121.00 96.00 100.00 91.30 21.11 2.83DIRECTIONAL DRILLING PERFORMANCE SUMMARYFootage Hrs ROP % DrillRotating2253.00 24.27 92.8 100%Drilling2253.00 24.27 92.8 100%Objectives: Drill lateral production section mainting 91 inclination and 20 azimuth until TD @ 7531' MD, 4149' TVD. Results: BHA held azimuth (~20) well while in inclination hold at 90.4 and 90.9 inclination. Surveys had to be DMAG corrected, surveys after 7200' were affected by a solar storm, no GMAG correction was applied. Survey stations 7227 and 7495 were retaken after wiper trip when the solar storm had decreased in intensity. Bit and stablizers were moderately balled up on surface, 2 broken cutters on shoulder of bit.Bit Properties & GradingA210931 M332PDC 2x9, 3x10NOV/PDC 0.354TDDrill ModeCommentsQugruk-301 9.30 Sidney Self Jeff PickeringQugruk-301 6.50 Jackie McKinley Andrey UuemaaNabors 105 47.002015-03-17 09:30Pumping HoursQugruk SOBM3/18/2015 9:10BRT HoursAKA 5241.00 Q-301 6.5in Production BHABit Run #Repsol 9.633/15/2015 12:25Drilling Hours Section 5 Directional Surveys Qugruk 301 Section 6 Directional Plots Qugruk 301 Borehole:Well:Field:Structure: Qugruk-301 Qugruk-301 Qugruk Qugruk-301 Gravity & Magnetic Parameters Surface Location NAD27 Alaska State Plane, Zone 04, US Feet Miscellaneous Model: BGGM 2014 Dip: 80.829° Date: 19-Feb-2015 MagDec: 18.569° FS: 57549.403nT Gravity FS: 1002.002mgn (9.80665 Based) Lat: N 70 20 3.01 Northing: 5972299.03ftU S Grid Conv: -0.665° Lon: W 150 42 22.19 Easting: 412953.93ftUS Scale Fact: 0.99990861 Slot: Qugruk-301 TVD Ref: Rotary Table(37ft above MSL) Plan: Qugruk-301 0 500 1000 1500 2000 2500 3000 3500 4000 0 500 1000 1500 2000 2500 3000 3500 4000 4500 0 500 1000 1500 2000 2500 3000 3500 4000 0 500 1000 1500 2000 2500 3000 3500 4000 4500 Vertical Section (ft) Azim = 20° Scale = 1:650(ft) Origin = 0N/-S, 0E/-WTVD (ft) Scale = 1:650(ft)Qugruk-301 13-3/8" 2107 MD 9-5/8" 5241 MD Liner Hanger 4553 MD Qugruk-301 (P16) update Borehole:Well:Field:Structure: Qugruk-301 Qugruk-301 Qugruk Qugruk-301 Gravity & Magnetic Parameters Surface Location NAD27 Alaska State Plane, Zone 04, US Feet Miscellaneous Model: BGGM 2014 Dip: 80.829° Date: 19-Feb-2015 MagDec: 18.569° FS: 57549.403nT Gravity FS: 1002.002mgn (9.80665 Based) Lat: N 70 20 3.01 Northing: 5972299.03ftU S Grid Conv: -0.665° Lon: W 150 42 22.19 Easting: 412953.93ftUS Scale Fact: 0.99990861 Slot: Qugruk-301 TVD Ref: Rotary Table(37ft above MSL) Plan: Qugruk-301 -1350 -900 -450 0 450 900 1350 1800 2250 0 450 900 1350 1800 2250 2700 3150 3600 4050 -1350 -900 -450 0 450 900 1350 1800 2250 0 450 900 1350 1800 2250 2700 3150 3600 4050 EW (ft) Scale = 1:600(ft)NS (ft) Scale = 1:600(ft)Qugruk-301 13-3/8" 2107 MD 2107 TVD 9-5/8" 5241 MD 4185 TVD Liner Hanger 4553 MD 4064 TVD Qugruk-301 (P16) update Section 7 KPIs Qugruk 301 Borehole:Well:Field:Structure:Qugruk-301Qugruk-301QugrukQugruk-301Gravity & Magnetic ParametersSurface Location NAD27 Alaska State Plane, Zone 04, US FeetMiscellaneousModel: BGGM 2014 Dip: 80.829° Date:19-Feb-2015MagDec: 18.569° FS: 57549.403nT Gravity FS: 1002.002mgn (9.80665 Based)Lat: N 70 20 3.01 Northing: 5972299.03ftUS Grid Conv: -0.665°Lon: W 150 42 22.19 Easting: 412953.93ftUS Scale Fact: 0.99990861Slot: Qugruk-301 TVD Ref: Rotary Table(37ft above MSL)Plan: Qugruk-30102040608010009501900285038004750570066507600INCLINATION (deg)MD (ft)Qugruk-301Qugruk-301 (P16) update05010015020025030035009501900285038004750570066507600AZIMUTH (deg)MD (ft)Qugruk-301Qugruk-301 (P16) update-0.700.71.42.12.83.54.24.95.609501900285038004750570066507600DOGLEG SEVERITY (deg)MD (ft)Qugruk-301Qugruk-301 (P16) update02040608010012009501900285038004750570066507600TORTUOSITY (deg)MD (ft)Qugruk-301Qugruk-301 (P16) update Section 8 MWD Depth Control Reports Qugruk 301 Rev 2.1 01-July-2013 Date Job no. Well Number Field Run # RMS Sensor RMS Sensor Type N/A N/A Serial Number N/A N/A Fill out an exemption request on QUEST and give its reference in this section if any of the following is true: 1. Depth reference is not Driller's Pipe Tally 2. Depth measurement data is obtained from third party for any reason. 3. If block height calibration system is using any method other than DWC calibrator. 16/Feb/15 16/Feb/15 16/Feb/15 Comments: FSM Joey Leblanc Email jleblanc@slb.com Telephone 907-231-9315 Qugruk 301 WOA Depth Reference Depth System Depth Reference Plan DWE LWD001 Further queries may be directed to: Client Representative: All depth-tracking queries should be directed to the cell manager for clarification Geologist: From - To Exemption Request Reference Valid fromDescriptionQuest Valid till Description HSPM Version 2014 CLT Maxwell Version Hookload sensor 16-Feb-2015 Permanent Depth Datum Reference Rotary Table Driller's Pipe Tally Stand length ~95ft Acquisition System Well Reference Point Zones of Interest ( As per Geologist Advice) N/A Pre-Run Depth Control Report Job Information 14AKA0170 MSL Hole Size D&M-SQ-S016 D&M Depth Control Standard Version 1.2 08-Apr-2013Controlling Document 16.00 in K. Antonini / M. KalimullinaD&M Cell Manager: N/A DWE-IS38 Depth EncoderGeolograph 19_1C_00 MAXWELL SYSTEM INFORMATION TOOLSTRING DESCRIPTION:LWD001 TOOLNAME LENGTH OD ID MAX_OD WEIGHT VOLUME CUMM_LEN CUMM_WT SERIAL_NUMBER ft in in in lbm ft3 ft lbm ========================================================================================================== Generic Milled Tooth Bit: 1.45 8.500 0.000 16.000 0.00 1.45 0.00 5233591 Motor: 8 1/4" : 29.35 8.375 6.250 4712.73 30.80 2137.66 1243 NM Stab: 8 1/4" : 8.04 8.313 2.875 1447.20 38.84 2794.10 SD 603876 ARC8 : 20.98 8.250 5.750 9.100 2550.00 3.69 59.82 3950.76 ZL2958 TELE825 : 27.33 8.410 4.250 8.410 3885.00 10.48 87.15 5712.96 E1166 NM Stab: 8 1/4" : 8.02 8.313 2.875 1443.60 95.17 6367.77 SD 603875 ---------------------------- | Sensor Offsets | ---------------------------- TOOLNAME Sensor [To Bit] [To Reference] ==================================================================== ARC8 : Pressure 46.24 ft 6.00 ft ARC8 : Resistivity 48.57 ft 3.67 ft ARC8 : GR 48.74 ft 3.50 ft TELE825 : Vibration 68.63 ft -4.42 ft TELE825 : D&I 71.92 ft -7.71 ft TOOLNAME Refpoint [To Tool Btm] [To Bit] ==================================================================== ARC8 : ROP 13.40 ft 52.24 ft TELE825 : ROP 4.39 ft 64.21 ft BHA Report Depth In Date In Total Depth Date Out MXW Stand Stand Drill Pipe Total String Stick Hole HSPM Block Delta BLK_POB_DEPTH Time Number Length Length Length Up Depth Depth Position depth Offset Offset Comment 0.00 BHA Length 187.55 0.00 187.55 187.55 187.55 0.00 10:41 HWDP 1 91.86 91.86 279.41 279.41 279.84 0.43 HWDP 2 91.86 91.86 371.27 1.50 369.77 368.64 -1.13 NC, will check on TJ 12:58 HWDP 3 91.87 91.87 463.14 1.50 461.64 462.09 0.45 NC, set BD after Trip out 17:44 HWDP 4 + Jar 92.27 92.27 555.41 1.80 553.61 552.56 -1.05 100ft depth change, reset 19:48 HWDP 5 92.28 92.28 647.69 1.50 646.19 651.95 5.76 Checked on TJ, off by 5.44ft, HD-5.44 21:01 1 95.74 95.74 743.43 1.50 741.93 752.93 11.00 Checked on TJ, HD-11ft 22:39 2 95.88 191.62 839.31 1.50 837.81 838.37 0.56 HD-1.77ft, checked on TJ 0:13 3 95.76 287.38 935.07 935.07 937.44 2.37 HD-2.37 at TJ 1:20 4 95.77 383.15 1030.84 1030.84 1034.53 3.69 HD-3.69 at TJ, adjust coef 2:25 5 95.82 478.97 1126.66 1126.66 1123.79 -2.87 HD+2.87 (+4.15 on BU) 3:47 6 95.88 574.85 1222.54 1222.54 1216.80 -5.74 HD+5.74 at TJ, adjust coef 5:34 7 95.7 670.55 1318.24 1318.24 1321.28 3.04 HD+3.04 at TJ, adjust coef 6:21 8 95.54 766.09 1413.78 1413.78 1412.96 -0.82 BD+0.82 at TJ 7:04 9 95.79 861.88 1509.57 1509.57 1507.44 -2.13 BD+1.95 at TJ 8:00 10 95.74 957.62 1605.31 1605.31 1603.19 -2.12 BD+1.5 at TJ, adjust coef 8:53 11 95.75 1053.37 1701.06 1701.06 1705.12 4.06 BD-4.1 at TJ 9:40 12 95.75 1149.12 1796.81 1796.81 1798.86 2.05 BD-2.05 at TJ 10:00 13 95.77 1244.89 1892.58 1892.58 1896.25 3.67 HD-3.67 at TJ 12:48 14 95.94 1340.83 1988.52 1988.52 1988.54 0.02 NC 15:00 15 95.11 1435.94 2083.63 2083.63 2087.02 3.39 HD-3.39 at TJ 16 95.53 1531.47 2179.16 2179.16 0.00 17 95.78 1627.25 2274.94 2274.94 0.00 18 95.83 1723.08 2370.77 2370.77 0.00 19 95.67 1818.75 2466.44 2466.44 0.00 20 95.36 1914.11 2561.80 2561.80 0.00 21 95.64 2009.75 2657.44 2657.44 0.00 22 95.07 2104.82 2752.51 2752.51 0.00 23 95.91 2200.73 2848.42 2848.42 0.00 24 95.8 2296.53 2944.22 2944.22 0.00 25 95.84 2392.37 3040.06 3040.06 0.00 26 95.55 2487.92 3135.61 3135.61 0.00 27 95.86 2583.78 3231.47 3231.47 0.00 28 95.63 2679.41 3327.10 3327.10 0.00 29 95.68 2775.09 3422.78 3422.78 0.00 30 95.53 2870.62 3518.31 3518.31 0.00 31 95.37 2965.99 3613.68 3613.68 0.00 32 95.33 3061.32 3709.01 3709.01 0.00 33 95.86 3157.18 3804.87 3804.87 0.00 34 95.81 3252.99 3900.68 3900.68 0.00 35 95.79 3348.78 3996.47 3996.47 0.00 36 95.61 3444.39 4092.08 4092.08 0.00 37 95.09 3539.48 4187.17 4187.17 0.00 38 95.78 3635.26 4282.95 4282.95 0.00 39 95.77 3731.03 4378.72 4378.72 0.00 40 95.77 3826.80 4474.49 4474.49 0.00 41 95.68 3922.48 4570.17 4570.17 0.00 42 95.82 4018.30 4665.99 4665.99 0.00 43 95.33 4113.63 4761.32 4761.32 0.00 44 95.59 4209.22 4856.91 4856.91 0.00 45 95.71 4304.93 4952.62 4952.62 0.00 46 95.85 4400.78 5048.47 5048.47 0.00 47 95.81 4496.59 5144.28 5144.28 0.00 48 95.83 4592.42 5240.11 5240.11 0.00 49 95.74 4688.16 5335.85 5335.85 0.00 50 95.87 4784.03 5431.72 5431.72 0.00 51 95.73 4879.76 5527.45 5527.45 0.00 52 95.82 4975.58 5623.27 5623.27 0.00 53 95.78 5071.36 5719.05 5719.05 0.00 54 95.83 5167.19 5814.88 5814.88 0.00 LWD001 16-Feb-150.00 . Date Rig Job no.AFE Well Number API Field Lead Eng Run #2nd Eng Maxwell QUEST No.From To Depth System 2014 Type HSPM Serial Number 19_1C_00 From (MD) To (MD)Tool Meas. Tool Meas. ft ft ft ft ft ft Calibration Date 16-Feb-15 Calibration Date 16-Feb-15 GeoService Comments Tool Tool Dump File Time Shifts CommentsTime shift Plot of Time versus Depth for Run Depth Interval Raw Depth txt File Corrections TIme Comments Applied Corrections Calibration ReferenceCalibration Type CLT Sensor Offsets from the BHA DistanceDescription DWE-IS38 Calibrations Used for this Run Hookload Sensor 0 Depth Encoder Distance Zones of Interest ( As per Geologist Advice) 0 Stand length ~95ftDepth Reference Plan Exemptions Description Depth Bin DB File Corrections Driller's Console N/A N/A X3-015N5-C:Drill 50-103-20700-00-00 WOA 14AKA0144 M. Kalimullina S-09A Acquisition System K. Antonini Depth Encoder Hookload Sensor LWD001 Depth System MSL Depth Reference Permanent Depth Datum Reference Well Reference Point Driller's Pipe Tally Rotary Table LWD001 End of Run Depth Control Report 0-Jan-1900 Job Information 16.00 inHole Size D&M-SQ-S016 D&M Depth Control Standard Version 1.2 08-Apr-2013 Parker 273 Controlling Document Rev 2.1 01-July-2013 Date Job no. Well Number Field Run # RMS Sensor RMS Sensor Type N/A N/A Serial Number N/A N/A Fill out an exemption request on QUEST and give its reference in this section if any of the following is true: 1. Depth reference is not Driller's Pipe Tally 2. Depth measurement data is obtained from third party for any reason. 3. If block height calibration system is using any method other than DWC calibrator. 27/Feb/15 27/Feb/15 27/Feb/15 Comments: FSM Joey Leblanc Email jleblanc@slb.com Telephone 907-231-9315 19_1C_00 MAXWELL SYSTEM INFORMATION TOOLSTRING DESCRIPTION:LWD002 TOOLNAME LENGTH OD ID MAX_OD WEIGHT VOLUME CUMM_LEN CUMM_WT SERIAL_NUMBER ft in in in lbm ft3 ft lbm ========================================================================================================== Bit: 12 1/4" : 0.93 8.500 3.750 12.250 145.55 0.93 66.02 E171034 PDXCEED_900 : 28.32 12.125 5.250 12.125 4400.00 33.01 29.25 2061.83 DN9-286 ARC8 : 18.69 8.250 5.750 9.100 2550.00 3.69 47.94 3218.49 E7648 SONICSCOPE8 : 34.04 12.000 4.250 12.000 4836.00 13.40 81.98 5412.06 G8991 TELE825 : 27.30 8.410 4.250 8.410 3885.00 10.50 109.28 7174.27 E1904 ADN8 : 22.13 8.406 4.250 8.406 2600.00 17.67 131.41 8353.61 47516 ---------------------------- | Sensor Offsets | ---------------------------- TOOLNAME Sensor [To Bit] [To Reference] ==================================================================== PDXCEED_900 : D&I 17.62 ft -5.00 ft ARC8 : Pressure 34.73 ft 6.00 ft ARC8 : Resistivity 37.06 ft 3.67 ft ARC8 : GR 37.23 ft 3.50 ft SONICSCOPE8 : Delta-T 68.67 ft 3.96 ft TELE825 : Vibration 92.09 ft -4.42 ft TELE825 : D&I 95.38 ft -7.71 ft ADN8 : UltraSonic 120.11 ft -3.16 ft ADN8 : Density 121.38 ft -4.43 ft ADN8 : Neutron 124.81 ft -7.86 ft TOOLNAME Refpoint [To Tool Btm] [To Bit] ==================================================================== PDXCEED_900 : ROP 11.69 ft 12.62 ft ARC8 : ROP 11.48 ft 40.73 ft SONICSCOPE8 : ROP 24.68 ft 72.62 ft TELE825 : ROP 5.69 ft 87.67 ft ADN8 : ROP 7.67 ft 116.95 ft BHA Report N/A DWE-IS38 Depth EncoderGeolograph K. Antonini / M. KalimullinaD&M Cell Manager: Zones of Interest ( As per Geologist Advice) N/A Pre-Run Depth Control Report Job Information 14AKA0170 MSL Hole Size D&M-SQ-S016 D&M Depth Control Standard Version 1.2 08-Apr-2013Controlling Document 12.25 in27-Feb-2015 Permanent Depth Datum Reference Rotary Table Driller's Pipe Tally Stand length ~95ft Acquisition System Well Reference Point HSPM Version 2014 CLT Maxwell Version Hookload sensor From - To Exemption Request Reference Valid fromDescriptionQuest Valid till Description Further queries may be directed to: Client Representative: All depth-tracking queries should be directed to the cell manager for clarification Geologist: Qugruk 301 WOA Depth Reference Depth System Depth Reference Plan DWE LWD002 Nabors105 Depth In Date In Qugruk 301 Total Depth Date Out MXW Stand Stand Drill Pipe Total String Stick Hole HSPM Block Delta BLK_POB_DEPTH Date Time Number Length Length Length Up Depth Depth Position depth Offset Offset Comment 0.00 BHA Length 702.69 0.00 702.69 702.69 0.00 1 95.74 95.74 798.43 798.43 0.00 28-Feb 15:01 2 95.88 191.62 894.31 894.31 0.00 Set the BD 3 95.76 287.38 990.07 990.07 0.00 4 95.77 383.15 1085.84 1085.84 0.00 5 95.82 478.97 1181.66 1181.66 0.00 6 95.88 574.85 1277.54 1277.54 0.00 7 95.7 670.55 1373.24 1373.24 0.00 8 95.54 766.09 1468.78 1468.78 0.00 9 95.79 861.88 1564.57 1564.57 0.00 10 95.74 957.62 1660.31 1660.31 0.00 11 95.75 1053.37 1756.06 1756.06 0.00 12 95.75 1149.12 1851.81 1851.81 0.00 1-Mar 7:23 13 95.77 1244.89 1947.58 1947.58 0.00 Set the BD 19:27 14 95.94 1340.83 2043.52 2043.52 0.00 20:56 15 95.11 1435.94 2138.63 4.00 2134.63 2133.60 -1.03 Reset HD, Change Coefficient 2-Mar 6:48 16 95.53 1531.47 2234.16 2234.16 2231.28 -2.88 HD+2.88 8:04 17 95.78 1627.25 2329.94 2329.94 2329.31 -0.63 BU HD+1.42, PR HD+0.63 9:13 18 95.83 1723.08 2425.77 2425.77 2423.60 -2.17 HD+2.17 11:20 19 95.67 1818.75 2521.44 2521.44 2521.26 -0.18 Set BP, Set HD 12:31 20 95.36 1914.11 2616.80 2616.80 2616.60 -0.20 Set BP, Set HD 13:50 21 95.64 2009.75 2712.44 2712.44 2712.59 0.15 Set BP, Set HD 14:47 22 95.07 2104.82 2807.51 2807.51 2808.25 0.74 Set BP, Set HD 15:54 23 95.91 2200.73 2903.42 2903.42 2903.20 -0.22 Set BP, HD+.22 16:53 24 95.8 2296.53 2999.22 2999.22 3000.26 1.04 Set BP, HD-1.04 18:32 25 95.84 2392.37 3095.06 3095.06 3096.17 1.11 HD-1.11 PR, -1.25 BU 20:08 26 95.55 2487.92 3190.61 3190.61 3191.99 1.38 HD-1.38 21:40 27 95.86 2583.78 3286.47 3286.47 3286.30 -0.17 NC 23:18 28 95.63 2679.41 3382.10 3382.10 3381.99 -0.11 NC 3-Mar 0:24 29 95.68 2775.09 3477.78 3477.78 3477.57 -0.21 NC 1:41 30 95.53 2870.62 3573.31 3573.31 3573.32 0.01 NC 10:21 31 95.37 2965.99 3668.68 3668.68 3669.07 0.39 NC 12:07 32 95.33 3061.32 3764.01 3764.01 3765.10 1.09 HD-1.1ft 14:13 33 95.86 3157.18 3859.87 3859.87 3859.36 -0.51 NC 16:19 34 95.81 3252.99 3955.68 3955.68 3955.01 -0.67 HD+0.67 20:08 35 95.79 3348.78 4051.47 4051.47 4051.32 -0.15 NC 4-Mar 5:04 36 95.61 3444.39 4147.08 4147.08 4147.33 0.25 NC 8:28 37 95.09 3539.48 4242.17 4242.17 4243.26 1.09 HD -1.0 PR, BU 10:29 38 95.78 3635.26 4337.95 4337.95 4338.21 0.26 NC 12:12 39 95.77 3731.03 4433.72 4433.72 4434.02 0.30 NC 13:55 40 95.77 3826.80 4529.49 4529.49 4529.35 -0.14 NC 16:24 41 95.68 3922.48 4625.17 4625.17 4625.51 0.34 NC 18:20 42 95.82 4018.30 4720.99 4720.99 4721.48 0.49 NC-in a payzone 21:11 43 95.33 4113.63 4816.32 4816.32 4817.60 1.28 NC-in a payzone 23:41 44 95.59 4209.22 4911.91 4911.91 4913.65 1.74 NC-in a payzone 5-Mar 2:53 45 95.71 4304.93 5007.62 5007.62 5009.62 2.00 NC-in a payzone 5:31 46 95.85 4400.78 5103.47 5103.47 5105.46 1.99 NC-in a payzone 7:38 47 95.81 4496.59 5199.28 5199.28 5201.31 2.03 NC-in a payzone 48 95.83 4592.42 5295.11 5295.11 0.00 49 95.74 4688.16 5390.85 5390.85 0.00 50 95.87 4784.03 5486.72 5486.72 0.00 51 95.73 4879.76 5582.45 5582.45 0.00 52 95.82 4975.58 5678.27 5678.27 0.00 53 95.78 5071.36 5774.05 5774.05 0.00 54 95.83 5167.19 5869.88 5869.88 0.00 LWD002 27-Feb-152115.00 Rev 2.1 01-July-2013 Date Job no. Well Number Field Run # RMS Sensor RMS Sensor Type N/A N/A Serial Number N/A N/A Fill out an exemption request on QUEST and give its reference in this section if any of the following is true: 1. Depth reference is not Driller's Pipe Tally 2. Depth measurement data is obtained from third party for any reason. 3. If block height calibration system is using any method other than DWC calibrator. 15/Mar/15 15/Mar/15 15/Mar/15 Comments: FSM Joey Leblanc Email jleblanc@slb.com Telephone 907-231-9315 19_1C_00 BHA Report N/A DWE-IS38 Depth EncoderGeolograph M. KalimullinaD&M Cell Manager: Zones of Interest ( As per Geologist Advice) N/A Pre-Run Depth Control Report Job Information 14AKA0170 MSL Hole Size D&M-SQ-S016 D&M Depth Control Standard Version 1.2 08-Apr-2013Controlling Document 6.50 in15-Mar-2015 Permanent Depth Datum Reference Rotary Table Driller's Pipe Tally Stand length ~95ft Acquisition System Well Reference Point HSPM Version 2014 CLT Maxwell Version Hookload sensor From - To Exemption Request Reference Valid fromDescriptionQuest Valid till Description Further queries may be directed to: Client Representative: All depth-tracking queries should be directed to the cell manager for clarification Geologist: Qugruk 301 WOA Depth Reference Depth System Depth Reference Plan DWE LWD003 Nabors105 Depth In Date In Qugruk 301 Total Depth Date Out MXW Stand Stand Drill Pipe Total String Stick Hole HSPM Block Delta BLK_POB_DEPTH Date Time Number Length Length Length Up Depth Depth Position depth Offset Offset Comment 0.00 BHA Length 262.30 0.00 262.30 262.30 0.00 1 96.33 96.33 358.63 358.63 0.00 2 96.12 192.45 454.75 454.75 0.00 3 96.57 289.02 551.32 551.32 0.00 4 96.37 385.39 647.69 647.69 0.00 5 95.98 481.37 743.67 743.67 0.00 6 96.21 577.58 839.88 839.88 0.00 7 96.07 673.65 935.95 935.95 0.00 8 96.12 769.77 1032.07 1032.07 0.00 9 96.22 865.99 1128.29 1128.29 0.00 10 96.37 962.36 1224.66 1224.66 0.00 11 96.37 1058.73 1321.03 1321.03 0.00 12 96.38 1155.11 1417.41 1417.41 0.00 13 96.05 1251.16 1513.46 1513.46 0.00 15-Mar 14 96.33 1347.49 1609.79 1609.79 0.00 Set BD before SHT 15 96.55 1444.04 1706.34 1706.34 0.00 16 96.33 1540.37 1802.67 1802.67 0.00 17 96.24 1636.61 1898.91 1898.91 0.00 18 96.51 1733.12 1995.42 1995.42 0.00 19 96.11 1829.23 2091.53 2091.53 0.00 20 95.96 1925.19 2187.49 2187.49 0.00 21 96.38 2021.57 2283.87 2283.87 0.00 22 96.44 2118.01 2380.31 2380.31 0.00 23 99.82 2217.83 2480.13 2480.13 0.00 24 95.74 2313.57 2575.87 2575.87 0.00 25 95.88 2409.45 2671.75 2671.75 0.00 26 95.76 2505.21 2767.51 2767.51 0.00 27 95.77 2600.98 2863.28 2863.28 0.00 28 95.82 2696.80 2959.10 2959.10 0.00 29 95.88 2792.68 3054.98 3054.98 0.00 30 95.7 2888.38 3150.68 3150.68 0.00 31 95.54 2983.92 3246.22 3246.22 0.00 32 95.79 3079.71 3342.01 3342.01 0.00 33 95.74 3175.45 3437.75 3437.75 0.00 34 95.75 3271.20 3533.50 3533.50 0.00 35 95.75 3366.95 3629.25 3629.25 0.00 36 95.77 3462.72 3725.02 3725.02 0.00 37 95.94 3558.66 3820.96 3820.96 0.00 38 95.11 3653.77 3916.07 3916.07 0.00 39 95.53 3749.30 4011.60 4011.60 0.00 40 95.78 3845.08 4107.38 4107.38 0.00 41 95.83 3940.91 4203.21 4203.21 0.00 42 95.67 4036.58 4298.88 4298.88 0.00 43 95.36 4131.94 4394.24 4394.24 0.00 44 95.64 4227.58 4489.88 4489.88 0.00 45 95.07 4322.65 4584.95 4584.95 0.00 46 95.91 4418.56 4680.86 4680.86 0.00 47 95.8 4514.36 4776.66 4776.66 0.00 48 95.84 4610.20 4872.50 4872.50 0.00 49 95.55 4705.75 4968.05 4968.05 0.00 50 95.86 4801.61 5063.91 5063.91 0.00 15-Mar 23:16 51 95.63 4897.24 5159.54 5159.54 5159.54 0.00 Set BD at the TJ 23:52 52 95.68 4992.92 5255.22 5255.22 5257.29 2.07 BD-2.07, adjusted cal coefficient 16-Mar 1:37 53 95.53 5088.45 5350.75 5350.75 5350.90 0.15 NC 3:42 54 95.37 5183.82 5446.12 5446.12 5446.46 0.34 NC 7:07 55 95.33 5279.15 5541.45 5541.45 5543.55 2.10 NC, payzone 8:48 56 95.86 5375.01 5637.31 5637.31 5638.71 1.40 NC, payzone 10:01 57 95.81 5470.82 5733.12 5733.12 5734.39 1.27 NC, payzone 10:55 58 95.79 5566.61 5828.91 5828.91 5829.85 0.94 NC, payzone 11:49 59 95.61 5662.22 5924.52 5924.52 5925.50 0.98 NC, payzone 12:49 60 95.09 5757.31 6019.61 6019.61 6021.43 1.82 NC, payzone 13:52 61 95.78 5853.09 6115.39 6115.39 6116.37 0.98 NC, payzone 15:00 62 95.77 5948.86 6211.16 6211.16 6211.11 -0.05 NC, payzone 16:03 63 95.77 6044.63 6306.93 6306.93 6305.45 -1.48 NC, payzone 17:25 64 95.68 6140.31 6402.61 6402.61 6401.92 -0.69 NC, payzone 18:49 65 95.82 6236.13 6498.43 6498.43 6497.94 -0.49 NC, payzone 20:15 66 95.33 6331.46 6593.76 6593.76 6595.06 1.30 NC, payzone 21:37 67 95.59 6427.05 6689.35 6689.35 6689.21 -0.14 NC, payzone 22:57 68 95.71 6522.76 6785.06 6785.06 6783.92 -1.14 NC, payzone 0:14 69 95.85 6618.61 6880.91 6880.91 6879.54 -1.37 NC,payzone 1:37 70 95.81 6714.42 6976.72 6976.72 6975.08 -1.64 NC, payzone 2:54 71 95.83 6810.25 7072.55 7072.55 7072.49 -0.06 NC,payzone 4:12 72 95.74 6905.99 7168.29 7168.29 7168.39 0.10 NC, payzone 5:49 73 95.87 7001.86 7264.16 7264.16 7263.96 -0.20 NC, payzone 7:09 74 95.73 7097.59 7359.89 7359.89 7359.63 -0.26 NC, payzone 8:29 75 95.82 7193.41 7455.71 7455.71 7455.31 -0.40 NC, payzone 76 95.78 7289.19 7551.49 7551.49 0.00 77 95.83 7385.02 7647.32 7647.32 0.00 LWD003 15-Mar-152115.00 . Date Rig Job no.AFE Well Number API Field Lead Eng Run #2nd Eng Maxwell QUEST No.From To Depth System 2014 Type HSPM Serial Number 19_1C_00 From (MD) To (MD)Tool Meas. Tool Meas. ft ft ft ft ft ft Calibration Date 15-Mar-15 Calibration Date 15-Mar-15 GeoService Comments Tool LWD003 End of Run Depth Control Report 0-Jan-1900 Job Information 6.50 inHole Size D&M-SQ-S016 D&M Depth Control Standard Version 1.2 08-Apr-2013 Parker 273 Controlling Document MSL Depth Reference Permanent Depth Datum Reference Well Reference Point Driller's Pipe Tally Rotary Table Acquisition System K. Antonini Depth Encoder Hookload Sensor LWD003 Depth System X3-015N5-C:Drill 50-103-20700-00-00 WOA 14AKA0144 M. Kalimullina S-09A Depth Bin DB File Corrections Driller's Console N/A N/A Stand length ~95ftDepth Reference Plan Exemptions Description Calibrations Used for this Run Hookload Sensor 0 Depth Encoder Distance Zones of Interest ( As per Geologist Advice) 0 CLT Sensor Offsets from the BHA DistanceDescription DWE-IS38 Depth Interval Raw Depth txt File Corrections TIme Comments Applied Corrections Calibration ReferenceCalibration Type Plot of Time versus Depth for Run Tool Dump File Time Shifts CommentsTime shift CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Well Test Report Wednesday, 15th April 2015, 03:00 hrs Repsol E&P USA Qugruk-301 Saturday, 28th March 2015, 8:46 hrs thru CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) 28-Mar-15 08:46 0:00:00 Open well to closed Expro choke 0 0.00 6 1.71 -1.71 1971.07 99.75 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 9 55 56 0.000 N/R 0.00 0.00 0.00 0.000 N/R 0.00 0.00 0.00 0.00 0.00 0 28-Mar-15 09:00 0:14:00 Open well to tanks on 16/64ths adjustable choke 16 147.31 28 0.00 137.01 1966.77 100.19 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 9 53 56 0.000 N/R 0.00 0.00 0.00 0.962 N/R 0.00 0.00 0.00 0.00 0.00 0 28-Mar-15 09:30 0:44:00 9:05 Coil starts RIH, 9:07 starts pumping N2 @ 500scf/m 16 303.93 31 14.07 302.17 2013.00 100.28 0.00 500.00 111.60 0.00 0.00 111.60 0.00 0.00 0.00 2.33 2.33 9 52 55 0.000 N/R 100.00 0.00 100.00 0.962 N/R 0.00 0.00 0.00 2.33 2.33 0 28-Mar-15 10:00 1:14:00 9:30 BS&W=100% LVT 10:00 BS&W, Increase choke to 32/64ths 18 721.35 34 54.58 635.58 1995.68 96.02 0.00 500.00 372.00 0.00 0.00 372.00 0.00 0.00 0.00 7.75 7.75 10 50 54 0.000 N/R 100.00 0.00 100.00 0.962 N/R 0.00 0.00 0.00 10.08 10.08 0 28-Mar-15 10:30 1:44:00 Nitrogen only at surface 32 629.35 30 88.82 524.26 1950.71 99.30 0.00 500.00 0.00 0.00 0.77 0.00 0.00 0.00 0.02 0.00 0.00 65 98 59 0.000 N/R 0.00 0.00 0.00 0.962 N/R 0.00 0.00 0.02 10.08 10.08 0 28-Mar-15 11:00 2:14:00 Nitrogen only at surface 32 640.75 30 36.04 596.64 1951.27 100.04 0.00 500.00 0.00 0.00 0.71 0.00 0.00 0.00 0.01 0.00 0.00 28 109 57 2.000 N/R 0.00 0.00 0.00 0.962 N/R 0.00 0.00 0.03 10.08 10.08 355 28-Mar-15 11:30 2:44:00 Coil @ 2000ft ppg @ 500scf/m, 11:23 fluid to choke 32 563.96 34 14.83 544.34 1947.26 100.60 0.00 500.00 334.80 0.00 0.54 334.80 0.00 0.00 0.01 6.98 6.98 12 106 84 1.500 N/R 100.00 0.00 100.00 0.962 N/R 0.00 0.00 0.04 17.05 17.05 355 28-Mar-15 12:00 3:14:00 BS&W= 100% brine 32 733.13 35 69.80 650.14 1940.82 100.84 0.00 500.00 372.00 0.00 0.96 372.00 0.00 0.00 0.02 7.75 7.75 56 111 80 1.500 N/R 100.00 0.00 100.00 0.962 N/R 0.00 0.00 0.06 24.80 24.80 355 28-Mar-15 12:30 3:44:00 Coil RIH from 2000ft BS&W 100% brine 32 794.91 38 89.39 693.31 1942.51 101.11 0.00 500.00 74.40 0.00 0.56 74.40 0.00 0.00 0.01 1.55 1.55 78 113 85 1.500 N/R 100.00 0.00 100.00 0.962 N/R 0.00 0.00 0.07 26.35 26.35 355 28-Mar-15 13:00 4:14:00 12:41 Coil reaches 2500ft BS&W 100% Brine increas choke to 36/64ths 32 817.91 36 83.59 708.35 1961.77 100.96 0.00 500.00 186.00 0.00 0.36 186.00 0.00 0.00 0.01 3.88 3.88 38 103 82 2.000 N/R 49000 7 100.00 0.00 100.00 0.962 N/R 0.00 0.00 0.08 30.23 30.23 355 28-Mar-15 13:30 4:44:00 Increase Daniels plate to 2.00'' 100% brine, 13:42 Coil POOH 36 497.81 44 93.29 386.74 1930.62 101.28 0.00 500.00 744.00 0.00 0.62 744.00 0.00 0.00 0.01 15.50 15.50 110 100 80 2.000 N/R 100.00 0.00 100.00 0.962 N/R 0.00 0.00 0.09 45.73 45.73 355 28-Mar-15 14:00 5:14:00 BS&W 100% , 90%brine 10%frac Gel 13:44 increase choke to 44/64ths 44 278.46 66 121.62 101.33 1845.56 101.76 0.00 500.00 1264.80 0.00 0.66 1264.80 0.00 0.00 0.01 26.35 26.35 70 91 73 2.000 N/R 51000 7 100.00 0.00 100.00 0.962 N/R 0.00 0.00 0.11 72.08 72.08 355 28-Mar-15 14:30 5:44:00 BS&W 98%, 78%Brine 20%Gel 2%Crude, Increase choke to 48/64ths 48 307.55 73 146.25 107.61 1833.19 102.68 0.00 500.00 2306.40 46.13 0.62 2260.27 0.00 0.96 0.01 47.09 48.05 76 96 77 1.500 N/R 98.00 0.00 98.00 0.962 13347.23 0.96 0.00 0.12 119.16 120.13 355 28-Mar-15 15:00 6:14:00 BS&W 98%, 97%brine 1%Gel 2%Crude increased choke to 52/64ths 48 305.27 75 171.83 73.93 1823.99 102.78 0.00 500.00 2529.60 50.59 0.46 2479.01 0.00 1.05 0.01 51.65 52.70 80 100 78 1.500 N/R 98.00 0.00 98.00 0.962 9041.74 2.02 0.00 0.13 170.81 172.83 355 28-Mar-15 15:30 6:44:00 BS&W 98%, 97%brine 1%Gel 2%Crude increased choke to 52/64ths 52 421.21 73 389.98 11.08 1859.58 102.66 0.00 500.00 1796.83 35.94 0.57 1760.89 0.00 0.75 0.01 36.69 37.43 279 100 79 1.500 N/R 98.00 0.00 98.00 0.962 15754.03 2.76 0.00 0.14 207.50 210.26 355 28-Mar-15 16:00 7:14:00 BS&W = 96%, 96%brine 4%crude 52 282.46 74 115.54 89.32 1827.93 102.60 0.00 500.00 1979.33 79.17 0.56 1900.16 0.00 1.65 0.01 39.59 41.24 165 92 78 1.500 N/R 96.00 0.00 96.00 0.962 7132.74 4.41 0.00 0.15 247.08 251.50 355 28-Mar-15 16:30 7:44:00 BS&W = 82%, 80%brine 2%Gel 18%crude 52 206.42 73 104.51 37.41 1826.48 102.57 0.76 500.00 1320.26 237.65 0.72 1082.61 0.00 4.95 0.02 22.55 27.51 70 96 78 1.500 N/R 46000 8 82.00 0.00 82.00 0.949 3031.96 9.36 0.00 0.17 269.64 279.00 355 28-Mar-15 17:00 8:14:00 BS&W 60%, 60%brine 40%crude 52 234.56 73 134.75 33.55 1812.60 102.51 0.00 500.00 2360.47 944.19 0.58 1416.28 0.00 19.67 0.01 29.51 49.18 78 97 77 1.500 N/R 60.00 0.00 60.00 0.949 613.01 29.03 0.00 0.18 299.14 328.18 355 28-Mar-15 17:30 8:44:00 BS&W = 60%, 60%brine 40%crude Tr Sed 52 237.60 73 143.69 42.33 1815.31 102.45 0.00 500.00 3080.62 1232.25 0.62 1848.37 0.00 25.67 0.01 38.51 64.18 83 96 77 1.500 N/R 60.00 0.00 60.00 0.949 504.56 54.71 0.00 0.19 337.65 392.36 355 28-Mar-15 18:00 9:14:00 BS&W = 81.9%, 81.9%brine, 0.1 sed, 18%crude 52 242.16 72 151.58 41.98 1817.47 102.39 13.15 500.00 2000.40 360.07 0.74 1638.33 2.00 7.50 0.02 34.13 41.68 92 95 77 1.500 N/R 44000 8 82.00 0.10 81.90 0.941 2044.62 62.21 0.04 0.21 371.78 434.03 355 28-Mar-15 18:30 9:44:00 BS&W = 72%, 72%brine 28% crude Tr Sed 52 258.51 71 155.76 46.27 1814.32 102.34 21.73 500.00 1900.38 532.11 0.76 1368.27 0.00 11.09 0.02 28.51 39.59 94 96 76 1.500 N/R 72.00 0.00 72.00 0.941 1425.87 73.29 0.04 0.22 400.29 473.62 355 28-Mar-15 19:00 10:14:00 BS&W = 72%, 72%brine 28% crude Tr Sed 52 226.57 70 133.04 43.75 1812.02 102.31 0.00 500.00 1560.31 436.89 0.69 1123.42 0.00 9.10 0.01 23.40 32.51 85 95 76 1.500 N/R 72.00 0.00 72.00 0.941 1579.52 82.40 0.04 0.24 423.69 506.13 355 28-Mar-15 19:30 10:44:00 BS&W = 74%, 74%brine 26% crude Tr Sed 52 227.52 71 135.03 42.88 1809.96 102.28 12.01 500.00 1840.37 478.50 0.68 1361.87 0.00 9.97 0.01 28.37 38.34 84 94 77 1.500 N/R 74.00 0.00 74.00 0.941 1420.12 92.36 0.04 0.25 452.06 544.47 355 28-Mar-15 20:00 11:14:00 BS&W = 70%, 70%brine 30% crude Tr Sed 52 220.87 71 145.02 32.89 1810.73 102.23 17.16 500.00 1785.60 535.68 0.68 1249.92 0.00 11.16 0.01 26.04 37.20 84 94 76 1.500 N/R 70.00 0.00 70.00 0.941 1276.79 103.52 0.04 0.27 478.10 581.67 355 28-Mar-15 20:30 11:44:00 BS&W = 72%, 72%brine 28% crude Tr Sed 52 221.25 70 138.08 30.22 1810.44 102.19 17.73 500.00 1525.20 427.06 0.68 1098.14 0.00 8.90 0.01 22.88 31.78 84 94 76 1.500 N/R 72.00 0.00 72.00 0.941 1603.59 112.42 0.04 0.28 500.98 613.45 355 28-Mar-15 21:00 12:14:00 BS&W = 70%, 70%brine 30% crude Tr Sed 52 228.47 72 139.98 25.50 1810.47 102.15 17.94 500.00 1767.00 530.10 0.69 1236.90 0.00 11.04 0.01 25.77 36.81 88 93 76 1.500 N/R 44000 8 70.00 0.00 70.00 0.937 1303.80 123.46 0.04 0.30 526.75 650.26 355 28-Mar-15 21:30 12:44:00 BS&W = 68%, 68%brine 32% crude Tr Sed 52 218.78 71 137.60 40.69 1810.36 102.12 31.67 500.00 1674.00 535.68 0.69 1138.32 0.00 11.16 0.01 23.72 34.88 88 93 76 1.500 N/R 68.00 0.00 68.00 0.937 1291.94 134.62 0.04 0.31 550.47 685.13 355 28-Mar-15 22:00 13:14:00 BS&W = 68%, 68%brine 34% crude Tr Sed 52 230.37 70 134.94 39.21 1809.84 102.10 33.55 500.00 1767.00 600.78 0.69 1166.22 0.00 12.52 0.01 24.30 36.81 87 93 76 1.500 N/R 66.00 0.00 66.00 0.937 1150.14 147.14 0.04 0.32 574.76 721.95 355 28-Mar-15 22:30 13:44:00 BS&W = 64%, 64%brine 36% crude Tr Sed 52 251.28 71 133.70 43.83 1809.04 102.07 61.38 500.00 1653.65 595.31 0.69 1058.34 0.00 12.40 0.01 22.05 34.45 86 93 76 1.500 N/R 64.00 0.00 64.00 0.937 1161.38 159.54 0.04 0.34 596.81 756.40 355 28-Mar-15 23:00 14:14:00 BS&W = 66%, 66%brine 34% crude Tr Sed 52 217.83 70 130.28 38.96 1810.09 102.05 47.46 500.00 1580.32 537.31 0.68 1043.01 0.00 11.19 0.01 21.73 32.92 84 94 76 1.500 N/R 66.00 0.00 66.00 0.937 1270.06 170.74 0.04 0.35 618.54 789.32 355 28-Mar-15 23:30 14:44:00 BS&W = 62%, 62%brine 38% crude Tr Sed 52 216.12 69 138.46 21.36 1809.81 102.04 53.56 500.00 1660.33 630.93 0.70 1029.40 0.00 13.14 0.01 21.45 34.59 87 94 76 1.500 N/R 62.00 0.00 62.00 0.937 1105.79 183.88 0.04 0.37 639.99 823.91 355 29-Mar-15 00:00 15:14:00 BS&W = 62%, 62%brine 38% crude Tr Sed, Coil Tubing at 3200 ft.52 215.93 69 145.02 21.21 1805.24 102.03 48.42 500.00 1600.32 608.12 0.85 992.20 0.00 12.67 0.02 20.67 33.34 96 95 77 1.500 N/R 42000 7 62.00 0.00 62.00 0.916 1391.82 196.55 0.04 0.39 660.66 857.25 355 29-Mar-15 00:30 15:44:00 BS&W = 58%, 58%brine 42% crude Tr Sed 52 211.37 67 124.19 36.57 1807.74 102.01 49.37 500.00 1460.29 613.32 0.72 846.97 0.00 12.78 0.02 17.65 30.42 77 93 76 1.500 N/R 58.00 0.00 58.00 0.916 1176.81 209.33 0.04 0.40 678.30 887.67 355 29-Mar-15 01:00 16:14:00 BS&W = 62%, 62%brine 38% crude Tr Sed 52 210.23 68 123.15 29.13 1805.50 101.98 51.85 500.00 1480.30 562.51 0.70 917.79 0.00 11.72 0.01 19.12 30.84 86 91 74 1.500 N/R 62.00 0.00 62.00 0.916 1241.39 221.05 0.04 0.42 697.42 918.51 355 29-Mar-15 01:30 16:44:00 BS&W = 54%, 54%brine 46% crude Tr Sed 52 210.61 64 131.89 29.62 1806.16 101.97 63.29 500.00 1480.30 680.94 0.70 799.36 0.00 14.19 0.01 16.65 30.84 71 91 74 1.500 N/R 54.00 0.00 54.00 0.916 1032.80 235.23 0.04 0.43 714.08 949.35 355 29-Mar-15 02:00 17:14:00 BS&W = 56%, 56%brine 44% crude Tr Sed 52 215.17 67 122.58 38.19 1805.67 101.95 53.18 500.00 1540.31 677.74 0.71 862.57 0.00 14.12 0.01 17.97 32.09 74 91 74 1.500 N/R 56.00 0.00 56.00 0.916 1054.30 249.35 0.04 0.44 732.05 981.44 355 29-Mar-15 02:30 17:44:00 BS&W = 56%, 56%brine 44% crude Tr Sed 52 219.54 66 129.42 11.55 1805.04 101.98 50.20 500.00 1540.31 677.74 0.71 862.57 0.00 14.12 0.01 17.97 32.09 72 91 74 1.500 N/R 56.00 0.00 56.00 0.916 1041.91 263.47 0.04 0.46 750.02 1013.53 355 29-Mar-15 03:00 18:14:00 BS&W = 58%, 58%brine 42% crude Tr Sed 52 230.56 65 146.44 26.38 1807.78 101.97 62.71 500.00 1413.60 593.71 0.80 819.89 0.00 12.37 0.02 17.08 29.45 92 90 74 1.500 N/R 42000 7 58.00 0.00 58.00 0.930 1349.31 275.84 0.04 0.48 767.10 1042.98 355 29-Mar-15 03:30 18:44:00 BS&W = 52%, 52%brine 48% crude Tr Sed 52 216.69 66 139.60 22.67 1805.35 101.95 65.96 500.00 1339.20 642.82 0.77 696.38 0.00 13.39 0.02 14.51 27.90 77 44 74 1.500 N/R 52.00 0.00 52.00 0.930 1194.39 289.23 0.04 0.49 781.61 1070.88 355 29-Mar-15 04:00 19:14:00 BS&W = 52%, 52%brine 48% crude Tr Sed 52 266.11 66 221.09 15.43 1810.58 101.93 55.28 500.00 1413.60 678.53 0.72 735.07 0.00 14.14 0.02 15.31 29.45 97 35 75 1.500 N/R 52.00 0.00 52.00 0.930 1066.27 303.37 0.04 0.51 796.92 1100.33 355 29-Mar-15 04:30 19:44:01 BS&W = 50%, 50%brine 50% crude Tr Sed 52 245.77 66 146.92 40.98 1794.27 101.95 37.74 500.00 1610.48 805.24 0.77 805.24 0.00 16.78 0.02 16.78 33.55 97 39 74 1.500 0.900 25.7 50.00 0.00 50.00 0.930 950.71 320.15 0.04 0.52 813.70 1133.88 355 29-Mar-15 05:00 20:14:01 BS&W = 44%, 44%brine 56% crude Tr Sed 52 445.54 65 235.55 119.71 1781.83 101.96 16.39 500.00 1635.41 915.83 0.78 719.58 0.00 19.08 0.02 14.99 34.07 98 40 74 1.500 N/R 44.00 0.00 44.00 0.930 853.05 339.23 0.04 0.54 828.69 1167.95 355 29-Mar-15 05:30 20:44:02 BS&W = 48%, 48%brine 52% crude Tr Sed 52 331.88 66 184.48 42.81 1779.47 101.91 71.67 500.00 1580.32 821.77 0.81 758.55 0.00 17.12 0.02 15.80 32.92 115 38 73 1.500 N/R 48.00 0.00 48.00 0.930 990.68 356.35 0.04 0.56 844.49 1200.88 355 29-Mar-15 06:00 21:14:02 BS&W = 47%, 48%brine 53% crude Tr Sed 52 211.75 63 121.62 46.68 1795.79 101.95 73.20 500.00 1680.34 890.58 0.82 789.76 0.00 18.55 0.02 16.45 35.01 82 53 75 1.500 N/R 47.00 0.00 47.00 0.964 923.72 374.90 0.04 0.57 860.94 1235.88 355 29-Mar-15 06:30 21:44:03 BS&W = 49%, 49%brine 51% crude Tr Sed 52 225.81 65 140.26 32.00 1790.45 101.90 81.97 500.00 1680.34 856.97 0.76 823.37 0.00 17.85 0.02 17.15 35.01 80 90 74 1.500 N/R 49.00 0.00 49.00 0.964 889.94 392.75 0.04 0.59 878.10 1270.89 355 29-Mar-15 07:00 22:14:03 BS&W = 55%, 55%brine 45% crude Tr Sed 52 254.32 66 154.62 39.12 1779.14 101.90 78.54 500.00 1760.35 792.16 0.80 968.19 0.00 16.50 0.02 20.17 36.67 80 92 74 1.500 N/R 55.00 0.00 55.00 0.964 1011.90 409.26 0.04 0.61 898.27 1307.57 355 29-Mar-15 07:30 22:44:04 BS&W = 60%, 60%brine 40% crude Tr Sed 52 199.58 64 115.63 32.12 1752.22 101.98 85.21 500.00 1840.37 736.15 0.86 1104.22 0.00 15.34 0.02 23.00 38.34 83 92 73 1.500 N/R 60.00 0.00 60.00 0.964 1170.95 424.59 0.04 0.62 921.27 1345.91 355 29-Mar-15 08:00 23:14:04 BS&W = 56%, 56%brine 44% crude Tr Sed 52 180.19 63 102.99 28.19 1769.17 101.97 76.25 500.00 1760.35 774.55 0.89 985.80 0.00 16.14 0.02 20.54 36.67 82 87 73 1.500 N/R 56.00 0.00 56.00 0.964 1153.84 440.73 0.04 0.64 941.81 1382.58 148 29-Mar-15 08:30 23:44:05 BS&W = 50%, 50%brine 50% crude Tr Sed 52 258.70 64 152.72 44.23 1778.42 101.94 90.16 500.00 1840.37 920.19 0.81 920.19 0.00 19.17 0.02 19.17 38.34 77 91 74 1.500 N/R 50.00 0.00 50.00 0.964 876.59 459.90 0.04 0.66 960.98 1420.92 148 29-Mar-15 09:00 24:14:05 BS&W = 50%, 50%brine 50% crude Tr Sed Api= 30.3@60F 48 370.46 65 219.38 74.06 1721.49 101.98 77.77 500.00 1840.37 920.19 1.18 920.19 0.00 19.17 0.02 19.17 38.34 108 93 74 1.500 0.875 30.3 50.00 0.00 50.00 0.942 1280.82 479.07 0.04 0.68 980.15 1459.26 148 29-Mar-15 09:30 24:44:05 BS&W = 54%, 54%brine 46% crude Tr Sed 44 344.61 60 122.10 180.39 1785.12 101.93 80.82 500.00 1520.30 699.34 0.83 820.96 0.00 14.57 0.02 17.10 31.67 84 90 74 1.500 N/R 54.00 0.00 54.00 0.942 1190.68 493.64 0.04 0.70 997.25 1490.94 148 29-Mar-15 10:00 25:14:06 BS&W = 46%, 46%brine 54% crude Tr Sed 40 487.93 58 117.06 333.94 1796.18 101.85 68.43 500.00 1000.20 540.11 0.66 460.09 0.00 11.25 0.01 9.59 20.84 80 90 75 1.500 N/R 46.00 0.00 46.00 0.942 1229.45 504.89 0.04 0.72 1006.84 1511.77 148 29-Mar-15 10:30 25:44:06 BS&W = 48%, 48%brine 52% crude Tr Sed Coil offline with N2 36 620.22 50 102.03 504.45 1832.13 101.65 36.03 0.00 1218.48 633.61 0.63 584.87 0.00 13.20 0.01 12.18 25.39 74 93 75 0.875 N/R 48.00 0.00 48.00 0.942 989.69 518.09 0.04 0.73 1019.02 1537.16 148 29-Mar-15 11:00 26:14:07 BS&W = 30%, 30%brine 70% crude Tr Sed 36 345.94 54 44.03 297.28 1839.04 101.67 17.35 0.00 297.60 208.32 0.11 89.28 0.00 4.34 0.00 1.86 6.20 50 87 73 0.875 N/R 30.00 0.00 30.00 0.942 543.92 522.43 0.04 0.73 1020.88 1543.36 148 29-Mar-15 11:30 26:44:07 BS&W = 40%, 40%brine 60% crude Tr Sed 36 390.42 52 32.05 348.28 1841.48 101.46 0.00 0.00 297.60 178.56 0.06 119.04 0.00 3.72 0.00 2.48 6.20 38 82 73 0.875 N/R 40.00 0.00 40.00 0.942 343.27 526.15 0.04 0.73 1023.36 1549.56 148 29-Mar-15 12:00 27:14:08 BS&W = 35%, 35%brine 65% crude Tr Sed Choke increased to 40/64ths 36 609.96 50 67.90 525.96 1845.46 101.30 0.00 0.00 818.40 531.96 0.07 286.44 0.00 11.08 0.00 5.97 17.05 36 84 71 0.875 N/R 40000 7 35.00 0.00 35.00 0.766 126.68 537.23 0.04 0.73 1029.33 1566.61 148 29-Mar-15 12:30 27:44:08 BS&W = 40%, 40%brine 60% crude Tr Sed 12:51 rock choke 40 280.75 63 57.53 215.93 1823.02 101.73 19.06 0.00 520.80 312.48 0.08 208.32 0.00 6.51 0.00 4.34 10.85 42 77 69 0.875 N/R 40.00 0.00 40.00 0.766 253.01 543.74 0.04 0.74 1033.67 1577.46 148 29-Mar-15 13:00 28:14:09 BS&W = 50%, 50%brine 50% crude Tr Sed. Increased choke 44/64ths 40 436.42 62 20.64 394.37 1839.81 101.64 29.74 0.00 967.20 483.60 0.07 483.60 0.00 10.08 0.00 10.08 20.15 40 74 69 0.875 0.887 28.0 50.00 0.00 50.00 0.766 134.71 553.82 0.04 0.74 1043.75 1597.61 148 29-Mar-15 13:30 28:44:09 BS&W = 60%, 60%brine 40% crude. 13:15 sparge sand trap 2gal sand 44 344.04 67 145.78 128.82 1749.65 101.84 55.66 0.00 612.05 244.82 0.59 367.23 0.00 5.10 0.01 7.65 12.75 64 81 70 1.500 N/R 60.00 0.00 60.00 0.766 2397.99 558.92 0.04 0.75 1051.40 1610.36 148 29-Mar-15 14:00 29:14:10 BS&W = 68%, 68%brine 32% crude. 14:09 increased choke 56/64ths 44 302.41 69 151.77 67.23 1741.73 101.85 219.98 0.00 2835.64 907.40 0.52 1928.24 0.00 18.90 0.01 40.17 59.08 66 86 73 1.500 N/R 68.00 0.00 68.00 0.766 571.98 577.82 0.04 0.76 1091.57 1669.43 148 29-Mar-15 14:30 29:44:10 BS&W = 45%, 45%brine 55% crude. 14:22 sparge sand trap 10gal sand 56 338.53 68 221.85 35.78 1744.44 101.89 51.47 0.00 3120.60 1716.33 0.50 1404.27 0.00 35.76 0.01 29.26 65.01 80 92 74 1.500 N/R 45.00 0.00 45.00 0.766 291.87 613.58 0.04 0.77 1120.82 1734.45 148 29-Mar-15 15:00 30:14:11 BS&W = 45%, 45%brine 55% crude. 15:05 sparge sand trap, trace sand 52 313.63 68 159.57 60.94 1725.15 101.89 120.85 0.00 3200.64 1760.35 0.58 1440.29 0.00 36.67 0.01 30.01 66.68 116 89 74 1.500 N/R 45.00 0.00 45.00 0.766 332.11 650.26 0.04 0.78 1150.83 1801.13 148 29-Mar-15 15:30 30:44:11 BS&W = 49%, 49%brine 51% crude Tr Sed 52 322.37 74 165.94 64.74 1729.62 101.88 136.87 0.00 3440.69 1754.75 0.58 1685.94 0.00 36.56 0.01 35.12 71.68 79 89 74 1.500 N/R 39000 7 49.00 0.00 49.00 0.766 330.87 686.81 0.04 0.79 1185.95 1872.81 148 29-Mar-15 16:00 31:14:12 BS&W = 40%, 40%brine 60% crude Tr Sed 56 329.41 71 166.41 49.57 1717.49 101.89 132.86 0.00 3360.67 2016.40 0.57 1344.27 0.00 42.01 0.01 28.01 70.01 76 89 74 1.500 N/R 40.00 0.00 40.00 0.736 283.42 728.82 0.04 0.81 1213.96 1942.82 148 29-Mar-15 16:30 31:44:12 BS&W = 50%, 50%brine 50% crude Tr Sed. 60 291.20 79 166.03 32.61 1716.76 101.91 147.92 0.00 3422.40 1711.20 0.55 1711.20 0.00 35.65 0.01 35.65 71.30 73 90 74 1.500 N/R 50.00 0.00 50.00 0.736 322.51 764.47 0.04 0.82 1249.61 2014.12 148 29-Mar-15 17:00 32:14:13 BS&W = 40%, 40%brine 60% crude Tr Sed. 60 313.63 74 162.61 43.01 1718.10 101.94 210.06 0.00 3440.69 2064.41 0.55 1376.28 0.00 43.01 0.01 28.67 71.68 74 90 74 1.500 N/R 40.00 0.00 40.00 0.736 268.62 807.48 0.04 0.83 1278.28 2085.80 148 29-Mar-15 17:30 32:44:13 BS&W = 12%, 6%brine 88% 6%Gel crude Tr Sed. 60 299.18 73 163.56 49.03 1716.46 101.95 172.13 0.00 3391.54 2984.56 0.56 406.98 0.00 62.18 0.01 8.48 70.66 75 91 74 1.500 N/R 12.00 0.00 12.00 0.736 188.02 869.66 0.04 0.84 1286.76 2156.46 148 Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives Expro Confidential 5/5/2015 Page 2 CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives 29-Mar-15 18:00 33:14:14 BS&W = 40%, 40%brine 60% crude Tr Sed. API= 29.3@60F 60 295.38 74 153.67 45.91 1713.84 101.95 141.06 0.00 3360.67 2016.40 0.56 1344.27 0.00 42.01 0.01 28.01 70.01 75 90 74 1.500 0.880 29.3 40000 7 40.00 0.00 40.00 0.734 277.21 911.67 0.04 0.85 1314.77 2226.47 148 29-Mar-15 18:30 33:44:14 BS&W = 46%, 46%brine 54% crude Tr Sed. Decrease choke 44/64ths 60 297.47 73 165.08 38.08 1720.61 101.93 285.55 0.00 3200.64 1728.35 0.53 1472.29 0.00 36.01 0.01 30.67 66.68 74 89 74 1.500 N/R 46.00 0.00 46.00 0.734 308.74 947.67 0.04 0.86 1345.44 2293.15 148 29-Mar-15 19:00 34:14:15 BS&W = 38%, 37.7%brine & 0.3%sed 62% crude. Sparge sandtrap (10 gal. sand)44 299.75 73 143.50 88.32 1729.33 101.91 202.06 0.00 2880.58 1785.96 0.47 1085.98 8.64 37.21 0.01 22.62 60.01 70 90 74 1.500 N/R 38.00 0.30 37.70 0.734 265.40 984.88 0.22 0.87 1368.06 2353.17 148 29-Mar-15 19:30 34:44:15 BS&W = 36%, 36%brine 64% crude Tr Sed. 44 294.24 73 139.03 80.54 1731.73 101.93 58.52 0.00 2640.53 1689.94 0.43 950.59 0.00 35.21 0.01 19.80 55.01 67 90 75 1.500 N/R 36.00 0.00 36.00 0.734 254.08 1020.09 0.22 0.88 1387.87 2408.18 148 29-Mar-15 20:00 35:14:15 BS&W = 46%, 46%brine 54% crude Tr Sed. 44 291.58 73 140.17 77.51 1732.20 101.93 101.03 0.00 2250.45 1215.24 0.42 1035.21 0.00 25.32 0.01 21.57 46.88 65 90 74 1.500 N/R 46.00 0.00 46.00 0.734 345.66 1045.41 0.22 0.89 1409.43 2455.06 148 29-Mar-15 20:30 35:44:16 BS&W = 44%, 44%brine 56% crude Tr Sed. Increase choke 60/64ths 60 301.65 73 137.50 78.48 1732.57 101.91 183.38 0.00 3960.79 2218.04 0.42 1742.75 0.00 46.21 0.01 36.31 82.52 66 90 75 1.500 N/R 44.00 0.00 44.00 0.734 190.79 1091.61 0.22 0.90 1445.74 2537.58 148 29-Mar-15 21:00 36:14:16 BS&W = 46%, 45.9%brine & 0.1%sed 62% crude. 0 H2S 0 CO2 60 279.03 74 155.76 28.93 1720.90 101.95 72.82 0.00 3240.65 1749.95 0.46 1487.46 3.24 36.46 0.01 30.99 67.51 72 91 75 1.500 N/R 38000 7 46.00 0.10 45.90 0.711 0.00 0 263.03 1128.07 0.29 0.91 1476.73 2605.09 148 29-Mar-15 21:30 36:44:17 BS&W = 46%, 46%brine 54% crude Tr Sed. 60 279.98 74 158.14 31.08 1719.87 101.95 140.68 0.00 2827.20 1526.69 0.47 1300.51 0.00 31.81 0.01 27.09 58.90 74 91 75 1.500 N/R 46.00 0.00 46.00 0.711 309.57 1159.88 0.29 0.92 1503.82 2663.99 148 29-Mar-15 22:00 37:14:17 BS&W = 44%, 44%brine 56% crude Tr Sed. 60 253.94 73 165.65 21.68 1719.86 101.94 305.76 0.00 3775.46 2114.26 0.49 1661.20 0.00 44.05 0.01 34.61 78.66 77 91 75 1.500 N/R 44.00 0.00 44.00 0.711 229.43 1203.92 0.29 0.93 1538.43 2742.65 148 29-Mar-15 22:30 37:44:18 BS&W = 38%, 38%brine 62% crude Tr Sed. 60 266.68 73 140.74 25.11 1717.70 101.93 209.68 0.00 3273.60 2029.63 0.49 1243.97 0.00 42.28 0.01 25.92 68.20 77 91 75 1.500 N/R 38.00 0.00 38.00 0.711 239.29 1246.21 0.29 0.94 1564.35 2810.85 148 29-Mar-15 23:00 38:14:18 BS&W = 42%, 41.9%brine & 0.1%sed 58% crude. Sparge sandtrap 2 gal. Frac sand 60 267.82 72 163.94 34.14 1716.33 101.93 151.35 0.00 3280.66 1902.78 0.49 1374.60 3.28 39.64 0.01 28.64 68.35 79 91 75 1.500 N/R 42.00 0.10 41.90 0.711 259.43 1285.85 0.36 0.95 1592.99 2879.19 148 29-Mar-15 23:30 38:44:19 BS&W = 42%, 42%brine 58% crude Tr Sed. Sparge sandtrap 0.5 gal. Frac sand 60 294.24 71 196.27 21.59 1718.63 101.91 217.88 0.00 3314.64 1922.49 0.44 1392.15 0.00 40.05 0.01 29.00 69.06 85 95 75 1.500 N/R 42.00 0.00 42.00 0.711 230.06 1325.90 0.36 0.96 1621.99 2948.25 148 30-Mar-15 00:00 39:14:19 BS&W = 42%, 42%brine 58% crude Tr Sed. API= 29.8@60F 60 296.33 70 151.96 31.80 1713.69 101.90 221.88 0.00 3300.66 1914.38 0.46 1386.28 0.00 39.88 0.01 28.88 68.76 77 91 74 1.500 0.877 29.8 38000 7 42.00 0.00 42.00 0.704 241.61 1365.79 0.36 0.97 1650.87 3017.01 148 30-Mar-15 00:30 39:44:20 BS&W = 42%, 41.9%brine & 0.1%sed 58% crude. Increase methanol @320gpd 60 303.55 70 170.69 33.98 1706.81 101.89 104.65 0.00 3260.28 1890.96 0.65 1366.06 3.26 39.40 0.01 28.46 67.92 82 90 74 1.500 N/R 42.00 0.10 41.90 0.704 342.83 1405.18 0.43 0.98 1679.33 3084.94 320 30-Mar-15 01:00 40:14:20 BS&W = 38%, 38%brine 62% crude Tr Sed. 60 312.68 70 171.17 45.94 1703.02 101.86 305.95 0.00 2860.57 1773.55 0.65 1087.02 0.00 36.95 0.01 22.65 59.60 81 90 74 1.500 N/R 38.00 0.00 38.00 0.704 366.26 1442.13 0.43 1.00 1701.98 3144.53 320 30-Mar-15 01:30 40:44:21 BS&W = 36%, 36%brine 64% crude Tr Sed. 60 303.74 70 172.31 29.92 1713.93 101.87 276.21 0.00 4000.80 2560.51 0.65 1440.29 0.00 53.34 0.01 30.01 83.35 81 90 74 1.500 N/R 36.00 0.00 36.00 0.704 255.44 1495.47 0.43 1.01 1731.98 3227.88 320 30-Mar-15 02:00 41:14:21 BS&W = 34%, 34%brine 66 % crude. Sparge sandtrap 1 gal. Frac sand 60 301.65 69 178.59 46.07 1709.50 101.85 117.23 0.00 3760.75 2482.10 0.67 1278.66 0.00 51.71 0.01 26.64 78.35 84 90 74 1.500 N/R 34.00 0.00 34.00 0.704 269.40 1547.18 0.43 1.02 1758.62 3306.23 320 30-Mar-15 02:30 41:44:22 BS&W = 36%, 36%brine 64% crude Tr Sed. 60 317.43 68 176.40 44.48 1697.19 101.84 225.51 0.00 3186.58 2039.41 0.70 1147.17 0.00 42.49 0.01 23.90 66.39 88 90 74 1.500 N/R 36.00 0.00 36.00 0.704 340.82 1589.67 0.43 1.04 1782.52 3372.62 320 30-Mar-15 03:00 42:14:22 BS&W = 34%, 34%brine 66% crude Tr Sed. Gas SG 0.731 60 318.19 69 180.49 45.48 1708.26 101.82 371.14 0.00 3500.70 2310.46 0.70 1190.24 0.00 48.13 0.01 24.80 72.93 83 90 74 1.500 N/R 38000 7 34.00 0.00 34.00 0.731 302.08 1637.81 0.43 1.05 1807.32 3445.55 320 30-Mar-15 03:30 42:44:22 BS&W = 34%, 34%brine 66 % crude. Sparge Sep vessel 25 gal. Frac sand 60 329.21 68 185.34 38.37 1706.33 101.81 231.03 0.00 3660.73 2416.08 0.71 1244.65 0.00 50.34 0.01 25.93 76.27 86 90 74 1.500 N/R 34.00 0.00 34.00 0.731 294.96 1688.14 0.43 1.07 1833.25 3521.81 320 30-Mar-15 04:00 43:14:23 BS&W = 34%, 34%brine 66% crude Tr Sed.60 328.64 67 181.25 43.03 1704.13 101.80 335.87 0.00 3260.65 2152.03 0.73 1108.62 0.00 44.83 0.02 23.10 67.93 85 89 74 1.500 N/R 34.00 0.00 34.00 0.731 339.54 1732.97 0.43 1.08 1856.34 3589.74 320 30-Mar-15 04:30 43:44:23 BS&W = 32%, 32%brine 68% crude Tr Sed.60 328.45 68 182.48 46.50 1700.53 101.80 251.24 0.00 3620.72 2462.09 0.75 1158.63 0.00 51.29 0.02 24.14 75.43 80 89 74 1.500 N/R 32.00 0.00 32.00 0.731 304.04 1784.27 0.43 1.10 1880.48 3665.18 320 30-Mar-15 05:00 44:14:24 BS&W = 30%, 30%brine 70% crude Tr Sed.60 328.45 68 183.24 40.28 1698.57 101.79 226.27 0.00 3740.75 2618.53 0.77 1122.23 0.00 54.55 0.02 23.38 77.93 73 89 74 1.500 N/R 30.00 0.00 30.00 0.731 293.00 1838.82 0.43 1.11 1903.86 3743.11 320 30-Mar-15 05:30 44:44:24 BS&W = 30%, 30%brine 70% crude Tr Sed. API= 29.8@60F 60 306.98 68 177.06 63.23 1696.16 101.79 127.91 0.00 3841.23 2688.86 0.78 1152.37 0.00 56.02 0.02 24.01 80.03 75 89 73 1.500 0.877 29.8 30.00 0.00 30.00 0.731 291.79 1894.84 0.43 1.13 1927.87 3823.13 320 30-Mar-15 06:00 45:14:25 BS&W = 30%, 30%brine 70% crude Tr Sed. Sparge sandtrap 1 gal. Frac sand 60 334.35 68 184.01 41.59 1694.18 101.79 122.38 0.00 4017.60 2812.32 0.79 1205.28 0.00 58.59 0.02 25.11 83.70 77 89 73 1.500 N/R 38000 7 30.00 0.00 30.00 0.698 282.49 1953.43 0.43 1.15 1952.98 3906.83 320 30-Mar-15 06:30 45:44:25 BS&W = 30%, 30%brine 70% crude Tr Sed.60 343.47 67 181.34 42.55 1691.85 101.79 229.13 0.00 3638.59 2547.01 0.81 1091.58 0.00 53.06 0.02 22.74 75.80 79 89 73 1.500 N/R 30.00 0.00 30.00 0.698 316.59 2006.49 0.43 1.16 1975.72 3982.64 320 30-Mar-15 07:00 46:14:26 BS&W = 30%, 30%brine 70% crude Tr Sed. Sparge sandtrap 2 gal. Frac sand 60 342.52 68 187.81 47.02 1689.99 101.77 118.57 0.00 4086.20 2860.34 0.81 1225.86 0.00 59.59 0.02 25.54 85.13 79 89 73 1.500 N/R 30.00 0.00 30.00 0.698 284.00 2066.08 0.43 1.18 2001.26 4067.77 266 30-Mar-15 07:30 46:44:26 BS&W = 28%, 28%brine 72% crude Tr Sed.60 341.00 68 192.66 47.45 1688.31 101.77 269.35 0.00 3760.75 2707.74 0.82 1053.01 0.00 56.41 0.02 21.94 78.35 80 89 73 1.500 N/R 28.00 0.00 28.00 0.698 304.40 2122.49 0.43 1.20 2023.20 4146.12 266 30-Mar-15 08:00 47:14:27 BS&W = 28%, 28%brine 72% crude Tr Sed.Sparge sandtrap 2 gal. Frac sand 60 330.55 65 186.29 54.76 1685.96 101.74 243.61 0.00 3600.72 2592.52 0.84 1008.20 0.00 54.01 0.02 21.00 75.02 79 89 73 1.500 N/R 28.00 0.00 28.00 0.698 323.08 2176.50 0.43 1.22 2044.20 4221.13 266 30-Mar-15 08:30 47:44:27 BS&W = 26%, 26%brine 74% crude Tr Sed.60 339.29 65 193.42 45.18 1683.90 101.74 261.34 0.00 4317.09 3194.65 0.85 1122.44 0.00 66.56 0.02 23.38 89.94 80 89 73 1.500 N/R 26.00 0.00 26.00 0.698 264.63 2243.06 0.43 1.23 2067.58 4311.07 266 30-Mar-15 09:00 48:14:28 BS&W = 24%, 24%brine 76% crude Tr Sed. API= 28.2@60F 60 359.82 66 188.28 54.08 1682.27 101.74 368.85 0.00 3720.74 2827.76 0.86 892.98 0.00 58.91 0.02 18.60 77.52 82 89 73 1.500 0.886 28.2 38000 7 24.00 0.00 24.00 0.698 305.20 2301.97 0.43 1.25 2086.19 4388.59 266 30-Mar-15 09:30 48:44:28 BS&W = 24%, 24%brine 76% crude Tr Sed. 60 351.26 67 184.67 62.22 1680.66 101.73 370.95 0.00 3645.60 2770.66 0.88 874.94 0.00 57.72 0.02 18.23 75.95 84 90 73 1.500 N/R 24.00 0.00 24.00 0.698 317.35 2359.69 0.43 1.27 2104.42 4464.54 266 30-Mar-15 10:00 49:14:29 BS&W = 22%, 22% brine, Tr Sed. 78% crude. Sparge sandtrap 2 gal. Frac sand 60 347.65 67 195.42 56.37 1678.49 101.73 243.23 0.00 3680.74 2870.98 0.88 809.76 0.00 59.81 0.02 16.87 76.68 85 89 73 1.500 N/R 22.00 0.00 22.00 0.698 308.08 2419.51 0.43 1.29 2121.29 4541.22 266 30-Mar-15 10:30 49:44:29 BS&W = 18%, 18%brine,Tr Sed. 82% crude 60 347.84 67 195.32 52.70 1676.94 101.73 203.58 0.00 3648.43 2991.71 0.90 656.72 0.00 62.33 0.02 13.68 76.01 87 89 73 1.500 N/R 18.00 0.00 18.00 0.698 300.45 2481.83 0.43 1.31 2134.97 4617.23 266 30-Mar-15 11:00 50:14:29 BS&W = 20%, 20%brine 80% crude Tr Sed. Sparge sandtrap 2 gal. Frac sand 60 343.28 66 199.22 52.38 1675.09 101.73 233.32 0.00 3762.14 3009.71 0.89 752.43 0.00 62.70 0.02 15.68 78.38 85 89 73 1.500 N/R 20.00 0.00 20.00 0.698 296.50 2544.53 0.43 1.32 2150.64 4695.60 266 30-Mar-15 11:30 50:44:30 BS&W = 20%, 20% brine, Tr Sed. 80% crude 60 343.66 66 197.13 53.72 1673.85 101.72 275.07 0.00 3680.74 2944.59 0.90 736.15 0.00 61.35 0.02 15.34 76.68 86 88 73 1.500 N/R 20.00 0.00 20.00 0.698 304.99 2605.88 0.43 1.34 2165.98 4772.29 266 30-Mar-15 12:00 51:14:30 BS&W = 18%, 18%brine, Tr Sed. 82% crude. Corr. API= 28.9 60 351.83 67 206.45 41.76 1672.81 101.72 225.12 0.00 3680.74 3018.21 0.90 662.53 0.00 62.88 0.02 13.80 76.68 85 88 73 1.500 0.882 28.9 38000 7 18.00 0.00 18.00 0.698 0.00 0 297.48 2668.76 0.43 1.36 2179.78 4848.97 266 30-Mar-15 12:30 51:44:31 BS&W = 18%, 18%brine, Tr Sed. 82% crude 60 356.02 67 195.42 55.05 1670.81 101.72 335.11 0.00 3080.62 2526.11 0.90 554.51 0.00 52.63 0.02 11.55 64.18 85 88 73 1.500 N/R 18.00 0.00 18.00 0.698 354.88 2721.39 0.43 1.38 2191.34 4913.15 266 30-Mar-15 13:00 52:14:31 BS&W = 20%, 20%brine 80% crude Tr Sed. Sparge sandtrap 2 gal. Frac sand 60 346.32 66 198.27 47.87 1670.34 101.71 232.94 0.00 3635.81 2908.65 0.91 727.16 0.00 60.60 0.02 15.15 75.75 86 87 72 1.500 N/R 20.00 0.00 20.00 0.698 311.70 2781.98 0.43 1.40 2206.48 4988.89 266 30-Mar-15 13:30 52:44:32 BS&W = 16%, 16%brine, Tr Sed. 84% Crude 60 357.16 66 202.64 54.80 1675.64 101.71 279.07 0.00 3652.66 3068.23 0.91 584.43 0.00 63.92 0.02 12.18 76.10 86 88 73 1.500 N/R 16.00 0.00 16.00 0.698 297.80 2845.91 0.43 1.42 2218.66 5064.99 266 30-Mar-15 14:00 53:14:32 BS&W = 16%, 16%brine, Tr Sed. 84% Crude.Sparge sandtrap 1 gal. Frac sand 60 348.98 66 196.08 57.59 1675.81 101.70 233.51 0.00 3760.75 3159.03 0.93 601.72 0.00 65.81 0.02 12.54 78.35 88 88 73 1.500 N/R 16.00 0.00 16.00 0.698 292.90 2911.72 0.43 1.44 2231.20 5143.34 266 30-Mar-15 14:30 53:44:33 BS&W = 20%, 20% brine, Tr Sed. 80% crude. 60 359.44 66 197.13 54.29 1675.11 101.69 80.63 0.00 3980.74 3184.59 0.92 796.15 0.00 66.35 0.02 16.59 82.93 87 88 73 1.500 N/R 20.00 0.00 20.00 0.698 288.59 2978.06 0.43 1.46 2247.78 5226.27 266 30-Mar-15 15:00 54:14:33 BS&W = 20%, 20% brine, Tr Sed. 80% crude. Corr. API= 28.5 60 357.16 67 198.46 52.77 1674.10 101.69 151.54 0.00 3760.75 3008.60 0.93 752.15 0.00 62.68 0.02 15.67 78.35 87 88 73 1.500 N/R 20.00 0.00 20.00 0.690 307.98 3040.74 0.43 1.48 2263.45 5304.62 266 30-Mar-15 15:30 54:44:34 BS&W = 18%, 18%brine, Tr Sed. 82% crude 60 360.77 69 199.98 54.45 1673.44 101.68 207.40 0.00 3870.24 3173.60 0.93 696.64 0.00 66.12 0.02 14.51 80.63 88 88 72 1.500 N/R 18.00 0.00 18.00 0.690 294.31 3106.86 0.43 1.50 2277.97 5385.25 266 30-Mar-15 16:00 55:14:34 BS&W = 20%, 20% brine, Tr Sed. 80% crude. Sparge sandtrap 1 gal. Frac sand 60 366.28 69 197.41 53.06 1671.98 101.68 199.96 0.00 3630.19 2904.15 0.93 726.04 0.00 60.50 0.02 15.13 75.63 87 88 72 1.500 N/R 20.00 0.00 20.00 0.690 319.89 3167.36 0.43 1.52 2293.09 5460.88 266 30-Mar-15 16:30 55:44:35 BS&W = 16%, 16%brine, Tr Sed. 84% Crude. 60 358.49 69 201.22 51.14 1671.07 101.67 122.76 0.00 3520.70 2957.39 0.94 563.31 0.00 61.61 0.02 11.74 73.35 89 88 73 1.500 N/R 16.00 0.00 16.00 0.690 318.64 3228.98 0.43 1.54 2304.83 5534.23 266 30-Mar-15 17:00 56:14:35 BS&W = 16%, 16%brine, Tr Sed. 84% Crude. Sparge sandtrap 1 gal. Frac sand 60 364.19 69 205.12 56.10 1670.13 101.67 334.73 0.00 3680.74 3091.82 0.96 588.92 0.00 64.41 0.02 12.27 76.68 91 88 72 1.500 N/R 16.00 0.00 16.00 0.690 309.17 3293.39 0.43 1.56 2317.10 5610.91 266 30-Mar-15 17:30 56:44:35 BS&W = 16%, 16%brine, Tr Sed. 84% Crude. 60 363.81 68 202.07 55.37 1668.69 101.65 68.05 0.00 3080.62 2587.72 0.96 492.90 0.00 53.91 0.02 10.27 64.18 92 87 72 1.500 N/R 16.00 0.00 16.00 0.690 371.47 3347.30 0.43 1.58 2327.36 5675.09 266 30-Mar-15 18:00 57:14:36 BS&W = 18%, 18% brine, Tr Sed. 82% crude. Corr. API= 28.5 Gas SG 0.691 60 356.78 68 198.08 53.15 1668.54 101.65 218.83 0.00 3080.62 2526.11 0.98 554.51 0.00 52.63 0.02 11.55 64.18 94 87 72 1.500 0.884 28.5 34000 7 18.00 0.00 18.00 0.691 386.48 3399.93 0.43 1.60 2338.92 5739.27 266 30-Mar-15 18:30 57:44:36 BS&W = 16%, 16%brine, Tr Sed. 84% Crude. 60 352.40 68 204.26 49.98 1668.13 101.64 166.98 0.00 3945.63 3314.33 0.96 631.30 0.00 69.05 0.02 13.15 82.20 92 86 72 1.500 N/R 16.00 0.00 16.00 0.691 290.93 3468.97 0.43 1.62 2352.07 5821.47 266 30-Mar-15 19:00 58:14:37 BS&W = 14%, 14%brine, Tr Sed. 86% Crude. Sparge sandtrap 0.5gal. Frac sand 60 369.32 69 204.74 54.40 1666.92 101.63 317.58 0.00 3440.00 2958.40 0.97 481.60 0.00 61.63 0.02 10.03 71.67 91 86 72 1.500 N/R 14.00 0.00 14.00 0.691 326.34 3530.61 0.43 1.64 2362.10 5893.14 266 30-Mar-15 19:30 58:44:37 BS&W = 14%, 14%brine, Tr Sed. 86% Crude. 60 371.79 68 209.01 57.10 1665.49 101.63 348.84 0.00 3868.80 3327.17 0.98 541.63 0.00 69.32 0.02 11.28 80.60 93 86 72 1.500 N/R 14.00 0.00 14.00 0.691 293.27 3599.92 0.43 1.66 2373.39 5973.74 266 30-Mar-15 20:00 59:14:38 BS&W = 13%, 13%brine, Tr Sed. 87% Crude. Sparge sandtrap 0.25gal. Frac sand 60 363.24 68 206.54 59.19 1665.29 101.63 226.08 0.00 4174.13 3631.49 0.98 542.64 0.00 75.66 0.02 11.30 86.96 93 87 72 1.500 N/R 13.00 0.00 13.00 0.691 269.40 3675.58 0.43 1.68 2384.69 6060.70 266 30-Mar-15 20:30 59:44:38 BS&W = 10%, 10%brine, Tr Sed. 90% Crude. 60 361.72 67 206.16 59.76 1664.96 101.62 216.36 0.00 3704.59 3223.00 0.99 481.60 0.00 67.15 0.02 10.03 77.18 96 85 72 1.500 N/R 13.00 0.00 13.00 0.691 308.71 3742.73 0.43 1.70 2394.72 6137.88 266 30-Mar-15 21:00 60:14:39 BS&W = 10%, 10%brine, Tr Sed. 90% Crude. Water salinity 32000ppm pH 7 60 374.83 68 209.59 52.57 1664.02 101.61 340.26 0.00 3906.72 3516.05 0.99 390.67 0.00 73.25 0.02 8.14 81.39 95 86 72 1.500 N/R 32000 7 10.00 0.00 10.00 0.691 282.12 3815.98 0.43 1.72 2402.86 6219.27 266 30-Mar-15 21:30 60:44:39 BS&W = 7%, 7%brine, Tr Sed. 93% Crude 60 373.69 67 206.54 48.83 1661.98 101.61 190.24 0.00 3868.80 3597.98 1.05 270.82 0.00 74.96 0.02 5.64 80.60 83 85 71 1.500 N/R 7.00 0.00 7.00 0.691 290.57 3890.94 0.43 1.74 2408.51 6299.87 266 30-Mar-15 22:00 61:14:40 BS&W = 9%, 9%brine, Tr Sed. 91% Crude 60 370.08 67 205.88 54.21 1661.01 101.61 191.96 0.00 4480.90 4077.62 1.04 403.28 0.00 84.95 0.02 8.40 93.35 79 85 72 1.500 N/R 9.00 0.00 9.00 0.691 254.76 3975.89 0.43 1.76 2416.91 6393.22 266 30-Mar-15 22:30 61:44:40 BS&W = 7%, 7%brine 93% crude Tr Sed. Dec. choke 30/64ths. 30 370.46 68 201.69 66.31 1659.47 101.60 208.35 0.00 3654.05 3398.27 1.05 255.78 0.00 70.80 0.02 5.33 76.13 81 85 72 1.500 0.883 28.7 7.00 0.00 7.00 0.691 308.42 4046.68 0.43 1.78 2422.24 6469.34 266 30-Mar-15 23:00 62:14:41 BS&W = 7%, 7%brine 93% crude Tr Sed. Dec choke 24/64ths (22:38)24 475.00 64 62.76 405.95 1729.72 101.40 184.33 0.00 1897.20 1764.40 0.51 132.80 0.00 36.76 0.01 2.77 39.53 56 83 74 1.500 N/R 7.00 0.00 7.00 0.691 288.47 4083.44 0.43 1.79 2425.00 6508.87 266 30-Mar-15 23:30 62:44:41 BS&W = 4%, 4%brine 96% crude Tr Sed. Increase choke 28/64ths (23:20)28 479.19 60 48.02 429.74 1735.95 101.37 143.35 0.00 720.14 691.34 0.25 28.81 0.00 14.40 0.01 0.60 15.00 59 81 74 1.500 N/R 4.00 0.00 4.00 0.691 363.18 4097.84 0.43 1.80 2425.60 6523.87 266 31-Mar-15 00:00 63:14:42 BS&W = 3%, 3%brine 97% crude Tr Sed. Increase choke 32/64ths. Gas SG 0.709 32 455.62 57 78.64 367.27 1742.64 101.36 98.36 0.00 632.40 613.43 0.23 18.97 0.00 12.78 0.00 0.40 13.18 71 83 72 1.500 N/R 40000 7 3.00 0.00 3.00 0.709 378.70 4110.62 0.43 1.80 2426.00 6537.05 266 31-Mar-15 00:30 63:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude. Rock choke to maintain rate 32 405.25 59 93.67 299.66 1736.75 101.39 89.54 0.00 1040.21 1009.00 0.34 31.21 0.00 21.02 0.01 0.65 21.67 64 82 70 1.500 N/R 3.00 0.00 3.00 0.709 339.33 4131.64 0.43 1.81 2426.65 6558.72 266 31-Mar-15 01:00 64:14:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude. Rock choke 32 456.00 63 120.20 310.45 1729.36 101.39 118.76 0.00 1618.20 1553.47 0.44 64.73 0.00 32.36 0.01 1.35 33.71 69 82 70 1.500 N/R 4.00 0.00 4.00 0.709 282.67 4164.01 0.43 1.82 2428.00 6592.43 266 31-Mar-15 01:30 64:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 32 475.57 63 120.01 322.51 1731.71 101.42 132.10 0.00 1760.35 1707.54 0.53 52.81 0.00 35.57 0.01 1.10 36.67 78 82 71 1.500 N/R 3.00 0.00 3.00 0.709 308.15 4199.58 0.43 1.83 2429.10 6629.10 266 31-Mar-15 02:00 65:14:00 BS&W = 2.5%, 2.5%brine Tr Sed. 97.5% Crude. Rock choke 32 472.34 63 120.20 325.52 1732.42 101.40 121.04 0.00 1854.74 1808.37 0.54 46.37 0.00 37.67 0.01 0.97 38.64 85 82 71 1.500 N/R 2.50 0.00 2.50 0.709 295.88 4237.26 0.43 1.84 2430.06 6667.75 266 31-Mar-15 02:30 65:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 32 466.26 63 121.24 322.22 1732.37 101.40 113.99 0.00 1760.35 1707.54 0.51 52.81 0.00 35.57 0.01 1.10 36.67 81 82 71 1.500 N/R 3.00 0.00 3.00 0.709 297.13 4272.83 0.43 1.85 2431.16 6704.42 266 31-Mar-15 03:00 66:14:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude. Corr API = 28.3. Gas SG 0.711 32 479.38 63 111.35 346.81 1733.98 101.39 86.90 0.00 1840.37 1785.16 0.51 55.21 0.00 37.19 0.01 1.15 38.34 80 82 71 1.500 0.885 28.3 40000 7 3.00 0.00 3.00 0.711 286.09 4310.02 0.43 1.86 2432.31 6742.76 266 Expro Confidential 5/5/2015 Page 3 CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives 31-Mar-15 03:30 66:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 471.58 62 124.29 325.02 1738.06 101.37 207.78 0.00 1600.32 1568.31 0.48 32.01 0.00 32.67 0.01 0.67 33.34 74 82 71 1.500 N/R 2.00 0.00 2.00 0.711 303.05 4342.69 0.43 1.87 2432.98 6776.10 266 31-Mar-15 04:00 67:14:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude. Rock choke 32 462.84 63 130.94 314.97 1736.94 101.38 151.93 0.00 1636.80 1587.70 0.47 49.10 0.00 33.08 0.01 1.02 34.10 73 83 71 1.500 N/R 3.00 0.00 3.00 0.711 295.32 4375.77 0.43 1.88 2434.00 6810.20 266 31-Mar-15 04:30 67:44:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude. Rock choke 32 463.60 63 137.31 303.70 1734.24 101.38 156.31 0.00 1488.00 1428.48 0.50 59.52 0.00 29.76 0.01 1.24 31.00 78 84 71 1.500 N/R 4.00 0.00 4.00 0.711 348.70 4405.53 0.43 1.89 2435.24 6841.20 266 31-Mar-15 05:00 68:14:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude. Rock choke 32 470.44 64 114.68 336.50 1734.73 101.36 0.00 0.00 1860.00 1785.60 0.51 74.40 0.00 37.20 0.01 1.55 38.75 82 84 71 1.500 N/R 4.00 0.00 4.00 0.711 288.31 4442.73 0.43 1.90 2436.79 6879.95 266 31-Mar-15 05:30 68:44:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude. Rock choke 32 468.54 64 141.21 293.95 1732.23 101.37 131.34 0.00 1852.35 1778.26 0.53 74.09 0.00 37.05 0.01 1.54 38.59 85 84 71 1.500 N/R 4.00 0.00 4.00 0.711 300.20 4479.78 0.43 1.92 2438.34 6918.54 266 31-Mar-15 06:00 69:14:00 BS&W = 6%, 6%brine Tr Sed. 94% Crude. Gas SG 0.712 32 461.70 63 128.57 301.14 1730.13 101.37 127.14 0.00 1836.84 1726.63 0.53 110.21 0.00 35.97 0.01 2.30 38.27 86 84 71 1.500 0.885 28.3 38000 7 6.00 0.00 6.00 0.712 309.41 4515.75 0.43 1.93 2440.63 6956.81 266 31-Mar-15 06:30 69:44:00 BS&W = 6%, 6%brine Tr Sed. 94% Crude.32 472.34 65 140.07 311.12 1731.30 101.37 121.81 0.00 1732.33 1628.39 0.52 103.94 0.00 33.92 0.01 2.17 36.09 83 85 71 1.500 N/R 6.00 0.00 6.00 0.712 319.96 4549.67 0.43 1.94 2442.80 6992.90 266 31-Mar-15 07:00 70:14:00 BS&W = 3%, 3%brine, Tr Sed. 97% Crude. Sparge sandtrap 0.5gal. Frac sand 32 474.62 64 124.76 327.37 1733.74 101.37 275.45 0.00 1652.72 1603.14 0.54 49.58 0.00 33.40 0.01 1.03 34.43 87 84 71 1.500 N/R 3.00 0.00 3.00 0.712 337.54 4583.07 0.43 1.95 2443.83 7027.33 266 31-Mar-15 07:30 70:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude.32 477.86 64 98.04 374.07 1741.57 101.30 124.29 0.00 1488.00 1458.24 0.47 29.76 0.00 30.38 0.01 0.62 31.00 73 84 72 1.500 N/R 2.00 0.00 2.00 0.712 321.23 4613.45 0.43 1.96 2444.45 7058.33 266 31-Mar-15 08:00 71:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude.32 487.17 61 84.82 386.91 1744.96 101.30 94.17 0.00 1240.45 1215.64 0.40 24.81 0.00 25.33 0.01 0.52 25.84 61 85 72 1.500 N/R 2.00 0.00 2.00 0.712 328.82 4638.78 0.43 1.97 2444.97 7084.17 266 31-Mar-15 08:30 71:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. 1.00 inch orifice plate in service 32 457.52 60 130.85 300.36 1737.24 101.29 84.64 0.00 1264.80 1239.50 0.38 25.30 0.00 25.82 0.01 0.53 26.35 57 87 72 1.500 N/R 2.00 0.00 2.00 0.712 307.79 4664.60 0.43 1.97 2445.50 7110.52 266 31-Mar-15 09:00 72:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Corr API = 28.1. Gas SG 0.706, rock choke 32 476.34 62 129.42 330.43 1734.97 101.30 14.87 0.00 1914.77 1876.47 0.39 38.30 0.00 39.09 0.01 0.80 39.89 86 83 70 1.500 0.887 28.1 40000 7 2.00 0.00 2.00 0.706 207.14 4703.70 0.43 1.98 2446.29 7150.41 266 31-Mar-15 09:30 72:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude. Rock choke 32 477.10 63 101.94 351.70 1741.56 101.30 101.98 0.00 1600.32 1552.31 0.43 48.01 0.00 32.34 0.01 1.00 33.34 77 84 72 1.500 N/R 3.00 0.00 3.00 0.706 276.59 4736.04 0.43 1.99 2447.29 7183.75 266 31-Mar-15 10:00 73:14:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude. Rock choke 32 468.92 65 124.19 326.05 1737.41 101.29 104.65 0.00 1846.37 1790.98 0.45 55.39 0.00 37.31 0.01 1.15 38.47 82 84 71 1.500 N/R 3.00 0.00 3.00 0.706 253.67 4773.35 0.43 2.00 2448.45 7222.22 266 31-Mar-15 10:30 73:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude. Rock choke 32 480.71 63 100.99 371.12 1741.89 101.27 92.26 0.00 1600.32 1568.31 0.41 32.01 0.00 32.67 0.01 0.67 33.34 72 85 72 1.500 N/R 2.00 0.00 2.00 0.706 258.27 4806.02 0.43 2.01 2449.11 7255.56 266 31-Mar-15 11:00 74:14:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude. Rock choke 32 487.55 62 98.80 371.99 1744.89 101.30 77.96 0.00 1320.26 1300.46 0.36 19.80 0.00 27.09 0.01 0.41 27.51 64 85 72 1.500 N/R 1.50 0.00 1.50 0.706 276.54 4833.11 0.43 2.02 2449.53 7283.07 266 31-Mar-15 11:30 74:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude. Rock choke 32 479.00 62 129.23 326.86 1734.79 101.33 93.98 0.00 1840.37 1785.16 0.46 55.21 0.00 37.19 0.01 1.15 38.34 83 83 71 1.500 N/R 3.00 0.00 3.00 0.706 260.20 4870.30 0.43 2.03 2450.68 7321.41 266 31-Mar-15 12:00 75:14:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude. Corr API = 29.3. Gas SG 0.706 32 474.81 62 113.35 331.24 1737.79 101.33 97.79 0.00 1640.33 1591.12 0.43 49.21 0.00 33.15 0.01 1.03 34.17 77 84 71 1.500 0.880 29.3 39000 7 3.00 0.00 3.00 0.706 270.67 4903.45 0.43 2.04 2451.70 7355.58 266 31-Mar-15 12:30 75:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude. Rock choke 32 478.43 63 103.08 357.34 1742.11 101.31 87.69 0.00 1711.20 1659.86 0.40 51.34 0.00 34.58 0.01 1.07 35.65 72 83 71 1.500 N/R 3.00 0.00 3.00 0.706 240.08 4938.03 0.43 2.04 2452.77 7391.23 266 31-Mar-15 13:00 76:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude.32 469.87 61 140.55 298.39 1732.92 101.34 85.02 0.00 1413.60 1385.33 0.44 28.27 0.00 28.86 0.01 0.59 29.45 79 82 70 1.500 N/R 2.00 0.00 2.00 0.706 314.67 4966.89 0.43 2.05 2453.36 7420.68 320 31-Mar-15 13:30 76:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Rock choke 32 483.18 61 129.71 333.35 1746.47 101.27 93.21 0.00 1636.80 1604.06 0.38 32.74 0.00 33.42 0.01 0.68 34.10 75 82 73 1.500 N/R 2.00 0.00 2.00 0.706 237.43 5000.31 0.43 2.06 2454.04 7454.78 320 31-Mar-15 14:00 77:14:00 BS&W = 1%, 1%brine Tr Sed. 99% Crude. (SHUT IN WELL AT CHOKE MANIFOLD)32 450.29 62 141.31 285.94 1732.78 101.34 86.16 0.00 1709.81 1692.71 0.47 17.10 0.00 35.26 0.01 0.36 35.62 83 82 70 1.500 N/R 1.00 0.00 1.00 0.706 278.04 5035.58 0.43 2.07 2454.40 7490.40 320 31-Mar-15 14:30 77:44:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 517.77 42 10.56 497.36 1773.80 100.93 46.89 0.00 0.00 0.00 0.04 0.00 0.00 0.00 0.00 0.00 0.00 74 75 67 0.000 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.07 2454.40 7490.40 0 31-Mar-15 15:00 78:14:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 529.37 30 10.65 511.02 1778.89 100.58 2.86 0.00 0.00 0.00 0.04 0.00 0.00 0.00 0.00 0.00 0.00 77 69 64 0.000 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.07 2454.40 7490.40 0 31-Mar-15 15:30 78:44:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 540.96 28 3.42 522.21 1782.33 100.35 0.00 0.00 0.00 0.00 0.04 0.00 0.00 0.00 0.00 0.00 0.00 79 60 61 0.000 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.07 2454.40 7490.40 0 31-Mar-15 16:00 79:14:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 551.04 23 5.33 535.95 1784.99 100.18 0.00 0.00 0.00 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.00 74 56 58 0.000 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.07 2454.40 7490.40 0 31-Mar-15 16:30 79:44:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 551.04 21 3.61 532.57 1787.20 100.03 0.00 0.00 0.00 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.00 71 56 58 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.07 2454.40 7490.40 0 31-Mar-15 17:00 80:14:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 551.99 17 4.28 539.26 1789.12 99.91 0.00 0.00 0.00 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.00 74 55 56 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 17:30 80:44:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 558.26 14 5.14 537.65 1790.72 99.82 0.00 0.00 0.00 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.00 72 56 56 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 18:00 81:14:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 561.68 13 1.81 545.31 1792.23 99.75 0.00 0.00 0.00 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.00 72 56 57 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 18:30 81:44:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 561.87 13 6.56 542.63 1793.58 99.69 0.00 0.00 0.00 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.00 73 58 57 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 19:00 82:14:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 552.56 12 2.47 545.59 1794.76 99.63 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 72 59 58 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 19:30 82:44:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 557.12 12 0.00 545.04 1795.79 99.57 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 73 60 59 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 20:00 83:14:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 559.97 11 0.00 549.75 1796.76 99.53 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 73 62 59 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 20:30 83:44:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 556.17 11 0.00 554.28 1797.61 99.49 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 74 63 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 21:00 84:14:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 561.87 10 2.95 542.85 1798.44 99.46 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 73 64 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 21:30 84:44:00 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 548.56 9 0.00 542.40 1799.27 99.43 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 73 64 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 22:00 85:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 550.85 9 4.56 535.39 1800.04 99.42 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 73 64 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 22:30 85:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 553.89 8 1.24 538.15 1800.78 99.40 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 73 64 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 23:00 86:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 554.46 8 1.52 540.32 1801.49 99.39 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 74 65 61 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 31-Mar-15 23:30 86:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 552.18 8 3.71 537.57 1802.19 99.36 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 72 66 61 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 00:00 87:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 544.95 8 0.00 538.26 1802.89 99.35 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 72 68 62 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 00:30 87:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 548.95 7 1.14 525.43 1803.52 99.34 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 73 68 62 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 01:00 88:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 543.43 7 4.18 533.70 1804.16 99.33 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 73 70 62 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 01:30 88:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 539.82 7 2.19 522.31 1804.78 99.32 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 54 67 64 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 02:00 89:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 540.58 8 1.81 525.14 1805.35 99.30 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 34 68 64 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 02:30 89:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 542.48 7 4.18 519.94 1805.89 99.28 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 36 68 63 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 03:00 90:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 541.15 7 2.38 526.83 1806.44 99.27 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 37 67 62 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 03:30 90:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 534.69 7 3.33 526.07 1806.97 99.26 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 36 67 62 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 04:00 91:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 539.06 7 1.81 525.71 1807.47 99.24 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 36 67 62 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 04:30 91:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 537.92 7 0.00 518.47 1807.97 99.23 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 38 65 61 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 05:00 92:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 532.22 6 0.00 526.76 1808.43 99.22 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 34 66 62 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 05:30 92:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 527.28 7 0.00 520.92 1808.88 99.20 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 35 69 62 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 06:00 93:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 532.41 6 0.38 517.71 1809.31 99.19 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 36 69 62 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 06:30 93:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 525.38 6 0.00 518.66 1809.75 99.17 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 37 70 63 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 07:00 94:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 524.04 5 3.61 514.67 1810.18 99.16 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 40 67 62 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 07:30 94:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 520.62 5 1.81 509.31 1810.58 99.15 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 39 63 61 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 08:00 95:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 525.76 5 0.00 519.04 1810.98 99.14 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 37 61 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 08:30 95:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 524.81 5 0.00 516.21 1811.38 99.12 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 33 63 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 09:00 96:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 520.05 6 2.19 507.05 1811.77 99.11 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 33 66 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 09:30 96:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 522.14 6 0.00 519.98 1812.16 99.10 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 38 64 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 10:00 97:14:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 516.25 7 1.62 517.80 1812.52 99.09 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 38 62 59 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 10:30 97:44:01 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 518.34 8 2.19 511.19 1812.90 99.09 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 37 61 59 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 11:00 98:14:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 522.52 9 3.71 509.86 1813.26 99.08 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 35 61 59 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 11:30 98:44:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 513.40 9 3.71 510.05 1813.59 99.07 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 34 63 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 12:00 99:14:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 520.24 10 0.00 510.18 1813.93 99.06 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 34 67 61 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 12:30 99:44:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 514.35 11 3.33 499.69 1814.25 99.04 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 35 71 62 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 Expro Confidential 5/5/2015 Page 4 CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives 01-Apr-15 13:00 100:14:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 518.53 11 1.14 502.25 1814.56 99.03 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 39 70 61 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 13:30 100:44:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 513.78 11 0.86 509.13 1814.87 99.03 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 39 68 61 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 14:00 101:14:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 515.11 11 3.04 499.22 1815.17 99.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 38 66 61 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 14:30 101:44:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 514.92 11 0.00 501.70 1815.47 99.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 37 64 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 15:00 102:14:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 516.06 11 4.47 495.34 1815.76 99.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 37 62 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 15:30 102:44:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 505.99 18 2.76 501.20 1816.04 99.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 36 62 60 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 16:00 103:14:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 512.45 20 0.00 506.41 1816.30 98.99 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 33 65 61 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 16:30 103:44:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 511.69 23 1.14 499.80 1816.56 98.98 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 34 69 62 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 17:00 104:14:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 503.52 21 4.09 493.27 1816.80 98.96 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 35 74 63 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 17:30 104:44:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 510.17 21 1.62 500.46 1817.03 98.96 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 27 73 63 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 18:00 105:14:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 506.56 20 0.00 507.35 1817.26 98.95 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 14 71 63 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 18:30 105:44:02 Well shut-in at Choke Manifold. Monitoring WHP, BHP & BHT 0 510.17 20 4.56 493.55 1817.49 98.94 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 5 70 63 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 0 01-Apr-15 19:00 106:14:02 Open well through Expro's separator on 16/64ths adjustable choke 16 496.10 19 19.59 473.81 1815.31 98.94 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 7 65 61 N/R 0.00 0.00 0.00 N/R 5035.58 0.43 2.08 2454.40 7490.40 120 01-Apr-15 19:30 106:44:02 19:12hrs: Switched to 16/64ths fixed choke. 19:20hrs: 1.000" orifice plate in service 16 440.03 29 136.55 297.48 1806.58 100.27 0.00 0.00 111.00 111.00 0.06 0.00 0.00 2.31 0.00 0.00 2.31 102 71 72 1.000 N/R 0.00 0.00 0.00 0.706 526.44 5037.89 0.43 2.08 2454.40 7492.71 120 01-Apr-15 20:00 107:14:02 BS&W = 0.1%, 0.1%brine Tr Sed. 99.9% Crude. 0.750" orifice plate out of service 20:15hrs 16 416.84 29 147.87 260.91 1809.54 100.65 0.00 0.00 297.60 297.30 0.14 0.30 0.00 6.19 0.00 0.01 6.20 104 75 73 1.000 N/R 0.10 0.00 0.10 0.706 454.20 5044.08 0.43 2.08 2454.41 7498.91 120 01-Apr-15 20:30 107:44:02 BS&W = 0.3%, 0.3%brine Tr Sed. 99.7% Crude. 0.750" orifice plate in service 20:15hrs 16 364.00 30 124.29 230.22 1809.42 100.58 0.00 0.00 334.80 333.80 0.08 1.00 0.00 6.95 0.00 0.02 6.98 140 76 73 0.750 N/R 0.30 0.00 0.30 0.706 247.68 5051.04 0.43 2.08 2454.43 7505.89 120 01-Apr-15 21:00 108:14:02 BS&W = 1%, 1%brine Tr Sed. 99% Crude. API 29.3 16 344.99 31 124.95 203.92 1810.23 100.58 0.00 0.00 446.40 437.47 0.07 4.46 4.46 9.11 0.00 0.09 9.30 116 76 73 0.750 0.880 29.3 1.00 0.00 1.00 0.706 156.09 5060.15 0.43 2.08 2454.52 7515.19 120 01-Apr-15 21:30 108:44:02 BS&W = 0.1%, 0.1%brine Tr Sed. 99.9% Crude 16 383.58 38 143.40 240.13 1806.72 100.61 0.00 0.00 483.60 482.63 0.06 0.48 0.48 10.05 0.00 0.01 10.08 119 74 72 0.750 N/R 0.20 0.10 0.10 0.706 114.06 5070.21 0.44 2.09 2454.53 7525.26 120 01-Apr-15 22:00 109:14:02 BS&W = 72%, 72%brine Tr Sed. 28% Crude. Water salinity 40000ppm, pH 7 16 472.53 41 144.35 319.46 1809.42 100.65 0.00 0.00 446.60 125.05 0.06 321.55 0.00 2.61 0.00 6.70 9.30 134 74 70 0.750 N/R 40000 7 72.00 0.00 72.00 0.706 492.43 5072.81 0.44 2.09 2461.23 7534.57 120 01-Apr-15 22:30 109:44:02 BS&W = 18%, 18%brine Tr Sed. 82% Crude. 0.500" orifice plate in service 16 479.95 40 137.03 332.82 1809.16 100.68 0.00 0.00 520.80 427.06 0.05 93.74 0.00 8.90 0.00 1.95 10.85 142 75 72 0.500 N/R 18.00 0.00 18.00 0.706 107.69 5081.71 0.44 2.09 2463.18 7545.42 120 01-Apr-15 23:00 110:14:02 BS&W = 7%, 7%brine Tr Sed. 93% Crude 16 483.37 40 135.22 342.92 1809.06 100.70 0.00 0.00 446.40 415.15 0.07 31.25 0.00 8.65 0.00 0.65 9.30 127 76 73 0.500 N/R 7.00 0.00 7.00 0.706 162.50 5090.36 0.44 2.09 2463.83 7554.72 120 01-Apr-15 23:30 110:44:03 BS&W = 4%, 4%brine Tr Sed. 96% Crude 16 496.29 40 135.89 344.51 1808.80 100.71 0.00 0.00 427.80 410.69 0.07 17.11 0.00 8.56 0.00 0.36 8.91 129 78 73 0.500 N/R 4.00 0.00 4.00 0.706 168.19 5098.91 0.44 2.09 2464.19 7563.63 120 02-Apr-15 00:00 111:14:03 BS&W = 3%, 3%brine Tr Sed. 97% Crude 16 496.48 40 135.03 354.60 1808.63 100.72 0.00 0.00 446.40 433.01 0.07 13.39 0.00 9.02 0.00 0.28 9.30 130 79 73 0.500 N/R 3.00 0.00 3.00 0.706 161.32 5107.93 0.44 2.09 2464.47 7572.93 120 02-Apr-15 00:30 111:44:03 BS&W = 2%, 2%brine Tr Sed. 98% Crude 16 498.38 40 142.35 347.85 1808.51 100.73 0.00 0.00 427.80 419.24 0.07 8.56 0.00 8.73 0.00 0.18 8.91 133 80 74 0.500 N/R 2.00 0.00 2.00 0.706 169.51 5116.67 0.44 2.09 2464.65 7581.84 120 02-Apr-15 01:00 112:14:03 BS&W = 1%, 1%brine Tr Sed. 99% Crude 16 496.86 40 139.88 349.19 1808.35 100.75 0.00 0.00 409.20 405.11 0.07 4.09 0.00 8.44 0.00 0.09 8.53 134 82 74 0.500 N/R 1.00 0.00 1.00 0.706 176.52 5125.11 0.44 2.09 2464.73 7590.37 120 02-Apr-15 01:30 112:44:03 BS&W = 1%, 1%brine Tr Sed. 99% Crude 16 501.62 40 144.07 341.42 1808.12 100.75 0.00 0.00 446.40 441.94 0.07 4.46 0.00 9.21 0.00 0.09 9.30 135 83 74 0.500 N/R 1.00 0.00 1.00 0.706 162.27 5134.32 0.44 2.10 2464.82 7599.67 120 02-Apr-15 02:00 113:14:03 BS&W = 0.7%, 0.7%brine Tr Sed. 99.3% Crude 16 497.24 39 144.73 349.80 1808.10 100.76 0.00 0.00 427.80 424.81 0.07 2.99 0.00 8.85 0.00 0.06 8.91 137 82 74 0.500 N/R 0.70 0.00 0.70 0.706 170.44 5143.17 0.44 2.10 2464.89 7608.58 120 02-Apr-15 02:30 113:44:03 BS&W = 0.5%, 0.5%brine Tr Sed. 99.5% Crude 16 491.16 40 143.97 342.65 1807.99 100.76 0.00 0.00 372.00 370.14 0.07 1.86 0.00 7.71 0.00 0.04 7.75 137 82 73 0.500 N/R 0.50 0.00 0.50 0.706 195.88 5150.88 0.44 2.10 2464.93 7616.33 120 02-Apr-15 03:00 114:14:03 BS&W = 0.8%, 0.8%brine Tr Sed. 99.2% Crude. Corr. API= 30.5 16 497.05 40 137.12 352.13 1807.78 100.77 0.00 0.00 502.20 498.18 0.07 4.02 0.00 10.38 0.00 0.08 10.46 136 82 73 0.500 0.873 30.5 0.80 0.00 0.80 0.706 145.57 5161.26 0.44 2.10 2465.01 7626.79 120 02-Apr-15 03:30 114:44:03 BS&W = 4%, 4%brine Tr Sed. 96% Crude 16 494.58 40 138.93 346.56 1807.81 100.77 0.00 0.00 446.40 428.54 0.07 17.86 0.00 8.93 0.00 0.37 9.30 136 81 73 0.500 N/R 4.00 0.00 4.00 0.706 169.05 5170.18 0.44 2.10 2465.38 7636.09 120 02-Apr-15 04:00 115:14:03 BS&W = 1%, 1%brine Tr Sed. 99% Crude 16 494.58 40 141.40 350.12 1807.70 100.77 0.00 0.00 372.00 368.28 0.07 3.72 0.00 7.67 0.00 0.08 7.75 136 82 73 0.500 N/R 1.00 0.00 1.00 0.706 196.72 5177.86 0.44 2.10 2465.46 7643.84 120 02-Apr-15 04:30 115:44:03 BS&W = 0.7%, 0.7%brine Tr Sed. 99.3% Crude 16 500.48 40 137.50 350.43 1807.63 100.78 0.00 0.00 409.20 406.34 0.07 2.86 0.00 8.47 0.00 0.06 8.53 134 82 73 0.500 N/R 0.70 0.00 0.70 0.706 176.56 5186.32 0.44 2.11 2465.52 7652.37 120 02-Apr-15 05:00 116:14:03 BS&W = 0.7%, 0.7%brine Tr Sed. 99.3% Crude 16 503.33 40 142.93 341.43 1807.55 100.78 0.00 0.00 372.00 369.40 0.07 2.60 0.00 7.70 0.00 0.05 7.75 134 82 73 0.500 N/R 0.70 0.00 0.70 0.706 193.97 5194.02 0.44 2.11 2465.57 7660.12 120 02-Apr-15 05:30 116:44:03 BS&W = 0.5%, 0.5%brine Tr Sed. 99.5% Crude 16 498.19 40 142.07 344.36 1807.51 100.78 0.00 0.00 446.00 443.77 0.07 2.23 0.00 9.25 0.00 0.05 9.29 133 83 73 0.500 N/R 0.50 0.00 0.50 0.706 160.67 5203.26 0.44 2.11 2465.62 7669.41 120 02-Apr-15 06:00 117:14:03 BS&W = 0.5%, 0.5%brine Tr Sed. 99.5% Crude 16 497.05 40 137.98 349.39 1807.26 100.78 0.00 0.00 446.00 443.77 0.07 2.23 0.00 9.25 0.00 0.05 9.29 133 82 73 0.500 N/R 0.50 0.00 0.50 0.706 159.97 5212.51 0.44 2.11 2465.67 7678.70 120 02-Apr-15 06:30 117:44:03 BS&W = 0.7%, 0.7%brine Tr Sed. 99.3% Crude 16 497.24 38 137.12 350.81 1807.44 100.78 0.00 0.00 334.80 332.46 0.07 2.34 0.00 6.93 0.00 0.05 6.98 133 83 73 0.500 N/R 0.70 0.00 0.70 0.706 214.62 5219.43 0.44 2.11 2465.71 7685.68 120 02-Apr-15 07:00 118:14:03 BS&W = 1%, 1%brine Tr Sed. 99% Crude 16 501.81 40 141.31 345.31 1807.27 100.78 0.00 0.00 297.60 294.62 0.07 2.98 0.00 6.14 0.00 0.06 6.20 133 84 73 0.500 N/R 1.00 0.00 1.00 0.706 239.67 5225.57 0.44 2.11 2465.78 7691.88 120 02-Apr-15 07:30 118:44:03 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude 16 500.86 40 146.63 340.55 1806.84 100.79 0.00 0.00 446.40 439.70 0.07 6.70 0.00 9.16 0.00 0.14 9.30 134 84 74 0.500 N/R 1.50 0.00 1.50 0.706 161.38 5234.73 0.44 2.11 2465.92 7701.18 120 02-Apr-15 08:00 119:14:03 BS&W = 1%, 1%brine Tr Sed. 99% Crude 16 494.77 40 152.81 339.08 1807.07 100.79 0.00 0.00 457.63 453.05 0.07 4.58 0.00 9.44 0.00 0.10 9.53 136 83 74 0.500 N/R 1.00 0.00 1.00 0.706 159.36 5244.17 0.44 2.12 2466.01 7710.71 120 02-Apr-15 08:30 119:44:03 BS&W = 1%, 1%brine Tr Sed. 99% Crude 16 503.14 40 139.69 351.26 1806.93 100.80 0.00 0.00 388.85 384.96 0.07 3.89 0.00 8.02 0.00 0.08 8.10 136 83 73 0.500 N/R 1.00 0.00 1.00 0.706 189.55 5252.19 0.44 2.12 2466.09 7718.81 120 02-Apr-15 09:00 120:14:03 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude. Corr. API= 29.3 16 496.10 41 141.59 355.01 1806.87 100.80 0.00 0.00 400.08 394.08 0.08 6.00 0.00 8.21 0.00 0.13 8.34 138 82 74 0.500 0.880 29.3 40000 7 1.50 0.00 1.50 0.688 190.62 5260.40 0.44 2.12 2466.22 7727.15 120 02-Apr-15 09:30 120:44:03 BS&W = 1%, 1%brine Tr Sed. 99% Crude 16 495.72 40 145.59 346.87 1806.86 100.80 0.00 0.00 400.80 396.79 0.08 4.01 0.00 8.27 0.00 0.08 8.35 138 81 74 0.500 N/R 1.00 0.00 1.00 0.688 191.31 5268.67 0.44 2.12 2466.30 7735.50 120 02-Apr-15 10:00 121:14:03 BS&W = 0.5%, 0.5%brine Tr Sed. 99.5% Crude 16 503.33 41 141.59 348.61 1806.68 100.80 0.00 0.00 440.09 437.89 0.08 2.20 0.00 9.12 0.00 0.05 9.17 136 81 74 0.500 N/R 0.50 0.00 0.50 0.688 172.25 5277.79 0.44 2.12 2466.35 7744.66 120 02-Apr-15 10:30 121:44:03 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude 16 502.95 40 139.41 346.65 1806.65 100.80 0.00 0.00 400.08 394.08 0.07 6.00 0.00 8.21 0.00 0.13 8.34 135 83 75 0.500 N/R 1.50 0.00 1.50 0.688 189.59 5286.00 0.44 2.12 2466.47 7753.00 120 02-Apr-15 11:00 122:14:03 BS&W = 0.5%, 0.5%brine Tr Sed. 99.5% Crude 16 502.38 41 140.93 343.43 1806.29 100.80 0.00 0.00 360.07 358.27 0.07 1.80 0.00 7.46 0.00 0.04 7.50 137 84 75 0.500 N/R 0.50 0.00 0.50 0.688 209.14 5293.46 0.44 2.13 2466.51 7760.50 120 02-Apr-15 11:30 122:44:03 BS&W = 0.7%, 0.7%brine Tr Sed. 99.3% Crude 16 503.52 41 143.31 348.59 1806.35 100.80 0.00 0.00 400.08 397.28 0.08 2.80 0.00 8.28 0.00 0.06 8.34 138 84 74 0.500 N/R 0.70 0.00 0.70 0.688 189.22 5301.74 0.44 2.13 2466.57 7768.84 120 02-Apr-15 12:00 123:14:03 BS&W = 0.7%, 0.7%brine Tr Sed. 99.3% Crude 16 500.48 42 138.93 350.51 1806.39 100.80 0.00 0.00 400.08 397.28 0.08 2.80 0.00 8.28 0.00 0.06 8.34 138 84 75 0.500 N/R 0.70 0.00 0.70 0.688 189.86 5310.02 0.44 2.13 2466.63 7777.17 120 02-Apr-15 12:30 123:44:03 BS&W = 0.7%, 0.7%brine Tr Sed. 99.3% Crude 16 494.39 42 140.64 342.40 1806.29 100.80 0.00 0.00 400.08 397.28 0.08 2.80 0.00 8.28 0.00 0.06 8.34 137 83 75 0.500 N/R 0.70 0.00 0.70 0.688 189.27 5318.29 0.44 2.13 2466.68 7785.51 120 02-Apr-15 13:00 124:14:03 BS&W = 0.7%, 0.7%brine Tr Sed. 99.3% Crude 16 501.05 40 142.16 343.14 1806.32 100.80 0.00 0.00 400.08 397.28 0.08 2.80 0.00 8.28 0.00 0.06 8.34 137 83 75 0.500 N/R 0.70 0.00 0.70 0.688 189.40 5326.57 0.44 2.13 2466.74 7793.84 120 02-Apr-15 13:30 124:44:02 BS&W = 0.7%, 0.7%brine Tr Sed. 99.3% Crude 16 493.06 40 143.50 347.65 1806.26 100.80 0.00 0.00 400.08 397.28 0.08 2.80 0.00 8.28 0.00 0.06 8.34 137 83 75 0.500 N/R 0.70 0.00 0.70 0.688 189.47 5334.85 0.44 2.13 2466.80 7802.18 120 02-Apr-15 14:00 125:14:02 BS&W = 0.7%, 0.7%brine Tr Sed. 99.3% Crude 16 493.82 40 138.08 343.08 1806.25 100.80 0.00 0.00 480.10 476.74 0.07 3.36 0.00 9.93 0.00 0.07 10.00 136 83 74 0.500 N/R 0.70 0.00 0.70 0.688 156.91 5344.78 0.44 2.13 2466.87 7812.18 120 02-Apr-15 14:30 125:44:02 BS&W = 0.5%, 0.5%brine Tr Sed. 99.5% Crude. Corr. API= 29.9 16 499.52 42 142.45 339.46 1806.20 100.80 0.00 0.00 480.10 477.70 0.07 2.40 0.00 9.95 0.00 0.05 10.00 134 82 73 0.500 0.877 29.9 40000 7 0.50 0.00 0.50 0.691 155.76 5354.73 0.44 2.14 2466.92 7822.18 120 02-Apr-15 15:00 126:14:02 BS&W = 0.7%, 0.7%brine Tr Sed. 99.3% Crude 16 498.76 41 143.02 339.83 1806.18 100.81 0.00 0.00 400.08 397.28 0.07 2.80 0.00 8.28 0.00 0.06 8.34 135 82 75 0.500 N/R 0.70 0.00 0.70 0.691 188.71 5363.01 0.44 2.14 2466.98 7830.52 120 02-Apr-15 15:30 126:44:02 BS&W = 0.5%, 0.5%brine Tr Sed. 99.5% Crude 16 491.54 41 120.48 358.41 1806.20 100.81 0.00 0.00 400.08 398.08 0.08 2.00 0.00 8.29 0.00 0.04 8.34 119 82 75 0.500 N/R 0.50 0.00 0.50 0.691 207.39 5371.30 0.44 2.14 2467.02 7838.85 120 02-Apr-15 16:00 127:14:02 BS&W = 0.5%, 0.5%brine Tr Sed. 99.5% Crude 16 492.49 43 118.58 362.76 1806.15 100.81 0.00 0.00 400.08 398.08 0.08 2.00 0.00 8.29 0.00 0.04 8.34 112 82 75 0.500 N/R 0.50 0.00 0.50 0.691 197.45 5379.59 0.44 2.14 2467.06 7847.19 120 02-Apr-15 16:30 127:44:02 BS&W = 0.5%, 0.5%brine Tr Sed. 99.5% Crude 16 493.63 44 118.58 361.25 1806.18 100.81 0.00 0.00 480.10 477.70 0.08 2.40 0.00 9.95 0.00 0.05 10.00 112 83 75 0.500 N/R 0.50 0.00 0.50 0.691 164.41 5389.55 0.44 2.14 2467.11 7857.19 120 02-Apr-15 17:00 128:14:02 BS&W = 0.5%, 0.5%brine Tr Sed. 99.5% Crude 16 496.86 43 120.01 365.86 1806.09 100.81 0.00 0.00 480.10 477.70 0.09 2.40 0.00 9.95 0.00 0.05 10.00 115 83 75 0.500 N/R 0.50 0.00 0.50 0.691 185.33 5399.50 0.44 2.14 2467.16 7867.19 120 02-Apr-15 17:30 128:44:02 BS&W = 0.5%, 0.5%brine Tr Sed. 99.5% Crude 16 496.67 43 121.15 362.08 1806.14 100.81 0.00 0.00 400.08 398.08 0.09 2.00 0.00 8.29 0.00 0.04 8.34 109 84 76 0.500 0.877 29.8 0.50 0.00 0.50 0.691 220.37 5407.79 0.44 2.15 2467.20 7875.52 120 02-Apr-15 18:00 129:14:02 BS&W = 1.2%, 1.2%brine Tr Sed. 98.8% Crude 16 490.02 43 130.18 352.86 1806.12 100.81 0.00 0.00 400.80 395.99 0.08 4.81 0.00 8.25 0.00 0.10 8.35 133 85 75 0.500 N/R 1.20 0.00 1.20 0.691 208.88 5416.04 0.44 2.15 2467.30 7883.87 120 02-Apr-15 18:30 129:44:02 BS&W = 2%, 2%brine Tr Sed. 98% Crude 16 493.06 43 115.63 368.91 1806.11 100.81 0.00 0.00 400.80 384.77 0.09 8.02 8.02 8.02 0.00 0.17 8.35 113 87 76 0.500 N/R 2.00 0.00 2.00 0.691 233.77 5424.06 0.44 2.15 2467.47 7892.22 120 02-Apr-15 19:00 130:14:02 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude. Water salinity 44000 ppm, pH=7 16 492.49 43 118.87 372.46 1806.09 100.81 0.00 0.00 480.10 472.89 0.09 7.20 0.00 9.85 0.00 0.15 10.00 111 87 76 0.500 N/R 44000 7 1.50 0.00 1.50 0.686 186.13 5433.91 0.44 2.15 2467.62 7902.23 120 02-Apr-15 19:30 130:44:02 BS&W = 0.5%, 0.5%brine Tr Sed. 99.5% Crude. Corr. API= 29.9. Gas SG .686 16 491.92 42 115.35 374.47 1806.07 100.81 0.00 0.00 440.09 437.89 0.09 2.20 0.00 9.12 0.00 0.05 9.17 111 87 76 0.500 0.877 29.9 0.50 0.00 0.50 0.686 201.62 5443.03 0.44 2.15 2467.67 7911.40 120 02-Apr-15 20:00 131:14:02 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude 16 499.71 41 118.30 371.15 1806.05 100.81 0.00 0.00 400.80 393.99 0.09 6.81 0.00 8.21 0.00 0.14 8.35 112 86 75 0.500 N/R 1.70 0.00 1.70 0.686 225.36 5451.24 0.44 2.16 2467.81 7919.75 120 02-Apr-15 20:30 131:44:02 BS&W = 2%, 2%brine Tr Sed. 98% Crude 16 490.97 42 114.30 368.17 1806.01 100.81 0.00 0.00 400.80 392.78 0.09 8.02 0.00 8.18 0.00 0.17 8.35 113 85 75 0.500 N/R 2.00 0.00 2.00 0.686 227.56 5459.42 0.44 2.16 2467.98 7928.10 120 02-Apr-15 21:00 132:14:02 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude 16 497.62 42 119.34 371.80 1806.00 100.81 0.00 0.00 400.80 391.18 0.09 9.62 0.00 8.15 0.00 0.20 8.35 111 86 75 0.500 N/R 2.40 0.00 2.40 0.686 226.66 5467.57 0.44 2.16 2468.18 7936.45 120 02-Apr-15 21:30 132:44:01 BS&W = 2%, 2%brine Tr Sed. 98% Crude 16 498.95 42 119.15 361.81 1805.97 100.81 0.00 0.00 446.40 437.47 0.09 8.93 0.00 9.11 0.00 0.19 9.30 111 87 76 0.500 N/R 2.00 0.00 2.00 0.686 202.63 5476.69 0.44 2.16 2468.36 7945.75 120 02-Apr-15 22:00 133:14:01 BS&W = 1.3%, 1.3%brine Tr Sed. 98.7% Crude. Increase choke 32/64ths 32 490.21 41 122.10 359.43 1805.90 100.81 0.00 0.00 446.40 440.60 0.09 5.80 0.00 9.18 0.00 0.12 9.30 112 86 75 0.000 N/R 42000 7 1.30 0.00 1.30 0.686 202.70 5485.87 0.44 2.16 2468.48 7955.05 120 Expro Confidential 5/5/2015 Page 5 CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives 02-Apr-15 22:30 133:44:01 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. 1.500" orifice plate in service(22:25)32 446.11 52 166.79 261.21 1785.12 101.01 0.00 0.00 1784.40 1741.57 0.27 42.83 0.00 36.28 0.01 0.89 37.18 139 83 68 1.500 0.876 30.1 2.40 0.00 2.40 0.688 152.82 5522.15 0.44 2.17 2469.38 7992.22 120 02-Apr-15 23:00 134:14:00 BS&W = 1.1%, 1.1%brine Tr Sed. 98.9% Crude. 1.000" orifice plate in service (23:12)32 512.64 59 157.76 338.28 1778.73 101.05 0.00 0.00 1934.40 1913.12 0.49 21.28 0.00 39.86 0.01 0.44 40.30 137 85 71 1.000 N/R 1.10 0.00 1.10 0.688 255.20 5562.01 0.44 2.18 2469.82 8032.52 120 02-Apr-15 23:30 134:44:00 BS&W = 1%, 1%brine Tr Sed. 99% Crude 32 512.64 60 158.90 328.66 1775.74 101.08 0.00 0.00 1860.00 1841.40 0.39 18.60 0.00 38.36 0.01 0.39 38.75 127 84 71 1.000 N/R 1.00 0.00 1.00 0.688 211.74 5600.37 0.44 2.19 2470.21 8071.27 120 03-Apr-15 00:00 135:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 512.45 60 155.67 335.47 1773.05 101.09 0.00 0.00 1934.40 1895.71 0.47 38.69 0.00 39.49 0.01 0.81 40.30 126 85 71 1.000 N/R 2.00 0.00 2.00 0.688 250.42 5639.86 0.44 2.20 2471.01 8111.57 120 03-Apr-15 00:30 135:44:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude 32 504.66 60 159.19 330.45 1771.27 101.10 0.00 0.00 1833.34 1741.67 0.47 91.67 0.00 36.28 0.01 1.91 38.19 125 86 72 1.000 N/R 5.00 0.00 5.00 0.688 270.91 5676.15 0.44 2.21 2472.92 8149.76 120 03-Apr-15 01:00 136:14:00 BS&W = 0.6%, 0.6%brine Tr Sed. 99.4% Crude. Water salinity 42000 ppm, pH=7 32 514.92 60 156.43 327.36 1769.03 101.10 0.00 0.00 1772.98 1762.34 0.47 10.64 0.00 36.72 0.01 0.22 36.94 125 86 72 1.000 N/R 42000 7 0.60 0.00 0.60 0.688 266.56 5712.86 0.44 2.22 2473.14 8186.70 120 03-Apr-15 01:30 136:44:00 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude. Corr. API= 29.3. Gas SG .692 32 508.08 61 159.47 332.80 1767.52 101.11 0.00 0.00 1822.80 1775.41 0.47 47.39 0.00 36.99 0.01 0.99 37.98 124 86 72 1.000 0.880 29.3 2.60 0.00 2.60 0.692 263.12 5749.85 0.44 2.23 2474.13 8224.68 120 03-Apr-15 02:00 137:14:00 BS&W = 1.2%, 1.2%brine Tr Sed. 98.8% Crude 32 506.94 59 157.76 330.56 1765.93 101.11 0.00 0.00 1897.20 1874.43 0.47 22.77 0.00 39.05 0.01 0.47 39.53 125 86 72 1.000 N/R 1.20 0.00 1.20 0.692 249.59 5788.90 0.44 2.24 2474.61 8264.20 120 03-Apr-15 02:30 137:44:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 32 524.62 59 155.29 323.23 1764.61 101.11 0.00 0.00 1822.80 1749.89 0.47 72.91 0.00 36.46 0.01 1.52 37.98 124 87 72 1.000 N/R 4.00 0.00 4.00 0.692 266.70 5825.36 0.44 2.25 2476.12 8302.18 120 03-Apr-15 03:00 138:14:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 32 507.32 59 153.67 328.80 1763.06 101.11 0.00 0.00 1822.80 1782.70 0.47 40.10 0.00 37.14 0.01 0.84 37.98 126 85 72 1.000 N/R 2.20 0.00 2.20 0.692 263.68 5862.50 0.44 2.26 2476.96 8340.15 120 03-Apr-15 03:30 138:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 496.86 60 158.90 326.21 1760.99 101.11 0.00 0.00 1796.83 1760.90 0.46 35.94 0.00 36.69 0.01 0.75 37.43 121 86 72 1.000 N/R 2.00 0.00 2.00 0.692 261.80 5899.18 0.44 2.26 2477.71 8377.59 120 03-Apr-15 04:00 139:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Water salinity 42000 ppm, pH=7 32 495.53 59 155.38 329.54 1759.62 101.11 0.00 0.00 1802.45 1766.40 0.46 36.05 0.00 36.80 0.01 0.75 37.55 122 86 72 1.000 N/R 42000 7 2.00 0.00 2.00 0.692 261.07 5935.98 0.44 2.27 2478.46 8415.14 120 03-Apr-15 04:30 139:44:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude. Corr. API= 29.1. Gas SG 0.714 32 493.25 60 151.77 326.75 1758.50 101.12 0.00 0.00 1760.35 1733.94 0.46 26.41 0.00 36.12 0.01 0.55 36.67 123 86 72 1.000 0.881 29.1 1.50 0.00 1.50 0.714 266.67 5972.11 0.44 2.28 2479.01 8451.81 120 03-Apr-15 05:00 140:14:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude 32 501.05 59 158.24 313.87 1757.49 101.12 0.00 0.00 1760.35 1718.10 0.45 42.25 0.00 35.79 0.01 0.88 36.67 122 86 72 1.000 N/R 2.40 0.00 2.40 0.714 264.45 6007.90 0.44 2.29 2479.89 8488.48 120 03-Apr-15 05:30 140:44:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude 32 494.01 60 149.30 317.72 1756.52 101.12 0.00 0.00 1785.60 1755.24 0.46 30.36 0.00 36.57 0.01 0.63 37.20 124 85 72 1.000 N/R 1.70 0.00 1.70 0.714 259.77 6044.47 0.44 2.30 2480.52 8525.68 120 03-Apr-15 06:00 141:14:00 BS&W = 1.2%, 1.2%brine Tr Sed. 98.8% Crude 32 492.49 61 154.05 316.17 1755.74 101.13 0.00 0.00 1934.40 1911.19 0.45 23.21 0.00 39.82 0.01 0.48 40.30 121 85 72 1.000 N/R 1.20 0.00 1.20 0.714 235.41 6084.28 0.44 2.31 2481.01 8565.98 120 03-Apr-15 06:30 141:44:00 BS&W = 1.6%, 1.6%brine Tr Sed. 98.4% Crude 32 498.19 62 155.10 322.48 1755.11 101.13 0.00 0.00 1711.20 1683.82 0.45 27.38 0.00 35.08 0.01 0.57 35.65 120 86 72 1.000 N/R 1.60 0.00 1.60 0.714 265.62 6119.36 0.44 2.32 2481.58 8601.63 120 03-Apr-15 07:00 142:14:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude. Corr. API= 29.3. Gas SG 0.682 32 500.10 59 152.72 319.01 1754.10 101.13 0.00 0.00 1711.20 1685.53 0.45 25.67 0.00 35.12 0.01 0.53 35.65 121 86 72 1.000 0.880 29.3 1.50 0.00 1.50 0.682 266.36 6154.48 0.44 2.33 2482.11 8637.28 44 03-Apr-15 07:30 142:44:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude 32 495.15 59 148.73 326.77 1753.33 101.13 90.55 0.00 1796.83 1766.28 0.45 30.55 0.00 36.80 0.01 0.64 37.43 120 87 72 1.000 N/R 1.70 0.00 1.70 0.682 253.57 6191.28 0.44 2.34 2482.75 8674.72 44 03-Apr-15 08:00 143:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 498.38 61 148.82 321.02 1752.65 101.13 0.76 0.00 1796.83 1760.89 0.45 35.94 0.00 36.69 0.01 0.75 37.43 123 86 72 1.000 N/R 2.00 0.00 2.00 0.682 257.20 6227.96 0.44 2.35 2483.50 8712.15 44 03-Apr-15 08:30 143:44:00 BS&W = 1.4%, 1.4%brine Tr Sed. 98.6% Crude 32 497.62 59 151.58 318.46 1751.77 101.13 73.58 0.00 1760.35 1735.71 0.46 24.64 0.00 36.16 0.01 0.51 36.67 122 86 72 1.000 N/R 38000 7 1.40 0.00 1.40 0.682 266.52 6264.12 0.44 2.36 2484.01 8748.83 44 03-Apr-15 09:00 144:14:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude. 32 487.74 57 150.63 317.33 1751.23 101.13 1.72 0.00 1760.35 1733.94 0.46 26.41 0.00 36.12 0.01 0.55 36.67 121 87 72 1.000 N/R 1.50 0.00 1.50 0.682 265.38 6300.25 0.44 2.37 2484.56 8785.50 44 03-Apr-15 09:30 144:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 487.36 58 154.72 319.84 1750.61 101.13 116.09 0.00 1760.35 1725.14 0.46 35.21 0.00 35.94 0.01 0.73 36.67 122 87 72 1.000 N/R 2.00 0.00 2.00 0.682 267.42 6336.19 0.44 2.38 2485.29 8822.17 44 03-Apr-15 10:00 145:14:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude. 32 491.73 59 154.34 316.64 1749.85 101.12 5.91 0.00 1785.60 1758.82 0.46 26.78 0.00 36.64 0.01 0.56 37.20 122 86 72 1.000 N/R 1.50 0.00 1.50 0.682 262.49 6372.83 0.44 2.39 2485.85 8859.37 44 03-Apr-15 10:30 145:44:00 BS&W = 1%, 1%brine Tr Sed. 99% Crude 32 495.91 59 152.05 322.69 1749.26 101.13 3.24 0.00 1636.80 1620.43 0.46 16.37 0.00 33.76 0.01 0.34 34.10 121 87 72 1.000 N/R 1.00 0.00 1.00 0.682 284.38 6406.59 0.44 2.40 2486.19 8893.47 44 03-Apr-15 11:00 146:14:00 BS&W = .7%, .7%brine Tr Sed. 99.3% Crude. Corr. API= 28.1. Gas SG 0.691 32 493.25 59 151.67 309.13 1748.71 101.13 36.60 0.00 1934.40 1920.86 0.46 13.54 0.00 40.02 0.01 0.28 40.30 124 86 73 1.000 0.887 28.1 0.70 0.00 0.70 0.691 241.66 6446.60 0.44 2.41 2486.47 8933.77 44 03-Apr-15 11:30 146:44:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5%. Water salinity 40000 ppm, pH=7 32 495.15 61 153.58 320.23 1748.02 101.12 0.00 0.00 1785.60 1758.82 0.47 26.78 0.00 36.64 0.01 0.56 37.20 124 86 72 1.000 N/R 40000 7 1.50 0.00 1.50 0.691 264.78 6483.25 0.44 2.42 2487.03 8970.97 44 03-Apr-15 12:00 147:14:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5%. 32 492.87 60 151.01 314.88 1747.11 101.12 0.00 0.00 1808.60 1781.47 0.47 27.13 0.00 37.11 0.01 0.57 37.68 125 85 73 1.000 N/R 1.50 0.00 1.50 0.691 262.28 6520.36 0.44 2.43 2487.60 9008.65 44 03-Apr-15 12:30 147:44:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5%. 32 490.02 60 145.49 330.76 1746.51 101.12 0.00 0.00 1711.20 1685.53 0.48 25.67 0.00 35.12 0.01 0.53 35.65 126 85 73 1.000 N/R 1.50 0.00 1.50 0.691 282.94 6555.48 0.44 2.44 2488.13 9044.30 44 03-Apr-15 13:00 148:14:00 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2%. 32 490.59 61 144.35 324.74 1745.13 101.12 149.64 0.00 1680.34 1650.09 0.47 30.25 0.00 34.38 0.01 0.63 35.01 108 87 73 1.000 N/R 1.80 0.00 1.80 0.691 286.34 6589.85 0.44 2.45 2488.76 9079.31 44 03-Apr-15 13:30 148:44:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5%. 32 493.25 61 141.59 332.21 1744.54 101.12 6.67 0.00 1749.12 1722.88 0.47 26.24 0.00 35.89 0.01 0.55 36.44 107 88 73 1.000 N/R 1.50 0.00 1.50 0.691 274.18 6625.75 0.44 2.46 2489.31 9115.75 44 03-Apr-15 14:00 149:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Corr. API= 29.9 32 496.29 61 143.88 326.35 1742.78 101.12 4.19 0.00 1600.32 1568.31 0.47 32.01 0.00 32.67 0.01 0.67 33.34 108 88 73 1.000 0.877 29.9 2.00 0.00 2.00 0.691 301.43 6658.42 0.44 2.47 2489.98 9149.09 44 03-Apr-15 14:30 149:44:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5%. Water salinity 39000 ppm, pH=7 32 492.68 61 146.25 331.88 1742.09 101.12 12.20 0.00 1760.35 1733.94 0.48 26.41 0.00 36.12 0.01 0.55 36.67 110 88 73 1.000 N/R 39000 7 1.50 0.00 1.50 0.697 274.91 6694.54 0.44 2.48 2490.53 9185.76 44 03-Apr-15 15:00 150:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. 32 492.11 61 143.78 337.00 1741.10 101.12 0.00 0.00 1785.60 1749.89 0.48 35.71 0.00 36.46 0.01 0.74 37.20 110 87 72 1.000 N/R 2.00 0.00 2.00 0.697 272.44 6731.00 0.44 2.49 2491.27 9222.96 44 03-Apr-15 15:30 150:44:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5%. 32 488.12 66 138.65 333.46 1740.71 101.12 0.00 0.00 1785.60 1758.82 0.48 26.78 0.00 36.64 0.01 0.56 37.20 113 84 70 1.000 N/R 1.50 0.00 1.50 0.697 273.45 6767.64 0.44 2.50 2491.83 9260.16 44 03-Apr-15 16:00 151:14:00 BS&W = 2.25%, 2.25%brine Tr Sed. 97.75% Crude. 32 494.77 64 145.49 330.01 1740.88 101.12 12.77 0.00 1711.20 1672.70 0.47 38.50 0.00 34.85 0.01 0.80 35.65 108 85 73 1.000 N/R 2.25 0.00 2.25 0.697 281.40 6802.49 0.44 2.51 2492.63 9295.81 44 03-Apr-15 16:30 151:44:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5%. 32 496.10 64 145.40 329.73 1740.63 101.12 10.67 0.00 1711.20 1685.53 0.47 25.67 0.00 35.12 0.01 0.53 35.65 109 86 73 1.000 N/R 1.50 0.00 1.50 0.697 281.33 6837.60 0.44 2.52 2493.16 9331.46 44 03-Apr-15 17:00 152:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Corr. API= 28.6 32 492.11 63 138.93 326.39 1740.22 101.12 8.58 0.00 1791.22 1755.40 0.47 35.82 0.00 36.57 0.01 0.75 37.32 109 87 73 1.000 0.884 28.6 2.00 0.00 2.00 0.697 270.49 6874.18 0.44 2.53 2493.91 9368.78 44 03-Apr-15 17:30 152:44:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5%. Water salinity 38000 ppm, pH=7 32 495.15 63 143.31 334.83 1739.74 101.11 0.00 0.00 1791.22 1764.35 0.47 26.87 0.00 36.76 0.01 0.56 37.32 109 87 73 1.000 N/R 38000 7 1.50 0.00 1.50 0.691 267.55 6910.93 0.44 2.54 2494.47 9406.10 44 03-Apr-15 18:00 153:14:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude. 32 493.82 62 142.93 338.98 1739.57 101.12 11.06 0.00 1720.34 1668.73 0.47 51.61 0.00 34.77 0.01 1.08 35.84 109 88 73 1.000 N/R 3.00 0.00 3.00 0.691 282.85 6945.70 0.44 2.55 2495.55 9441.94 44 03-Apr-15 18:30 153:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 493.44 63 143.40 330.78 1739.15 101.11 5.78 0.00 1720.34 1685.93 0.47 34.41 0.00 35.12 0.01 0.72 35.84 108 88 73 1.000 N/R 2.00 0.00 2.00 0.691 278.35 6980.82 0.44 2.56 2496.26 9477.78 44 03-Apr-15 19:00 154:14:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude 32 492.68 63 142.83 329.84 1739.03 101.11 17.92 0.00 1748.40 1718.68 0.47 29.72 0.00 35.81 0.01 0.62 36.43 109 87 73 1.000 N/R 1.70 0.00 1.70 0.691 274.02 7016.63 0.44 2.57 2496.88 9514.20 44 03-Apr-15 19:30 154:44:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude. Halliburton starts taking PVT samples (19:35)32 494.58 62 143.88 321.63 1738.72 101.11 18.49 0.00 1711.20 1685.53 0.47 25.67 0.00 35.12 0.01 0.53 35.65 109 87 73 1.000 N/R 1.50 0.00 1.50 0.691 279.06 7051.74 0.44 2.57 2497.42 9549.85 44 03-Apr-15 20:00 155:14:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude. Corr. API= 28.6. Gas SG 0.688 32 489.07 63 141.69 329.10 1738.56 101.11 8.77 0.00 1785.60 1755.24 0.47 30.36 0.00 36.57 0.01 0.63 37.20 108 88 73 1.000 0.884 28.6 1.70 0.00 1.70 0.688 267.13 7088.31 0.44 2.58 2498.05 9587.05 44 03-Apr-15 20:30 155:44:00 BS&W = 2%, 2 %brine Tr Sed. 98% Crude. Water salinity 40000 ppm, pH=7 32 485.65 63 147.97 314.34 1737.95 101.11 3.24 0.00 1785.60 1749.89 0.47 35.71 0.00 36.46 0.01 0.74 37.20 109 87 73 1.000 N/R 40000 7 2.00 0.00 2.00 0.688 269.35 7124.77 0.44 2.59 2498.79 9624.25 44 03-Apr-15 21:00 156:14:00 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude. Halliburton collect 2nd sample (21:13)32 488.50 63 140.64 324.68 1737.45 101.11 21.92 0.00 1711.20 1680.40 0.47 30.80 0.00 35.01 0.01 0.64 35.65 108 88 73 1.000 N/R 1.80 0.00 1.80 0.688 279.37 7159.77 0.44 2.60 2499.43 9659.90 44 03-Apr-15 21:30 156:44:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude 32 491.92 63 143.12 315.05 1736.78 101.10 25.54 0.00 1711.20 1685.53 0.47 25.67 0.00 35.12 0.01 0.53 35.65 108 87 73 1.000 N/R 1.50 0.00 1.50 0.688 279.02 7194.89 0.44 2.61 2499.97 9695.55 44 03-Apr-15 22:00 157:14:00 BS&W = 1.2%, 1.2%brine Tr Sed. 98.8% Crude. Halliburton collect 3rd sample (21:34)32 491.16 62 143.88 325.22 1736.68 101.10 20.97 0.00 1760.35 1739.23 0.47 21.12 0.00 36.23 0.01 0.44 36.67 108 87 72 1.000 N/R 1.20 0.00 1.20 0.688 269.53 7231.12 0.44 2.62 2500.41 9732.23 44 03-Apr-15 22:30 157:44:00 BS&W = 1%, 1%brine Tr Sed. 99% Crude. Halliburton collect 4th PVT sample (22:45)32 489.26 62 140.64 321.85 1736.49 101.10 24.40 0.00 1785.60 1767.74 0.47 17.86 0.00 36.83 0.01 0.37 37.20 107 87 72 1.000 N/R 1.00 0.00 1.00 0.688 264.79 7267.95 0.44 2.63 2500.78 9769.43 44 03-Apr-15 23:00 158:14:00 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude. Corr. API= 28.8. Gas SG 0.69 32 491.54 62 144.35 327.38 1735.95 101.10 18.30 0.00 1711.20 1678.69 0.47 32.51 0.00 34.97 0.01 0.68 35.65 109 87 72 1.000 0.883 28.8 1.90 0.00 1.90 0.690 280.15 7302.92 0.44 2.64 2501.46 9805.08 44 03-Apr-15 23:30 158:44:00 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4%. Water salinity 40000 ppm, pH=7 32 490.02 61 138.93 333.93 1735.65 101.10 10.23 0.00 1716.12 1671.50 0.47 44.62 0.00 34.82 0.01 0.93 35.75 109 87 73 1.000 N/R 40000 7 2.60 0.00 2.60 0.690 281.66 7337.75 0.44 2.65 2502.39 9840.83 44 04-Apr-15 00:00 159:14:00 BS&W = 1.2%, 1.2%brine Tr Sed. 98.8% Crude. Halliburton collect 5th PVT sample (23:38)32 489.45 62 141.69 325.71 1735.32 101.10 24.40 0.00 1704.19 1683.74 0.47 20.45 0.00 35.08 0.01 0.43 35.50 108 87 73 1.000 N/R 1.20 0.00 1.20 0.690 278.68 7372.82 0.44 2.66 2502.81 9876.33 44 04-Apr-15 00:30 159:44:00 BS&W = 1.4%, 1.4%brine Tr Sed. 98.6% Crude 32 491.35 60 142.26 325.70 1734.71 101.10 0.00 0.00 1711.20 1687.24 0.47 23.96 0.00 35.15 0.01 0.50 35.65 108 87 73 1.000 N/R 1.40 0.00 1.40 0.690 278.17 7407.98 0.44 2.67 2503.31 9911.98 44 04-Apr-15 01:00 160:14:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude. Halliburton collect 6th PVT sample (01:05)32 492.30 59 145.30 328.31 1734.86 101.10 28.40 0.00 1711.20 1682.11 0.47 29.09 0.00 35.04 0.01 0.61 35.65 108 87 73 1.000 N/R 1.70 0.00 1.70 0.690 279.07 7443.02 0.44 2.68 2503.92 9947.63 44 04-Apr-15 01:30 160:44:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude 32 486.98 59 140.93 329.11 1734.49 101.09 20.78 0.00 1711.20 1685.53 0.47 25.67 0.00 35.12 0.01 0.53 35.65 109 87 72 1.000 N/R 1.50 0.00 1.50 0.690 279.37 7478.13 0.44 2.69 2504.45 9983.28 44 04-Apr-15 02:00 161:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Corr API = 28.5 32 492.30 58 143.97 321.92 1733.80 101.09 29.36 0.00 1785.60 1749.89 0.47 35.71 0.00 36.46 0.01 0.74 37.20 109 86 72 1.000 0.884 28.5 2.00 0.00 2.00 0.690 269.65 7514.59 0.44 2.70 2505.20 10020.48 44 04-Apr-15 02:30 161:44:00 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2%. Water salinity 38000 ppm, pH=7 32 488.88 59 141.12 326.65 1733.24 101.09 30.88 0.00 1785.60 1753.46 0.48 32.14 0.00 36.53 0.01 0.67 37.20 111 85 72 1.000 N/R 38000 7 1.80 0.00 1.80 0.690 271.16 7551.12 0.44 2.71 2505.87 10057.68 44 04-Apr-15 03:00 162:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 485.84 58 141.31 321.94 1732.49 101.09 24.02 0.00 1841.76 1804.92 0.47 36.84 0.00 37.60 0.01 0.77 38.37 108 85 72 1.000 N/R 2.00 0.00 2.00 0.690 260.38 7588.72 0.44 2.72 2506.64 10096.05 44 04-Apr-15 03:00 162:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 485.84 58 141.31 321.94 1732.49 101.09 24.02 0.00 1841.76 1804.92 0.47 36.84 0.00 37.60 0.01 0.77 38.37 108 85 72 1.000 N/R 2.00 0.00 2.00 0.690 260.38 7588.72 0.44 2.72 2506.64 10096.05 44 04-Apr-15 03:30 162:44:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude 32 491.35 58 141.78 319.96 1732.56 101.09 62.91 0.00 1720.34 1679.05 0.47 41.29 0.00 34.98 0.01 0.86 35.84 109 85 72 1.000 N/R 2.40 0.00 2.40 0.690 278.93 7623.70 0.44 2.73 2507.50 10131.90 44 04-Apr-15 04:00 163:14:00 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude 32 491.54 59 138.93 324.13 1732.14 101.09 30.12 0.00 1785.60 1751.67 0.47 33.93 0.00 36.49 0.01 0.71 37.20 107 85 72 1.000 N/R 1.90 0.00 1.90 0.690 266.33 7660.20 0.44 2.74 2508.20 10169.10 44 04-Apr-15 04:30 163:44:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 32 483.56 58 141.12 323.45 1731.57 101.09 23.26 0.00 1785.60 1746.32 0.47 39.28 0.00 36.38 0.01 0.82 37.20 108 85 72 1.000 N/R 2.20 0.00 2.20 0.690 268.17 7696.58 0.44 2.75 2509.02 10206.30 44 04-Apr-15 05:00 164:14:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude. Corr API = 28.7 32 487.74 58 143.21 320.23 1731.58 101.09 15.82 0.00 1785.60 1758.82 0.47 26.78 0.00 36.64 0.01 0.56 37.20 109 84 72 1.000 0.883 28.7 1.50 0.00 1.50 0.690 267.55 7733.22 0.44 2.76 2509.58 10243.50 44 04-Apr-15 05:30 164:44:00 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude. Water salinity 40000 ppm, pH=7. Gas SG .686 32 488.88 60 141.12 323.64 1731.22 101.09 5.53 0.00 1711.20 1678.69 0.47 32.51 0.00 34.97 0.01 0.68 35.65 110 84 72 1.000 N/R 40000 7 1.90 0.00 1.90 0.686 281.69 7768.19 0.44 2.77 2510.26 10279.15 44 04-Apr-15 06:00 165:14:00 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude 32 490.02 60 140.55 317.42 1730.92 101.09 52.23 0.00 1716.82 1684.20 0.47 32.62 0.00 35.09 0.01 0.68 35.77 109 84 72 1.000 N/R 1.90 0.00 1.90 0.686 280.74 7803.28 0.44 2.78 2510.94 10314.91 44 04-Apr-15 06:30 165:44:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude 32 490.78 58 141.97 332.21 1730.80 101.09 28.78 0.00 1636.80 1597.52 0.47 39.28 0.00 33.28 0.01 0.82 34.10 102 85 72 1.000 N/R 2.40 0.00 2.40 0.686 294.21 7836.56 0.44 2.79 2511.75 10349.01 44 04-Apr-15 07:00 166:14:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 32 487.93 59 142.16 329.00 1730.38 101.09 27.45 0.00 1680.34 1629.93 0.47 50.41 0.00 33.96 0.01 1.05 35.01 106 86 72 1.000 N/R 3.00 0.00 3.00 0.686 286.48 7870.52 0.44 2.80 2512.80 10384.02 44 Expro Confidential 5/5/2015 Page 6 CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives 04-Apr-15 07:30 166:44:00 BS&W = 3.5%, 3.5%brine Tr Sed. 96.5% Crude 32 487.74 60 137.41 327.16 1729.82 101.09 0.00 0.00 1914.77 1847.75 0.47 67.02 0.00 38.49 0.01 1.40 39.89 109 86 72 1.000 N/R 3.50 0.00 3.50 0.686 256.10 7909.01 0.44 2.81 2514.20 10423.91 44 04-Apr-15 08:00 167:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Corr API = 28.7. Gas SG .689 32 487.74 58 145.02 329.35 1729.44 101.09 33.74 0.00 1600.32 1568.31 0.47 32.01 0.00 32.67 0.01 0.67 33.34 108 86 72 1.000 0.883 28.7 2.00 0.00 2.00 0.689 300.03 7941.69 0.44 2.82 2514.87 10457.25 44 04-Apr-15 08:30 167:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 32 484.89 58 139.12 323.94 1729.26 101.09 55.85 0.00 1840.37 1785.16 0.47 55.21 0.00 37.19 0.01 1.15 38.34 109 86 72 1.000 N/R 40000 7 3.00 0.00 3.00 0.689 264.58 7978.88 0.44 2.83 2516.02 10495.59 44 04-Apr-15 09:00 168:14:00 BS&W = 3.5%, 3.5%brine Tr Sed. 96.5% Crude 32 485.46 57 141.02 329.76 1729.07 101.09 26.88 0.00 1680.34 1621.53 0.47 58.81 0.00 33.78 0.01 1.23 35.01 108 85 72 1.000 N/R 3.50 0.00 3.50 0.689 290.11 8012.66 0.44 2.84 2517.24 10530.60 44 04-Apr-15 09:30 168:44:00 BS&W = 3.5%, 3.5%brine Tr Sed. 96.5% Crude 32 491.16 58 145.11 314.74 1728.91 101.09 0.00 0.00 1760.35 1698.74 0.47 61.61 0.00 35.39 0.01 1.28 36.67 106 85 72 1.000 N/R 3.50 0.00 3.50 0.689 277.25 8048.05 0.44 2.85 2518.53 10567.27 44 04-Apr-15 10:00 169:14:00 BS&W = 2.5%, 2.5%brine Tr Sed. 97.5% Crude 32 493.44 59 141.59 324.86 1728.41 101.09 37.17 0.00 1562.40 1523.34 0.47 39.06 0.00 31.74 0.01 0.81 32.55 109 85 72 1.000 N/R 2.50 0.00 2.50 0.689 309.13 8079.79 0.44 2.86 2519.34 10599.82 44 04-Apr-15 10:30 169:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 492.87 60 143.21 329.65 1727.92 101.09 8.39 0.00 1785.60 1749.89 0.47 35.71 0.00 36.46 0.01 0.74 37.20 109 86 72 1.000 N/R 2.00 0.00 2.00 0.689 269.07 8116.24 0.44 2.87 2520.08 10637.02 44 04-Apr-15 11:00 170:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Corr API = 28.9. Gas SG .686 32 487.74 62 139.50 329.02 1727.91 101.09 175.94 0.00 1711.20 1676.98 0.47 34.22 0.00 34.94 0.01 0.71 35.65 109 85 72 1.000 0.882 28.9 2.00 0.00 2.00 0.689 280.73 8151.18 0.44 2.88 2520.80 10672.67 44 04-Apr-15 11:30 170:44:00 BS&W = 2.5%, 2.5%brine Tr Sed. 97.5% Crude 32 491.73 60 139.79 321.77 1727.76 101.09 26.12 0.00 1860.00 1813.50 0.47 46.50 0.00 37.78 0.01 0.97 38.75 108 86 72 1.000 N/R 48000 7 2.50 0.00 2.50 0.686 259.57 8188.96 0.44 2.89 2521.77 10711.42 44 04-Apr-15 12:00 171:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 484.13 61 139.79 320.82 1727.08 101.09 27.83 0.00 1562.40 1531.15 0.47 31.25 0.00 31.90 0.01 0.65 32.55 108 86 72 1.000 N/R 2.00 0.00 2.00 0.686 307.39 8220.86 0.44 2.90 2522.42 10743.97 44 04-Apr-15 12:30 171:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 489.07 60 142.93 325.04 1726.83 101.08 39.46 0.00 1743.50 1708.63 0.47 34.87 0.00 35.60 0.01 0.73 36.32 108 86 73 1.000 N/R 2.00 0.00 2.00 0.686 275.43 8256.46 0.44 2.91 2523.14 10780.30 44 04-Apr-15 13:00 172:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 486.79 61 142.45 327.96 1726.61 101.08 1.72 0.00 1652.26 1619.21 0.47 33.05 0.00 33.73 0.01 0.69 34.42 110 86 73 1.000 N/R 2.00 0.00 2.00 0.686 290.60 8290.19 0.44 2.92 2523.83 10814.72 44 04-Apr-15 13:30 172:44:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude 32 492.68 62 146.73 318.78 1726.37 101.08 29.93 0.00 1785.60 1758.82 0.47 26.78 0.00 36.64 0.01 0.56 37.20 111 86 72 1.000 N/R 1.50 0.00 1.50 0.686 267.50 8326.83 0.44 2.93 2524.39 10851.92 44 04-Apr-15 14:00 173:14:00 BS&W = 2.5%, 2.5%brine Tr Sed. 97.5% Crude. Corr API = 28.7. Gas SG .694 32 490.21 63 145.40 317.66 1726.06 101.08 73.20 0.00 1860.00 1813.50 0.47 46.50 0.00 37.78 0.01 0.97 38.75 109 86 72 1.000 0.883 28.7 2.50 0.00 2.50 0.694 259.40 8364.61 0.44 2.94 2525.36 10890.67 44 04-Apr-15 14:30 173:44:00 BS&W = 2.8%, 2.8%brine Tr Sed. 97.2% Crude 32 482.80 63 147.30 313.88 1725.45 101.08 29.36 0.00 1711.20 1663.29 0.47 47.91 0.00 34.65 0.01 1.00 35.65 109 86 72 1.000 N/R 39000 7 2.80 0.00 2.80 0.694 282.79 8399.27 0.44 2.95 2526.36 10926.32 44 04-Apr-15 15:00 174:14:00 BS&W = 2.5%, 2.5%brine Tr Sed. 97.5% Crude 32 488.31 62 140.55 321.01 1725.73 101.08 68.05 0.00 1674.00 1632.15 0.47 41.85 0.00 34.00 0.01 0.87 34.88 108 84 71 1.000 N/R 2.50 0.00 2.50 0.694 288.14 8433.27 0.44 2.96 2527.23 10961.19 44 04-Apr-15 15:30 174:44:00 BS&W = 2.5%, 2.5%brine Tr Sed. 97.5% Crude 32 493.63 70 143.69 319.75 1725.68 101.06 32.98 0.00 1636.80 1595.88 0.47 40.92 0.00 33.25 0.01 0.85 34.10 109 85 72 1.000 N/R 2.50 0.00 2.50 0.694 293.70 8466.52 0.44 2.97 2528.08 10995.29 44 04-Apr-15 16:00 175:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 490.21 65 139.60 326.29 1725.32 101.06 51.28 0.00 1674.00 1640.52 0.47 33.48 0.00 34.18 0.01 0.70 34.88 109 85 72 1.000 N/R 2.00 0.00 2.00 0.694 286.38 8500.69 0.44 2.98 2528.78 11030.17 44 04-Apr-15 16:30 175:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 484.89 66 145.68 318.32 1725.02 101.06 33.74 0.00 1754.74 1719.65 0.47 35.09 0.00 35.83 0.01 0.73 36.56 110 86 72 1.000 N/R 2.00 0.00 2.00 0.694 274.23 8536.52 0.44 2.99 2529.51 11066.72 44 04-Apr-15 17:00 176:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Corr API = 28.9. Gas SG .689 32 497.24 61 144.16 327.19 1724.99 101.06 36.41 0.00 1754.74 1719.65 0.47 35.09 0.00 35.83 0.01 0.73 36.56 108 86 73 1.000 0.882 28.9 2.00 0.00 2.00 0.689 272.80 8572.35 0.44 3.00 2530.24 11103.28 44 04-Apr-15 17:30 176:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 32 490.78 64 140.83 319.40 1724.57 101.06 34.88 0.00 1711.20 1676.98 0.47 34.22 0.00 34.94 0.01 0.71 35.65 110 86 73 1.000 N/R 40000 7 2.00 0.00 2.00 0.689 281.47 8607.28 0.44 3.01 2530.95 11138.93 44 04-Apr-15 18:00 177:14:00 BS&W = 1%, 1%brine Tr Sed. 99% Crude 32 484.32 64 144.16 323.61 1724.23 101.06 31.83 0.00 1711.20 1694.09 0.47 17.11 0.00 35.29 0.01 0.36 35.65 109 86 72 1.000 N/R 1.00 0.00 1.00 0.689 278.42 8642.58 0.44 3.02 2531.31 11174.58 44 04-Apr-15 18:30 177:44:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude 32 479.95 63 140.74 329.11 1723.86 101.06 18.90 0.00 1711.20 1670.13 0.47 41.07 0.00 34.79 0.01 0.86 35.65 109 86 72 1.000 N/R 2.40 0.00 2.40 0.689 282.90 8677.37 0.44 3.03 2532.17 11210.23 44 04-Apr-15 19:00 178:14:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 32 499.14 63 145.30 318.70 1723.77 101.05 41.94 0.00 1711.20 1673.55 0.47 37.65 0.00 34.87 0.01 0.78 35.65 110 86 72 1.000 N/R 2.20 0.00 2.20 0.689 283.18 8712.24 0.44 3.04 2532.95 11245.88 44 04-Apr-15 19:30 178:44:00 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude 32 488.12 65 146.25 313.79 1723.50 101.05 36.60 0.00 1785.60 1751.67 0.47 33.93 0.00 36.49 0.01 0.71 37.20 110 86 72 1.000 N/R 1.90 0.00 1.90 0.689 270.25 8748.73 0.44 3.05 2533.66 11283.08 44 04-Apr-15 20:00 179:14:00 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude. Corr API = 29.3 32 492.49 64 143.40 327.01 1722.76 101.05 43.27 0.00 1711.20 1680.40 0.48 30.80 0.00 35.01 0.01 0.64 35.65 111 86 72 1.000 0.880 29.3 1.80 0.00 1.80 0.689 282.80 8783.74 0.44 3.06 2534.30 11318.73 44 04-Apr-15 20:30 179:44:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude. Water salinity 40000 ppm, pH=7. Gas SG .694 32 483.56 64 144.92 318.33 1722.67 101.05 37.36 0.00 1760.35 1721.62 0.47 38.73 0.00 35.87 0.01 0.81 36.67 109 86 72 1.000 N/R 40000 7 2.20 0.00 2.20 0.694 274.32 8819.60 0.44 3.07 2535.11 11355.41 44 04-Apr-15 21:00 180:14:00 BS&W = 1.6%, 1.6%brine Tr Sed. 98.4% Crude 32 485.08 62 142.07 332.11 1722.74 101.05 42.89 0.00 1711.20 1683.82 0.47 27.38 0.00 35.08 0.01 0.57 35.65 110 87 73 1.000 N/R 1.60 0.00 1.60 0.694 280.34 8854.68 0.44 3.08 2535.68 11391.06 44 04-Apr-15 21:30 180:44:00 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude 32 486.03 62 145.11 323.41 1722.57 101.05 28.59 0.00 1711.20 1678.69 0.47 32.51 0.00 34.97 0.01 0.68 35.65 110 86 72 1.000 N/R 1.90 0.00 1.90 0.694 281.28 8889.92 0.44 3.08 2536.35 11426.71 44 04-Apr-15 22:00 181:14:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. Inc. choke 38/64ths adj. 1.000" orifice plate out of service 38 483.56 61 141.69 323.82 1722.00 101.05 42.51 0.00 1785.60 1742.75 0.00 42.85 0.00 36.31 0.00 0.89 37.20 109 86 72 0.000 N/R 2.40 0.00 2.40 0.694 N/R 8926.22 0.44 3.08 2537.25 11463.91 44 04-Apr-15 22:30 181:44:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude. Inc. choke 50/64ths adj (22:28). Incr. 52/64ths adj.52 372.36 65 229.36 101.77 1668.10 101.16 51.09 0.00 3050.40 2983.29 0.00 67.11 0.00 62.15 0.00 1.40 63.55 131 85 71 1.500 N/R 2.20 0.00 2.20 0.694 N/R 8988.38 0.44 3.08 2538.64 11527.46 44 04-Apr-15 23:00 182:14:00 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude. Inc. choke 56/64ths fixed (22:40). 1.250" orifice plate 56 392.70 66 214.53 104.17 1668.86 101.20 138.20 0.00 3317.14 3230.89 0.57 86.25 0.00 67.31 0.01 1.80 69.11 135 86 72 1.250 0.888 27.8 2.60 0.00 2.60 0.694 177.24 9055.69 0.51 3.10 2540.44 11596.56 44 04-Apr-15 23:30 182:44:00 BS&W = 2.8%, 2.7%brine & 0.1% sed. 97.2% Crude. Water salinity 38000 ppm, pH=7. Gas SG .688 56 410.19 67 223.47 97.11 1665.27 101.21 42.70 0.00 3422.40 3326.57 0.90 92.40 3.42 69.30 0.02 1.93 71.30 138 86 72 1.250 N/R 38000 7 2.80 0.10 2.70 0.688 269.93 9124.99 0.51 3.12 2542.37 11667.86 44 05-Apr-15 00:00 183:14:00 BS&W = 3.5%, 3.5%brine Tr Sed. 95.5% Crude 56 414.18 68 217.19 103.95 1663.36 101.20 67.50 0.00 3496.80 3374.41 0.91 122.39 0.00 70.30 0.02 2.55 72.85 139 86 72 1.250 N/R 3.50 0.00 3.50 0.688 270.51 9195.29 0.51 3.13 2544.92 11740.71 44 05-Apr-15 00:30 183:44:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude. Sparge separator 3 gal. Frac sand 56 405.25 69 216.91 114.42 1661.19 101.20 41.56 0.00 2939.52 2821.94 0.91 117.58 0.00 58.79 0.02 2.45 61.24 138 87 72 1.250 N/R 4.00 0.00 4.00 0.688 322.61 9254.08 0.51 3.15 2547.37 11801.95 44 05-Apr-15 01:00 184:14:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude. Sparge sandtrap 1 gal Frac sand 56 409.81 67 221.00 112.02 1659.45 101.20 45.56 0.00 3199.20 3039.24 0.91 159.96 0.00 63.32 0.02 3.33 66.65 139 87 72 1.250 N/R 5.00 0.00 5.00 0.688 300.13 9317.40 0.51 3.17 2550.70 11868.60 44 05-Apr-15 01:30 184:44:00 BS&W = 7%, 7%brine Tr Sed. 93% Crude 56 410.38 68 221.19 109.38 1658.47 101.20 102.55 0.00 3422.40 3182.83 0.92 239.57 0.00 66.31 0.02 4.99 71.30 140 87 72 1.250 N/R 7.00 0.00 7.00 0.688 288.19 9383.71 0.51 3.19 2555.69 11939.90 44 05-Apr-15 02:00 185:14:00 BS&W = 7%, 7%brine Tr Sed. 93% Crude. Corr API = 28.5 56 407.91 67 220.24 110.52 1656.28 101.19 30.12 0.00 3459.60 3217.43 0.91 242.17 0.00 67.03 0.02 5.05 72.08 139 87 72 1.250 0.884 28.5 7.00 0.00 7.00 0.688 283.82 9450.74 0.51 3.21 2560.73 12011.98 44 05-Apr-15 02:30 185:44:00 BS&W = 6%, 6%brine Tr Sed. 94% Crude. Water salinity 38000 ppm, pH=7. Gas SG .692 56 405.44 66 222.71 104.28 1655.06 101.19 43.65 0.00 3496.80 3286.99 0.92 209.81 0.00 68.48 0.02 4.37 72.85 141 87 72 1.250 N/R 38000 7 6.00 0.00 6.00 0.692 280.22 9519.22 0.51 3.23 2565.11 12084.83 44 05-Apr-15 03:00 186:14:00 BS&W = 7%, 7%brine Tr Sed. 93% Crude. Stop injecting DH methanol 56 413.42 66 218.24 99.33 1653.59 101.18 50.32 0.00 3422.40 3182.83 0.92 239.57 0.00 66.31 0.02 4.99 71.30 140 86 72 1.250 N/R 7.00 0.00 7.00 0.692 288.12 9585.52 0.51 3.25 2570.10 12156.13 0 05-Apr-15 03:30 186:44:00 BS&W = 7%, 7%brine Tr Sed. 93% Crude. Sparge sandtrap 1 gal Frac sand 56 413.42 66 220.24 110.14 1652.16 101.18 76.80 0.00 3348.00 3113.64 0.92 234.36 0.00 64.87 0.02 4.88 69.75 140 87 72 1.250 N/R 7.00 0.00 7.00 0.692 294.37 9650.39 0.51 3.27 2574.98 12225.88 0 05-Apr-15 04:00 187:14:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude 56 406.58 67 224.80 107.65 1651.06 101.17 178.23 0.00 3351.53 3183.95 0.92 167.58 0.00 66.33 0.02 3.49 69.82 140 87 72 1.250 N/R 5.00 0.00 5.00 0.692 287.71 9716.72 0.51 3.29 2578.47 12295.70 0 05-Apr-15 04:30 187:44:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude 56 410.95 67 223.75 105.50 1649.64 101.17 29.36 0.00 3500.33 3325.31 0.91 175.02 0.00 69.28 0.02 3.65 72.92 140 87 72 1.250 N/R 5.00 0.00 5.00 0.692 275.05 9786.00 0.51 3.31 2582.12 12368.62 0 05-Apr-15 05:00 188:14:00 BS&W = 7%, 6.95%brine Tr % sed. 93% Crude. Corr API = 28.3. Resume DH methanol injection 56 406.01 66 220.24 132.95 1648.93 101.16 208.54 0.00 3422.40 3182.83 0.92 239.57 0.00 66.31 0.02 4.99 71.30 140 86 72 1.250 0.885 28.3 7.00 0.00 7.00 0.692 287.93 9852.31 0.51 3.33 2587.11 12439.92 0 05-Apr-15 05:30 188:44:00 BS&W = 6%, 6%brine Tr Sed. 94% Crude. **05:18hrs Sparge sand trap. Recovered 36 gallons of frac sand.56 400.87 67 225.56 98.03 1647.32 101.14 141.06 0.00 3310.80 3112.15 0.92 198.65 0.00 64.84 0.02 4.14 68.98 141 87 72 1.250 N/R 38000 7 6.00 0.00 6.00 0.688 295.62 9917.15 0.51 3.34 2591.25 12508.90 44 05-Apr-15 06:00 189:14:00 BS&W = 6%, 6%brine Tr Sed. 94% Crude. Water salinity 38000 ppm, pH=7. Gas SG .688 56 409.62 66 219.76 97.43 1646.88 101.13 117.42 0.00 3145.87 2957.12 0.92 188.75 0.00 61.61 0.02 3.93 65.54 142 87 72 1.250 N/R 6.00 0.00 6.00 0.688 311.11 9978.75 0.51 3.36 2595.18 12574.44 44 05-Apr-15 06:30 189:44:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude.56 380.73 67 227.75 80.58 1640.04 101.11 0.00 0.00 3430.85 3259.31 0.99 171.54 0.00 67.90 0.02 3.57 71.48 129 86 72 1.250 N/R 5.00 0.00 5.00 0.688 304.00 10046.66 0.51 3.38 2598.75 12645.91 44 05-Apr-15 07:00 190:14:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude. ** 06:37hrs Divert Flow through 48/64ths fixed choke 48 417.03 66 186.10 176.51 1656.03 101.13 151.35 0.00 3200.64 3072.61 0.92 128.03 0.00 64.01 0.02 2.67 66.68 109 87 72 1.250 N/R 4.00 0.00 4.00 0.688 300.12 10110.67 0.51 3.40 2601.42 12712.59 44 05-Apr-15 07:30 190:44:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 422.54 65 186.38 164.92 1655.92 101.12 102.17 0.00 3120.62 2964.59 0.90 156.03 0.00 61.76 0.02 3.25 65.01 106 86 72 1.250 N/R 5.00 0.00 5.00 0.688 302.37 10172.43 0.51 3.42 2604.67 12777.61 44 05-Apr-15 08:00 191:14:01 BS&W = 6%, 6%brine Tr Sed. 94% Crude. Corr API = 28.5. 48 429.96 65 185.43 179.25 1655.21 101.12 123.52 0.00 3050.40 2867.38 0.89 183.02 0.00 59.74 0.02 3.81 63.55 103 86 72 1.250 0.884 28.5 6.00 0.00 6.00 0.688 309.88 10232.17 0.51 3.44 2608.48 12841.16 44 05-Apr-15 08:30 191:44:01 BS&W = 6%, 6%brine Tr Sed. 94% Crude. ** 08:29 Sparged sand trap. Recovered 10 gals of frac sand 48 429.96 65 193.70 173.99 1653.56 101.11 133.82 0.00 3056.02 2872.66 0.89 183.36 0.00 59.85 0.02 3.82 63.67 104 86 72 1.250 N/R 39000 7 6.00 0.00 6.00 0.690 310.12 10292.02 0.51 3.46 2612.30 12904.82 44 05-Apr-15 09:00 192:14:02 BS&W = 6%, 6%brine Tr Sed. 94% Crude. Water salinity 38000 ppm, pH=7. Gas SG .691 48 432.05 66 183.53 165.70 1654.61 101.11 140.30 0.00 3003.38 2823.18 0.90 180.20 0.00 58.82 0.02 3.75 62.57 105 86 72 1.250 N/R 6.00 0.00 6.00 0.690 317.65 10350.83 0.51 3.48 2616.06 12967.40 44 05-Apr-15 09:30 192:44:02 BS&W = 7%, 7%brine Tr Sed. 93% Crude 48 413.42 66 195.23 159.47 1654.26 101.10 112.66 0.00 3200.64 2976.60 0.89 224.04 0.00 62.01 0.02 4.67 66.68 103 86 72 1.250 N/R 7.00 0.00 7.00 0.690 298.59 10412.84 0.51 3.50 2620.72 13034.08 44 05-Apr-15 10:00 193:14:03 BS&W = 6%, 6%brine Tr Sed. 94% Crude. ** 09:41hrs Sparged sand trap. Recovered a trace of frac sand 48 417.60 66 188.76 167.63 1653.32 101.10 119.14 0.00 3124.80 2937.31 0.89 187.49 0.00 61.19 0.02 3.91 65.10 104 86 72 1.250 N/R 6.00 0.00 6.00 0.690 303.77 10474.04 0.51 3.51 2624.63 13099.18 44 05-Apr-15 10:30 193:44:03 BS&W = 7%, 7%brine Tr Sed. 93% Crude 48 419.12 65 189.33 175.16 1652.69 101.10 66.91 0.00 3087.60 2871.47 0.89 216.13 0.00 59.82 0.02 4.50 64.33 105 86 72 1.250 N/R 7.00 0.00 7.00 0.690 310.40 10533.86 0.51 3.53 2629.13 13163.50 44 05-Apr-15 11:00 194:14:04 BS&W = 6%, 6%brine Tr Sed. 94% Crude. Corr API = 29.1 48 421.02 65 184.96 176.14 1651.90 101.09 121.43 0.00 3037.78 2855.51 0.89 182.27 0.00 59.49 0.02 3.80 63.29 104 86 72 1.250 0.881 29.1 6.00 0.00 6.00 0.690 312.24 10593.35 0.51 3.55 2632.93 13226.79 44 05-Apr-15 11:30 194:44:05 BS&W = 7%, 7%brine Tr Sed. 93% Crude 48 427.49 65 186.67 152.38 1651.31 101.09 139.15 0.00 3114.29 2896.29 0.90 218.00 0.00 60.34 0.02 4.54 64.88 105 86 72 1.250 N/R 38000 7 7.00 0.00 7.00 0.690 309.07 10653.69 0.51 3.57 2637.47 13291.67 44 05-Apr-15 12:00 195:14:05 BS&W = 6%, 6%brine Tr Sed. 94% Crude. 48 415.51 67 186.95 174.15 1650.78 101.09 120.09 0.00 3050.40 2867.38 0.90 183.02 0.00 59.74 0.02 3.81 63.55 106 85 72 1.250 N/R 6.00 0.00 6.00 0.690 313.84 10713.43 0.51 3.59 2641.29 13355.22 44 05-Apr-15 12:30 195:44:06 BS&W = 6%, 6%brine Tr Sed. 94% Crude. 48 422.16 66 181.34 182.77 1650.10 101.08 231.99 0.00 3124.80 2937.31 0.89 187.49 0.00 61.19 0.02 3.91 65.10 105 86 72 1.250 N/R 6.00 0.00 6.00 0.690 304.24 10774.62 0.51 3.61 2645.19 13420.32 44 05-Apr-15 13:00 196:14:06 BS&W = 6%, 6%brine Tr Sed. 94% Crude. 48 426.72 66 188.76 166.12 1649.21 101.08 12.39 0.00 3043.39 2860.79 0.89 182.60 0.00 59.60 0.02 3.80 63.40 103 85 72 1.250 N/R 6.00 0.00 6.00 0.690 310.57 10834.22 0.51 3.63 2649.00 13483.72 44 05-Apr-15 13:30 196:44:07 BS&W = 5%, 5%brine Tr Sed. 95% Crude. 48 416.27 67 188.09 173.01 1648.88 101.08 162.03 0.00 3209.00 3048.55 0.89 160.45 0.00 63.51 0.02 3.34 66.85 104 86 72 1.250 N/R 5.00 0.00 5.00 0.690 290.93 10897.73 0.51 3.65 2652.34 13550.58 44 05-Apr-15 14:00 197:14:07 BS&W = 6%, 6%brine Tr Sed. 94% Crude. Corr API = 29.2. Water salinity 38000 ppm, pH=7 48 422.92 67 183.62 174.27 1648.15 101.06 124.48 0.00 3200.64 3008.60 0.89 192.04 0.00 62.68 0.02 4.00 66.68 104 86 72 1.250 0.881 29.2 40000 7 6.00 0.00 6.00 0.690 295.77 10960.41 0.51 3.66 2656.34 13617.26 44 05-Apr-15 14:30 197:44:07 BS&W = 6%, 6%brine Tr Sed. 94% Crude. Gas SG .692 48 422.54 68 185.72 168.79 1647.59 101.06 213.69 0.00 3050.40 2867.38 0.89 183.02 0.00 59.74 0.02 3.81 63.55 103 86 72 1.250 N/R 6.00 0.00 6.00 0.692 308.80 11020.15 0.51 3.68 2660.15 13680.81 44 05-Apr-15 15:00 198:14:08 BS&W = 5%, 5%brine Tr Sed. 95% Crude. **14:52hrs Sparged sand trap. Recovered 15 gallons of frac sand 48 394.98 68 174.50 161.54 1634.69 101.05 119.52 0.00 3050.40 2897.88 0.89 152.52 0.00 60.37 0.02 3.18 63.55 104 88 72 1.250 N/R 5.00 0.00 5.00 0.692 306.96 11080.52 0.51 3.70 2663.33 13744.36 44 05-Apr-15 15:30 198:44:08 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 422.16 75 185.72 162.38 1646.43 101.05 111.32 0.00 3117.79 2961.90 0.89 155.89 0.00 61.71 0.02 3.25 64.95 104 86 72 1.250 N/R 5.00 0.00 5.00 0.692 300.59 11142.23 0.51 3.72 2666.58 13809.31 44 05-Apr-15 16:00 199:14:09 BS&W = 6%, 6%brine Tr Sed. 94% Crude 48 416.27 71 188.00 167.82 1645.87 101.04 97.22 0.00 3037.80 2855.53 0.89 182.27 0.00 59.49 0.02 3.80 63.29 104 86 72 1.250 N/R 6.00 0.00 6.00 0.692 311.98 11201.72 0.51 3.74 2670.37 13872.60 44 05-Apr-15 16:30 199:44:09 BS&W = 6%, 6%brine Tr Sed. 94% Crude 48 422.16 68 186.57 174.90 1645.36 101.04 184.71 0.00 3040.61 2858.17 0.89 182.44 0.00 59.55 0.02 3.80 63.35 104 87 72 1.250 N/R 6.00 0.00 6.00 0.692 311.42 11261.26 0.51 3.76 2674.18 13935.94 44 Expro Confidential 5/5/2015 Page 7 CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives 05-Apr-15 17:00 200:14:09 BS&W = 5%, 5%brine Tr Sed. 95% Crude. 48 418.93 67 185.72 170.67 1645.12 101.04 131.34 0.00 3050.40 2897.88 0.89 152.52 0.00 60.37 0.02 3.18 63.55 104 87 72 1.250 N/R 5.00 0.00 5.00 0.692 307.41 11321.63 0.51 3.77 2677.35 13999.49 44 05-Apr-15 17:30 200:44:10 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 416.46 69 185.72 176.33 1645.08 101.03 195.58 0.00 2455.20 2332.44 0.90 122.76 0.00 48.59 0.02 2.56 51.15 106 86 72 1.250 N/R 5.00 0.00 5.00 0.692 384.16 11370.23 0.51 3.79 2679.91 14050.64 44 05-Apr-15 18:00 201:14:10 BS&W = 4.5%, 4.5%brine Tr Sed. 95.5% Crude. Corr API = 30.0. Gas SG .692 48 424.82 71 185.15 179.54 1644.77 101.03 28.97 0.00 3155.71 3013.70 0.90 142.01 0.00 62.79 0.02 2.96 65.74 106 86 72 1.250 0.876 30.0 4.50 0.00 4.50 0.692 297.10 11433.01 0.51 3.81 2682.87 14116.39 44 05-Apr-15 18:30 201:44:11 BS&W = 5%, 5%brine Tr Sed. 95% Crude. Water salinity 36000 ppm, pH=7 48 415.89 69 188.76 174.04 1643.76 101.02 279.83 0.00 3042.00 2889.90 0.89 152.10 0.00 60.21 0.02 3.17 63.38 104 87 72 1.250 N/R 36000 7 5.00 0.00 5.00 0.692 307.86 11493.22 0.51 3.83 2686.04 14179.76 44 05-Apr-15 19:00 202:14:11 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 420.64 68 189.43 160.74 1643.53 101.02 121.43 0.00 3120.62 2964.59 0.89 156.03 0.00 61.76 0.02 3.25 65.01 104 87 72 1.250 N/R 5.00 0.00 5.00 0.692 301.01 11554.98 0.51 3.85 2689.29 14244.78 44 05-Apr-15 19:30 202:44:12 BS&W = 6%, 6%brine Tr Sed. 94% Crude 48 427.68 66 185.62 175.86 1642.85 101.02 278.12 0.00 3023.04 2841.66 0.89 181.38 0.00 59.20 0.02 3.78 62.98 105 87 72 1.250 N/R 6.00 0.00 6.00 0.692 314.81 11614.18 0.51 3.87 2693.07 14307.76 44 05-Apr-15 20:00 203:14:12 BS&W = 4%, 4%brine Tr Sed. 96% Crude. Sparged separator. Recovered 10 gallons of Frac sand 48 420.26 66 187.81 177.25 1642.53 101.01 140.87 0.00 2976.00 2856.96 0.90 119.04 0.00 59.52 0.02 2.48 62.00 105 87 72 1.250 N/R 4.00 0.00 4.00 0.692 313.65 11673.70 0.51 3.89 2695.55 14369.76 44 05-Apr-15 20:30 203:44:12 BS&W = 6%, 6%brine Tr Sed. 94% Crude 48 417.03 65 192.75 155.91 1642.00 101.01 129.24 0.00 3120.62 2933.39 0.90 187.24 0.00 61.11 0.02 3.90 65.01 106 87 72 1.250 N/R 6.00 0.00 6.00 0.692 306.97 11734.81 0.51 3.91 2699.45 14434.77 44 05-Apr-15 21:00 204:14:13 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 415.51 65 187.52 167.92 1641.84 101.01 166.03 0.00 3124.80 2968.56 0.90 156.24 0.00 61.85 0.02 3.26 65.10 106 87 72 1.250 N/R 5.00 0.00 5.00 0.692 302.55 11796.66 0.51 3.92 2702.70 14499.87 44 05-Apr-15 21:30 204:44:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 418.55 67 188.19 164.81 1641.36 101.00 127.34 0.00 3071.47 2917.90 0.90 153.57 0.00 60.79 0.02 3.20 63.99 106 87 72 1.250 N/R 5.00 0.00 5.00 0.692 308.05 11855.98 0.51 3.94 2705.82 14562.31 44 05-Apr-15 22:00 205:14:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude. Corr API = 29.4. Water salinity 36000 ppm, pH=7. Gas SG 0.690 48 422.16 66 185.53 162.19 1641.21 101.00 190.43 0.00 3178.18 3019.27 0.90 158.91 0.00 62.90 0.02 3.31 66.21 106 86 72 1.250 0.879 29.4 36000 7 5.00 0.00 5.00 0.690 298.10 11918.88 0.51 3.96 2709.14 14628.52 44 05-Apr-15 22:30 205:44:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 48 424.44 66 189.14 165.36 1640.80 100.98 50.71 0.00 3050.40 2928.38 0.90 122.02 0.00 61.01 0.02 2.54 63.55 106 86 71 1.250 N/R 4.00 0.00 4.00 0.690 308.39 11979.89 0.51 3.98 2711.68 14692.07 44 05-Apr-15 23:00 206:14:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 48 418.93 66 186.57 174.53 1640.39 100.98 120.09 0.00 3050.40 2928.38 0.90 122.02 0.00 61.01 0.02 2.54 63.55 106 86 71 1.250 N/R 4.00 0.00 4.00 0.690 308.22 12040.89 0.51 4.00 2714.22 14755.62 44 05-Apr-15 23:30 206:44:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 424.25 66 189.52 174.22 1640.07 100.98 92.64 0.00 3032.16 2880.55 0.90 151.61 0.00 60.01 0.02 3.16 63.17 106 86 71 1.250 N/R 5.00 0.00 5.00 0.690 313.80 12100.91 0.51 4.02 2717.38 14818.79 44 06-Apr-15 00:00 207:14:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 416.65 66 198.65 155.29 1639.53 100.97 120.09 0.00 3064.46 2911.24 0.89 153.22 0.00 60.65 0.02 3.19 63.84 104 86 71 1.250 N/R 5.00 0.00 5.00 0.690 307.35 12161.56 0.51 4.04 2720.57 14882.63 44 06-Apr-15 00:30 207:44:00 BS&W = 4.5%, 4.5%brine Tr Sed. 95.5% Crude 48 425.96 66 190.38 164.50 1638.91 100.97 130.58 0.00 3050.40 2913.13 0.90 137.27 0.00 60.69 0.02 2.86 63.55 105 86 71 1.250 N/R 4.50 0.00 4.50 0.690 309.21 12222.25 0.51 4.06 2723.43 14946.18 44 06-Apr-15 01:00 208:14:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 426.92 66 184.10 172.85 1638.54 100.97 67.45 0.00 3050.40 2897.88 0.90 152.52 0.00 60.37 0.02 3.18 63.55 106 86 71 1.250 N/R 5.00 0.00 5.00 0.690 311.31 12282.62 0.51 4.07 2726.61 15009.73 44 06-Apr-15 01:30 208:44:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 426.92 66 191.71 164.12 1638.20 100.96 122.95 0.00 3037.78 2885.89 0.91 151.89 0.00 60.12 0.02 3.16 63.29 108 86 72 1.250 N/R 5.00 0.00 5.00 0.690 315.37 12342.74 0.51 4.09 2729.77 15073.02 44 06-Apr-15 02:00 209:14:00 BS&W = 4.5%, 4.5%brine Tr Sed. 95.5% Crude. Corr API = 29.3. Water salinity 36000 ppm, pH=7. Gas SG 0.692 48 421.21 66 188.00 169.71 1637.70 100.96 166.79 0.00 3050.40 2913.13 0.91 137.27 0.00 60.69 0.02 2.86 63.55 108 86 72 1.250 0.880 29.3 36000 7 4.50 0.00 4.50 0.692 312.48 12403.43 0.51 4.11 2732.63 15136.57 44 06-Apr-15 02:30 209:44:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 48 423.68 65 189.90 177.42 1637.31 100.96 124.48 0.00 3050.40 2928.38 0.90 122.02 0.00 61.01 0.02 2.54 63.55 106 86 71 1.250 N/R 4.00 0.00 4.00 0.692 307.70 12464.44 0.51 4.13 2735.17 15200.12 44 06-Apr-15 03:00 210:14:00 BS&W = 4.5%, 4.5%brine Tr Sed. 95.5% Crude. Sparged sandtrap. Recovered 10 gallons of sand 48 426.72 65 185.81 179.43 1636.49 100.95 246.28 0.00 3032.16 2895.71 0.91 136.45 0.00 60.33 0.02 2.84 63.17 108 86 71 1.250 N/R 4.50 0.00 4.50 0.692 313.83 12524.77 0.51 4.15 2738.02 15263.29 44 06-Apr-15 03:30 210:44:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 426.92 65 190.19 162.81 1636.51 100.95 258.10 0.00 2957.76 2809.87 0.89 147.89 0.00 58.54 0.02 3.08 61.62 103 86 71 1.250 N/R 5.00 0.00 5.00 0.692 315.98 12583.31 0.51 4.17 2741.10 15324.91 44 06-Apr-15 04:00 211:14:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 48 426.53 65 187.81 169.15 1636.16 100.95 120.28 0.00 2901.60 2785.54 0.90 116.06 0.00 58.03 0.02 2.42 60.45 105 86 71 1.250 N/R 4.00 0.00 4.00 0.692 322.71 12641.34 0.51 4.19 2743.51 15385.36 44 06-Apr-15 04:30 211:44:00 BS&W = 4.5%, 4.5%brine Tr Sed. 95.5% Crude 48 422.35 66 190.85 171.00 1635.72 100.94 139.15 0.00 3095.33 2956.04 0.90 139.29 0.00 61.58 0.02 2.90 64.49 106 86 72 1.250 N/R 4.50 0.00 4.50 0.692 304.94 12702.92 0.51 4.21 2746.42 15449.85 44 06-Apr-15 05:00 212:14:00 BS&W = 3.5%, 3.5%brine Tr Sed. 96.5% Crude. Sparged sandtrap. Recovered 5 gallons of sand (5:15) 48 417.22 65 187.90 169.80 1635.47 100.94 120.28 0.00 3032.16 2926.03 0.90 106.13 0.00 60.96 0.02 2.21 63.17 106 86 72 1.250 N/R 3.50 0.00 3.50 0.692 308.86 12763.88 0.51 4.22 2748.63 15513.02 44 06-Apr-15 05:30 212:44:00 BS&W = 4.5%, 4.5%brine Tr Sed. 95.5% Crude 48 426.15 64 185.72 179.53 1634.62 100.94 281.55 0.00 3050.40 2913.13 0.91 137.27 0.00 60.69 0.02 2.86 63.55 108 87 71 1.250 N/R 4.50 0.00 4.50 0.692 312.34 12824.57 0.51 4.24 2751.49 15576.57 44 06-Apr-15 06:00 213:14:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude. Corr API = 29.3. Water salinity 38000 ppm, pH=7. Gas SG 0.690 48 420.45 65 187.43 171.41 1634.49 100.94 153.26 0.00 3050.40 2897.88 0.91 152.52 0.00 60.37 0.02 3.18 63.55 108 86 71 1.250 0.880 29.3 37000 7 5.00 0.00 5.00 0.690 314.47 12884.94 0.51 4.26 2754.66 15640.12 44 06-Apr-15 06:30 213:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 48 421.02 66 185.62 179.25 1633.97 100.93 121.62 0.00 2952.41 2863.84 0.92 88.57 0.00 59.66 0.02 1.85 61.51 111 86 71 1.250 N/R 3.00 0.00 3.00 0.690 322.32 12944.61 0.51 4.28 2756.51 15701.62 44 06-Apr-15 07:00 214:14:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 48 426.92 65 191.99 166.47 1633.49 100.93 207.01 0.00 3129.02 3003.86 0.92 125.16 0.00 62.58 0.02 2.61 65.19 110 85 71 1.250 N/R 4.00 0.00 4.00 0.690 306.03 13007.19 0.51 4.30 2759.12 15766.81 44 06-Apr-15 07:30 214:44:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 423.49 66 188.28 175.64 1632.97 100.93 122.00 0.00 3124.80 2968.56 0.91 156.24 0.00 61.85 0.02 3.26 65.10 107 85 71 1.250 N/R 5.00 0.00 5.00 0.690 305.24 13069.03 0.51 4.32 2762.37 15831.91 44 06-Apr-15 08:00 215:14:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude. Sparged sandtrap. Recovered 2 gallons of frac sand (8:06) 48 418.17 67 191.42 171.00 1632.50 100.93 0.00 0.00 3087.60 2964.10 0.90 123.50 0.00 61.75 0.02 2.57 64.33 106 85 71 1.250 N/R 4.00 0.00 4.00 0.690 305.29 13130.78 0.51 4.34 2764.95 15896.24 44 06-Apr-15 08:30 215:44:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 48 421.59 65 190.95 177.88 1631.80 100.93 123.14 0.00 3002.69 2882.58 0.91 120.11 0.00 60.05 0.02 2.50 62.56 107 85 71 1.250 N/R 4.00 0.00 4.00 0.690 316.08 13190.84 0.51 4.36 2767.45 15958.79 44 06-Apr-15 09:00 216:14:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 48 425.77 66 191.33 168.64 1631.44 100.92 129.24 0.00 3117.79 2993.08 0.91 124.71 0.00 62.36 0.02 2.60 64.95 106 86 71 1.250 N/R 4.00 0.00 4.00 0.690 302.92 13253.19 0.51 4.38 2770.05 16023.75 44 06-Apr-15 09:30 216:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 48 421.97 66 188.00 164.24 1631.06 100.92 122.95 0.00 2976.00 2886.72 0.92 89.28 0.00 60.14 0.02 1.86 62.00 110 86 71 1.250 N/R 3.00 0.00 3.00 0.690 318.61 13313.33 0.51 4.40 2771.91 16085.75 44 06-Apr-15 10:00 217:14:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude. Corr API = 29.4. Water salinity 40000 ppm, pH=7. Gas SG 0.698 48 417.60 66 189.62 167.53 1630.67 100.92 129.24 0.00 3124.80 3031.06 0.91 93.74 0.00 63.15 0.02 1.95 65.10 108 85 71 1.250 0.879 29.4 40000 7 3.00 0.00 3.00 0.698 300.90 13376.48 0.51 4.41 2773.86 16150.85 44 06-Apr-15 10:30 217:44:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 48 419.69 67 189.52 162.35 1630.45 100.92 125.80 0.00 3117.79 2993.08 0.91 124.71 0.00 62.36 0.02 2.60 64.95 109 85 71 1.250 N/R 4.00 0.00 4.00 0.698 305.59 13438.84 0.51 4.43 2776.46 16215.80 44 06-Apr-15 11:00 218:14:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 48 415.51 68 189.81 165.83 1629.87 100.91 108.65 0.00 2968.99 2850.23 0.91 118.76 0.00 59.38 0.02 2.47 61.85 108 85 71 1.250 N/R 4.00 0.00 4.00 0.698 318.51 13498.22 0.51 4.45 2778.93 16277.66 44 06-Apr-15 11:30 218:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 48 424.25 68 186.76 167.74 1629.28 100.91 112.00 0.00 3050.40 2958.89 0.90 91.51 0.00 61.64 0.02 1.91 63.55 107 85 71 1.250 N/R 3.00 0.00 3.00 0.698 305.59 13559.86 0.51 4.47 2780.84 16341.21 44 06-Apr-15 12:00 219:14:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 48 418.36 67 190.38 183.16 1629.10 100.91 100.08 0.00 2901.60 2814.55 0.90 87.05 0.00 58.64 0.02 1.81 60.45 107 85 71 1.250 N/R 3.00 0.00 3.00 0.698 320.74 13618.50 0.51 4.49 2782.65 16401.66 44 06-Apr-15 12:30 219:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 48 425.58 70 190.76 167.89 1628.79 100.91 121.23 0.00 2963.38 2874.48 0.90 88.90 0.00 59.88 0.02 1.85 61.74 106 86 71 1.250 N/R 3.00 0.00 3.00 0.698 313.57 13678.38 0.51 4.51 2784.50 16463.39 44 06-Apr-15 13:00 220:14:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 48 422.54 68 189.33 174.79 1628.53 100.89 119.33 0.00 3140.26 3014.65 0.91 125.61 0.00 62.81 0.02 2.62 65.42 109 85 71 1.250 N/R 4.00 0.00 4.00 0.698 302.57 13741.19 0.51 4.53 2787.12 16528.81 44 06-Apr-15 13:30 220:44:00 BS&W = 2.5%, 2.5%brine Tr Sed. 97.5% Crude. Sparged sandtrap. Recovered 10 gallons of frac sand (13:50) 48 417.98 66 191.99 171.93 1628.14 100.89 91.03 0.00 3050.40 2974.14 0.91 76.26 0.00 61.96 0.02 1.59 63.55 109 85 71 1.250 N/R 2.50 0.00 2.50 0.698 307.53 13803.15 0.51 4.55 2788.71 16592.36 44 06-Apr-15 14:00 221:14:00 BS&W = 3.5%, 3.5%brine Tr Sed. 96.5% Crude. Corr API = 30.3. Water salinity 40000 ppm, pH=7. Gas SG 0.691 48 416.08 67 189.14 169.70 1627.50 100.89 128.89 0.00 2827.20 2728.25 0.91 98.95 0.00 56.84 0.02 2.06 58.90 110 85 71 1.250 0.875 30.3 40000 7 3.50 0.00 3.50 0.691 335.20 13859.99 0.51 4.57 2790.77 16651.26 44 06-Apr-15 14:30 221:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 48 422.73 65 180.49 176.47 1627.28 100.89 117.66 0.00 3037.78 2946.65 0.91 91.13 0.00 61.39 0.02 1.90 63.29 117 85 71 1.250 N/R 3.00 0.00 3.00 0.691 310.12 13921.38 0.51 4.59 2792.67 16714.55 44 06-Apr-15 15:00 222:14:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 48 417.03 66 190.66 167.05 1626.94 100.88 115.84 0.00 3088.32 2995.67 0.91 92.65 0.00 62.41 0.02 1.93 64.34 106 85 71 1.250 N/R 3.00 0.00 3.00 0.691 305.02 13983.79 0.51 4.60 2794.60 16778.89 44 06-Apr-15 15:30 222:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 48 420.83 65 190.57 171.10 1626.61 100.88 133.71 0.00 3050.40 2958.89 0.91 91.51 0.00 61.64 0.02 1.91 63.55 105 84 71 1.250 N/R 3.00 0.00 3.00 0.691 306.59 14045.43 0.51 4.62 2796.51 16842.44 44 06-Apr-15 16:00 223:14:00 BS&W = 2.5%, 2.5%brine Tr Sed. 97.5% Crude 48 427.68 65 189.14 175.92 1626.14 100.88 117.17 0.00 3050.40 2974.14 0.91 76.26 0.00 61.96 0.02 1.59 63.55 109 84 71 1.250 N/R 2.50 0.00 2.50 0.691 305.34 14107.39 0.51 4.64 2798.09 16905.99 44 06-Apr-15 16:30 223:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 48 413.80 67 187.90 169.80 1625.68 100.88 116.26 0.00 2961.98 2873.12 0.90 88.86 0.00 59.86 0.02 1.85 61.71 109 85 71 1.250 N/R 3.00 0.00 3.00 0.691 313.80 14167.25 0.51 4.66 2799.95 16967.70 44 06-Apr-15 17:00 224:14:00 BS&W = 4.5%, 4.5%brine Tr Sed. 95.5% Crude 48 424.63 65 195.42 170.96 1624.91 100.87 116.45 0.00 2957.67 2824.57 0.91 133.10 0.00 58.85 0.02 2.77 61.62 111 84 71 1.250 N/R 4.50 0.00 4.50 0.691 323.46 14226.09 0.51 4.68 2802.72 17029.32 44 06-Apr-15 17:30 224:44:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 48 438.89 65 188.28 174.89 1624.80 100.87 108.97 0.00 2976.00 2856.96 0.92 119.04 0.00 59.52 0.02 2.48 62.00 112 84 71 1.250 N/R 4.00 0.00 4.00 0.691 320.48 14285.61 0.51 4.70 2805.20 17091.32 44 06-Apr-15 18:00 225:14:00 BS&W = 1.5%, 1.5%brine Tr Sed. 95.5% Crude. Corr API = 30.3. Water salinity 40000 ppm, pH=7. Gas SG 0.692 48 417.03 70 187.71 167.36 1624.45 100.87 116.68 0.00 2861.54 2818.62 0.90 42.92 0.00 58.72 0.02 0.89 59.62 109 84 71 1.250 0.875 30.3 40000 7 1.50 0.00 1.50 0.692 321.07 14344.33 0.51 4.72 2806.09 17150.93 44 06-Apr-15 18:30 225:44:00 BS&W = 5%, 5%brine Tr Sed. 95% Crude 48 420.64 70 192.18 171.18 1624.13 100.87 117.06 0.00 2973.22 2824.56 0.89 148.66 0.00 58.84 0.02 3.10 61.94 106 84 71 1.250 N/R 5.00 0.00 5.00 0.692 315.08 14404.00 0.51 4.74 2809.20 17213.71 44 06-Apr-15 19:00 226:14:00 BS&W = 4%, 4%brine Tr Sed. 96% Crude 48 418.74 69 188.19 168.01 1623.81 100.86 114.63 0.00 2894.59 2778.81 0.91 115.78 0.00 57.89 0.02 2.41 60.30 110 84 71 1.250 N/R 4.00 0.00 4.00 0.692 326.14 14461.89 0.51 4.76 2811.61 17274.01 44 06-Apr-15 19:30 226:44:00 BS&W = 3.5%, 3.5%brine Tr Sed. 96.5% Crude. *Ice plug at flare line (19:45). Pump methanol on scrubber outlet 48 416.27 67 189.14 166.12 1623.45 100.86 116.83 0.00 2976.00 2871.84 0.92 104.16 0.00 59.83 0.02 2.17 62.00 112 84 71 1.250 N/R 3.50 0.00 3.50 0.692 318.87 14521.72 0.51 4.77 2813.78 17336.01 44 06-Apr-15 20:00 227:14:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude. Clear ice plug at the flare (20:13). 1.250" plate out of service (19:45)48 428.06 66 311.81 76.81 1631.36 100.86 112.54 0.00 2976.00 2886.72 0.00 89.28 0.00 60.14 0.00 1.86 62.00 153 88 72 0.000 N/R 3.00 0.00 3.00 0.692 N/R 14581.86 0.51 4.77 2815.64 17398.01 44 06-Apr-15 20:30 227:44:00 BS&W = 3.5%, 3.5%brine Tr Sed. 96.5% Crude. 1.250" plate back in service (20:15)48 417.03 64 193.70 165.13 1623.66 100.85 108.90 0.00 3032.16 2926.03 0.77 106.13 0.00 60.96 0.02 2.21 63.17 183 83 70 1.250 N/R 3.50 0.00 3.50 0.692 263.91 14642.82 0.51 4.79 2817.86 17461.18 44 06-Apr-15 21:00 228:14:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 48 395.36 65 188.57 172.53 1622.95 100.85 120.51 0.00 2939.52 2851.33 0.90 88.19 0.00 59.40 0.02 1.84 61.24 112 84 71 1.250 N/R 3.00 0.00 3.00 0.692 317.26 14702.22 0.51 4.81 2819.69 17522.42 44 06-Apr-15 21:30 228:44:00 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude. 48 418.17 65 188.95 168.76 1622.51 100.85 122.79 0.00 2976.00 2898.62 0.89 77.38 0.00 60.39 0.02 1.61 62.00 107 84 71 1.250 N/R 2.60 0.00 2.60 0.692 306.01 14762.61 0.51 4.83 2821.30 17584.42 44 06-Apr-15 22:00 229:14:00 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude. Corr API = 29.5. Water salinity 40000 ppm, pH=7. Gas SG 0.692 48 416.08 64 188.28 169.42 1622.07 100.85 142.48 0.00 3050.40 2971.09 0.90 79.31 0.00 61.90 0.02 1.65 63.55 110 84 71 1.250 0.879 29.5 40000 7 2.60 0.00 2.60 0.692 302.38 14824.51 0.51 4.85 2822.96 17647.97 44 06-Apr-15 22:30 229:44:00 BS&W = 2.8%, 2.8%brine Tr Sed. 97.2% Crude. 48 422.54 65 190.66 171.38 1621.72 100.85 103.47 0.00 3032.16 2947.26 0.90 84.90 0.00 61.40 0.02 1.77 63.17 112 85 71 1.250 N/R 2.80 0.00 2.80 0.692 306.72 14885.91 0.51 4.87 2824.73 17711.14 44 06-Apr-15 23:00 230:14:00 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude. 48 417.60 65 190.57 168.65 1621.36 100.85 124.15 0.00 3058.85 2979.32 0.90 79.53 0.00 62.07 0.02 1.66 63.73 112 85 71 1.250 N/R 2.60 0.00 2.60 0.692 303.27 14947.98 0.51 4.88 2826.38 17774.87 44 06-Apr-15 23:30 230:44:00 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude. 48 423.49 64 191.71 161.85 1621.00 100.85 116.11 0.00 2976.00 2898.62 0.90 77.38 0.00 60.39 0.02 1.61 62.00 111 85 71 1.250 N/R 2.60 0.00 2.60 0.692 311.38 15008.37 0.51 4.90 2827.99 17836.87 44 07-Apr-15 00:00 231:14:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude. 48 423.68 65 187.43 168.96 1620.67 100.84 108.29 0.00 2976.00 2910.53 0.90 65.47 0.00 60.64 0.02 1.36 62.00 112 85 71 1.250 N/R 2.20 0.00 2.20 0.692 310.40 15069.00 0.51 4.92 2829.36 17898.87 44 07-Apr-15 00:30 231:44:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. 48 406.58 65 194.94 155.23 1620.28 100.84 115.20 0.00 3032.16 2959.39 0.93 72.77 0.00 61.65 0.02 1.52 63.17 117 84 71 1.250 N/R 2.40 0.00 2.40 0.692 312.63 15130.66 0.51 4.94 2830.87 17962.04 44 07-Apr-15 01:00 232:14:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude. Sparged sandtrap & separator. Recovered 10 gal. of frac sand 48 415.89 65 187.43 159.54 1616.67 100.84 138.68 0.00 2921.98 2857.69 0.92 64.28 0.00 59.54 0.02 1.34 60.87 115 84 70 1.250 N/R 2.20 0.00 2.20 0.692 320.38 15190.19 0.51 4.96 2832.21 18022.91 44 07-Apr-15 01:30 232:44:00 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude. 48 418.36 65 193.42 162.78 1619.44 100.84 114.78 0.00 2976.00 2898.62 0.91 77.38 0.00 60.39 0.02 1.61 62.00 114 84 70 1.250 N/R 2.60 0.00 2.60 0.692 314.66 15250.58 0.51 4.98 2833.83 18084.91 44 07-Apr-15 02:00 233:14:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. Corr API = 29.7. Water salinity 40000 ppm, pH=7. Gas SG 0.688 48 418.55 65 189.43 165.83 1619.04 100.84 112.92 0.00 2901.60 2831.96 0.91 69.64 0.00 59.00 0.02 1.45 60.45 113 84 71 1.250 0.878 29.7 40000 7 2.40 0.00 2.40 0.688 320.18 15309.58 0.51 5.00 2835.28 18145.36 44 Expro Confidential 5/5/2015 Page 8 CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives 07-Apr-15 02:30 233:44:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. 48 419.12 64 192.47 170.52 1618.66 100.84 117.21 0.00 2928.29 2858.01 0.90 70.28 0.00 59.54 0.02 1.46 61.01 110 84 70 1.250 N/R 2.40 0.00 2.40 0.688 314.21 15369.12 0.51 5.02 2836.74 18206.37 44 07-Apr-15 03:00 234:14:00 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude 48 425.01 63 188.86 178.65 1618.25 100.84 117.25 0.00 3093.94 3013.49 0.90 80.44 0.00 62.78 0.02 1.68 64.46 110 85 71 1.250 N/R 2.60 0.00 2.60 0.688 298.57 15431.90 0.51 5.04 2838.42 18270.83 44 07-Apr-15 03:30 234:44:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude 48 424.25 65 191.71 167.89 1617.88 100.83 115.84 0.00 3040.61 2967.63 0.90 72.97 0.00 61.83 0.02 1.52 63.35 111 84 70 1.250 N/R 2.40 0.00 2.40 0.688 304.24 15493.73 0.51 5.05 2839.94 18334.17 44 07-Apr-15 04:00 235:14:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 48 417.60 65 188.57 173.10 1617.50 100.83 117.70 0.00 2960.59 2895.46 0.91 65.13 0.00 60.32 0.02 1.36 61.68 112 84 71 1.250 N/R 2.20 0.00 2.20 0.688 313.45 15554.05 0.51 5.07 2841.29 18395.85 44 07-Apr-15 04:30 235:44:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 48 429.01 64 193.42 153.17 1617.15 100.83 107.34 0.00 3050.40 2983.29 0.90 67.11 0.00 62.15 0.02 1.40 63.55 111 84 71 1.250 N/R 2.20 0.00 2.20 0.688 302.76 15616.20 0.51 5.09 2842.69 18459.40 44 07-Apr-15 05:00 236:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 420.83 65 187.05 171.79 1616.78 100.83 116.98 0.00 2827.20 2765.00 0.91 62.20 0.00 57.60 0.02 1.30 58.90 112 84 71 1.250 N/R 2.20 0.00 2.20 0.688 327.82 15673.81 0.51 5.11 2843.99 18518.30 44 07-Apr-15 05:30 236:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 415.89 64 192.75 161.00 1616.25 100.83 138.15 0.00 2945.14 2880.35 0.91 64.79 0.00 60.01 0.02 1.35 61.36 113 85 71 1.250 N/R 2.20 0.00 2.20 0.688 315.93 15733.81 0.51 5.13 2845.34 18579.66 44 07-Apr-15 06:00 237:14:00 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude. Corr API = 29.2. Water salinity 38000 ppm, pH=7. Gas SG 0.690 48 428.06 64 192.28 169.95 1615.84 100.83 111.17 0.00 2724.94 2654.09 0.91 70.85 0.00 55.29 0.02 1.48 56.77 112 85 71 1.250 0.881 29.2 38000 7 2.60 0.00 2.60 0.690 342.87 15789.11 0.51 5.15 2846.81 18636.43 44 07-Apr-15 06:30 237:44:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. Sparged sand trap. Recovered 5 gal. of frac sand (6:54)48 418.93 67 192.94 155.34 1615.51 100.83 117.47 0.00 2976.00 2904.58 0.90 71.42 0.00 60.51 0.02 1.49 62.00 113 85 71 1.250 N/R 2.40 0.00 2.40 0.690 311.56 15849.62 0.51 5.17 2848.30 18698.43 44 07-Apr-15 07:00 238:14:00 BS&W = 2.5%, 2.5%brine Tr Sed. 97.5% Crude 48 419.50 66 192.85 158.83 1614.36 100.83 97.44 0.00 3050.40 2974.14 0.91 76.26 0.00 61.96 0.02 1.59 63.55 112 84 71 1.250 N/R 2.50 0.00 2.50 0.690 304.67 15911.58 0.51 5.19 2849.89 18761.98 44 07-Apr-15 07:30 238:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 415.89 66 191.52 168.26 1614.72 100.81 111.86 0.00 3112.18 3049.94 0.91 62.24 0.00 63.54 0.02 1.30 64.84 114 85 71 1.250 N/R 2.00 0.00 2.00 0.690 298.49 15975.12 0.51 5.21 2851.19 18826.82 44 07-Apr-15 08:00 239:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 420.26 65 192.75 157.42 1614.39 100.81 133.30 0.00 3192.19 3128.35 0.90 63.84 0.00 65.17 0.02 1.33 66.50 110 83 70 1.250 N/R 2.00 0.00 2.00 0.690 286.66 16040.30 0.51 5.22 2852.52 18893.32 44 07-Apr-15 08:30 239:44:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 48 422.54 65 188.00 174.42 1613.83 100.81 185.05 0.00 2938.80 2850.64 0.90 88.16 0.00 59.39 0.02 1.84 61.23 111 80 68 1.250 N/R 3.00 0.00 3.00 0.690 315.41 16099.68 0.51 5.24 2854.35 18954.54 44 07-Apr-15 09:00 240:14:00 BS&W = 3%, 3%brine Tr Sed. 97% Crude 48 420.07 66 189.90 162.72 1613.41 100.81 143.81 0.00 3199.20 3103.22 0.91 95.98 0.00 64.65 0.02 2.00 66.65 113 78 67 1.250 N/R 3.00 0.00 3.00 0.690 291.70 16164.33 0.51 5.26 2856.35 19021.19 44 07-Apr-15 09:30 240:44:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude 48 422.54 66 188.95 163.48 1613.04 100.81 139.67 0.00 2945.14 2874.46 0.89 70.68 0.00 59.88 0.02 1.47 61.36 110 79 69 1.250 N/R 2.40 0.00 2.40 0.690 310.22 16224.22 0.51 5.28 2857.83 19082.55 0 07-Apr-15 10:00 241:14:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. Corr API = 29.9. Water salinity 38000 ppm, pH=7. Gas SG 0.687 48 422.92 65 186.38 177.17 1612.72 100.81 125.25 0.00 2807.57 2740.19 0.89 67.38 0.00 57.09 0.02 1.40 58.49 110 83 70 1.250 0.877 29.9 40000 7 2.40 0.00 2.40 0.687 326.17 16281.31 0.51 5.30 2859.23 19141.04 0 07-Apr-15 10:30 241:44:00 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude.48 421.40 65 191.52 161.86 1612.33 100.81 143.20 0.00 3050.40 2971.09 0.90 79.31 0.00 61.90 0.02 1.65 63.55 110 83 70 1.250 N/R 2.60 0.00 2.60 0.687 301.66 16343.20 0.51 5.32 2860.88 19204.59 0 07-Apr-15 11:00 242:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Sparged sand trap. Recovered 1 gal. of frac sand (11:07)48 441.55 63 188.76 166.12 1611.99 100.81 113.15 0.00 2976.00 2916.48 0.90 59.52 0.00 60.76 0.02 1.24 62.00 112 83 70 1.250 N/R 2.00 0.00 2.00 0.687 308.98 16403.96 0.51 5.34 2862.12 19266.59 0 07-Apr-15 11:30 242:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 422.54 64 192.66 159.96 1611.53 100.81 108.40 0.00 3032.16 2971.52 0.91 60.64 0.00 61.91 0.02 1.26 63.17 113 84 70 1.250 N/R 2.00 0.00 2.00 0.687 304.67 16465.87 0.51 5.36 2863.39 19329.76 0 07-Apr-15 12:00 243:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 417.98 64 190.66 165.54 1611.25 100.80 117.70 0.00 2976.00 2916.48 0.90 59.52 0.00 60.76 0.02 1.24 62.00 112 84 70 1.250 N/R 2.00 0.00 2.00 0.687 309.64 16526.63 0.51 5.37 2864.63 19391.76 0 07-Apr-15 12:30 243:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 424.82 64 193.42 165.98 1610.79 100.80 115.16 0.00 2976.00 2916.48 0.90 59.52 0.00 60.76 0.02 1.24 62.00 110 84 70 1.250 N/R 2.00 0.00 2.00 0.687 306.94 16587.39 0.51 5.39 2865.87 19453.76 0 07-Apr-15 13:00 244:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 436.80 65 189.81 163.57 1610.15 100.80 113.15 0.00 2957.76 2898.60 0.91 59.16 0.00 60.39 0.02 1.23 61.62 113 84 70 1.250 N/R 2.00 0.00 2.00 0.687 313.21 16647.78 0.51 5.41 2867.10 19515.38 0 07-Apr-15 13:30 244:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 415.89 64 192.18 163.64 1609.53 100.80 140.09 0.00 3140.26 3077.45 0.91 62.81 0.00 64.11 0.02 1.31 65.42 113 83 70 1.250 N/R 2.00 0.00 2.00 0.687 294.50 16711.89 0.51 5.43 2868.41 19580.81 0 07-Apr-15 14:00 245:14:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. Corr API = 30.1. Water salinity 38000 ppm, pH=7. Gas SG 0.697 48 418.17 64 194.56 160.13 1609.05 100.80 85.41 0.00 3050.40 2977.19 0.90 73.21 0.00 62.02 0.02 1.53 63.55 112 83 70 1.250 N/R 30.1 38000 7 2.40 0.00 2.40 0.697 300.71 16773.92 0.51 5.45 2869.93 19644.36 0 07-Apr-15 14:30 245:44:00 BS&W = 2.8%, 2.8%brine Tr Sed. 97.2% Crude 48 419.12 66 187.62 165.75 1608.66 100.80 133.37 0.00 2827.20 2748.04 0.89 79.16 0.00 57.25 0.02 1.65 58.90 110 84 70 1.250 N/R 2.80 0.00 2.80 0.697 323.36 16831.17 0.51 5.47 2871.58 19703.26 0 07-Apr-15 15:00 246:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 409.43 66 192.09 158.65 1608.95 100.80 111.93 0.00 2808.96 2730.31 0.80 78.65 0.00 56.88 0.02 1.64 58.52 119 81 70 1.250 N/R 2.80 0.00 2.80 0.697 291.85 16888.05 0.51 5.48 2873.22 19761.78 0 07-Apr-15 15:30 246:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Sparged sand trap. Recovered 2 gal. of frac sand (15:29)48 421.40 66 188.76 159.34 1607.82 100.80 113.41 0.00 3050.40 2989.39 0.90 61.01 0.00 62.28 0.02 1.27 63.55 107 85 71 1.250 N/R 2.00 0.00 2.00 0.697 0.00 16950.80 0.51 5.50 2874.02 19825.33 0 07-Apr-15 16:00 247:14:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude 48 414.56 66 187.33 164.72 1607.40 100.80 96.11 0.00 2901.60 2858.08 0.90 43.52 0.00 59.54 0.02 0.91 60.45 106 85 71 1.250 N/R 1.50 0.00 1.50 0.697 0.00 17010.34 0.51 5.52 2874.93 19885.78 0 07-Apr-15 16:30 247:44:00 BS&W = 2.8%, 2.8%brine Tr Sed. 97.2% Crude 48 409.43 66 184.39 179.73 1607.13 100.80 110.91 0.00 3273.60 3181.94 0.91 91.66 0.00 66.29 0.02 1.91 68.20 108 83 71 1.250 N/R 2.80 0.00 2.80 0.697 0.00 17076.63 0.51 5.54 2876.84 19953.98 0 07-Apr-15 17:00 248:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 424.06 66 186.76 158.88 1606.81 100.79 116.33 0.00 2786.50 2730.77 0.91 55.73 0.00 56.89 0.02 1.16 58.05 108 84 71 1.250 N/R 2.00 0.00 2.00 0.697 0.00 17133.52 0.51 5.56 2878.00 20012.03 0 07-Apr-15 17:30 248:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 425.20 65 189.90 151.03 1606.47 100.79 111.82 0.00 3088.32 3026.55 0.90 61.77 0.00 63.05 0.02 1.29 64.34 106 84 71 1.250 N/R 2.00 0.00 2.00 0.697 0.00 17196.57 0.51 5.58 2879.29 20076.37 0 07-Apr-15 18:00 249:14:00 BS&W = 1.8%, 1.8%brine Tr Sed. 97.4% Crude. Corr API = 29.3. Water salinity 40000 ppm, pH=7. Gas SG 0.692 48 416.46 65 189.52 166.11 1606.00 100.79 122.18 0.00 2976.00 2922.43 0.90 53.57 0.00 60.88 0.02 1.12 62.00 107 85 71 1.250 N/R 29.3 40000 7 1.80 0.00 1.80 0.692 0.00 17257.46 0.51 5.60 2880.40 20138.37 0 07-Apr-15 18:30 249:44:00 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude 48 407.72 65 185.72 171.80 1605.58 100.79 127.26 0.00 2827.20 2776.31 0.90 50.89 0.00 57.84 0.02 1.06 58.90 105 84 71 1.250 N/R 1.80 0.00 1.80 0.697 0.00 17315.30 0.51 5.62 2881.46 20197.27 0 07-Apr-15 19:00 250:14:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude 48 411.14 65 186.48 160.49 1605.22 100.79 128.32 0.00 3106.56 3053.75 0.90 52.81 0.00 63.62 0.02 1.10 64.72 106 84 71 1.250 N/R 1.70 0.00 1.70 0.697 0.00 17378.92 0.51 5.63 2882.56 20261.99 0 07-Apr-15 19:30 250:44:00 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude 48 417.22 65 188.76 156.89 1604.79 100.79 137.96 0.00 2894.59 2839.59 0.90 55.00 0.00 59.16 0.02 1.15 60.30 106 85 71 1.250 N/R 1.90 0.00 1.90 0.697 0.00 17438.08 0.51 5.65 2883.71 20322.29 0 07-Apr-15 20:00 251:14:00 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude 48 417.79 65 184.77 171.43 1604.44 100.79 122.10 0.00 3040.61 2982.84 0.90 57.77 0.00 62.14 0.02 1.20 63.35 107 85 71 1.250 N/R 1.90 0.00 1.90 0.697 0.00 17500.22 0.51 5.67 2884.91 20385.64 0 07-Apr-15 20:30 251:44:00 BS&W = 1.6%, 1.6%brine Tr Sed. 98.4% Crude 48 403.35 65 185.81 159.08 1604.12 100.79 127.87 0.00 2827.20 2781.96 0.90 45.24 0.00 57.96 0.02 0.94 58.90 106 84 71 1.250 N/R 1.60 0.00 1.60 0.697 0.00 17558.18 0.51 5.69 2885.85 20444.54 0 07-Apr-15 21:00 252:14:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 48 411.71 65 184.96 168.98 1603.82 100.79 122.71 0.00 2827.20 2765.00 0.90 62.20 0.00 57.60 0.02 1.30 58.90 107 84 71 1.250 N/R 2.20 0.00 2.20 0.697 0.00 17615.78 0.51 5.71 2887.15 20503.44 0 07-Apr-15 21:30 252:44:00 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude 48 416.27 68 186.86 169.34 1603.56 100.79 130.11 0.00 2946.53 2875.81 0.89 70.72 0.00 59.91 0.02 1.47 61.39 104 84 71 1.250 N/R 2.40 0.00 2.40 0.692 0.00 17675.69 0.51 5.73 2888.62 20564.82 0 07-Apr-15 22:00 253:14:00 BS&W = 1.9%, 1.9%brine Tr Sed. 97.1% Crude. Corr API = 29.3. Water salinity 42000 ppm, pH=7. Gas SG 0.698 48 416.84 64 182.96 168.34 1603.15 100.79 120.81 0.00 3168.34 3108.14 0.90 60.20 0.00 64.75 0.02 1.25 66.01 107 84 71 1.250 N/R 29.3 42000 7 1.90 0.00 1.90 0.698 0.00 17740.45 0.51 5.75 2889.88 20630.83 0 07-Apr-15 22:30 253:44:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 420.64 65 186.76 161.15 1602.85 100.78 123.92 0.00 2880.58 2822.96 0.90 57.61 0.00 58.81 0.02 1.20 60.01 107 84 71 1.250 N/R 2.00 0.00 2.00 0.698 0.00 17799.26 0.51 5.77 2891.08 20690.84 0 07-Apr-15 23:00 254:14:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 48 416.65 64 185.62 164.92 1602.49 100.78 103.70 0.00 2901.60 2837.76 0.90 63.84 0.00 59.12 0.02 1.33 60.45 107 84 71 1.250 N/R 2.20 0.00 2.20 0.698 0.00 17858.38 0.51 5.78 2892.41 20751.29 0 07-Apr-15 23:30 254:44:00 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude. Sparged sand trap. Recovered 5 gal. of frac sand (23:32)48 413.23 65 183.34 163.06 1602.17 100.78 90.76 0.00 2976.00 2922.43 0.90 53.57 0.00 60.88 0.02 1.12 62.00 106 84 71 1.250 N/R 1.80 0.00 1.80 0.698 0.00 17919.26 0.51 5.80 2893.52 20813.29 0 08-Apr-15 00:00 255:14:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 48 405.44 65 189.33 168.00 1601.78 100.78 122.14 0.00 2990.06 2924.28 0.90 65.78 0.00 60.92 0.02 1.37 62.29 106 84 71 1.250 N/R 2.20 0.00 2.20 0.698 0.00 17980.18 0.51 5.82 2894.89 20875.59 0 08-Apr-15 00:30 255:44:00 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude 48 408.29 65 184.29 162.86 1601.51 100.78 145.70 0.00 2915.66 2860.27 0.90 55.40 0.00 59.59 0.02 1.15 60.74 107 84 71 1.250 N/R 1.90 0.00 1.90 0.698 0.00 18039.77 0.51 5.84 2896.05 20936.33 0 08-Apr-15 01:00 256:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 415.70 64 186.19 167.56 1601.17 100.78 113.64 0.00 2960.59 2901.38 0.90 59.21 0.00 60.45 0.02 1.23 61.68 106 84 71 1.250 N/R 2.00 0.00 2.00 0.698 0.00 18100.22 0.51 5.86 2897.28 20998.01 0 08-Apr-15 01:30 256:44:00 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude 48 411.33 64 185.34 154.47 1600.79 100.78 120.89 0.00 3050.40 2995.49 0.90 54.91 0.00 62.41 0.02 1.14 63.55 107 84 71 1.250 N/R 1.80 0.00 1.80 0.698 0.00 18162.62 0.51 5.88 2898.43 21061.56 0 08-Apr-15 02:00 257:14:00 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude. Corr API = 29.8. Water salinity 40000 ppm, pH=7. Gas SG 0.696 48 410.95 64 184.01 159.38 1600.52 100.78 138.00 0.00 2976.00 2922.43 0.90 53.57 0.00 60.88 0.02 1.12 62.00 107 84 71 1.250 0.877 29.8 40000 7 1.80 0.00 1.80 0.696 0.00 18223.51 0.51 5.90 2899.54 21123.56 0 08-Apr-15 02:30 257:44:00 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 48 412.09 65 189.24 156.41 1600.20 100.78 117.55 0.00 3115.01 3046.48 0.90 68.53 0.00 63.47 0.02 1.43 64.90 107 84 71 1.250 N/R 2.20 0.00 2.20 0.696 0.00 18286.98 0.51 5.91 2900.97 21188.45 0 08-Apr-15 03:00 258:14:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude 48 410.19 65 185.81 168.50 1599.86 100.77 89.85 0.00 2869.34 2820.57 0.90 48.78 0.00 58.76 0.02 1.02 59.78 107 84 71 1.250 N/R 1.70 0.00 1.70 0.696 0.00 18345.74 0.51 5.93 2901.99 21248.23 0 08-Apr-15 03:30 258:44:00 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude 48 410.57 65 183.15 168.34 1599.55 100.77 126.47 0.00 3015.31 2958.02 0.93 57.29 0.00 61.63 0.02 1.19 62.82 115 84 71 1.250 N/R 1.90 0.00 1.90 0.696 0.00 18407.36 0.51 5.95 2903.18 21311.05 0 08-Apr-15 04:00 259:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude 48 417.22 65 188.76 167.44 1599.16 100.77 122.18 0.00 2831.42 2774.80 0.90 56.63 0.00 57.81 0.02 1.18 58.99 107 84 71 1.250 N/R 2.00 0.00 2.00 0.696 0.00 18465.17 0.51 5.97 2904.36 21370.04 0 08-Apr-15 04:30 259:44:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude. Sparged sand trap. Recovered 5 gal. of frac sand (04:47)48 418.55 66 185.05 161.91 1598.84 100.77 121.19 0.00 2880.58 2831.61 0.90 48.97 0.00 58.99 0.02 1.02 60.01 107 85 71 1.250 N/R 1.70 0.00 1.70 0.696 0.00 18524.16 0.51 5.99 2905.38 21430.05 0 08-Apr-15 05:00 260:14:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude 48 408.86 65 185.81 165.49 1598.16 100.77 88.86 0.00 2901.60 2852.27 0.90 49.33 0.00 59.42 0.02 1.03 60.45 107 84 71 1.250 N/R 1.70 0.00 1.70 0.696 0.00 18583.59 0.51 6.01 2906.41 21490.50 0 08-Apr-15 05:30 260:44:00 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude 48 419.12 65 185.43 173.41 1597.91 100.77 116.98 0.00 2752.80 2700.50 0.90 52.30 0.00 56.26 0.02 1.09 57.35 107 84 71 1.250 N/R 1.90 0.00 1.90 0.696 0.00 18639.85 0.51 6.03 2907.50 21547.85 0 08-Apr-15 06:00 261:14:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude. Corr API = 30.0. Water salinity 41000 ppm, pH=7. Gas SG 0.691`48 414.37 64 184.67 166.63 1597.83 100.77 117.81 0.00 2976.00 2931.36 0.89 44.64 0.00 61.07 0.02 0.93 62.00 106 84 71 1.250 0.876 30.0 41000 7 1.50 0.00 1.50 0.961 0.00 18700.92 0.51 6.05 2908.43 21609.85 0 08-Apr-15 06:30 261:44:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude 48 415.13 65 183.15 163.82 1597.45 100.77 149.00 0.00 2938.80 2888.84 0.90 49.96 0.00 60.18 0.02 1.04 61.23 108 84 71 1.250 N/R 1.70 0.00 1.70 0.691 312.95 18761.10 0.51 6.07 2909.47 21671.08 0 08-Apr-15 07:00 262:14:00 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude. **07:07hrs Divert flow through 60/64ths adjustable choke 48 415.70 65 181.63 162.13 1597.18 100.77 92.66 0.00 2954.98 2910.66 0.90 44.32 0.00 60.64 0.02 0.92 61.56 108 84 71 1.250 N/R 1.50 0.00 1.50 0.691 310.72 18821.74 0.51 6.08 2910.39 21732.64 0 08-Apr-15 07:30 262:44:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude. Sparge sand trap. Recovered 2 gallons of frac sand 60 381.30 66 226.04 58.55 1575.56 100.77 135.72 0.00 3533.33 3473.26 1.05 60.07 0.00 72.36 0.02 1.25 73.61 117 84 71 1.250 N/R 1.70 0.00 1.70 0.691 301.19 18894.10 0.51 6.11 2911.64 21806.25 0 08-Apr-15 08:00 263:14:00 BS&W = 1.9%brine Tr Sed. ** Increase adjustable choke to 72/64ths. Sparge sand trap. Recover 2 galons of frac sand 60 366.85 68 234.88 19.17 1574.78 100.78 162.13 0.00 3571.20 3503.35 1.09 67.85 0.00 72.99 0.02 1.41 74.40 115 85 71 1.250 N/R 1.90 0.00 1.90 0.691 311.72 18967.09 0.51 6.13 2913.06 21880.65 0 08-Apr-15 08:30 263:44:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude. Sparge sand trap Recover 2 gallons (8:37)72 361.72 68 219.67 29.86 1569.45 100.79 157.31 0.00 3794.40 3729.90 1.12 64.50 0.00 77.71 0.02 1.34 79.05 118 85 71 1.250 N/R 1.70 0.00 1.70 0.691 299.53 19044.79 0.51 6.15 2914.40 21959.70 0 08-Apr-15 09:00 264:14:00 BS&W = 1.8%brine Tr Sed. **Increase adjustable choke to 84/64ths. Sparge sand trap. Recover 1 gallon of frac sand 72 361.91 67 229.08 21.39 1568.57 100.79 124.26 0.00 3648.43 3582.76 1.11 65.67 0.00 74.64 0.02 1.37 76.01 118 85 71 1.250 N/R 1.80 0.00 1.80 0.691 309.78 19119.43 0.51 6.18 2915.77 22035.71 0 08-Apr-15 09:30 264:44:00 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude. Sparge sand trap Recover 2 gallons of frac sand 84 357.73 67 223.75 21.06 1565.61 100.79 130.15 0.00 3814.08 3722.54 1.10 91.54 0.00 77.55 0.02 1.91 79.46 115 85 71 1.250 N/R 2.40 0.00 2.40 0.691 294.97 19196.99 0.51 6.20 2917.68 22115.17 0 08-Apr-15 10:00 265:14:00 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Inc choke to 96/64ths Adjustable. Sparge sand trap Recover trace frac sand 84 364.19 68 227.37 18.96 1564.16 100.79 151.05 0.00 3720.00 3645.60 1.11 74.40 0.00 75.95 0.02 1.55 77.50 118 85 71 1.250 0.876 30.1 32000 8 2.00 0.00 2.00 0.686 305.75 19272.94 0.51 6.22 2919.23 22192.67 0 08-Apr-15 10:30 265:44:00 BS&W = 3.5%, 3.5%brine Tr Sed. 96.5% Crude 96 364.38 68 227.46 6.42 1561.83 100.79 127.30 0.00 3731.23 3600.64 1.13 130.59 0.00 75.01 0.02 2.72 77.73 119 85 71 1.250 N/R 3.50 0.00 3.50 0.686 315.00 19347.95 0.51 6.24 2921.95 22270.40 0 08-Apr-15 11:00 266:14:00 BS&W = 1.5%brine Tr Sed. **Increase adjustable choke to to 128/64ths. Sparge sand trap, recover trace frac sand 96 351.45 68 236.97 -4.22 1561.13 100.79 104.15 0.00 3750.91 3694.65 1.13 56.26 0.00 76.97 0.02 1.17 78.14 118 86 71 1.250 N/R 1.50 0.00 1.50 0.686 305.16 19424.92 0.51 6.27 2923.12 22348.55 0 08-Apr-15 11:30 266:44:01 BS&W = 2%, 2%brine Tr Sed. 98% Crude 128 354.12 68 228.89 10.65 1559.72 100.79 148.28 0.00 3920.78 3842.36 1.13 78.42 0.00 80.05 0.02 1.63 81.68 119 86 72 1.250 N/R 2.00 0.00 2.00 0.686 294.48 19504.97 0.51 6.29 2924.75 22430.23 0 Expro Confidential 5/5/2015 Page 9 CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives 08-Apr-15 12:00 267:14:01 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude. Sparge sand trap recover trace frac sand 128 362.10 68 229.75 4.71 1557.84 100.79 135.23 0.00 3868.80 3768.21 1.13 100.59 0.00 78.50 0.02 2.10 80.60 119 86 71 1.250 N/R 2.60 0.00 2.60 0.686 300.06 19583.47 0.51 6.32 2926.85 22510.83 0 08-Apr-15 12:30 267:44:02 BS&W = 3%, 3%brine Tr Sed. 97% Crude. Divert flow through 128/65ths fixed choke 128 360.58 69 229.75 8.29 1556.82 100.79 163.57 0.00 3794.40 3680.57 1.15 113.83 0.00 76.68 0.02 2.37 79.05 123 86 71 1.250 N/R 3.00 0.00 3.00 0.686 311.52 19660.15 0.51 6.34 2929.22 22589.88 0 08-Apr-15 13:00 268:14:01 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Sparge sand trap, recover trace frac sand 128 352.40 68 228.03 0.20 1555.31 100.79 132.88 0.00 3745.30 3670.39 1.13 74.91 0.00 76.47 0.02 1.56 78.03 120 86 71 1.250 N/R 2.00 0.00 2.00 0.686 308.82 19736.62 0.51 6.36 2930.78 22667.91 0 08-Apr-15 13:30 268:44:02 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude.128 361.91 68 227.94 4.82 1555.04 100.79 131.70 0.00 3814.80 3715.62 1.13 99.18 0.00 77.41 0.02 2.07 79.48 119 86 72 1.250 N/R 2.60 0.00 2.60 0.686 303.67 19814.03 0.51 6.39 2932.85 22747.38 0 08-Apr-15 14:00 269:14:02 BS&W = 3%, 3%brine Tr Sed. 97% Crude 128 348.98 67 227.37 9.16 1554.11 100.78 107.72 0.00 3868.80 3752.74 1.13 116.06 0.00 78.18 0.02 2.42 80.60 119 86 71 1.250 N/R 3.00 0.00 3.00 0.691 300.76 19892.21 0.51 6.41 2935.26 22827.98 0 08-Apr-15 14:30 269:44:02 BS&W = 2%, 2%brine Tr Sed. 98% Crude 128 349.74 69 233.45 -5.79 1553.43 100.78 110.00 0.00 3720.00 3645.60 1.12 74.40 0.00 75.95 0.02 1.55 77.50 119 86 71 1.250 N/R 2.00 0.00 2.00 0.691 308.48 19968.16 0.51 6.43 2936.81 22905.48 0 08-Apr-15 15:00 270:14:02 BS&W = 3%, 3%brine Tr Sed. 97% Crude 128 357.35 69 228.03 3.21 1552.85 100.78 131.21 0.00 3814.08 3699.66 1.12 114.42 0.00 77.08 0.02 2.38 79.46 119 85 71 1.250 N/R 3.00 0.00 3.00 0.691 303.70 20045.24 0.51 6.46 2939.20 22984.94 0 08-Apr-15 15:30 270:44:03 BS&W = 3.5%, 3.5%brine Tr Sed. 96.5% Crude 128 355.64 68 225.09 25.95 1552.02 100.78 157.05 0.00 3859.01 3723.94 1.12 135.07 0.00 77.58 0.02 2.81 80.40 119 84 70 1.250 N/R 3.50 0.00 3.50 0.691 300.25 20122.82 0.51 6.48 2942.01 23065.34 0 08-Apr-15 16:00 271:14:03 BS&W = 3.5%, 3.5%brine Tr Sed. 96.5% Crude. Sparge sand trap, recover trace frac sand (16:17)128 349.17 69 222.90 3.45 1551.32 100.78 109.88 0.00 3720.00 3589.80 1.11 130.20 0.00 74.79 0.02 2.71 77.50 118 84 70 1.250 N/R 3.50 0.00 3.50 0.691 310.45 20197.61 0.51 6.50 2944.72 23142.84 0 08-Apr-15 16:30 271:44:03 BS&W = 2%, 2%brine Tr Sed. 98% Crude 128 359.06 69 234.50 8.06 1550.39 100.78 136.37 0.00 3757.20 3682.06 1.12 75.14 0.00 76.71 0.02 1.57 78.28 118 83 70 1.250 N/R 2.00 0.00 2.00 0.691 303.34 20274.31 0.51 6.53 2946.29 23221.11 0 08-Apr-15 17:00 272:14:03 BS&W = 3%, 3%brine Tr Sed. 97% Crude 128 357.16 68 227.27 5.67 1549.97 100.77 143.43 0.00 3888.48 3771.83 1.12 116.65 0.00 78.58 0.02 2.43 81.01 118 83 70 1.250 N/R 3.00 0.00 3.00 0.691 296.36 20352.89 0.51 6.55 2948.72 23302.12 0 08-Apr-15 17:30 272:44:03 BS&W = 3%, 3%brine Tr Sed. 97% Crude 128 350.50 68 230.89 3.94 1549.30 100.77 154.73 0.00 3931.30 3813.36 1.12 117.94 0.00 79.45 0.02 2.46 81.90 119 83 70 1.250 N/R 3.00 0.00 3.00 0.691 293.37 20432.34 0.51 6.57 2951.18 23384.02 0 08-Apr-15 18:00 273:14:04 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude. Corr API = 30.0. Water salinity 40000 ppm, pH=7. Gas SG 0.688 128 353.35 67 229.46 4.43 1548.24 100.77 144.68 0.00 3868.80 3783.69 1.12 85.11 0.00 78.83 0.02 1.77 80.60 120 82 70 1.250 0.876 30.0 40000 7 2.20 0.00 2.20 0.688 297.14 20511.17 0.51 6.60 2952.95 23464.62 0 08-Apr-15 18:30 273:44:04 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude 128 348.60 67 229.08 -1.60 1547.47 100.77 155.68 0.00 3868.80 3783.69 1.12 85.11 0.00 78.83 0.02 1.77 80.60 119 83 70 1.250 N/R 2.20 0.00 2.20 0.688 296.33 20589.99 0.51 6.62 2954.72 23545.22 0 08-Apr-15 19:00 274:14:04 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude 128 338.34 67 219.28 1.97 1546.04 100.77 119.22 0.00 3654.05 3566.35 1.12 87.70 0.00 74.30 0.02 1.83 76.13 118 82 70 1.250 N/R 2.40 0.00 2.40 0.688 313.85 20664.29 0.51 6.64 2956.55 23621.35 0 08-Apr-15 19:30 274:44:04 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. **Bypass ball catcher (19:14) and line heater (19:31)128 344.99 66 187.71 18.47 1541.12 100.77 161.07 0.00 3899.71 3806.12 1.14 93.59 0.00 79.29 0.02 1.95 81.24 119 81 69 1.250 N/R 2.40 0.00 2.40 0.688 298.30 20743.59 0.51 6.67 2958.50 23702.59 0 08-Apr-15 20:00 275:14:05 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 128 348.22 66 197.32 23.00 1539.58 100.77 163.80 0.00 4017.60 3929.21 1.18 88.39 0.00 81.86 0.02 1.84 83.70 117 78 68 1.250 N/R 2.20 0.00 2.20 0.688 299.42 20825.44 0.51 6.69 2960.34 23786.29 0 08-Apr-15 20:30 275:44:05 BS&W = 2.8%, 2.8%brine Tr Sed. 97.2% Crude 128 315.91 67 194.85 14.16 1538.71 100.77 159.02 0.00 4033.06 3920.13 1.17 112.93 0.00 81.67 0.02 2.35 84.02 116 79 67 1.250 N/R 2.80 0.00 2.80 0.688 298.14 20907.11 0.51 6.72 2962.69 23870.32 0 08-Apr-15 21:00 276:14:05 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude. 1.250" orifice plate out of service (20:55)128 334.14 66 181.82 15.88 1537.17 100.77 162.02 0.00 4070.98 3981.41 0.00 89.56 0.00 82.95 0.00 1.87 84.81 112 77 67 1.250 N/R 2.20 0.00 2.20 0.688 N/R 20990.06 0.51 6.72 2964.56 23955.13 0 08-Apr-15 21:30 276:44:05 BS&W = 3%, 3%brine Tr Sed. 97% Crude. 1.250" orifice plate back in service 128 325.25 66 173.83 16.52 1535.63 100.77 156.21 0.00 4096.22 3973.34 1.35 122.89 0.00 82.78 0.03 2.56 85.34 88 77 67 1.250 N/R 3.00 0.00 3.00 0.688 340.11 21072.84 0.51 6.74 2967.12 24040.47 0 08-Apr-15 22:00 277:14:05 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. Corr API = 30.6. Gas SG 0.698. 1.500" orifice plate in service (21:50)128 334.45 67 178.11 10.73 1535.44 100.77 129.84 0.00 4103.23 4004.75 1.42 98.48 0.00 83.43 0.03 2.05 85.48 87 76 67 1.500 0.873 30.6 40000 7 2.40 0.00 2.40 0.698 354.80 21156.27 0.51 6.77 2969.17 24125.95 0 08-Apr-15 22:30 277:44:06 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude 128 332.47 67 179.06 18.26 1534.83 100.77 122.63 0.00 4678.20 4593.99 1.24 84.21 0.00 95.71 0.03 1.75 97.46 87 77 67 1.500 N/R 1.80 0.00 1.80 0.698 270.68 21251.98 0.51 6.80 2970.93 24223.41 0 08-Apr-15 23:00 278:14:06 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude.128 334.22 66 175.83 14.71 1534.36 100.76 161.87 0.00 4004.98 3900.85 1.24 104.13 0.00 81.27 0.03 2.17 83.44 87 77 67 1.500 N/R 2.60 0.00 2.60 0.698 318.36 21333.25 0.51 6.83 2973.10 24306.85 0 08-Apr-15 23:30 278:44:06 BS&W = 2%, 2%brine Tr Sed. 98% Crude 128 330.49 68 180.30 14.01 1533.86 100.76 125.48 0.00 4132.75 4050.10 1.24 82.66 0.00 84.38 0.03 1.72 86.10 87 77 67 1.500 N/R 2.00 0.00 2.00 0.698 307.24 21417.62 0.51 6.85 2974.82 24392.95 0 09-Apr-15 00:00 279:14:06 BS&W = 2.8%, 2.8%brine Tr Sed. 97.2% Crude 128 330.95 67 181.06 12.87 1533.22 100.76 125.74 0.00 4166.40 4049.74 1.24 116.66 0.00 84.37 0.03 2.43 86.80 86 77 67 1.500 N/R 2.80 0.00 2.80 0.698 305.91 21501.99 0.51 6.88 2977.25 24479.75 0 09-Apr-15 00:30 279:44:06 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 128 332.78 67 180.11 16.65 1532.72 100.76 158.00 0.00 4092.00 4001.98 1.24 90.02 0.00 83.37 0.03 1.88 85.25 87 77 67 1.500 N/R 2.20 0.00 2.20 0.698 309.80 21585.37 0.51 6.90 2979.12 24565.00 0 09-Apr-15 01:00 280:14:07 BS&W = 3%, 3%brine Tr Sed. 97% Crude. H2S 0.5 ppm. CO2 0% 128 331.33 68 183.24 6.16 1532.10 100.76 128.93 0.00 4082.21 3959.74 1.24 122.47 0.00 82.49 0.03 2.55 85.05 87 77 67 1.500 N/R 3.00 0.00 3.00 0.698 0.00 0.50 314.36 21667.86 0.51 6.93 2981.67 24650.04 0 09-Apr-15 01:30 280:44:07 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude 128 331.94 67 181.34 4.86 1531.51 100.76 183.46 0.00 4156.61 4081.79 1.24 74.82 0.00 85.04 0.03 1.56 86.60 87 78 67 1.500 N/R 1.80 0.00 1.80 0.698 304.08 21752.90 0.51 6.95 2983.23 24736.64 0 09-Apr-15 02:00 281:14:07 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Corr API = 29.9. Water salinity 40000 ppm, pH=7. Gas SG 0.702. H2S 0.5ppm 128 331.41 68 181.25 7.60 1531.13 100.76 161.72 0.00 3707.38 3633.23 1.24 74.15 0.00 75.69 0.03 1.54 77.24 87 77 67 1.500 0.877 29.9 40000 7 2.00 0.00 2.00 0.702 0.50 342.24 21828.59 0.51 6.98 2984.78 24813.88 0 09-Apr-15 02:30 281:44:07 BS&W = 2.8%, 2.8%brine Tr Sed. 97.2% Crude. Sparge sand trap, recover 10 gallons frac sand (2:45)128 333.69 70 180.96 6.37 1530.27 100.75 152.08 0.00 3776.16 3670.43 1.25 105.73 0.00 76.47 0.03 2.20 78.67 88 77 67 1.500 N/R 2.80 0.00 2.80 0.702 339.28 21905.06 0.51 7.01 2986.98 24892.55 0 09-Apr-15 03:00 282:14:08 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude. H2S 0.5ppm 128 331.41 70 183.15 -0.90 1529.65 100.75 143.05 0.00 3760.75 3689.30 1.24 71.45 0.00 76.86 0.03 1.49 78.35 87 76 67 1.500 N/R 1.90 0.00 1.90 0.702 0.50 336.14 21981.92 0.51 7.03 2988.47 24970.90 0 09-Apr-15 03:30 282:44:08 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 128 325.32 69 178.78 2.34 1529.47 100.75 172.72 0.00 4146.77 4055.54 1.24 91.23 0.00 84.49 0.03 1.90 86.39 88 76 67 1.500 N/R 2.20 0.00 2.20 0.702 306.29 22066.41 0.51 7.06 2990.37 25057.29 0 09-Apr-15 04:00 283:14:08 BS&W = 2.8%, 2.8%brine Tr Sed. 97.2% Crude. H2S 0.5ppm 128 328.59 69 178.01 7.06 1529.12 100.75 144.30 0.00 4296.96 4176.65 1.23 120.31 0.00 87.01 0.03 2.51 89.52 85 77 67 1.500 N/R 2.80 0.00 2.80 0.702 0.50 293.52 22153.42 0.51 7.08 2992.88 25146.81 0 09-Apr-15 04:30 283:44:08 BS&W = 2%, 2%brine Tr Sed. 98% Crude 128 332.09 69 181.34 3.92 1528.65 100.75 168.05 0.00 4160.83 4077.62 1.25 83.22 0.00 84.95 0.03 1.73 86.68 89 77 67 1.500 N/R 2.00 0.00 2.00 0.702 306.40 22238.37 0.51 7.11 2994.61 25233.49 0 09-Apr-15 05:00 284:14:08 BS&W = 1.6%, 1.6%brine Tr Sed. 98.4% Crude. H2S 0.5ppm 128 333.31 69 180.96 3.55 1528.48 100.75 160.69 0.00 4027.44 3963.00 1.24 64.44 0.00 82.56 0.03 1.34 83.91 87 77 67 1.500 N/R 1.60 0.00 1.60 0.702 0.50 312.61 22320.94 0.51 7.14 2995.95 25317.40 0 09-Apr-15 05:30 284:44:09 BS&W = 2%, 2%brine Tr Sed. 98% Crude 128 338.10 69 192.94 16.25 1529.97 100.75 137.20 0.00 3960.05 3880.85 1.18 79.20 0.00 80.85 0.02 1.65 82.50 111 77 67 1.500 N/R 2.00 0.00 2.00 0.702 302.87 22401.79 0.51 7.16 2997.60 25399.90 0 09-Apr-15 06:00 285:14:09 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% . Corr API = 30.5. Water salinity 40000 ppm, pH=7. Gas SG 0.691. H2S 0.5ppm 128 335.21 68 190.38 19.76 1530.08 100.73 176.74 0.00 4000.80 3904.78 1.15 96.02 0.00 81.35 0.02 2.00 83.35 116 78 67 1.500 0.873 30.5 40000 7 2.40 0.00 2.40 0.702 0.50 294.21 22483.14 0.51 7.18 2999.60 25483.25 0 09-Apr-15 06:30 285:44:09 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 128 340.08 69 190.38 9.77 1529.59 100.73 153.33 0.00 4000.80 3912.78 1.15 88.02 0.00 81.52 0.02 1.83 83.35 117 78 67 1.500 N/R 2.20 0.00 2.20 0.691 294.83 22564.65 0.51 7.21 3001.44 25566.60 0 09-Apr-15 07:00 286:14:09 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude.128 337.49 69 199.13 0.84 1529.25 100.73 143.88 0.00 4054.80 3949.38 1.15 105.42 0.00 82.28 0.02 2.20 84.48 117 78 67 1.500 N/R 2.60 0.00 2.60 0.691 0.50 292.34 22646.93 0.51 7.23 3003.63 25651.07 0 09-Apr-15 07:30 286:44:10 BS&W = 3%, 3%brine Tr Sed. 97% Crude 128 333.99 69 202.83 0.52 1528.96 100.73 120.55 0.00 3943.20 3824.90 1.16 118.30 0.00 79.69 0.02 2.46 82.15 118 78 67 1.500 N/R 3.00 0.00 3.00 0.691 302.53 22726.62 0.51 7.26 3006.10 25733.22 0 09-Apr-15 08:00 287:14:10 BS&W = 2.8%, 2.8%brine Tr Sed. 97.2% Crude.128 336.35 70 193.70 6.82 1528.75 100.73 136.03 0.00 3910.94 3801.43 1.16 109.51 0.00 79.20 0.02 2.28 81.48 118 78 67 1.500 N/R 2.80 0.00 2.80 0.691 0.50 304.61 22805.81 0.51 7.28 3008.38 25814.70 0 09-Apr-15 08:30 287:44:10 BS&W = 2%, 2%brine Tr Sed. 98% Crude 128 338.33 69 192.94 11.73 1528.44 100.73 129.58 0.00 3995.18 3915.28 1.16 79.90 0.00 81.57 0.02 1.66 83.23 118 78 67 1.500 N/R 2.00 0.00 2.00 0.691 295.31 22887.38 0.51 7.30 3010.04 25897.93 0 09-Apr-15 09:00 288:14:10 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. Sparge sand trap, recover 2 gallons frac sand 128 338.48 69 190.66 6.47 1527.96 100.73 172.15 0.00 4092.00 3993.79 1.16 98.21 0.00 83.20 0.02 2.05 85.25 118 78 67 1.500 N/R 2.40 0.00 2.40 0.691 290.09 22970.59 0.51 7.33 3012.09 25983.18 0 09-Apr-15 09:30 288:44:10 BS&W = 2%, 2%brine Tr Sed. 98% Crude 128 337.03 69 195.23 10.20 1527.27 100.73 162.21 0.00 3868.80 3791.42 1.16 77.38 0.00 78.99 0.02 1.61 80.60 118 78 67 1.500 N/R 2.00 0.00 2.00 0.691 306.37 23049.57 0.51 7.35 3013.70 26063.78 0 09-Apr-15 10:00 289:14:11 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Corr API = 30.2. Water salinity 40000 ppm, pH=7. Gas SG 0.703. 128 335.13 69 198.65 3.57 1526.77 100.72 141.61 0.00 3962.18 3882.94 1.16 79.24 0.00 80.89 0.02 1.65 82.55 118 78 67 1.500 0.875 30.2 40000 7 2.00 0.00 2.00 0.703 298.27 23130.47 0.51 7.38 3015.35 26146.33 0 09-Apr-15 10:30 289:44:11 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. 128 335.13 70 193.90 10.40 1526.63 100.72 144.41 0.00 3905.33 3811.60 1.16 93.73 0.00 79.41 0.02 1.95 81.36 118 78 67 1.500 N/R 2.40 0.00 2.40 0.703 303.24 23209.88 0.51 7.40 3017.31 26227.69 0 09-Apr-15 11:00 290:14:11 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude.128 336.20 71 196.46 17.26 1526.27 100.72 138.49 0.00 4054.80 3949.38 1.16 105.42 0.00 82.28 0.02 2.20 84.48 118 79 68 1.500 N/R 2.60 0.00 2.60 0.703 292.95 23292.16 0.51 7.43 3019.50 26312.16 0 09-Apr-15 11:30 290:44:11 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude.128 338.86 70 205.59 -5.25 1525.73 100.72 133.07 0.00 4092.00 3985.61 1.16 106.39 0.00 83.03 0.02 2.22 85.25 118 78 68 1.500 N/R 2.60 0.00 2.60 0.703 290.93 23375.19 0.51 7.45 3021.72 26397.41 0 09-Apr-15 12:00 291:14:12 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude. Sparge sand trap, recover 1 gallons frac sand 128 337.64 70 195.32 13.50 1525.22 100.72 137.96 0.00 4070.98 3981.42 1.16 89.56 0.00 82.95 0.02 1.87 84.81 119 78 68 1.500 N/R 2.20 0.00 2.20 0.703 291.91 23458.14 0.51 7.47 3023.58 26482.23 0 09-Apr-15 12:30 291:44:12 BS&W = 3%, 3%brine Tr Sed. 97% Crude 128 339.39 71 198.84 8.85 1524.63 100.72 174.39 0.00 3830.93 3716.00 1.16 114.93 0.00 77.42 0.02 2.39 79.81 119 78 68 1.500 N/R 3.00 0.00 3.00 0.703 312.73 23535.55 0.51 7.50 3025.98 26562.04 0 09-Apr-15 13:00 292:14:12 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude.128 336.20 71 189.81 1.68 1522.32 100.72 170.02 0.00 4092.00 3985.61 1.23 106.39 0.00 83.03 0.03 2.22 85.25 101 78 67 1.500 N/R 2.60 0.00 2.60 0.703 308.60 23618.59 0.51 7.52 3028.19 26647.29 0 09-Apr-15 13:30 292:44:12 BS&W = 2%, 2%brine Tr Sed. 98% Crude 128 344.18 71 184.39 15.01 1522.47 100.72 148.70 0.00 4092.00 4010.16 1.23 81.84 0.00 83.55 0.03 1.71 85.25 98 78 67 1.500 0.873 30.5 39000 7 2.00 0.00 2.00 0.703 307.10 23702.13 0.51 7.55 3029.90 26732.54 0 09-Apr-15 14:00 293:14:12 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Corr API = 30.2. Water salinity 39000 ppm, pH=7. Gas SG 0.698. 128 337.87 71 189.14 14.03 1523.47 100.72 170.10 0.00 3842.16 3765.32 1.19 76.84 0.00 78.44 0.02 1.60 80.05 110 78 68 1.500 N/R 2.00 0.00 2.00 0.698 315.25 23780.57 0.51 7.57 3031.50 26812.58 0 09-Apr-15 14:30 293:44:13 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. 128 330.49 71 193.04 1.65 1523.14 100.72 141.91 0.00 3996.58 3900.66 1.18 95.92 0.00 81.26 0.02 2.00 83.26 110 78 68 1.500 N/R 2.40 0.00 2.40 0.698 303.70 23861.84 0.51 7.60 3033.50 26895.84 0 09-Apr-15 15:00 294:14:13 BS&W = 2.6%, 2.6%brine Tr Sed. 97.4% Crude.128 333.08 71 192.94 3.06 1522.73 100.72 128.25 0.00 4092.00 3985.61 1.19 106.39 0.00 83.03 0.02 2.22 85.25 110 78 68 1.500 N/R 2.60 0.00 2.60 0.698 298.34 23944.87 0.51 7.62 3035.72 26981.09 0 09-Apr-15 15:30 294:44:13 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. 128 335.21 71 189.24 9.97 1522.42 100.72 151.17 0.00 3805.63 3714.29 1.20 91.34 0.00 77.38 0.03 1.90 79.28 113 78 68 1.500 N/R 2.40 0.00 2.40 0.698 323.56 24022.25 0.51 7.65 3037.62 27060.38 0 09-Apr-15 16:00 295:14:13 BS&W = 2%, 2%brine Tr Sed. 98% Crude 128 335.36 72 192.75 21.34 1521.92 100.72 136.22 0.00 4070.98 3989.56 1.19 81.42 0.00 83.12 0.02 1.70 84.81 110 78 68 1.500 N/R 2.00 0.00 2.00 0.698 298.27 24105.37 0.51 7.67 3039.31 27145.19 0 09-Apr-15 16:30 295:44:14 BS&W = 2%, 2%brine Tr Sed. 98% Crude 128 337.41 72 199.60 6.96 1522.43 100.72 153.90 0.00 3920.78 3842.36 1.17 78.42 0.00 80.05 0.02 1.63 81.68 116 78 67 1.500 N/R 2.00 0.00 2.00 0.698 305.75 24185.42 0.51 7.70 3040.95 27226.87 0 09-Apr-15 17:00 296:14:14 BS&W = 2%, 2%brine Tr Sed. 98% Crude.Sparge sand trap, recover 1 gallons frac sand 128 342.13 71 200.08 10.63 1522.53 100.71 144.75 0.00 3943.20 3864.34 1.16 78.86 0.00 80.51 0.02 1.64 82.15 122 78 68 1.500 N/R 2.00 0.00 2.00 0.698 300.87 24265.92 0.51 7.72 3042.59 27309.02 0 09-Apr-15 17:30 296:44:14 BS&W = 2%, 2%brine Tr Sed. 98% Crude 128 341.14 71 194.28 9.64 1521.77 100.71 126.88 0.00 3980.40 3900.79 1.16 79.61 0.00 81.27 0.02 1.66 82.93 121 78 67 1.500 N/R 2.00 0.00 2.00 0.698 297.65 24347.19 0.51 7.75 3044.25 27391.95 0 09-Apr-15 18:00 297:14:14 BS&W = 1.6%, 1.6%brine Tr Sed. 98.4% Crude. Corr API = 30.3. Water salinity 40000 ppm, pH=7. Gas SG 0.702 128 339.01 70 195.70 17.08 1521.52 100.71 118.88 0.00 4145.38 4079.05 1.16 66.33 0.00 84.98 0.02 1.38 86.36 121 78 67 1.500 0.875 30.3 40000 7 1.60 0.00 1.60 0.698 284.76 24432.17 0.51 7.77 3045.63 27478.31 0 09-Apr-15 18:30 297:44:14 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude 128 337.41 70 201.60 13.25 1520.66 100.71 139.02 0.00 3943.20 3884.05 1.16 59.15 0.00 80.92 0.02 1.23 82.15 122 79 67 1.500 N/R 1.50 0.00 1.50 0.702 299.03 24513.09 0.51 7.79 3046.86 27560.46 0 09-Apr-15 19:00 298:14:15 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude 128 341.14 70 198.17 14.79 1520.90 100.71 133.75 0.00 3943.20 3872.22 1.16 70.98 0.00 80.67 0.02 1.48 82.15 122 78 67 1.500 N/R 1.80 0.00 1.80 0.702 300.15 24593.76 0.51 7.82 3048.34 27642.61 0 09-Apr-15 19:30 298:44:15 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude. 128 339.16 68 199.41 6.77 1520.55 100.71 115.77 0.00 4017.60 3921.18 1.17 96.42 0.00 81.69 0.02 2.01 83.70 123 78 67 1.500 N/R 2.40 0.00 2.40 0.702 298.98 24675.45 0.51 7.84 3050.35 27726.31 0 09-Apr-15 20:00 299:14:15 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 128 338.10 68 201.60 -0.69 1520.47 100.71 162.40 0.00 4156.61 4065.16 1.16 91.45 0.00 84.69 0.02 1.91 86.60 121 78 67 1.500 N/R 2.20 0.00 2.20 0.702 284.89 24760.14 0.51 7.87 3052.26 27812.91 0 09-Apr-15 20:30 299:44:15 BS&W = 1.6%, 1.6%brine Tr Sed. 98.4% Crude. 128 340.99 67 197.98 14.98 1519.83 100.71 141.57 0.00 3985.34 3921.57 1.16 63.77 0.00 81.70 0.02 1.33 83.03 121 78 67 1.500 N/R 1.60 0.00 1.60 0.702 294.83 24841.84 0.51 7.89 3053.58 27895.93 0 09-Apr-15 21:00 300:14:15 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude 128 342.28 66 196.84 7.27 1519.43 100.71 152.68 0.00 4092.00 4022.44 1.16 69.56 0.00 83.80 0.02 1.45 85.25 122 78 67 1.500 N/R 1.70 0.00 1.70 0.702 288.99 24925.64 0.51 7.92 3055.03 27981.18 0 Expro Confidential 5/5/2015 Page 10 CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives 09-Apr-15 21:30 300:44:16 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude 128 337.26 65 197.98 9.33 1518.91 100.71 145.97 0.00 3960.05 3865.01 1.16 95.04 0.00 80.52 0.02 1.98 82.50 122 78 67 1.500 N/R 2.40 0.00 2.40 0.702 301.24 25006.16 0.51 7.94 3057.01 28063.69 0 09-Apr-15 22:00 301:14:16 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude. Corr API = 30.4. Water salinity 42000 ppm, pH=7. Gas SG 0.696 128 344.41 65 200.65 5.35 1518.44 100.71 156.40 0.00 3881.47 3811.60 1.17 69.87 0.00 79.41 0.02 1.46 80.86 122 78 67 1.500 0.874 30.4 42000 7 1.80 0.00 1.80 0.696 305.93 25085.57 0.51 7.96 3058.47 28144.55 0 09-Apr-15 22:30 301:44:16 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude 128 342.21 65 201.69 4.30 1518.12 100.71 130.18 0.00 3988.13 3912.36 1.17 75.77 0.00 81.51 0.02 1.58 83.09 121 78 67 1.500 N/R 1.90 0.00 1.90 0.696 297.85 25167.08 0.51 7.99 3060.05 28227.64 0 09-Apr-15 23:00 302:14:16 BS&W = 2.4%, 2.4%brine Tr Sed. 97.6% Crude 128 343.73 64 200.55 16.18 1517.73 100.70 154.13 0.00 4027.44 3930.78 1.17 96.66 0.00 81.89 0.02 2.01 83.91 122 78 67 1.500 N/R 2.40 0.00 2.40 0.696 297.38 25248.97 0.51 8.01 3062.06 28311.54 0 09-Apr-15 23:30 302:44:17 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude 128 341.75 65 203.69 13.80 1517.64 100.70 121.80 0.00 3920.78 3854.13 1.17 66.65 0.00 80.29 0.02 1.39 81.68 123 78 67 1.500 N/R 1.70 0.00 1.70 0.696 304.41 25329.27 0.51 8.04 3063.45 28393.22 0 10-Apr-15 00:00 303:14:17 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 128 341.29 65 196.27 16.88 1517.38 100.70 134.05 0.00 3840.77 3756.27 1.17 84.50 0.00 78.26 0.02 1.76 80.02 123 78 67 1.500 N/R 2.20 0.00 2.20 0.696 312.58 25407.52 0.51 8.06 3065.21 28473.24 0 10-Apr-15 00:30 303:44:17 BS&W = 1.6%, 1.6%brine Tr Sed. 98.4% Crude. 128 340.23 65 197.03 8.21 1516.51 100.70 123.13 0.00 3943.20 3880.11 1.18 63.09 0.00 80.84 0.02 1.31 82.15 123 78 68 1.500 N/R 1.60 0.00 1.60 0.696 302.87 25488.36 0.51 8.09 3066.53 28555.39 0 10-Apr-15 01:00 304:14:17 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude 128 342.59 64 198.93 18.93 1516.50 100.70 139.52 0.00 4040.06 3963.30 1.17 76.76 0.00 82.57 0.02 1.60 84.17 123 78 67 1.500 N/R 1.90 0.00 1.90 0.696 296.38 25570.93 0.51 8.11 3068.12 28639.56 0 10-Apr-15 01:30 304:44:17 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude 128 342.51 66 201.03 8.36 1516.13 100.70 164.07 0.00 3871.63 3801.94 1.17 69.69 0.00 79.21 0.02 1.45 80.66 123 78 68 1.500 N/R 1.80 0.00 1.80 0.696 308.46 25650.13 0.51 8.13 3069.58 28720.22 0 10-Apr-15 02:00 305:14:18 BS&W = 1.6%, 1.6%brine Tr Sed. 98.4% Crude. Corr API = 29.5. Water salinity 42000 ppm, pH=7. Gas SG 0.696 128 343.57 67 197.89 13.57 1515.65 100.70 147.52 0.00 3992.35 3928.47 1.18 63.88 0.00 81.84 0.02 1.33 83.17 123 78 67 1.500 0.879 29.5 42000 7 1.60 0.00 1.60 0.696 299.71 25731.98 0.51 8.16 3070.91 28803.39 0 10-Apr-15 02:30 305:44:18 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude 128 342.13 64 201.41 8.54 1516.00 100.70 132.35 0.00 3943.20 3872.22 1.18 70.98 0.00 80.67 0.02 1.48 82.15 123 78 67 1.500 N/R 1.80 0.00 1.80 0.696 303.54 25812.65 0.51 8.18 3072.39 28885.54 0 10-Apr-15 03:00 306:14:18 BS&W = 2.2%, 2.2%brine Tr Sed. 97.8% Crude 128 341.37 66 200.84 13.07 1514.66 100.70 137.89 0.00 3868.80 3783.69 1.18 85.11 0.00 78.83 0.02 1.77 80.60 123 78 67 1.500 N/R 2.20 0.00 2.20 0.696 310.73 25891.47 0.51 8.21 3074.16 28966.14 0 10-Apr-15 03:30 306:44:18 BS&W = 1.5%, 1.5%brine Tr Sed. 98.5% Crude 128 347.53 64 202.74 0.05 1515.11 100.70 108.44 0.00 4002.19 3942.16 1.18 60.03 0.00 82.13 0.02 1.25 83.38 123 77 67 1.500 N/R 1.50 0.00 1.50 0.696 298.47 25973.60 0.51 8.23 3075.41 29049.52 0 10-Apr-15 04:00 307:14:19 BS&W = 1.9%, 1.9%brine Tr Sed. 98.1% Crude 128 340.30 65 193.70 7.58 1514.40 100.70 133.45 0.00 4167.84 4088.65 1.18 79.19 0.00 85.18 0.02 1.65 86.83 123 78 67 1.500 N/R 1.90 0.00 1.90 0.696 287.64 26058.78 0.51 8.26 3077.06 29136.35 0 10-Apr-15 04:30 307:44:19 BS&W = 1.7%, 1.7%brine Tr Sed. 98.3% Crude 128 332.78 65 195.70 8.22 1513.41 100.70 114.85 0.00 3868.80 3803.03 1.18 65.77 0.00 79.23 0.02 1.37 80.60 123 78 67 1.500 N/R 1.70 0.00 1.70 0.696 309.87 26138.01 0.51 8.28 3078.43 29216.95 0 10-Apr-15 05:00 308:14:19 BS&W = 2%, 2%brine Tr Sed. 98% Crude. Sparge sand trap & separator, recover 5 gallon frac sand 128 343.65 65 202.64 11.27 1513.76 100.70 141.87 0.00 4166.40 4083.07 1.18 83.33 0.00 85.06 0.02 1.74 86.80 124 78 67 1.500 N/R 2.00 0.00 2.00 0.696 289.31 26223.08 0.51 8.31 3080.17 29303.75 0 10-Apr-15 05:30 308:44:19 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude 128 346.62 66 198.08 6.03 1513.84 100.70 139.40 0.00 3828.10 3759.19 1.19 68.91 0.00 78.32 0.02 1.44 79.75 125 77 67 1.500 N/R 1.80 0.00 1.80 0.696 316.14 26301.39 0.51 8.33 3081.60 29383.50 0 10-Apr-15 06:00 309:14:19 BS&W = 1.8%, 1.8%brine Tr Sed. 98.2% Crude. Corr API = 30.1. Water salinity 40000 ppm, pH=7. Gas SG 0.698 128 340.00 66 201.60 29.46 1513.63 100.70 121.08 0.00 3831.60 3762.63 1.19 68.97 0.00 78.39 0.02 1.44 79.83 125 77 67 1.500 0.876 30.1 40000 7 1.80 0.00 1.80 0.696 315.59 26379.78 0.51 8.36 3083.04 29463.33 0 10-Apr-15 06:30 309:44:20 BS&W = 1.6%, 1.6%brine Tr Sed. 98.4% Crude. Sparge sand trap & separator, recover trace frac sand 128 342.51 67 204.07 -5.43 1513.29 100.70 152.12 0.00 4080.82 4015.53 1.17 65.29 0.00 83.66 0.02 1.36 85.02 123 77 67 1.500 N/R 1.60 0.00 1.60 0.698 292.23 26463.44 0.51 8.38 3084.40 29548.34 0 10-Apr-15 07:00 310:14:20 BS&W = 1.6%, 1.6%brine Tr Sed. 98.4% Crude. Divert flow through 32/64ths positive choke 128 437.33 66 113.54 313.71 1557.30 100.71 136.52 0.00 3348.00 3294.43 0.40 53.57 0.00 68.63 0.01 1.12 69.75 116 75 67 1.500 N/R 1.60 0.00 1.60 0.698 121.69 26532.07 0.51 8.39 3085.51 29618.09 0 10-Apr-15 07:30 310:44:20 BS&W = 1.6%, 1.6%brine Tr Sed. 98.4% Crude. 32 417.52 61 100.23 301.77 1569.64 100.65 114.89 0.00 1562.20 1537.20 0.40 25.00 0.00 32.03 0.01 0.52 32.55 91 74 65 1.000 N/R 1.60 0.00 1.60 0.698 261.39 26564.10 0.51 8.40 3086.04 29650.64 0 10-Apr-15 08:00 311:14:20 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude 32 414.17 60 101.18 288.76 1572.48 100.63 94.14 0.00 1488.00 1480.56 0.41 7.44 0.00 30.85 0.01 0.16 31.00 87 73 64 1.000 N/R 0.50 0.00 0.50 0.698 274.87 26594.94 0.51 8.41 3086.19 29681.64 0 10-Apr-15 08:30 311:44:21 BS&W = .7%, .7%brine Tr Sed. 99.3% Crude 32 421.02 61 106.03 282.78 1576.46 100.62 106.73 0.00 1562.40 1551.46 0.40 10.94 0.00 32.32 0.01 0.23 32.55 87 71 64 1.000 N/R 0.70 0.00 0.70 0.698 257.40 26627.26 0.51 8.41 3086.42 29714.19 0 10-Apr-15 09:00 312:14:21 BS&W = .7%, .7%brine Tr Sed. 99.3% Crude 32 426.28 60 102.89 300.99 1578.59 100.62 72.40 0.00 1572.24 1561.23 0.40 11.01 0.00 32.53 0.01 0.23 32.76 87 71 63 1.000 N/R 0.70 0.00 0.70 0.698 256.70 26659.79 0.51 8.42 3086.65 29746.94 0 10-Apr-15 09:30 312:44:21 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 424.22 60 110.78 296.49 1579.96 100.61 65.76 0.00 1488.00 1484.28 0.40 3.72 0.00 30.92 0.01 0.08 31.00 88 70 63 1.000 N/R 0.25 0.00 0.25 0.698 271.02 26690.71 0.51 8.43 3086.72 29777.94 0 10-Apr-15 10:00 313:14:21 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude. Corr API = 30.4. Water salinity 40000 ppm, pH=7. Gas SG 0.699 32 428.11 60 108.22 306.79 1581.96 100.61 58.47 0.00 1520.30 1516.50 0.40 3.80 0.00 31.59 0.01 0.08 31.67 89 70 63 1.000 0.874 30.4 40000 7 0.25 0.00 0.25 0.699 264.27 26722.31 0.51 8.44 3086.80 29809.62 0 10-Apr-15 10:30 313:44:21 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude 32 425.90 60 141.88 259.93 1583.07 100.61 55.44 0.00 1562.40 1554.59 0.34 7.81 0.00 32.39 0.01 0.16 32.55 98 71 64 1.000 N/R 0.50 0.00 0.50 0.699 217.05 26754.69 0.51 8.45 3086.97 29842.17 0 10-Apr-15 11:00 314:14:22 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude 32 430.17 61 131.42 282.83 1584.43 100.61 51.57 0.00 1488.00 1480.56 0.39 7.44 0.00 30.85 0.01 0.16 31.00 121 69 64 1.000 N/R 0.50 0.00 0.50 0.699 261.05 26785.54 0.51 8.45 3087.12 29873.17 0 10-Apr-15 11:30 314:44:22 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 431.31 61 131.04 270.21 1585.57 100.61 46.56 0.00 1488.00 1485.02 0.38 2.98 0.00 30.94 0.01 0.06 31.00 117 69 64 1.000 N/R 0.20 0.00 0.20 0.699 256.13 26816.48 0.51 8.46 3087.18 29904.17 0 10-Apr-15 12:00 315:14:22 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude 32 430.62 60 131.42 278.68 1586.94 100.61 23.90 0.00 1492.22 1484.76 0.38 7.46 0.00 30.93 0.01 0.16 31.09 116 70 64 1.000 N/R 0.50 0.00 0.50 0.699 256.09 26847.41 0.51 8.47 3087.34 29935.26 0 10-Apr-15 12:30 315:44:22 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude 32 440.53 60 134.46 272.44 1587.99 100.61 41.81 0.00 1636.80 1628.62 0.38 8.18 0.00 33.93 0.01 0.17 34.10 118 70 64 1.000 N/R 0.50 0.00 0.50 0.699 235.11 26881.34 0.51 8.48 3087.51 29969.36 0 10-Apr-15 13:00 316:14:22 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 432.98 60 133.99 279.51 1588.80 100.61 44.77 0.00 1636.80 1633.53 0.39 3.27 0.00 34.03 0.01 0.07 34.10 120 70 64 1.000 N/R 0.20 0.00 0.20 0.699 236.08 26915.37 0.51 8.49 3087.58 30003.46 0 10-Apr-15 13:30 316:44:23 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 428.64 62 134.94 277.80 1589.49 100.61 49.10 0.00 1562.40 1559.28 0.39 3.12 0.00 32.48 0.01 0.07 32.55 120 69 64 1.000 N/R 0.20 0.00 0.20 0.699 247.57 26947.86 0.51 8.49 3087.64 30036.01 0 10-Apr-15 14:00 317:14:23 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude. Corr API = 30.2. Water salinity 40000 ppm, pH=7. Gas SG 0.690 32 431.31 62 137.03 271.94 1590.49 100.60 34.98 0.00 1525.20 1517.57 0.38 7.63 0.00 31.62 0.01 0.16 31.78 120 69 64 1.000 0.875 30.2 40000 7 0.50 0.00 0.50 0.690 252.29 26979.47 0.51 8.50 3087.80 30067.78 0 10-Apr-15 14:30 317:44:23 BS&W = Tr H20, 100% Crude 32 432.15 63 137.22 282.49 1591.42 100.60 39.61 0.00 1562.40 1562.40 0.39 0.00 0.00 32.55 0.01 0.00 32.55 119 70 64 1.000 N/R 0.00 0.00 0.00 0.690 249.84 27012.02 0.51 8.51 3087.80 30100.33 0 10-Apr-15 15:00 318:14:23 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 434.43 63 132.08 275.19 1591.90 100.60 33.24 0.00 1525.20 1521.39 0.39 3.81 0.00 31.70 0.01 0.08 31.78 120 69 64 1.000 N/R 0.25 0.00 0.25 0.690 258.14 27043.72 0.51 8.52 3087.88 30132.11 0 10-Apr-15 15:30 318:44:23 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude 32 433.52 64 135.41 279.02 1592.51 100.60 30.39 0.00 1488.00 1480.56 0.39 7.44 0.00 30.85 0.01 0.16 31.00 121 69 64 1.000 N/R 0.50 0.00 0.50 0.690 266.18 27074.56 0.51 8.53 3088.04 30163.11 0 10-Apr-15 16:00 319:14:24 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 434.28 63 133.04 287.06 1593.42 100.60 30.54 0.00 1642.42 1638.31 0.39 4.11 0.00 34.13 0.01 0.09 34.22 120 69 64 1.000 N/R 0.25 0.00 0.25 0.690 239.32 27108.69 0.51 8.53 3088.12 30197.32 0 10-Apr-15 16:30 319:44:24 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 436.56 63 132.66 278.95 1594.02 100.60 26.71 0.00 1629.79 1625.72 0.39 4.07 0.00 33.87 0.01 0.08 33.95 121 70 64 1.000 N/R 0.25 0.00 0.25 0.690 241.59 27142.56 0.51 8.54 3088.21 30231.28 0 10-Apr-15 17:00 320:14:24 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 431.77 61 137.03 275.71 1594.33 100.60 26.52 0.00 1440.29 1436.69 0.39 3.60 0.00 29.93 0.01 0.08 30.01 121 70 64 1.000 N/R 0.25 0.00 0.25 0.690 273.18 27172.49 0.51 8.55 3088.28 30261.28 0 10-Apr-15 17:30 320:44:24 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude 32 436.87 62 135.22 276.20 1595.05 100.60 20.79 0.00 1488.00 1480.56 0.40 7.44 0.00 30.85 0.01 0.16 31.00 123 69 64 1.000 N/R 0.50 0.00 0.50 0.690 268.03 27203.34 0.51 8.56 3088.44 30292.28 0 10-Apr-15 18:00 321:14:24 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude. Corr API = 30. Water salinity 40000 ppm, pH=7. Gas SG 0.692 32 438.77 61 136.17 280.71 1595.60 100.60 25.31 0.00 1562.40 1557.71 0.39 4.69 0.00 32.45 0.01 0.10 32.55 121 70 64 1.000 0.876 30.0 40000 7 0.30 0.00 0.30 0.692 252.60 27235.79 0.51 8.57 3088.53 30324.83 0 10-Apr-15 18:30 321:44:25 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 439.38 61 139.79 272.01 1596.13 100.60 0.19 0.00 1488.00 1484.28 0.39 3.72 0.00 30.92 0.01 0.08 31.00 122 70 64 1.000 N/R 0.25 0.00 0.25 0.692 265.70 27266.71 0.51 8.58 3088.61 30355.83 0 10-Apr-15 19:00 322:14:25 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude 32 437.63 62 135.98 278.83 1596.56 100.60 24.85 0.00 1562.40 1554.59 0.40 7.81 0.00 32.39 0.01 0.16 32.55 123 70 64 1.000 N/R 0.50 0.00 0.50 0.692 254.70 27299.10 0.51 8.58 3088.77 30388.38 0 10-Apr-15 19:30 322:44:25 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude 32 439.84 62 138.93 286.44 1597.22 100.60 25.31 0.00 1562.40 1558.49 0.40 3.91 0.00 32.47 0.01 0.08 32.55 123 70 63 1.000 N/R 0.25 0.00 0.25 0.692 253.84 27331.57 0.51 8.59 3088.86 30420.93 0 10-Apr-15 20:00 323:14:25 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 437.63 62 137.03 277.03 1597.78 100.60 18.10 0.00 1636.80 1632.71 0.40 4.09 0.00 34.01 0.01 0.09 34.10 124 70 63 1.000 N/R 0.25 0.00 0.25 0.692 243.21 27365.58 0.51 8.60 3088.94 30455.03 0 10-Apr-15 20:30 323:44:25 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude 32 437.78 62 138.84 272.40 1597.14 100.60 22.54 0.00 1475.38 1468.00 0.40 7.38 0.00 30.58 0.01 0.15 30.74 124 70 63 1.000 N/R 0.50 0.00 0.50 0.692 270.26 27396.17 0.51 8.61 3089.10 30485.77 0 10-Apr-15 21:00 324:14:26 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude 32 439.00 61 137.79 274.38 1598.17 100.60 21.17 0.00 1486.61 1480.66 0.40 5.95 0.00 30.85 0.01 0.12 30.97 123 70 64 1.000 N/R 0.40 0.00 0.40 0.692 267.15 27427.01 0.51 8.62 3089.22 30516.74 0 10-Apr-15 21:30 324:44:26 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 438.85 61 140.64 282.27 1598.47 100.60 21.78 0.00 1520.30 1515.74 0.40 4.56 0.00 31.58 0.01 0.10 31.67 124 70 63 1.000 N/R 0.30 0.00 0.30 0.692 261.35 27458.59 0.51 8.63 3089.31 30548.41 0 10-Apr-15 22:00 325:14:26 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude. Corr API = 30.6. Water salinity 40000 ppm, pH=7. Gas SG 0.698 32 439.99 62 136.84 286.27 1598.91 100.60 21.86 0.00 1488.00 1484.28 0.40 3.72 0.00 30.92 0.01 0.08 31.00 124 69 63 1.000 0.873 30.6 40000 7 0.25 0.00 0.25 0.698 267.68 27489.51 0.51 8.63 3089.39 30579.41 0 10-Apr-15 22:30 325:44:26 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 439.23 62 138.55 285.12 1599.02 100.60 19.81 0.00 1488.00 1484.28 0.40 3.72 0.00 30.92 0.01 0.08 31.00 125 69 63 1.000 N/R 0.25 0.00 0.25 0.698 268.69 27520.44 0.51 8.64 3089.47 30610.41 0 10-Apr-15 23:00 326:14:26 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude 32 439.92 62 141.59 283.77 1599.66 100.60 19.62 0.00 1562.40 1556.15 0.39 6.25 0.00 32.42 0.01 0.13 32.55 124 69 63 1.000 N/R 0.40 0.00 0.40 0.698 253.75 27552.86 0.51 8.65 3089.60 30642.96 0 10-Apr-15 23:30 326:44:27 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 438.24 62 140.45 282.65 1599.30 100.60 20.22 0.00 1488.00 1484.28 0.40 3.72 0.00 30.92 0.01 0.08 31.00 124 69 63 1.000 N/R 0.25 0.00 0.25 0.698 266.35 27583.78 0.51 8.66 3089.68 30673.96 0 11-Apr-15 00:00 327:14:27 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 437.02 62 142.83 282.35 1600.21 100.60 30.96 0.00 1562.40 1558.49 0.40 3.91 0.00 32.47 0.01 0.08 32.55 125 69 63 1.000 N/R 0.25 0.00 0.25 0.698 254.17 27616.25 0.51 8.67 3089.76 30706.51 0 11-Apr-15 00:30 327:44:27 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 440.53 63 137.12 281.27 1600.66 100.60 21.29 0.00 1488.00 1483.54 0.39 4.46 0.00 30.91 0.01 0.09 31.00 124 69 63 1.000 N/R 0.30 0.00 0.30 0.698 266.07 27647.16 0.51 8.67 3089.85 30737.51 0 11-Apr-15 01:00 328:14:27 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude 32 443.88 62 139.50 276.82 1600.86 100.59 20.26 0.00 1562.40 1554.59 0.40 7.81 0.00 32.39 0.01 0.16 32.55 125 69 63 1.000 N/R 0.50 0.00 0.50 0.698 254.39 27679.54 0.51 8.68 3090.01 30770.06 0 11-Apr-15 01:30 328:44:27 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 445.25 62 139.12 291.71 1601.10 100.59 20.53 0.00 1562.40 1558.49 0.40 3.91 0.00 32.47 0.01 0.08 32.55 125 69 63 1.000 N/R 0.25 0.00 0.25 0.698 253.82 27712.01 0.51 8.69 3090.10 30802.61 0 11-Apr-15 02:00 329:14:28 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude. Corr API = 30.4. Water salinity 40000 ppm, pH=7. Gas SG 0.702 32 441.21 62 142.35 284.33 1600.96 100.59 25.54 0.00 1488.00 1484.28 0.40 3.72 0.00 30.92 0.01 0.08 31.00 125 69 63 1.000 0.874 30.4 40000 7 0.25 0.00 0.25 0.702 266.75 27742.93 0.51 8.70 3090.17 30833.61 0 11-Apr-15 02:30 329:44:28 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 439.38 62 143.40 283.47 1601.62 100.59 19.16 0.00 1636.80 1631.89 0.40 4.91 0.00 34.00 0.01 0.10 34.10 125 69 63 1.000 N/R 0.30 0.00 0.30 0.702 242.31 27776.93 0.51 8.71 3090.27 30867.71 0 11-Apr-15 03:00 330:14:28 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 442.89 61 142.45 277.08 1601.99 100.59 19.69 0.00 1636.80 1631.89 0.39 4.91 0.00 34.00 0.01 0.10 34.10 126 69 63 1.000 N/R 0.30 0.00 0.30 0.702 241.97 27810.93 0.51 8.72 3090.38 30901.81 0 11-Apr-15 03:30 330:44:28 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude 32 445.10 61 144.73 287.42 1601.75 100.59 7.13 0.00 1562.40 1554.59 0.39 7.81 0.00 32.39 0.01 0.16 32.55 125 70 63 1.000 N/R 0.50 0.00 0.50 0.702 253.80 27843.32 0.51 8.72 3090.54 30934.36 0 11-Apr-15 04:00 331:14:28 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 443.88 61 139.79 287.47 1602.43 100.59 12.71 0.00 1636.80 1631.89 0.39 4.91 0.00 34.00 0.01 0.10 34.10 126 70 63 1.000 N/R 0.30 0.00 0.30 0.702 242.01 27877.31 0.51 8.73 3090.64 30968.46 0 11-Apr-15 04:30 331:44:29 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 444.79 61 143.21 284.80 1602.63 100.59 41.62 0.00 1562.40 1559.28 0.40 3.12 0.00 32.48 0.01 0.07 32.55 125 69 63 1.000 N/R 0.20 0.00 0.20 0.702 254.81 27909.80 0.51 8.74 3090.71 31001.01 0 11-Apr-15 05:00 332:14:29 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 443.88 61 141.12 280.48 1602.91 100.59 18.25 0.00 1492.22 1489.24 0.40 2.98 0.00 31.03 0.01 0.06 31.09 125 68 63 1.000 N/R 0.20 0.00 0.20 0.702 267.24 27940.82 0.51 8.75 3090.77 31032.10 0 11-Apr-15 05:30 332:44:29 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 446.02 61 140.36 284.28 1603.13 100.59 26.44 0.00 1641.02 1637.74 0.40 3.28 0.00 34.12 0.01 0.07 34.19 125 67 63 1.000 N/R 0.20 0.00 0.20 0.702 243.86 27974.94 0.51 8.76 3090.84 31066.29 0 11-Apr-15 06:00 333:14:29 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude. Corr API = 30.1. Water salinity 40000 ppm, pH=7. Gas SG 0.696 32 446.79 61 139.62 284.52 1603.38 100.59 28.35 0.00 1488.00 1485.02 0.40 2.98 0.00 30.94 0.01 0.06 31.00 125 67 63 1.000 N/R 30.1 40000 7 0.20 0.00 0.20 0.702 269.79 28005.88 0.51 8.77 3090.90 31097.29 0 11-Apr-15 06:30 333:44:29 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 448.30 61 142.64 288.76 1603.49 100.59 17.30 0.00 1562.40 1559.28 0.40 3.12 0.00 32.48 0.01 0.07 32.55 126 68 63 1.000 N/R 0.20 0.00 0.20 0.696 255.21 28038.37 0.51 8.77 3090.97 31129.84 0 Expro Confidential 5/5/2015 Page 11 CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives 11-Apr-15 07:00 334:14:30 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 443.88 61 140.45 291.70 1603.71 100.59 18.44 0.00 1636.80 1633.53 0.40 3.27 0.00 34.03 0.01 0.07 34.10 127 68 63 1.000 N/R 0.20 0.00 0.20 0.696 243.76 28072.40 0.51 8.78 3091.03 31163.94 0 11-Apr-15 07:30 334:44:30 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 442.58 62 140.74 282.93 1603.87 100.59 16.62 0.00 1636.80 1633.53 0.40 3.27 0.00 34.03 0.01 0.07 34.10 127 69 63 1.000 N/R 0.20 0.00 0.20 0.696 243.35 28106.43 0.51 8.79 3091.10 31198.04 0 11-Apr-15 08:00 335:14:30 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 442.51 61 146.06 278.74 1604.08 100.59 45.95 0.00 1406.59 1403.07 0.40 3.52 0.00 29.23 0.01 0.07 29.30 127 68 63 1.000 N/R 0.25 0.00 0.25 0.696 284.11 28135.66 0.51 8.80 3091.17 31227.34 0 11-Apr-15 08:30 335:44:30 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 443.27 60 144.83 273.57 1604.17 100.59 0.00 0.00 1492.22 1488.49 0.40 3.73 0.00 31.01 0.01 0.08 31.09 126 69 63 1.000 N/R 0.25 0.00 0.25 0.696 266.58 28166.67 0.51 8.81 3091.25 31258.43 0 11-Apr-15 09:00 336:14:31 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 443.73 60 142.64 276.51 1604.29 100.59 16.66 0.00 1562.40 1559.28 0.40 3.12 0.00 32.48 0.01 0.07 32.55 127 69 63 1.000 N/R 0.20 0.00 0.20 0.696 255.45 28199.16 0.51 8.82 3091.32 31290.98 0 11-Apr-15 09:30 336:44:31 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 445.40 61 142.93 281.31 1604.75 100.59 9.79 0.00 1562.40 1557.71 0.40 4.69 0.00 32.45 0.01 0.10 32.55 128 69 63 1.000 N/R 0.30 0.00 0.30 0.696 256.53 28231.61 0.51 8.82 3091.42 31323.53 0 11-Apr-15 10:00 337:14:31 BS&W = .2%, .2%brine Tr Sed. 99.98% Crude. Corr API = 30.5. Water salinity 40000 ppm, pH=7. Gas SG 0.672 32 444.18 62 143.69 279.99 1604.76 100.59 16.73 0.00 1488.00 1485.02 0.40 2.98 0.00 30.94 0.01 0.06 31.00 127 70 63 1.000 0.873 30.5 40000 7 0.20 0.00 0.20 0.672 267.83 28262.55 0.51 8.83 3091.48 31354.53 0 11-Apr-15 10:30 337:44:31 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 443.73 61 139.88 284.35 1604.97 100.59 15.71 0.00 1562.40 1559.28 0.40 3.12 0.00 32.48 0.01 0.07 32.55 127 70 64 1.000 N/R 0.20 0.00 0.20 0.672 259.07 28295.03 0.51 8.84 3091.54 31387.08 0 11-Apr-15 11:00 338:14:31 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude 32 445.48 60 143.78 284.41 1604.69 100.59 15.52 0.00 1562.40 1556.15 0.41 6.25 0.00 32.42 0.01 0.13 32.55 128 70 64 1.000 N/R 0.40 0.00 0.40 0.672 260.33 28327.45 0.51 8.85 3091.67 31419.63 0 11-Apr-15 11:30 338:44:32 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 443.88 60 147.01 277.98 1605.17 100.59 17.19 0.00 1664.88 1661.55 0.41 3.33 0.00 34.62 0.01 0.07 34.69 129 70 63 1.000 N/R 0.20 0.00 0.20 0.672 244.77 28362.07 0.51 8.86 3091.74 31454.32 0 11-Apr-15 12:00 339:14:32 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 442.66 61 146.82 277.41 1605.23 100.59 0.00 0.00 1475.38 1470.95 0.41 4.43 0.00 30.64 0.01 0.09 30.74 128 70 64 1.000 N/R 0.30 0.00 0.30 0.672 275.45 28392.71 0.51 8.87 3091.83 31485.05 0 11-Apr-15 12:30 339:44:32 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 444.33 62 145.21 278.65 1605.04 100.59 14.80 0.00 1413.60 1410.77 0.41 2.83 0.00 29.39 0.01 0.06 29.45 128 70 64 1.000 N/R 0.20 0.00 0.20 0.672 287.53 28422.10 0.51 8.87 3091.89 31514.50 0 11-Apr-15 13:00 340:14:32 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 443.65 63 142.64 276.89 1605.67 100.59 14.34 0.00 1413.60 1409.36 0.41 4.24 0.00 29.36 0.01 0.09 29.45 130 69 63 1.000 N/R 0.30 0.00 0.30 0.672 290.38 28451.46 0.51 8.88 3091.98 31543.95 0 11-Apr-15 13:30 340:44:32 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude 32 445.86 62 144.83 289.02 1605.95 100.59 16.77 0.00 1488.00 1480.56 0.41 7.44 0.00 30.85 0.01 0.16 31.00 130 68 64 1.000 N/R 0.50 0.00 0.50 0.672 275.82 28482.31 0.51 8.89 3092.14 31574.95 0 11-Apr-15 14:00 341:14:33 BS&W = .5%, .5%brine Tr Sed. 99.5% Crude. Corr API = 30.3. Water salinity 40000 ppm, pH=7. Gas SG 0.678 32 444.94 61 146.25 280.81 1606.16 100.59 15.90 0.00 1413.60 1406.53 0.41 7.07 0.00 29.30 0.01 0.15 29.45 129 68 64 1.000 N/R 30.3 40000 7 0.50 0.00 0.50 0.678 289.00 28511.61 0.51 8.90 3092.28 31604.40 0 11-Apr-15 14:30 341:44:33 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 445.78 61 140.74 278.79 1606.14 100.59 34.26 0.00 1562.40 1557.71 0.41 4.69 0.00 32.45 0.01 0.10 32.55 129 67 64 1.000 N/R 0.30 0.00 0.30 0.678 261.07 28544.06 0.51 8.91 3092.38 31636.95 0 11-Apr-15 15:00 342:14:33 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 445.48 61 144.64 283.93 1606.23 100.59 29.41 0.00 1636.80 1633.53 0.40 3.27 0.00 34.03 0.01 0.07 34.10 128 68 63 1.000 N/R 0.20 0.00 0.20 0.678 246.92 28578.10 0.51 8.92 3092.45 31671.05 0 11-Apr-15 15:30 342:44:33 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 445.48 62 142.64 284.24 1606.34 100.59 29.29 0.00 1572.24 1569.10 0.40 3.14 0.00 32.69 0.01 0.07 32.76 127 68 63 1.000 N/R 0.20 0.00 0.20 0.678 256.94 28610.79 0.51 8.92 3092.51 31703.81 0 11-Apr-15 16:00 343:14:33 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 446.77 63 140.64 280.77 1606.47 100.59 47.88 0.00 1577.86 1574.70 0.40 3.16 0.00 32.81 0.01 0.07 32.87 128 68 63 1.000 N/R 0.20 0.00 0.20 0.678 256.76 28643.59 0.51 8.93 3092.58 31736.68 0 11-Apr-15 16:30 343:44:34 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 446.85 64 138.74 291.15 1606.72 100.59 43.80 0.00 1600.32 1595.52 0.40 4.80 0.00 33.24 0.01 0.10 33.34 126 68 64 1.000 N/R 0.30 0.00 0.30 0.678 251.48 28676.83 0.51 8.94 3092.68 31770.02 0 11-Apr-15 17:00 344:14:34 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 447.31 65 144.54 279.13 1606.97 100.59 20.30 0.00 1520.30 1517.26 0.41 3.04 0.00 31.61 0.01 0.06 31.67 128 68 64 1.000 N/R 0.20 0.00 0.20 0.678 267.17 28708.44 0.51 8.95 3092.74 31801.69 0 11-Apr-15 17:30 344:44:34 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 447.84 63 140.93 288.96 1606.85 100.59 25.30 0.00 1600.32 1597.12 0.41 3.20 0.00 33.27 0.01 0.07 33.34 129 69 64 1.000 N/R 0.20 0.00 0.20 0.678 253.63 28741.72 0.51 8.96 3092.81 31835.03 0 11-Apr-15 18:00 345:14:34 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude. Corr API = 30.2. Water salinity 40000 ppm, pH=7. Gas SG 0.674 32 449.36 65 145.11 278.37 1606.98 100.59 30.60 0.00 1840.37 1831.17 0.40 9.20 0.00 38.15 0.01 0.19 38.34 129 70 64 1.000 0.875 30.2 40000 7 0.50 0.00 0.50 0.674 220.95 28779.86 0.51 8.97 3093.00 31873.37 0 11-Apr-15 18:30 345:44:34 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 447.53 64 143.88 276.97 1606.93 100.58 23.78 0.00 1636.80 1632.71 0.41 4.09 0.00 34.01 0.01 0.09 34.10 128 70 63 1.000 N/R 0.25 0.00 0.25 0.674 248.16 28813.88 0.51 8.98 3093.09 31907.47 0 11-Apr-15 19:00 346:14:35 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 447.99 64 146.73 283.54 1606.95 100.59 20.56 0.00 1636.80 1631.89 0.41 4.91 0.00 34.00 0.01 0.10 34.10 129 70 63 1.000 N/R 0.30 0.00 0.30 0.674 248.59 28847.88 0.51 8.98 3093.19 31941.57 0 11-Apr-15 19:30 346:44:35 BS&W = .35%, .35%brine Tr Sed. 99.65% Crude 32 446.54 62 147.20 282.31 1607.21 100.59 17.57 0.00 1562.40 1556.93 0.41 5.47 0.00 32.44 0.01 0.11 32.55 129 69 63 1.000 N/R 0.35 0.00 0.35 0.674 260.19 28880.31 0.51 8.99 3093.30 31974.12 0 11-Apr-15 20:00 347:14:35 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 446.54 62 140.07 294.91 1607.22 100.58 18.73 0.00 1562.40 1557.71 0.41 4.69 0.00 32.45 0.01 0.10 32.55 130 70 63 1.000 N/R 0.30 0.00 0.30 0.674 261.38 28912.77 0.51 9.00 3093.40 32006.67 0 11-Apr-15 20:30 347:44:35 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude 32 444.79 64 146.44 283.45 1607.32 100.59 18.02 0.00 1562.40 1556.15 0.41 6.25 0.00 32.42 0.01 0.13 32.55 128 69 63 1.000 N/R 0.40 0.00 0.40 0.674 260.32 28945.19 0.51 9.01 3093.53 32039.22 0 11-Apr-15 21:00 348:14:35 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude 32 447.61 63 143.12 284.14 1607.44 100.59 15.80 0.00 1488.00 1482.05 0.40 5.95 0.00 30.88 0.01 0.12 31.00 128 70 63 1.000 N/R 0.40 0.00 0.40 0.674 272.27 28976.06 0.51 9.02 3093.66 32070.22 0 11-Apr-15 21:30 348:44:36 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude 32 446.77 63 142.07 281.04 1607.50 100.59 16.55 0.00 1641.02 1634.46 0.40 6.56 0.00 34.05 0.01 0.14 34.19 129 70 63 1.000 N/R 0.40 0.00 0.40 0.674 247.70 29010.14 0.51 9.03 3093.76 32104.41 0 11-Apr-15 22:00 349:14:36 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude. Corr API = 30.0. Water salinity 40000 ppm, pH=7. Gas SG 0.68 32 446.16 62 142.45 285.74 1607.53 100.58 17.00 0.00 1555.39 1549.17 0.40 6.22 0.00 32.27 0.01 0.13 32.40 129 70 63 1.000 0.876 30.0 40000 7 0.40 0.00 0.40 0.680 261.30 29042.42 0.51 9.03 3093.89 32136.82 0 11-Apr-15 22:30 349:44:36 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude 32 447.99 63 146.73 280.71 1607.73 100.58 17.94 0.00 1562.40 1556.15 0.41 6.25 0.00 32.42 0.01 0.13 32.55 131 69 63 1.000 N/R 0.40 0.00 0.40 0.680 262.18 29074.84 0.51 9.04 3094.02 32169.37 0 11-Apr-15 23:00 350:14:36 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 445.02 61 143.50 285.83 1607.73 100.58 16.70 0.00 1636.80 1631.89 0.41 4.91 0.00 34.00 0.01 0.10 34.10 132 68 63 1.000 N/R 0.30 0.00 0.30 0.680 252.05 29108.84 0.51 9.05 3094.12 32203.47 0 11-Apr-15 23:30 350:44:36 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 447.84 61 145.30 284.40 1607.79 100.58 16.52 0.00 1488.00 1485.02 0.40 2.98 0.00 30.94 0.01 0.06 31.00 129 69 63 1.000 N/R 0.20 0.00 0.20 0.680 271.57 29139.77 0.51 9.06 3094.19 32234.47 0 12-Apr-15 00:00 351:14:37 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 446.85 62 146.63 282.31 1607.87 100.58 16.37 0.00 1562.40 1558.49 0.40 3.91 0.00 32.47 0.01 0.08 32.55 128 69 63 1.000 N/R 0.25 0.00 0.25 0.680 258.26 29172.24 0.51 9.07 3094.27 32267.02 0 12-Apr-15 00:30 351:44:37 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 448.83 61 140.74 280.29 1607.95 100.58 18.36 0.00 1562.40 1558.49 0.40 3.91 0.00 32.47 0.01 0.08 32.55 129 69 63 1.000 N/R 0.25 0.00 0.25 0.680 258.76 29204.71 0.51 9.08 3094.35 32299.57 0 12-Apr-15 01:00 352:14:37 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude 32 448.45 62 143.02 291.58 1607.99 100.58 16.18 0.00 1636.80 1630.25 0.40 6.55 0.00 33.96 0.01 0.14 34.10 129 69 63 1.000 N/R 0.40 0.00 0.40 0.680 247.35 29238.67 0.51 9.09 3094.48 32333.67 0 12-Apr-15 01:30 352:44:37 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 447.76 63 143.31 289.22 1608.11 100.58 17.64 0.00 1480.99 1476.55 0.40 4.44 0.00 30.76 0.01 0.09 30.85 130 69 63 1.000 N/R 0.30 0.00 0.30 0.680 273.76 29269.44 0.51 9.09 3094.58 32364.52 0 12-Apr-15 02:00 353:14:37 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude. Corr API = 30.0. Water salinity 40000 ppm, pH=7. Gas SG 0.686 32 447.84 61 147.49 291.64 1608.15 100.58 16.82 0.00 1566.62 1561.92 0.40 4.70 0.00 32.54 0.01 0.10 32.64 129 69 63 1.000 0.876 30.0 40000 7 0.30 0.00 0.30 0.686 258.17 29301.98 0.51 9.10 3094.68 32397.16 0 12-Apr-15 02:30 353:44:38 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 447.53 61 148.44 274.85 1608.17 100.58 16.22 0.00 1488.00 1484.28 0.40 3.72 0.00 30.92 0.01 0.08 31.00 130 69 63 1.000 N/R 0.25 0.00 0.25 0.686 271.58 29332.90 0.51 9.11 3094.75 32428.16 0 12-Apr-15 03:00 354:14:38 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude 32 447.53 61 144.73 286.10 1608.32 100.58 18.36 0.00 1488.00 1482.05 0.40 5.95 0.00 30.88 0.01 0.12 31.00 129 69 63 1.000 N/R 0.40 0.00 0.40 0.686 270.95 29363.77 0.51 9.12 3094.88 32459.16 0 12-Apr-15 03:30 354:44:38 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 449.90 61 144.64 282.24 1608.31 100.58 16.40 0.00 1635.80 1631.71 0.40 4.09 0.00 33.99 0.01 0.09 34.08 130 69 63 1.000 N/R 0.25 0.00 0.25 0.686 246.51 29397.77 0.51 9.13 3094.96 32493.24 0 12-Apr-15 04:00 355:14:38 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 445.40 62 149.11 279.09 1608.42 100.58 16.14 0.00 1635.80 1630.89 0.40 4.91 0.00 33.98 0.01 0.10 34.08 130 70 63 1.000 N/R 0.30 0.00 0.30 0.686 246.95 29431.75 0.51 9.14 3095.06 32527.32 0 12-Apr-15 04:30 355:44:39 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude 32 447.61 61 143.88 286.58 1608.46 100.58 16.40 0.00 1636.80 1630.25 0.40 6.55 0.00 33.96 0.01 0.14 34.10 130 69 63 1.000 N/R 0.40 0.00 0.40 0.686 246.77 29465.71 0.51 9.14 3095.20 32561.42 0 12-Apr-15 05:00 356:14:39 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 446.77 61 145.11 280.07 1608.54 100.58 18.09 0.00 1636.80 1632.71 0.40 4.09 0.00 34.01 0.01 0.09 34.10 130 69 63 1.000 N/R 0.25 0.00 0.25 0.686 246.88 29499.72 0.51 9.15 3095.29 32595.52 0 12-Apr-15 05:30 356:44:39 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 445.63 62 144.73 282.24 1608.62 100.58 18.09 0.00 1509.07 1505.30 0.40 3.77 0.00 31.36 0.01 0.08 31.44 130 69 63 1.000 N/R 0.25 0.00 0.25 0.686 267.80 29531.08 0.51 9.16 3095.36 32626.96 0 12-Apr-15 06:00 357:14:39 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude. Corr API = 30.4. Water salinity 40000 ppm, pH=7. Gas SG 0.684 32 444.91 62 144.35 282.34 1608.70 100.58 18.62 0.00 1488.00 1484.28 0.40 3.72 0.00 30.92 0.01 0.08 31.00 131 69 63 1.000 N/R 30.4 40000 7 0.25 0.00 0.25 0.684 271.73 29562.01 0.51 9.17 3095.44 32657.96 0 12-Apr-15 06:30 357:44:39 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 446.92 62 144.54 278.75 1608.63 100.58 17.12 0.00 1488.00 1483.54 0.40 4.46 0.00 30.91 0.01 0.09 31.00 130 69 63 1.000 N/R 0.30 0.00 0.30 0.684 271.75 29592.91 0.51 9.18 3095.53 32688.96 0 12-Apr-15 07:00 358:14:40 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude 32 447.31 62 146.54 277.51 1608.66 100.58 16.82 0.00 1562.40 1558.49 0.40 3.91 0.00 32.47 0.01 0.08 32.55 130 69 63 1.000 N/R 0.25 0.00 0.25 0.684 258.52 29625.38 0.51 9.19 3095.62 32721.51 0 12-Apr-15 07:30 358:44:40 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 447.53 62 144.45 278.47 1608.74 100.58 16.59 0.00 1562.40 1559.28 0.40 3.12 0.00 32.48 0.01 0.07 32.55 131 69 63 1.000 N/R 0.20 0.00 0.20 0.684 259.60 29657.87 0.51 9.19 3095.68 32754.06 0 12-Apr-15 08:00 359:14:40 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 450.05 62 148.92 278.52 1608.81 100.58 16.48 0.00 1562.40 1559.28 0.41 3.12 0.00 32.48 0.01 0.07 32.55 131 68 63 1.000 N/R 0.20 0.00 0.20 0.684 259.82 29690.35 0.51 9.20 3095.75 32786.61 0 12-Apr-15 08:30 359:44:40 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 448.98 62 146.35 281.47 1609.02 100.58 18.13 0.00 1562.40 1559.28 0.40 3.12 0.00 32.48 0.01 0.07 32.55 131 69 63 1.000 N/R 0.20 0.00 0.20 0.684 259.25 29722.84 0.51 9.21 3095.81 32819.16 0 12-Apr-15 09:00 360:14:40 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 446.70 63 145.68 281.76 1608.94 100.58 16.40 0.00 1497.84 1494.84 0.40 3.00 0.00 31.14 0.01 0.06 31.21 131 69 63 1.000 N/R 0.20 0.00 0.20 0.684 270.06 29753.98 0.51 9.22 3095.87 32850.36 0 12-Apr-15 09:30 360:44:41 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 447.38 67 146.92 276.19 1608.85 100.58 17.00 0.00 1577.86 1574.70 0.40 3.16 0.00 32.81 0.01 0.07 32.87 131 70 63 1.000 N/R 0.20 0.00 0.20 0.684 256.04 29786.79 0.51 9.23 3095.94 32883.23 0 12-Apr-15 10:00 361:14:41 BS&W = .25%, .25%brine Tr Sed. 99.75% Crude. Corr API = 30.4. Water salinity 40000 ppm, pH=7. Gas SG 0.674 32 445.55 66 146.44 276.85 1608.71 100.58 18.02 0.00 1562.40 1558.49 0.40 3.91 0.00 32.47 0.01 0.08 32.55 131 69 63 1.000 N/R 0.25 0.00 0.25 0.674 258.83 29819.25 0.51 9.24 3096.02 32915.78 0 12-Apr-15 10:30 361:44:41 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude. **Begin pressuring annulus to cycle Select Tester 32 448.30 66 147.77 273.82 1608.99 100.58 17.53 0.00 1636.00 1632.73 0.41 3.27 0.00 34.02 0.01 0.07 34.08 130 70 63 1.000 N/R 0.20 0.00 0.20 0.674 248.50 29853.27 0.51 9.24 3096.09 32949.87 0 12-Apr-15 11:00 362:14:41 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude. **10:50hrs Bleed off annulus pressure. **Shut select Tester Valve 32 229.58 60 100.51 118.11 1631.31 100.37 23.27 0.00 1413.60 1410.77 0.39 2.83 0.00 29.39 0.01 0.06 29.45 126 67 63 1.000 N/R 0.20 0.00 0.20 0.674 279.03 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 11:30 362:44:41 11:03 Shut in at Expro choke. WHP at 200 psi. monitoring WHP.0 255.21 56 87.39 154.03 1638.54 100.07 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 65 62 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 12:00 363:14:42 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 265.70 52 85.30 176.29 1641.99 99.93 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 62 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 12:30 363:44:42 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 286.69 49 83.68 195.06 1644.59 99.81 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 58 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 13:00 364:14:42 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 310.34 46 83.59 215.51 1646.63 99.73 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 56 58 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 13:30 364:44:42 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 335.29 45 80.07 233.92 1648.38 99.69 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 84 56 58 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 14:00 365:14:42 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 344.79 46 79.97 248.33 1649.97 99.63 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 84 57 58 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 14:30 365:44:43 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 354.14 48 75.60 266.84 1651.42 99.58 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 84 57 58 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 15:00 366:14:43 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 356.43 48 81.11 261.70 1652.68 99.54 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 57 58 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 15:30 366:44:43 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 362.51 50 80.07 263.50 1654.03 99.49 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 53 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 16:00 367:14:43 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 365.48 50 76.93 277.76 1655.20 99.46 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 84 54 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 Expro Confidential 5/5/2015 Page 12 CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives 12-Apr-15 16:30 367:44:43 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 362.89 50 80.64 275.94 1656.35 99.42 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 52 56 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 17:00 368:14:44 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 362.36 50 78.07 278.13 1657.45 99.39 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 84 54 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 17:30 368:44:44 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 362.05 49 74.46 278.16 1658.51 99.36 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 54 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 18:00 369:14:44 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 363.80 50 79.88 263.51 1659.55 99.33 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 84 55 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 18:30 369:44:44 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 361.60 49 72.75 270.26 1660.54 99.31 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 84 57 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 19:00 370:14:44 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 363.73 49 74.65 277.41 1661.48 99.28 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 58 58 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 19:30 370:44:45 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 360.23 49 76.45 270.13 1662.43 99.26 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 59 58 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 20:00 371:14:45 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 363.50 49 76.93 274.94 1663.33 99.24 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 60 58 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 20:30 371:44:45 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 361.83 49 77.22 270.69 1664.19 99.22 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 61 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 21:00 372:14:45 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 359.32 50 77.12 266.26 1665.02 99.19 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 62 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 21:30 372:44:45 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 358.48 49 75.98 265.90 1665.84 99.17 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 63 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 22:00 373:14:46 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 360.46 50 76.84 269.19 1666.64 99.16 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 64 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 22:30 373:44:46 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 358.02 50 71.70 273.76 1667.42 99.14 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 64 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 23:00 374:14:46 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 358.48 49 71.41 272.35 1668.18 99.12 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 66 61 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 12-Apr-15 23:30 374:44:46 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 360.61 46 75.03 267.41 1668.94 99.10 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 68 61 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 00:00 375:14:46 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 359.32 44 70.94 278.48 1669.67 99.09 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 69 62 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 00:30 375:44:47 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 359.47 43 72.84 277.52 1670.39 99.08 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 71 62 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 01:00 376:14:47 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 356.50 44 76.36 274.56 1671.12 99.07 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 71 62 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 01:30 376:44:47 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 355.59 46 72.46 276.01 1671.83 99.04 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 70 62 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 02:00 377:14:47 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 358.63 44 75.50 275.42 1672.55 99.03 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 67 61 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 02:30 377:44:47 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 356.65 46 70.46 277.26 1673.25 99.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 67 61 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 03:00 378:14:48 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 358.17 47 69.99 270.38 1673.92 99.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 67 61 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 03:30 378:44:48 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 357.95 46 75.31 272.97 1674.60 99.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 67 62 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 04:00 379:14:48 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 355.13 46 75.31 266.19 1675.25 98.99 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 68 62 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 04:30 379:44:48 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 355.21 44 71.51 274.14 1675.90 98.98 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 68 62 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 05:00 380:14:48 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 353.84 43 73.41 274.31 1676.54 98.96 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 68 62 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 05:30 380:44:49 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 354.30 42 73.79 272.23 1677.18 98.95 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 68 63 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 06:00 381:14:49 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 353.31 42 72.27 276.39 1677.37 98.95 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 68 63 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 06:30 381:44:49 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 354.07 38 72.56 275.35 1678.41 98.94 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 68 63 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 07:00 382:14:49 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 354.60 38 72.46 266.02 1679.01 98.93 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 68 62 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 07:30 382:44:49 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 355.89 41 69.99 274.15 1679.62 98.92 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 65 62 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 08:00 383:14:49 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 355.67 42 69.42 270.20 1680.21 98.91 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 63 61 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 08:30 383:44:50 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 355.89 44 71.99 268.57 1680.79 98.91 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 60 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 09:00 384:14:50 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 353.00 46 75.31 274.10 1681.38 98.89 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 59 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 09:30 384:44:50 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 353.46 43 72.94 273.84 1681.95 98.88 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 84 63 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 10:00 385:14:50 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 352.78 42 73.79 262.81 1682.51 98.88 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 63 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 10:30 385:44:50 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 352.24 44 76.07 272.40 1683.09 98.87 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 89 59 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 11:00 386:14:51 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 353.23 44 75.88 263.35 1683.64 98.86 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 89 55 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 11:30 386:44:51 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 352.24 44 73.70 267.61 1684.21 98.86 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 56 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 12:00 387:14:51 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 354.68 43 71.13 268.86 1684.59 98.85 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 84 58 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 12:30 387:44:51 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 354.30 41 72.56 266.68 1685.32 98.84 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 84 60 58 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 13:00 388:14:51 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 352.02 41 76.55 266.83 1685.87 98.84 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 62 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 13:30 388:44:52 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 354.37 41 73.79 267.71 1686.41 98.83 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 63 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 14:00 389:14:52 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 354.83 41 77.12 263.44 1686.94 98.83 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 65 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 14:30 389:44:52 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 354.75 41 79.40 262.29 1687.48 98.81 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 67 61 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 15:00 390:14:52 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 355.36 43 75.22 263.08 1688.00 98.81 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 67 61 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 15:30 390:44:52 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.41 45 74.84 262.89 1688.52 98.80 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 66 61 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 16:00 391:14:53 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 352.55 45 75.31 272.41 1689.04 98.80 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 66 61 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 16:30 391:44:53 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 354.37 45 73.98 270.72 1689.56 98.79 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 90 62 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 17:00 392:14:53 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 353.31 43 77.69 272.29 1690.07 98.79 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 61 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 17:30 392:44:53 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.33 42 73.60 274.12 1690.58 98.78 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 63 61 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 18:00 393:14:53 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 354.60 46 77.22 263.15 1691.08 98.78 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 63 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 18:30 393:44:53 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.48 44 71.41 277.81 1691.58 98.77 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 63 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 19:00 394:14:54 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.25 40 75.69 267.88 1692.08 98.77 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 63 61 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 19:30 394:44:54 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.95 35 76.26 270.14 1692.56 98.76 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 89 61 60 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 20:00 395:14:54 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.33 34 72.75 264.80 1693.04 98.76 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 59 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 20:30 395:44:54 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 352.93 34 72.18 273.09 1693.52 98.75 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 59 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 21:00 396:14:54 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 352.17 31 71.89 273.00 1694.00 98.75 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 59 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 21:30 396:44:55 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.42 29 73.79 262.43 1694.47 98.73 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 59 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 22:00 397:14:55 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 352.24 27 70.08 268.02 1694.93 98.73 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 59 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 22:30 397:44:55 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.79 26 69.70 277.83 1695.39 98.73 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 59 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 23:00 398:14:55 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 348.75 26 72.84 267.15 1695.86 98.72 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 58 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 13-Apr-15 23:30 398:44:55 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 348.06 24 73.60 259.61 1696.31 98.72 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 57 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 00:00 399:14:56 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 348.59 27 68.18 265.97 1696.77 98.71 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 58 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 00:30 399:44:56 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 349.35 27 72.46 268.29 1697.21 98.71 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 57 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 01:00 400:14:56 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 352.85 27 68.09 275.86 1697.66 98.71 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 57 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 01:30 400:44:56 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.63 30 71.80 262.92 1698.10 98.70 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 56 58 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 Expro Confidential 5/5/2015 Page 13 CUSTOMER:TEST No: CUSTOMER REP:START DATE: EXPRO SUPERVISOR:END DATE: WELL NUMBER: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© Comments Ratio Methanol Time & Date Elapsed TimeChoke Size Manual ReadWHP @ the WellheadWHT @ SwabDown Stream ChokeDiff Press Across ChokeBottom Hole Pressure (Lower Gauge)Bottom Hole TemperatureAnnulus PressureNitrogen InjectionTotal FluidsOilGas @ Expro SeparatorWaterMud & SedimentOilGas @ Expro SeparatorWaterTotal Fluid IncrementPressure @ Meter Run Gas Temperature @ Meter RunOil Temperature @ Oil LegOriface Plate SizeOil Gravity Manual Read Oil Gravity Manual Read (Corrected)Water Gravity Manual ReadWater Salinity Manual ReadWater pH Manual ReadBS&W ShakeoutsSolids, Mud, EmulsionWater CutGas Gravity Ranarex Manual ReadCO2 Drager Manual ReadH²S Drager Manual ReadGOROilMudGas @ EXPRO SeparatorWater Calc. from SamplesTotal FluidDownhole Methanol Injection (dd-mmm-yy hh:mm)(hours)Initial WHP 125 psig Initial BHP 1955 psig (64ths)(psig)(F)(psi)(psig)(psig)(F)(psig)(scf/min)(stb/d)(stb/d)(MMscf/d)(stb/d)stb/d (stb)(MMscf)(stb)(stb)(psig)(F)(F)(inches)(SG60)(API60)(API60)(ppm)(pH)(%)(%)(%)(Air=1)(%)(ppm)(scfd/bbls)(stb)(stb)(MMscf)(stb)(stb)(gal/day) Time SeparatorVolumes (30 mins) David Ross 8:46 hrs 03:00 hrs Rates Repsol E&P USA Gas PropertiesFluid Properties BS&W Properties Roland Taylor Qugruk-301 CasingChoke 1 March 28, 2015 April 15, 2015 Cumulatives 14-Apr-15 02:00 401:14:56 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 348.82 31 69.04 266.24 1698.54 98.70 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 57 59 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 02:30 401:44:57 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.33 33 69.23 265.11 1698.96 98.70 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 89 53 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 03:00 402:14:57 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.87 36 68.47 273.03 1699.39 98.69 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 53 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 03:30 402:44:57 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.72 34 72.08 267.91 1699.83 98.69 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 53 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 04:00 403:14:57 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.86 37 67.33 274.36 1700.26 98.68 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 50 56 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 04:30 403:44:57 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.10 35 68.28 275.11 1700.68 98.68 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 51 56 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 05:00 404:14:57 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.18 35 69.51 267.09 1701.10 98.68 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 50 55 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 05:30 404:44:58 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.27 34 71.61 264.43 1701.52 98.67 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 48 55 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 06:00 405:14:58 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 346.92 34 67.99 273.13 1701.92 98.67 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 46 54 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 06:30 405:44:58 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 347.45 36 69.23 268.31 1702.33 98.67 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 44 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 07:00 406:14:58 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.57 37 65.52 268.25 1702.73 98.65 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 39 54 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 07:30 406:44:58 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.18 32 66.38 269.85 1703.13 98.65 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 82 40 53 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 08:00 407:14:59 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 348.90 33 70.27 261.05 1703.53 98.65 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 81 43 53 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 08:30 407:44:59 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.87 33 70.46 265.19 1703.93 98.65 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 82 45 53 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 09:00 408:14:59 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.49 38 69.61 267.56 1704.33 98.64 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 82 48 54 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 09:30 408:44:59 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.27 40 71.89 269.23 1704.71 98.64 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 82 50 55 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 10:00 409:14:59 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.34 37 69.32 274.44 1705.10 98.64 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 83 52 56 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 10:30 409:44:59 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 348.59 35 67.33 269.27 1705.48 98.63 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 50 55 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 11:00 410:14:00 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 347.38 33 70.01 238.53 1705.86 98.63 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 83 51 56 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 11:30 410:44:00 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 348.06 34 70.23 229.68 1706.24 98.63 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 82 54 56 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 12:00 411:14:00 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.48 39 70.46 222.05 1706.62 98.63 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 83 55 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 12:30 411:44:00 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 348.29 42 125.71 218.99 1706.99 98.62 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 83 56 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 13:00 412:14:00 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 348.82 48 71.89 267.91 1707.36 98.62 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 85 56 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 13:30 412:44:00 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 348.67 51 76.65 266.74 1707.73 98.62 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 56 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 14:00 413:14:00 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.48 52 75.88 259.77 1708.09 98.61 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 57 57 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 14:30 413:44:00 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.49 53 76.36 266.08 1708.46 98.61 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 53 55 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 15:00 414:14:00 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.57 54 78.45 261.35 1708.75 98.61 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 52 54 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 15:30 414:44:00 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.11 68 82.07 255.85 1709.17 98.61 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86 54 55 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 16:00 415:14:00 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 351.03 71 81.97 256.89 1709.53 98.60 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 52 55 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 0 14-Apr-15 16:30 415:44:00 Well shut-in downhole at Select Tester Valve. Choke Manifold shut. Monitoring WHP, BHP & BHT 0 350.72 59 87.77 257.31 1709.88 98.60 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 90 50 54 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 355 14-Apr-15 17:00 416:14:00 Start pressuring up annulus. 17:04hrs Select Tester Valve open. 17:07hrs. Open well through Expro separator on 16/64ths 16 347.53 52 85.96 256.48 1710.23 98.60 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 87 47 53 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.25 3096.15 32979.32 355 14-Apr-15 17:30 416:44:00 17:21hrs Fluid to surface. 1.000" orifice plate in service. Increase choke to 32/64ths adjustable 32 349.81 33 80.92 258.50 1695.43 100.02 1421.14 0.00 0.00 0.00 0.21 0.00 0.00 0.00 0.00 0.00 0.00 85 61 65 1.000 N/R 0.00 0.00 0.00 N/R 29882.66 0.51 9.26 3096.15 32979.32 355 14-Apr-15 18:00 417:14:00 BS&W = Trace Sediment. 100% Crude. Divert flow through 32/64ths fixed choke 32 463.84 36 117.25 313.21 1696.04 100.15 1506.98 0.00 1153.20 1153.20 0.18 0.00 0.00 24.03 0.00 0.00 24.03 93 66 64 1.000 N/R 0.00 0.00 0.00 153.83 29906.69 0.51 9.26 3096.15 33003.34 355 14-Apr-15 18:30 417:44:00 BS&W = Trace Brine. 100% Crude. Gas SG 0.646.32 479.60 45 164.61 291.10 1663.84 100.37 1633.53 0.00 1562.40 1562.40 0.47 0.00 0.00 32.55 0.01 0.00 32.55 111 66 62 1.000 N/R 0.00 0.00 0.00 0.646 302.52 29939.24 0.51 9.27 3096.15 33035.89 0 14-Apr-15 19:00 418:14:00 BS&W = Trace Sediment . 100% Crude. Corr API = 31.7. Sparge sandtrap. Recover trace of sand 32 474.88 51 161.28 298.20 1662.15 100.44 1745.94 0.00 1636.80 1636.80 0.48 0.00 0.00 34.10 0.01 0.00 34.10 131 68 64 1.000 N/R 31.7 0.00 0.00 0.00 0.646 294.44 29973.34 0.51 9.28 3096.15 33069.99 0 14-Apr-15 19:30 418:44:00 BS&W = .2%, .2%brine Tr Sed. 99.8% Crude 32 477.55 53 157.76 317.74 1659.03 100.47 1821.83 0.00 1636.80 1633.53 0.47 3.27 0.00 34.03 0.01 0.07 34.10 129 71 65 1.000 N/R 0.20 0.00 0.20 0.646 289.69 30007.37 0.51 9.29 3096.22 33104.09 0 14-Apr-15 20:00 419:14:00 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude 32 475.87 53 159.00 294.26 1658.40 100.50 1891.61 0.00 1711.20 1706.07 0.47 5.13 0.00 35.54 0.01 0.11 35.65 130 71 66 1.000 N/R 0.30 0.00 0.30 0.646 275.39 30042.91 0.51 9.30 3096.32 33139.74 0 14-Apr-15 20:30 419:44:00 BS&W = .4%, .4%brine Tr Sed. 99.6% Crude 32 476.71 55 162.42 299.70 1656.53 100.51 1939.02 0.00 1636.80 1630.25 0.47 6.55 0.00 33.96 0.01 0.14 34.10 129 74 68 1.000 N/R 0.40 0.00 0.40 0.646 286.75 30076.87 0.51 9.31 3096.46 33173.84 0 14-Apr-15 21:00 420:14:00 BS&W = .3%, .3%brine Tr Sed. 99.7% Crude. Sparge sandtrap. Recover trace of sand 32 475.11 55 159.76 292.18 1654.43 100.52 1982.60 0.00 1778.59 1773.26 0.47 5.34 0.00 36.94 0.01 0.11 37.05 129 75 67 1.000 N/R 0.30 0.00 0.30 0.646 262.77 30113.82 0.51 9.32 3096.57 33210.89 0 14-Apr-15 21:30 420:44:00 BS&W = .1%, .1%brine Tr Sed. 99.9% Crude 32 477.01 53 158.71 300.02 1652.99 100.52 2019.70 0.00 1572.24 1570.67 0.47 1.57 0.00 32.72 0.01 0.03 32.76 131 74 67 1.000 N/R 0.10 0.00 0.10 0.646 299.37 30146.54 0.51 9.33 3096.60 33243.65 0 14-Apr-15 22:00 421:14:00 BS&W = .1%, .1%brine Tr Sed. 99.9% Crude 32 475.57 54 154.24 298.83 1651.46 100.53 2062.54 0.00 1680.34 1678.66 0.47 1.68 0.00 34.97 0.01 0.04 35.01 130 74 67 1.000 N/R 0.10 0.00 0.10 0.646 277.43 30181.51 0.51 9.34 3096.64 33278.66 0 14-Apr-15 22:30 421:44:00 BS&W = Trace Brine. 100% Crude 32 473.81 53 155.86 289.86 1650.32 100.53 2092.94 0.00 1600.32 1600.32 0.46 0.00 0.00 33.34 0.01 0.00 33.34 129 75 67 1.000 N/R 0.00 0.00 0.00 0.646 289.55 30214.85 0.51 9.35 3096.64 33312.00 0 14-Apr-15 23:00 422:14:00 BS&W = Trace Sediment. 100% Crude. Corr API = 31.1 32 472.82 54 155.38 300.33 1649.04 100.54 2120.10 0.00 1562.40 1562.40 0.46 0.00 0.00 32.55 0.01 0.00 32.55 129 75 66 1.000 0.870 31.1 0.00 0.00 0.00 0.646 296.61 30247.40 0.51 9.36 3096.64 33344.55 0 14-Apr-15 23:30 422:44:00 BS&W = Trace Brine. 100% Crude 32 471.30 54 157.47 298.99 1648.07 100.54 2137.69 0.00 1562.40 1562.40 0.46 0.00 0.00 32.55 0.01 0.00 32.55 129 75 67 1.000 N/R 0.00 0.00 0.00 0.646 296.35 30279.95 0.51 9.37 3096.64 33377.10 0 15-Apr-15 00:00 423:14:00 BS&W = Trace Brine. 100% Crude 32 470.69 54 157.57 288.72 1647.02 100.54 2164.08 0.00 1562.40 1562.40 0.46 0.00 0.00 32.55 0.01 0.00 32.55 128 75 68 1.000 N/R 0.00 0.00 0.00 0.646 295.67 30312.50 0.51 9.38 3096.64 33409.65 0 15-Apr-15 00:30 423:44:00 BS&W = .1%, .1%brine Tr Sed. 99.9% Crude 32 472.98 54 156.33 290.33 1645.63 100.54 2189.33 0.00 1562.40 1560.84 0.46 1.56 0.00 32.52 0.01 0.03 32.55 129 75 67 1.000 N/R 0.10 0.00 0.10 0.646 296.18 30345.02 0.51 9.39 3096.67 33442.20 0 15-Apr-15 01:00 424:14:00 BS&W = .1%, .1%brine Tr Sed. 99.9% Crude. Sparge sandtrap. Recover 1 gallon frac sand (1:02hrs.)32 469.93 55 155.19 294.49 1645.12 100.54 2200.61 0.00 1636.80 1635.16 0.46 1.64 0.00 34.07 0.01 0.03 34.10 129 75 67 1.000 N/R 0.10 0.00 0.10 0.646 282.48 30379.08 0.51 9.40 3096.71 33476.30 0 15-Apr-15 01:30 424:44:00 BS&W = Trace Brine. 100% Crude. Shut-in at Expro's choke manifold (1:34). 1.00" orifice plate out of service (1:36). Monitor WHP 32 477.93 55 152.91 296.20 1643.87 100.54 2225.47 0.00 1711.20 1711.20 0.47 0.00 0.00 35.65 0.01 0.00 35.65 130 76 68 1.000 N/R 0.00 0.00 0.00 0.646 273.32 30414.73 0.51 9.41 3096.71 33511.95 0 15-Apr-15 02:00 425:14:00 Shut in at Wing Valve (2:04). END OF TEST 32 515.10 44 102.70 402.39 1685.40 100.29 2188.56 0.00 186.00 186.00 0.00 0.00 0.00 3.88 0.00 0.00 3.88 101 70 65 0.000 N/R 0.00 0.00 0.00 0.646 N/R 30418.61 0.51 9.41 3096.71 33515.82 0 15-Apr-15 02:30 425:44:00 Shut in Wing Valve. Choke Manifold shut. Monitoring WHP, BHP, BHT and Annulus Pressure 32 507.41 37 104.41 395.78 1689.79 100.05 2128.32 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 97 66 64 0.000 N/R 0.00 0.00 0.00 0.646 N/R 30418.61 0.51 9.41 3096.71 33515.82 0 15-Apr-15 03:00 426:14:00 Shut in Wing Valve. Choke Manifold shut. Monitoring WHP, BHP, BHT and Annulus Pressure 32 500.78 27 104.03 378.82 1692.82 99.88 2063.49 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 97 64 62 0.000 N/R 0.00 0.00 0.00 0.646 N/R 30418.61 0.51 9.41 3096.71 33515.82 0 Expro Confidential 5/5/2015 Page 14 0 20 40 60 80 100 120 140 160 0.00 250.00 500.00 750.00 1000.00 1250.00 1500.00 1750.00 2000.00 2250.00 2500.00 Well Head Temperature [F] and Choke Size [64ths] Pressure [psig] Date & Time WELL HEAD PLOT Qugruk-301 WHP Annulus Pressure WHT Choke Size CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© 0.00 50.00 100.00 150.00 200.00 250.00 300.00 0.00 500.00 1000.00 1500.00 2000.00 2500.00 3000.00 Temperature [F] Pressure [psig] Date & Time Bottom Hole Plot Qugruk-301 Bottom Hole Pressure Bottom Hole Temperature CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© 0 20 40 60 80 100 120 0 50 100 150 200 250 300 Temperature [F] Pressure [psig] Date & Time SEPARATOR PLOT Qugruk-301 Separator Pressure Separator Temperature CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© 0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 0.00 500.00 1000.00 1500.00 2000.00 2500.00 3000.00 3500.00 4000.00 4500.00 5000.00 Flow Rate [Mscf/d] Flow Rate [stb/d] Date & Time PRODUCTION PLOT Qugruk-301 Oil Rate Water Rate Total Liquid Rate Mud & Sediment rate Gas Rate CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© 0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 0.00 5000.00 10000.00 15000.00 20000.00 25000.00 30000.00 35000.00 40000.00 Cumulative Volume [Mscf/d) Cumulative Volume [Bbls] Date & Time CUMULATIVE PLOT Qugruk-301 Oil Cumulative Water Cumulative Total Liquid Mud Cumulative Gas Cumulative CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© COMPANY:Repsol E&P USA FIELD:Qugruk LEASE:Qugruk-301 Exploration Pad WELL#:Qugruk-301 A.F.E.#: CONFIDENTIAL in accordance with AS 38.05.035(a)(8)© DATE TIME OPERATIONS PERFORMED 28-Mar-15 8:45 Opened well to closed Expro choke 8:46 Initial pressure WHP 125psi BHP 1955psi I/A 0psi 9:00 Open well on 16/16ths adjustable choke to tanks 9:05 Coil tubing starts running in hole 9:07 Coil tubing starts pumping Nitrogen at 500scf/m 9:20 Gas gravity .962 9:30 Tank 2 strap 3" divert to tank 4 9:41 Increase choke to 18/64ths 10:00 Tank two strap 10:00 Start opening choke slowly to 32/64ths 10:01 Coke to 32/64ths 10:03 Divert flow through separator 10:08 Start shipping gas to flare 10:13 Nitrogen only at surface 10:30 Nitrogen only at surface 10:45 Start chemical injection 11:24 Fluid to choke 11:15 Coil Tubing continuing to 2000ft 11:28 Coil Tubing reach 2000ft 12:30 Coil Tubing continues in hole 12:41 Coil Tubing reaches 2500 ft. 12:58 Rock choke 13:00 Increased choke to 36/64ths 13:13 Increased Daniels plate to 2.00'' 13:25 Sparge sand trap (5 gallons of sand) 13:30 Increased choke to 38/64ths 13:42 Coil Tubing POOH 14:30 Increased choke to 48/64ths 14:30 Sparge sand trap (no sand) 14:51 Decrease Daniels plate to 1.500'' 15:00 Increased choke to 52/64ths 15:12 Sparge sand trap (no sand) 16:00 Rig up separate air supply line for methanol injection pump Sequence of Events STE CREW ON SITE Page 20 14:25 Drop heater bath thermostat to 120 degF 17:25 Nightshift arrives on location 17:30 Hold shift handover meeting 18:00 Day shift departs location 18:15 Hold pre-job safety meeting. Fill out TRAC for flowing well operations 18:30 Gas SG = 0.941 pH=8 Salinity = 44000 ppm 19:00 Sparge sand trap (no sand) 19:22 Start fluid transfer from Tank to Vac Truck 20:18 Complete fluid transfer 20:30 Request heaters for horizontal tank farm 20:40 Pump fluid back to tanks 21:00 Gas SG = 0.937 pH=8 Salinity = 44000 ppm 22:00 Received 3-heaters and stage at horizontal tanks 22:00 Conduct UT survey of identified critical points 22:30 Start fluid transfer from Tank 3 to Vac Truck 22:40 Complete fluid transfer from tank 3 to Vac Truck. Volume transferred= 150.26 bbls 23:00 Start fluid transfer from Tank 2 to Vac Truck 23:20 Complete fluid transfer from tank 2 to Vac Truck. Volume transferred= 116.27 bbls 23:40 Coil Tubing reach @ 3200 ft. 23:50 First Vac Truck depart location with water load. Volume transferred= 266.53 bbls 0:00 Gas SG = 0.916 pH=7 Salinity = 42000 ppm 1:00 Sparge Sandtrap ( no sand ) 1:30 Start fluid transfer from Tank 2 to Vac Truck 2:00 Complete fluid transfer from tank 2 to Vac Truck. Volume transferred= 127.98 bbls 2:03 Start fluid transfer from Tank 3 to Vac Truck 2:10 Complete fluid transfer from tank 3 to Vac Truck. Volume transferred= 39.4 bbls 2:53 Start fluid transfer from Tank 4 to Vac Truck 2:57 Complete fluid transfer from tank 4 to Vac Truck. Volume transferred= 51.26 bbls 3:00 Gas SG = 0.930 pH=7 Salinity = 42000 ppm 3:20 Second Vac Truck depart location with water load. Volume transferred= 218.64 bbls 4:30 Obs. API 26 @ 65F. Corrected API 25.7 @60F 5:00 Rock choke 5:30 Day shift arrives on location 5:35 Hold shift handover meeting with day crew. Discuss current operation 6:00 Night shift departs location 6:15 Hold pre-job safety meeting. Review RA for flowing well, BS&W Measurement and Fluid Transfers 7:27 Sparge Sand Trap 8:00 Dropped methanol injection rate from 355gpd to 148gpd 8:30 Sparge separator 9:00 Decreased choke to 48/64ths 9:00 Corrected API 30.3@ 60F Gas Gravity .942 9:20 Decreased choke to 40/64ths 9:58 Rock choke 10:02 Decreased choke 36/64ths 10:32 Coil comes off line with N2 Jamon Sandoval Adam Carpenter Dave Poulin Vince Madrid Mike Pannone Roland Taylor Frank Tower Travis Stone Sharon Oyao Adam Nelson John Croffut Page 21 10:57 Put 0.875" orifice plate in service 12:00 Increased choke to 40/64ths 12:40 Rock choke 13:15 Sparge Sand trap. Recovered @ 2 gallons of sand 13:16 Corrected API= 28 @ 60degF 13:28 1.5" Plate in service 13:34 Increased choke to 48/64ths 14:03 Increased choke to 52/64ths 14:09 Increased choke to 56/64ths 14:22 Sparge sand trap. Recovered @ 10 gallons of sand 14:25 Decreased choke to 52/64ths 14:43 Sparge sand trap. Recovered @ 1 gallon of sand 15:00 Water Salinity= 39000ppm, pH=7 15:05 Sparge sand trap. Recovered trace of sand 15:20 Start UT on inlet ( thickness test ) 15:30 Gas Gravity .736 15:36 Increase choke to 56/64ths 15:40 Begin pumping emulsion breaker and defoamer at choke 15:42 Sparge sand trap. Recovered @ 1 gallons of sand 16:10 Sparge sand trap. Recovered no sand 16:14 Increase choke to 60/64ths 17:00 Start pulling bottom off of tank 1 to vac truck 17:08 Complete pulling bottom off of tank 1 to vac truck 17:10 Start pulling bottom off of tank 4 to vac truck 17:16 Complete pulling bottom off of tank 4 to vac truck 18:00 Gas Gravity .734 18:00 Corrected API= 29.3 @ 60degF 18:01 Water Salinity= 40000ppm, pH=7 18:27 Nightshift arrives on location 18:30 Divert tanks every 15 minutes time for tank space 18:37 Decrease choke to 44/64ths 18:40 Vac Truck load depart location 18:50 Sparge sand trap. Recovered @ 10 gallons of sand 19:20 Start pulling bottom off of tank 2 to storage horizontal tank 5 20:18 Complete pulling bottom off of tank 2 to storage horizontal tank 5. Tank 5 =89" = 397 bbls. 20:25 Start pulling bottom off of tank 2 and tank 4 to storage horizontal tank 6 20:30 Increased choke to 60/64ths 20:56 Shut-in transfer pump. No flow on tank 2, open tank 4 21:00 Water Salinity= 38000ppm, pH=7 21:00 Gas Gravity .711 21:00 0 H2S / 0 CO2 21:50 Sparge Sandtrap. Recovered @ 1 gallons of sand 22:10 Pumping emulsion breaker @ 7 gpd 23:00 Sparge sand trap. Recovered @ 2 gallons of Frac sand 23:30 Sparge sand trap. Recovered @ 0.5 gallon of Frac sand Travis Stone Sharon Oyao Adam Nelson Frank Tower John Croffut Page 22 23:32 Start pulling bottom off of tank 3 to vac truck #86097 30-Mar-15 0:00 Water Salinity= 38000ppm, pH=7 0:00 Gas Gravity .704 0:00 Obs. API 30.8 @ 74F. Corrected API 29.8 @60F 0:00 Sparge Sandtrap. Recovered @ 1 gallons of Frac sand 0:20 Increase Downhole methanol injection to 320 gpd 0:25 Sparge sand trap. Recovered @ 3 gallon of Frac sand 0:25 Complete pulling bottom off of tank 3 to vac truck #86077. Vac 132.53 bbls. 0:27 Start pulling bottom off of tank 1 to vac truck #86097 0:45 Complete pulling bottom off of tank 1 to vac truck #86077. Vac 60.85 bbls. 1:00 Start fluid transfer of tank 3 to vac truck #86097 1:30 Complete fluid transfer of tank 3 to vac truck #86097 1:50 Start fluid transfer from tank 3 to tank 6 (oil) 1:52 Sparge Sandtrap. Recovered @ 1 gallons of Frac sand 2:27 Complete fluid transfer from tank 3 to tank 6 (oil) 2:30 Vac Trucks #86097 and #86077 depart location 3:00 Water Salinity= 38000ppm, pH=7 3:00 Gas Gravity .731 3:05 Start fluid transfer from tank 1 & tank 4 to Tank 8 3:10 2-Vac Truck arrive on location 3:34 Start fluid transfer of water from tank 5 to Vac Truck #86100 3:53 Sparge Separator. Recovered 25 gallons of Frac sand 4:45 Sparge Sandtrap. Recovered @ 1 gallons of Frac sand 5:19 Sparge Sandtrap. Recovered @ 0.5gallons of Frac sand 5:30 Obs. API 30.9 @ 74F. Corrected API 29.8 @60F 5:30 Day shift arrives on location 5:35 Hold shift handover meeting with day crew. Discuss current operation 6:00 Night shift departs location 6:05 Hold pre-job safety meeting. Review RA for flowing well, BS&W Measurement and Fluid Transfers 6:10 Gas Gravity .698 6:25 Sparge Sandtrap. Recovered @ 1 gallon of Frac Sand 7:00 Sparge Sandtrap. Recovered @ 2 gallon of Frac Sand 8:00 Sparge Sandtrap. Recovered @ 2 gallon of Frac Sand 8:50 Obs. API 28.5 @ 65F. Corrected API 28.2 @60F 8:52 Gas Gravity .698 8:55 Water Salinity= 38000ppm, pH=7 9:00 Sparge Sandtrap. Recovered @ 2 gallon of Frac Sand 10:00 Sparge Sandtrap. Recovered @ 2 gallon of Frac Sand 10:20 Sparge Separator. Recovered 0 gallons of Frac sand 11:00 Sparge Sandtrap. Recovered @ 2 gallon of Frac Sand 12:00 Sparge Sandtrap. Recovered @ 2 gallon of Frac Sand 12:05 Obs. API 30 @ 75F. Corrected API 28.9 @60F 12:06 Water Salinity= 38000ppm, pH=7 12:07 0ppm H2S / 0% CO2 13:00 Sparge Sandtrap. Recovered @ 2 gallon of Frac Sand Dave Poulin Vince Madrid Mike Pannone Roland Taylor Jamon Sandoval Adam Carpenter Page 23 14:00 Sparge Sandtrap. Recovered @ 1 gallon of Frac Sand 15:00 Sparge Sandtrap. Recovered @ 1 gallon of Frac Sand 15:05 Obs. API 29.3 @ 72F. Corrected API 28.5 @60F 15:06 Water Salinity= 39000ppm, pH=7 15:07 0ppm H2S / 0% CO2 15:07 Gas Gravity .690 16:00 Sparge Sandtrap. Recovered @ 1 gallon of Frac Sand 17:00 Sparge Sandtrap. Recovered @ 1 gallon of Frac Sand 17:25 Nightshift arrives on location 17:30 Hold shift handover meeting 18:00 Obs. API 29 @ 68F. Corrected API 28.5 @60F 18:00 Water Salinity= 34000ppm, pH=7 18:00 Gas Gravity .691 18:15 Sparge Sandtrap. Recovered @ 1 gallon of Frac Sand 18:30 Day shift departs location 18:45 Hold pre-job safety meeting. Fill out TRAC for flowing well operations 19:00 Sparge Sandtrap. Recovered @ 1 gallon of Frac Sand 20:05 Sparge Sandtrap. Recovered @ 1 gallon of Frac Sand 21:00 LRS arrive on location to blow down separator sparge line 21:00 Water Salinity= 32000ppm, pH=7 22:00 Weather check: Phase II 22:30 Decreased choke to 30/64ths 22:30 Obs. API 28.6 @ 58F. Corrected API 28.7 @60F 22:38 Decreased choke to 24/64ths. For tank space and Phase II weather condition 23:09 Sparge Sandtrap. Recovered @ 1 gallon of Frac Sand 23:20 Increased choke to 28/64ths 23:52 Increased choke to 32/64ths 31-Mar-15 0:00 Gas Gravity .709 0:10 Increased choke to 34/64ths 0:20 Decreased choke to 32/64ths 0:15 LRS complete to blow down separator sparge line to clear ice plug. Recovered 25 gal Frac sand 0:30 LRS depart location to Q8 0:30 Rock choke to maintain flow rates 1:00 Sparge Separator Vessel 1:00 Rock choke to maintain flow rates 2:35 Rock choke 3:00 Obs. API 29 @ 70F. Corrected API 28.1@60F 3:00 Gas Gravity .711 3:00 Water Salinity= 40000ppm, pH=7 4:05 Rock choke 4:15 Sparge Separator Vessel 5:00 Rock choke 5:30 Rock choke 5:30 Sparge sandtrap 6:00 Water Salinity= 38000ppm, pH=7 Travis Stone Sharon Oyao Adam Nelson Frank Tower John Croffut Page 24 6:00 Gas Gravity .712 6:00 Obs. API 29 @ 70F. Corrected API 28.3 @60F 6:00 Day shift arrives on location 6:10 Hold shift handover meeting with day crew. Discuss current operation 6:30 Night shift departs location 6:35 Hold pre-job safety meeting. Fill out TRAC/JSA for flowing well 7:00 Sparge Sandtrap. Recovered @ .5 gallon of Frac Sand 8:00 Sparge Sandtrap. Recovered @ 0 gallons of Frac Sand 8:30 Rock choke 8:40 1.00 inch orifice plate in service. 1.500 inch orifice plate removed 8:55 Obs. API 29 @ 70F. Corrected API 28.1 @60F 8:56 Gas Gravity .706 8:57 Water Salinity= 40000ppm, pH=7 9:00 Rock choke 9:05 Sparge Sandtrap. Recovered @ 0 gallons of Frac Sand 10:00 Sparge Sandtrap. Recovered @ 0 gallons of Frac Sand 10:01 Rock choke 11:00 Sparge Sandtrap. Recovered @ 0 gallons of Frac Sand 11:03 Rock choke 12:00 Sparge Sandtrap. Recovered @ 0 gallons of Frac Sand 12:01 Obs. API 30 @ 70F. Corrected API 29.3 @60F 12:03 Gas Gravity .706 12:05 Water Salinity= 40000ppm, pH=7 13:00 Increase Downhole methanol injection to 320 gpd 13:59 Shut in surface chemical injection 14:00 Shut well in. Shut in scheduled to allow storage tanks to be evacuated. 14:05 Continue Transferring fluid from storage tanks 14:30 Begin snow removal and repairs to tank farm hooch 19:15 Nightshift arrives on location. Convoy with loader due to Phase III road condition 19:20 Hold shift handover meeting 19:30 Day shift departs location. Convoy with loader due to Phase III road condition 20:00 Hold pre-job safety meeting. Fill out TRAC for snow removal 20:15 Conduct snow removal around well test area 23:00 Contact loader to scrape snow in front of main berm 0:45 Continue snow removal well test area 1-Apr-15 1:00 Start pumping out Frac sand and water out of Sparge tank to Cusco vac truck #90027 3:15 Complete pumping out sand and water. Recovered 5% sand, 64% oil & 31% crude 1:50 3-Vac Trucks arrive on location. Vac Truck # 86077 / #86101 and #86086 2:00 Start pumping fluid out of tank 1 to tank 4 3:00 Start pumping fluid out of and tanks 8 and tank 9 4:00 Complete pumping all fluid out of tanks 1 to 4 and tanks 8 & 9 4:00 Tank 8 = 44" = 183 bbls and tank 9 = 33.5" = 132 bbls 4:30 3-Vac Trucks depart location. Vac Truck # 86077 / #86101 and #86086 4:45 Verify choke at 32/64ths on positive side 5:00 Verify orifice plate out of service Jamon Sandoval Adam Carpenter Dave Poulin Vince Madrid Roland Taylor Mike Pannone John Croffut Sharon Oyao Frank Tower Adam Nelson Travis Stone Page 25 6:00 Day shift arrives on location 6:10 Hold shift handover meeting with day crew. Discuss current operation 6:30 Night shift departs location 6:35 Hold pre-job safety meeting. Fill out TRAC/JSA for Fluid transfers/ Snow Removal 7:00 Begin snow removal from around flare line 8:00 Nabors, CH2MHILL and Cruze personnel on site and starts assisting Expro with snow removal 10:30 Complete snow removal from flare line 10:45 Begin snow removal from main berm 12:25 Vac truck arrives on location and backs in to pull load from horizontal tanks 16:40 Complete removing snow from main berm 16:55 Install 16/64ths positive choke in choke manifold 17:00 Align valves to flow to tank #2 17:05 Light igniter pilot 17:30 Nightshift arrives on location. Convoy with loader due to Phase III road condition 17:45 Entire crew attends pre-flow meeting with Repsol, Halliburton, Nabors and Vac Truck crew 18:10 Conduct walk-around inspection with Repsol and Halliburton at Q-301 pad prior to open the well 18:30 Pre-test safety systems prior to open well 18:35 Hold shift handover meeting 18:50 Day shift departs location. Convoy with loader due to Phase III road condition 18:50 Verify align valves to flow to tank #2 19:00 Opened well to Expro choke. Choke at 16/64ths positive 19:00 Start pumping methanol downhole injection @ 120 gal/day 19:12 Switch choke to 16/64ths fixed choke 19:20 1.000" orifice plate in service 20:15 1.000" orifice plate out of service 20:19 0.750" orifice plate in service 21:00 Obs. API 31.4 @ 64F. Corrected API 29.3 @60F 21:36 2-Vac Truck arrive on location. Vac Truck #86101 and #86077 21:45 Start pumping out of tank 7 to Vac Truck #86077 and tank 10 to Vac Truck #86101 22:00 Water Salinity= 40000ppm, pH=7 22:25 0.750" orifice plate out of service 22:25 0.500" orifice plate in service 22:45 Complete pumping out of tank 7 to Vac Truck #86077 23:00 Gas Gravity .706 23:00 Complete pumping out of tank 10 to Vac Truck #86101 23:05 Vac Truck #86077 depart location 23:20 Vac Truck #86101 depart location 3:00 Obs. API 30.8 @ 64F. Corrected API 30.5 @60F 2-Apr-15 3:05 2-Vac Truck arrive on location. Vac Truck #86100 and #86097 3:30 Start pumping out of tank 5 to Vac Truck #86100 3:40 Start pumping out of tank 10 to Vac Truck #86097 4:05 Complete pumping out of tank 5. Begin pumping tank 6 to Vac Truck #86100. Tank 5 = 8.3 bbls 4:20 Complete pumping out of tank 6. Begin pumping tank 13. Tank 6 = 34 bbls 4:44 Complete pumping out of tank 13. Begin pumping tank 12. Tank 13 = 13 bbls 4:54 Complete pumping out of tank 12. Begin pumping tank 11. Tank 12 = 13 bbls Dave Poulin Vince Madrid Mike Pannone Roland Taylor Jamon Sandoval Adam Carpenter Travis Stone Sharon Oyao Adam Nelson Frank Tower John Croffut Page 26 5:15 Complete pumping out of tank 11. Begin pumping tank 10. Tank 11 = 5 bbls. 5:31 Complete pumping out of tank 10. Vac Truck #86097 reach max capacity 5:30 Day shift arrives on location 5:40 Hold shift handover meeting with day crew. Discuss current operation 5:55 Night shift departs location 6:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 6:15 Complete pumping out of tank 8. Begin pumping tank 9. Tank 8 = 8.3 bbls 6:35 Complete pumping out of tank 9. Tank 9 = 13 bbls 8:50 Obs. API 29.9 @ 69F. Corrected API 29.3 @60F 8:55 Water Salinity= 40000ppm, pH=7 9:00 Gas Gravity .688 9:05 H2S = 0 ppm / CO2 = 0% 13:13 Begin function test of safety system 13:15 Test pull station at save 13:20 Test pull station at choke 13:30 Test pull station at heater 13:35 Test pull station at separator 13:40 Test pull station at tank farm 13:35 Test pull station at flare 14:00 Compete Safety system function test 14:25 Obs. API 30.7 @ 71F. Corrected API 29.9 @60F 14:26 Water Salinity= 40000ppm, pH=7 14:28 Gas Gravity .691 14:30 H2S = 0 ppm / CO2 = 0% 15:00 Continue flowing well on 16/64ths. positive choke 17:30 Nightshift arrives on location. 17:45 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 18:00 Day shift departs location. 19:00 Water Salinity= 44000ppm, pH=7 19:30 Obs. API 30.2 @ 64F. Corrected API 29.9 @60F 19:30 Gas Gravity 0.686 21:05 Start pumping out of tank 2 to Vac Truck #86086 22:00 Slowly increase choke to 32/64ths 22:00 0.500" orifice plate out of service 22:00 Water Salinity= 42000ppm, pH=7 22:12 Increase choke to 32/64ths fixed choke 22:25 1.500" orifice plate in service 22:30 Complete pumping out of tank 2 to Vac Truck 86086. Tank 2 = 1" = 1.55 bbls 22:30 Obs. API 30 @ 58F. Corrected API 30.1 @60F 22:30 Gas Gravity 0.688 22:37 Start pumping out of tank 1 to Vac Truck #86077 23:00 1.250" orifice plate in service 23:10 1.250" orifice plate out of service 23:12 1.000" orifice plate in service 23:50 Complete pumping out of tank 1 to Vac Truck 86077. Tank 1 = 1" = 1.55 bbls Adam Nelson Frank Tower John Croffut Travis Stone Sharon Oyao Roland Taylor Jamon Sandoval Adam Carpenter Dave Poulin Vince Madrid Mike Pannone Page 27 3-Apr-15 0:18 Vac Truck 86077 depart location 1:00 Water Salinity= 42000ppm, pH=7 1:30 Start pumping out of tank 4 to Vac Truck #86101 1:30 Obs. API 29.8 @ 68F. Corrected API 29.3 @60F 1:40 Complete pumping out of tank 4. Start pumping tank 3 to Vac Truck 86101. Tank 4 = 1.55 bbls 2:20 Complete pumping out of tank 3. Tank 3 = 4.65 bbls 4:00 Water Salinity= 42000ppm, pH=7 4:30 Gas Gravity 0.714 4:30 Obs. API 29.6 @ 68F. Corrected API 29.1 @60F 4:45 Start pumping out of tank 2 to Vac Truck #86097 5:30 Complete pumping out of tank 2 to Vac Truck 86097. Tank 2 = 1.55 bbls 5:30 Day shift arrives on location 5:40 Hold shift handover meeting with day crew. Discuss current operation 5:55 Night shift departs location 6:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 6:01 Complete pumping out of tank 1 to Vac Truck 86097. Tank 1 = 77.5 bbls 6:15 Begin pumping out of tank 1 to Vac Truck 86100 6:35 Complete pumping out of tank 1 to Vac Truck 86100. Tank 3.1 bbls 7:00 Obs. API 30.1 @ 71F. Corrected API 29.3 @60F 7:05 Gas Gravity 0.682 8:30 Water Salinity= 38000ppm, pH=7 9:21 Begin pumping out of tank 4 to Vac Truck 86100 9:30 Start UT survey on inlet ( thickness check ) 9:55 Complete pumping out of tank 4 to Vac Truck 86100. Tank 4 = 3.1 bbls 10:11 Begin pumping out of tank 3 to Vac Truck 86086 11:01 Complete pumping out of tank 3 to Vac Truck 86086. Tank 3 = 3.1 bbls 11:30 Water salinity 40000 ppm, pH=7 14:16 Begin pumping out of tank 1 to Vac Truck 86086 14:31 Complete pumping out of tank 1 to Vac Truck 86086. Tank 1 = 128.27 bbls 14:40 Begin function test of safety system 14:45 Test pull station at save 14:50 Test pull station at choke 14:52 Begin pumping out of tank 1 to Vac Truck 86077 14:55 Test pull station at heater 15:00 Test pull station at separator 15:05 Test pull station at tank farm 15:10 Test pull station at flare 15:30 Complete pumping out of tank 1 to Vac Truck 86077. Tank 1 = 3.10 bbls 15:31 Begin pumping out of tank 2 to Vac Truck 86077 15:55 Complete pumping out of tank 2 to Vac Truck 86077. Tank 2 = 74.40 bbls 16:12 Begin pumping out of tank 2 to Vac Truck 86101 16:35 Complete pumping out of tank 2 to Vac Truck 86101. Tank 2 = 2.3 bbls 17:00 Obs. API 30 @ 80F. Corrected API 28.6 @60F 17:01 Gas Gravity 0.691 17:30 Nightshift arrives on location. Travis Stone Roland Taylor Jamon Sandoval Adam Carpenter Dave Poulin Vince Madrid Mike Pannone Page 28 17:45 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 18:00 Day shift departs location. 18:10 Halliburton personnel at Separator unit to take PVT samples 18:20 Starts rig up sample ports at separator in oil leg and gas leg 19:30 Begin pumping out of tank 3 and tank 4 to Vac Truck 86101 19:35 Halliburton personnel starts taking 1st PVT samples at separator oil and gas legs 19:45 Complete pumping out of tank 3 to Vac Truck 86101. Tank 3= 51.2 bbls 19:45 Complete pumping out of tank 4 to Vac Truck 86101. Tank 4= 60.4 bbls 20:00 Obs. API 29 @ 66F. Corrected API 28.6 @60F 20:00 Gas Gravity 0.688 20:30 Halliburton personnel complete taking 1st PVT sample at separator oil and gas legs 20:30 Water salinity 40000 ppm, pH=7 20:40 Halliburton personnel starts taking 2nd PVT sample at separator oil and gas legs 21:13 Halliburton personnel complete taking 2nd PVT sample at separator oil and gas legs 21:34 Halliburton personnel starts taking 3rd PVT sample at separator oil and gas legs 21:52 Begin pumping out of tank 1 to Vac Truck #86097 22:23 Halliburton personnel complete taking 3rd PVT sample at separator oil and gas legs 22:25 Complete pumping out of tank 1 to Vac Truck #86097. Tank 1 = 3.1 bbls 22:27 Begin pumping out of tank 2 to Vac Truck #86097 22:45 Halliburton personnel starts taking 4th PVT sample at separator oil and gas legs 23:00 Obs. API 29.4 @ 68F. Corrected API 28.8 @60F 23:00 Gas Gravity 0.690 23:05 Complete pumping out of tank 2 to Vac Truck #86097. Tank 2 = 17.1 bbls 23:10 Halliburton personnel complete taking 4th PVT sample at separator oil and gas legs 23:30 Water salinity 40000 ppm, pH=7 23:38 Halliburton personnel starts taking 5th PVT sample at separator oil and gas legs 4-Apr-15 0:00 Halliburton personnel complete taking 5th PVT sample at separator oil and gas legs 0:05 Begin pumping out of tank 3 to Vac Truck #86100 0:22 Halliburton personnel starts taking 6th PVT sample at separator oil and gas legs 0:36 Complete pumping out of tank 3 to Vac Truck #86100. Tank 3 = 3.1 bbls 0:37 Begin pumping out of tank 4 to Vac Truck #86100 1:05 Halliburton personnel complete taking 6th PVT sample at separator oil and gas legs 1:10 Complete pumping out of tank 4 to Vac Truck #86100. Tank 4 = 3.1 bbls 2:00 Obs. API 29.2 @ 70F. Corrected API 28.5 @60F 2:30 Conduct UT survey on pipe (thickness test) 3:00 Water salinity 38000 ppm, pH=7 3:40 Begin pumping out of tank 2 to Vac Truck #86077 4:15 Complete pumping out of tank 2 to Vac Truck #86077. Tank 2 = bbls 4:16 Begin pumping out of tank 1 to Vac Truck #86077 4:40 Complete pumping out of tank 1 to Vac Truck #86077. Tank 1 = bbls 5:00 Obs. API 29.2 @ 68F. Corrected API 28.7 @60F 5:30 Water salinity 40000 ppm, pH=7 5:30 Gas Gravity 0.686 5:30 Day shift arrives on location 5:40 Hold shift handover meeting with day crew. Discuss current operation Roland Taylor Jamon Sandoval Sharon Oyao Adam Nelson Frank Tower John Croffut Page 29 5:55 Night shift departs location 6:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 7:55 Roland T. Attends OPS meeting 8:00 Obs. API 30 @ 76F. Corrected API 28.7 @60F. Gas SG .689 8:05 Water salinity 40000 ppm, pH=7 9:55 Begin pumping out of tank 3 to Vac Truck #86086 10:50 Complete pumping out of tank 1 to Vac Truck #86086. Tank 3 = 3.10 bbls 10:57 Begin pumping out of tank 4 to Vac Truck #86086 11:00 Obs. API 29.6 @ 74F. Corrected API 28.9 @60F 11:05 Water salinity 48000 ppm, pH=7 11:08 Gas Gravity 0.686 11:15 Complete pumping out of tank 4 to Vac Truck #86086. Tank 4 = 191 bbls 11:20 Begin pumping out of tank 4 to Vac Truck #86101 12:20 Complete pumping out of tank 4 to Vac Truck #86101. Tank 4 = 1.5 bbls 13:35 Begin pumping out of tank 1/2 to Vac Truck #86101 13:50 Complete pumping out of tank 1/2 to Vac Truck #86101. Tank 1. = 106 bbls, Tank 2. = 102 bbls 14:00 Obs. API 29.8 @ 74F. Corrected API 28.7 @60F 14:05 Water salinity 39000 ppm, pH=7 14:10 Gas Gravity 0.694 14:35 Begin testing ESD system 14:40 Begin pumping out of tank 1/2 to Vac Truck #86097 15:10 Complete testing ESD system 15:33 Complete pumping out of tank 1/2 to Vac Truck #86101. Tank 1. = 3.10 bbls, Tank 2. = 3.10 bbls 17:00 Obs. API 30.8 @ 75F. Corrected API 28.9 @60F 17:01 Water salinity 40000 ppm, pH=7 17:05 Gas Gravity 0.694 17:06 Begin pumping out of tank 3 to Vac Truck #86097 17:15 Complete pumping out of tank 3 to Vac Truck #86097. Tank 3 = 116 bbls 17:24 Begin pumping out of tank 3 to Vac Truck #86100 17:30 Nightshift arrives on location. 17:35 Hold shift handover meeting with day crew. Discuss current operation 17:45 Day shift departs location. 18:20 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 18:40 Complete pumping out of tank 3 to Vac Truck #86100. Tank 3 = 4.7 bbls 18:42 Begin pumping out of tank 4 to Vac Truck #86100 19:15 Complete pumping out of tank 4 to Vac Truck #86100. Tank 4 = 10.9 bbls 20:00 Obs. API 29.8 @ 68F. Corrected API 29.3 @60F 20:13 Begin pumping out of tank 2 to Vac Truck #86077 20:30 Water salinity 40000 ppm, pH=7 20:30 Gas Gravity 0.694 20:50 Complete pumping out of tank 2 to Vac Truck #86077. Tank 2 =1.55 bbls 20:51 Begin pumping out of tank 1 to Vac Truck #86077 21:35 Complete pumping out of tank 1 to Vac Truck #86077. Tank 1 = 12.4 bbls 21:58 1.000" orifice plate out of service 22:00 Increase choke to 38/64ths adjustable Adam Nelson Frank Tower John Croffut Travis Stone Sharon Oyao Adam Carpenter Dave Poulin Vince Madrid Mike Pannone Page 30 22:10 Increase choke to 40/64ths adjustable 22:17 Increase choke to 42/64ths adjustable 22:20 Sparge Sandtrap. Recovered trace of Frac Sand 22:21 Increase choke to 44/64ths adjustable choke 22:23 Increase choke to 46/64ths adjustable choke 22:26 Increase choke to 48/64ths adjustable choke 22:28 Increase choke to 50/64ths adjustable choke 22:31 Increase choke to 52/64ths adjustable choke 22:39 Increase choke to 56/64ths fixed choke 22:43 1.500" orifice plate in service 22:46 Begin pumping out of tank 4 to Vac Truck #86101 22:48 1.250" orifice plate in service 23:00 Obs. API 28.2 @ 66F. Corrected API 27.8 @60F 23:21 Complete pumping out of tank 4 to Vac Truck #86101. Tank 4 = 1.55 bbls 23:25 Begin pumping out of tank 3 to Vac Truck #86101 23:30 Water salinity 38000 ppm, pH=7 5-Apr-15 23:30 Gas Gravity 0.688 0:10 Complete pumping out of tank 3 to Vac Truck #86101. Tank 3 = 5 bbls 0:20 Begin pumping out of tank 2 to Vac Truck #86097 0:40 Complete pumping out of tank 2 to Vac Truck #86097. Tank 2 = 1.55 bbls 0:41 Begin pumping out of tank 1 to Vac Truck #86097 0:55 Sparge Separator. Recovered 3 gallons of Frac sand and crude 1:00 Sparge Sandtrap. Recovered 1 gallon of Frac sand 1:28 Complete pumping out of tank 1 to Vac Truck #86097. Tank 1 = 3.1 bbls 1:30 Begin pumping out of tank 4 to Vac Truck #86097 1:33 Stop pumping tank 4 to Vac Truck #86097. Vac Truck reach max capacity. Tank 4 = 49.6 bbls 1:44 Continue pumping tank 4 to Vac Truck # 86100 2:00 Complete pumping out of tank 4 to Vac Truck #86100. Tank 4 = 3.1 bbls 2:00 Obs. API 29.4 @ 74F. Corrected API 28.5 @60F 2:01 Begin pumping out of tank 3 to Vac Truck #86100 2:15 Sparge Sandtrap. Recovered 1 gallon of Frac sand 2:30 Complete pumping out of tank 3 to Vac Truck #86100. Tank 3 = 5 bbls 2:30 Water salinity 38000 ppm, pH=7 2:30 Gas Gravity 0.692 2:55 Begin pumping out of tank 1 to Vac Truck #86100 3:00 Stop injecting downhole methanol 3:15 Sparge Sandtrap. Recovered 1 gallon of Frac sand 3:20 Complete pumping out of tank 1 to Vac Truck #86100. Tank 1 = 17.8 bbls 3:22 Begin pumping out of tank 2 to Vac Truck #86100 3:30 Complete pumping out of tank 2 to Vac Truck #86100. Tank 2 = 3.1 bbls 4:20 Begin pumping out of tank 3 to Vac Truck #86077 5:00 Complete pumping out of tank 3 to Vac Truck #86077. Tank 3 = bbls 5:00 Begin pumping out of tank 4 to Vac Truck #86077 5:00 Obs. API 29 @ 70F. Corrected API 28.3 @60F 5:18 Sparge Sandtrap. Recovered 36 gallon of Frac sand Page 31 5:25 Sparge Separator. Suspected ice plug at sparge line 5:30 Water salinity 38000 ppm, pH=7 5:30 Gas Gravity 0.688 5:35 Complete pumping out of tank 4 to Vac Truck #86077. Tank 4 = 49.6 bbls 5:30 Day shift arrives on location 5:40 Hold shift handover meeting with day crew. Discuss current operation 5:55 Night shift departs location 6:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 6:37 Decreased choke to 48/64ths fixed choke 7:25 Begin transfer from tank#2 to tank #8 8:00 Obs. API 29.4 @ 74F. Corrected API 28.5 @60F 8:04 Begin transfer from tank#1 to tank #8 8:29 Sparge sand trap 10 gal frac sand 8:35 Stop transfer to tank 1 and 2 to tank #8 Begin pushing to tank #13 8:38 Begin transfer tank 8 to Vac truck #86101 9:34 Complete vac from tank #8, Tank #8 = 38.74bbls 9:41 Sparge sand trap. Trace of frac sand 9:53 Begin transfer out of tank 1 and Tank 2 to Vac Truck #86097 10:55 Complete transfer out of tank 4 and tank 3 to Vac Truck #86097. Tank 4 = 43 bbls. Tank 3 = 35 bbls. 10:58 Begin transfer out of tank 1 and Tank 2 to Vac Truck #86100 11:00 Obs. API 30 @ 72F. Corrected API 29.1 @60F 11:11 Complete transfer out of tank 4 and tank 3 to Vac Truck #86097. Tank 4 = 3.10 bbls. Tank 3 = 3.10 bbls. 11:15 Obs. API 30 @ 72F. Corrected API 29.1 @60F 12:35 Complete transfer out of tank 1 and tank 2 to Vac Truck #86100. Tank 1 = 46 bbls. Tank 2 = 48 bbls. 13:00 Begin transfer out of tank 1 and Tank 2 to Vac Truck #86077 13:02 Switched from generator 1 to generator 2 13:25 Complete vac from tanks 1 and 2 to Vac Truck #86077. Tank 1= 3.10bbls, Tank 2= 3.10bbls 13:35 Begin transfer tank 4 to vac truck #86077 13:55 Complete vac from tank 4 to Vac Truck #86077. Tank 4= 121.60 14:00 Obs. API= 29.9 @ 69F. Corrected API= 29.2 @60F, 14:15 Gas Gravity 0.692, Water salinity 40000 ppm, pH=7 14:27 Begin transfer out of tank 3 and Tank 4 to Vac Truck #86101 14:52 Sparge sand trap. Recovered 15 Gallons of Frac Sand 15:44 Complete vac from tanks 3 and 4 to Vac Truck #86101. Tank 3= 35bbls, Tank 4= 38 bbls 16:15 Begin transfer tank 2 to vac truck #86097 16:48 Begin transfer tank 1 to vac truck #86097 16:53 Complete vac from tank 2 to vac Truck #86097. Tank 2= 10.8 bbls 17:24 Complete vac from tank 1 to vac Truck #86097. Tank 1= 73.6 bbls 17:30 Nightshift arrives on location. 17:35 Hold shift handover meeting with day crew. Discuss current operation 17:50 Day shift departs location. 18:00 Obs. API= 30.8 @ 72F. Corrected API= 30.0 @60F 18:00 Gas Gravity 0.692 18:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 18:30 Water salinity 36000 ppm, pH=7 Frank Tower John Croffut Travis Stone Sharon Oyao Adam Nelson Vince Madrid Mike Pannone Roland Taylor Jamon Sandoval Adam Carpenter Dave Poulin Page 32 18:41 Begin transferring tank 4 to Vac Truck #86100 19:15 Complete transferring tank 4 to Vac Truck #86100. Tank 4 = 41.85 bbls 19:15 Begin transferring tank 3 to Vac Truck #86100 20:00 Complete transferring tank 3 to Vac Truck #86100. Tank 3 = 75.95 bbls 20:15 Begin transferring tank 2 to Vac Truck #86077 20:18 Sparge separator. Recovered 10 Gallons of Frac Sand 20:45 Complete transferring tank 2 to Vac Truck #86077. Tank 2 = 1.55 bbls 20:47 Begin transferring tank 1 to Vac Truck #86077 21:37 Complete transferring tank 1 to Vac Truck #86077. Tank 1 = 32.6 bbls 21:50 Begin transferring tank 3 to Vac Truck #86086 22:00 Obs. API= 30.2 @ 72F. Corrected API= 29.4 @60F 22:00 Gas Gravity 0.690 22:00 Water salinity 36000 ppm, pH=7 22:15 Complete transferring tank 3 to Vac Truck #86086. Tank 3 = 35.65 bbls 22:15 Begin transferring tank 4 to Vac Truck #86086 23:00 Complete transferring tank 4 to Vac Truck #86086. Tank 4 = 52.7 bbls. Truck reach max capacity 23:20 Begin transferring tank 4 to Vac Truck #86101 6-Apr-15 23:50 Complete transferring tank 4 to Vac Truck #86101. Tank 4 = 3.1 bbls 0:00 Begin transferring tank 2 to Vac Truck #86101 0:35 Complete transferring tank 2 to Vac Truck #86101. Tank 2 = 1.55 bbls 0:40 Begin transferring tank 1 to Vac Truck #86101 1:00 Complete transferring tank 1 to Vac Truck #86101. Tank 1 = 86.8 bbls. Truck reach max capacity 1:12 Begin transferring tank 1 to Vac Truck #86097 1:45 Complete transferring tank 1 to Vac Truck #86096. Tank 1 = 3.1 bbls 1:46 Begin transferring tank 3 to Vac Truck #86097 2:00 Obs. API= 30.2 @ 74F. Corrected API= 29.4 @60F 2:00 Gas Gravity 0.692 2:00 Water salinity 36000 ppm, pH=7 2:15 Complete transferring tank 3 to Vac Truck #86097. Tank 3 = 4.65 bbls 2:16 Begin transferring tank 4 to Vac Truck #86097 2:36 Complete transferring tank 4 to Vac Truck #86097. Tank 4 = 60.45 bbls 3:00 Sparge sandtrap and separator. Recovered 10 Gallons of Frac Sand 3:24 Begin transferring tank 2 to Vac Truck #86100 4:07 Complete transferring tank 2 to Vac Truck #86100. Tank 2 = 1.55 bbls 4:07 Begin transferring tank 1 to Vac Truck #86100 4:50 Complete transferring tank 1 to Vac Truck #86100. Tank 1 = 6.2 bbls 5:00 Begin transferring tank 4 to Vac Truck #86077 5:15 Sparge sandtrap and separator. Recovered 5 Gallons of Frac Sand 5:25 Day shift arrives on location 5:30 Hold shift handover meeting with day crew. Discuss current operation 5:40 Night shift departs location 5:55 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 5:56 Complete transferring tank 4 to Vac Truck #86077. Tank 4 = 2.3 bbls 5:58 Begin transferring tank 3 to Vac Truck #86077 6:00 Obs. API= 30.4 @ 78F. Corrected API= 29.3 @60F Roland Taylor Jamon Sandoval Adam Carpenter Dave Poulin Vince Madrid Mike Pannone Page 33 6:00 Gas Gravity 0.690 6:00 Water salinity 38000 ppm, pH=7 6:20 Complete transferring tank 3 to Vac Truck #86077. Tank 3 =13.95 bbls 7:19 Begin Transferring tank 1 and tank 2 to Vac Truck #86086 8:06 Sparge sand trap. Recover 2 Gallon's of frac sand 8:20 Complete transferring tank 1 & tank 2 to Vac Truck #86086. Tank 1 = 4.65 bbls. Tank 2 = 4.65 bbls 8:49 Begin transferring tank 3 to Vac Truck #86101 9:31 Complete transferring tank 3 to Vac Truck #86077. Tank 3 = 4.65 bbls 9:32 Begin transferring tank 4 to Vac Truck #86101 10:00 Obs. API= 30.2 @ 72F. Corrected API= 29.4 @60F 10:00 Gas Gravity 0.698 10:00 Water salinity 40000 ppm, pH=7 10:11 Complete transferring tank 4 to Vac Truck #86101. Tank 4 = 12.40 bbls 10:48 Begin transferring tank 1 to Vac Truck #86091 11:24 Complete transferring tank 1 to Vac Truck #86091. Tank 1 = 3.1 bbls 11:55 Complete transferring tank 2 to Vac Truck #86091. Tank 2 = 3.1 bbls 12:06 Replaced transducer on I/A 12:50 Begin transferring tank 3 to Vac Truck #86100 13:25 Complete transferring tank 3 to Vac Truck #86100. Tank 3 = 3.1 bbls 13:26 Begin transferring tank 4 to Vac Truck #86100 13:50 Sparge sand trap. Recover 10 Gallons of frac sand 13:57 Sparge Separator. Recover no sand 14:58 Complete transferring tank 4 to Vac Truck #86100. Tank 4 = 26.3bbls 14:00 Obs. API= 31 @ 71F. Corrected API= 30.3 @60F 14:00 Gas Gravity 0.691 14:00 Water salinity 40000 ppm, pH=7 14:50 Begin transferring tank 1 to Vac Truck #86077 15:24 Begin testing ESD system 15:27 Complete transferring tank 1 to Vac Truck #86077. Tank 1 = 12.40 bbls 15:27 Begin transferring tank 2 to Vac Truck #86077 15:45 Complete ESD system test 15:58 Complete transferring tank 2 to Vac Truck #86077. Tank 2 = 31 bbls 16:50 Begin transferring tank 4 to Vac Truck #86086 16:53 Sparge sand trap. Recover 5 Gallons of frac sand 17:30 Night shift arrives on location 17:34 Complete transferring tank 4 to Vac Truck #86086. Tank 4 = 3.1 bbls 17:34 Begin transferring tank 3 to Vac Truck #86086 17:35 Hold shift handover meeting with day crew. Discuss current operation 17:45 Day shift departs location. 18:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 18:00 Obs. API= 30.8 @ 68F. Corrected API= 30.3 @60F 18:00 Gas Gravity 0.692 18:00 Water salinity 40000 ppm, pH=7 18:35 Complete transferring tank 3 to Vac Truck #86086. Tank 3 = 21.7 bbls 19:15 Begin transferring tank 2 to Vac Truck #86101 Travis Stone Sharon Oyao Adam Nelson Frank Tower John Croffut Page 34 19:40 Complete transferring tank 2 to Vac Truck #86086. Tank 2 = 3.1 bbls 19:45 Ice plug off at flare line 19:45 Start pumping methanol at scrubber outlet line 19:45 1.250" orifice plate out of service 19:50 Begin transferring tank 1 to Vac Truck #86101 20:13 Ice breaks off at flare line 20:15 1.250" orifice plate in service 20:15 Complete transferring tank 1 to Vac Truck #86101. Tank 1 = 31 bbls 21:20 Begin transferring tank 4 to Vac Truck #86097 21:25 Received road condition update: Phase II weather condition 21:33 Complete transferring tank 4 to Vac Truck #86097. Tank 4 = bbls 21:34 Begin transferring tank 3 to Vac Truck #86097 22:00 Obs. API= 30.2 @ 70F. Corrected API= 29.5 @60F 22:00 Gas Gravity 0.692 22:00 Water salinity 40000 ppm, pH=7 22:10 Complete transferring tank 3 to Vac Truck #86097. Tank 3 = 27.9 bbls 7-Apr-15 23:24 Begin transferring tank 1 and tank 2 to Vac Truck #86100 0:40 Complete transferring tank 1 and tank 2 to Vac Truck #86100. Tank 1 = 21.7 bbls. Tank 2 = 18.6 bbls. 1:00 Sparged sandtrap and separator. Recovered 10 gallons of Frac sand 1:10 Begin transferring tank 3 and tank 4 to Vac Truck #86077 2:00 Obs. API= 30.2 @ 68F. Corrected API= 29.7 @60F 2:00 Gas Gravity 0.688 2:00 Water salinity 40000 ppm, pH=7 2:20 Complete transferring tank 3 and tank 4 to Vac Truck #86077. Tank 3 = 31 bbls. Tank 4 = 21.7 bbls. 4:20 Begin transferring tank 1 and tank 2 to tank 6 5:24 Complete transferring tank 1 and tank 2 to tank 6 5:25 Begin transferring tank 1 and tank 2 to tank 5 5:25 Day shift arrives on location 5:30 Hold shift handover meeting with day crew. Discuss current operation 5:40 Night shift departs location 5:55 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 6:00 Obs. API= 30 @ 72F. Corrected API= 29.2 @60F 6:00 Gas Gravity 0.690 6:00 Water salinity 38000 ppm, pH=7 6:22 Begin transferring tank 3 and tank 4 to Vac truck #86086 6:54 Sparge sand trap. Recover 5 Gallons of frac sand 7:30 Complete transferring tank 3 and 4 to Vac truck #86086. Tank 3 = 24 bbls Tank 4 = 24 bbls 7:46 Begin transferring tank 1 to Vac truck # 86097 8:40 Complete transferring tank 1 to Vac truck # 86097. Tank 1 = 1.5 bbls 8:43 Begin transferring tank 2 to Vac truck # 86097 9:08 Complete transferring tank 2 to Vac truck # 86097. Tank 2 = 15.5 9:50 Begin transferring tank 3 to Vac truck # 86101 10:00 Obs. API= 30.2 @ 64F. Corrected API= 29.9 @60F 10:00 Gas Gravity 0.687 10:00 Water salinity 40000 ppm, pH=7 Jamon Sandoval Adam Carpenter Vince Madrid Mike Pannone Roland Taylor Dave Poulin Page 35 8:43 Begin transfering tank 2 to Vac truck # 86097 9:08 Complete transfering tank 2 to Vac truck # 86097. Tank 2 = 15.5 9:50 Begin transfering tank 3 to Vac truck # 86101 10:00 Obs. API= 30.2 @ 64F. Corrected API= 29.9 @60F 10:00 Gas Gravity 0.687 10:00 Water salinity 40000 ppm, pH=7 10:34 Complete transfering tank 3 to Vac truck # 86101 tank 3 = 4.65 10:34 Begin transfering tank 4 to Vac truck # 86101 11:07 Sparge sand trap. 1 Gallon recoverd 11:11 Complete transfering tank 4 to Vac truck # 86101 tank 4 = 34 bbls 11:17 Begin transfering tank 4 to Vac truck # 86077 11:23 Complete transfering tank 4 to Vac truck # 86077. tank 4 = 11 bbls 11:49 Begin transfering tank 1 and 2 to Vac truck # 86077 12:36 Complete transfering tank 1 and 2 to Vac truck # 86077. Tank 1= 6.2 bbls Tank 2 = 1.5 bbls 13:19 Begin transfering tank 3 to Vac truck # 86100 13:49 Complete transfering tank 3 to Vac truck # 86100. Tank 3 = 3.10 bbls 13:51 Begin transfering tank 4 to Vac truck # 86100 14:00 Obs. API= 31 @ 73F. Corrected API= 30.1 @60F 14:00 Gas Gravity 0.697 14:00 Water salinity 38000 ppm, pH=7 14:26 Complete transfering tank 4 to Vac truck # 86100. Tank 4 = 12.4 bbls 14:35 Begin testing ESD system 14:58 Complete testing ESD system 15:15 Begin transfering tank 1 to Vac truck # 86086 15:29 Sparge sand trap. 2 Gallons 15:55 Complete transfering tank 1 to Vac truck # 86086. Tank 1 = 1.5 bbls 15:55 Begin transfering tank 2 to Vac truck # 86086 16:34 Complete transfering tank 2 to Vac truck # 86086. Tank 4 = 12.4 bbls 17:21 Begin transfering tank 2 to Vac truck # 86097 17:30 Night shift arrives on location 17:35 Hold shift handover meeting with day crew. Discuss current operation 17:45 Day shift departs location. 18:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 18:00 Obs. API= 30.2 @ 74F. Corrected API= 29.3 @60F 18:00 Gas Gravity 0.692 18:00 Water salinity 40000 ppm, pH=7 18:30 Complete transfering tank 3 to Vac truck # 86097. Tank 2 = 4.65 bbls 18:32 Begin transfering tank 4 to Vac truck # 86097 18:50 Complete transfering tank 4 to Vac truck # 86097. Tank 4 = 21.7 bbls 20:18 Begin transferring tank 1 and tank 2 to Vac Truck #86101 21:30 Complete transferring tank 1 and tank 2 to Vac Truck #86101. Tank 1 = 37.2 bbls. Tank 2 = 37.2 bbls. 22:00 Obs. API= 30.2 @ 74F. Corrected API= 29.3 @60F 22:00 Gas Gravity 0.698 22:00 Water salinity 42000 ppm, pH=7 22:45 Begin transferring tank 3 and tank 4 to Vac Truck #86077 John Croffut Travis Stone Sharon Oyao Adam Nelson Frank Tower Page 36 23:30 Sparged sandtrap and separator. Recover @ 5 gallons of frac sand 8-Apr-15 0:00 Complete transferring tank 3 and tank 4 to Vac Truck #86077. Tank 3 = 46.5 bbls. Tank 4 = 46.5 bbls. 1:20 Begin transferring tank 1 and tank 2 to Vac Truck #86100 2:00 Obs. API= 30.6 @ 72F. Corrected API= 29.8 @60F 2:00 Gas Gravity 0.696 2:00 Water salinity 40000 ppm, pH=7 2:10 Complete transferring tank 1 and tank 2 to Vac Truck #86077. Tank 1 = 60.45 bbls. Tank 2 = 75.95 bbls. 3:10 Begin transferring tank 3 and tank 4 to Vac Truck #86086 4:30 Complete transferring tank 3 and tank 4 to Vac Truck #86086. Tank 3 = 51.15 bbls. Tank 4 = 51.15 bbls. 4:40 Begin transferring tank 1 and tank 2 to Vac Truck #86097 4:47 Sparged sandtrap and separator. Recover 5 gallons of Frac sand 5:15 Complete transfering tank 2 to Vac truck # 86097. Tank 2 = 48.05 bbls 5:30 Day shift arrives on location 5:35 Hold shift handover meeting with day crew. Discuss current operation 5:40 Night shift departs location 5:55 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 5:58 Complete transfering tank 1 to Vac truck # 86097. Tank 1 = 31.78 bbls 5:59 Begin transferring tank 3 and tank 4 to Vac Truck #86101 6:00 Obs. API= 30.9 @ 73F. Corrected API= 30.0 @60F 6:00 Gas Gravity 0.691 6:00 Water salinity 41000 ppm, pH=7 7:00 Complete transferring tank 3 and tank 4 to Vac Truck #86101. Tank 3 = 6.2 bbls. Tank 4 = 3.10 bbls. 7:07 Divert flow through 60/64ths Adjustable choke 7:10 Begin transfering tank 2 to Vac truck # 86101. 7:25 Sparge sand trap. Recover @ 2 Gallons 7:30 Complete transfering tank 2 to Vac truck # 86101. Tank 2 = 123 bbls 7:32 Begin transfering tank 2 to Vac truck # 86077. 7:45 Begin transfering tank 1 to Vac truck # 86077. 8:00 Increase choke to 72/64ths Adjustable choke 8:02 Sparge sand trap. Recover @ 1 Gallons 8:31 Complete transfering tank 1 to Vac truck # 86077. Tank 1 = 37 bbls 8:31 Complete transfering tank 2 to Vac truck # 86077. Tank 2 = 9 bbls 8:37 Sparge sand trap. Recover @ 2 Gallons 9:00 Increase choke to 84/64ths Adjustable choke 9:05 Sparge sand trap. Recover @ 1 Gallons 9:16 Begin transfering tank 3 to Vac truck # 86100. 9:34 Sparge sand trap. Recover Trace sand 9:56 Complete transfering tank 3 to Vac truck # 86100. Tank 3 = 4.65 bbls 9:56 Begin transfering tank 4 to Vac truck # 86100. 10:00 Increase choke to 96/64ths Adjustable choke 10:03 Sparge sand trap. Recover Trace frac sand 10:00 Obs. API= 31.6 @ 82F. Corrected API= 30.1 @60F 10:00 Gas Gravity 0.686 10:00 Water salinity 32000 ppm, pH=8 10:24 Complete transfering tank 4 to Vac truck # 86100. Tank 4 = 94.55 bbls Roland Taylor Jamon Sandoval Adam Carpenter Dave Poulin Vince Madrid Mike Pannone Page 37 11:00 Increase choke to 128/64ths adjustable 11:04 Begin transfering tank 4 to Vac truck # 86086. 11:05 Sparge sand trap. Recover trace frac sand 11:26 Complete transfering tank 4 to Vac truck # 86086. Tank 4 = 3.10 bbls 11:39 Begin transfering tank 2 to tank 5 11:45 Begin transfering tank 1 to tank 5 12:02 Sparge sand trap. Recover trace frac sand 12:35 Sparge sand trap. Recover trace frac sand 12:55 Complete transfering tank 1 and 2 to tank 5 13:00 Divert flow through 128/64ths Fixed choke 13:06 Sparge sand trap. Recover trace frac sand 13:15 Begin transfering tank 3 to Vac truck # 86086. 14:00 Obs. API= 31.5 @ 80degF. Corrected API= 30.1 @60F 14:00 Water salinity 40,000 ppm, pH=7 14:00 Gas Gravity 0.686 14:15 Complete transfering tank 3 to Vac truck # 86086. Tank 3 = 3.10 bbls. 14:16 Begin transfering tank 4 to Vac truck # 86086. 14:25 Complete transfering tank 4 to Vac truck # 86086. Tank 4 = 136 bbls 14:30 Begin transfering tank 4 to Vac truck # 86097. 15:07 Complete transfering tank 4 to Vac truck # 86097. 15:19 Begin transfering tank 2 to Vac truck # 86097. 15:50 Complete transfering tank 2 to Vac truck # 86097. Tank 2 = 54 bbls 15:54 Begin transfering tank 2 to Vac truck # 86101. 16:10 Complete transfering tank 2 to Vac truck # 86101. 16:15 Begin transfering tank 1 to Vac truck # 86101. 16:17 Sparge sand trap. Recover trace frac sand 17:11 Complete transfering tank 1 to Vac truck # 86101. Tank 1 = 3.10 bbls 17:19 Begin transfering tank 3 to Vac truck # 86101. 17:28 Complete transfering tank 3 to Vac truck # 86101. Tank 3 = 133.27 bbls 17:30 Begin transfering tank 3 to Vac truck # 86077. 17:30 Night shift arrives on location 17:35 Hold shift handover meeting with day crew. Discuss current operation 17:45 Day shift departs location. 18:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 18:00 Obs. API= 30.8 @ 72degF. Corrected API= 30.0 @60F 18:00 Water salinity 40,000 ppm, pH=7 18:00 Gas Gravity 0.688 18:15 Complete transfering tank 3 to Vac truck # 86077. Tank 3 = 3.1 bbls 18:20 Begin transfering tank 4 to Vac truck # 86077. 19:00 Sparge sand trap. Recover trace frac sand 19:10 Complete transfering tank 4 to Vac truck # 86077. Tank 4 = 54.25 bbls 19:14 Bypass ballcatcher 19:31 Bypass line heater. Shut-in line heater. Closed inlet valve 19:40 Begin transfering tank 1 to Vac truck # 86100. 19:50 Begin transfering tank 2 to Vac truck # 86100. Frank Tower John Croffut Travis Stone Sharon Oyao Adam Nelson Page 38 20:20 Complete transfering tank 1 to Vac truck # 86100. Tank 1 = 49.6 bbls 20:20 Complete transfering tank 2 to Vac truck # 86100. Tank 2 = 29.45 bbls 20:31 Replaced pressure transducer on Wellhead. Input calibration S/N 1316970 on channel 1 20:55 1.250" orifice plate out of service 21:15 Begin transfering tank 3 to Vac truck # 86086. 21:30 1.250" orifice plate in service 21:50 1.500" orifice plate in service 21:50 Stop transfering tank 3 to Vac truck # 86086. 21:55 Begin transfering tank 4 to Vac truck # 86086. 21:55 Resume transfering tank 3 to Vac truck # 86086. 22:15 Start clearing snow around well test area with loader 22:00 Obs. API= 31.4 @ 72degF. Corrected API= 30.6 @60F 22:00 Water salinity 40,000 ppm, pH=7 22:00 Gas Gravity 0.698 22:00 Complete transfering tank 3 to Vac truck # 86086. Tank 3 = 46.5 bbls 22:03 Complete transfering tank 4 to Vac truck # 86086. Tank 4 = 6.2 bbls 22:10 Begin transfering tank 1 and tank 2 to Vac truck # 86097 23:15 Complete transferring tank 1 and tank 2 to Vac Truck #86097. Tank 1 = 3.10 bbls. Tank 2 = 3.10 bbls. 23:45 Begin transfering tank 3 to Vac truck # 86077 23:50 Begin transfering tank 4 to Vac truck # 86077 9-Apr-15 1:00 0.5 ppm H2S / 0% CO2 1:00 Complete transferring tank 3 and tank 4 to Vac Truck #86077. Tank 3 = 49.6 bbls. Tank 4 = 52.7 bbls. 1:55 Begin transfering tank 1 to Vac truck # 86101. 2:00 Begin transfering tank 2 to Vac truck # 86101. 2:00 Obs. API= 30.8 @ 74degF. Corrected API= 29.9 @60F 2:00 Water salinity 40,000 ppm, pH=7 2:00 Gas Gravity 0.702 2:00 0.5 ppm H2S 2:45 Sparge sand trap and separator. Recover 10 gallons of frac sand 2:55 Complete transfering tank 2 to Vac truck # 86101. Tank 2 = 63.55 bbls 3:00 0.5 ppm H2S 3:00 Complete transfering tank 1 to Vac truck # 86101. Tank 1 = 38.75 bbls 3:00 Begin transfering tank 3 to Vac truck # 86100 3:10 Begin transfering tank 4 to Vac truck # 86100 4:05 Complete transfering tank 3 to Vac truck # 86100. Tank 3 = 34.1 bbls 4:08 Complete transfering tank 4 to Vac truck # 86100. Tank 4 = 52.7 bbls 5:15 Begin transfering tank 1 and tank 2 to Vac truck # 86086. 5:30 Day shift arrives on location 5:35 Hold shift handover meeting with day crew. Discuss current operation 5:45 Night shift departs location 5:55 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 5:55 Complete transfering tank 1 and tank 2 to Vac truck # 86086. tank 1 = 2.3 bbls 6:00 Obs. API= 31.2 @ 70degF.rrected API= 30.5 @60F 6:00 Water salinity 40,000 ppm, pH=7 6:00 Gas Gravity 0.691 Mike Pannone Sunil Goolcharan Roland Taylor Jamon Sandoval Adam Carpenter Dave Poulin Vince Madrid Page 39 6:00 0.5 ppm H2S 6:30 Begin transfering tank 2 to tank 7 6:55 Complete transfering tank 2 to tank 7. tank 2 = 27.90 bbls 6:59 Begin transfering tank 3 and tank 4 to tank 7 8:14 Complete transfering tank 3 and tank 4 to tank 7. tank 3 = 4.65 bbls. Tank4 = 4.65 bbls. 8:28 Begin transfering tank 1 to Vac truck # 86077. 9:10 Sparge sand trap and separator. Recover 2 gallons of frac sand 9:17 Complete transfering tank 1 to Vac truck # 86077. tank 1 = bbls 9:17 Begin transfering tank 2 to Vac truck # 86077. 9:41 Complete transfering tank 2 to Vac truck # 86077. tank 2 = 74 bbls 9:45 Begin transfering tank 2 to Vac truck # 86097. 10:00 Obs. API= 31 @ 72degF.rrected API= 30.2 @60F 10:00 Water salinity 40,000 ppm, pH=7 10:00 Gas Gravity 0.703 10:21 Complete transfering tank 2 to Vac truck # 86097. tank 2 = 1.55 bbls 10:24 Begin transfering tank 3 to Vac truck #86097 10:59 Complete transfering tank 3 to Vac truck #86097 tank 3 = 59 bbls 11:07 Begin transfering tank 3 to Vac truck #86100 11:24 Complete transfering tank 3 to Vac truck #86100. tank 3 = 4.65 bbls 11:25 Begin transfering tank 4 to Vac truck #86100 12:10 Sparge sand trap and separator. Recover 1 gallons of frac sand 12:11 Complete transfering tank 4 to Vac truck #86100. tank 4 = 3.10 bbls 12:13 Begin transfering tank 1 to Vac truck #86100 12:25 Complete transfering tank 1 to Vac truck #86100. tank 1 = 143 bbls 12:28 Begin transfering tank 1 to Vac truck #86086 13:09 Complete transfering tank 1 to Vac truck #86086. tank 1 = 1.55 bbls 13:09 Begin transfering tank 2 to Vac truck #86086 13:44 Complete transfering tank 2 to Vac truck #86086. tank 2= 34.5 bbls 14:00 Obs. API= 31 @ 68degF.rrected API= 30.5 @60F 14:00 Water salinity 39,000 ppm, pH=7 14:00 Gas Gravity 0.698 14:28 Begin transfering tank 3 & 4 to tank 5 16:00 Complete transfering tank 3 & 4 to tank 5. tank 3 = 67 bbls. Tank 4 = 3.10 bbls 16:05 Begin transfering tank 3 to Vac truck #86077 16:30 Complete transfering tank 3 to Vac truck #86077. Tank 3 = 16:32 Begin transfering tank 1 to Vac truck #86077 17:00 Sparge sand trap and separator. Recover 1 gallon of frac sand 17:22 Complete transfering tank 1 to Vac truck #86077 17:28 Begin transfering tank 2 to Vac truck #86077 17:30 Night shift arrives on location 17:35 Hold shift handover meeting with day crew. Discuss current operation 17:45 Day shift departs location. 18:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 18:00 Obs. API= 31 @ 70degF. Corrected API= 30.3 @60F 18:00 Water salinity 40,000 ppm, pH=7 Travis Stone Sharon Oyao Adam Nelson Frank Tower John Croffut Page 40 18:00 Gas Gravity 0.702 18:25 Complete transfering tank 2 to Vac truck #86097. Tank 2= 1.55 bbls 18:27 Begin transfering tank 4 to Vac truck #86077 18:40 Complete transfering tank 4 to Vac truck #86097. Tank 4= 126.6 bbls 18:45 Begin transfering tank 3 to Vac truck #86100 19:00 Complete transfering tank 3 to Vac truck #86100. tank 3 = 34.1 bbls 19:05 Begin transfering tank 4 to Vac truck #86100 19:50 Complete transfering tank 4 to Vac truck #86100. tank 4 = 15.5 bbls 20:24 Begin transfering tank 1 to Vac truck #86086 20:30 Complete transfering tank 1 to Vac truck #86086. tank 1 = 41.85 bbls 20:34 Begin transfering tank 2 to Vac truck #86086 21:30 Complete transfering tank 2 to Vac truck #86086. tank 2 = 52.7 bbls 22:00 Obs. API= 31.2 @ 72degF. Corrected API= 30.4 @60F 22:00 Water salinity 42,000 ppm, pH=7 22:00 Gas Gravity 0.696 22:25 Begin transfering tank 3 to Vac truck #86077 22:50 Complete transfering tank 3 to Vac truck #86100. tank 3 = 27.9 bbls 22:55 Begin transfering tank 4 to Vac truck #86077 23:30 Complete transfering tank 4 to Vac truck #86077. tank 4 = 34.1 bbls 10-Apr-15 0:12 Begin transfering tank 1 and tank 2 to tank 8 1:00 Complete transfering tank 1 and tank 2 to tank 8. Tank 1 = 65.1 bbls. Tank 2 = 75.95 bbls. 1:15 Begin transfering tank 3 to Vac Truck #86097 1:35 Complete transfering tank 3 to Vac truck #86097. Tank 3 = 7.75 bbls 1:37 Begin transfering tank 4 to Vac Truck #86097 1:50 Complete transfering tank 4 to Vac truck #86097. Tank 4 = 10.85 bbls 1:50 Begin transfering tank 2 to Vac Truck #86097 2:00 Complete transfering tank 2 to Vac truck #86097. Tank 2 = 124.94 bbls 2:00 Obs. API= 30.2 @ 70degF. Corrected API= 29.5 @60F 2:00 Water salinity 42,000 ppm, pH=7 2:00 Gas Gravity 0.696 2:05 Begin transfering tank 1 and tank 2 to Vac Truck #86101 2:30 Complete transfering tank 1 to Vac truck #86101. Tank 1 = 10.85 bbls 2:35 Begin transfering tank 2 to Vac Truck #86101 3:30 Complete transfering tank 2 to Vac truck #86101. Tank 2 = 10.85 bbls 3:40 Begin transfering tank 3 to Vac Truck #86086 4:05 Begin transfering tank 4 to Vac Truck #86086 4:40 Complete transfering tank 3 and tank 4 to Vac truck #8086. Tank 3 = 41.85 bbls. Tank 4 = 71.3 bbls. 4:50 Begin transfering tank 4 to Vac Truck #86100 5:00 Complete transfering tank 4 to Vac truck #86100. Tank 4 = bbls tank 4 = 3.10 bbls 5:15 Begin transfering tank 1 and tank 2 to Vac Truck #86100 5:19 Sparge sand trap and separator. Recover 5 gallon of frac sand 5:30 Day shift arrives on location 5:35 Hold shift handover meeting with day crew. Discuss current operation 5:45 Night shift departs location 6:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement Jamon Sandoval Adam Carpenter Sunil Goolcharan Roland Taylor Page 41 6:00 Obs. API= 31 @ 73degF. Corrected API= 30.1 @60F 6:00 Water salinity 40,000 ppm, pH=7 6:00 Gas Gravity 0.698 6:09 Complete transfering tank 1 and tank 2 to Vac Truck #86100. tank 1 = 3.10 bbls. Tank 2 = 3.10 bbls 6:40 Sparge sand trap and separator. trace of frac sand 6:41 Divert flow to 128/64ths Adjustable choke 6:51 Start to walk adjustable choke down to 32/6ths 6:55 Begin transfering tank 3 and tank 4 to Vac Truck #86097 7:00 Divert flow through 32/64ths Positive 7:48 Complete transfering tank 3 and tank 4 to Vac Truck #86097 tank 3 = 40 bbls. Tank 4 = 12.5 bbls. 10:00 Obs. API= 31.6 @ 78degF. Corrected API= 30.5 @60F 10:00 Water salinity 40,000 ppm, pH=7 10:00 Gas Gravity 0.699 10:18 Begin transfering tank 1 and tank 2 to Vac Truck #86086 11:20 Complete transfering tank 1 and tank 2 to Vac Truck #86086. tank 1 = 15.5 bbls. Tank 2 = 1.55 bbls. 13:15 Begin transfering tank 3 and tank 4 to Vac Truck #86100 14:00 Obs. API= 31 @ 72degF. Corrected API= 30.2 @60F 14:00 Water salinity 40,000 ppm, pH=7 14:00 Gas Gravity 0.690 14:20 Complete transfering tank 3 and tank 4 to Vac Truck #86100 17:17 Begin transfering tank 1 and tank 2 to Vac Truck #86101 17:30 Night shift arrives on location 17:35 Hold shift handover meeting with day crew. Discuss current operation 17:45 Day shift departs location. 18:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 18:00 Obs. API= 31 @ 74 degF. Corrected API= 30.0 @60F 18:00 Water salinity 40,000 ppm, pH=7 18:00 Gas Gravity 0.692 18:05 Complete transfering tank 1 to Vac truck #86101. Tank 1 = 9.3 bbls 18:22 Complete transfering tank 2 to Vac truck #86101. Tank 2 = 10.85 bbls 21:45 Begin transfering tank 3 and tank 4 to Vac Truck #86100 22:00 Obs. API= 31.4 @ 72 degF. Corrected API= 30.6 @60F 22:00 Water salinity 40,000 ppm, pH=7 22:00 Gas Gravity 0.698 22:13 Begin transfering tank 7 to Vac Truck #86097 22:50 Complete transfering tank 3 to Vac truck #86100. Tank 3 = 27.9 bbls. 23:00 Complete transfering tank 4 to Vac truck #86100. Tank 4 = 24.8 bbls. 23:20 Complete transfering tank 7 to Vac Truck #86097. Tank 7 = 47 bbls. 23:30 Begin transfering tank 8 to Vac Truck #86097 23:37 Complete transfering tank 8 to Vac Truck #86097. Tank 8 = 309 bbls. 11-Apr-15 0:15 Begin transfering tank 1 and tank 2 to Vac Truck #86101 1:10 Complete transfering tank 1 to Vac truck #86101. Tank 1 = 1.55 bbls. 1:20 Complete transfering tank 2 to Vac truck #86101. Tank 2 = 4.65 bbls 1:40 Begin transfering tank 3 and tank 4 to Vac Truck #86101 2:00 Obs. API= 31 @ 74 degF. Corrected API= 30.0 @60F Travis Stone Sharon Oyao Adam Nelson Frank Tower John Croffut Vince Madrid Mike Pannone Page 42 2:00 Water salinity 40,000 ppm, pH=7 2:00 Gas Gravity 0.702 2:12 Complete transfering tank 3 to Vac truck #86101. Tank 3 = 37.2 bbls. 2:15 Complete transfering tank 4 to Vac truck #86101. Tank 4 = 37.2 bbls 5:05 Begin transfering tank 2 to Vac Truck #86100 5:30 Day shift arrives on location 5:35 Hold shift handover meeting with day crew. Discuss current operation 5:45 Night shift departs location 5:55 Complete transfering tank 2 to Vac Truck #86100. tank 2 = 3.10 bbls 6:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 6:01 Begin transfering tank 1 to Vac Truck #86100 6:05 Obs. API= 31 @ 73 degF. Corrected API= 30.1 @60F 6:05 Water salinity 40,000 ppm, pH=7 6:05 Gas Gravity 0.696 6:28 Complete transfering tank 1 to Vac Truck #86100. Tank 1 = 143 bbls 9:49 Begin transfering tank 3 and tank 4 to Vac Truck #86086 10:00 Obs. API= 31 @ 73 degF. Corrected API= 30.1 @60F 10:00 Water salinity 40,000 ppm, pH=7 10:00 Gas Gravity 0.696 10:53 Complete transfering tank 3 and tank 4 to Vac Truck #86086. Tank 3 = 10.8 bbls. Tank 4 = 12.4 bbls. 12:18 Begin transfering tank 1 and tank 2 to Vac Truck #86100 13:20 Complete transfering tank 1 and tank 2 to Vac Truck #86100. Tank 1 = 1.55 bbls. Tank 2 = 1.55 bbls 14:00 Obs. API= 31.4 @ 76 degF. Corrected API= 30.3 @60F 14:00 Water salinity 40,000 ppm, pH=7 14:00 Gas Gravity 0.678 17:30 Night shift arrives on location 17:35 Hold shift handover meeting with day crew. Discuss current operation 17:45 Day shift departs location. 18:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 18:00 Obs. API= 31.2 @ 78 degF. Corrected API= 30.2 @60F 18:00 Water salinity 40,000 ppm, pH=7 18:00 Gas Gravity 0.674 18:10 Begin transfering tank 3 to Vac Truck #86101 18:45 Complete transfering tank 3 to Vac truck #86101. Tank 3 = 31 bbls 18:55 Begin transfering tank 3 and tank 4 to Vac Truck #86097 20:00 Complete transfering tank 3 and tank 4 to Vac Truck #86097. Tank 3 = 4.65 bbls. Tank 4 = 1.55 bbls. 22:00 Begin transfering tank 1 and tank 2 to Vac Truck #86086 22:00 Obs. API= 31.2 @ 76 degF. Corrected API= 30.0 @60F 22:00 Water salinity 40,000 ppm, pH=7 22:00 Gas Gravity 0.680 23:20 Complete transfering tank 1 and tank 2 to Vac Truck #86086. Tank 1 = 9.3 bbls. Tank 2 = 9.3 bbls. 12-Apr-15 1:55 Begin transfering tank 3 to Vac Truck #86100 2:00 Obs. API= 31 @ 74 degF. Corrected API= 30.0 @60F 2:00 Water salinity 40,000 ppm, pH=7 2:00 Gas Gravity 0.686 Travis Stone Sharon Oyao Adam Nelson Frank Tower John Croffut Jamon Sandoval Adam Carpenter Sunil Goolcharan Vince Madrid Mike Pannone Roland Taylor Page 43 2:04 Begin transfering tank 4 to Vac Truck #86100 3:05 Complete transfering tank 3 and tank 4 to Vac Truck #86100. Tank 3 = 9.3 bbls. Tank 4 = 9.3 bbls. 5:18 Begin transfering tank 1 to Vac Truck #86086 5:30 Day shift arrives on location 5:35 Hold shift handover meeting with day crew. Discuss current operation 5:45 Night shift departs location 5:55 Complete transfering tank 2 to Vac Truck #86100. tank 2 = 3.10 bbls 6:00 Hold pre-job safety meeting. Review RA for Fluid transfers/ Flowing well and BS&W Measurement 6:00 Obs. API= 31.2 @ 72 degF. Corrected API= 30.4 @60F 6:00 Water salinity 40,000 ppm, pH=7 6:00 Gas Gravity 0.684 6:03 Complete transfering tank 1 to Vac Truck #86086. tank 1 = 3.10 bbls 6:04 Begin transfering tank 2 to Vac Truck #86086 6:48 Complete transfering tank 2 to Vac Truck #86086. tank 2 = 1.55 bbls 8:50 Disconnect chemical injection from wellhead. 9:19 Begin transfering tank 3 to Vac Truck #86097 10:00 Sunil attends meeting on rig floor. To discuss scheduled shut in of well down hole. 10:00 Obs. API= 31.2 @ 72 degF. Corrected API= 30.4 @60F 10:00 Water salinity 40,000 ppm, pH=7 10:00 Gas Gravity 0.674 10:01 Complete transfering tank 3 to Vac Truck #86097. tank 3 = 3.10 bbls 10:05 Begin transferring tank 4 to Vac Truck #86097 10:30 Begin pressuring annulus to 2500 10:30 Hold 2500psi for 15 min 10:50 Bleed off annulus pressure 10:51 Monitor well head pressure drop 11:03 Shut in at Expro choke at 200psi 11:05 Monitor shut in pressure at Expro choke 11:15 Complete transferring tank 4 to Vac Truck #86097. tank 4 = 27.9 bbls 11:31 Begin transferring tank 1,2 & 4 to Vac Truck #86100 12:00 Complete transferring tank 1,2 & 4 to Vac Truck #86100. tk 1 = 2.33bbls. Tk 2 = 3.10bbls. Tk 4= 3.10bbls 17:30 Night shift arrives on location 17:35 Hold shift handover meeting with day crew. Discuss current operation 17:45 Day shift departs location. 18:00 Hold pre-job safety meeting. Fill out TRAC for snow removal and housekeeping well test area 18:00 Well shut-in downhole at Select Tester Valve. Continue monitor WHP, BHP & BHT 18:30 Conduct snow removal around well test area 18:30 LRS add 10 bbls of hot water to horizontal tanks 5, 6, 7 and 8 19:00 LRS add 30 bbls of hot water to sparge tank 19:30 Begin transferring fluid from tanks 5, 7 and 8 to Vac Truck 20:00 Conduct housekeeping well test area 22:00 Put cautioned taped around well test area 13-Apr-15 1:00 Continue snow removal on flare lines 2:00 Conduct housekeeping at choke house 3:00 Conduct housekeeping at DAQ lab Frank Tower John Croffut Jeff Inman Sharon Oyao Adam Nelson Jamon Sandoval Adam Carpenter Sunil Goolcharan Vincent Madrid Mike Pannone Page 44 3:20 Repair handrail on stairs between sand trap and choke house 5:30 Day shift arrives on location 5:35 Hold shift handover meeting with day crew. Discuss current operation 5:45 Night shift departs location 6:00 Hold pre-job safety meeting. Fill out TRAC for snow removal and housekeeping well test area 6:30 Continue snow removal in main berm 7:00 Start performing housekeeping in well test area 8:00 R. Taylor attends daily SIMOPS meeting 8:45 Begin testing ESD system 10:15 Complete testing ESD system 10:30 Hold toolbox meeting with vac truck operator. Create TRAC for rigging down horizontal tanks 10:45 Begin rigging down hooch on horizontal tanks and tank farm walls 11:30 Complete rigging down hooch on horizontal tanks 12:00 Begin rigging down horizontal tank hoses and manifolds 13:00 Complete rigging down hoses and tank manifolds 13:15 Loader delivers C&D dumpster to tank farm 13:45 Load all plastic sheeting and wood from hooch into C&D dumpster 14:00 Load all tank fittings and hoses into hose conex 14:30 Label all unused hoses in hose conex 14:45 Begin to break down berm wall to remove storage tanks 15:05 Tank 14, 13, & 12, Removed from berm to be transported to camp pad 15:20 Cusco arrives on location to resume emptying sparge tank 15:25 Start pulling load from sparge tank 16:45 Complete pulling load from sparge tank 17:30 Night shift arrives on location 17:35 Hold shift handover meeting with day crew. Discuss current operation 17:45 Day shift departs location. 18:00 Hold pre-job safety meeting. Fill out TRAC for rig down tank farm fittings and housekeeping well site area 18:00 Continue monitor WHP, BHP & BHT 18:30 Continue uninstall remaining tank fittings off of horizontal storage tanks 19:00 Rig down grounding cables at horizontal storage tanks 20:30 Complete rigging down tank fittings on storage tanks 21:00 Load all tank fittings into hose conex skid 21:30 LRS on location, discuss adding hot water to sparge tank. 22:30 Continue break down tank farm berm wall 22:45 LRS starts to add 50 bbls of hot water to sparge tank 23:00 Complete rig down tank farm berm wall 23:30 Pile all plastic sheeting from tank farm hooch in preparation for disposal 14-Apr-15 0:00 Load all wood from tank farm hooch into C&D dumpster 0:40 LRS complete adding 50 bbls of hot water into sparge tank 1:00 Load all plastic sheeting from tank farm hooch into C&D dumpster 2:00 Conduct inspection in all heater trunks 2:30 Snow removal inside main berm 3:00 Test fired igniter. Good test 5:30 Day shift arrives on location John Croffut Adam Nelson Frank Tower Jeff Inman Sharon Oyao Adam Carpenter Sunil Goolcharan Roland Taylor Jamon Sandoval Vincent Madrid Mike Pannone Roland Taylor Page 45 5:35 Hold shift handover meeting with day crew. Discuss current operation 5:45 Night shift departs location 6:00 Hold pre-job safety meeting. Fill out TRAC for snow removal and housekeeping well test area 6:30 Continue general house keeping of well test area 7:00 Loader delivers C&D dumpster to back of Expro berm 7:05 Begin loading all wood and plastic sheeting into C&D dumpster 7:30 Complete loading wood and plastic sheeting into C&D dumpster 8:00 R. Taylor attends daily SIMOPS meeting 9:00 Pick up all loose pieces of wood and plastic sheeting in main berm and dispose in C&D dumpster 9:05 L. Tucker on location conduct walk through with Roland Taylor 10:00 L. Tucker departs location 10:30 Start moving tank farm hoses from area in front horizontal tanks 11:00 Loader starts removing heaters from area at front of horizontal tank farm 11:00 Start removing horizontal tanks from tank farm berm 12:20 Complete removing tanks from storage tank farm berm. 12:45 Begin to break down storage tank berm walls 13:30 Complete breaking down storage tank berm walls 13:45 Begin removing rig mats from storage tank berm 14:30 Complete removing rig mats from storage tank berm 14:45 Roll up berm liner from storage tank berm 15:00 Start checking line up of well test equipment in preparation for reopening well 15:30 Light flare Pilot 15:35 Begin testing ESD system 15:45 Complete testing ESD system 16:00 Hold pre-flow safety meeting with Repsol personnel and Expro 16:30 Function ESD stations with Repsol company rep witness 16:40 Begin pumping methanol down hole at 355 gallons/day 17:02 Begin pressuring annulus to1200psi to open Select Tester Valve 17:04 Select Tester Valve displays indication of opening 17:07 Open well at choke manifold on 16/64ths adjustable 17:21 Fluid to surface 17:25 Start collecting tracer samples 17:22 Increase choke to 24/64ths Adjustable 17:30 Increase choke to 32/64ths Adjustable 17:30 Night shift arrives on location 17:35 Hold shift handover meeting with day crew. Discuss current operation 17:45 Hold pre-job safety meeting. Fill out TRAC for rig down tank farm fittings and housekeeping well site area 18:00 Divert flow through 32/64ths Positive (fixed) choke 18:00 Day crew depart location 18:03 Sparge sandtrap. Recover trace of sand 18:30 Gas Gravity 0.646 19:00 Obs. API= 31.4 @ 56 degF. Corrected API= 31.7 @60F 19:03 Sparge sandtrap. Recover trace of sand 21:00 Sparge sandtrap. Recover trace of sand 21:25 Halliburton personnel to verify Annulus pressure. IA pressure = 2000psi Vincent Madrid Mike Pannone Jamon Sandoval Sunil Goolcharan Adam Carpenter Jeff Inman Sharon Oyao Adam Nelson Frank Tower John Croffut Page 46 23:00 Obs. API= 31.2 @ 62 degF. Corrected API= 31.1 @60F 23:15 Begin transfering tank 1 and tank 2 to Vac Truck #86086 15-Apr-15 0:25 Complete transfering tank 1 and tank 2 to Vac Truck #86086. Tank 1 = 40.3 bbls. Tank 2 = 44.95 bbls. 0:46 Vac Truck #86086 depart location 1:00 Begin transfering tank 1 and tank 2 to Vac Truck #86099 1:02 Sparge sandtrap. Recover 1 gallon of sand 1:30 Complete transfering tank 1 and tank 2 to Vac Truck #86099. Tank 1 = bbls. Tank 2 = bbls. 1:32 Collect last sample #92 1:34 Shut in at Expro's choke manifold 1:35 Shut in chemical injection pump 1:36 1.000" orifice plate out of service 1:37 J. Inman and A. Nelson attend pre-job Safety Meeting at Rig Floor for shut-in the well 2:04 Shut in Wing valve. Monitor Annulus pressure. IA = 2150psi 2:18 Shut off line heater Page 47 Technical Report Title Date Client: Repsol E&P USA Inc. Field: Colville River Rig: Nabors 105AC Date: April 18, 2015 Surface Data Logging End of Well Report Qugruk 301 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) TABLE OF CONTENTS 1.General Information 2.Daily Summary 3.Days vs. Depth 4.After Action Review 5.Formation Tops 6.Show Reports 7.Mud Record 8.Bit Record 9.Morning Reports 10.Survey Report Digital Data to include: Final Log Files Final End of Well Report Final LAS Exports Halliburton Log Viewer EMF Log Viewer CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) GENERAL WELL INFORMATION Company: Repsol Rig: Nabors 105AC Well: Qugruk 301 Field: Colville River Borough: North Slope Borough State: Alaska Country: United States API Number: 50-103-20700-00-00 Sperry Job Number: AK-XX-0902062414 Job Start Date: 30 January 2015 Spud Date: 18 February 2015 Total Depth: 7531’ MD, 4146.46’ TVD North Reference: True Declination: 18.569° Dip Angle: 80.829° Total Field Strength: 57549.403 nT Date Of Magnetic Data: 19 February 2015 Wellhead Coordinates N: North 70° 20’ 03.01248” Wellhead Coordinates W: West 150° 42’ 22.18790“ Drill Floor Elevation 37.00’ Ground Elevation: 17.00’ Permanent Datum: Mean Sea Level SDL Engineers: Andrew Bongard, Ryan Lenberg, Rebecca Mulkey, Michael LaDouceur, Sonny Tiger, Beverly Hur, SDL Sample Catchers: Jarrett Johns, Stanford Alexander, Hilarion Castro Company Geologist: Zenon Kotelko, Ramona Ciobanu, John White, Tom Rozak Company Representatives: Sidney Self, Jackie Mckinley, David Dunbar, Carlos Cretsinger SSDS Unit Number: 102 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) DAILY SUMMARY Note: Daily summaries are written from 03:00 to 03:00 (i.e. The summary dated 2/18/2015, contains a summary from 03:00 2/17/2015 through 03:00 2/18/2015) 02/18/2015 Pick-up the BHA, make-up bit, motor, stabilizer, cross-over, and 1 stand of HWDP. Fill hole with spud mud. Circulate and condition mud. Repair diverter system. Prepare to spud the well. Gas: There was no gas data. Fluids: There were 0 barrels of water-based mud lost down hole. 02/19/2015 Drill ahead from 98' to 225'. Trip out of hole, blow down top drive, and pick up remaining BHA. Drill ahead from 225' to 462'. Circulate mud while working on Mud Pump #2. Short trip, rack- back 1 stand and make-up jars. Ream to bottom and drill ahead from 462' to 1171'. Gas: The max gas was 2061 units at 1171’ MD and the average drilling background gas was 79 units. Fluids: There were 10.3 barrels of water-based mud lost down hole. Geology: Samples have consisted mainly of sandstone translucent, transparent, white, yellow, green, brown, black, coarse to very coarse, sub-angular to sub-rounded, moderately sorted, unconsolidated, no cement, inferred very good porosity, no shows with abundant gravel and a good trace of clay and black lithics, as well as traces of pyrite and wood. 02/20/2015 Drill ahead from 1171' MD to 2115' MD. Circulate hole clean. Pull out of hole and lay down BHA. Gas peaks of 7650 u and 9510 u were witnessed at 1188' MD and 1259' MD, respectively. Gas: The max gas was 9510 units at 1259’ MD and the average drilling background gas was 503 units. Fluids: There were 20.7 barrels of water-based mud lost down hole. Geology: Samples have consisted mainly of claystone grey to light grey, hardness ranges from soft to plastic to firm, smooth texture and no visible porosity. 02/21/2015 Finish laying down BHA. Service the top drive. Rig-up to run casing. Run casing in hole to 870' MD; tight hole witnessed. Wash down to 920' MD. Continue to run in hole with casing to 1807' MD. Gas: The max gas was 247 units and the average gas was 20 units. Fluids: There were 0 barrels of water-based mud lost down hole. 02/22/2015 Continue to run in hole with casing. Work tight spot at 1,862' MD. Lost 80 bbls while working through with 65 bbls returned. Continue run in hole and land casing at 2,107' MD. Run in hole with 5" drill pipe and stab into cement stinger. Pump cement: 10 bbls fresh water, 81.8 bbls 11 ppg spacer, followed by 180 bbls 10.7 ppg lead before cement observed at shakers. Diverted returns to cellar and pumped additional 60 bbls lead before losing returns. Continued pumping lead (347 bbls total) and 15.8 ppg tail cement (72.3 bbls) without returns. Rig down cementers. Circulate and condition mud. Gas: The max gas (trip gas) was 431 units and the average gas was 13 units. Fluids: There were 15 barrels of water-based mud lost down hole. CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) 02/23/2015 Circulate surface to surface and displace to OBM. Clear spud mud from mud mix pumps and lines. Pull out of hole. Rig up/down for top cement job. Nipple down BOP. Rig down diverter line. Nipple up/down diverter system. Gas: No significant gas data. Fluids: There were 0 barrels of water-based mud lost down hole. 02/24/2015 Remove annular. Clear cellar area. Pick-up tubing and tag top of cement 34' from top of conductor. Nipple down BOPs, and remove well head starting head. Rig-up cementer. Make- up 1" pipe, pressure test, and cement top hole (6 bbls cement). Pull out 1" pipe, clean lines and cellar. Nipple up BOPs. Gas: No significant gas data. Fluids: There were 0 barrels of water-based mud lost down hole. 02/25/2015 Continue to nipple up BOPs. Gas: No significant gas data. Fluids: There were 0 barrels of water-based mud lost down hole. 02/26/2015 Continue to nipple up BOPs. Gas: No significant gas data. Fluids: There were 0 barrels of water-based mud lost down hole. 02/27/2015 Complete nippling up BOPs. Begin testing BOPs: troubleshoot super-choke, test HCR valve, pipe rams, choke valves, and blind rams. Continue testing BOPs. Gas: No significant gas data. Fluids: There were 0 barrels of water-based mud lost down hole. 02/28/2015 Continue testing BOPs. IBOP test failure: Replace IBOP on top drive. Identify bad choke valve: Replace #8 valve on choke manifold. Re-test valve and shell test- BOP test good. Rig-down BOP test equipment. Pick-up BHA. Gas: No significant gas data. Fluids: There were 0 barrels of water-based mud lost down hole. 03/01/2015 Continue Pick-up BHA. Wait on bit breaker from Prudhoe Bay. Continue make up and pick up BHA. Load nuke and TIH T/1945’. Broke Circulation, Circulated mud, got good returns at 3300 stks. Dumped a total of 234 bbls of thick/clobbered up mud to cuttings box. Increased pump rate to 80 spm. Circulated mud due to phase III weather conditions. Gas: No significant gas data. Fluids: There were 0 barrels of water-based mud lost down hole 03/02/2015 Continue to wait on the weather. Hold safety meeting and rig-up Halliburton to pressure test. Perform rig service on motors. Pressure test the casing/shoe to 2500 psi. Circulate and condition mud. Work on shaker screens. Circulate mud around. Tag float at 2017' MD. Drill out CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) cement/float. Drill new formation from 2115' MD to 2145' MD. Circulate bottoms up and pull back to shoe. Rig-up to perform FIT. FIT to 13.7 equivalent mud weight. Gas: The max gas was 50 units at 2136’ MD and the average drilling background gas was 34 units. Fluids: There were 0 barrels of mineral oil-based mud lost down hole Geology: Samples have consisted of claystone gray to light gray, firm, platy, arenaceous. 03/03/2015 Rig down third party lines from formation integrity test. Clean and clear rig floor. Trip in hole to 2145' MD and establish returns. Rotary drill from 2145' MD to 2475' MD. Circulate and condition mud. Circulate gas out. Rotary drill from 2475' MD to 3669' MD. Circulate bottoms up. Gas: The max gas was 926 units at 2640’ MD and the average drilling background gas was 178 units. Fluids: There were 30 barrels of mineral oil-based mud lost down hole Geology: The samples have been consistently dark gray to gray, soft to firm, blocky, laminated, arenaceous claystone with a smaller portion being a gray or brown, soft-firm, blocky- unconsolidated siltstone with an occasional milky quartz ooidic inclusion with no visible fluorescence. 03/04/2015 Complete short wiper trip to 2041. Service top drive. Rotary drill from 3669' MD to 4147'MD. Circulate and condition mud. Circulate gas out. Circulate bottoms up. Wait on weather. Gas: The max gas was 810 units at 4077’ MD and the average drilling background gas was 178 units. Fluids: There were 0 barrels of mineral oil-based mud lost down hole Geology: The samples have been consistently dark gray to gray, firm, sub-platy, very finely laminated, silty to shaly claystone with a smaller portion being a gray to light brown, slightly hard, consolidated siltstone with a trace of shale fragments and no visible fluorescence. 03/05/2015 Wait for phase III weather conditions to be lifted. Fix rig electrical issues. Drill ahead from 4147' to 5000'. Gas: The max gas was 1338 units at 4648’ MD and the average drilling background gas was 382 units. Fluids: There were 0 barrels of mineral oil-based mud lost down hole Geology: The samples have been predominantly dark grey to grey to light brown, firm, blocky to sub-blocky claystone, moderately soft siltstone with same coloration and light to medium brown, very fine soft well sorted, sub rounded sandstone and fluorescence ranging from 20 to 60% patchy bright yellow with blue white moderately slow to very weak slow cut. 03/06/2015 Drill ahead from 5000’ to 5248’. Circulate bottoms. Short wiper trip to bottom of shoe. Trip in, circulate, and prepare to trip out. Gas: The max gas was 1348 units at 5144’ and the average drilling background gas was 794 units. Fluids: There were 0 barrels of mineral oil-based mud lost down hole Geology: The samples have been mainly clear, transparent to translucent, milky, with light to medium brown staining, soft, very fine to fine, spherical to sub spherical, round to sub rounded, moderately sorted, moderately consolidated, weak calcareous cemented sandstone with CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) fluorescence ranging from 20 to 70% very weak to patchy yellow with blue white very weak very slow cuts. 03/07/2015 Continue to trip out of hole. Lay down BHA and source. Install casing rams. Riging up to run 9- 5/8" casing. Gas: No significant gas data. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/08/2015 Run in hole with 9 5/8" casing. Gas: The max circulating gas was 1808 u (trip gas), and the average circulating gas was 205 u. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/09/2015 Cement 9 5/8” casing. Gas: The max circulating gas was 404 u (Bottoms up) and the average circulating gas was 63 u. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/10/2015 Test BOP. Gas: No significant gas data. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/11/2015 Test and troubleshoot BOP Gas: No significant gas data. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/12/2015 Run in hole to 2970’ then trip out to 1905’ to retest BOP, trip back in to mill out cement and pressure test casing. Gas: No significant gas data. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/13/2015 Pick up BHA and run in hole to 2970’ then trip out to 1905’ to retest BOP. Gas: No significant gas data. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/14/2015 Run in hole to 3008’, drilled out DV tool, continued run in to 3600’, circulated out cement stringer, pressure test casing, continue running in to 5109’ and drill through cement. Gas: Max gas while drilling 5 units, average gas 3 units. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/15/2015 Drill cement from 5010’ to 5248’, drilled 30’ of new formation. Performed FIT, pumped slug, trip out and lay down BHA, prepare to run wireline. Gas: Max gas while drilling 60 units, average gas 40 units. CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/16/2015 Wireline rigged up for cement log, picked up BHA and trip in hole to commence drilling 6 1/8” production section Gas: Max gas while drilling 225 units at 5345’, average gas 145 units. Fluids: There were 0 barrels of mineral oil-based mud lost down hole Geology: Samples have been mainly sandstone at 80%, clear translucent to milky, light to medium brown staining, soft, fine to very fine grained, moderately to well sorted, with weak calcareous cement, with minor amounts of siltstone at 20%. Shows are 50% patchy to even light brown staining, 70% dark yellow fluorescence with pale blue white blush cut. 03/17/2015 Drilling ahead from 5450’ to 7072’. Gas: Max gas while drilling 517 units at 6487’ units, average gas 313units. Fluids: There were 0 barrels of mineral oil-based mud lost down hole Geology: Samples have been mainly sandstone at 90%, clear translucent to milky, light to medium brown staining, soft, fine to very fine grained, moderately to well sorted, with weak calcareous cement, with minor amounts of siltstone at 10%. Shows are 30-40% patchy to even light brown staining, 70% dull dark yellow fluorescence with pale blue white blush cut. 03/18/2015 Continued to drill from 1072’ to 7531’. TD production section at 7531’. Circulated bottoms up. Short trip to the shoe. Return to bottom. Begin trip out of hole Gas: Max gas while drilling 624 units at 7198’, average gas 122 units. Fluids: There were 0 barrels of mineral oil-based mud lost down hole Geology: Samples have been mainly sandstone at 90%, clear translucent to milky, light to medium brown staining, soft, fine to very fine grained, moderately to well sorted, with weak calcareous cement, with minor amounts of siltstone at 10%. Shows are 30-40% patchy to even light brown staining, 70% dull dark yellow fluorescence with pale blue white blush cut. 03/19/2015 Finish testing BOPs. Prepare for displacement and begin trip back to bottom. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole Geology: Samples have been mainly sandstone at 90%, clear translucent to milky, light to medium brown staining, soft, fine to very fine grained, moderately to well sorted, with weak calcareous cement, with minor amounts of siltstone at 10%. Shows are 30-40% patchy to even light brown staining, 70% dull dark yellow fluorescence with pale blue white blush cut. 03/20/2015 Displaced 9.4 ppg SFMOBF mud to surface and sent spacer. Tripped out of hole, laid down 4” drill pipe and BHA. Begin run in hole with production liner. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/21/2015 Continue running production liner to bottom at 7531’ MD and set liner. Begin trip out of hole and lay down 5” drill pipe. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) 03/22/2015 Continue trip out of hole and lay down 5" drill pipe. Test BOPs. Run completion string. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/23/2015 Continue to run and pressure test the completion string. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/24/2015 Run and land tubing and jewelry. Test annulus, install back pressure valve, and nipple down BOP. Remove pipe shed. Nipple up and test frac BOP. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/25/2015 Continue to rig up and test BOPS and surface equipment in preparation for the upcoming fracing program. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/26/2015 Continue to rig up the well head. Pressure test separators and flow back surface equipment. Pump 40 bbls ahead and perform diagnostic fracture injection test (DFIT). Continue to prepare for the upcoming frac program. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/27/2015 Analyze DFIT and finalize the frac program. Pump seawater to the frac tanks and heat. Pump 6 stage frac job. Rig down Halliburton high pressure line from the frac tree. Rig up Expro chemical injection line and prepare to flow back the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/28/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/29/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 03/30/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) 03/31/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/01/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/02/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/03/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/04/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/05/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/06/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/07/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/08/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/09/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) 04/10/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/11/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/12/2015 Flow test the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/13/2015 Flow test the well. Shut in the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/14/2015 Well shut in and opened to flow test. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/15/2015 Bullhead the well with 160 barrels of 9.4 ppg mineral oil-based mud. Flow check the well. Rig down coil tubing. Nippled down frac tree and nippled up blow out preventers. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/16/2015 Completed testing of blow out preventers. Pumped a 40 barrel pill and bullheaded the pill. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole 04/17/2015 Tripped out of the hole with tubing, tripped back in with retainer. Gas: No significant gas recorded. Fluids: There were 40 barrels of mineral oil-based mud lost down hole 04/18/2015 Cemented the hole to plug and abandon the well. Gas: No significant gas recorded. Fluids: There were 0 barrels of mineral oil-based mud lost down hole CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) 0 1000 2000 3000 4000 5000 6000 7000 8000 0 5 10 15 20 25 30 35 40 45 50 55 60 65Measured Depth Rig Days Prognosed Actual WELL NAME: Qugruk 301 OPERATOR: Nabors MUD CO: Halliburton RIG: Nabors 105 AC SPERRY JOB: Days vs. Depth 30 January, 2015 Sperry SDL Arrived on Location LOCATION: Colville Delta AREA: North Slope STATE: Alaska SPUD: TD: WELL NAME: Qugruk 301 OPERATOR: Nabors MUD CO: Halliburton RIG: Nabors 105 AC SPERRY JOB: Days vs. Depth 30 January, 2015 Sperry SDL Arrived on Location LOCATION: Colville Delta AREA: North Slope STATE: Alaska SPUD: TD: WELL NAME: Qugruk 301 OPERATOR: Nabors MUD CO: Halliburton RIG: Nabors 105 AC SPERRY JOB: Days vs. Depth 30 January, 2015 Sperry SDL Arrived on Location LOCATION: Colville Delta AREA: North Slope STATE: Alaska SPUD: TD: WELL NAME: Qugruk 301 OPERATOR: Repsol E&P USA Inc. MUD CO: Baroid RIG: Nabors 105 AC SPERRY JOB: AK-XX-0902062414 Days vs. Depth 30 Jan 2015 Sperry SDL arrived on location 01 Feb 2015 Sperry SDL services online LOCATION: Colville River AREA: North Slope Borough STATE: Alaska SPUD: 18-Feb-2015 TD: 17-Mar-2015 Commenced 16" Surface Hole Section On Bot: 03:00 18 Feb 2015 Commenced 12.25" Intermediate Hole Section On Bot: 20:43 01 Mar 2015 Landed 13.375" Casing 2107' MD, 2107' TVD 21 Feb 2015 TD Surface Hole Section 2115' MD, 2115' TVD Off Bot: 15:52 19 Feb 2015 Test BOPs 10-13 Mar 2015 Landed 4.5" Liner 7531' MD, 4146' TVD 21 Mar 2015 TD Production Hole Section 7531' MD, 4146.46' TVD Off Bot: 10:22 17 Mar 2015 Commenced 6.125" Production Hole Section On Bot: 00:39 16 Mar 2015 Landed 9.625" Casing 5235' MD, 4184' TVD 08 Mar 2015 TD Intermediate Hole Section 5248' MD, 4183' TVD Off Bot: 09:48 05 Mar 2015 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) WELL NAME:LOCATION: OPERATOR:AREA: SPERRY JOB:STATE: RIG:HOLE SECTION: EMPLOYEE NAME:DATE: Sperry Drilling Confidential Document v 3.0 Our ROP was much faster than expected and completed surface sooner than anticipated. Qugruk 301 Repsol E&P USA Inc. AK-XX-0902062414 Nabors 105AC Ryan Lenberg Colville River North Slope Borough Alaska Surface 21-Feb-2015 What went as, or better than, planned: Difficulties experienced: 1. Clay clogging up the gas trap. 2. Sample catcher bucket froze samples constantly. 3. Total gas analyzer required full restarts after we shut down the sample pressure to clean the clogged trap. 4. Clay rich samples clogged up the sieves on our sample drying vacuum, which caused inefficient and long sample drying times. Recommendations: During connections while drilling in clay rich formations; we should shut down trap and spray water through the mud exhaust to minimize clay build up inside the unit. Which will reduce loss of gas data while drilling due to clogged exhaust ports. The sieves used on our sample drying device need to be cleaned and rotated frequently, so multiple sieves are neccesary. Innovations and/or cost savings: N/A Surface Data Logging After Action Review Surface Data LoggingCONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) WELL NAME:LOCATION: OPERATOR:AREA: SPERRY JOB:STATE: RIG:HOLE SECTION: EMPLOYEE NAME:DATE: Sperry Drilling Confidential Document v 3.0 Difficulties experienced: We experience a lot moisture in the sample lines and the overall gas gear system. This can be detrimental to our gear over time if the lines are not blown out during each connection or a couple of times in hour. Recommendations: We have ordered some wire mesh to put in the dropout jar to help us remove as much moisture as possible from the sample line. Hopefully this will help us eliminate moisture from getting to the THC and the gas gear. Innovations and/or cost savings: N/A Nabors 105AC Andrew Bongard Colville River North Slope Borough Alaska Intermediate 8-Mar-2015 What went as, or better than, planned: The supersaul and vacuum proved to be an effective means of cleaning and drying the samples. Qugruk 301 Repsol E&P USA Inc. AK-XX-0902062414 Surface Data Logging After Action Review Surface Data LoggingCONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) WELL NAME:LOCATION: OPERATOR:AREA: SPERRY JOB:STATE: RIG:HOLE SECTION: EMPLOYEE NAME:DATE: Sperry Drilling Confidential Document v 3.0 Difficulties experienced: The ROP was higher then we expected and as a result we started catching 60ft samples. We still had some mosture in the gas lines. Recommendations: A conex on location for storage would be very useful for storing samples. Innovations and/or cost savings: N/A Nabors 105AC Production Rebecca Mulkey 20-Mar-2015 What went as, or better than, planned: There were no major problems with equipment and no safety incidents. Everyone completed their jobs to the best of their abilities. Qugruk 301 Colville River Repsol E&P USA Inc.North Slope Borough AK-XX-0902062414 Alaska Surface Data Logging After Action Review Surface Data LoggingCONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) WELL NAME:Qugruk 301 LOCATION:Colville River OPERATOR:Repsol E&P USA Inc.AREA:North Slope Borough MUD CO:Baroid STATE:Alaska RIG:Nabors 105AC SPUD:18-Feb-2015 SPERRY JOB:AK-XX-0902062414 TD:17-Mar-2015 Marker MD INC AZ TVD TVDSS Base of Permafrost 1,090.0 1.3 162.9 1,090.0 -1,053.0 Upper Schrader Bluff 930.0 1.2 174.2 930.0 -893.0 Middle Schrader Bluff 1,652.0 0.5 137.5 1,652.0 -1,615.0 MCU / Lower Schrader Bluff 2,023.0 0.6 139.6 2,023.0 -1,986.0 Lower Schrader Bluff MFS 2,223.0 1.6 356.0 2,223.0 -2,186.0 Tuluvak 2,455.0 7.2 349.7 2,454.0 -2,417.0 Nanushuk 4,042.0 52.7 17.1 3,814.0 -3,777.0 Nanushuk Target 4,631.0 73.0 19.9 4,091.0 -4,054.0 Formation Tops CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Well Name:Depth (MD) to ft Location:(TVD) to ft Operator: Report Prepared By:Formation: Report Delivered To:Date: Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Show Report Report # 01 Qugruk 301 4076 4079 Coville High Basin 3834 3836 Repsol E&P USA Inc. Michael LaDouceur Nanunsuk Repsol E&P USA Inc.3/3/2015 Interpretation: CLAYSTONE: dark grey to light grey, firm, sub-platy, very finely laminated, silty. SILTSTONE: grey to light brown, soft, consolidated with a trace of shale fragments. Cuttings Analysis: Odor Slight Fluorescence Cut Fluorescence Residual Cut Amount None Distribution Even Intensity Dull Color Stain Amount Moderate Type Very Slow Amount Color Intensity Bright Color Bluish White Residual Flourescence None Oil Show Rating Free Oil in Mud None Color Bluish White Color Cut Color Light Yellow Intensity None 107007 48387 58620 20 1 Hydrocarbon Ratios 4076 Gas Units 612 Mud Chlorides (mg/L) =N/A 594 225 369 771 4839 1861 2978 48 1974 744 1230 159 2 129 53 76 129455 48387 81068 20 6015 1861 4154 50 4077 Gas Units 810 Mud Chlorides (mg/L) =N/A 2372 744 1628 164 720 225 495 795 155 53 102 Oil Gas NPH NPH 1 10 100 1000 Oil Gas NPH NPHCONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 =C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Hydrocarbon Ratios N/A 126484 48387 78097 20 3 5778 1861 3917 51 2274 744 1530 168 4078 Gas Units 808 Mud Chlorides (mg/L) = 4 4079 Gas Units 529 Mud Chlorides (mg/L) = 691 225 466 630 152 28 124 N/A 99525 48387 51138 20 4459 1861 2598 49 123 53 70 1781 744 1037 161 543 225 318 731 NPH Oil Gas NPH 1 10 100 1000 NPH Oil Gas NPH CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Well Name:Depth (MD) to ft Location:(TVD) to ft Operator: Report Prepared By:Formation: Report Delivered To:Date: Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Show Report Report # 02 Qugruk 301 4635 4660 Colville High Basin 4091 4102 Repsol, E&P USA Inc. Michael LaDouceur Nanushuk Repsol, E&P USA Inc.3/4/2015 Interpretation: CLAYSTONE: dark grey to light grey, laminated, firm, blocky, trace silt. SILTSTONE: grey to light brown,firm, laminated, consolidated, arenaceous. SANDSTONE: clear, translucent to transparent, brown, milky, frm to hrd, fine to very fine, spherical to sub spherical, sub rounded to rounded, well sorted, weak calcareous cement, moderate consolidation, with common black lithics. Cuttings Analysis: Odor slight Fluorescence Cut Fluorescence Residual Cut Color light brown Intensity low Color pale Blueish white Residual Flourescence Amount Moderate Distribution even Intensity Dull Color Stain Amount slight Type slow streaming Amount Oil Show Rating Free Oil in Mud Color Pale Blueish white Color Cut Color yellow Intensity None 31703 14867 16836 21 1 Hydrocarbon Ratios 4635 Gas Units 330 Mud Chlorides (mg/L) =N/A 156 92 64 990 1356 572 784 73 480 249 231 263 2 51 34 17 137011 14867 122144 23 6000 572 5428 71 4647 Gas Units 1338 Mud Chlorides (mg/L) =N/A 1959 249 1710 243 594 92 502 912 168 34 134 Oil Gas NPH NPH 1 10 100 1000 Oil Gas NPH NPHCONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 =C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Hydrocarbon Ratios N/A 124898 14867 110031 22 3 5667 572 5095 71 1795 249 1546 238 4652 Gas Units 1221 Mud Chlorides (mg/L) = 4 4660 Gas Units 1022 Mud Chlorides (mg/L) = 555 92 463 803 155 18 137 N/A 104892 14867 90025 22 4730 572 4158 69 142 34 108 1561 249 1312 231 481 92 389 834 NPH Oil Gas NPH 1 10 100 1000 NPH Oil Gas NPH CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Well Name:Depth (MD) to ft Location:(TVD) to ft Operator: Report Prepared By:Formation: Report Delivered To:Date: None Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Show Report Report # 03 Qugruk 301 5130 5155 Coville High Basin 4183 4184 Repsol, E&P USA Inc. Michael LaDouceur Nanushuk Repsol E&P USA Inc.3/6/2015 Interpretation: CLAYSTONE: dark grey to light grey, laminated, firm, blocky, trace silt. SILTSTONE : black, grey to light brown, firm, laminations, consolidated, arenaceous. SANDSTONE:clear, transparent to translucent, milky, light to medium brown staining, soft, very fine to fine, spherical to sub spherical, round to sub rounded, moderatly to well sorted, moderatly consolidated, weak calcareous cement, common black lithics. Cuttings Analysis: Odor Slight Fluorescence Cut Fluorescence Residual Cut Amount Low Distribution Even Intensity Moderate Color Stain Amount 70%Type Slow Amount Color Light Brown Intensity Weak Color Buish White Residual Flourescence None Oil Show Rating Free Oil in Mud None Color Bluish White Color Cut Color Light Yellow Intensity 103267 17725 85542 26 1 Hydrocarbon Ratios 5130 Gas Units 1034 Mud Chlorides (mg/L) =N/A 653 315 338 891 4590 1260 3330 76 1806 675 1131 253 2 233 137 96 131958 17725 114233 25 5838 1260 4578 74 5142 Gas Units 1316 Mud Chlorides (mg/L) =N/A 2227 675 1552 240 790 315 475 865 269 137 132 Oil Gas NPH NPH 1 10 100 1000 Oil Gas NPH NPHCONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 =C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Hydrocarbon Ratios N/A 132612 17725 114887 26 3 5744 1260 4484 74 2238 675 1563 244 5143 Gas Units 1338 Mud Chlorides (mg/L) = 4 5155 Gas Units 1070 Mud Chlorides (mg/L) = 785 315 470 877 268 137 131 N/A 106422 17725 88697 23 5188 1260 3928 70 253 137 116 1943 675 1268 227 705 315 390 765 NPH Oil Gas NPH 1 10 100 1000 NPH Oil Gas NPH CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Well Name:Depth (MD) to ft Location:(TVD) to ft Operator: Report Prepared By:Formation: Report Delivered To:Date: None Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Show Report Report # 04 Qugruk 301 5436 5437 Coville High Basin 4182 4183 Repsol, E&P USA Inc. Beverly Hur Nanushuk Repsol E&P USA Inc.3/18/2015 Interpretation: SILTSTONE : Light to medium gray brown, firm to moderately soft, earthy texture, trace very fine carbonaceous laminations, very argillaceous in part, grades to very fine sandstone in places. SANDSTONE: Light brown to brown grey in part, poorly consolidated quartz grains, very fine grained to lower fine grained, sub rounded, well sorted, minor to moderate calcareous argillaceous cement, traces of very fine carbonaceous laminations. 8- 10% intergranular porosity. SHOW: 30% patchy to even light brown staining, 70% even dark yellow fluorescence, pale blue white blush cut. Cuttings Analysis: Odor Slight Fluorescence Cut Fluorescence Residual Cut Color Light Brown Intensity W eak Color Buish White Residual Flourescence None Amount Low Distribution Even Intensity Moderate Color Stain Amount 70%Type Slow Amount Oil Show Rating Free Oil in Mud None Color Bluish White Color Cut Color Dark Yellow Intensity 54992 27814 27178 45 1 Hydrocarbon Ratios 5446 Gas Units 1034 Mud Chlorides (mg/L) =N/A 152 112 40 3883 1913 1314 599 167 554 391 163 679 2 36 29 7 54992 27814 27178 45 1913 1314 599 167 5446 Gas Units 1316 Mud Chlorides (mg/L) =N/A 554 391 163 679 152 112 40 3883 36 29 7 Oil Gas NPH NPH 1 10 100 1000 Oil Gas NPH NPHCONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 =C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Hydrocarbon Ratios N/A 54992 27814 27178 45 3 1913 1314 599 167 554 391 163 679 5446 Gas Units 1338 Mud Chlorides (mg/L) = 4 5446 Gas Units 1070 Mud Chlorides (mg/L) = 152 112 40 3883 36 29 7 N/A 54992 27814 27178 45 1913 1314 599 167 36 29 7 554 391 163 679 152 112 40 3883 NPH Oil Gas NPH 1 10 100 1000 NPH Oil Gas NPH CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Well Name:Depth (MD) to ft Location:(TVD) to ft Operator: Report Prepared By:Formation: Report Delivered To:Date: None Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production 44 57 -13 438 623 -185 244 141 196 -55 1032 26996 40406 -13410 23 1288 1863 -575 72 5901 Gas Units 1316 Mud Chlorides (mg/L) =N/A 2 44 57 -13 141 196 -55 1032 1288 1863 -575 72 438 623 -185 244 26996 40406 -13410 23 1 Hydrocarbon Ratios 5901 Gas Units 1034 Mud Chlorides (mg/L) =N/A Oil Show Rating Free Oil in Mud None Color yellow Color Cut Color Dark Yellow Intensity Color Light Brown Intensity Faint Color Yellow Residual Flourescence None Amount Low Distribution Patchy Intensity Moderate Color Stain Amount 10%Type Fast Amount Cuttings Analysis: Odor Slight Fluorescence Cut Fluorescence Residual Cut Beverly Hur Nanushuk Repsol E&P USA Inc.3/18/2015 Interpretation: SILTSTONE : Light to medium gray brown, firm to moderately soft, earthy texture, very argillaceous in part, grades to very fine sandstone in places. SANDSTONE: Light brown to brown grey in part, poorly consolidated to unconsolidated, very fine grained to lower fine grained, trace medium grained, sub rounded, well sorted, minor to moderate calcareous argillaceous cement, trace of calcite nodules. 8-10% intergranular porosity. SHOW: 30% patchy to even light brown staining, 10% dark yellow patchy fluorescence, faint yellow streaming fast cut. Show Report Report # 05 Qugruk 301 5901 5901 Coville High Basin 4177 4178 Repsol, E&P USA Inc. Oil Gas NPH NPH 1 10 100 1000 Oil Gas NPH NPHCONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 =C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons 44 57 -13 438 623 -185 244 141 196 -55 1032 N/A 26996 40406 -13410 23 1288 1863 -575 72 4 5901 Gas Units 1070 Mud Chlorides (mg/L) = 141 196 -55 1032 44 57 -13 1288 1863 -575 72 438 623 -185 244 5901 Gas Units 1338 Mud Chlorides (mg/L) =N/A 26996 40406 -13410 23 3 Hydrocarbon Ratios NPH Oil Gas NPH 1 10 100 1000 NPH Oil Gas NPH CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Well Name:Depth (MD) to ft Location:(TVD) to ft Operator: Report Prepared By:Formation: Report Delivered To:Date: None Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production 116 91 25 815 590 225 209 307 231 76 636 45206 29314 15892 26 2148 1530 618 71 7338 Gas Units 1316 Mud Chlorides (mg/L) =N/A 2 116 91 25 307 231 76 636 2148 1530 618 71 815 590 225 209 45206 29314 15892 26 1 Hydrocarbon Ratios 7338 Gas Units 1034 Mud Chlorides (mg/L) =N/A Oil Show Rating Free Oil in Mud None Color yellow Color Cut Color Dark Yellow Intensity Color Light Brown Intensity Faint Color Blue White Residual Flourescence None Amount Low Distribution Even Intensity Moderate Color Stain Amount 40%Type Slow Amount Cuttings Analysis: Odor Slight Fluorescence Cut Fluorescence Residual Cut Beverly Hur Nanushuk Repsol E&P USA Inc.3/18/2015 Interpretation: SILTSTONE : Light to medium gray brown, firm to moderately soft, trace very fine carbonaceous laminations, earthy texture, very argillaceous in part, grades to very fine sandstone in places. SANDSTONE: Light brown to brown grey in part, poorly consolidated clear to frosted quartz grains, very fine grained to lower fine grained, sub rounded, well sorted minor to moderate calcareous argillaceous cement, occasional traces of very fine carbonaceous laminations. 8 to 12% intergranular porosity. SHOW: 20% patchy to even light brown staining, 40% dull dark yellow even fluorescence, faint blue white streaming slow cut. Show Report Report # 06 Qugruk 301 7338 7338 Coville High Basin 4150 4150 Repsol, E&P USA Inc. Oil Gas NPH NPH 1 10 100 1000 Oil Gas NPH NPHCONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft C1 C1 C1 C1 .C2 C3 C4 C5 Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 =C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons Depth ft . Flowline Background Show ppm ppm ppm Hydrocarbon Ratios C1 -=C1/C2 = C2 -=C1/C3 = C3 -=C1/C4 = C4 -=C1/C5 = C5 -= Production Analysis Gas Oil Water Non-Producible Hydrocarbons 116 91 25 815 590 225 209 307 231 76 636 N/A 45206 29314 15892 26 2148 1530 618 71 4 7338 Gas Units 1070 Mud Chlorides (mg/L) = 307 231 76 636 116 91 25 2148 1530 618 71 815 590 225 209 7338 Gas Units 1338 Mud Chlorides (mg/L) =N/A 45206 29314 15892 26 3 Hydrocarbon Ratios NPH Oil Gas NPH 1 10 100 1000 NPH Oil Gas NPH CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Qugruk 301 Repsol E&P USA Inc. Baroid Nabors 105AC AK-XX-0902062414 Date Depth Wt Vis PV YP Gels Filt R600/R300/R200/R100/ R6/R3 Cake Solids Oil/Water Sd Pm pH MBT Pf/Mf Chlor Hard ft - MD ppg sec lb/100 lb/100ft2 m/30m Rheometer 32nds %%%ppb Eqv mg/l Ca++ 17-Feb 98 9.80 80 27 26 9/21/32 7.5 80/53/42/28/9/8 2/0 6.8 0.5/92.5 N/A 0.50 9.9 20.0 0.01/0.15 600 40 Circulate and Condition Mud 18-Feb 902 9.92 90 32 31 21/50/71 8.2 95/63/50/35/17/16 3/0 7.8 0.5/91.5 1.00 0.60 10.0 20.0 0.30/0.65 800 40 Drill Ahead 19-Feb 2115 10.00 96 22 28 30/70/87 7.5 72/50/42/33/23/22 4/0 10.7 0.5/88.5 3.00 0.60 9.8 27.5 0.15/0.50 1200 80 Lay down BHA 20-Feb 2115 10.00 63 18 21 23/55/74 7.8 57/39/33/25/17/16 4/0 10.7 0.5/88.5 3.00 0.65 9.8 27.5 0.15/0.60 1300 80 Run Casing 21-Feb 2115 10.00 65 21 16 14/39/54 6.4 58/37/31/22/10/9 6.4 10.7 0.5/88.5 3.00 0.70 10.3 27.5 0.20/0.75 1500 120 Rig down cementers 22-Feb 2115 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Nipple up/down Diverter System 23-Feb 2115 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Nipple up BOP 24-Feb 2115 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Nipple up BOP Date Depth Wt Vis PV YP Gels HTHP R600/R300/R200/R100/ R6/R3 Cake Solids Oil/Water Alka POM Excess Lime Elec Stab CaCl2 WPS LGS/HGS ASG Remarks ft - MD ppg sec lb/100 lb/100ft2 m/30m Rheometer 32nds %%ml ppb volts ppb ppm ppb ASG 25-Feb 2115 10.4 93 38 14 8/15/17 N/A 90/52/38/23/5/4 N/A 12.2 68.5/17.0 7.0692 9.19 466 27.62 326386 44.78/101.79 3.435 Nipple up BOP 26-Feb 2115 10.4 78 39 14 6/14/17 4.0 92/53/39/24/5/4 0/2 12.2 67.5/18.0 7.9692 10.36 498 28.59 313562 38.48/112.30 3.517 Testing BOPs 27-Feb 2115 10.4 79 36 14 5/12/14 3.2 86/50/36/22/5/4 0/2 12.1 68.5/17.0 6.9769 9.07 460 29.56 336450 35.60/114.42 3.547 Make-up BHA 28-Feb 2115 10.3 141 33 13 6/12/15 3.8 79/46/34/21/5/4 2/0 12.3 68.5/17 3.9846 5.18 375 27.44 315312 45.48/103.11 3.434 TIH/Wait on weather 1-Mar 2145 10.4 100 36 14 6/14/18 3.6 86/50/37/23/6/4 0/2 12.2 67.0/18.5 3.9846 5.18 564 18.88 290517 34.19/118.54 3.57 Rig Down FIT 2-Mar 3475 10.34 73 31 13 5/11/14 3.2 75/44/32/19/5/4 0/2 13 67.5/15.7 4.4846 5.83 595 20.82 288716 46.15/110.58 3.453 Circulate Bottoms Up 3-Mar 4084 10.4 73 31 13 5/11/14 3.6 75/44/32/19/5/4 0/2 13.6 80.5/19.5 4.4846 5.83 547 20.82 288525 52.83/109.53 3.404 Circulate/ wait on weather 4-Mar 4834 10.45 73 36 14 6/17/22 3.8 86/50/37/23/5/4 0/2 14 81.4/18.6 2.9846 3.88 707 19.85 286163 54.81/112.42 3.4 Drill 12.625" hole 5-Mar 5248 10.4 74 30 15 6/17/23 3.8 75/45/34/21/6/5 0/2 14 83.1/16.9 3.4846 4.53 660 19.85 307108 56.18/109.95 3.384 TOOH 6-Mar 5248 10.4 98 33 16 7/19/24 4.0 82/49/36/24/6/5 0/2 14.4 83.1/16.9 3.9846 5.18 659 19.85 292888 62.24/105.90 3.335 Rig Up to run 9 5/8" casing 7-Mar 5248 10.4 84 30 16 8/22/31 3.8 84/50/37/247/5 0/2 14.2 83/17 4.4846 5.83 660 17.91 292466 58.55/109.14 3.367 TIH 9 5/8" casing 8-Mar 5248 10.4 144 33 15 8/23/31 4.0 81/48/36/23/6/5 0/2 14.2 83/17 3.9846 5.18 668 15.97 296677 59.53/108.17 3.358 wait on cement 9-Mar 5248 9.85 82 29 17 9/17/24 4.0 75/46/34/22/6/5 0/2 11.3 80.5/17 3.9846 5.18 668 15.97 258949 43.75/90.72 3.404 Test BOP 10-Mar 5248 9.3 86 28 16 8/20/24 3.6 72/44/32/20/6/5 0/2 9.4 80.7/19.3 3.9846 5.18 815.0 15.0 258297 48.53/57.60 3.21 Test BOP 11-Mar 5248 9.3 84 26 16 8/19/23 3.6 68/42/31/20/6/5 0/2 9.2 80.3/19.7 3.9846 5.18 760.0 16.9 259471 45.89/58.79 3.236 Test BOP/pick up BHA 12-Mar 5248 9.3 96 28 15 8/19/24 3.6 71/43/33/21/6/5 02 9.0 80.6/17.3 3.9846 5.18 695.0 16.9 268122 42.64/61.17 3.276 Test BPO/TIH 13-Mar 5248 9.35 99 28 15 7/18/24 3.8 71/43/31/19/6/5 0/2 9.3 80.9/19.1 4.4846 5.83 610.0 17.9 257999 42.99/64.9 3.293 Pressure testing 14-Mar 5278 9.3 95 26 15 7/16/23 3.6 67/41/30/18/5/4 0/2 9.2 82.9/17.1 2.5923 3.37 720 14.51 259501 38.5/69.73 3.357 Wait on wireline 15-Mar 5278 9.35 95 26 15 6/17/22 3.4 67/41/30/19/6/5 0/2 8.9 82.4/17.6 3.7846 4.92 768 15.5 260063 30.20/78.42 3.479 TIH 16-Mar 6734 9.35 97 30 18 10/25/34 3.8 78/48/37/24/8/7 0/2 9.7 83.1/16.9 4.1846 5.44 734 16.5 269039 45.5/65.8 3.278 Drill 6 1/8" hole 17-Mar 7531 9.4 95 28 20 11/26/35 3.8 76/48/37/25/8/7 0/2 10.0 83.1/16.9 4.3846 5.70 723 16.5 261624 47.68/67.15 3.269 Circulate/TOOH 18-Mar 7531 9.40 110 28 20 11/25/34 3.4 76/48/37/24/8/7 0/2 9.5 83.1/16.9 3.9846 5.18 735 16.5 261624 37.3/76.12 3.398 Test BOP 19-Mar 7531 9.40 100 28 20 11/25/34 3.4 76/48/37/24/8/7 0/2 9.5 83.1/16.9 3.9846 5.18 730 16.0 261891 36.85/76.54 3.404 TOOH 20-Mar 7531 9.40 110 25 9 4/4/4 3.4 59/34/25/15/4/3 0/2 2.6 50.0/50.0 2.9846 3.88 195 85.9 361947 23.73/.03 2.599 TIH 4 1/2" liner 21-Mar 7531 9.40 105 29 14 8/218/28 3.8 72/43/33/20/6/5 0/2 7.9 68.0/21.0 3.9846 5.18 480 34.4 337552 37.7/52.83 3.267 TOOH lay down 5" drill pipe 22-Mar 7531 9.40 107 29 14 8/20/27 3.8 72/43/33/21/6/5 0/2 7.9 76.4/23.6 3.7846 4.92 455 34.4 337552 37.7/52.83 3.267 TIH with Compleation string 23-Mar 7531 9.40 109 29 14 8/21/28 3.8 72/43/33/20/6/5 0/2 7.9 68.0/21.0 3.7846 4.92 440 34.4 337552 37.7/52.83 3.267 Land Tubing 24-Mar 7531 9.40 135 30 16 8/23/31 4.0 76/46/36/23/7/5 0/2 8.2 69.5/19.5 3.6846 4.79 416 31.5 335522 36.7/57.84 3.308 Test Frac BOP 25-Mar 7531 9.40 139 31 16 8/23/31 3.8 78/47/35/22/6/5 0/2 8.2 69.5/19.5 3.7846 4.92 520 30.53 331230 36.81/58.38 3.311 Pressure Test Frac Lines 26-Mar 7531 9.40 140 30 16 8/23/31 3.8 76/46/36/24/6/5 0/2 8.2 69.5/19.5 3.7846 4.92 525 31.50 335522 36.70/57.84 3.308 Prepare for Frac Program 27-Mar 7531 9.40 130 31 16 8/23/31 4.0 78/47/36/22/7/5 0/2 8.2 69.5/19.5 3.7846 4.92 500 31.50 335522 36.70/57.84 3.308 Prepare to Flow Back Well 28-Mar 7531 9.40 130 31 16 8/23/31 4.0 78/47/35/22/6/5 0/2 8.2 69.5/19.5 3.7846 4.92 670 31.50 335079 36.79/57.81 3.307 Flow Test the Well 29-Mar 7531 9.40 115 30 16 7/22/29 4.0 76/46/34/22/6/5 0/2 8.3 69.5/19.5 3.7846 4.92 390 29.56 327013 36.89/58.94 3.313 Flow Test the Well Remarks WELL NAME:LOCATION:Colville River OPERATOR:AREA:North Slope Borough MUD CO:STATE:Alaska RIG:SPUD:18-Feb-2015 SPERRY JOB:TD:17-Mar-2015 Water and Oil Based Mud Record CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) Qugruk 301 Repsol E&P USA Inc. Baroid Nabors 105AC AK-XX-0902062414 Date Depth Wt Vis PV YP Gels HTHP R600/R300/R200/R100/ R6/R3 Cake Solids Oil/Water Alka POM Excess Lime Elec Stab CaCl2 WPS LGS/HGS ASG Remarks ft - MD ppg sec lb/100 lb/100ft2 m/30m Rheometer 32nds %%ml ppb volts ppb ppm ppb ASG 30-Mar 7531 9.40 129 32 16 8/23/31 4.0 80/48/36/23/6/5 0/2 8.3 69.5/19.5 3.7846 4.92 510 29.56 327013 36.89/58.94 3.313 Flow Test the Well 31-Mar 7531 9.40 126 31 16 7/22/29 4.0 78/47/36/23/6/5 0/2 8.3 69.5/19.5 3.7846 4.92 400 29.56 327013 36.89/58.94 3.313 Flow Test the Well 1-Apr 7531 9.40 130 31 16 7/22/28 4.0 78/47/36/22/6/5 0/2 8.3 69.5/19.5 3.7846 4.92 420 29.56 327013 36.89/58.94 3.313 Flow Test the Well 2-Apr 7531 9.40 130 31 15 7/22/28 4.0 77/46/35/22/6/5 0/2 8.3 69.5/19.5 3.7846 4.92 350 29.56 327013 36.89/58.94 3.313 Flow Test the Well 3-Apr 7531 9.40 133 33 16 7/22/28 4.0 82/49/37/23/6/5 0/2 8.3 69.5/19.5 3.7846 4.92 350 29.56 327013 36.89/58.94 3.313 Flow Test the Well 4-Apr 7531 9.40 128 30 17 7/22/28 4.0 77/47/36/23/6/5 0/2 8.3 69.5/19.5 3.7846 4.92 365 29.56 327013 36.89/58.94 3.313 Flow Test the Well 5-Apr 7531 9.40 125 31 16 7/22/28 4.0 78/47/36/23/6/5 0/2 8.3 69.5/19.5 3.7846 4.92 350 29.56 327013 36.89/58.94 3.313 Flow Test the Well 6-Apr 7531 9.40 136 31 16 7/22/29 4.0 78/47/36/23/6/5 0/2 8.2 68.5/20.5 3.7846 4.92 500 29.56 320900 33.78/62.74 3.366 Flow Test the Well 7-Apr 7531 9.40 134 31 16 7/22/28 4.0 78/47/36/23/6/5 0/2 8.2 68.5/20.5 3.7846 4.92 463 29.56 320900 33.78/62.74 3.366 Flow Test the Well 8-Apr 7531 9.40 136 31 16 7/22/29 4.0 78/47/36/23/6/5 0/2 8.2 68.5/20.5 3.7846 4.92 422 29.56 320900 33.78/62.74 3.366 Flow Test the Well 9-Apr 7531 9.40 140 31 16 7/22/28 3.8 78/47/36/23/6/5 0/2 8.2 68.5/20.5 3.7846 4.92 463 29.56 320900 33.78/62.74 3.366 Flow Test the Well 10-Apr 7531 9.40 139 31 16 7/22/29 4.0 78/47/36/23/6/5 0/2 8.2 68.5/20.5 3.9846 5.18 452 29.56 320900 33.78/62.74 3.366 Flow Test the Well 11-Apr 7531 9.40 157 30 16 6/15/21 4.0 76/46/34/21/5/4 0/2 8.3 68.0/21.0 3.9846 5.18 590 24.71 300751 37.58/58.80 3.306 Flow Test the Well 12-Apr 7531 9.40 159 30 16 6/15/22 4.0 76/46/34/21/5/4 0/2 8.3 68.0/21.0 3.9846 5.18 582 24.71 300751 37.58/58.80 3.306 Shut in the Well 13-Apr 7531 9.40 158 30 16 6/15/21 4.0 76/46/34/21/5/4 0/2 8.3 68.0/21.0 3.985 5.18 570 24.71 300751 37.58/58.80 3.306 Shut in the Well 14-Apr 7531 9.40 160 30 16 6/15/22 4.0 76/46/34/21/5/4 0/2 8.3 68.0/21.0 3.985 5.18 576 24.71 300751 37.58/58.80 3.306 Flow Test the Well 15-Apr 7531 9.40 158 30 16 6/15/22 4.0 76/46/34/21/5/4 0/2 8.3 68.0/21.1 3.985 5.18 560 24.71 300751 37.58/58.80 3.306 Bullheaded the well 16-Apr 7531 9.40 153 24 14 6/13/16 4.4 62/38/27/17/5/4 0/2 7.6 62.0/27.0 3.985 4.92 304 40.24 310653 46.32/35.08 3.062 Pumped and squeezed pill 17-Apr 7531 10.40 157 25 12 7/1/14 4.0 62/37/27/17/5/4 2 10.2 63.0/24.0 3.985 5.18 307 35.38 297840 26.94/104.47 3.666 TOOH/TIH Casing Record 20" Conductor @ 98' MD, 98'TVD 13.375" Casing @ 2107' MD, 2107'TVD 9.625" Casing @ 5235' MD, 4184'TVD 4.5" Liner @ 7531' MD, 4146'TVD WELL NAME:LOCATION:Colville River OPERATOR:AREA:North Slope Borough MUD CO:STATE:Alaska RIG:SPUD:18-Feb-2015 SPERRY JOB:TD:17-Mar-2015 Water and Oil Based Mud Record CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) BHA#SDL RUN #Bit #Bit Type Bit Size Depth In Depth Out Footage Bit Hours TFA AVG ROP WOB (max) RPM (max) SPP (max) FLOW GPM (max)Bit Grade Comments 1 100 1 VM-3 Milltooth 16.00 98 2115 2017 20.18 0.942 100.0 41.4 80 1495 600 1-1-WT-A-E/E/E-IN-NO-TD Surface section 2 200 2 NOV SKH519M-A7C 12.25 2115 5248 3133 47.54 0.796 55.2 24.1 142 1818 612 1-2-CT-A-X-I-WT-TD Intermediate section 3 300 3 VM-3 Milltooth 8.50 5248 5278 30 7.50 0.942 40.0 28.8 50 1087 408 1-1-WT-A-E-NO-TD Clean out run 4 300 4 NOV SKH513M 6.50 5278 7531 2253 21.25 0.354 92.8 76.1 120 2548 382 1-1-BU-A-X-I-BT-TD Production section 5 330 5 5 3/4" Z 5.75 7531 7531 0 --------Clean out run Alaska RIG:Nabors 105AC SPUD:18-Feb-2015 WELL NAME:Qugruk 301 LOCATION:Colville River OPERATOR:Repsol E&P USA Inc.AREA:North Slope Borough MUD CO: SPERRY JOB:AK-XX-0902062414 TD:17-Mar-2015 Baroid STATE:Bit Record CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) . . * 24 hr Recap:Pick-up BHA, make-up bit, motor, stabilizer, cross-over, 1 stand of HWDP. Fill hole with spud mud. Ciculate and Density (ppg) out (sec/qt) Viscosity Cor Solids %mg/l 600.00 N/A N/A Current Pump & Flow Data: 315 Max Condition Rig: ROP ROP (ft/hr) 3.14 @ Mud Data Depth MWD Summary 95% Rig Activity: Report For: Morning Report Report # 1 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: 6.8 Size Job No.: Daily Charges: Total Charges: Chlorides WOB 100% Gas In Air=10,000 UnitsN/AConnection Avg Min Comments RPM ECD (ppg) ml/30min Tools API FL (max)Trip N/AN/ABackground Lst Type (lb/100ft2) Bit Type 7.526 Depth in / out 98' 9.90 N/AN/A N/A CementChtSilt C-4i C-4n Chromatograph (ppm) 24 hr Max Weight N/A Hours C-3 Gas Summary (current) Footage ShClyst Tuff C-5n GvlCoal Avg to98' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Max @ ft Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC S. Self / J. Mckinley 3:00 AM 98' 98' 0' Repsol E&P USA Inc.AK-AM-0902062414 Circ. and Cond. Mud 18-Feb-2015 Time: condition mud. Repair diverter system. Prepare to spud the well. N/A N/A N/A VM-3 Milltooth Bit in Minimum Depth C-2C-1 C-5i N/AN/A SPP (psi) Gallons/stroke TFA Depth 20.080 (ppb Eq)cP 1 16 MBT 98' pH N/A PV YP N/AN/A N/A Gamma/Resistivity Spud 9.809.80 27 Mud Type 440 140 Units* Casing Summary Lithology (%) 98' Bit # 0.942 Grade N/A R. Lenberg / A. Bongard A. Bongard N/AAverage N/A N/A N/AN/A N/A N/A N/A N/A (907) 685-3276Unit Phone: N/AMaximum Report By:Logging Engineers: 131.0 J-5520.00''Conductor80' Set AtSize SiltstSs N/AN/A N/A (max) N/A (current) N/A N/A Cly N/A . . * 24 hr Recap:Drill ahead from 98' to 225'. Trip out of hole, blow down top drive, and pick up remaining BHA. Drill ahead from 225' Density (ppg) out (sec/qt) Viscosity Cor Solids %mg/l 800.00 0 0 Current Pump & Flow Data: 1269 Max Condition Rig: ROP ROP (ft/hr) 3.14 @ Mud Data Depth MWD Summary 95% Rig Activity: Report For: Morning Report Report # 2 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: 7.8 Size Job No.: Daily Charges: Total Charges: Chlorides WOB ahead from 462' to 902'. 100% Gas In Air=10,000 UnitsN/AConnection 10 Avg Min Comments RPM ECD (ppg) ml/30min Tools API FL (max)Trip N/A188Background Lst 70 Type (lb/100ft2) Bit Type 8.231 Depth in / out 98' 10.00 000 CementChtSilt C-4i C-4n Chromatograph (ppm) 20 24 hr Max Weight 23 Hours C-3 Gas Summary (current) Footage ShClyst Tuff C-5n GvlCoal Avg to98' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Max @ ft Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC S. Self / J. Mckinley 3:00 AM 98' 902' 804' Repsol E&P USA Inc.AK-AM-0902062414 Drill Ahead 19-Feb-2015 Time: to 462'. Circulate mud while working on Mud Pump #2. Short trip, rack-back 1 stand and make-up jars. Ream to bottom and drill 48 N/A N/A VM-3 Milltooth Bit in Minimum Depth C-2C-1 C-5i 00 SPP (psi) Gallons/stroke TFA Depth 20.090 (ppb Eq)cP 1 16 MBT 935' pH N/A PV YP 331'114.0 377.0 Gamma/Resistivity Spud 9.959.95 32 Mud Type 583 182 Units* Casing Summary Lithology (%) 785' Bit # 0.942 Grade 103.0 R. Lenberg / A. Bongard A. Bongard 5491Average 0 0 00107'0 5 0 (907) 685-3276Unit Phone: 0Maximum Report By:Logging Engineers: 131.0 J-5520.00''Conductor80' Set AtSize SiltstSs 846'205 6 (max) 17 (current) 23 0 Cly 18537 . . * 24 hr Recap:Drill ahead from 1171' MD to 2115' MD. Circulate hole clean. Pull out of hole and lay down BHA. Gas peaks of 7650 Density (ppg) out (sec/qt) Viscosity Cor Solids %mg/l 1200.00 18 53 Current Pump & Flow Data: 0 Max Condition ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Rig Activity: Report For: Morning Report Report # 3 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 10.7 Size Job No.: Daily Charges: Total Charges: Chlorides 2115' 10,000 UnitsN/AConnection 90 70 C-3 Avg Min Comments RPM ECD (ppg) ml/30min Tools API FL (max)Trip N/A0Background Type (lb/100ft2) Bit Type 2017' WOB Hours 80.0 7.528 Depth in / out 41.4 9.80 000 Gas Summary (current) CementChtSiltClyTuff 1 16 24 hr Max Weight 98' MWD Summary ShClyst C-4i C-4n Avg to1171' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger / J. Mckinley 3:00 AM 1171' 2115' 944' Repsol E&P USA Inc.AK-AM-0902062414 Rig up to run casing 20-Feb-2015 Time: u and 9510 u were witnessed at 1188' MD and 1259' MD, respectively. 503 00 N/A VM-3 Milltooth Bit in Minimum Depth C-5i 261 0 N/A C-5n GvlCoal cP C-2C-1 Chromatograph (ppm) Lst PV YP Footage SPP (psi) Gallons/stroke TFA Depth 22 Mud Type MBT 2115' pH N/A 27.596 (ppb Eq) 0.942 Grade N/A 1835'139.8 393.9 Gamma/Resistivity Spud 10.0010.00 (907) 685-3276 Average 0 0 Units* Casing Summary Lithology (%) 2115' Bit # 16 R. Lenberg / A. Bongard A. Bongard 63267 (max) 001120'0 100% Gas In Air= Unit Phone: 0Maximum Report By:Logging Engineers: 0122 10 131.0 J-5520.00''Conductor80' (current) 493 0 509746 Set AtSize SiltstSs 0 1259'9510 . . * 24 hr Recap: 0 N/A247 (current) 45 0 33364 Set AtSize SiltstSs 131.0 J-5520.00''Conductor80' Unit Phone: 0Maximum Report By:Logging Engineers: 010 (max) 00N/A 0 100% Gas In Air= 0 R. Lenberg / A. Bongard A. Bongard 223 (907) 685-3276 Average 0 0 Units* Casing Summary Lithology (%) 2115' Bit # 0.942 Grade N/A N/AN/A N/A Gamma/Resistivity Spud 10.0010.00 18 Mud Type MBT 2115' pH N/A 27.563 (ppb Eq) 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth cP C-2C-1 Chromatograph (ppm) Lst C-5i 18 0 N/A C-5n GvlCoal N/A VM-3 Milltooth Bit in Minimum Depth witnessed. Wash down to 920' MD. Continue to run in hole with casing to 1807' MD. 20 00 C. Cretsinger / J. Mckinley 3:00 AM 2115' 2115' 0' Repsol E&P USA Inc.AK-AM-0902062414 Running Casing 21-Feb-2015 Time: Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC Avg to2115' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) ShClyst C-4i C-4n Tuff 1 16 24 hr Max Weight 98' MWD Summary Gas Summary (current) CementChtSiltCly 9.80 000 80.0 7.821 Depth in / out 41.4 Type (lb/100ft2) Bit Type 2017' WOB Hours (max)Trip N/A0Background Avg Min Comments RPM ECD (ppg) ml/30min Tools API FL 10,000 UnitsN/AConnection 0 C-3 1-1-WT-A-E/E/E-IN-NO-TD 10.7 Size Job No.: Daily Charges: Total Charges: Chlorides 2115' Rig Activity: Report For: Morning Report Report # 4 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Current Pump & Flow Data: 0 Max Condition 0 0 mg/l 1300.00 Finish laying down BHA. Service the top drive. Rig-up to run casing. Run casing in hole to 870' MD; tight hole Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Continue to run in hole with casing. Work tight spot at 1,862' MD. Lost 80 bbls while working through with 65 bbls Density (ppg) out (sec/qt) Viscosity Cor Solids %mg/l 1500.00 0 0 Current Pump & Flow Data: 0 Max Condition ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Rig Activity: Report For: Morning Report Report # 5 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-1-WT-A-E/E/E-IN-NO-TD 10.7 Size Job No.: Daily Charges: Total Charges: Chlorides 2115' 15.8 ppg tail cement (72.3 bbls) without returns. Rig down cementers. Circulate and condition mud. Diverted returns to cellar and pumped additional 60 bbls lead before losing returns. Continued pumping lead (347 bbls total) and cement: 10 bbls fresh water, 81.8 bbls 11 ppg spacer, followed by 180 bbls 10.7 ppg lead before cement observed at shakers. 2107' 10,000 UnitsN/AConnection 0 C-3 Avg Min Comments RPM ECD (ppg) ml/30min Tools API FL (max)Trip 4310Background Type (lb/100ft2) Bit Type 2017' WOB Hours 80.0 6.416 Depth in / out 41.4 10.30 000 Gas Summary (current) CementChtSiltClyTuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary ShClyst C-4i C-4n Avg to2115' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger / J. Mckinley 3:00 AM 2115' 2115' 0' Repsol E&P USA Inc.AK-AM-0902062414 Circ. & Cond. Mud 22-Feb-2015 Time: returned. Continue run in hole and land casing at 2,107' MD. Run in hole with 5" drill pipe and stab into cement stinger. Pump 13 00 N/A VM-3 Milltooth Bit in Minimum Depth C-5i 0 0 N/A C-5n GvlCoal cP C-2C-1 Chromatograph (ppm) Lst 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth 21 Mud Type MBT 2115' pH N/A 27.565 (ppb Eq) 0.942 Grade N/A N/AN/A N/A Gamma/Resistivity Spud 10.0010.00 (907) 685-3276 Average 0 0 Units* Casing Summary Lithology (%) 2115' Bit # 0 R. Lenberg / A. Bongard A. Bongard 1438 (max) 00N/A 0 100% Gas In Air= Surface Unit Phone: 0Maximum Report By:Logging Engineers: 03 131.0 J-5520.00''Conductor80' 13.375" (current) 36 0 58120 Set AtSize SiltstSs 0 N/A431 . . * 24 hr Recap:Circulate surface to surface and displace to OBM. Clear spud mud from mud mix pumps and lines. Pull out of hole. Density (ppg) out (sec/qt) Viscosity Cor Solids %mg/l N/A 0 0 Current Pump & Flow Data: 0 Max Condition ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Rig Activity: Report For: Morning Report Report # 6 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-1-WT-A-E/E/E-IN-NO-TD N/A Size Job No.: Daily Charges: Total Charges: Chlorides 2115' 2107' 10,000 UnitsN/AConnection 0 C-3 Avg Min Comments RPM ECD (ppg) ml/30min Tools API FL (max)Trip N/A0Background Type (lb/100ft2) Bit Type 2017' WOB Hours 80.0 N/AN/A Depth in / out 41.4 N/A 000 Gas Summary (current) CementChtSiltClyTuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary ShClyst C-4i C-4n Avg to2115' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger / J. Mckinley 3:00 AM 2115' 2115' 0' Repsol E&P USA Inc.AK-AM-0902062414 Nipple Up/Down Diverter 23-Feb-2015 Time: Rig up/down for top cement job. Nipple down BOP. Rig down diverter line. Nipple up/down diverter system. 0 00 N/A VM-3 Milltooth Bit in Minimum Depth C-5i 0 0 N/A C-5n GvlCoal cP C-2C-1 Chromatograph (ppm) Lst 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth N/A Mud Type MBT 2115' pH N/A N/AN/A (ppb Eq) 0.942 Grade N/A N/AN/A N/A Gamma/Resistivity N/A N/AN/A (907) 685-3276 Average 0 0 Units* Casing Summary Lithology (%) 2115' Bit # 0 R. Lenberg / A. Bongard A. Bongard 0 (max) 00N/A 0 100% Gas In Air= Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 131.0 J-5520.00''Conductor80' 13.375" (current) 0 0 0 Set AtSize SiltstSs 0 N/A0 . . * 24 hr Recap:Remove annular. Clear cellar area. Pick-up tubing and tag top of cement 34' from top of conductor. Nipple down Density (ppg) out (sec/qt) Viscosity Cor Solids %mg/l N/A 0 0 Current Pump & Flow Data: 0 Max Condition ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Rig Activity: Report For: Morning Report Report # 7 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-1-WT-A-E/E/E-IN-NO-TD N/A Size Job No.: Daily Charges: Total Charges: Chlorides 2115' cement). Pull out 1" pipe, clean lines and cellar. Nipple up BOPs. 2107' 10,000 UnitsN/AConnection 0 C-3 Avg Min Comments RPM ECD (ppg) ml/30min Tools API FL (max)Trip N/A0Background Type (lb/100ft2) Bit Type 2017' WOB Hours 80.0 N/AN/A Depth in / out 41.4 N/A 000 Gas Summary (current) CementChtSiltClyTuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary ShClyst C-4i C-4n Avg to2115' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger / D. Dunbar 3:00 AM 2115' 2115' 0' Repsol E&P USA Inc.AK-AM-0902062414 Nipple up BOPs 24-Feb-2015 Time: BOPs, and remove well head starting head. Rig-up cementer. Make-up 1" pipe, pressure test, and cement top hole (6 bbls 0 00 N/A VM-3 Milltooth Bit in Minimum Depth C-5i 0 0 N/A C-5n GvlCoal cP C-2C-1 Chromatograph (ppm) Lst 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth N/A Mud Type MBT 2115' pH N/A N/AN/A (ppb Eq) 0.942 Grade N/A N/AN/A N/A Gamma/Resistivity N/A N/AN/A (907) 685-3276 Average 0 0 Units* Casing Summary Lithology (%) 2115' Bit # 0 R. Lenberg / A. Bongard A. Bongard 0 (max) 00N/A 0 100% Gas In Air= Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 131.0 J-5520.00''Conductor80' 13.375" (current) 0 0 0 Set AtSize SiltstSs 0 N/A0 . . * 24 hr Recap: 0 N/A0 (current) 0 0 0 Set AtSize SiltstSs 131.0 J-5520.00''Conductor80' 13.375"Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 (max) 00N/A 0 100% Gas In Air= 0 R. Lenberg / A. Bongard A. Bongard 0 (907) 685-3276 Average 0 0 Units* Casing Summary Lithology (%) 2115' Bit # 0.942 Grade N/A N/AN/A N/A Gamma/Resistivity N/A N/AN/A N/A Mud Type MBT 2115' pH N/A N/AN/A (ppb Eq) 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth cP C-2C-1 Chromatograph (ppm) Lst C-5i 0 0 N/A C-5n GvlCoal N/A VM-3 Milltooth Bit in Minimum Depth 0 00 C. Cretsinger / D. Dunbar 3:00 AM 2115' 2115' 0' Repsol E&P USA Inc.AK-AM-0902062414 Nipple up BOPs 25-Feb-2015 Time: Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC Avg to2115' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) ShClyst C-4i C-4n Tuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary Gas Summary (current) CementChtSiltCly N/A 000 80.0 N/AN/A Depth in / out 41.4 Type (lb/100ft2) Bit Type 2017' WOB Hours (max)Trip N/A0Background Avg Min Comments RPM ECD (ppg) ml/30min Tools API FL 10,000 UnitsN/AConnection 0 C-3 2107' 1-1-WT-A-E/E/E-IN-NO-TD N/A Size Job No.: Daily Charges: Total Charges: Chlorides 2115' Rig Activity: Report For: Morning Report Report # 8 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Current Pump & Flow Data: 0 Max Condition 0 0 mg/l N/A Continue to nipple up BOPs. Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Continue to nipple up BOPs. Density (ppg) out (sec/qt) Viscosity Cor Solids %mg/l N/A 0 0 Current Pump & Flow Data: 0 Max Condition ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Rig Activity: Report For: Morning Report Report # 9 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-1-WT-A-E/E/E-IN-NO-TD N/A Size Job No.: Daily Charges: Total Charges: Chlorides 2115' 2107' 10,000 UnitsN/AConnection 0 C-3 Avg Min Comments RPM ECD (ppg) ml/30min Tools API FL (max)Trip N/A0Background Type (lb/100ft2) Bit Type 2017' WOB Hours 80.0 N/AN/A Depth in / out 41.4 N/A 000 Gas Summary (current) CementChtSiltClyTuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary ShClyst C-4i C-4n Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger / D. Dunbar 3:00 AM 2115' 2115' 0' Repsol E&P USA Inc.AK-AM-0902062414 Nipple up BOPs 26-Feb-2015 Time: 0 00 N/A VM-3 Milltooth Bit in Minimum Depth C-5i 0 0 N/A C-5n GvlCoal cP C-2C-1 Chromatograph (ppm) Lst 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth N/A Mud Type MBT pH N/A N/AN/A (ppb Eq) 0.942 Grade N/A N/AN/A N/A N/A N/AN/A (907) 685-3276 Average 0 0 Units* Casing Summary Lithology (%) 2115' Bit # 0 R. Lenberg / A. Bongard A. Bongard 0 (max) 00N/A 0 100% Gas In Air= Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 131.0 J-5520.00''Conductor80' 13.375" (current) 0 0 0 Set AtSize SiltstSs 0 N/A0 . . * 24 hr Recap:Complete nippling up BOPs. Begin testing BOPs: trouble shootsuper-choke, test HCR valve, pipe rams, choke Density (ppg) out (sec/qt) Viscosity Cor Solids %(lb/bbl) 10.36 0 0 Current Pump & Flow Data: 0 Max Condition ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Rig Activity: Report For: Morning Report Report # 10 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-1-WT-A-E/E/E-IN-NO-TD 12.2 Size Job No.: Daily Charges: Total Charges: Lime 2115' 2107' 10,000 UnitsN/AConnection 0 C-3 Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL (max)Trip N/A0Background Type (lb/100ft2) Bit Type 2017' WOB Hours 80.0 N/A14.00 Depth in / out 41.4 7.97 000 Gas Summary (current) CementChtSiltClyTuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary ShClyst C-4i C-4n Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger / D. Dunbar 3:00 AM 2115' 2115' 0' Repsol E&P USA Inc.AK-AM-0902062414 Test BOPs 27-Feb-2015 Time: valves, and blind rams. Continue testing BOPs. 0 00 N/A VM-3 Milltooth Bit in Minimum Depth C-5i 0 0 N/A C-5n GvlCoal cP C-2C-1 Chromatograph (ppm) Lst 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth 39.00 Mud Type Oil / Water Alkal N/A 78.9/21.178 Ratio 0.942 Grade N/A N/AN/A N/A MOBM 10.4010.40 (907) 685-3276 Average 0 0 Units* Casing Summary Lithology (%) 2115' Bit # 0 R. Mulkey / A. Bongard A. Bongard 0 (max) 00N/A 0 100% Gas In Air= Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 131.0 J-5520.00''Conductor80' 13.375" (current) 0 0 0 Set AtSize SiltstSs 0 N/A0 . . * 24 hr Recap:Continue testing BOPs. IBOP test failure: Replace IBOP on top drive. Identify bad choke valve: Replace #8 valve on Density (ppg) out (sec/qt) Viscosity Cor Solids %(lb/bbl) 9.07 0 0 Current Pump & Flow Data: 0 Max Condition ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Rig Activity: Report For: Morning Report Report # 11 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-1-WT-A-E/E/E-IN-NO-TD 12.1 Size Job No.: Daily Charges: Total Charges: Lime 2115' 2 2107' 10,000 UnitsN/AConnection 0 C-3 Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL (max)Trip N/A0Background Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours 80.0 NOV SKH519M-A7C N/A 2115' 14.00 Depth in / out 41.4 6.98 000 Gas Summary (current) CementChtSiltClyTuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary ShClyst C-4i C-4n Avg to2115' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger / D. Dunbar 3:00 AM 2115' 2115' 0' Repsol E&P USA Inc.AK-AM-0902062414 P/U BHA 28-Feb-2015 Time: choke manifold. Re-test valve and shell test- BOP test good. Rig-down BOP test equipment. Pick-up BHA. 0 00 N/A VM-3 Milltooth Bit in Minimum Depth C-5i 0 0 N/A C-5n GvlCoal cP C-2C-1 Chromatograph (ppm) Lst 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth 36.00 Mud Type Oil / Water 2115' Alkal N/A 80.1/19.979 Ratio 0.942 Grade N/A N/AN/A N/A Gamma/Res, Density Neutron, Sonic MOBM 10.4010.40 (907) 685-3276 Average 0 0 Units* Casing Summary Lithology (%) 2115' Bit # 0 R. Mulkey / A. Bongard A. Bongard 0 (max) 00N/A 0 100% Gas In Air= Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 131.0 J-5520.00''Conductor80' 13.375" (current) 0 0 0 Set AtSize SiltstSs 0 N/A0 . . * 24 hr Recap: 0 N/A0 (current) 0 0 0 Set AtSize SiltstSs 131.0 J-5520.00''Conductor80' 13.375"Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 (max) 00N/A 0 100% Gas In Air= 0 R. Mulkey / A. Bongard A. Bongard 0 (907) 685-3276 Average 0 0 Units* Casing Summary Lithology (%) 2115' Bit # 0.942 Grade N/A N/AN/A N/A Gamma/Res, Density Neutron, Sonic MOBM 10.3010.30 33.00 Mud Type Oil / Water 2115' Alkal N/A 80.1/19.9141 Ratio 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth cP C-2C-1 Chromatograph (ppm) Lst C-5i 0 0 N/A C-5n GvlCoal N/A VM-3 Milltooth Bit in Minimum Depth rate to 80 spm. Circulating and waiting on weather due to phase III weather conditions. 0 00 C. Cretsinger / D. Dunbar 3:00 AM 2115' 2115' 0' Repsol E&P USA Inc.AK-AM-0902062414 Cond. Mud Circ 1-Mar-2015 Time: Current Date: Qugruk 301 North Slope Alaska Nabors 105 AC Avg to2115' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) ShClyst C-4i C-4n Tuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary Gas Summary (current) CementChtSiltCly 3.98 000 80.0 NOV SKH519M-A7C N/A 2115' 13.00 Depth in / out 41.4 Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours (max)Trip N/A0Background Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL 10,000 UnitsN/AConnection 0 C-3 2 2107' 1-1-WT-A-E/E/E-IN-NO-TD 12.1 Size Job No.: Daily Charges: Total Charges: Lime 2115' Rig Activity: Report For: Morning Report Report # 12 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Current Pump & Flow Data: 0 Max Condition 0 0 (lb/bbl) 5.18 Continue M/U BHA. TIH to 1945'. Broke Circulation, circulate mud untel returns seen at shakers, increased pump Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap: 0 2136'50 (current) 0 0 10164 Set AtSize SiltstSs 131.0 J-5520.00''Conductor80' 13.375"Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 (max) 002115'0 100% Gas In Air= 28 R. Mulkey / A. Bongard A. Bongard 8006 (907) 685-3276 Average 0 0 Units* Casing Summary Lithology (%) 2135' Bit # 0.942 Grade 0.0 2116'140.4 259.0 Gamma/Res, Density Neutron, Sonic MOBM 10.4010.40 36.00 Mud Type Oil / Water 2145' Alkal N/A 78.4/21.6100 Ratio 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth cP C-2C-1 Chromatograph (ppm) Lst C-5i 0 0 N/A C-5n GvlCoal N/A VM-3 Milltooth Bit in Minimum Depth motors. Pressure test the casing/shoe to 2500 psi. Circulate and condition mud. Work on shaker screens. Circulate mud around. 34 00 C. Cretsinger / D. Dunbar 3:00 AM 2115' 2145' 30' Repsol E&P USA Inc.AK-AM-0902062414 R/D FIT Eqipment 2-Mar-2015 Time: Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC Avg to2115' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) ShClyst C-4i C-4n Tuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary Gas Summary (current) CementChtSiltCly 3.98 000 80.0 NOV SKH519M-A7C N/A 2115' 14.00 Depth in / out 41.4 Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours (max)Trip N/A3Background Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL 10,000 UnitsN/AConnection 100 0 C-3 2 shoe. Rig-up to perform FIT. FIT to 13.7 equivalent mud weight. Tag float at 2017' MD. Drill out cement/float. Drill new formation from 2115' MD to 2145' MD. Circulate bottoms up and pull back to 2107' 1-1-WT-A-E/E/E-IN-NO-TD 12.2 Size Job No.: Daily Charges: Total Charges: Lime 2115' Rig Activity: Report For: Morning Report Report # 13 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Current Pump & Flow Data: 0 Max Condition 0 0 (lb/bbl) 5.18 Continue to wait on the weather. Hold safety meeting and rig-up Halliburton to pressure test. Perform rig service on Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Rig down third party lines from formation integrity test. Clean and clear rig floor. Trip in hole to 2145' MD and Density (ppg) out (sec/qt) Viscosity Cor Solids %(lb/bbl) N/A 487 51 Current Pump & Flow Data: 1622 Max Condition ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Rig Activity: Report For: Morning Report Report # 14 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-1-WT-A-E/E/E-IN-NO-TD N/A Size Job No.: Daily Charges: Total Charges: Lime 2115' 2 The samples have been consistently dark gray to gray, soft to firm, blocky, laminated, arenaceous claystone with a smaller portion MD to 3669' MD. Circulate bottoms up. 2107' 10,000 UnitsN/AConnection 50 969 C-3 Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL (max)Trip N/A49Background Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours 80.0 NOV SKH519M-A7C N/A 2115' N/A Depth in / out 41.4 N/A 0460 Gas Summary (current) CementChtSiltClyTuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary ShClyst C-4i C-4n Avg to2115' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger / D. Dunbar 3:00 AM 2145' 3669' 1524' Repsol E&P USA Inc.AK-AM-0902062414 Circulate Bottoms Up 3-Mar-2015 Time: establish returns. Rotary drill from 2145' MD to 2475' MD. Circulate and condition mud. Circulate gas out. Rotary drill from 2475' 178 being a gray or brown, soft-firm, blocky-unconsolidated siltstone with an occasional milky quartz ooidic inclusion with no visible 013 N/A VM-3 Milltooth Bit fluorescence. in Minimum Depth C-5i 153 99 N/A C-5n GvlCoal cP C-2C-1 Chromatograph (ppm) Lst 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth N/A Mud Type Oil / Water 3669' Alkal N/A N/AN/A Ratio 0.942 Grade 0.0 2350'124.3 326.1 Gamma/Res, Density Neutron, Sonic MOBM 10.4010.40 (907) 685-3276 Average 590 188 Units* Casing Summary Lithology (%) Bit # 2207 R. Mulkey / A. Bongard A. Bongard 32182 (max) 1002875'0 100% Gas In Air= Surface Unit Phone: 14Maximum Report By:Logging Engineers: 141727 131.0 J-5520.00''Conductor80' 13.375" (current) 3584 117 159066 Set AtSize 50 SiltstSs 71 2640'926 . . * 24 hr Recap: 323 4077'810 (current) 6015 809 129455 Set AtSize 20 SiltstSs 131.0 J-5520.00''Conductor80' 13.375"Surface Unit Phone: 75Maximum Report By:Logging Engineers: 722251 (max) 301664036'8 100% Gas In Air= 27752 R. Mulkey / A. Bongard R. Mulkey 27614 (907) 685-3276 Average 433 138 Units* Casing Summary Lithology (%) 4084' Bit # 0.942 Grade 0.0 3697'23.4 200.3 Gamma/Res, Density Neutron, Sonic MOBM 10.4010.40 31.00 Mud Type Oil / Water 4147' Alkal N/A 80.5/19.573 Ratio 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth cP C-2C-1 Chromatograph (ppm) Lst C-5i 214 468 N/A C-5n GvlCoal N/A VM-3 Milltooth Bit in Minimum Depth mud. Circulate gas out. Circulate bottoms up. Wait on weather. 178 claystone, and trace shale fragments. 856 S. Self / D. Dunbar 3:00 AM 3669' 4147' 478' Repsol E&P USA Inc.AK-AM-0902062414 Circulate/wait on weather 4-Mar-2015 Time: Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC Avg to3669' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) ShClyst C-4i C-4n Tuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary Gas Summary (current) CementChtSiltCly N/A 6525 80.0 NOV SKH519M-A7C 3.6 2115' 13.00 Depth in / out 41.4 Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours (max)Trip 48991Background Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL 10,000 UnitsN/AConnection 80 779 C-3 2 The Samples have been consistently gray to light brown, soft, laminated, consolidated siltstone with dark gray to light gray, firm, platy 2107' 1-1-WT-A-E/E/E-IN-NO-TD 13.6 Size Job No.: Daily Charges: Total Charges: Lime 2115' Rig Activity: Report For: Morning Report Report # 15 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Current Pump & Flow Data: 947 Max Condition 301 27 (lb/bbl) 5.83 Complete short wiper trip to 2041. Service top drive. Rotary drill from 3669' MD to 4147'MD. Circulate and condition Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Waited for phase III weather conditions to be lifted. Fix rig electrical issues. Drill ahead from 4147' to 5000'. Density (ppg) out (sec/qt) Viscosity Cor Solids %(lb/bbl) 3.88 890 100 Current Pump & Flow Data: 1750 Max Condition ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Rig Activity: Report For: Morning Report Report # 16 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-1-WT-A-E/E/E-IN-NO-TD 14.0 Size Job No.: Daily Charges: Total Charges: Lime 2115' 2 sorted with abundant silstone. The samples have been predominantly sandstone, light to medium brown, laminated, soft, very fine to fine grained, well 2107' 10,000 UnitsN/AConnection 2170 C-3 Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL (max)Trip N/A644Background Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours 80.0 NOV SKH519M-A7C 3.6 2115' 14.00 Depth in / out 41.4 2.99 6222955 Gas Summary (current) CementChtSiltClyTuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary ShClyst C-4i C-4n Avg to4147' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC S. Self / D. Dunbar 3:00 AM 4147' 5008' 861' Repsol E&P USA Inc.AK-AM-0902062414 Drill 12.25" hole 5-Mar-2015 Time: 382 023 N/A VM-3 Milltooth Bit in Minimum Depth C-5i 187 407 N/A C-5n GvlCoal cP C-2C-1 Chromatograph (ppm) Lst 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth 36.00 Mud Type Oil / Water 5008' Alkal N/A 81.4/18.673 Ratio 0.942 Grade 36.2 4817'39.0 258.0 Gamma/Res, Density Neutron, Sonic MOBM 10.4510.45 (907) 685-3276 Average 603 192 Units* Casing Summary Lithology (%) 4834' Bit # 744 R. Mulkey / A. Bongard R. Mulkey 41568 (max) 11134198'0 100% Gas In Air= Surface Unit Phone: 88Maximum Report By:Logging Engineers: 791959 70 131.0 J-5520.00''Conductor80' 13.375" (current) 6000 86 137011 Set AtSize 30 SiltstSs 71 4648'1338 . . * 24 hr Recap: 1169 5144'1348 (current) 5927 2658 129592 Set AtSize 20 SiltstSs 80 131.0 J-5520.00''Conductor80' 13.375"Surface Unit Phone: 143Maximum Report By:Logging Engineers: 1252199 (max) 1434795071'83 100% Gas In Air= 46734 R. Mulkey / A. Bongard R. Mulkey 75719 (907) 685-3276 Average 603 192 Units* Casing Summary Lithology (%) 5248' Bit # 0.942 Grade N/A N/AN/A N/A Gamma/Res, Density Neutron, Sonic MOBM 10.4010.40 30.00 Mud Type Oil / Water 5248' Alkal N/A 83.1/16.974 Ratio 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth cP C-2C-1 Chromatograph (ppm) Lst C-5i 236 543 N/A C-5n GvlCoal N/A VM-3 Milltooth Bit firm with laminations. in Minimum Depth and TOOH. 795 very weak patchy yellow flouresence with bluish white, very weak very slow cut, and 20% siltstone; black to grey to light brown, 96322 S. Self / D. Dunbar 3:00 AM 5008' 5248' 240' Repsol E&P USA Inc.AK-AM-0902062414 TOOH 6-Mar-2015 Time: Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC Avg to5008' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) ShClyst C-4i C-4n Tuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary Gas Summary (current) CementChtSiltCly 3.48 126433107 80.0 NOV SKH519M-A7C N/A 2115' 15.00 Depth in / out 41.4 Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours (max)Trip 69818Background Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL 10,000 UnitsN/AConnection 4010 C-3 2 Ditch magnet cuttings: daily= 52 grams, total=2420 grams Last sample consisted of: 80% sandstone; transparent to translucent, light to medium brown staining, patchy dull yellow stain, 20% 2107' 1-1-WT-A-E/E/E-IN-NO-TD 14.0 Size Job No.: Daily Charges: Total Charges: Lime 2115' Rig Activity: Report For: Morning Report Report # 17 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Current Pump & Flow Data: 1750 Max Condition 1615 186 (lb/bbl) 4.53 Continued drilling ahead from 5008' to intermediate TD at 5248'. Short tipped to 3477'. TIH. Circulate bottoms up Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap: 0 0 (current) 0 0 0 Set AtSize SiltstSs 131.0 J-5520.00''Conductor80' 13.375"Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 (max) 00 0 100% Gas In Air= 0 R. Mulkey / A. Bongard R. Mulkey 0 (907) 685-3276 Average Units* Casing Summary Lithology (%) 5248' Bit # 0.942 Grade N/A N/AN/A N/A Gamma/Res, Density Neutron, Sonic MOBM 10.4010.40 30.00 Mud Type Oil / Water 5248' Alkal N/A 83.1/16.974 Ratio 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth cP C-2C-1 Chromatograph (ppm) Lst C-5i 0 0 N/A C-5n GvlCoal N/A VM-3 Milltooth Bit in Minimum Depth 0 00 S. Self / D. Dunbar 3:00 AM 5248' 5248' 0' Repsol E&P USA Inc.AK-AM-0902062414 Rig up for casing run 7-Mar-2015 Time: Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC Avg to5008' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) ShClyst C-4i C-4n Tuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary 3133' Gas Summary (current) CementChtSiltCly 3.48 000 80.0 NOV SKH519M-A7C N/A 2115' 15.00 5248' Depth in / out 41.4 Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours (max)Trip N/A0Background Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL 10,000 UnitsN/AConnection 0 C-3 2 Ditch magnet cuttings: total=2486 grams 2107' 1-1-WT-A-E/E/E-IN-NO-TD 14.0 Size Job No.: Daily Charges: Total Charges: Lime 2115' Rig Activity: Report For: Morning Report Report # 18 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Current Pump & Flow Data: Max Condition 0 0 (lb/bbl) 4.53 Continued to TOOH. Lay down BHA and source. Installed casing rams. Riging up to run 9 5/8" casing. Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap: 0 0 (current) 0 0 0 Set AtSize SiltstSs 131.0 J-5520.00''Conductor80' 13.375"Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 (max) 00 0 100% Gas In Air= 0 R. Mulkey / A. Bongard R. Mulkey 0 (907) 685-3276 Average Units* Casing Summary Lithology (%) 5248' Bit # 0.942 Grade MOBM 10.4510.40 30.00 Mud Type Oil / Water Alkal 4.984 Ratio 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth cP C-2C-1 Chromatograph (ppm) Lst C-5i 0 0 C-5n GvlCoal VM-3 Milltooth Bit in Minimum Depth 370 00 S. Self / D. Dunbar 3:00 AM 5248' 5248' 0' Repsol E&P USA Inc.AK-AM-0902062414 TIH with casing 8-Mar-2015 Time: Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) ShClyst C-4i C-4n Tuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary 47.54 3133' Gas Summary (current) CementChtSiltCly 4.49 000 142 80.0 NOV SKH519M-A7C N/A 2115' 16.00 5248' Depth in / out 24 41.4 Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours (max)Trip 180890Background Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL 10,000 UnitsN/AConnection 0 C-3 2 Ditch magnet cuttings: total=2486 grams 2107' 1-1-WT-A-E/E/E-IN-NO-TD 14.2 Size Job No.: Daily Charges: Total Charges: Lime 2115' Rig Activity: Report For: Morning Report Report # 19 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-2-CT-A-X-WT-TD ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Current Pump & Flow Data: Max Condition 0 0 (lb/bbl) 5.83 Runing in with 9 5/8" casing. Trip gas so far was 1808 units. Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Finished triping in with 9 5/8" casing. Circulated 2 bottoms up and prepare for cement job. Rig up for stage one of Density (ppg) out (sec/qt) Viscosity Cor Solids %(lb/bbl) 5.18 0 0 Current Pump & Flow Data: Max Condition 1-2-CT-A-X-I-WT-TD ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Rig Activity: Report For: Morning Report Report # 20 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-1-WT-A-E/E/E-IN-NO-TD 14.2 Size Job No.: Daily Charges: Total Charges: Lime 2115' 2 Ditch magnet cuttings: total=2486 grams 2107' 10,000 UnitsN/AConnection 0 C-3 Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL (max)Trip N/A7Background Intermedate Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours 80.0 NOV SKH519M-A7C N/A 2115' 15.00 5248' Depth in / out 24 41.4 4.49 703.6 14247.54 3133' Gas Summary (current) CementChtSiltClyTuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary ShClyst C-4i C-4n Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC S. Self / D. Dunbar 3:00 AM 5248' 5248' 0' Repsol E&P USA Inc.AK-AM-0902062414 Cement casing 9-Mar-2015 Time: cement job. Completed stage one of cement job. Circulate and condition mud while waiting on cement to being stage 2. 63 00 VM-3 Milltooth Bit in Minimum Depth C-5i 0 0 C-5n GvlCoal cP C-2C-1 Chromatograph (ppm) Lst 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth 33.00 Mud Type Oil / Water Alkal 83.0/17.0114 Ratio 0.942 Grade MOBM 10.4010.40 (907) 685-3276 Average Units* Casing Summary Lithology (%) 5248' Bit # 9 R. Mulkey / A. Bongard R. Mulkey 9 (max) 06 6.5 100% Gas In Air= Surface Unit Phone: 0Maximum Report By:Logging Engineers: 40.20 5235'9.63'' 131.0 J-5520.00''Conductor80' 13.375" (current) 14 7 201 Set AtSize SiltstSs 0 404 . . * 24 hr Recap: 0 (current) 0 0 0 Set AtSize SiltstSs L-805235'9.63'' 131.0 J-5520.00''Conductor80' 13.375"Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 (max) 0 0 100% Gas In Air= 0 R. Mulkey / A. Bongard R. Mulkey 0 (907) 685-3276 Average Units* Casing Summary Lithology (%) 5248' Bit # 0.942 Grade MOBM 9.309.85 29.00 Mud Type Oil / Water Alkal 80.5/19.582 Ratio 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth cP C-2C-1 Chromatograph (ppm) Lst C-5i 0 0 C-5n GvlCoal VM-3 Milltooth Bit in Minimum Depth 2nd stage of cement job. Rig down cement crew. Service top drive. Rig up to test BOP. No significant gas data recorded. 00 S. Self / D. Dunbar 3:00 AM 5248' 5248' 0' Repsol E&P USA Inc.AK-AM-0902062414 Testing BOP 10-Mar-2015 Time: Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) 47.0 ShClyst C-4i C-4n Tuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary 47.54 3133' Gas Summary (current) CementChtSiltCly 4.49 000 142 80.0 NOV SKH519M-A7C N/A 2115' 17.00 5248' Depth in / out 24 41.4 Intermedate Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours (max)Trip N/A1Background Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL 10,000 UnitsN/AConnection 0 C-3 2 Ditch magnet cuttings: total=2486 grams 2107' 1-1-WT-A-E/E/E-IN-NO-TD 11.3 Size Job No.: Daily Charges: Total Charges: Lime 2115' Rig Activity: Report For: Morning Report Report # 21 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-2-CT-A-X-I-WT-TD ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Current Pump & Flow Data: Max Condition 0 0 (lb/bbl) 5.18 Circulate mud and prepare for 2nd stage of cement job. Began 2nd stage of cement job. Displace mud and finish Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Set pack off assembly and test seal. Rig up to test and test BOP. No significant gas data recorded. Density (ppg) out (sec/qt) Viscosity Cor Solids %(lb/bbl) 5.18 0 0 Current Pump & Flow Data: Max Condition 1-2-CT-A-X-I-WT-TD ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Rig Activity: Report For: Morning Report Report # 22 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-1-WT-A-E/E/E-IN-NO-TD 9.4 Size Job No.: Daily Charges: Total Charges: Lime 2115' 2 Ditch magnet cuttings: total=2486 grams or 5.48 pounds. 2107' 10,000 UnitsN/AConnection 0 C-3 Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL (max)Trip N/A1Background Intermedate Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours 80.0 NOV SKH519M-A7C N/A 2115' 16.00 5248' Depth in / out 24 41.4 4.49 000 14247.54 3133' Gas Summary (current) CementChtSiltClyTuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary ShClyst C-4i C-4n Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) 47.0 Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC S. Self / J. McKinley 3:00 AM 5248' 5248' 0' Repsol E&P USA Inc.AK-AM-0902062414 Testing BOP 11-Mar-2015 Time: 00 VM-3 Milltooth Bit in Minimum Depth C-5i 0 0 C-5n GvlCoal cP C-2C-1 Chromatograph (ppm) Lst 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth 28.00 Mud Type Oil / Water Alkal 80.7/19.386 Ratio 0.942 Grade MOBM 9.309.30 (907) 685-3276 Average Units* Casing Summary Lithology (%) 5248' Bit # 0 R. Mulkey / A. Bongard R. Mulkey 0 (max) 0 0 100% Gas In Air= Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 L-805235'9.63'' 131.0 J-5520.00''Conductor80' 13.375" (current) 0 0 0 Set AtSize SiltstSs 0 . . * 24 hr Recap: 0 (current) 0 0 0 Set AtSize SiltstSs L-805235'9.63'' 131.0 J-5520.00''Conductor80' 13.375"Surface Unit Phone: 0Maximum Report By:Logging Engineers: 00 (max) 0 0 100% Gas In Air= 0 R. Mulkey / A. Bongard R. Mulkey 0 (907) 685-3276 Average Units* Casing Summary Lithology (%) 5248' Bit # 0.942 Grade MOBM 9.309.30 26.00 Mud Type Oil / Water Alkal 80.3/19.784 Ratio 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth cP C-2C-1 Chromatograph (ppm) Lst C-5i 0 0 C-5n GvlCoal VM-3 Milltooth Bit in Minimum Depth 00 S. Self / J. McKinley 3:00 AM 5248' 5248' 0' Repsol E&P USA Inc.AK-AM-0902062414 Testing BOP 12-Mar-2015 Time: Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) 47.0 ShClyst C-4i C-4n Tuff 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary 47.54 3133' Gas Summary (current) CementChtSiltCly 3.98 000 142 80.0 NOV SKH519M-A7C N/A 2115' 16.00 5248' Depth in / out 24 41.4 Intermedate Type (lb/100ft2) Bit Type 2017' 12.25 0.796 WOB Hours (max)Trip N/A1Background Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL 10,000 UnitsN/AConnection 0 C-3 2 Ditch magnet cuttings: 24 hour total: 0 grams. total=2486 grams ( 5.48 pounds) 2107' 1-1-WT-A-E/E/E-IN-NO-TD 9.2 Size Job No.: Daily Charges: Total Charges: Lime 2115' Rig Activity: Report For: Morning Report Report # 23 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-2-CT-A-X-I-WT-TD ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Current Pump & Flow Data: Max Condition 0 0 (lb/bbl) 5.18 Rig up to test and test BOP. And Prepare to pick up BHA. No significant gas data recorded. Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap: pick up BHA, and Run in the hole to 2970'. trip out to 1905' to retest BOP. Resume triping in. Density (ppg) out (sec/qt) Viscosity Cor Solids %(lb/bbl) 5.18 0 Current Pump & Flow Data: Max Condition ROP ROP (ft/hr) 3.14 @ Mud Data Depth 95% Report For: Morning Report Report # 24 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Max @ ft 1-1-WT-A-E/E/E-IN-NO-TD 9.0 Size Job No.: Daily Charges: Total Charges: Lime 2115' Rig Activity: 3 Ditch magnet cuttings: 24 hour total: 12 grams. total= 12grams ( .026 pounds) 2107' 0 C-3 0 Avg Min Comments Mud RPM ECD (ppg) ml/30min Tools API FL Hours (max)N/A 41.4 Intermedate Type (lb/100ft2) Bit Type 2017' 8.5 0.796 WOB 80.0 Hughes 8 1/2" mill N/A 5248' 15.00 Depth in / out Cly 3.98 00 1 16 L80 24 hr Max 68.0 Weight 98' MWD Summary -5248' ShClyst C-4i C-4n Tuff Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) 47.0 Current Date: Qugruk 301 North Slope Alaska N/A N/A Nabors 105 AC S. Self / J. McKinley 3:00 AM 5248' 5248' 0' Repsol E&P USA Inc.AK-AM-0902062414 Testing BOP/TIH 13-Mar-2015 Time: 00 0 VM-3 Milltooth Bit in Minimum Depth No significant gas data recorded. C-5n GvlCoal Gas Summary Lst C-5i 0 0 Cement C-2C-1 Chromatograph (ppm) 20.18 PV YP Footage SPP (psi) Gallons/stroke TFA Depth Oil / Water Alkal 80.6/19.493 Ratio cP MOBM 9.309.30 28.00 Mud Type Units* Casing Summary Lithology (%) 5248' Bit # 0.942 Grade R. Mulkey / A. Bongard R. Mulkey 0 (907) 685-3276 Average 0 10,000 UnitsN/AConnection 0 0 100% Gas In Air= Unit Phone: 0Maximum Report By:Logging Engineers: 00 (max) L-805235'9.63'' 131.0 J-5520.00''Conductor80' 13.375"Surface Set AtSize SiltstSs (current) Cht Silt (current) 0 0 0 Trip1Background 2115' 0 5248' 3133'24 142 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: Viscosity Cor Solids %in Ditch magnet cuttings: 24 hour total: 234 grams (.516 LBS). total= 246grams ( .542 LBS) 3 C-3 Current Pump & Flow Data: 1180 Max Condition (lb/bbl) 3.14 @ Mud Data Depth 95% 5.83 Morning Report Report # 25 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) casing, continue running in to 5,109'. 0 0 Min Comments Mud RPM ECD (ppg) ml/30min 9.3 Lime Tools 1-1-WT-A-E/E/E-IN-NO-TD (max)N/A 41.4 Intermedate Type Cly 2017' Lst L-805235' VM-3 Milltooth Bit 20.18 2115' 5248' 2115' Size 0.942 00 24 hr Max 68.0 Weight 98' MWD Summary -5248' Hours Hughes 8 1/2" mill 5248' Tuff 1 16 L80 80.0 8.5 0.796 Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) 47.0 N/A15.00 Depth in / out WOB N/A N/A Nabors 105 AC S. Self / J. McKinley Rig Activity: Avg to 5248' 5248' 0' Repsol E&P USA Inc.AK-AM-0902062414 Drilling Cement 14-Mar-2015Date: North Slope Alaska (current) 00 10,000 Units Depth Run in hole to 3008' drilled out DV tool, continued run in to 3600', circulated out cement stringer, pressure test 3 0 0 C-5n GvlCoal Gas Summary Cement C-2 ShClyst 0 C-4i C-4n C-5i TFA Depth Oil / Water Bit Type Density (ppg) out Footage SPP (psi) Gallons/stroke 3.98 Avg API FL Alkal 80.9/19.199 Ratio cP PV YP (lb/100ft2)(sec/qt) 0.0 0.0 MOBM 9.3510.10 28.00 Mud Type 128 401 Units* Casing Summary Lithology (%) 5248' Bit # Grade 0.0 R. Mulkey / A. Bongard R. Mulkey 14 (907) 685-3276 Average 100% Gas In Air= 0 Unit Phone: N/AConnection 0 0 Maximum Report By:Logging Engineers: 00 (max) 25 20.00''Conductor80' 13.375"Surface 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' 9.63'' Trip3Background 1Minimum 5 0 00 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 60 15 0 5278' 5248' (current) Cht Silt 2107' 9.63'' Trip0Background 2 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 0112 (max) 7059 Minimum Unit Phone: N/AConnection 81 6 100% Gas In Air 0 Conductor = 5252' R. Mulkey / R. Lennberg R. Mulkey 26.00 (907) 685-3276 Units* Casing Summary Lithology (%) 5278' Bit # Grade 20.00'' out 80' 13.375" 370.0 MOBM 9.309.30 Alkal Mud Type 82.9/17.195 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.98 Avg API FL TFA Depth Oil / Water 360 C-4i C-4n C-5iC-2 ShClyst C-3 C-5n GvlCoal Gas Summary Drill cement from 5010' to 5248'. Drilled 30' of new formation. Perform FIT. Pump slug. Trip out of hole and lay down BHA. Prepare 40 9 20 (current) 016 10,000 Units Average 5248' 5278' 30' Repsol E&P USA Inc.AK-AM-0902062414 Prepare for Wire Line 15-Mar-2015Date: North Slope Alaska N/A N/A Nabors 105 AC S. Self / J. McKinley Rig Activity: Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) 47.0 N/A15.00 Depth in / out WOB 1 16 L80 80.0 8.5 0.796 Surface VM-3 Milltooth Bit 24 hr Max 68.0 Weight 98' MWD Summary -5248' Hours Hughes 8 1/2" mill 5248' 00 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Intermedate Type Cly 2017' Lst L-805235' 1-1-WT-A-E/E/E-IN-NO-TD (max)40 Min Comments Mud RPM ECD (ppg) ml/30min 9.3 Lime Tools to run Wire Line. 269 05127 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 26 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 5.18 Current Pump & Flow Data: Max Condition (lb/bbl) 3.14 Depth Ditch magnet cuttings: 24 hour total: 636 grams (1.4 LBS). total= 882grams ( 1.94 LBS) Viscosity Cor Solids %in 3 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 431 3133'24 142 131.0 J-55 0 Set At 225 7582 138 5345' 5279' (current) Cht Silt 2107' 9.63'' Trip72Background 55 0 C-1 Chromatograph (ppm) Size 20 SiltstSs 80% Maximum Report By:Logging Engineers: 11331 (max) 25513 Minimum Unit Phone: N/AConnection 234 21 100% Gas In Air 13 Conductor = 78.0 5400' R. Mulkey / R. Lennberg R. Mulkey 26.00 (907) 685-3276 Units* Casing Summary Lithology (%) 5278' Bit # Grade 20.00'' out 80' 13.375" 65.7 183.6 SonicScope 475, IM Pulse 20K, MOBM 9.309.35 Alkal Mud Type 5450' 82.4/17.695 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.98 Avg API FL 10.85 226 72 TFA Depth Oil / Water 1118 C-4i C-4n C-5iC-2 ShClyst C-3 10.82 C-5n GvlCoal 11.10 Gas Summary comence drilling 6 1/8" hole. 145 28 61 70% dark yellow luorescence, pale blue white blush cut. (current) 043 10,000 Units 20% SILTSTONE : black, grey to light brown, firm, laminations, consolidated, arenaceous. 80% SANDSTONE: clear, transparent Average moderately to well sorted, moderately consolidated, weak calcareous cement. SHOW: 50% patchy to even light brown staining, 5248' 5450' 202' Repsol E&P USA Inc.AK-AM-0902062414 Drill 6 1/8" hole 16-Mar-2015Date: North Slope Alaska N/A N/A Nabors 105 AC S. Self / J. McKinley Rig Activity: Avg to5278' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) 47.0 N/A15.00 Depth in / out WOB 1 16 L80 80.0 6.5 0.354 Surface VM-3 Milltooth Bit 24 hr Max 68.0 Weight 98' MWD Summary -5278' Hours NOV SKH513M 5278' 025 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Intermedate Type Cly 2017' Lst L-805235' 1-1-WT-A-E/E/E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 8.9 Lime Tools 819 018133 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 27 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 4.92 Current Pump & Flow Data: 2006 Max Condition (lb/bbl) 3.14 Depth Ditch magnet cuttings: 24 hour total: 204 grams (.45 LBS). total= 1082grams ( 2.38 LBS) Viscosity Cor Solids %in Wireline truck arrived and rigged up for wireline. Successful log of cement. Pick up BHA and trip in the hole. to translucent, milky, light to medium brown staining, soft, very fine to fine, spherical to sub spherical, round to sub rounded 3 . . * 24 hr Recap: Viscosity Cor Solids %in Drilled a head from 5450' to 7072'. Max gas of 517 units. poorly consolidated clear to frosted quartz grains, trace chert, very fine grained to lower fine grained, sub rounded, well sorted minor 3 Ditch magnet cuttings: 24 hour total: 1426 grams (3.14 LBS). total= 2508grams ( 5.52 LBS) 70% dull dark yellow patchy fluorescence, faint blue white blush cut. Depth Current Pump & Flow Data: 2168 Max Condition (lb/bbl) 3.14 @ Mud Data Depth 95% 5.18 Morning Report Report # 28 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) SILTSTONE : Light to medium gray brown, firm to moderately soft, trace very fine carbonaceous laminations, earthy texture, very 1565 4130981 Min Comments Mud RPM ECD (ppg) ml/30min 9.7 Lime Tools 1-1-WT-A-E/E/E-IN-NO-TD (max)N/A 41.4 Intermedate Type Cly 2017' Lst L-805235' 20.18 2115' 5248' 2115' Size 0.942 54205 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary -5278' Hours NOV SKH513M 5278' 1 16 L80 80.0 6.5 0.354 Surface VM-3 Milltooth Bit Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) 47.0 N/A18.00 Depth in / out WOB N/A N/A Nabors 105 AC C. Cretsinger/ J. McKinley Rig Activity: Avg to5278' 5450' 7072' 1622' Repsol E&P USA Inc.AK-AM-0902062414 Drill 6 1/8" hole 17-Mar-2015Date: North Slope Alaska porosity. SHOW: 30-40% patchy to even light brown staining, 70% dull dark yellow patchy to even light brown staining, (current) 47160 10,000 Units argillaceous in part, grades to very fine sandstone in places. SANDSTONE: Light brown to brown grey in part, clear to mily quartz Average to moderate calcareous argillaceous cement, occasional traces of very fine carbonaceous laminations. 8 to 12% intergranular 313 92 205 9.34 C-5n GvlCoal 10.73 Gas Summary C-2 ShClyst C-3 2668 C-4i C-4n C-5i 9.94 273 87 TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.98 Avg API FL Alkal Mud Type 7072' 83.1/16.997 Ratio cP PVDensity (ppg) out 80' 13.375" 135.0 308.0 SonicScope 475, IM Pulse 20K, MOBM 9.309.35 30.00 (907) 685-3276 Units* Casing Summary Lithology (%) 6734' Bit # Grade 20.00''Conductor = 121.0 6687' R. Mulkey / R. Lennberg R. Mulkey 92 Unit Phone: N/AConnection 604 69 100% Gas In Air Maximum Report By:Logging Engineers: 48876 (max) 55554 Minimum 54 C-1 Chromatograph (ppm) Size 10 SiltstSs 90(current) Cht Silt 2107' 9.63'' Trip391Background 20 517 55554 876 6487' 5646'2668 3133'24 142 131.0 J-55 48 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: Viscosity Cor Solids %in Continued to drill from 7072' to 7531'. TD production section at 7531'. Circulated bottoms up. Short trip to the shoe. poorly consolidated clear to frosted quartz grains, trace chert, very fine grained to lower fine grained, sub rounded, well sorted minor 3 Ditch magnet cuttings: 24 hour total: 2860 grams (6.3 LBS). total= 4720grams ( 10.4 LBS) 70% dull dark yellow patchy fluorescence, faint blue white blush cut. Depth Current Pump & Flow Data: 1966 Max Condition (lb/bbl) 3.14 @ Mud Data Depth 95% 5.70 Morning Report Report # 29 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) SILTSTONE : Light to medium gray brown, firm to moderately soft, trace very fine carbonaceous laminations, earthy texture, very 908 4111374 Min Comments Mud RPM ECD (ppg) ml/30min 10.0 Lime Tools 1-1-WT-A-E/E/E-IN-NO-TD (max)N/A 41.4 Intermedate Type Cly 2017' Lst L-805235' 20.18 2115' 5248' 2115' Size 0.942 40110 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary 22.10 2253' Hours NOV SKH513M 5278' 1 16 L80 80.0 7531' 6.5 0.354 Surface VM-3 Milltooth Bit Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) 47.0 N/A20.00 Depth in / out WOB N/A N/A Nabors 105 AC C. Cretsinger/ J. McKinley Rig Activity: Avg to5278' 7072' 7531' 459' Repsol E&P USA Inc.AK-AM-0902062414 Circulate/TOOH 18-Mar-2015Date: North Slope Alaska porosity. SHOW: 30-40% patchy to even light brown staining, 70% dull dark yellow patchy to even light brown staining, (current) 49135 10,000 Units argillaceous in part, grades to very fine sandstone in places. SANDSTONE: Light brown to brown grey in part, clear to mily quartz Average to moderate calcareous argillaceous cement, occasional traces of very fine carbonaceous laminations. 8 to 12% intergranular Return to bottom. Begin trip out of hole. 122 103 237 10.44 C-5n GvlCoal 10.96 Gas Summary C-2 ShClyst C-3 2873 C-4i C-4n C-5i 10.72 276 88 TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.98 Avg API FL Alkal Mud Type 7531' 83.1/16.995 Ratio cP PVDensity (ppg) out 80' 13.375" 93.8 116.0 SonicScope 475, IM Pulse 20K, MOBM 9.359.40 28.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = 0.0 7368' R. Mulkey / R. Lennberg R. Mulkey 43 Unit Phone: N/AConnection 400 54 100% Gas In Air Maximum Report By:Logging Engineers: 57964 (max) 63363 Minimum 63 C-1 Chromatograph (ppm) Size 10 SiltstSs 90(current) Cht Silt 2107' 9.63'' Trip15Background 30 624 8670 325 7198' 7265'681 3133'24 142 131.0 J-55 33 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 8 0 0 (current) Cht Silt 2107' Trip2Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 9.20 (max) 0.002 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = R. Mulkey / R. Lennberg R. Mulkey 28.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" SonicScope 475, IM Pulse 20K, MOBM 9.409.40 Alkal Mud Type 7531' 83.1/16.9110 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.98 Avg API FL 10.72 276 88 TFA Depth Oil / Water 0.0005 C-4i C-4n C-5iC-2 ShClyst C-3 10.44 C-5n GvlCoal 10.96 Gas Summary Test BOP. No significant gas recorded. 4 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 BOP testing 19-Mar-2015Date: North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger/ J. McKinley Rig Activity: Avg to5278' Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A20.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary 0' Hours 5 3/4" Z 7531' 00 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 9.5 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 30 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 5.18 Current Pump & Flow Data: 1966 Max Condition (lb/bbl) 3.14 Depth Viscosity Cor Solids %in trip out of hole to 5063'. Circulate hole. Pump slug. Lay down BHA. Pick up BHA for clean out run. Trip in to 5182'. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Finish testing BOP. Trip in from 5241' to 7531' MD. Circulate and displace mud. Begin tripping out. 5 Depth Current Pump & Flow Data: Max Condition (lb/bbl) 3.14 @ Mud Data Depth 95% 5.18 Morning Report Report # 31 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 9.5 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A20.00 Depth in / out WOB N/A N/A Nabors 105 AC C. Cretsinger/ J. McKinley Rig Activity: Avg to 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 TOOH 20-Mar-2015Date: North Slope Alaska (current) 00 10,000 Units Average No significant gas recorded. 2 0 0 C-5n GvlCoal Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.99 Avg API FL Alkal Mud Type 83.1/16.9100 Ratio cP PVDensity (ppg) out 80' 13.375" MOBM 9.409.40 28.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = R. Mulkey / R. Lennberg R. Mulkey 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip2Background 0 4 0 00 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 2 0 0 (current) Cht Silt 2107' Trip2Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = R. Mulkey / R. Lennberg R. Mulkey 28.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" MOBM 9.409.40 Alkal Mud Type 83.1/16.9100 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.99 Avg API FL TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 C-5n GvlCoal Gas Summary No significant gas recorded. 2 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 TIH with 4.5" liner 21-Mar-2015Date: North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger/ J. McKinley Rig Activity: Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A20.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary 0' Hours 5 3/4" Z 7531' 00 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 9.5 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 32 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 5.18 Current Pump & Flow Data: Max Condition (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Finish Triping out. Rig up to run casing. Begain run in with 4.5" liner. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Continue running in production liner. Tag bottom at 7531' set liner and prepare to trip out. Trip out of hole and lay 5 Depth Current Pump & Flow Data: Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 5.18 Morning Report Report # 33 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 7.9 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A14.00 Depth in / out WOB N/A N/A Nabors 105 AC C. Cretsinger/ J. McKinley Rig Activity: Avg to 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 TOOH lay dpwn 4" drill pipe 22-Mar-2015Date: North Slope Alaska (current) 00 10,000 Units Average down 5" drill pipe. No significant gas recorded. 2 0 0 C-5n GvlCoal Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.09 Avg API FL Alkal Mud Type 76.4/23.6105 Ratio cP PVDensity (ppg) out 80' 13.375" MOBM 9.409.40 29.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = R. Mulkey / R. Lennberg R. Mulkey 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip3Background 0 4 0 00 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 4 0 0 (current) Cht Silt 2107' Trip3Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = R. Mulkey / R. Lennberg R. Mulkey 29.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" MOBM 9.409.40 Alkal Mud Type 76.4/23.6107 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.09 Avg API FL TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 C-5n GvlCoal Gas Summary No significant gas recorded. 2 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Trip in hole 23-Mar-2015Date: North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger/ J. McKinley Rig Activity: Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A14.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary 0' Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 7.9 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 34 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 4.92 Current Pump & Flow Data: Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Continue trip out of hole and lay down 5" drill pipe. Test BOPs. Run completion string. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 4 0 0 N/A N/A (current) Cht Silt 2107' Trip0Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 29.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" N/A N/A N/A MOBM 9.409.40 Alkal Mud Type N/A 76.4/23.6109 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL N/A N/A N/A TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 N/A C-5n GvlCoal N/A Gas Summary No significant gas recorded. 2 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Land Tubing 24-Mar-2015Date: North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger/ D. Dunbar Rig Activity: Avg toN/A Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A14.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary N/A N/A Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 7.9 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 35 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 4.92 Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Continue to run and pressure test the completion string. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Run and land tubing and jewelry. Test annulus, install back pressure valve, and nipple down BOP. Remove pipe 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 4.79 Morning Report Report # 36 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) No significant gas recorded. 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.2 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC C. Cretsinger/ D. Dunbar Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Test Frac BOP 25-Mar-2015Date: North Slope Alaska (current) 00 10,000 Units Average shed. Nipple up and test frac BOP. 1 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.69 Avg API FL Alkal Mud Type N/A 78.1/21.9135 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 30.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 3 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 0 0 0 N/A N/A (current) Cht Silt 2107' Trip0Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 31.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" N/A N/A N/A MOBM 9.409.40 Alkal Mud Type N/A 78.1/21.9139 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL N/A N/A N/A TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 N/A C-5n GvlCoal N/A Gas Summary 0 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 PSI Test Frac Lines 26-Mar-2015Date: North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger/ D. Dunbar Rig Activity: Avg toN/A Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 8.2 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 37 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 4.92 Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Continue to rig up and test BOPS and surface equipment in preparation for the upcoming fracing program. No significant gas recorded. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Continue to rig up the well head. Pressure test separators and flow back surface equipment. Pump 40 bbls ahead 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 4.92 Morning Report Report # 38 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) No significant gas recorded. 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.2 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC C. Cretsinger/ D. Dunbar Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Prepare to Frac 27-Mar-2015Date: North Slope Alaska (current) 00 10,000 Units Average and perform diagnostic fracture injection test (DFIT). Continue to prepare for the upcoming frac program. 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL Alkal Mud Type N/A 78.1/21.9140 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 30.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 0 0 0 N/A N/A (current) Cht Silt 2107' Trip0Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 31.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" N/A N/A N/A MOBM 9.409.40 Alkal Mud Type N/A 78.1/21.9130 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL N/A N/A N/A TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 N/A C-5n GvlCoal N/A Gas Summary down Halliburton high pressure line from the frac tree. Rig up Expro chemical injection line and prepare to flow back the well. 0 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Prep to Flow Back the Well 28-Mar-2015Date: North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger/ D. Dunbar Rig Activity: Avg toN/A Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 8.2 Lime Tools No significant gas recorded. 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 39 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 4.92 Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Analyze DFIT and finalize the frac program. Pump seawater to the frac tanks and heat. Pump 6 stage frac job. Rig 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 4.92 Morning Report Report # 40 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.2 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC C. Cretsinger/ D. Dunbar Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 29-Mar-2015Date: North Slope Alaska (current) 00 10,000 Units Average 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL Alkal Mud Type N/A 78.1/21.9130 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 31.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 0 0 0 N/A N/A (current) Cht Silt 2107' Trip0Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 30.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" N/A N/A N/A MOBM 9.409.40 Alkal Mud Type N/A 78.1/21.9115 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL N/A N/A N/A TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 N/A C-5n GvlCoal N/A Gas Summary 0 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 30-Mar-2015Date: North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger/ D. Dunbar Rig Activity: Avg toN/A Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 41 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 4.92 Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 4.92 Morning Report Report # 42 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC C. Cretsinger/ D. Dunbar Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 31-Mar-2015Date: North Slope Alaska (current) 00 10,000 Units Average 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL Alkal Mud Type N/A 78.1/21.9129 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 32.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 0 0 0 N/A N/A (current) Cht Silt 2107' Trip0Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 31.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" N/A N/A N/A MOBM 9.409.40 Alkal Mud Type N/A 78.1/21.9126 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL N/A N/A N/A TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 N/A C-5n GvlCoal N/A Gas Summary 0 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 1-Apr-2015Date: North Slope Alaska N/A N/A Nabors 105 AC S. Self / D. Dunbar Rig Activity: Avg toN/A Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 43 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 4.92 Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 4.92 Morning Report Report # 44 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC S. Self / D. Dunbar Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 2-Apr-2015Date: North Slope Alaska (current) 00 10,000 Units Average 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL Alkal Mud Type N/A 78.1/21.9130 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 31.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 0 0 0 N/A N/A (current) Cht Silt 2107' Trip0Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 31.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" N/A N/A N/A MOBM 9.409.40 Alkal Mud Type N/A 78.1/21.9130 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL N/A N/A N/A TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 N/A C-5n GvlCoal N/A Gas Summary 0 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 3-Apr-2015Date: North Slope Alaska N/A N/A Nabors 105 AC S. Self / D. Dunbar Rig Activity: Avg toN/A Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A15.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 45 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 4.92 Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 4.92 Morning Report Report # 46 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC S. Self / D. Dunbar Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 4-Apr-2015Date: North Slope Alaska (current) 00 10,000 Units Average 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL Alkal Mud Type N/A 78.1/21.9133 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 33.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 0 0 0 N/A N/A (current) Cht Silt 2107' Trip0Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 30.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" N/A N/A N/A MOBM 9.409.40 Alkal Mud Type N/A 78.1/21.9128 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL N/A N/A N/A TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 N/A C-5n GvlCoal N/A Gas Summary 0 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 5-Apr-2015Date: North Slope Alaska N/A N/A Nabors 105 AC S. Self / D. Dunbar Rig Activity: Avg toN/A Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A17.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 47 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 4.92 Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 4.92 Morning Report Report # 48 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC S. Self / D. Dunbar Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 6-Apr-2015Date: North Slope Alaska (current) 00 10,000 Units Average 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL Alkal Mud Type N/A 78.1/21.9125 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 31.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 0 0 0 N/A N/A (current) Cht Silt 2107' Trip0Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 31.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" N/A N/A N/A MOBM 9.409.40 Alkal Mud Type N/A 77.0/23.0136 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL N/A N/A N/A TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 N/A C-5n GvlCoal N/A Gas Summary 0 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 7-Apr-2015Date: North Slope Alaska N/A N/A Nabors 105 AC S. Self / D. Dunbar Rig Activity: Avg toN/A Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 8.2 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 49 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 4.92 Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 4.92 Morning Report Report # 50 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.2 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC S. Self / D. Dunbar Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 8-Apr-2015Date: North Slope Alaska (current) 00 10,000 Units Average 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL Alkal Mud Type N/A 77.0/23.0134 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 31.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 0 0 0 N/A N/A (current) Cht Silt 2107' Trip0Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 31.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" N/A N/A N/A MOBM 9.409.40 Alkal Mud Type N/A 77.0/23.0136 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL N/A N/A N/A TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 N/A C-5n GvlCoal N/A Gas Summary 0 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 9-Apr-2015Date: North Slope Alaska N/A N/A Nabors 105 AC S. Self / D. Dunbar Rig Activity: Avg toN/A Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 8.2 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 51 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 4.92 Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 4.92 Morning Report Report # 52 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.2 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC S. Self / J. McKinley Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 10-Apr-2015Date: North Slope Alaska (current) 00 10,000 Units Average 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.79 Avg API FL Alkal Mud Type N/A 77.0/23.0140 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 31.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 5.18 Morning Report Report # 53 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.2 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC S. Self / J. McKinley Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 11-Apr-2015Date: North Slope Alaska (current) 00 10,000 Units Average 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.99 Avg API FL Alkal Mud Type N/A 77.0/23.0139 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 31.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 0 0 0 N/A N/A (current) Cht Silt 2107' Trip0Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 30.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" N/A N/A N/A MOBM 9.409.40 Alkal Mud Type N/A 76.4/23.6157 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.99 Avg API FL N/A N/A N/A TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 N/A C-5n GvlCoal N/A Gas Summary 0 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Flow Test the Well 12-Apr-2015Date: North Slope Alaska N/A N/A Nabors 105 AC S. Self / J. McKinley Rig Activity: Avg toN/A Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 54 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 5.18 Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Flow test the well. No significant gas recorded. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Flow test the well. Shut in the well. No significant gas recorded. 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 5.18 Morning Report Report # 55 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC S. Self / J. McKinley Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Shut in the well.13-Apr-2015Date: North Slope Alaska (current) 00 10,000 Units Average 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.99 Avg API FL Alkal Mud Type N/A 76.4/23.6159 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 30.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / A. Bongard A. Bongard 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Well shut in at time of report. No significant gas recorded. 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 5.18 Morning Report Report # 56 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC S. Self / J. McKinley Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Shut in the well.14-Apr-2015Date: North Slope Alaska (current) 00 10,000 Units Average 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 3.99 Avg API FL Alkal Mud Type N/A 76.4/23.6158 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 30.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / B. Hur B. Hur 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 0 0 0 N/A N/A (current) Cht Silt 2107' Trip0Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = N/A N/A R. Lennberg / B. Hur B. Hur 30.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" N/A N/A N/A MOBM 9.409.40 Alkal Mud Type N/A 76.4/23.6160 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 4.00 Avg API FL N/A N/A N/A TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 N/A C-5n GvlCoal N/A Gas Summary 0 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Shut in the well.15-Apr-2015Date: North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger / J. McKinley Rig Activity: Avg toN/A Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 57 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 5.18 Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Pressure up to 1,200 psi and opened well. Flow testing well at time of report. No significant gas recorded. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Flow tested well. Bullheaded well with 160 bbls of 9.4 ppg MOBM. Flow checked well and shut the well in. Rigged No significant gas recorded. 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 5.18 Morning Report Report # 58 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 8.3 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A16.00 Depth in / out WOB N/A N/A Nabors 105 AC C. Cretsinger / J. McKinley Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 N/U BOPS 16-Apr-2015Date: North Slope Alaska (current) 00 10,000 Units Average down coil tubing. Closed and tested the downhole valve. Nippled down frac tree. Nippling up BOPS at time of report. 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 4.00 Avg API FL Alkal Mud Type N/A 76.4/23.6158 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 30.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / B. Hur B. Hur 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 9.63''5235'Intermedate 47.0 L-80 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 3 VM-3 Milltooth 8.5 0.942 7.50 5248' Viscosity Cor Solids %in Continued to nipple up BOP's and test. Circulated a bottoms up. Pumped a 30 bbls LCM pill followed by 10 bbl of Monitored losses at 11 bbls/hr. Pumped a 31 bbls LCM pill followed by 5 bbls MOBM and then squeezed into liner 5 Depth Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 @ Mud Data Depth 95% 4.92 Morning Report Report # 59 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) with 40 bbls of MOBM. Minor losses at time of report. 0 00 Min Comments Mud RPM ECD (ppg) ml/30min 7.6 Lime Tools 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A 41.4 Type Cly 2017' Lst 20.18 2115' 5248' 2115' Size 0.942 00 6 Tuff Cement 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A14.00 Depth in / out WOB N/A N/A Nabors 105 AC C. Cretsinger / J. McKinley Rig Activity: Avg toN/A 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 Pump Pill 17-Apr-2015Date: North Slope Alaska (current) 00 10,000 Units Average MOBM then squeezed into liner with 40 bbls MOBM. Seal assembly not 100% stung and some returns were taken. 0 0 0 N/A C-5n GvlCoal N/A Gas Summary C-2 ShClyst C-3 0 C-4i C-4n C-5i N/A N/A N/A TFA Depth Oil / Water Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 4.00 Avg API FL Alkal Mud Type N/A 62.0/27.0153 Ratio cP PVDensity (ppg) out 80' 13.375" N/A N/A N/A MOBM 9.409.40 24.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00''Conductor = N/A N/A R. Lennberg / B. Hur B. Hur 0 Unit Phone: N/AConnection 0 0 100% Gas In Air Maximum Report By:Logging Engineers: 00 (max) 0 Minimum 0 C-1 Chromatograph (ppm) Size SiltstSs (current) Cht Silt 2107' Trip0Background 0 0 0 0 N/A N/A 0 3133'24 142 131.0 J-55 0 Set At 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 . . * 24 hr Recap: 1-2-CT-A-X-I-WT-TD2NOV SKH519M-A7C 12.25 0.796 47.54 0 3133'24 142 131.0 J-55 0 Set At 0 0 0 N/A N/A (current) Cht Silt 2107' Trip0Background 0 0 C-1 Chromatograph (ppm) Size SiltstSs Maximum Report By:Logging Engineers: 00 (max) 0 Minimum Unit Phone: N/AConnection 0 0 100% Gas In Air 0 Conductor = N/A N/A R. Lennberg / B. Hur B. Hur 25.00 (907) 685-3276 Units* Casing Summary Lithology (%) 7531' Bit # Grade 20.00'' out 80' 13.375" N/A N/A N/A MOBM 10.4010.40 Alkal Mud Type N/A 72.4/27.6157 Ratio cP PVDensity (ppg) Bit Type YP (lb/100ft2)(sec/qt) Footage SPP (psi) Gallons/stroke 4.00 Avg API FL N/A N/A N/A TFA Depth Oil / Water 0 C-4i C-4n C-5iC-2 ShClyst C-3 N/A C-5n GvlCoal N/A Gas Summary Decision made to trip out despite losses. Losses were mitigated to 1 bb/hr oncee to surface. TIH and R/U cementer. Waiting on 0 0 0 (current) 00 10,000 Units Average 7531' 7531' 0' Repsol E&P USA Inc.AK-AM-0902062414 TIH and R/U Cementers 18-Apr-2015Date: North Slope Alaska N/A N/A Nabors 105 AC C. Cretsinger / J. McKinley Rig Activity: Avg toN/A Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) N/A12.00 Depth in / out WOB 1 16 L80 80.0 7531' 5.75 0.614 3 Surface VM-3 Milltooth 24 hr Max 68.0 Weight 98' MWD Summary N/A 0' Hours 5 3/4" Z 7531' 00 6 Tuff Cement 20.18 2115' 5248' 2115' Size 0.942 41.4 Type Cly 2017' Lst 1-1-WT-A-E-E-E-IN-NO-TD (max)N/A Min Comments Mud RPM ECD (ppg) ml/30min 10.2 Lime Tools 0 00 Report For: Max @ ft 3:00 AMTime: Current ROP ROP (ft/hr) Morning Report Report # 60 CONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(c) Customer: Well: Area: Location: Rig: Job No.: Daily Charges: Total Charges: Qugruk 301 @ Mud Data Depth 95% 5.18 Current Pump & Flow Data: N/A Max Condition 0-0-NO-A-X-I-NO-TD (lb/bbl) 3.14 Depth Viscosity Cor Solids %in Monitored Losses at 8.4 bbl/hr, squeezed an additional 35 bbl LCM pill and monitored losses at 8-9 bbl/hr. spacer at time of report. 5 3 VM-3 Milltooth 8.5 0.942 7.50 5248' 5278' 30'29 50 1-1-WT-A-E-NO-TD 4 NOV SKH513M 6.5 0.354 22.10 5278' 7531' 2253'76 120 1-1-BU-A-X-I-BT-TD 9.63''5235'Intermedate 47.0 L-80 WELL INFORMATION Created On : Apr 28 2015 Customer :Repsol E&P USA Inc. Well Name :Qugruk 301 Job Number :AK-XX-0902062414 Rig Name :Nabors 105AC Field Name :Colville River State / Province :Alaska Survey Report SURVEY HEADER Survey data provided by Schlumberger. DIRECTIONAL SURVEY DATA Tie-in 0.00 0.00 0.00 0.00 0.00 N 0.00 E (ft) Measured Depth DoglegVertical SectionDeparture (ft) Latitude (ft) Vertical Depth (deg) DirectionInclination (deg)(ft)(ft)(°/100') 20.00 0.00 0.00 20.00 0.00 N 0.00 E 0.00 0.00 101.08 0.17 54.29 101.08 0.07 N 0.10 E 0.07 0.21 204.00 0.50 161.08 204.00 0.27 S 0.37 E -0.27 0.56 293.45 0.72 153.93 293.44 1.14 S 0.74 E -1.14 0.26 389.15 0.65 157.17 389.14 2.18 S 1.22 E -2.18 0.08 478.11 0.80 165.50 478.09 3.25 S 1.57 E -3.25 0.21 575.60 1.00 169.67 575.57 4.74 S 1.89 E -4.74 0.22 667.64 0.96 142.79 667.59 6.15 S 2.50 E -6.15 0.50 765.90 1.04 168.22 765.84 7.67 S 3.18 E -7.67 0.45 862.02 1.17 178.95 861.94 9.51 S 3.38 E -9.51 0.25 958.99 1.27 172.02 958.89 11.56 S 3.54 E -11.56 0.18 1046.84 1.37 164.63 1,046.72 13.54 S 3.96 E -13.54 0.22 1140.25 1.17 158.48 1,140.10 15.50 S 4.60 E -15.50 0.26 1239.79 0.86 161.23 1,239.63 17.16 S 5.22 E -17.16 0.32 1337.01 0.75 156.37 1,336.84 18.43 S 5.71 E -18.43 0.13 1431.83 0.60 157.77 1,431.65 19.46 S 6.14 E -19.46 0.16 1527.15 0.53 152.72 1,526.97 20.31 S 6.53 E -20.31 0.09 1625.64 0.51 136.72 1,625.45 21.04 S 7.04 E -21.04 0.15 1721.70 0.52 140.27 1,721.51 21.68 S 7.61 E -21.68 0.03 1816.07 0.43 154.77 1,815.88 22.33 S 8.04 E -22.33 0.16 1912.27 0.55 141.09 1,912.07 23.02 S 8.48 E -23.02 0.17 2007.40 0.58 141.04 2,007.20 23.75 S 9.07 E -23.75 0.03 2040.60 0.63 137.93 2,040.40 24.01 S 9.30 E -24.01 0.18 2134.84 0.68 125.71 2,134.63 24.73 S 10.10 E -24.73 0.16 2229.81 1.57 356.44 2,229.59 23.76 S 10.48 E -23.76 2.18 2326.55 3.96 347.80 2,326.21 19.17 S 9.69 E -19.17 2.50 2422.49 6.61 349.41 2,421.73 10.50 S 7.97 E -10.50 2.77 2517.50 8.10 350.12 2,515.96 1.47 N 5.82 E 1.47 1.57 2614.06 10.26 348.56 2,611.28 16.60 N 2.95 E 16.60 2.25 2709.78 13.17 345.16 2,704.99 35.50 N 1.54 W 35.50 3.12 INSITE V8.1.10 Page 1Job No: AK-XX-0902062414 Well Name: Qugruk 301 Survey ReportCONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) DIRECTIONAL SURVEY DATA (ft) Measured Depth DoglegVertical SectionDeparture (ft) Latitude (ft) Vertical Depth (deg) DirectionInclination (deg)(ft)(ft)(°/100') 2804.63 16.08 342.53 2,796.76 58.48 N 8.25 W 58.48 3.15 2901.61 17.91 340.74 2,889.50 85.37 N 17.20 W 85.37 1.96 2997.48 19.73 339.75 2,980.24 114.47 N 27.67 W 114.47 1.93 3092.02 22.55 340.76 3,068.41 146.57 N 39.16 W 146.57 3.01 3187.55 25.12 341.87 3,155.79 183.14 N 51.51 W 183.14 2.73 3282.26 27.93 349.26 3,240.55 224.05 N 61.91 W 224.05 4.57 3377.30 30.28 353.59 3,323.59 269.74 N 68.73 W 269.74 3.32 3472.92 33.68 357.52 3,404.69 320.21 N 72.57 W 320.21 4.17 3568.99 37.42 3.22 3,482.86 376.00 N 72.08 W 376.00 5.20 3664.95 40.71 5.93 3,557.37 436.26 N 67.21 W 436.26 3.86 3760.82 43.93 11.13 3,628.26 500.02 N 57.56 W 500.02 4.96 3857.14 47.05 13.29 3,695.78 567.13 N 43.00 W 567.13 3.61 3953.49 50.44 15.35 3,759.31 637.29 N 25.05 W 637.29 3.87 4047.39 52.60 17.05 3,817.74 707.87 N 4.53 W 707.87 2.70 4143.67 55.77 17.03 3,874.07 782.50 N 18.34 E 782.50 3.29 4238.08 59.17 17.82 3,924.83 858.43 N 42.18 E 858.43 3.67 4333.22 61.70 19.48 3,971.78 936.83 N 68.66 E 936.83 3.06 4429.08 64.83 18.45 4,014.90 1,017.78 N 96.47 E 1017.78 3.40 4526.18 67.83 18.20 4,053.87 1,102.20 N 124.42 E 1102.20 3.10 4621.74 69.81 19.43 4,088.40 1,186.53 N 153.16 E 1186.53 2.39 4717.52 74.11 20.08 4,118.05 1,272.22 N 183.94 E 1272.22 4.54 4813.13 76.52 18.46 4,142.29 1,359.52 N 214.46 E 1359.52 3.01 4911.01 80.54 19.78 4,161.75 1,450.13 N 245.88 E 1450.13 4.31 5007.05 84.22 17.96 4,174.49 1,540.19 N 276.65 E 1540.19 4.27 5102.59 86.86 17.33 4,181.92 1,630.95 N 305.52 E 1630.95 2.84 5241.00 90.17 19.00 4,185.50 1,762.39 N 348.65 E 1762.39 2.68 5312.94 90.65 19.74 4,184.99 1,830.26 N 372.51 E 1830.26 1.23 5359.69 90.76 18.96 4,184.41 1,874.36 N 388.00 E 1874.36 1.68 5408.85 90.45 18.43 4,183.89 1,920.93 N 403.75 E 1920.93 1.25 5453.17 90.41 17.91 4,183.56 1,963.03 N 417.57 E 1963.03 1.18 5504.94 90.72 18.57 4,183.05 2,012.20 N 433.78 E 2012.20 1.41 5553.25 90.48 19.22 4,182.54 2,057.90 N 449.42 E 2057.90 1.43 5600.80 90.79 19.40 4,182.02 2,102.78 N 465.14 E 2102.78 0.75 5654.47 90.72 19.23 4,181.31 2,153.42 N 482.89 E 2153.42 0.34 5696.41 90.38 19.06 4,180.91 2,193.04 N 496.65 E 2193.04 0.91 5792.46 90.99 20.21 4,179.76 2,283.50 N 528.92 E 2283.50 1.36 5888.06 91.27 20.09 4,177.87 2,373.23 N 561.85 E 2373.23 0.32 5985.60 91.27 20.49 4,175.71 2,464.69 N 595.66 E 2464.69 0.41 6078.80 90.99 19.75 4,173.87 2,552.19 N 627.72 E 2552.19 0.85 6173.33 91.06 19.90 4,172.18 2,641.10 N 659.77 E 2641.10 0.18 6267.70 90.96 20.07 4,170.52 2,729.77 N 692.02 E 2729.77 0.21 6362.80 91.13 19.65 4,168.78 2,819.20 N 724.32 E 2819.20 0.48 6460.51 90.93 19.84 4,167.03 2,911.15 N 757.32 E 2911.15 0.28 6557.05 90.93 19.37 4,165.46 3,002.08 N 789.71 E 3002.08 0.49 6651.66 91.17 19.14 4,163.73 3,091.39 N 820.91 E 3091.39 0.35 INSITE V8.1.10 Page 2Job No: AK-XX-0902062414 Well Name: Qugruk 301 Survey ReportCONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C) DIRECTIONAL SURVEY DATA (ft) Measured Depth DoglegVertical SectionDeparture (ft) Latitude (ft) Vertical Depth (deg) DirectionInclination (deg)(ft)(ft)(°/100') 6746.17 91.30 19.38 4,161.69 3,180.59 N 852.07 E 3180.59 0.29 6843.67 91.07 21.11 4,159.67 3,272.04 N 885.80 E 3272.04 1.79 6938.05 91.24 19.57 4,157.77 3,360.51 N 918.60 E 3360.51 1.64 7035.52 91.10 20.34 4,155.78 3,452.11 N 951.86 E 3452.11 0.80 7131.48 90.93 20.07 4,154.08 3,542.15 N 985.00 E 3542.15 0.33 7227.03 91.03 19.78 4,152.45 3,631.97 N 1,017.55 E 3631.97 0.32 7321.66 91.20 17.11 4,150.61 3,721.71 N 1,047.49 E 3721.71 2.83 7417.21 90.96 18.25 4,148.80 3,812.73 N 1,076.50 E 3812.73 1.22 7494.91 90.93 18.89 4,147.52 3,886.38 N 1,101.24 E 3886.38 0.82 7531.00 90.93 18.89 4,146.94 3,920.52 N 1,112.92 E 3920.52 0.00 SURVEY FOOTER DIRECTIONAL SURVEY DATA NOTES - Calculation based on minimum curvature method. - Survey coordinates relative to well system reference point. - TVD values given relative to drilling measurement point. - Vertical section relative to well head. - Vertical section is computed along a direction of 0.00 degrees (Grid) - A total correction of 18.61 deg from Magnetic north to Grid north has been applied - Horizontal displacement is relative to the well head. - Horizontal displacement (closure) at 7,531.00 feet is 4,075.42 feet along 15.85 degrees (Grid) WARRANTY HALLIBURTON ENERGY SERVICES, INC. WILL USE ITS BEST EFFORTS TO FURNISH CUSTOMERS WITH ACCURATE INFORMATION AND INTERPRETATIONS THAT ARE PART OF, AND INCIDENT TO, THE SERVICES PROVIDED. HOWEVER, HALLIBURTON ENERGY SERVICES, INC. CANNOT AND DOES NOT WARRANT THE ACCURACY OR CORRECTNESS OF SUCH INFORMATION AND INTERPRETATIONS. UNDER NO CIRCUMSTANCES SHOULD ANY SUCH INFORMATION OR INTERPRETATION BE RELIED UPON AS THE SOLE BASIS FOR ANY DRILLING, COMPLETION, PRODUCTION, OR FINANCIAL DECISION OR ANY PROCEDURE INVOLVING ANY RISK TO THE SAFETY OF ANY DRILLING VENTURE, DRILLING RIG OR ITS CREW OR ANY THIRD PARTY. THE CUSTOMER HAS FULL RESPONSIBILITY FOR ALL DRILLING, COMPLETION, AND PRODUCTION OPERATION. HALLIBURTON ENERGY SERVICES, INC. MAKES NO REPRESENTATIONS OR WARRANTIES, EITHER EXPRESSED OR IMPLIED, INCLUDING, BUT NOT LIMITED TO, THE IMPLIED WARRANTIES OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, WITH RESPECT TO THE SERVICES RENDERED. IN NO EVENT WILL HALLIBURTON ENERGY SERVICES, INC. SERVICES BE LIABLE FOR FAILURE TO OBTAIN ANY PARTICULAR RESULTS OR FOR ANY DAMAGES, INCLUDING, BUT NOT LIMITED TO, INDIRECT, SPECIAL OR CONSEQUENTIAL DAMAGES, RESULTING FROM THE USE OF ANY INFORMATION OR INTERPRETATION PROVIDED BY HALLIBURTON ENERGY SERVICES, INC. INSITE V8.1.10 Page 3Job No: AK-XX-0902062414 Well Name: Qugruk 301 Survey ReportCONFIDENTIAL DATA TRANSMITTAL PER AS 38.05.035(a)(8)(C)