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O 109
OTHER ORDER NO. 109 Hilcorp Alaska, LLC Docket No. OTH-15-029 1. April 23, 2015 Approved Sundry Application 2. November 16, 2015 NOV to Hilcorp re: Failure to Test BOPE After Use, Nordic Rig 3, MPU I-03 (PTD 1900920) 3. November 18, 2015 Letter from Lane Powell, notice of appearance as attorney of record on behalf of Hilcorp. 4. November 20, 2015 Hilcorp requesting informal review with attorney present 5. November 23, 2015 Letter from AOGCC informing Hilcorp that informal review is without attorney present 6. November 25, 2015 Hilcorp request for Informal Review with no attorney present 7. December 15, 2015 AOGCC letter informing Hilcorp of date and time of informal review 8. January 29, 2016 Hilcorp's submission for informal review 9. February 18, 2016 Informal Review sign -in sheet 10. February 19, 2016 Hilcorp response to questions asked during informal review 11. February 24, 2016 Hilcorp's request to maintain confidentiality of individual's names involved in incident 12. May 16, 2016 Hilcorp's civil penalty payment and letter (CONFIDENTIAL Penalty Calculation held in Secure Storage) OTHER ORDER NO. 109 ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: Failure to Test BOPE After Use Other Order 109 Milne Point Unit I-03 Docket Number: OTH-15-029 PTD 1900920 May 3, 2016 DECISION AND ORDER On November 16, 2015 the Alaska Oil and Gas Conservation Commission (AOGCC) issued a Notice of Proposed Enforcement Action (Notice) to Hilcorp Alaska, LLC (Hilcorp) regarding the Milne Point Unit well I-03 (MPU I-03). The Notice was based upon Hilcorp's failure to notify AOGCC of the use of blowout prevention equipment (BOPE) and the failure to test the BOPE after its use prior to reentering MPU I-03 to run the well completion. The Notice proposed specific corrective actions and a $40,000 civil penalty under AS 31.05.150(a). Hilcorp requested an informal review. That review was held February 18, 2016. Summary of Proposed Enforcement Action: The Notice identified violations by Hilcorp of 20 AAC 25.285. Hilcorp shut in MPU I-03 with BOPE to stop the flow of fluids from the well. After use of the BOPE, Hilcorp was required to test the used BOPE components before the next wellbore entry. Hilcorp failed to test the BOPE components used during well control operations. The Notice proposed the following corrective actions be completed by Hilcorp: 1) provide AOGCC a detailed description and an example of its regulatory compliance tracking program; 2) provide AOGCC a copy of the written management of change procedures that correct the violations; and 3) provide AOGCC a detailed written explanation that describes how recurrence of the violations will be prevented. For violating 20 AAC 25.285 the AOGCC proposed civil penalties under AS 31.05.150(a) as follows: - $20,000 for failing to notify AOGCC of the use of BOPE to prevent the flow of fluids from MPU I-03. - $20,000 for failing to test BOPE used to prevent the flow of fluids from MPU I-03. Blowout Prevention Equipment: Secondary well control equipment (known as BOPE) includes the casinghead assembly of valves, rams and other pack -off devices installed on a rig during drilling, completion, and workover operations. The BOPE — designed to close around the drill pipe, work string, tubing, casing or tools — is able to completely close the top of the casing to control well pressure. The rated working pressure of the BOPE must exceed the maximum potential surface pressure. BOPE must be maintained in good operating condition at all times and must be regularly tested. Other Order 109 May 3, 2016 Page 2 of 7 If any BOPE is used for well control or equivalent purpose, the components used must be function pressure -tested before the next wellbore entry. Informal Review: On January 29, 2016 Hilcorp submitted a consolidated brief ("brief') in advance of an informal review covering four Notices of Proposed Enforcement Actions, including this action.' On February 18, 2016 Hilcorp was provided an opportunity to present the information it claimed AOGCC should have considered in its proposed enforcement action. Hilcorp argued that the rig's Well Site Manager provided proper notice to AOGCC by electronic mail regarding the use of BOPE at MPU I-03. Hilcorp also argued that the well flowing was an "expected possible consequence of the operation" and that actions taken in response were consistent with its work plan. Hilcorp included copies of email messages — both internal to Hilcorp and between Hilcorp's Well Site Manager and AOGCC. Hilcorp asserts that AOGCC's proposed penalties are based on an "incomplete understanding of the factual record", and claims AOGCC has "overlooked" communications between Hilcorp and AOGCC personnel. Hilcorp also contends that the BOPE was not used for well control purposes at MPU I-03, therefore no re -test was required .2 Discussion: Workover operations on MPU I-03 were approved by AOGCC on April 23, 2015 (Sundry Approval 315-233), authorizing Hilcorp to replace a failed electric submersible pump (ESP) with a new ESP completion. Operations reports indicate Hilcorp commenced the workover with Nordic Rig 3 on April 30, 2015. MPU I-03 began to flow during workover operations on May 1, 2015. The well was shut in with the annular preventer and with a floor safety valve installed in the work string. Kill weight fluid was also ordered as there was an insufficient volume available at the location to displace and kill the well. The AOGCC has considered the factors in AS 31.05.150(g) in its determination of penalties for the MPU I-03 violations. Hilcorp neither offers mitigating factors nor demonstrates AOGCC missed information in reviewing the enforcement action. Relying on emails between Hilcorp and AOGCC, Hilcorp argued proper notice had been provided and that AOGCC approved Hilcorp's failure to report use of BOPE. However, review of internal Hilcorp emails establishes that critical factual information known to Hilcorp was not provided to AOGCC when Hilcorp asked if it was required to report use of the BOPE. Specifically, Hilcorp failed to provide information regarding well pressures, failed to advise AOGCC there were insufficient materials on hand for weighting up the well fluid, and failed to advise AOGCC that a floor safety valve was installed to stop the flow of fluids to surface from the work string. All of the information Hilcorp failed to provide was critical to AOGCC's determination of whether a report was required. Because that information points to a well control event instead of a planned activity, 1 Other 15-025 (Unauthorized Changes to Approved Permit; MPU J-08A); Other 15-029 (Failure to Test BOPE After Use, MPU I-03); Other 15-030 (Failure to Note of Changes to an Approved Permit; MPU J-01A); Other 15- 031 (Failure to Notify of Changes to an Approved Permit; MPU J-09A) 2 Hilcorp Submission to AOGCC for Informal Review (Dockets OTH-15-25, OTH-15-29, OTH-15-30, and OTH- 15-31), pages 1 and 15. Other Order 109 • • May 3, 2016 Page 3 of 7 Hilcorp would have been required to report its use of the BOPE had it provided the missing information. Hilcorp has provided no evidence to support its claim this well control event was a planned event. In fact, its failure to maintain sufficient materials at the locations to weight up the well fluid undermines its claim that the use of the BOPE was planned. AOGCC's proposed enforcement noted the violation here was not isolated and is emblematic of ongoing compliance problems with Hilcorp rig workover operations. AOGCC also noted the disregard for regulatory compliance is endemic to Hilcorp's approach to its Alaska operations. Hilcorp objects to these statements, characterizes AOGCC's observations as "inflammatory" and "harsh", and claims "virtually all" of its operations are performed in full compliance. Table 1 attached to this Decision lists numerous incidents of noncompliance, some of which are recurring events. Specific to this incident, in 2013 the AOGCC fined Hilcorp a total of $115,000 for violations relating to failure to test BOPE after use for well control.3 Previous versions of Table 1 have been provided to Hilcorp's Alaska managers during meetings about compliance concerns. The noncompliance history even triggered at least one unprecedented meeting with Hilcorp field operations staff at their Kenai field office to emphasize AOGCC's concerns and elaborate on AOGCC expectations for regulatory compliance.4 Findings and Conclusions: Hilcorp violated 20 AAC 25.285. Hilcorp was clearly aware of the requirement to notify the AOGCC that the BOPE was used to control flow from the well based on the internal Hilcorp email correspondence. While Hilcorp did initiate contact with AOGCC staff regarding the use of BOPE, the email from Hilcorp to the AOGCC failed to advise AOGCC that MPU I-03 was flowing and had been shut in with the annular preventer and a floor safety valve, did not mention that the well started flowing with oil to surface almost immediately upon releasing off the packer, nor were the shut in tubing and shut in casing pressures provided to the AOGCC. Hilcorp communicated to AOGCC that only the annular preventer was used to shut in while waiting to increase the workover fluid density.5 If the details included in the internal Hilcorp emails (May 2, 2015, 5:43 am) had been provided in the email to AOGCC questioning the need to report a BOPE use (May 2, 2015 12:31 pm), the AOGCC would have required a BOPE use report and instructed Hilcorp that the used BOPE components must be tested before reentering the well. Hilcorp's suggestion that the use of BOPE at MPU I-03 was not for well control is unconvincing. The MPU 1-03 event was clearly well control related, clearly warranted closure of the BOPE to prevent the flow of well fluids at surface, and required proper notice and testing of all used components of the BOPE prior to running the replacement ESP completion. AOGCC does acknowledge that notice of BOPE use did occur despite Hilcorp's communication being misleading and incomplete. As a result, the proposed penalty will be mitigated. 3 AOGCC Other Order 80, "Failure to Notify of Changes to an Approved Permit; and Failure to Test Blowout Prevention Equipment" 4 Meeting requested and arranged by Hilcorp management; held November 11, 2013 5 Hilcorp Submission to AOGCC for Informal Review (Dockets OTH-15-25, OTH-15-29, OTH-15-30, OTH 15-31), Exhibits 21 and 22 Other Order 109 • May 3, 2016 Page 4 of 7 Now Therefore It Is Ordered That: A civil penalty in the amount of $20,000 is imposed for the initial event of failing to test BOPE after being used for well control purposes and prior to the next wellbore entry (in this case prior to running the replacement ESP completion). AOGCC is eliminating the penalty for failure to notify of the use of BOPE. In addition, Hilcorp is instructed to provide AOGCC with a detailed explanation of how recurrence of this violation will be prevented in the future. Included in the corrective actions must be how Hilcorp has acted or will act to ensure accurate information is provided to AOGCC for decisions. As an Operator involved in an enforcement action, you are required to preserve documents concerning the above action until after resolution of the proceeding. Done at Anchorage, Alaska and dated May 3, 2016. Cath P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner Attachment RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or 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 of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Other Order 109 May 3, 2016 Page 5 of 7 Table 1— Hilcorp Noncompliance History Date Non -Compliance Location AOGCC Comments Action April 2012 Missing SVS tests; Failure Westside CI No action taken Numerous efforts by AOGCC to obtain SVS test to notify AOGCC for test results for IRU, PCU, LRU, Stump Lake; some witness missing SVS tests between 5/2011 and 2/2012; some failure to notify AOGCC for opportunity to witness (previous operator responsible for some tests) 5/8/2012 Missing Kill Line Valve Swanson River 21-22 NOV BOPE test; Inspector observed missing kill line valve (Aurora Rig 1) at inlet to stack (1 installed; 2 required) 9/17/2012 Choke Manifold Valves Swanson River 21-25 Corrective Rig crew performing choke manifold test greased and cheated closed during (Aurora Rig 1) actions had to cheat choke manifold valves closed to pass BOPE test pressure test 10/2/2012 Notice of Meter Happy Valley Corrective AOGCC has not received notice of meter calibration Calibrations actions for Happy Valley custody transfer meter for at least as long as Hilcorp has been responsible for the meter; schedule provided 10/9/12 10/18/2012 Incorrect BOPE Test Soldotna Ck 44-33 See 10/23/12 When finally tested BOPE after use (10/18/12), tested Pressure (Do on Rig 1) enforcement to wrong pressure (4000 si instead of 5000 si) Failure to notify of changes Civil Penalty; Hilcorp failed to follow well drilling procedures to approved permit Corrective approved in PTD by AOGCC; failed to notify 10/23/2012 Soldotna Ck 44-33 Actions (Other AOGCC of changes to well plan; failed to maintain (Doyon Rig 1) Order 80) well in overbalanced condition; lack mgt of change Well control; Failure to test Hilcorp failed to test BOPE used in well control BOPE after use operations prior to first wellbore entry following use 10/26/2012 Failure to Test BOPE Granite Pt 32-13RD Denied request Test due 10/26/12, started running completion within 7 days (crane workover) for delaying 1500hrs on 10/26 without making any attempt to get BOPE test test extension (working daylight hours only); landed pipe high, had to trip pipe; request extension 10/27/12 10/31/2012 Improper gauge on IA Trading Bay Unit D- none Hilcorp self -reported that gauge was pegged out; 45 2000 si alarm set, 1000 si gauge; well Sl by Hilco 6 NOV — Notice of Violation; no financial penalty; corrective actions only • Other Order 109 May 3, 2016 Page 6 of 7 Date Non -Compliance Location AOGCC Comments Action 11/29/2012 Missing well control Happy Valley B-16 NOV Missing top drive valve(s) on 10/10/12 and again equipment Aurora Rig 1) 11/18/12; reviewing Hilcorp response rec'd 12/11/12 11/29/2012 Incorrect BOPE test Granite Point #50 NOV Sundry 312-439 required BOPE rams, valves to test to pressure Schlumber er CT 2) 4500 si; Hilcorp tested to 3500 si 12/6/2012 Conduct of operations Trading Bay Unit G- NOV Violation found 11/7/12 as part of rig inspection/ and 32 (Williams Rig 404) BOPE test witness; hazardous conditions; wellbore fluids on deck; equipment placement; lack of winterization; reviewing Hilcorp response rec'd 12/21/12 12/16/2012 Winterization; Conduct of Trading Bay Unit G- Ordered ops Inspector arrived 12/15/12 for BOPE test; unable to Operations 32 (Williams Rig 404) shut down on test due to fluids covering stack well cellar (similar to Rig 404 until issued noted in 12/6/12 NOV); returned 12/16/12 to corrective test BOPE — unable to test BOPE (frozen choke actions manifold, top drive valves, floor safety valves, choke implemented and kill lines along with everything else not in heated enclosure. Rig ops allowed to restart 12/31/12 after corrective actions, inspection and passing BOPE test 12/16/2012 Commence production w/o Nikolaevsk Unit (Red Corrective 12/18/12 — Hilcorp contacts AOGCC with notice of approved LACT meter pad) actions SVS testing; AOGCC determined by questioning status that well commenced production 12/16/12; application for LACT meter rec'd 1/9/12 4/11/2013 Defeated SVS Sterling 43-09X NOV SVS found defeated 3/15/13 during AOGCC inspection; well was SI without testing 9/30/2013 Defeated SVS Swanson River Field NOV SVS found defeated 9/2/13 during AOGCC KGSF # 1 inspection; needle valve on actuator blocked 1/14/2014 Defeated SVS Swanson River Field NOV SVS on 3 rod pump wells found defeated during Missing Annulus Gauges SCU 12A-04; SCU 12/9/13 AOGCC inspection; found SCU 24A-09 w/o 24A-09; SCU 41A-08 the re 'd pressure gauge to monitor outer annulus 4/22/2014 Defeated SVS Ninilchik Unit SD-3; Corrective SSSV found by AOGCC Inspectors 4/15/14 and Ninilchik Unit FC-5 actions 4/16/14; Hilcorp reported on 4/21/14; Inspector required SSSV back in service before departing 8/29/2014 Failure to Test BOPE Trading Bay Unit G- NOV Rig exceeded allowed 7days between BOPE tests 11 (Moncla Rig 301) without AOGCC approval • • Other Order 109 May 3, 2016 Page 7 of 7 Date Non -Compliance Location AOGCC Comments Action 10/31/2014 Failure to Test Required Ninilchik Unit Paxton Corrective No enforcement; reported by Hilcorp; approved Well Control Equipment 7 & Paxton 8 actions sundry required testing despite wells being isolated from the formation 1/5/2015 Workover Safety Concerns Hilcorp Cook Inlet Meeting 1/9/15; List of concerns provided to Hilcorp addressing and Kenai Peninsula Corrective suitability of equipment and procedures; unsafe Rig Workovers actions working conditions associated with rig workovers; onshore and offshore Cook Inlet 1/7/2015 Casing Valves Inaccessible Ninilchik Unit Paxton Meeting 1/9/15; Frozen well cellar found by Inspector 1/7/15; operator 8 Corrective instructed to thaw cellar; no action taken per Hilcorp actions (1/9/15 mtg - "operator unclear about req'd action"); AOGCC Deficiency Report created to track corrective actions identified during inspections 2/4/2015 Defeated SVS Northstar Unit NS-15 NOV SSV found defeated during 1/23/15 AOGCC inspection 4/22/2015 Failure to Obtain Approval Kenai Gas Field KDU NOV Operating without required competent tubing and for Continued Production 1 packer; no AOGCC approval (20 AAC 25.200); discovered as part of well review; well shut in 9/4/2015 Rig Operations with Failed Milne Pt Unit F-96 Notice of AOGCC Docket OTH 15-024; Notice sent 11/25/15; Gas Detection System Proposed informal review held 2/18/16; Final Decision pending Enforcement (Civil Penal 10/1/2015 Failure to follow approved All Hilcorp-operated Shut down well AOGCC-ordered suspension of all rig workover procedures/good oilfield rigs performing workover operations; corrective actions required; conditional practices workovers operations approval for restart 10/21/15 is Singh, Angela K (DOA) From: Carlisle, Samantha 1 (DOA) Sent: Tuesday, May 03, 2016 2:3S PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, lames B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Karen Thomas; Kari Moriarty, Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skiilern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Moothart, Steve R (DNR); Suzanne Gibson; Sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen 1 (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: Other Order 109 (MPU, Hilcorp) Attachments: other109.pdf Please see attached. Samantha Carlisle Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West Th Avenue Anchorage, AK 99501 (907) 793-1223 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 Samantha Carlisle at (907) 793-1223 or Samantha.Carhsle@alaskaziV-. 0 0 James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 David Wilkins Richard Wagner Darwin Waidsmith Senior Vice President P.O. Box 60868 P.O. Box 39309 Hilcorp Alaska, LLC Fairbanks, AK 99706 Ninilchik, AK 99639 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 ,,,A�Q% Angela K. Singh INDEXES 12 0 • Hilcorp Alaska, LLC David Wilkins Senior Vice President Post Office Box 244027 RECEIVED Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 May 16, 2016 MAY 16 2016 Anchorage, AK 99503 AOGCCFax: 907/777 858097 dwilkins@hilcorp.com Cathy Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3572 Re: AOGCC Docket No. OTH-15-029 Decision and Order dated May 3, 2016 Dear Chair Foerster: We are in receipt of Other Order 109 in Docket No. OTH-15-029 dated May 3, 2016. In addition to imposing a fine of $20,000, the Order concludes with the following direction: "Hilcorp is instructed to provide AOGCC with a detailed explanation of how recurrence of this violation will be prevented in the future. Included in the corrective actions must be how Hilcorp has acted or will act to ensure accurate information is provided to AOGCC for decisions." Hilcorp Alaska has elected not to pursue this matter further. Hilcorp Alaska herewith submits a check in the amount of $20,000 in full payment of the fine imposed in Other Order 109. Hilcorp Alaska has undertaken the following steps to prevent recurrence of this violation in the future and to ensure accurate information is provided to AOGCC for decisions: Each Hilcorp Alaska Asset Team has implemented a "Changes to Approved Rig Work Over Sundry Procedure" form to capture changes and assure approvals are obtained prior to execution. The completed forms are available to AOGCC upon request. This change management tool mirrors the tool developed and implemented by Hilcorp Alaska's drilling department. Hilcorp Alaska has instituted a monthly training program that covers AOGCC regulations. The intent is to refresh, reiterate, and reinforce knowledge of and compliance with AOGCC regulations for our personnel associated with operations. Specifically, within the next three months the program will include the AOGCC sundry, communication, and reporting regulations for work over operations. Cathy Foerster • • OTH-15-029 May 16, 2016 Page 2 of 2 • Hilcorp Alaska has formalized the information flow from our well site leads (WSL) through our operations engineer staff prior to communicating with AOGCC technical staff on rig work activities. This information flow will ensure that an adequate internal review occurs on rig activity, and that accurate and complete information is provided to AOGCC staff. This will enhance the quality of decisions both internally in Hilcorp Alaska and in the AOGCC staff. WSLs will continue to contact AOGCC staff directly on BOPE testing and timing. • Hilcorp Alaska has changed our well site lead staffing to provide one WSL to cover one shift (e.g., one WSL per 12-hour shift so two WSLs cover 24-hour operations). This allows each WSL to obtain the necessary rest so that he can be alert and attentive during his shift. • In addition to regular daily discussions, Hilcorp Alaska has a monthly meeting with Operations engineers and Operations Managers to discuss subjects regarding well work, regulations, vendors, etc. The information regarding the events as they occurred in this incident, the Other Order 109 dated May 3, 2016, and these corrective actions will be discussed in our next meeting on May 16t' with our Alaska Operations Engineers and Operations Staff. Our objectives in reviewing this incident are to align our understanding of AOGCC requirements and recognition of events and situations which require additional communication to and/or approval from AOGCC staff. Should you have any questions or comments regarding these mitigation steps, please contact Bo York (byork@hilcorp.com; (907) 777-8345) or Larry Greenstein (lreenstein@hilcorp.com; (907) 777-8322). Sincerely, HILCORP ALASKA, LLC David ilkins Senior Vice President Enclosure (Check) • E Hilcorp Alaska LLC P.O. Box 61529 HOUSTON TX 77208-1529 PAY Twenty Thousand Dollars and Zero Cents TO STATE OF ALASKA THE AOGCC ORDER 333 WEST 7TH AVE ANCHORAGE AK 99501-3539 OF AMEGY BANK Void After 90 Days 35-1058 1131 Check No Check Date Check Amount 0082040000 05/11/2016 ""***"`$20 000.00 Authorized Signature ii'008 2040000I'm 1: 113 L 105861: 0444407748111 "PLEASE DETACH AT PERFORATION ABOVE" Hilcorg Alaska LLC P. Box 61529 HOUSTON TX 77208-1529 Description 051016 05/10/2016 AOGCC DOCKET NO. OTH-15-029 20,000.00 'PLEASE DETACH AT PERFORATION ABOVE^ •- 11: 1�11 Discount I Net Amount I 0.00 20,000.00 MAY 16 201b AOGCC ------ - ---- 1083380 1,;�ra Owner Check Date: 05/11/2016 Check Amount z —� 20,000.00 11 • LANE POWE LL ATTORNEYS & COUNSELORS February 24, 2016 VIA HAND DELIVERY Ms. Samantha Carlisle BREWSTER H. JAMIESON 907.264.3325 jamiesonb@lanepowell.com FEB 2 4 2016 Executive Secretary III AOGCC Alaska Oil and Gas Conservation Commission tt�� 333 W Seventh Avenue, Suite 100 Anchorage, AK 99501-3572 Re: Hilcorp Alaska, LLC AOGCC Docket Nos. OTH-15-025, OTH-15-029, OTH-15-030, OTH-15-031 Dear Ms. Carlisle: During the informal review, it was mentioned that Hilcorp would like to maintain the confidentiality of the individual's names involved in the incident. Several of the exhibits contained names and/or signatures of individuals. AOGCC requested that by March 3, 2016, Hilcorp provide a redacted copy of the informal review submission for Docket Nos. OTH-15-025, OTH-15-029, OTH-15-030, and OTH-15-031. Pursuant to that request, I am delivering to you four (4) hard copies and a DVD containing an electronic copy of the Redacted Version of Hilcorp's Submission for Informal Review, previously submitted on January 29, 2016. Please contact me directly at 907-264-3305, if you require any additional copies. Enclosures 129387.0002/6609889.1 www.lanepowell.com T . 907.277.9511 F . 907.276.2631 Very truly yours, LANE POWELL LLC Jeri Ann Jenson, ega�to Brewster H. Jamieson A PROFESSIONAL CORPORATION 301 WEST NORTHERN LIGHTS BLVD., SUITE 301 ANCHORAGE, ALASKA 99503-2648 LAW OFFICES ANCHORAGE, AK PORTLAND, OR. SEATTLE, WA LONDON,ENGLAND 10 Carlisle, Samantha J (DOA) From: Bo York <byork@hilcorp.com> Sent: Friday, February 19, 2016 11:11 AM To: Schwartz, Guy L (DOA); Regg, James B (DOA); Carlisle, Samantha J (DOA); Quick, Michael J (DOA) Cc: David Wilkins; Justin Furnace Subject: Hilcorp Response to AOGCC Questions During 18 Feb 2016 Informal Review: OTH-15-024, -025, -029, -030, and -031 Attachments: 2015 iNet Brochure_EN.PDF; Aug _Sep Calibrations.pdf Guy, Jim, Mike, and Samantha - Below are answers to questions you posed during the informal review yesterday. Let me know if there are other questions you asked that I did not capture and answer below. Q: Were any gauges installed on the valves on the well head for J-08A? A: Hilcorp's previously submitted drawings depict a valve on the IA and OA. A pressure gauge was on the OA valve monitoring pressure between the surface casing and production casing. The valve on the IA was removed for the RWO activitites. It is correctly shown in the drawings submitted on 23 Oct (shown below). sum ',ET UP ON 25 SEPT 2015 ON J 08 N2 PUMPING OPERATIONS YELL J-A MPU GEN PROCESS WPiNC k INSTRUMENT DIAGRAM Exhibit 15 correctly shows the IA "casing valve" with no gauge but does not depict the OA valve and gauge. Standpipe SO ASK R W f...........................: • MUD ►UMP BOM tank Une C12 RAi line � �,_ I _ Chow Lk* —w p---q ra CtfMj Valve Q: When was N2 procedure developed? A: The Hilcorp N2 procedure was initially developed on 23 March 2015 for the 1-15 well. Q: Is the stripping head on the top of the ASR BOP tested as part of the BOP procedure? A: No, it is not tested as it is not part of the BOP well control system. Q: Was the work string (pipe) being moved during the N2 cleanout on J-08A? A: No, the work string was static and was not moved during the pumping of the N2 cleanout jobs. Q: What clean out depths were achieved with the N2 jobs? A: We washed down as deep as our open-ended mule shoe would allow and then held static while the N2 was pumped. Depths varied on all jobs. Q: Was annular BOP or stripping head used for the J-08A N2 pumping? A: Annular BOP. Q: Provide calibration of portable hand held gas detector utilized on ASR for J-08A and F-96. A: All portable gas detectors at Milne are Ventis MX-4 portable detectors. Hilcorp has a contract with Industrial Scientific "I -net" where the detectors are automatically calibrated every month via a docking/charging station. If an individual device is not docked over 7 days or is not calibrated in the course of the month, an alert is trigger. Milne did not receive any alerts in 2015. Note that one detector failed the calibration on 1 Aug but was recalibrated and passed same day. Gas detectors are portable and interchangeable within the field and we do not keep a record of which one is used in specific locations on any given day. Therefore, I can't state which device was utilized on J-08A or F-96. However, attached are the calibrations of all devices in the field over the month of Aug and Sept showing that all received a calibration within that month. We have 14-20 in the field on any given day (number fluctuates as we have some returned for maint to Industrial Scientific). Also attached is the iNet brochure detailing the detector program. Bo York Operations Manager, Milne Point bvork@Hilcorp.com 907.777.8345 907.727.9247 cell Serial Number 12024J7-016 Equipment MX4 T"lle Equipillent Cat(Tory Instrument Reason Unscheduled Activity Calibration Time 9/16/2015 13:28 Result Passed Docking Station 11052EF-001 237 Hilcorp Alaska LLC Milne Point 12050YF-001 13034D6-010 MX4 MX4 Instrument Instrument Scheduled Scheduled Calibration Calibration 9/15/2015 9:56 9/12/2015 17:50 Passed Passed 11052EF-001 11052EF-001 218 251 Hilcorp Alaska LLC Milne Point Hilcorp Alaska LLC Milne Point 13044C5-001 MX4 Instrument Unscheduled Calibration 9/6/2015 7:34 Passed 11052EF-001 238 Hilcorp Alaska LLC Milne Point 13032QH-026 12052P7-002 MX4 MX4 Instrument Instrument Scheduled Unscheduled Calibration Calibration 9/5/2015 13:41 9/5/2015 7:07 Passed Passed 11052EF-001 11052EF-001 231 237 Hilcorp Alaska LLC Milne Point Mlcorp Alaska LLC Milne Point 13015PA-078 150121Q-011 14021NZ-005 MX4 MX4 MX4 Instrument Instrument Instrument Scheduled Scheduled Scheduled Calibration Calibration Calibration 9/4/2015 8:45 9/3/2015 8:01 9/1/2015 23:06 Passed Passed Passed 11052EF-001 11052EF-001 11052EF-001 248 240 258 Hilcorp Alaska LLC Milne Point Hilcorp Alaska LLC Milne Point Hilcorp Alaska LLC Milne Point 120741S-015 MX4 Instrument Scheduled Calibration 9/1/2015 0:07 Passed 11052EF-001 368 Hilcorp Alaska LLC Milne Point 13032QH-026 150121Q-011 MX4 MX4 Instrument Instrument Scheduled Scheduled Calibration Calibration 8/23/2015 12:20 8/4/2015 11:35 Passed Passed 11052EF-001 11052EF-001 249 240 Hilcorp Alaska LLC Milne Point Hilcorp Alaska LLC Milne Point 11041Z1-005 13034D6-010 13034D6-010 120741S-015 150121Q-011 MX4 MX4 MX4 MX4 MX4 Instrument Instrument Instrument Instrument Instrument Scheduled Forced Scheduled Scheduled Scheduled Calibration Calibration Calibration Calibration Calibration 8/2/2015 9:02 8/1/2015 14:26 8/1/2015 7:22 9/30/2015 23:04 9/4/2015 7:04 Passed Passed Failed Passed Passed 11052EF-001 11052EF-001 11052EF-001 11083SW-012 11083SW-012 267 271 1080 251 242 Hilcorp Alaska LLC Milne Point Hilcorp Alaska LLC Milne Point Hilcorp Alaska LLC Milne Point Hilcorp Alaska LLC Milne Point Hilcorp Alaska LLC Milne Point 1211324-001 MX4 Instrument Scheduled Calibration 9/3/2015 7:27 Passed 11083SW-012 269 Hilcorp Alaska LLC Milne Point 13044C5-001 MX4 Instrument Scheduled Calibration 9/1/2015 23:08 Passed 11083SW-012 262 Hilcorp Alaska LLC Milne Point 14021NZ-005 13044C5-001 12113OM-071 MX4 MX4 MX4 Instrument Instrument Instrument Scheduled Scheduled Scheduled Calibration Calibration Calibration 8/31/2015 23:02 8/2/2015 6:57 8/2/2015 0:36 Passed Passed Passed 11083SW-012 11083SW-012 11083SW-012 2741 244 261 Hilcorp Alaska LLC Milne Point Hilcorp Alaska LLC Milne Point Hilcorp Alaska LLC Milne Point 130444T-012 MX4 Instrument Scheduled Calibration 8/1/2015 23:10 Passed 11083SW-012 238 Hilcorp Alaska LLC Milne Point 13031D2-003 MX4 Instrument Scheduled Calibration 8/1/2015 12:18 Passed 11083SW-012 220 Hilcorp Alaska LLC Milne Point 12112QU-026 130444T-012 MX4 MX4 Instrument Instrument Scheduled Scheduled Calibration Calibration 9/1/2015 23:08 9/1/2015 6:26 Passed Passed 11094KP-004 11094KP-004 249 235 Hilcorp Alaska LLC Milne Point Hilcorp Alaska LLC Milne Point 12112QU-026 MX4 Instrument Scheduled Calibration 8/3/2015 23:06 Passed 11094KP-004 229 Hilcorp Alaska LLC Milne Point 13015PA-078 MX4 Instrument Scheduled Calibration 8/1/2015 23:11 Passed 11094KP-004 2491 Hilcorp Alaska LLC Milne Point 12113OM-071 MX4 Instrument Scheduled Calibration 9/6/2015 23:03 Passed 11094KP-005 266 Hilcorp Alaska LLC Milne Point 13070XB-035 MX4 Instrument Unscheduled Calibration 9/4/2015 23:06 Passed 11094KP-005 248 Hilcorp Alaska LLC Milne Point 13070XB-035 MX4 Instrument Scheduled Calibration 9/1/2015 23:09 Passed 11094YP-005 279 Hilcorp Alaska LLC Milne Point 13031D2-003 MX4 Instrument Scheduled Calibration 9/1/2015 6:25 Passed 11094KP-005 229 Hilcorp Alaska LLC Milne Point 1211324-001 MX4 Instrument Scheduled Calibration 8/4/2015 6:26 Passed 11094KP-005 276 Hilcorp Alaska LLC Milne Point 13070XB-035 jMX4 Instrument Scheduled Calibration 8/l/2015 23:10 Passed 11094KP-005 1 2571 Hilcorp Alaska LLC Milne Point 1] 13070XB-035 MX4 Instrument Scheduled Calibration 9/30/2015 23:04 Passed 11115EZ-003 215 Hilcorp Alaska LLC Milne Point 12113OM-071 MX4 Instrument Scheduled Calibration 8/31/2015 23:02 Passed 11115EZ-003 268 Hilcorp Alaska LLC Milne Point 12112QU-026 MX4 Instrument Scheduled Calibration 9/30/2015 23:04 Passed 131003C-010 232 Hilcorp Alaska LLC Milne Point 11083VW-052 MX4 Instrument Unscheduled Calibration 9/6/2015 8:09 Passed 131003C-010 318 Hilcorp Alaska LLC Milne Point 120741S-015 MX4 Instrument Unscheduled Calibration 8/28/2015 6:41 Passed 131003C-010 246 Hilcorp Alaska LLC Milne Point 11041Z1-005 MX4 Instrument Scheduled Calibration 8/5/2015 7:49 Passed 131003C-010 224 Hilcorp Alaska LLC Milne Point 12050YF-001 MX4 Instrument Scheduled Calibration 8/2/2015 7:41 Passed 131003C-010 224 Hilcorp Alaska LLC Milne Point 14021NZ-005 MX4 Instrument Scheduled Calibration 8/1/2015 14:27 Passed 131003C-010 213 Hilcorp Alaska LLC Milne Point 12052P7-002 MX4 Instrument Manual Calibration 9/13/2015 13:59 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 13044C5-001 MX4 Instrument Manual Calibration 9/11/2015 9:36 Passed Instrument 18 Hilcorp Alaska LLC Milne Point 13044C5-001 MX4 Instrument Manual Calibration 9/10/2015 8:51 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 12024J7-016 MX4 Instrument Manual Calibration 9/8/2015 8:21 Passed Instrument 18 Hilcorp Alaska LLC Milne Point 1211324-001 MX4 Instrument Manual Calibration 9/5/2015 10:29 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 14021NZ-005 MX4 Instrument Manual Calibration 9/5/2015 6:19 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 1211324-001 MX4 Instrument Manual Calibration 9/4/2015 8:20 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 13044C5-001 MX4 Instrument Manual Calibration 9/4/2015 8:18 Passed Instrument 16 Hilcorp Alaska LLC Milne Point 150121Q-011 MX4 Instrument Manual Calibration 9/3/2015 11:58 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 150121Q-011 MX4 Instrument Manual Calibration 9/3/2015 11:51 Passed Instrument 16 Hilcorp Alaska LLC Milne Point 150121Q-011 MX4 Instrument Manual Calibration 9/3/2015 11:31 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 14021NZ-005 MX4 Instrument Manual Calibration 9/3/2015 3:26 Passed Instrument 16 Hilcorp Alaska LLC Milne Point 14021NZ-005 MX4 Instrument Manual Calibration 9/3/2015 3:26 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 130311)2-003 MX4 Instrument Manual Calibration 9/3/2015 3:09 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 130311)2-003 MX4 Instrument Manual Calibration 9/3/2015 2:54 Passed Instrument 16 Hilcorp Alaska LLC Milne Point 12052P7-002 MX4 Instrument Manual Calibration 8/31/2015 13:41 Passed Instrument 18 Hilcorp Alaska LLC Milne Point 12052P7-002 MX4 Instrument Manual Calibration 8/31/2015 13:39 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 13031D2-003 MX4 Instrument Manual Calibration 8/25/2015 3:45 Passed Instrument 16 Hilcorp Alaska LLC Milne Point 130311)2-003 MX4 Instrument Manual Calibration 8/23/2015 9:44 Passed Instrument 16 Hilcorp Alaska LLC Milne Point 14021NZ-005 MX4 Instrument Manual Calibration 8/21/2015 5:28 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 150121Q-011 MX4 Instrument Manual Calibration 8/17/2015 9:27 Passed Instrument 16 Hilcorp Alaska LLC Milne Point 14021NZ-005 MX4 Instrument Manual Calibration 8/11/2015 5:29 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 150121Q-011 MX4 Instrument Manual Calibration 8/8/2015 13:26 Passed Instrument 161 Hilcorp Alaska LLC Milne Point 150121Q-011 jMX4 Instrument Manual Calibration 8/8/2015 12:37 Passed Instrument 16 Hilcorp Alaska LLC Milne Point 13015PA-078 MX4 Instrument Manual Calibration 8/4/2015 17:09 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 0 0 0 40 IMAGINE YOUR PEACE OF MIND. The Gas Detection People INDUSTRIAL SCIENTIFIC www.indsci.com IMAGINE WWW. I NDSCI . COM/I MAGI NE- I NET/ You're plenty busy focusing on the things that matter to your business. Amid your daily tasks is the hefty responsibility of ensuring your people are kept safe from hazardous gases and that they go home at the end of each day. Buying your fleet of gas detectors was easy, but then the challenges came. What challenges coo you face in your program? -What is your process for regularly maintaining and servicing your gas detector fleet? - How do you maintain accurate records reflecting your gas detection program? - Do you know how your instruments are being used in the field; what your workers are exposed to; and at what levels they're exposed? The Gas Detection People INDUSTRIAL SCIENTIFIC www.indsci.com Wet Can Help Net is a subscription -based gas detection program designed to give you peace of mind that your equipment is properly maintained and proactively serviced; that you are able to provide required records on demand with minimal effort; and that your people are kept safe from hazardous gases. R1 Instrument Maintenance • Schedule instrument bump tests and -- calibrations to occur automatically • Receive replacement units from Industrial Scientific when Net detects a instrument in fleet malfunctioning your Rr Reeordkeeping is Produce required records on demand • Eliminate the prone -to -error task of manually maintaining records art Field Visibility • Understand how your ® ri instruments are being used in the field and the risks your team faces • Use data to proactively correct poor use behavior co How Wet Works t. Dock the gas monitor. 2. Docking station performs bump tests, calibrations, and uploads monitor data to Net. 9. Net Control provides full access to your program's most critical data. 4. Replacement monitors are delivered to you should Net 1 uncover a problem. S. Your team goes back into the field using reliable gas monitors. • What our customers are saying about Net: "Wet is a cost-effective solution that has removed the hassle of managing our gas detection fleet and has made our people much safer." - Sam Woollacott, South West Water "Quick replacements of any monitors requiring work allows me to keep the plant operations running without missing a beat. love iNet...end of story." - Rob Steckler, Dixie Chemical INDUSTRIAL SCIENTIFIC www.indsci.com 0 Is Wet right for your program? To learn more about iNet click below to watch a video. While there, request to be contacted by an Industrial Scientific representative to determine if iNet is the right solution for your program. And begin to �MAGINE ,0 • ffl � k-j OHSAS 18001 IS09001 IS014001 Certified Certified Certified AMERICAS Phone:+1-412-788-4353 1-800-DETECTS (338-3287) North America Fax: +1-412-788-8353 info@indsci.com ASIA PACIFIC Phone: +65-6561-7377 Fax:+65-6561-7787 info@ap.indsci.com EMEA Phone: +33-1-57-32-92-61 00-800-WORKSAFE (9675-7233) Europe Fax:+33-1-57-32-92-67 info@eu.indsci.com INDUSTRIAL SCIENTIFIC www.indsci.com REV 0115 © 2015 Industrial Scientific Corporation STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION SUBJECT: Informal Review Dockets: OTH-15-024, OTH-15-025, OTH-15-029, OTH-15-030, and OTH-15-031 DATE: 2/18/2016 NAME AFFILIATION �Ta kF�l29ip AoG, c A c c- Carlisle, Samantha J (DOA) From: Marc Bond <mbond@hilcorp.com> Sent: Friday, January 29, 2016 3:28 PM To: Carlisle, Samantha J (DOA) Cc: Larry Greenstein Subject: OTH-15-25, OTH-15-29, OTH-15-30, OTH-15-31: Hilcorp Alaska Submission for Informal Review Attachments: 2016-01-29 Hilcorp Submission to AOGCC for Informal Review w Exhibits.pdf Sam: Written Submission Per our discussion, attached please find a PDF of Hilcorp Alaska's submission to the AOGCC in the referenced matters for the Informal Review now scheduled for February 18, 2016. Larry and I delivered ten (10) hard copies of the submission in separate binders. If you need more, please let me know. Oral Statements At the Informal Review, the following Hilcorp Alaska representatives will be present: David Wilkins: Mr. Wilkins will address general matters regarding the management of Hilcorp Alaska oil and gas operations. Bo York: Mr. York will address the specifics of North Slope operations, particularly the facts related to the matters which are the subject of the notices of proposed enforcement referenced above. Justin Furnace: Mr. Furnace will address the overall Hilcorp Energy response to these matters. Please let me know if you have any questions. Marc Bond • Asst Gen Counsel Hilcorp Alaska, LLC 0:907.777.8309 • C:907.331.7440 mbond@hilcorp.com 3800 Centerpoint Drive • Ste 1400 • Anchorage • Alaska • 99503 This email may contain confidential and / or privileged information and is intended for the recipient(s) only. In the event you receive this message in error, please notify me and delete the message. CEiVED • • FEB 2 4 2016 AOGCC nHilcorp Alaska, LL4 Hilcorp Alaska, LLC's Submission to the AOGCC for Informal Review of AOGCC Docket Nos. OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31 Submitted: January 29, 2016 Mr. David Wilkins Brewster Jamieson, Esq. Mr. Bo York Lane Powell PC Hilcorp Alaska, LLC 301 W. Northern Lights Blvd, Ste 301 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Anchorage AK 99503-5826 Phone: (907) 277-9511 Phone: (907) 777-8300 Email: jamiesonb@lanepowell.com Email: dwilkins(a,hilcorp.com I. INTRODUCTION On November 12 and 16, 2015, the Alaska Oil and Gas Conservation Commission ("AOGCC") issued four Notices of Proposed Enforcement Action ("the Notices") to Hilcorp Alaska, LLC ("Hilcorp"). Three of these Notices (Dockets OTH-15-025, OTH-15-030, and OTH-15-031) involve the use of nitrogen gas in well cleanout operations at the Milne Point Unit on Alaska's North Slope. The fourth Notice (OTH-15-029) concerns a different alleged failure but it is cited in each of the other Notices as justification for enhancing the penalties assessed against Hilcorp. Accordingly, Hilcorp requested, and the AOGCC agreed, that all four Notices would be consolidated for purposes of an Informal Review, currently scheduled for February 18, 2015. Hilcorp concedes that certain operational conduct described in the Notices was not in accordance with its own or its contractors' well -established policies and procedures. Where this is true, Hilcorp has candidly acknowledged these deficiencies, and has taken appropriate remedial action to prevent such occurrences in the future. However, Hilcorp also respectfully believes that the proposed penalties are impermissively excessive, based on an incomplete understanding of the factual record, or arise from regulatory provisions that are ambiguous. Hilcorp also is concerned that in certain respects AOGCC is attempting to enforce its regulation in a manner beyond its statutory mandate, but within the statutory authority of other regulatory agencies. Of greatest concern to Hilcorp are comments in the Notices that are extreme and, to the extent based on incorrect assumptions of fact, unjustified and unfair. Hilcorp's highest priority is, and will continue to be, to conduct its operations in a safe and compliant manner, and it has worked diligently with AOGCC to understand and address its concerns. As demonstrated in this 1 On Milne Point well I-03 Commission alleges, incorrectly as demonstrated herein, that Hilcorp failed to notify the Commission regarding the use of BOPE upon isolation of a casing leak, and also failed to retest the BOPE after this operation. 2 E.g., In the Notice for Dkt. OTH-15-029, which concerns the alleged failure to notify the Commission regarding the use of BOPE on well I-03 and the concomitant failure to re -test the BOPE, the Commission writes, "The disregard for regulatory compliance is endemic to Hilcorp's approach to its Alaska operation and virtually assured the occurrence of this violation." As discussed infra at Section IIE, the alleged violation is not factually based, and therefore the extreme conclusion is unwarranted. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 2 of 30 brief, Hilcorp has taken numerous corrective actions in light of the J-08A incident. Hilcorp invites an open discussion of these issues in the informal review, and hopes one outcome will be a commitment to a greater degree of open communication between Hilcorp and AOGCC in the future. II. STATEMENT OF FACTS The most serious penalties proposed by AOGCC in the Notices are contained in Dkt. OTH-15-25, and concern an incident which occurred during workover operations at Milne Point well J-08A on September 25, 2015. The rig used during this operation was Automated Service Rig 1 (ASR1). ASRI was constructed by Rangeland Drilling Automation, Inc. in the spring of 2015, and was put into service on July 19, 2015. The rig is operated by Integrated Well Services (IWS) personnel working in two shifts, from 6:00 am to 6:00 pm and 6:00 pm to 6:00 am. These crews were directly supervised by two IWS toolpushers, whose shifts were noon -to -midnight and midnight to noon. At the time of this incident, Hilcorp was represented on the worksite by a very experienced wellsite leader, who provided overall operational direction and supervision, and who was onsite 24 hours per day. A. Hilcorp Contractor Safety Expectations and Practices. As part of its own comprehensive safety program,3 Hilcorp requires by contract that all of its contractors, including IWS, to maintain their own safety programs, train their employees to recognize work hazards, and to adhere to all applicable workplace safety standards: 3 See, Ex. 1, Hilcorp Safety Manual Table of Contents (a full copy of the Safety Manual is available upon request). Hilcorp has a comprehensive safety program that ensures standards of federal, state and local regulatory agencies are adhered to in the workplace, and ultimately that personnel are safe and the environment protected. The program includes the standard elements of a Safety Management System, including Employee Training and Contractor Oversight. It is implemented by ten safety professionals, one fire chief, and one safety systems administrator. Four of the safety professionals work on the North Slope while another four work in the Cook Inlet directly supporting field activities. Additionally Hilcorp Alaska's environmental department has twelve environmental professionals who oversee the environmental aspects of Hilcorp's activities. Two environmental specialists work on the North Slope; eight others work out of the Anchorage office and deploy to field locations as work conditions dictate. In addition to the twenty-four safety and environmental professionals staffed in Alaska, Hilcorp has another eighteen Environment, Health and Safety (EH&S) professionals staffed in the Lower-48. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 3 of 30 [IWS] must perform all work and services in accordance with all applicable safety regulations, precautions and procedures, and shall employ all protective equipment and devices required by governmental authorities, or reasonably recommended by industry safety associations. [Hilcorp] expects [IWS] to train its employees to recognize common hazards associated with their work tasks and [IWS] must adhere to all Hazard Communication Standards as required by all applicable Federal, State, and Local Safety Regulations or industry standards. 4 Hilcorp also mandates that everyone, including IWS personnel, have Stop Work Authority; All [Hilcorp] employees, [IWS] and its employees, agents or sub -contractors have "Stop Work Authority" for any unsafe or potentially unsafe situation. Any potential hazards identified must be reported immediately to a [Hilcorp] representative and work stopped until the hazard can be properly understood and corrected. s IWS utilizes the DuPont Stop Work Program and incorporates the DuPont Stop Work cards into the daily operations. Personal Protective Equipment, Safety Meetings, and Job Safety Analyses are additional contractual requirements.6 Hilcorp EH&S professionals worked extensively with IWS prior to start-up of ASR1, and were assured that IWS's safety program was fully compliant.7 After ASR1 was placed in service, Hilcorp EH&S professionals regularly visited the rig and conducted audits, orientation and other support.8 Hilcorp's Wellsite Leader was aware of and observed participation at safety meetings and JSAs by IWS personnel. After the J-08A incident, Hilcorp obtained further confirmation, through copies of training logs, JSAs, STOP cards and Near Miss Reports,9 that IWS personnel regularly participated in and contributed to these vital programs. 4 See Ex. 2, Hilcorp Alaska, LLC Minimum Contractor Safety Requirements, which is an exhibit to the Hilcorp/IWS Master Services Agreement in effect at the time of the incident. 5 Id. 6 Id. Ex. 3, ASR Rig Crew Contacts. 8 Id. 9 Ex. 4, ASRl STOP Cards and Near Miss Reports. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 4 of 30 B. Milne Point Workover Project Planning and Sundry Submission Pursuant to its general powers and duties set forth in AS 31.05.030, the AOGCC has promulgated regulations10 requiring operators to submit (a) an Application for Sundry Approvals (Form 10-403) ("Sundry Application") prior to commencement of workover operations, and (b) a Report of Sundry Well Operations (Form 10-404) ("Sundry Report") after completion of such operations. The Commission may waive these requirements "for wells in a pool for which pool rules have been prescribed,"" which it did for certain BPXA's workover operations at Milne Point prior to Hilcorp becoming operator. Upon becoming operator at Milne Point, Hilcorp began submitting Sundry Applications for all workover projects, and received approvals from AOGCC personnel prior to commencement of any operations. It has also regularly submitted Sundry Reports at the conclusion of all such operations. In 20 ACC 25.280(b), the Commission has listed six specific types of information that must be provided with a Sundry Application.12 Section 280(b)(5) requires "a description of wellbore fluid to be used for primary well control" but it is otherwise silent on the topic of liquids or gasses that might be employed during the course of any particular workover, such as for well cleanout. In addition, Section 280(b)(2) requires submission of "a copy of the proposed 10 20 AAC 25.280. " 20 AAC 25.280(e). 12 These are: (1) the current condition of the well; (2) a copy of the proposed program for well work; (3) unless already on file with the commission, a diagram and description of the well control equipment to be used, including if applicable a list of the blowout prevention equipment (BOPE) with specifications; (4) the maximum downhole pressure that may be encountered, criteria used to determine it, and the maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of true vertical depth, unless the commission approves a different pressure gradient that provides a more accurate means of determining the maximum potential surface pressure, such as using a stabilized shut-in tubing pressure; (5) a description of any wellbore fluid to be used for primary well control; and (6) the current bottom -hole pressure, or, if data setting out the actual pressure are not available, an estimate of the current bottom -hole pressure. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 5 of 30 program for well work," but provides no further detail or guidance regarding the content or level of detail of that item. Specifically, there is no requirement for submission of detailed descriptions of each particular step of the operation, or for submission of detailed written procedures for each of those steps. Box 12 of Form 10-403 lists three types of attachments13 that can be submitted with the Sundry Application, with a box next to each to be checked as an indication of which of those are being submitted with the application. In every Sundry Application for Milne Point workovers submitted prior to the J-08A incident (including each of the Summary Applications that are at issue herein), Hilcorp informed the Commission that it was submitting only a Description Summary of Proposal and a BOP Sketch; in every case, the Commission approved the Sundry Application. Prior to the J-08A incident, Commission staff did not advise that it expected Hilcorp to state whether it intended to or might employ nitrified fluids or other additives to assist with well cleanout. A total of 4 workovers (including J-08A) involving the use of nitrogen gas have been performed at Milne Point since Hilcorp assumed the role of operator in early 2015, two using the Nordic 3 rig, and two using ASR1.14 On the first such job —MP Well I-15—the Hilcorp operations engineer indicated that nitrified fluids, surfactants and gel sweeps might be employed if "unable to gain circulations or solids to surface."15 This Sundry Application was approved, and the description of the proposed cleanout methods received no comment. At the end of this job, a 10-404 Sundry Report form was submitted, with a Weekly Operations Summary detailing the use of nitrogen gas in the cleanout.16 The AOGCC again made no comment. The same operations engineer submitted a Sundry Application for Well J-09A (approved the same day as the Sundry Application on I-15),17 but indicated only the plan to "circulate the 13 Description Summary Proposal, Detailed Operations Program, and/or BOP sketch. 14 These are: Well I-15, Ex. 5 (Form 10-403, Sundry No. 315-158, approved March 25, 2015, and Form 10-404); Well J-09A, Ex. 6, (Form 10-403, Sundry No. 315-162, approved March 25, 2015, and Form 10- 404); Well J-01A, Ex. 7 (Form 10-403, Sundry No. 315-459, approved July 30, 2015 and Form 10-404) and Well J-08A, Ex. 8 (Form 10-403, Sundry No. 315-527, approved August 31, 2015, and Form 10- 404). 15 Ex. 5, Well I-15. 16 Id. 17 Ex. 6, Well J-09A. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 6 of 30 well clean" without indication of the fluid, gas or other products that might be required to complete the cleanout operation. Seawater and nitrogen were used in that operation, and this was duly noted on Weekly Operations Summary submitted with the 10-404 Sundry Report form, to which the AOGCC made no comment.' 8 The third workover involving nitrogen use —on well J-01A—was performed by ASR1. A different Hilcorp operations engineer submitted a Sundry Application which did not mention that nitrogen gas would or might be used;19 again, this fact was noted in the materials submitted with the 10-404 form, 20 without comment from the AOGCC. The final project involving nitrogen —also performed by ASR1—was on J-08A, and the Sundry Application again did not state whether nitrogen would or might be used during the well cleanout.21 Hilcorp fully reported the incident at J-08A to the Commission, including the use of nitrogen. Its use was also clearly identified in documents submitted with the 10-404 following conclusion of the operation.22 As a result of the incident at J-08A, Hilcorp first became aware that the AOGCC expected disclosure of intended or possible nitrogen use in Sundry Approvals, and that if the need to use nitrogen became apparent during the operation (and after its Sundry Application had been approved), that this would constitute "substantive change" requiring notification to the Commission pursuant to 20 AAC 25.507.23 In response, Hilcorp has altered its practice to require that future Sundries will note where the use of nitrogen is reasonably anticipated, and 18 Id. 19 Ex. 7, Well J-0IA. 20 Id. 2' Ex. 8, Well J-08A. 22 Id. 23 The first and operative sentence of 20 AAC 25.507 provides in relevant part: If an operator desires to make a substantive change in a[n] . .. activity for which commission approval is required and has been obtained ... complete details of the well's current condition and the proposed change must be submitted to the commission with [a Sundry Application] .... Nothing in the regulations suggests that using nitrogen to assist in well cleanout operations is "substantive," and that qualifier is not defined or discussed in any other regulation. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 7 of 30 0 • contact the Commission prior to use of nitrogen where its use was not reasonably anticipated and therefore not noted in the Sundry.24 C. The J-08A Incident. On September 25, 2015, three IWS employees (a toolpusher and two operators) were overcome by nitrogen gas inside the tank module of the ASR1 rig. An investigation team was convened to conduct an on -site investigation, resulting in an Internal Incident Investigation report,25 an event sequencing chart,26 a Root Cause Analysis27 and a Lessons Learned Summary.28 All of these items have previously been provided to the Commission. In order to assist the J-08A well cleanout, Halliburton was engaged to deliver and pump nitrogen to the ASRI rig. Job Safety Analyses were conducted as the night crew came on duty at 6:00 pm on the 24th, 29and again when the day crew came on tour at 6:00 am on the 25tn. 30 Both IWS toolpushers attended both JSAs, and the topic of nitrogen pumping was covered at both meetings. The 6:00 am meeting notes indicates discussion occurred of both the hazards (3rd party work, pressure, plugged lines, and loss of oxygen) and controls (good communications, monitoring pressure, avoidance of nitrogen clouds, and avoidance of areas where nitrogen is present). These items were all appropriate and accurate, and, indeed foreshadowed issues that later arose. The procedure involved simultaneous pumping of water and nitrogen down the annulus, with the intended goal of floating fluids and solids at the bottom of the well up and out the tubing. The returns, including fluids, solids and nitrogen were to be routed from the tubing to an open-air bleed tank located away from the other structures on the wellsite. 24 See infra, note 42. 25 Ex. 9, Internal Incident Investigation Report. 26 Ex. 10, Event Sequencing Chart. 27 Ex. 11, Root Cause Analysis. 28 Ex. 12, Lessons Learned Summary. 29 Ex. 13, JSA 9/24. This JSA form indicates that this meeting was conducted at 5:43 pm on September 24t" 30 Ex. 13, JSA 9/25. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 8 of 30 The Halliburton crew made its connections to the ASR1 rig starting just after midnight on the 251h, after which it conducted another safety meeting at 2:10 am. 31 A nitrogen line was run from Halliburton's truck to a T junction, which also connected to the ASR1's pump; the third leg of the T junction was connected to the well annulus (or kill side). Check valves were installed on the kill side of the T junction, in order to prevent nitrogen or well fluids from flowing back into the ASR1 pump line.32 The only pressure gauge on the pump line was located on the kill side of the check valve —this meant that when there was back pressure (i.e., well pressure) on the check valve, it would close, and the gauge would only "see" pressure between the pump and the check valve.33 After making its connection and conducting a pressure test to 3500 psi, the Halliburton crew began pumping nitrogen at 2:40 am. The volume of nitrogen was gradually increased, to 1200 scfm, and pumping proceeded for approximately 2 hours, when a leak developed in Halliburton's nitrogen hose. The pumping was suspended for approximately 25 minutes while the hose was replaced, after which the pumping continued from 4:55 am to 6:30 am, when nitrogen pumping ceased. The wellsite leader monitored returns to the bleed tank, and these indicated that the nitrogen cleanout had been a success. The Halliburton crew then stood by while the ASR1 crew pumped 50 bbl of seawater down the annulus, and monitored the well to ensure that the nitrogen had been removed. After pumping the first 50 bbl seawater pill, the pressure gauge on the tubing indicated 0 psig, while the annulus pressure indicated 300 psi —as noted above, however, the gauge which the crew relied on for annular pressure was reading the pressure trapped between the check valve and the ASR1 pump. In reality, the annular pressure was likely at least 1000 psi. The wellsite leader then released the Halliburton crew at approximately 8:00 am, who disconnected its nitrogen lines from the T junction (but left the T junction and the check valves in place). The wellsite leader called for a second 50 bbl seawater pill to be pumped down the annulus, but after only approximately 4 bbls, the crew encountered an unexpected pressure spike 31 Ex. 14, Halliburton Job Log. " Ex. 15, ASRI Fluid Flow Diagram J-08A Incident. 33 Id. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 9 of 30 to around 1100 psi, which was thought to be due to an obstruction or a closed valve. This was reported by radio to the wellsite leader, who reportedly responded, "I'm confused fellas, let's sit down and talk." He directed the crew to stop pumping, and to bleed off what was anticipated to be a relatively small quantity of fluid. At this time, the IWS toolpusher was with the wellsite leader in the wellsite leader's office, located approximately 200-300 feet away from the rig and tank modules. The IWS operators (MB and JG34) determined that in order to bleed off the annulus pressure, the only readily available flow path was through the choke manifold and into the mud pits. On the way to the mud pits, the flow would go through a gas buster, which is a tank with baffles that directs liquid into the mud pit tanks, while it directs gas out a pipe which vents to the atmosphere at the top of the pit trailer.35 The toolpusher met MB in the manifold room,36 located at one end of the pit trailer, while JG stayed on the rig floor. MB walked down the lines from the rig floor, through the choke manifold and into the mud pit tank, which was the expected path for the fluid being bled off the annulus. MB reports that he simply missed the dump valve on the bottom of the gas buster. It is unclear whether the toolpusher also walked down the flow line path with MB; it is clear that the wellsite leader, who remained in his office, did not. As the bleed -off began, the toolpusher returned to the wellsite leader's office, while MB was in the manifold room and JG was on the rig floor, each monitoring the respective pressure gauges.37 The noise level in the manifold room increased significantly, indicating that a gas, and not a liquid, was being bled off through the choke manifold. JG attempted to raise MB on the 34 The operators' initials will be used to protect their identities. 35 Id. 36 Ex. 16, J-08A Jobsite Overview; Ex. 17 ASRI Tank Trailer Passenger Side View; Ex. 18 ASRI Tank Trailer Driver Side View. 37 JG was monitoring the pressure gauge at the pump, which, as noted previously, was "blind" to the annular pressure because of the check valve. Upon opening the HCR valve to route the annular returns through the choke manifold and into the pits, the pressure gauge on the choke manifold began recording the actual annular pressure. That gauge was visible in the manifold room on a screen, which would also have been viewable in the wellsite leader's office. It is believed that the pressure against the check valve was nearly equal to the annular pressure when the crew stopped pumping. This would have led to similar readings at both pressure gauges when the HCR valve was opened. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 10 of 30 radio, who did not respond due to the noise. JG then went to the manifold room and motioned to MB to join him on the stairs between the manifold room and rig floor. They walked into the tank room (immediately adjacent to the gas buster) in order to exit the tank trailer and proceed up the stairs toward the rig. After only this brief passage through the tank room, both remarked that they were light headed and feeling funny but were not thinking clearly enough to associate these symptoms with their work environment. JG then radioed the toolpusher to meet him by the tank trailer. MB stayed behind, and went back to his "station" in the manifold room. When they met outside, JG told the toolpusher that he and MB were both "loopy and dizzy." The toolpusher then stated that he would check this out, but did not stop the operation, and did not inform the wellsite leader of this development. They both walked around the back end of the tank trailer to the opposite side, and then to the front of the trailer where there is another set of stairs leading directly into the manifold room. As they passed the back of the trailer, the toolpusher indicated to JG that the mud hatch at the back of the trailer should be opened for extra ventilation. The toolpusher and JG arrived in the mud room and encountered MB. MB stepped out onto the landing for fresh air, JG stepped into the manifold room, and the toolpusher entered the tank room, presumably to open the mud hatch at the rear of the trailer. Again, the toolpusher did not inform the wellsite leader or shut down the job. After about 15-20 seconds, JG went into the tank room, and upon ascending the steps, observed the toolpusher in the far end near the mud hatch. JG then took a deep breath (right next to the gas buster), with the intent of assisting the toolpusher. He blacked out about halfway into the room, but he managed to reverse his direction and exit the trailer at the front entrance. MB then went into the tank room via the door between the manifold room and tank room, saw the toolpusher slumped at the back of the tank room, and then immediately went back to the manifold room and shut the choke valve to stop the pressure flow. He took a deep breath, re-entered the tank room, made it to the mud hatch which he opened, and then positioned the toolpusher next to the open hatch. He managed to make it back to the tank room side exit, where he was overcome on the stairs outside the exit. JG, in the meantime, had recovered sufficiently to see MB at the tank room entrance, assist him outside, and then make his way to the rig floor, where he shut in the well completely. He then sounded the man down alarm, and an emergency response was initiated. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 11 of 30 The toolpusher, JG and MB received oxygen, and were transported to the Milne Point unit clinic for evaluation. An incident team was assembled, and an investigation conducted. AOGCC was notified, and its representative went to the wellsite to investigate. Presumably, a report of the AOGCC investigation was prepared, but this has not been provided to Hilcorp as of the date of this submission. D. Hilcorp Has Engaged in Extensive Efforts to Identify and Correct the Causes of the J-08A Incident. As noted above, immediately after this incident, Hilcorp voluntarily conducted a thorough investigation, which identified and considered many potential causes that led to this incident. In addition, Hilcorp prepared a Comprehensive List of Causes (CLC)'38 and a corresponding CLC Corrective Actions matrix39 detailing numerous action items to address the CLC. A Lessons Learned Summary40 was also prepared and voluntarily distributed widely throughout the company and to other North Slope producers. Hilcorp's investigation was rapid, candid and self-critical. Hilcorp has also cooperated fully with the Commission's own investigation, and agreed to all conditions imposed by the Commission prior to recommencing ASR1 operations. All but one of the items on the CLC Corrective Actions matrix have been completed.ai These corrective actions range from locking and tagging out the dump valve on the gas buster, to providing further training regarding the ASR1 rig's choke manifold and associated flow lines, to supplementing the rig's gas detection system with low oxygen sensors, to providing in -ear headsets to facilitate communication in high noise environments, etc. In addition, Hilcorp effected a leadership change at ASR1, now assigning two wellsite leaders (instead of one) to manage the drilling programs. 38 See, Ex. 11 (Comprehensive List of Causes contained in Root Cause Analysis). 39 Ex. 19, CLC Corrective Actions Matrix. 40 Ex. 12, Lessons Learned Summary. 41 Item 5 of the CLC Corrective Actions Matrix, installation of low oxygen detectors, is very close to completion. The detectors have been installed, but have not yet fully been wired and commissioned. That will occur by mid -February, during the ASR1 crew's scheduled time off. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 12 of 30 • Significantly, Hilcorp has also changed its approach to the preparation of Sundry Authorization forms to standardize the level of detail provided to the Commission. Prior to this incident, there was some degree of variability in the level of detail submitted to the Commission to comply with the requirement in 20 AAC 25.280(b)(2) for "a copy of the proposed program for well work." Some operations engineers at Milne Point tended to provide more of a summary with the Sundry Authorization, and then provide a more detailed work program to the field. Other operations engineers provided a summary procedure to both, with the expectation that the field personnel would be better suited to develop detailed procedures matching the on -site conditions at the time of the operation. Prior to the J-08A incident, Commission staff routinely approved workover plans with more or less detail, and did not express a preference or expectation for one format over the other. Hilcorp has now adopted a practice intended to standardize Sundry Authorization submissions, and to ensure both that the submitted procedures are adequately detailed, and that these same procedures will be provided to the wellsite for execution.42 Deviations from the submitted procedures require notice to and approval from the Commission. 42 Ex. 20, email from Bo York (Operations Manager at Milne Point) to Hilcorp personnel, dated November 30, 2015. In relevant part, Hilcorp management expects strict adherence to the following practices: Prior to Initiating Well Work: 1. Operations engineer responsible for the well work will develop the procedure with adequate detail to ensure field execution may occur within the steps included in the procedure and all AOGCC requirements are addressed. 2. Regulatory Tech (Tom Fouts) will generate Form 10-403 to accompany the procedure. 3. Operations engineer that developed the procedure will review the procedure with the Field Foremen and Well Site Manager that will be performing the work. Intent is to obtain their comments and input on the steps and to leverage their 20+ years of performing well work. 4. Operations engineer will provide the reviewed procedure and Form 10-403 to the operations manager for review and schedule a peer review meeting with the other operations engineers in town. Typically this meeting will occur on Friday after the AFE review meeting but can be scheduled at any time. Field Foreman and WSMs should also be invited to this meeting. 5. After the changes are incorporated from the peer review, the operations engineer will initial the Form 10-403 and the operations manager will sign it. (continued) Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 13 of 30 • All of the efforts detailed above (most of which were voluntarily and independently taken prior to receipt of the AOGCC Notices) demonstrate Hilcorp's sincere and thoughtful desire to improve both safety in its operations and compliance with the Commission's expectations. As discussed infra,43 these actions should be considered in determining the amount of the penalty to be assessed for the violations detailed in the Notices. E. The I-03 Alleged Failure to Report Use of Blowout Prevention Equipment. The Notice at Dkt. OTH-15-029 relates to an incident that occurred on May 2, 2015, during a workover of MP Well I-03, which was being performed for the purpose of straddling a casing leak which had been discovered previously. After the straddle assembly was successfully set, the well began to flow, which was an expected possible consequence of the operation. The BOPE, which was already closed in anticipation of the possible flow, was used to restrict the flow of the well while it was weighted up with fluid. 6. The Reg Tech will submit the 10-403, procedure, and all attachments to AOGCC two weeks prior to performing the work. 7. The Reg Tech will track the submittal and let the operations engineer know once approval is received. Work Execution: 1. The operations engineer and WSM are responsible for executing the work. 2. Prior to starting the work, a kick off meeting will be held by the WSM with the rig crew. The entire procedure will be walked through and any special safety considerations will be addressed. The rig crew should understand the procedure and the approved steps. This meeting will be documented on a safety meeting sign in sheet. 3. ANY deviation from the approved procedures will be discussed with the operations engineer and in turn the AOGCC representative. Work will not proceed until the deviation is approved by AOGCC. 4. ANY step or detail not included in the approved procedure but is discovered during well work activities and needs to be added will be discussed with the operations engineer and in turn the AOGCC representative. Work will not proceed until the addition is approved by AOGCC. 5. I repeat this .... If the step is not included in the approved procedure or if a detail is added/chanced, work will stop until the operations engineer notifies the AOGCC and the change/added step is approved. The operations engineer may get verbal approval but ALWAYS followed up with written confirmation via email. (emphasis in original). 43 At Section IIIB(8). Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 14 of 30 The wellsite leader advised Hilcorp's team by email of the success of the straddle and that the well had begun to flow.44 Hilcorp's operations engineer responded: ... please make sure that you notify AOGCC of closure of BOPs due to well control within 24hrs. Looks like you have everything under control. The wellsite leader then responded "Ha they were already closed!" referring to the fact that the BOPE had been closed in anticipation of the well flowing when the packer placed during the operation was released. The wellsite leader nevertheless sent an email message to several AOGCC personnel, including Jeff Jones and James Regg, advising them as follows: Utilized Annular BOP for Shut in while waiting to weight up after successful straddle isolation. Weighting up fluid density .5 ppg. Not sure if notification required in this situation.45 James Regg responded to Hilcorp's wellsite leader, "If planned step in your operation report is not required. 06 Accordingly, no further report was made to the AOGCC. In its Notice, the Commission alleges that Hilcorp violated 20 AAC 25.285 by failing to provide notice of the BOPE use, and by failing to re -test the equipment before re-entering the well after its use. However, the Commission apparently overlooked the above -quoted communications between Hilcorp and AOGCC personnel. Pursuant to 20 AAC 25.285(f)(2), routine use of BOPE in workover operations where such use is not suspected to have compromised its effectiveness is an exception to the retesting requirements of 20 AAC 25.285(f)(2) .41 Section .285(f)(2) requires are -test of BOPE when it is "used for well control or other equivalent purpose, or when routine use of the equipment may have compromised its effectiveness ...." Since that is not how the BOPE was used in this instance, no re -test was required. Under these circumstances, Hilcorp respectfully disagrees with the Commission's imposition of a fine. Based on the communications between Hilcorp and AOGCC staff 44 Ex. 21, Email string between WB and Chris Kanyer, May 2, 2015. 45 Ex. 22, Email from WB to AOGCC, May 2, 2015. 46 Id. 47 Hilcorp personnel advise that the industry shorthand of "closing the BOP in anger," as distinguished from routine use, is the trigger for the re -testing requirements of 20 AAC 25.285(f)(2). Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 15 of 30 discussed above, it is clear that Hilcorp did not willfully disregard 20 AAC 25.285(f). The fact that Hilcorp promptly reached out to AOGCC staff to clarify the regulatory requirements demonstrates Hilcorp's good faith efforts to comply. Moreover, Hilcorp does not believe the factual circumstances surrounding the I-03 workover establish a sufficient basis to enhance the penalties proposed in the other Notices48 at issue here. F. The Facts Do Not Justify the AOGCC's Use of Inflammatory Language. In proposing fines for these and other violations, the Commission employs particularly harsh language in the notices of proposed enforcement. Regardless of the nature of the alleged violation, or its relationship to other alleged violations, each notice of proposed enforcement states the following: [This] violation is neither isolated nor innocent and is emblematic of ongoing compliance problems with Hilcorp rig workover operations. The disregard for regulatory compliance is endemic to Hilcorp's approach to its Alaska operations and virtually assured the occurrence of this violation. Hilcorp's conduct is inexcusable. Hilcorp conducts many operations in over 20 units and fields in Cook Inlet and on the North Slope. Virtually all of these operations are permitted, conducted, concluded, and reported in full compliance with AOGCC and other statutes and regulations. Rather than operating with a disregard for compliance, Hilcorp works diligently and in good faith to comply with all applicable laws and regulations, and has swiftly implemented corrective actions where it has fallen short. Therefore, the Commission's use of inflammatory language in the notices is not justified by the facts. III. ANALYSIS OF PROPOSED FINES Hilcorp believes that the enforcement action proposed by the Commission in the Notices raises serious concerns about the scope of the Commission's authority, as well as the cumulative nature of the proposed fines. These concerns are addressed infra in section IV. 48 Dockets OTH-15-025, 030 and 031. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 16 of 30 This section discusses Hilcorp's concerns with the fines, using the factors contained in AS 31.05.150(g), which provides: In determining the amount of a penalty assessed under (a) of this section, the commission shall consider (1) the extent to which the person committing the violation was acting in good faith in attempting to comply; (2) the extent to which the person committing the violation acted in a wilful or knowing manner; (3) the extent and seriousness of the violation and the actual or potential threat to public health or the environment; (4) the injury to the public resulting from the violation; (5) the benefits derived by the person committing the violation from the violation; (6) the history of compliance or noncompliance by the person committing the violation with the provisions of this chapter, the regulations adopted under this chapter, and the orders, stipulations, or terms of permits issued by the commission; (7) the need to deter similar behavior by the person committing the violation and others similarly situated at the time of the violation or in the future; (8) the effort made by the person committing the violation to correct the violation and prevent future violations; and (9) other factors considered relevant to the assessment that are adopted by the commission in regulation. Hilcorp respectfully submits that if due regard is given to these factors, the fines proposed by the Commission should be substantially reduced, and in some instances eliminated. A. $250,000 Total Fines for Failure to Provide Notice of Expected or Potential Nitrogen Use in Workover Operations. The Commission issued three Notices as a result of workovers that employed nitrogen. The Notice at docket OTH-15-025, which addresses the incident at J-08A, proposes an overall fine of $700,00049 related to this incident, with $100,000 being assessed for performing the 49 This Notice also assesses a $20,000 fine for late reporting of the BOPE test conducted prior to startup after the J-08A incident. Although this late reporting (of a successful BOPE test) was pure oversight and a departure from its otherwise timely BOPE test submittal practice, Hilcorp does not contest that it submitted its BOPE test results three days late. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 17 of 30 cleanout of J-08A using an unapproved contingent plan. The Notices at Dockets OTH-15-030 and 031 relate to two other workovers that employed nitrogen, and propose a fine of $75,000 in each instance. The Notice at docket OTH-15-029 relates to a different issue entirely,50 but is cited as an aggravating factor which justifies the severe penalties contained in the other Notices. Hilcorp questions the regulatory basis for, as well as the amount of, the proposed fines. As noted previously,51 the Commission has promulgated no regulation nor issued any guidance stating or even suggesting that Sundry Applications must include mention of the expected or potential use of nitrogen gas during the well cleanout portion of a workover operation, or that deciding to use nitrogen due to unforeseen factors constitutes a "substantive change" of the approved activity.52 Well cleanout is a standard step in every workover at Milne Point. The use of seawater, nitrogen, or other substances is standard industry practice and depends on actual well conditions encountered during the operation. On the one occasion where Hilcorp mentioned in its Sundry Application that nitrogen or other additives might be employed,53 the Commission made no comment. On the two other jobs where nitrogen was not mentioned in the Sundry Application but used during the operation, this fact was clearly identified in material submitted in the Sundry Report forms 10-404 after the conclusion of the operations —again, without any comment from the Commission that it considered this a "substantive change" of the operations. In the absence of any regulation, guidance or mention of this topic by the Commission, Hilcorp's failure to include the potential for nitrogen use in Sundry Application stemmed from a good faith belief that such mention was not required. The failure to include mention of nitrogen was not due to a willful failure to comply or for the purposes of deceiving the Commission. Hilcorp received no benefit, either —the Commission's previous silence regarding the use of nitrogen (both before and after workovers involving the use of nitrogen) hardly gave Hilcorp the 50 Discussed supra, at Section IIE. 51 Supra, at Section IIB. 52 See discussion at Section IIB, supra regarding the lack of any definition of "substantive change" in the Commissions regulations or guidance; as well as the fact that the Sundry Application form 10-403 does not inquire on this or similar topics. 53 MPU Well I-15 on March 24-29, 2015. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 18 of 30 sense that it could avoid scrutiny or otherwise benefit if it failed to seek pre -approval of nitrogen use. Thus, factors 1, 2 and 5 of AS 31.05.150(g) do not support imposition of any fine, much less that the fine should be enhanced. In addition, there is no indication that the failure to mention nitrogen in the Sundry Applications, or to notify the Commission of its use during the operation, was in any way a cause of the IWS personnel being overcome by nitrogen. At the time of the incident, the nitrogen pumping was concluded, and Halliburton's nitrogen truck had been disconnected from the rig. The release occurred not because the nitrogen cleanout was performed incorrectly, but because, inter alia, the rig crew failed to manage a change in flow direction correctly. Notifying AOGCC personnel prior to the pumping would not have prevented this incident; likewise there is nothing to suggest that failing to notify AOGCC personnel of the possible use of nitrogen during the workover made the occurrence of this event more likely. Thus, factors 3 and 4 of AS 31.05.150(g), which consider the causal connection between the violation and the actual or potential injury or threat to public health and safety, do not support imposition or enhancement of any fine. Regarding factor 6 of AS 31.05.150(g), and as addressed supra in Section IIE, the Commission has improperly alleged violations of 20 AAC 25.285(f) as a basis for these fines. As noted previously,54 Hilcorp has now adopted procedures to both standardize and improve its Sundry Applications. Hilcorp respectfully suggests that the Commission's expectations for its Sundry Applications in general, and for notification about anticipated use of nitrogen in particular, could have been more clearly communicated, particularly with respect to the operations at Milne Point, a unit where Sundry Applications for certain workover activities had not historically been required. Hilcorp wants and intends to comply with the Commission's expectations for its Sundry Applications, and clear communication, rather than the proposed fines, is the most effective way to achieve this.55 54 Supra, at Section IID, n. 42. 55 AS 31.05.150(g)(9) suggests that the Commission may consider "other factors ... that are adopted by the commission in regulation." Hilcorp is unaware of any such regulations. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 19 of 30 B. $600,000 Fine for Failure to Maintain Safe Work Environment in Accordance With Good Oilfield Engineering Practices. The proposed fine at docket OTH-15-025 is based on a single operation56 that was conducted in an unsafe manner. The proposed fine consists of six separate sub -parts, each of which will be discussed in greater detail below. As a preliminary matter, Hilcorp believes that the AOGCC does not have statutory authority to levy fines to multiple asserted violations of 20 AAC 25.526 that occur during the same incident on the same day, and thus the fine based on this regulation should be reduced to a single fine of no more than $100,000. 1. No Authority to Assess Multiple Fines for a Single Unsafe Operation. Alaska law provides the AOGCC authority to levy a fine "of not more than $100,000 for the initial violation and not more than $10,000 for each day thereafter on which the violation continues."57 The statute therefore permits the levying of a fine for the initial regulatory violation and daily fines thereafter so long as the underlying violation continues. 20 AAC 25.526 provides that "An operator shall carry on all operations and maintain the property at all times in a safe and skillful manner in accordance with good oil field engineering practices and having due regard for the preservation and conservation of the property and protection of freshwater." This regulation contains no discrete subparts that can be independently violated — instead, an operator is either in compliance or in violation at any given time. Put simply, once an operator is conducting an operation in an unsafe manner, the operator is in violation of this regulation (and subject to additional daily fines) until the operator remedies the conditions that make its operation unsafe. In its Notice, the AOGCC asserts that Hilcorp failed to maintain a "safe work environment" at the wellsite as a result of six distinct acts that it asserts failed to conform with "generally accepted oilfield practices." The Commission proposes to levy a $100,000 fine for each of these individual conditions. For instance, the Commission alleges that Hilcorp failed "to 56 The operation in question may be seen in general terms as the workover, which was the subject of an approved Sundry Application. The precise step in that operation which resulted in an unsafe condition was the decision to bleed annular pressure to the tank trailer via the choke manifold and gas buster. No matter how viewed, this was a single operation. 57 AS 31.05.150(a). Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 20 of 30 engage in a formal hazards identification" before performing the cleanout of MPU J-08A. If this or any other act identified in the Notice resulted in an unsafe workover operation, there was still only one unsafe operation —the additional acts did not re -violate 25 AAC 25.526. The AOGCC has the statutory authority to levy a fine upon Hilcorp's failure to meet the "safe and skillful manner" standard of 20 AAC 25.526—regardless of whether this violation was caused by one or more acts or omissions. Once in violation, however caused, the AOGCC's authority to levy additional fines was limited to daily fines for on -going violation. This interpretation of AOGCC's fining authority comports with Alaska law regarding multiple penalties for conduct arising out of a single transaction, which focuses on the consequences of multiple violations of the same law. 58 Here, the consequence of one or all of Hilcorp's asserted actions was that Hilcorp was failing to perform its operation in a safe and skillful manner. Whether a single act or multiple acts occurred during the operation to produce the violation, the consequence was the same. Accordingly, AOGCC has the authority to levy a single fine for failing to conduct the operation on September 25, 2015 in a safe and skillful manner, but it may not assess separate fines for each act or omission that may have contributed to that failure. 2. $100,000 for failure to engage in formal hazards identification process. Contrary to the Commission's assertion, Hilcorp required IWS to —and IWS did routinely —engage in a formal hazard identification process before all operations'59 including in particular the nitrogen pumping operation on September 24-25 at J-08A. The JSAs prepared by the IWS crew specifically identified the hazards and risks of nitrogen (particularly creating an oxygen -deprived environment). The set-up of the job adequately assessed the risks associated with normal nitrogen cleanout operations, which properly directed the well returns (including nitrogen) to an outside, open-air tank. Signs were posted at the job site warning that nitrogen was in use. In this instance, the particular hazard to the IWS crew arose after the nitrogen cleanout was complete, after Halliburton's nitrogen pumping truck had disconnected from the rig, and 58 Johnson v. State, 328 P.3d 77, 88 (Alaska 2014). 59 See supra, Section IIA. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 21 of 30 after the crew believed all of the nitrogen gas had been removed from the well. Unexpected pressure was encountered while pumping seawater down the annulus, and the toolpusher and wellsite leader decided to "bleed off' what was believed to be a small amount of water to the mud pits via the gas buster, which (unbeknownst to all) had the dump valve in an open position through which nitrogen escaped into the enclosed space. Upon encountering this changed operation, Hilcorp's expectations were that a hazard assessment for the new operation would be conducted. The crew and wellsite leader incorrectly believed that the bleed -off operation was such a minor and routine step that the existing JSA was adequate and did not need to be revisited. This failure to employ the established hazard identification process, rather than the lack of such a process, led directly to this incident. Although Hilcorp and its contractors routinely engage in job hazard identification and follow industry and governmental standards specific to this issue, the Commission has not promulgated any regulation or issued any guidance which requires an operator to engage in a formal hazards identification process. Here, the Commission states that this process should have been facilitated by "hazards/risk experts ... including assessing the risks of using nitrogen in a fill cleanout on ASRL" It is unclear what the Commission's expectations are for the involvement of "hazards/risk experts." In discussing this issue, the Notice refers to an OSHA publication, but the Commission has not adopted any regulation making violation of this publication a basis for a fine under 20 AAC 25.526. 3. $100,000 for failure to identify and implement safeguards to ensure personnel safety in the event of a nitrogen release. The principal safeguard employed to ensure personal safety in the event of a nitrogen release —avoidance of accumulations of nitrogen gas —was identified and implemented through direction of the cleanout returns, including the nitrogen gas, to outside open-air tanks. Directing the nitrogen returns to the tank trailer was not a normal or anticipated operation. Even so, the mud pit trailer had both a gas buster and a high volume air exchange/exhaust system that were sufficient to deal with any accumulation of nitrogen gas in the returns from the well bore —it was the failure to use these as designed which led to the incident, and this failure was one of management of change, which is covered below. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 22 of 30 To the extent this fine is based on a failure to include a low oxygen alarm along with the ASR1's gas detection system, this is not mandated either by industry or OSHA standards, or in any regulation promulgated by the Commission, and thus cannot form the basis for the proposed fine. Nevertheless, after this incident, Hilcorp voluntarily outfitted the ASR1 rig with such alarms as additional protection against low oxygen due to any cause, including nitrogen accumulation. 4. $100,000 for "Failure to provide and make available at the rig a detailed procedure for performing a fill cleanout with nitrogen, including requirements for verification of the integrity of all barriers in the flow paths for wellbore fluids returning to surface during the fill cleanout operations." The Commission has issued no regulations requiring that procedures for workover operations be provided to the rig, and has issued no guidance specifying the level of detail that the Commission would consider adequate. This finding also overlooks the fact that Halliburton made available a detailed and comprehensive procedure for performing a fill cleanout with nitrogen60 and communicated this to the rig hands at pre job safety meetings at the wellsite. In addition, verifying the integrity of all barriers in the flow paths for fluids returning to surface is a well -understood and constant responsibility of the wellsite leader and toolpusher. This was in fact done before the nitrogen pumping operation itself. The nitrogen pumping operation was concluded at the time of this incident, and no procedure for nitrogen cleanout would have addressed the precise circumstances that were encountered. Accordingly, the alleged failure to include a detailed procedure had no causal relationship to this incident. The cause of this incident was Hilcorp's ineffective management of change, not the lack of a detailed procedure at the wellsite. The IWS crew state that they did, in fact, walk down the lines prior to initiating flow into the mud pits, thus demonstrating knowledge that verification of flow paths was a requirement. However, the open dump valve at the bottom of the gas buster was missed in this process. In addition, the wellsite leader did not walk down the lines, as was his clearly understood responsibility. 60 Ex. 23, Halliburton N2 Procedures. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 23 of 30 Nevertheless, Hilcorp has instituted a practice of requiring such detailed procedures at the wellsite, and has created diagrams of anticipated connections and flows for various standard pumping operations. 5. $100,000 for failure to have in place a robust "Stop Work Authority" that was clearly understood and readily implemented by ASR1. This fine is contrary to the evidence and not supported by regulation. As demonstrated above,61 Hilcorp mandates incorporation of a Stop Work Authority into its operations, and IWS utilizes the Dupont STOP program, a state-of-the-art safety program that, among other things, empowers each and every worker to stop work at any time when safety concerns arise. This stop work authority was regularly underscored during pre -job meetings, during safety meetings, during numerous training sessions, and through IWS's regular use of "STOP cards." Interviews of the personnel involved in this operation disclose that they all readily understood their right and duty to stop work; all readily understand that they could and should have stopped the work at a number of points in the operation, particularly just after they detected an unusual smell and experienced light-headedness. None of the involved employees can explain their failure to do so —and all of them readily admit that this was a mistake —but it was not due to the lack of such a program in the first instance. The Commission has adopted no regulations addressing stop work authority policies or programs, nor has it promulgated regulations or issued guidance regarding the "robustness" that such policies and programs must achieve. The proposed fine on this alleged basis is therefore unsupported. 6. $100,000 for failure to assess and manage changes that potentially introduce new hazards or unknowingly increase the risk of existing hazards during a rig workover. Hilcorp has identified this failure as the principal cause of this accident, and has taken numerous corrective actions, including replacing and enhancing wellsite leadership, to prevent such incidents from reoccurring. 61 See supra, Section IIA. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 24 of 30 7. $100,000 for inadequate training of personnel on ASR1. As detailed above,62 Hilcorp's employees receive extensive regular and ongoing training, and possess all required certifications. While the personnel involved failed to follow their training in several key respects, it does not follow that the training they received was inadequate or deficient. The training records of every employee are available for inspection by the Commission, and the Commission has not specified which training was supposedly inadequate, nor the regulatory authority for imposing a fine on this basis. Accordingly, this proposed fine is not legally or factually supported. 8. The proposed fines do not consider the factors in AS 31.05.150(g). The Commission proposes to assess the maximum fine, six times, for conduct leading to the J-08A incident. In so doing, the Commission has focused on one of nine factors set forth in AS 31.05.150(g)—factor 6, "the history of compliance or noncompliance by the person committing the violation with the provisions of this chapter." In so doing, the Commission raises unadjudicated allegations contained in other Notices, at least one of which63 lacks a factual basis. Increasing the severity of a fine based on unproven allegations is a practice inconsistent with due process, and when, as here, the unproven allegations are shown to be without basis, the proposed action loses its support entirely. In imposing its maximum fine, multiplied six -fold, the Commission also fails to consider any of the other 8 factors of 31.05.150(g). In particular, the Commission should consider: that the violations alleged were not willful or knowing (factors 1-2); that Hilcorp derived absolutely no benefit from the alleged violations (factor 5); that Hilcorp is highly motivated by factors other than the proposed fine to prevent such incidents from reoccurring (factor 7); and that Hilcorp has voluntarily initiated a wide range of corrective actions to prevent such incidents from occurring in the future (factor 8). 62 Id. 63 Docket OTH-15-029, discussed supra , at Section IIE. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 25 of 30 IV. VAGUENESS, REGULATORY OVERREACH AND DUE PROCESS The Notice indicates that the Commission intends to impose $600,000 in penalties against Hilcorp under AS 31.05.150 for violation of 20 AAC 25.526 (".526"), citing conduct that threatened worker safety. The Commission promulgated .526 to create operational standards to conserve and protect oil, gas, and freshwater. It does not and cannot apply to worker safety. Further, to extend .526 to worker safety would require an expansive interpretation that would render the regulation impermissibly ambiguous and vague, violating due process. A. The Commission Lacks Authority to Regulate Worker Safety. Alaska's Administrative Procedure Act ("APA") states that when "a state agency has authority to adopt regulations to implement, interpret, make specific or otherwise carry out the provisions of [a] statute, a regulation adopted is not valid or effective unless consistent with the statute and reasonably necessary to carry out the purpose of the statute. ,64 In addition, the APA states that "[t]o be effective, each regulation adopted must be within the scope of authority conferred and in accordance with standards prescribed by other provisions of law. ,65 Here, it is clear that, by extending application of .526 to worker safety, the Commission has exceeded its statutory authority.66 64 AS 44.62.030 65 AS 44.62.020. 66 When .526 was adopted, AS 31.05.150 did not authorize the Commission to regulate worker safety, or impose fines against an oilfield operator for action that threatens worker safety. Recognizing this lack of authority, John K. Norman, then Chair of the Commission, testified before the Alaska Senate in 2007 that a "recently concluded enforcement action [had] emphasized the lack of [the AOGCC's] specific authority for the regulation of safety issues." Hearing on H.B. 109, Alaska State Legislature, House Special Committee on Oil and Gas, April 12, 2007 (statement of Chair John K. Norman, Alaska Oil and Gas Conservation Commission). In response, the Legislature revised AS 31.05.030 to provide the Commission the ability, but not the mandate, to regulate "for conservation purposes and, to the extent not in conflict with regulation by the Department of Labor and Workforce Development or the Department of Environmental Conservation, for public health and safety purposes." 2007 Alaska Sess. Laws ch. 54, §§ 2 to 5 (S.B. 109) (codified as AS 31.05.030). However, the Commission has never implemented regulations to exercise this permissive authority. Mr. Norman's testimony recognized that the Commission lacked statutory authority to regulate safety issues when it adopted .526. The authorizing statute in effect in 1999 allowed the Commission to regulate only "for conservation purposes." AS 31.05.030(e)(1) (1998). Subsequent to the 2007 amendment of AS 31.05.030, the Commission has not issued formal or informal guidance in the form of promulgated regulations, "Industry Guidance (continued) Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 26 of 30 • • B. Ambiguity of 20 AAC 25.526 Prohibits Application to Worker Safety. Even if the Commission had the statutory authority to regulate safety when it adopted 526, the regulation would be ambiguous and unenforceable in that respect. As the Alaska Supreme Court explained in 2015: A regulation is ambiguous when [it] is capable of two or more equally logical interpretations. And ambiguous statutory or regulatory requirements must be strictly construed in favor of the accused before an alleged breach may give rise to a civil penalty.... People should not be required to guess whether a certain course of conduct is one which is apt to subject them to criminal or serious civil penalties.67 The terms "safe and skillful manner" and "in accordance with good oilfield engineering practices" are vague and undefined. However, the phrase "having due regard for the preservation and conservation of the property and protection of freshwater" indicates the conduct proscribed relates to the goal of resource and freshwater conservation. The Commission has underscored this interpretation in its public statements. For instance, in its 2010 Statement to the Governor, the Commission wrote that it "strives to ensure safe, technically prudent, and environmentally protective oil and gas well construction and operations" through its regulatory programs.68 The Commission stated: Specific to drilling and workover operations, Commission performs periodic compliance inspections to ensure the equipment being used is consistent with the approved application, provides redundant levels of safety and protection for the well operations being performed, and is suitable for the environment in which activities are being conducted. Blowout prevention equipment inspections and witnessing tests per the regulatory frequency is a particular emphasis for AOGCC inspections. 69 Bulletins," or enforcement orders that purport to expand the meaning of .526 beyond the bounds statutorily authorized when it was adopted in 1999. The Commission lacked authority to regulate any safety issue when it adopted .526, and the Commission cannot now attempt to utilize it for this purpose. 67 RBG Bush Planes, LLC v. Alaska Public Offices Comm'n, 361 P.3d 886, 892 (Alaska 2015) (internal quotation marks and citations omitted). 68 AOGCC Statement to Governor, May 2010, available at http://doa.alaska.gov/ogc/reports- studies/AOGCC Statement to Gov.pdf. 69 Id. (emphasis added). Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 27 of 30 The Commission went on to explain: After well drilling and completion, upon and after the onset of well production operations, other Commission regulations require installation, use, and maintenance of safety -related well hardware such as surface safety valves for certain types of wells, subsurface safety valves for certain wells, and various well production flow control devices. All offshore wells require an automatic, failsafe surface safety valve. A subsurface safety valve is required in every offshore producing well unless the operator can demonstrate to the Commission's satisfaction that the well is incapable of unassisted flow of hydrocarbons to surface. The components of a well safety valve system are regularly inspected by Commission for proper operation given the production characteristics of the well and the challenges of operating environment, including witnessing tests. Operators are required to test of the components of a safety valve system at least once every 6 months and provide all test results to the Commission for review.70 These statements make clear that the Commission's regulation of "safety" refers to ensuring wells are equipped sufficiently to prevent catastrophic blowouts that waste resources and pollute freshwater. While blowouts are inherently unsafe for workers, the Commission does not indicate (nor does the legislature) that worker safety is the object of its regulatory structure and inspections. In fact, the Commission's statutes and regulations do not even mention the words "employee" (other than Commission employees) or "worker." This orientation toward well safety, not worker safety, is consistent with Alaska's larger regulatory scheme. The Legislature has a specifically designated agency to ensure worker safety, the Alaska Occupational Safety and Health section of the Department of Labor and Workforce Development. The Commission's authorizing statute, which grants it the authority to regulate oil and gas operations for public health and safety only "to the extent not in conflict with regulation by the Department of Labor and Workforce Development,"71 makes this division of purpose between the Commission and AKOSH clear. This prohibits "conflict," but does not create overlapping authority. Finally, application of .526 in the Commission's publicly -available enforcement orders is consistent with Hilcorp's understanding that the "safe and skillful" requirement means an operator must conduct operations in a prudent manner to avoid waste of oil and gas or 70 Id. 71 AS 31.05.030(e). Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 28 of 30 contamination of freshwater. The Commission has not cited .526 in an enforcement order in over 10 years, and not since 2007 amendment of AS 31.05.150. It has only cited the regulation three times.72 The Commission has applied .526 exclusively to engineering practices creating a significant risk of resource waste through a blowout, and they support interpretation that .526 regulates the safe operation of a well, not the work environment. C. 20 AAC 25.526 is Unconstitutionally Vague. The Commission has the authority to levy fines for violation of its promulgated regulations. As a result, Commission's regulations must meet basic constitutional due process requirements to be enforceable. Alaska courts recognize that "in order to be consistent with notions of fundamental fairness a statute must give adequate notice of the conduct that is prohibited. ,73 Even if Commission had the statutory authority to regulate worker safety at the time .526 was adopted, .526 would be unconstitutionally vague in that respect. As outlined above, by its language and history, .526 limits its application to conservation of resource and protection of freshwater, and nothing the Commission has done provides notice that .526 encompasses worker safety.74 The regulation fails to give "the ordinary citizen fair notice of what is and what is not prohibited. ,75 Hilcorp "should not be required to guess whether a certain course of conduct is one which is apt to subject [it] to ... serious civil penalties," but .526, as the Commission is now interpreting it, requires operators to do just that.76 As a result, 526 is void for vagueness under Alaska law. 72 In a June 2, 2005 order, the Commission cited Nabors Alaska Drilling for violating rules regarding testing of blowout prevention equipment on a rig by falsifying test results with a practice referred to as "chart spinning." AOGCC Order 34 - Nabors Alaska Drilling, Rig 9ES, Enforcement Order. In 2004, the Commission cited BPXA in two orders for failing to bleed off well pressure before restarting a shut-in well and in connection with its practices in managing wells with sustained annular pressures, in the latter case resulting in a catastrophic failure and explosion. AOGCC Order 32 - BPXA, PBU, H-11, Enforcement Order; AOGCC Order 29 - BPXA, PBU A-22, Enforcement Order. These orders did not cite worker safety as a basis for the operators' failure to conduct activities in a "safe and skillful" manner. 73 State v. Rice, 626 P.2d 104, 109 (Alaska 1981) (applying due process doctrine to regulatory violation). 74 See AS 44.62.190 (requiring publication 30 days before the adoption, amendment, or repeal of a regulation). 75 VECO Intern., Inc. v. Alaska Public Offices Conun n, 753 P.2d 703, 714 (Alaska 1988). 76 Id. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 29 of 30 In addition to the notice requirement, the Alaska Supreme Court has held that a statute is unenforceably vague if a "statute's imprecise language encourages arbitrary enforcement by allowing prosecuting authorities undue discretion to determine the scope of its prohibitions." 77 Again, the Commission has never applied .526 to worker safety, never issued any regulations or guidance that it intended to do so, and only imposed penalties for conduct creating a significant risk of resource waste through a blowout. That the Commission has not consistently sought to enforce .526 on the basis of worker safety demonstrates selective enforcement in this instance that makes the regulation unenforceably vague. V. CONCLUSION Hilcorp concedes that the incident at J-08A was unfortunate and preventable. Hilcorp immediately and dispassionately investigated the incident, identified its most likely contributing causes, and then systematically proceeded to make corrections and improvements with the goal of substantially reducing the likelihood of similar future incidents. However, the fines proposed by the Commission are excessive, not justified by the factual record, and outside the scope of its regulatory authority. Further, the factual record does not support the Commission's claims that Hilcorp has an "endemic disregard" for compliance. On the contrary, Hilcorp's record in Alaska demonstrates conscientious attention to regulatory compliance, and swift corrective action when Hilcorp falls short. Hilcorp looks forward to engaging in an open and candid discussion of these issues with the Commissioners at the upcoming informal review, and hopes that by doing so an agreed resolution of this matter can be achieved. The Commissioners and Hilcorp share the same goal —encouraging the safe and responsible production of Alaska's oil and gas resources. " State v. Rice, 626 P.2d at 109. Hilcorp Alaska, LLC Submission for Informal Review (OTH-15-25, OTH-15-29, OTH-15-30, and OTH-15-31) Page 30 of 30 Exhibits: Table of Contents 1 Hilcorp Safety Manual Table of Contents 2 Hilcorp Alaska, LLC Minimum Contractor Safety Requirements 3 ASR Rig Crew Contacts 4 ASR1 STOP Cards and Near Miss Reports (various dates) 5 Well I-15 (Form 10-403, Sundry No. 315-158, approved March 25, 2015) and follow-on Form 10-404 6 Well J-09A (Form 10-403, Sundry No. 315-162, approved March 25, 2015) and follow- on Form 10-404 7 Well J-01A (Form 10-403, Sundry No. 315-459, approved July 30, 2015) and follow-on Form 10-404 8 Well J-08A (Form 10-403, Sundry No. 315-527, approved August 31, 2015), and follow- on Form 10-404 9 Hilcorp Alaska, LLC: Internal Incident Investigation Report (October 1, 2015) 10 Automated Service Rig 1 (ASR 1) Incident Investigation Events Sequencing Chart (September 25, 2015) 11 Root Cause Analysis (RCA) September 25, 2015 Incident 12 Lessons Learned Summary titled "Milne Point Automated Service Rig 1 (ASR 1) Incident" from Hilcorp Alaska, LLC's Safety — SharingtheExperience Program 13 Job Safety Analysis (JSA) Forms (September 24-25, 2015) 14 Halliburton Job Log for MPJ-08A (September 24, 2015) 15 ASRI Fluid Flow Diagram J-08A Incident 16 J-08A Jobsite Overview 17 ASR1 Tank Trailer Passenger Side View 18 ASR1 Tank Trailer Driver Side View 19 CLC Corrective Actions Matrix for 9/25/2015 ASR Rig (various dates) 20 Email from Bo York to Milne Point personnel re Compliance with Well Work Sundry Procedures — Coil Tubing, ASR, Nordic, Doyon (November 30, 2015) 21 Email string between Chris Kanyer and WB re I-03 (May 2, 2015) 22 Email from WB to AOGCC re AOGCC Test Witness Notification Request: BOPE, Nordic 3 & nbsp; MPU 1-03 (May 2, 2015) 23 Halliburton Pressure Test and N2 Pumping Procedures • • TABLE OF CONTENTS SECTION I: INTRODUCTION.........................................................1 MANAGEMENT POLICY STATEMENT.............................................................................I SAFETYGOALS............................................................................................................................................2 SAFETYRESPONSIBILITIES......................................................................................................................2 A. EMPLOYEES...................................................................................................................................2 B. SUPERVISORY PERSONNEL........................................................................................................3 C. EH&S DEPARTMENT....................................................................................................................4 D. MANAGEMENT..............................................................................................................................4 E. CONTRACTORS..............................................................................................................................4 PROCESS SAFETY MANAGEMENT POLICY...........................................................................................5 SECTION II: SAFETY POLICY AND PROCEDURES....................................5 1. GENERAL SAFETY RULES.........................................................................................................................5 2. DISCIPLINE POLICY....................................................................................................................................6 3. SAFETY PROGRAM COMMUNICATIONS................................................................................................7 4. SAFETY ORIENTATION..............................................................................................................................7 5. INSPECTIONS................................................................................................................................................8 6. HAZARD CORRECTION PROCEDURES...................................................................................................9 7. ACCIDENT INVESTIGATION...................................................................................................................10 8. SAFETY MEETINGS...................................................................................................................................10 9. SAFETY AND HEALTH TRAINING.........................................................................................................11 10. EMERGENCY CARE, FIRST AID /CPR & AED PROVISIONS...............................................................12 A. EMERGENCY MEDICAL CARE.................................................................................................12 B. FIRST AID/CPR & AED & BBP TRAINING...............................................................................12 C. FIRST AID SUPPLIES AND EQUIPMENT.................................................................................13 11. BLOOD BORNE PATHOGEN EXPOSURE CONTROL PROGRAM.......................................................13 A. PURPOSE AND SCOPE................................................................................................................13 B. DELEGATION OF RESPONSIBILITY.........................................................................................13 C. WRITTEN EXPOSURE PLAN......................................................................................................13 D. EXPOSURE DETERMINATION..................................................................................................14 E. METHODS OF COMPLIANCE.....................................................................................................14 F. ENGINEERING AND WORK PRACTICE CONTROLS.............................................................15 G. PERSONAL PROTECTION EQUIPMENT...................................................................................15 H. HOUSEKEEPING..........................................................................................................................15 I. WASTE HANDLING.....................................................................................................................15 J. HEPATITIS B VACCINATION....................................................................................................15 K. POST -EXPOSURE EVALUATION AND FOLLOW-UP.............................................................16 L. FIRST AID CARE INCIDENT REPORTS....................................................................................17 M. MEDICAL RECORDS...................................................................................................................17 N. LABELS AND SIGNS....................................................................................................................17 O. INFORMATION AND TRAINING...............................................................................................17 P. AVAILABILITY OF RECORDS...................................................................................................18 12. INCENTIVE PROGRAM.............................................................................................................................18 13. BUDDY SYSTEM........................................................................................................................................19 14. HEARING CONSERVATION PROGRAM.................................................................................................19 A. PURPOSE/SCOPE..........................................................................................................................19 15. RESPIRATORY PROTECTION PROGRAM..............................................................................................20 A. PURPOSE/SCOPE..........................................................................................................................20 B. GENERAL REQUIREMENTS.......................................................................................................20 C. FIT TESTING.................................................................................................................................20 16. CONTRACTOR SAFETY............................................................................................................................20 A. PURPOSE/SCOPE..........................................................................................................................20 B. GENERAL REQUIREMENTS.......................................................................................................20 17. CRANE..........................................................................................................................................................21 - (i)- EXHIBIT 1 Page 1 of 5 A. GENERAL......................................................................................................................................21 B. CRANE...........................................................................................................................................22 C. SLINGS AND WIRE ROPES.........................................................................................................24 18. FORKLIFT....................................................................................................................................................25 A. GENERAL......................................................................................................................................25 19. HYDROGEN SULFIDE CONTINGENCY PLAN......................................................................................25 A. SCOPE............................................................................................................................................25 B. CONTINGENCY PLAN.................................................................................................................26 C. TRAINING.....................................................................................................................................27 D. EQUIPMENT AND LOCATION OF EQUIPMENT.....................................................................27 E. BRIEFING AREA SAFETY TRAILER AND WIND DIRECTION INDICATORS ....................27 F. H2S DETECTION AND MONITORING EQUIPMENT..............................................................27 20. TOXICITY AND FIRST AID.......................................................................................................................28 A. TABLE: TOXICITY OF VARIOUS GASES................................................................................28 B. PROPERTIES OF VARIOUS GASES...........................................................................................28 C. PHYSICAL PROPERTIES AND PHYSIOLOGICAL EFFECTS ON HUMANS ........................28 D. FIRST AID TREATMENT FOR H2S EXPOSURE.......................................................................29 E. RESCUE BREATHING..................................................................................................................29 F. WELL OUT OF CONTROL...........................................................................................................30 G. EMERGENCY TELEPHONE NUMBERS....................................................................................32 SECTION III: WORK AREA SAFETY.............................................................32 1. PERSONAL PROTECTIVE EQUIPMENT.................................................................................................32 A. PURPOSE OF PROGRAM...................................................................................33 B. HAZARD ASSESSMENT..............................................................................................................33 C. SELECTION GUIDELINES..........................................................................................................33 D. PROGRAM EVALUATION..........................................................................................................34 E. EMPLOYEE TRAINING...............................................................................................................34 F. CLEANING, MAINTENANCE & INSPECTION.........................................................................35 G. PPE SPECIFIC INFORMATION...................................................................................................35 2. STATIONARY MACHINERY/GUARDING & OPERATION...................................................................37 3. HOT WORK..................................................................................................................................................38 4. WALKING AND WORKING SURFACES.................................................................................................39 5. TOOLS (HAND AND POWER)...................................................................................................................39 6. LADDER SAFETY / FALL PROTECTION................................................................................................40 7. COMPRESSED GAS CYLINDERS.............................................................................................................41 8. DRIVING SAFETY......................................................................................................................................41 A. GENERAL......................................................................................................................................41 B. INTERSECTION SAFETY............................................................................................................42 C. SPACE CUSHION CONCEPT.......................................................................................................42 D. LOOKING AHEAD AND BEHIND..............................................................................................42 E. BACKING.......................................................................................................................................42 F. COMMUNICATIONS....................................................................................................................43 G. VEHICLE EQUIPMENT, MAINTENANCE AND INSPECTION...............................................43 9. ELECTRICAL SAFEGUARDS - LOCK OUT / TAG OUT.......................................................................44 A. LIVE CIRCUITS.............................................................................................................................44 B. LOAD BREAK SWITCHES..........................................................................................................44 C. POWER SUBSTATIONS...............................................................................................................45 D. TRANSFORMERS.........................................................................................................................45 E. HIGH VOLTAGE MOTOR STARTERS.......................................................................................45 F. FUSES.............................................................................................................................................45 G. CIRCUIT BREAKERS...................................................................................................................46 H. MOTOR STARTERS.....................................................................................................................46 I. GROUNDING.................................................................................................................................46 J. ELECTRICAL MOTORS...............................................................................................................46 K. CONTROL CIRCUITS...................................................................................................................46 L. EXTERNAL CONTROL CIRCUITS.............................................................................................46 M. INDUCED CURRENTS.................................................................................................................46 N. EXPLOSION PROOF FITTINGS..................................................................................................47 EXHIBIT 1 Page 2 of 5 O. EXTENSION CORDS....................................................................................................................47 P. RUBBER MATS IN LABS AND SHOPS......................................................................................47 Q. BATTERIES AND STAND BY GENERATORS..........................................................................47 R. OVERLOADING CIRCUITS.........................................................................................................47 S. GIN POLES....................................................................................................................................47 T. ELECTRICAL BOXES..................................................................................................................47 U. PORTABLE ELECTRIC MOTORS AND PUMPS.......................................................................47 V. GROUNDING OF FENCES...........................................................................................................48 W. CATHODIC PROTECTION RECTIFIERS...................................................................................48 X. RUBBER GLOVES........................................................................................................................48 Y. HOT STICKS..................................................................................................................................48 Z. STATIC ELECTRICITY................................................................................................................48 10. PLANT EQUIPMENT - CONTROL OF HAZARDOUS ENERGY (LOCKOUT/TAGOUT) ...................51 A. GAS COMPRESSORS...................................................................................................................51 B. COMPRESSORS............................................................................................................................51 C. AIR COMPRESSORS....................................................................................................................52 D. HEATERS.......................................................................................................................................52 E. BOILERS........................................................................................................................................52 F. PRESSURE SAFEGUARDS..........................................................................................................52 11. LAWN MOWERS, TRACTORS, ATV'S AND CHAIN SAWS.................................................................53 12. CONFINED SPACE ENTRY.......................................................................................................................53 13. SCAFFOLD...................................................................................................................................................54 14. EQUIPMENT ISOLATION & BLINDING (LOCKOUT/TAGOUT)..........................................................55 15. TANK/VESSEL CLEANING PROCEDURE..............................................................................................56 A. PURPOSE/SCOPE..........................................................................................................................56 B. PROCEDURE/PROCESS...............................................................................................................57 C. TANK EMPTYING AND CLEANING.........................................................................................57 SECTION IV: OTHER WORK AREAS............................................................59 1. FIELD LOCATION SAFETY......................................................................................................................59 A. GENERAL......................................................................................................................................59 B. HIGH PRESSURE PIPING............................................................................................................59 C. SUN PRESSURE............................................................................................................................59 D. PRESSURE RELIEVING VESSELS AND PIPE BEFORE OPENING........................................59 E. REMOTE STARTING EQUIPMENT............................................................................................60 F. SUMPS............................................................................................................................................60 G. VIBRATION EFFECT ON HIGH PRESSURE FITTINGS...........................................................60 H. PRODUCT SAMPLING.................................................................................................................60 I. FLEXIBLE TUBING......................................................................................................................60 J. GAS METERS................................................................................................................................60 2. TANK AND GAUGING SAFETY...............................................................................................................61 A. CARRYING EQUIPMENT UP THE TANK.................................................................................61 B. PROPER GAUGING AND SAMPLING EQUIPMENT...............................................................61 C. OPENING THE GAUGE HATCH.................................................................................................61 D. TANK TOP SAFETY.....................................................................................................................62 E. GROUNDING TECHNIQUES.......................................................................................................62 F. GAUGING TANKS WITH H2S VAPORS....................................................................................62 G. TANK DIKE MAINTENANCE.....................................................................................................62 H. RECEIVING PROCEDURES TO AVOID SPILLS.......................................................................62 I. TANK BOTTOM REPAIRS...........................................................................................................62 3. GATHERING SYSTEM AND LEASE TANK GAUGING.........................................................................63 A. GAUGING TANKS........................................................................................................................63 B. LACT HAZARDS...........................................................................................................................63 C. GASOLINE POWERED PUMP HAZARDS.................................................................................63 D. GATHERING SYSTEM LEAK REPAIR......................................................................................64 E. WATER DRAWS...........................................................................................................................64 4. WATER AND BOATING OPERATIONS...................................................................................................64 A. GENERAL......................................................................................................................................64 B. QUARTERS AND GENERAL DECK RULES.............................................................................65 EXHIBIT 1 Page 3 of 5 C. BOAT TRANSPORTATION.........................................................................................................65 SECTION V: MATERIAL HANDLING SAFETY...........................................66 1. DRUM HANDLING.....................................................................................................................................66 2. BACK SAFETY............................................................................................................................................66 3. NORM...........................................................................................................................................................67 A. PURPOSE/SCOPE..........................................................................................................................67 B. DEFINITION..................................................................................................................................67 C. RESPONSIBILITIES......................................................................................................................67 D. GENERAL REQUIREMENTS.......................................................................................................67 SECTION VI: OFFICE SAFETY........................................................................68 1. OFFICE FURNITURE AND EQUIPMENT.................................................................................................68 2. FLAMMABLE AND HAZARDOUS MATERIALS...................................................................................69 3. DOORS, WALKWAYS, AND ELEVATORS.............................................................................................69 SECTION VII: FIRE PREVENTION PLAN.....................................................69 1. PURPOSE......................................................................................................................................................69 2. WORKPLACE FIRE HAZARDS.................................................................................................................70 3. FIRE PROTECTION EQUIPMENT.............................................................................................................70 A. FIRE EXTINGUISHERS................................................................................................................71 4. MAINTENANCE OF FIRE PROTECTION EQUIPMENT.........................................................................71 5. GENERAL PREVENTION AND PROTECTION.......................................................................................71 6. TRAINING....................................................................................................................................................73 A. FIRE PREVENTION PLAN...........................................................................................................73 B. FIRE PREVENTION EQUIPMENT..............................................................................................73 SECTION VIII: HAZARD COMMUNICATION PROGRAM .......................74 1. HAZARD EVALUATION PROCEDURES.................................................................................................74 2. MATERIAL SAFETY DATA SHEETS (MSDS)........................................................................................74 3. LABELS AND OTHER FORMS OF WARNING.......................................................................................75 A. MISSING OR DAMAGED LABELS.............................................................................................75 4. TRAINING....................................................................................................................................................75 5. TRAINING CONTENT................................................................................................................................76 6. HAZARDS OF NON -ROUTINE TASKS....................................................................................................77 7. HAZARDS OF UNLABELED PIPES..........................................................................................................77 8. CONTRACTORS..........................................................................................................................................77 SECTION IX: RECORDKEEPING....................................................................77 1. RECORDS LIST AND FILING SYSTEM...................................................................................................78 SECTION X: EMERGENCY ACTION PLAN..................................................78 1. PURPOSE......................................................................................................................................................78 2. EMERGENCY ESCAPE PROCEDURES AND ASSIGNMENTS.............................................................79 3. RESCUE AND MEDICAL DUTY ASSIGNMENTS..................................................................................80 4. EMERGENCY REPORTING PROCEDURES............................................................................................81 5. EH&S DEPARTMENT RESPONSIBILITIES.............................................................................................81 6. TRAINING....................................................................................................................................................81 7. DRILLS.........................................................................................................................................................82 8. MEDICAL EMERGENCY...........................................................................................................................82 9. FIRE AND EXPLOSIONS............................................................................................................................83 10. BOMB THREAT...........................................................................................................................................84 11. HOSTAGE SITUATION..............................................................................................................................84 EXHIBIT 1 Page 4 of 5 SECTION XI: NATURAL DISASTER EMERGENCY RESPONSE.............85 1. INTRODUCTION.........................................................................................................................................85 2. GENERAL INFORMATION AND TIPS.....................................................................................................85 3. LOSS OF POWER........................................................................................................................................85 4. HURRICANE PREPAREDNESS.................................................................................................................86 5. RESPONSIBILITY AND PROCEDURE.....................................................................................................87 6. THREE PHASES OF STORM ALERT........................................................................................................87 7. ANNOUNCEMENT OF STORM ALERT...................................................................................................88 8. DIRECTION OF ACTION............................................................................................................................88 9. HURRICANE EVACUATION PROCEDURES..........................................................................................88 A. PHASE I..........................................................................................................................................88 B. PHASE II........................................................................................................................................88 C. PHASE III.......................................................................................................................................89 10. SUCCESSION OF AUTHORITY................................................................................................................89 11. ALTERNATE EMERGENCY CENTERS...................................................................................................89 12. NOTIFICATION OF DEPARTURE.............................................................................................................89 A. IN ADVANCE OF STORM...........................................................................................................89 B. AFTER THE STORM.....................................................................................................................90 13. TORNADOES...............................................................................................................................................90 14. EARTHQUAKES..........................................................................................................................................90 FORMS INCIDENT REPORT ACCIDENT FOLLOW-UP REFUSAL OF CARE SAFETY MEETING REPORT JOB HAZARD ASSESSMENT FORM HURRICANE PRODUCTION LOSS AND DAMAGE REPORT AUDIT CHECKLIST AUDIT OBSERVATIONS ACTION ITEM LIST EMPLOYEE ACKNOWLEDGEMENT EXHIBIT 1 Page 5 of 5 EXHIBIT "C" TO MASTER SERVICE AGREEMENT Hilcorp Alaska, LLC Minimum Contractor Safety Requirements INTRODUCTION Hilcorp Alaska, LLC (hereinafter referred to as "COMPANY") stresses the importance of safety and safety requirements as outlined in the Minimum Contractor Safety Requirements herein (the "Standar&'). These Standards are incorporated by reference into the Agreement. COMPANY, through the use of safe work practices, personal protective equipment (PPE), safety meetings, and Job Safety Analyses (JSAs), emphasizes the importance of safety at each COMPANY work site. Contractors are expected at all times to meet or exceed the Standards; Contractor's own safety manuals, and any applicable Federal, State, and Local regulation (whichever are most stringent). Contractor is responsible for ensuring that its subcontractors also do the same. Please be advised that these Standards do not reduce or replace CONTRACTOR's responsibility to maintain a safe work environment for all persons*, and regularly and repeatedly perform appropriate training and safety programs for it, and its subcontractors, and its and their employees and agents. CONTRACTOR must perform all work and services in accordance with all applicable safety regulations, precautions, and procedures, and shall employ all protective equipment and devices required by governmental authorities, or reasonably recommended by industry safety associations. CONTRACTOR shall take all necessary and appropriate precautions to safeguard it, and its subcontractors, and its and their employees and agents, COMPANY's employees and representatives, visitors, the general public, any public or private property, the environment, and natural resources with respect to any work or services to be performed for COMPANY. SAFE WORK PRACTICES COMPANY requires that CONTRACTOR convey these Standards to its subcontractors, and its and their employees, agents and visitors, and mandate compliance with these Standards at all times while at COMPANY work sites. COMPANY prohibits the possession, transportation, use, or consumption of any controlled substances, drugs, or drug - related paraphernalia on or around any property, facility, aircraft, vehicle, or boat owned or used by COMPANY. (Possession and use of prescription medications with doctor's and user's name on container label and prescription date within one year is not prohibited by this policy.) COMPANY requires CONTRACTOR to have its own written Comprehensive Safety Proeram and Comprehensive Substance Abuse and Alcohol Misuse Program. Strict compliance with these requirements is mandated while working on COMPANY work sites. COMPANY prohibits the possession or consumption of alcoholic beverages on any property, facility, aircraft, vehicle, or boat owned or used by COMPANY, except where such possession or consumption is explicitly authorized by COMPANY for limited business or social functions. COMPANY prohibits the possession of firearms, weapons, or explosives on or around any proper(y, facility, aircraft, vehicle, or boat owned or used by COMPANY, (Transportation of firearms for sporting activities or for personal protection in vehicles is not prohibited by this policy; provided the firearms are broke" down, displayed, and handled in a manner that meets acceptable safety standards and complies with Local, State, and Federal statutes covering gun control,) Under no circumstances will any person have in his/her possession a firearm, weapon, or explosive while offshore, in an office, warehouse, or other COMPANY facility. COMPANY expects CONTRACTOR to train its employees to recognize common hazards associated with their work tasks and CONTRACTOR must adhere to all Hazard Communication Standards as required by all applicable Federal, State, and Local Safety Regulations or industry safety standards. Hilcorp Alaska, LLC, MSA Master Fom November2014 Exhibit C-1 EXHIBIT 2 Page 1 of 4 All COMPANY employees, CONTRACTOR and its employees, agents or sub -contractors have "Stop Work Authority" for any unsafe or potentially unsafe situation. Any potential hazards identified must be reported immediately to a COMPANY representative and work stopped until the hazard can be properly understood and corrected. COMPANY reserves the right to audit CONTRACTOR, including, without limitation, its agents, sub -contractors, programs, policies, or procedures while work is being performed on COMPANY sites. PERSONAL PROTECTIVE FOUIPMENT(PPE CONTRACTOR is required to provide all applicable PPE, for its employees. The following PPE is required to be worn by all persons while on COMPANY work sites; Clothing - Flame Resistant Clothing (FRC) must be worn at all times while an COMPANY work sites. COMPANY accepts only shirt and pant combinations and coverall FRC. FPC must be fully buttoned and/or zipped (no cotton showing) at all times. Loot Protection - Steel -toed boots must be worn at all times. Please note that steel -toed tennis shoes are not allowed. Head Protection - Each person in a work area must wear a hard hat secured by the chinstrap, if applicable. Eye Protection - Each person must wear properly fitted safety glasses. Goggles, face shields, or other eye protection equipment may be required, based on the job -specific task. Life Vests - For job locations located on or near water, life vests must be worn at work sites vvIten working outside of handrails near or over water. This includes docks, shore based facilities (within 10 feet ofwater's edge), platforms, and camps. Inflatable life vests are discouraged, but, if used, must be auto -inflating. In the situations identified below, COMPANY requires that life vests be worn at all times. • When travelling on a boat or barge • When loading or unloading from a boat or barge • When working on a construction barge (unless the life vest creates an unsafe working condition) AddIdonal PPE Protection - Additional PPE may be required based on the task being performed. Consult additional safety resources such as Material Safety Data Sheets (MSDSs) to determine if additional PPE is required. Additional PPE that may be required could include, but is not limited to, respiratory equipment, gloves, hearing protective gear, safety belts, lifelines, and others. SAFETY MEETINGS COMPANY requires that CONTRACTOR conduct safety meetings prior to starting work each day. Meetings should be documented and that documentation maintained at the work site. JOB SAFETY ANALYSES USAO In order to help further identify workplace hazards, COMPANY recommends JSAs for any task. Any JSAs performed should be documented, signed by all parties/personnel involved, with documentation maintained at the work site. JSAs are required for the following tasks: • Hot Work • Confined Space Entry Hilcorp Alaska, LLC, MSA Master Form, November 2014 Lxhibit C-2 EXHIBIT 2 Page 2 of 4 • Si MOPS (Multiple operations occurring simultaneously on the same work site) • Heavy Lifts • New Equipment Startup • Adverse Weather Conditions Hot 01ork - COMPANY prohibits any Hot Work (Welding, Cutting Torch, grinding or other spark or heat creating activity), unless an approved hot work permit has been issued by an authorized COMPANY representative, or such Hot Work is being performed in an area specifically designated or posted as an area for Hot Work, such as a welding shop. Confined Space Entry - COMPANY prohibits Confined Space Entry unless an approved Confined Space Entry Pert -nit has been issued by an authorized COMPANY representative. Fall Protection - COMPANY requires that each CONTRACTOR follow all applicable Federal, State and Local Safety Regulations, and industry safety standards, when advisable, relative to fall protection when work is being conducted on elevated surfaces or in areas with the potential for falls. This includes, but is not limited to, use of safetybelts, lifelines and lanyards, safety nets, and climbing devices. Lock OntlTag Our - COMPANY mandates that all applicable Federal, State and Local Safety Regulations and industry safety standards, when advisable, must be followed for working on or around Energized equipment, or when there exists a risk ofelectric shock; including, but not limited to, Lock Out/Tag Out procedures. Demolition Work — A COMPANY representative must authorize demolition work prior to beginning any such work. Engineering plans should be developed if applicable to the scope of work. SEARCH AND SEIZURE POLICY COMPANY reserves the right, with or without notice, to lawfully and reasonably search any person, including, without limitation, CONTRACTOR's and its subcontractors' employees, agents or visitors, along with their personal effects, prior to entry or departure from a COMPANY work site, facility, vehicle, aircraft, or boa(. Methods used may include physical searches and, as appropriate, scheduled or random drug urinalysis screening. Info -actions of this policy includinp failure to submit to a search, will be grounds for disciplinary action, up to and includinp_ immediate termination of the Agreement. When appropriate, if any item is discovered through COMPANY searches, inspections or otherwise that is deemed dangerous or harmful to life or property, law enforcement officials may be notified. CONTRACTOR'S and its subcontractors', employees, agents or visitors not complying with this policy will be removed from COMPANY premises and not allowed to return. REPORTING INCIDENT'S in the event ofan accident or an emergency, including, but not limited to, worker injuries, occupational -related illnesses, vehicle accidents, property damage, spills, chemical releases, fires and near hits on any COMPANY location, CONTRACTOR shall immediately provide oral notification to COMPANY and shall prepare and furnish to COMPANY an incident report as soon as reasonably practicable, but not later than eight (8) hours after each such accident or emergency. CONTRACTOR shall provide COMPANY with copies of all photographs, videotapes, audiolapes, and written or electronic documents associated with the incident. COMPANY shall pursue all rights and remedies available to it under law or equity if CONTRACTOR tails to timely report an incident, including. without limitation, termination of this Agreement or recovery ofany actual damages resulting, from such an event. All written reports shall be submitted to the onsite COMPANY representative or to the Environmental Health & Safety Department ("EH&S") at the COMPANY's corporate offices via facsimile transmission to (713) 299-2750 or email to hertftlIc—ormcom. irCONTRACTOR cannot notify an on -site COMPANY representative, CONTRACTOR shall immediately notify EH&S at 713-209-2400. flilcmp Alaska, LLC, MSA Master Farm, Novemb*2014 Exhibit C-3 EXHIBIT 2 Page 3 of 4 COMPLIANCE COMPANY strives to create a safe work environment for all who enter our work sites. COMPANY's safety policy is designed with that goal in mind. Therefore, all safety Standards will be enforced, and failure to follow these safety Standards while on a COMPANY work site may result in immediate dismissal. Please feel free to contact COMPANY's Environmental Health & Safety Department at 7I3-209-2400 with any questions or concerns. THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK tlitcorp Alaska, LLC. MSA Master Form, November2014 Exbibit CA EXHIBIT 2 Page 4 of 4 Activity ID 1040 1388 1864 1394 1870 1412 1415 1460 1472 1471 1478 1479 1915 1919 1924 1927 1931 Dte Employee 6/10/2015 8/3/2015 8/3/2015 8/4/2015 8/4/2015 8/24/2015 8/25/2015 9/21/2015 9/25/2015 9/26/2015 9/27/2015 9/27/2015 10/1/2015 10/2/2015 10/2/2015 10/3/2015 10/4/2015 1937 10/5/2015 1962 10/10/2015 Activity Description ASR Rig Crew Orientation Orientation ASR Rig Orientation ASR Rig ASR Rig Visit ASR Rig Visit Replaced fire extinguishers on ASR Rig Site Visits: ASR rig, J-Pad Drilling, Pigging shop Site Audit: Rig, ASR Rig ASR Rig Incident Management/Information Review with Investigation Team. Witness Statements, Powerpoint, ASR Rig Incident Investigation ASR Rig GasBuster/Shaker/Flowback Monitoring ASR Rig Incident Investigation Attended ASR Rig Toolbox Mtg Attended ASR Rig Toolbox ASR Rig Corrective Action Discussion w/ field foreman ASR Rig Site Visit Facilitated ASR Rig Corrective Action discussion with IWS Drafted ASR Rig corrective actions ASR Rig LC Presentation development Field Audits Prgm Audits Safety Mtgs Supports Invstgtns 1 1 1 1 1 1 1 1 1 •1 1 4 1 1 1 1 1 1 1 1 •1 1 1 1 1 Tuesday, January 19, 2016 Page 1 of 2 EXHIBIT 3 Page 1 of 2 Activity ID Dte Employee 1981 10/29/2015 1989 10/30/2015 1490 11/2/2015 1492 11/2/2015 1994 11/2/2015 1995 11/2/2015 1491 11/3/2015 1996 11/3/2015 1998 11/3/2015 1999 11/3/2015 2002 11/4/2015 2003 11/4/2015 2005 11/6/2015 2012 11/8/2015 2036 1/5/2016 2051 1/9/2016 Activity Description ASR Rig Investigation Corrective Action Follow up ASR Rig Support — Personal Gas Detector Set up Travel to Mline point. Went to ASR Rig to review expectations of audit. Start auditing ASR Rig work - over rig. Finish audit on ASR Rig, started to put together audit report with findings, recommendations, and regulatory information. Travel from Mline Point back to Kenai ASR Rig Day 1 Audit ASR Rig Toolbox Mtgs Continue auditing ASR Rig and interviewing crew and IWS owner regarding taining/records. Complete S01 for ATF leak at GPTF, reviewed incident with lead operator at GPTF. ASR Rig Toolbox Meeting ASR Rig Auidt Day 2 Developed ASR Rig Audit presentation Hot Work Permit — ASR Rig Tank Trailer ASR Rig Audit Debrief with ASR president ASR Rig Toolbox Meeting ASR Rig Hazard Assessment — for SEMS audit ASR Rig OSHA investigation photos ASR Rig Sundry meeting Field Audits Prgm Audits Safety Mtgs Supports Invstgtns 1 1 1 1 2 1 2 1 1 1 2 1 2 1 1 1 1 1 1 1 Tuesday, January 19, 2016 Page 2 of 2 EXHIBIT 3 Page 2 of 2 • E • • THE STOP° SAFETY OBSERVATION CYCLE DECIDE REPORT TOP\ ACT 1 J 0a✓!lRVE Actions Unsafe Safe Unsafe Safe Reactions Personal PfOtectivc of Pleople All Safe I111% All Safe FA: Equipment — Adjusting Personal — Head -to -Toe Check Protective Equipment _ Head - - Changing Position — Eyes and Face - - Rearranging Job — — Ears - - Stopping Job Respiratory System - -- Attaching Grounds — Arms and Hands — Performing Lockouts — — Trunk - - Legs and Feet _ sitions .�People All Safe Injury Causes Toolq and Equipment All Safe 1% — Right for the Job - - Striking Against or — — Used Correctly — Being Struck by Objects — In Safe Condition Caught In, On, or Between Objects Falling Contacting Temperature Extremes —Available — Contacting — Adequate Electric Current — Known — Inhaling, Absorbing, — — Understood — or Swallowing a __ Followed Hazardous Substance — Repetitive Motions - - Awkward Positions! — orderliness Static Postures Standards — Known - - Understood — Followed — STOP00-OCL•ENG-0003 THE STOP® SAFETY OBSERVATION CYCLE PECIOEE REPORT BTOP ACT 1 pBBHRVE Actions Unsafe _ Safe Unsafe Bafe Adjusting Personal — Head -to -Toe Cheek Protective Equipment — Head — Changing Position — -- Eyes and Face — Rearranging Job — Ears - - Stopping Job — — Respiratory System — — Attaching Grounds — — Arms and Hands - - Performing Lockouts — — Trunk - - Legs and Feet — injury Causes — Right for the Job - - Striking Against or — — Used Correctly — Being Struck by — in Safe Condition — Objects — Caught In, On, c — Between Objects — Falling - - Contacting Available Temperature Extremes Extremes —Adequate — Contacting Electric Current — Known Understood — Inhaling, Absorbing, — Followed — or Swallowing a — Hazardous Substance — Repetitive Motions — Awkward Positions? —1StandardBtd Static Postures nowndeoodollowe — STOPOO.00L-ENG-0003 EXHIBIT 4 Page 1 of 33 • na BTep•....xru.erwt aorta ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES Conditions Unsafe Safe Safe acts observed Are They — Right for the Job — In Safe Condition —I Are They Unsafe acts observed — Clean — v Orderly - - Right for the Job - - in Safe Condition is It — Clear, — — Orderly — in Safe Condition = Name i 2 Date Ordetlinoss All Safe rA Site Standards — Available Area — Adequate — Doy Shift Time spent on observation Q # of people Contacted 1E hltpaiwvrw trasfirg dupnnt.cam' v;aearsto•,*d>ecklist # of People Observed Additional STOP' observation Checklists DuPont. Please visit y tre'ri place an order onalna. Ce�ygnt 4�i 2C1� __..�_ crnoz,..,,., �.e r teret trademarks can be obtained Cy contacting for cortaot information or to uPont. All rights reserved. STOP' of Dupont. .. WaP' Wnv.a.en..no. eltl. ELIMINATE UNSAFE CONDITIONS... `� cmr � PREVENT INJURIES "�1 Unsafe Safe acts observed i i1 It ^7t �l Are They — Right for the Job - - In Safe Condition — Are They Unsafe acts observed — Clean - - Orderly - - Right for the Job - -- in Safe Condition Is tt Clean — Orderly — Name — In Sate•Condition — Date o rA Standards —. Available — Are — Adequate — "ems 5 "l Shift Time spent on observation 0 # of People Contacted Q ht -flwww 1ni`,Sduprmtmnti Observed vvleds�Ti�drast # of People Additional STOP' Observation Checklists can be obtained by contacting b for contact information or to Dupont. please trisil place an order on-dne. opyright R 20i t OuPont. AI rights reserved. STOP' and the STOP" logo are registered trademarks of DuPont. EXHIBIT 4 Page 2 of 33 • THE STO P• SAFETY OBSERVATION CYCLE DECIDE REPORT \ @ / ti STOP a.,.-.......... ACT 1 09°ERVE Actions Safe Unsafe Safe . Adjusting Personal — Head -to -Toe Check Protective Equipment — Head - - Changing Position — Eyes and Face - - Rearranging Job — Ears - - Stopping Job .— Respiratory System - - Attaching Grounds — Arms and Hands — - Performing Lockouts — — Trunk - — Legs and Feet — Injury Causes Right for the Job - - Striking Against or — — Used Correctly — Being Struck by — in Safe Condition — Objects — Caught In, On, or — Between Objects *Available Falling — Contacting Temperature Extremes _ Contacting — Adequate Electric Current — Known — Inhaling, Absorbing, — -- Understood or Swallowing a — Followed Hazardous Substance — Repetitive Motions — Awkward Positions! — • Static Postures Standards — Known - - Understood — Followed STOP00-OOL-ENG-0003 THE STOP* SAFETY OBSERVATION CYCLE DECIDE REPORT e TOP x AC/ OBSERVCy,�,.. Actions Unsafe safe Unsafe Safe PeoplePersonal Reactions 21 Protective of Equipment — Adjusting Personal — Head -to -Toe Check Protective Equipment — Head — Changing Position — — Eyes and Face — Rearranging Job — — Ears - - Stopping Job — Respiratory System - - Attaching Grounds — — Arms and Hands — Performing Lockouts — — Trunk — Legs and Feet kip ositions Tools and of People All safe Equipment Alt Safe Injury Causes Right for the Job — Striking Againsi or — — Used Correctly — Being Struck by — In Safe Condition Objects - - Caught In, On, or Between Objects — Failing - - Contacting —Available Temperature Extremes -..,- Contacting — _ Adequate — Electric Current — Known - - Inhaling, Absorbing, — — Understood or Swallowing a — Followed — Hazardous Substance — Repetitive Motions - - Awkward Positions! -- ° Static Postures Standards — Known — Understood — Followed — STOP00-OCL-ENG 3003 EXHIBIT 4 Page 3 of 33 0 • i"aTo�^—, aaewN.nc.7 PREVELIMENT EI JURIES UNSAFE CONDITIONS... \ It Conditions Unsafe Safe Are They — Right for the Job In Safe Condition Are They — Clean —. Orderly _- Right for the Job In Safe Condition IS It — Clean — Orderly — In Safe Condition Standards — Available .— Adequate err MrR;'Mww.raB1!9g.d��x:nl.LortV Vtdeo/s1obGIeCNFst an �m Safe acts observed Unsafe acts observed r — 1 h�rP '�,� ��•Y ��LM't c0"l Name Date J- �L.z Site �- _ Area h,'S j"hr2 _ Time spent on observation # of People Contacted En # of People Observed Can be obtainw by contacting Coror contari inRvmnkn„ ,.. r. ra aTor•.rti. waarvn ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES Conditions Unsafe Safe t Safe acts observed \ Are They — Right for the Job —InSafeCondition Strticturi!s and WorkAwa All Saft, In Are They Unsafe acts observed — Clean — Orderly — Right for the Job — In Safe Condition Environment All Safe rA is It — Clean — Orderly — Name In Safe Condition -- 'R - t Date • -Z - si��tt{e�� Standards 1 3lit, �� - Area Available — - _ Adequate — t Shift %59 rnt o Timpenobservation # of People Contacted Q Mc WlNN.88tlIA!g.dU(10n'. LVn�i deas;oa d e.�Gst # of People Observed 0 Additional STOP° Observation Checklists can be obtained by9 contac^fing contact information or to DuPont. Please rish wwv.•,ls•IIl place an radar on-line. Copyright S.SX7@<or 11 DuPortl. All rights reserved. STOP* end the STUf''° Iega are reglstered hadomarka of DuPont. o C J 'j m ern 8a� C, p .0 o U � g m CD U 0 E 5 CU O y v L « c> 0 _� teary EXHIBIT 4 Page 4 of 33 THE STOP• SAFETY OBSERVATION CYCLE DECIDE REPORT s STOP 4P ACT f O88ERVE Actions Unsafe Safe Unsafe Safe Person al 01 People All Sat, -- Adjusting Personal — Equipment Head -to -Toe Check Protective Equipment — Head - - Changing Position — — Eyes and Face — Rearranging Job — --. Ears — Stopping Job — — Respiratory System - - Attaching Grounds — Arms and Hands - - Performing Lookouts — — Trunk — Legs and Feet 'Positions of PeoPle All Safe I!-: Injury Causes Tool� And Equipment All Sate- F.- — Right for the Job — Striking Against or — — Used Correctly — Being Struck by — In Safe Condition — Objects — Caught In, On, Or Between Objects .— Falling - - Contacting Temperature Extremes —Available — Contacting -- Adequate Electric Current Current — Known — Inhaling, Absorbing, — -- Understood — or Swallowing a _ Followed Hazardous Substance — Repetitive Motions - - Awkward Positions) —!.Orderliness All Sate �'4 Static Postures Standards — Known - - Understood — Followed STOPOO-OCL-ENG-0003 ll�li4l4 141 !141{i 141 E I , N C J {n y Y U LL T 2 U. y O p O 'O 'r M N% c O p c o • t3 S W W a l H J c Q¢ Y LL C 1 1 ! ! f I I 1 f! I! I I Y - � ro �y (+1 E C7 t y N E u1 Yt ° o W o � M OA _N o° _ . o W m Q GO rn aV Qo c` a r o E C @ ,c u�UlY L a�i �'5-Oot — 07O- ![ E 7 C ECL '6 t Ol $ N .!r a+ A cad iq O N O _ W ¢ 2 U 4Y vn d U. 3 cn m p CS o7 U- U Y U W b m ¢ Q S EXHIBIT 4 Page 5 of 33 • • L cot m sror+urc,r-xc...nax ELIMINATE UNSAFE CONDITIONS... �— PREVENT INJURIES �`�7 �._.� Conditions Unsafe Safe Safe acts observed A I Ir`h��"►�2 5 Are They — Right for the Job —---- -- - In Safe Condition Work Area Ail Sate Y-4: Are They Unsafe acts observed — Clean - - Orderly _ Right for the Job — In Safe Condition Is it — Clean — — Orderly _ Name — In Safe Condition — Date C - Q0.� Site Standards i :' Ylf_ ��k•Y Area r 9, r 5 L, apt Available w Adequate — Shift Orf 121 Time spent on observation # of People Contacted hill :lMvm.kanprg.dupcsl.0 w NaeaMop.cnecdist # of People Observed ZI Adrf@icnal STOP- Observation Chec�lr;pspts� DuPont. Ptease visit �gl}gdt.r�m place an order o'ne. Copyrght 20111 and the STOP logo are registered Trademarks �co�n be obtained by contacting for contact information or to DuPont All rights reseved. STOP' of DuPont. CONDITIONS... 7 A Conditions Unsafe Safe Tools and Lquipmont Alt Sate 07,111 Are They — Right for the Job - - In Safe Condition — Are They — Clean — Orderly — Right for the Job — in Safe Condition Is N — Clean — Orderly — in Safe Condition Standards — Available w Adequate b httpi!wAvr ;rt+xiing ap�cni.rprnr vidaofstbpthreddlst ,net STOP* Obasfvatton C it. Please "'it an order OrAne. opydgh' Safe acts observed (�►ah.1 S 1w.e-a rC �f w, eol-%' y -I Unsafe acts observed —_ Name _ _ 1_►3-1� Dat site OIL,, i n� Poiy _ Area t f A! Shift r Time spent on observation # of People Contacted # of People Observed Q iecklists can be obtained try contacting "pCL6M for contact information or to e bnli Pont. All riches reserved. STOP' i I y m ro o Q. go � l c W y N u) I I I I I I I I I I f a z7 Mz' it)c Y° 9 o c 1 m W nr• 'x U _ 2 U U m A1, zFRr EXHIBIT 4 Page 6 of 33 • THE STOP* SAFETY OBSERVATION CYCLE DECIDE REPORT N WSSRWR .'t'p4 �'�`� a'��sst"Ctleckllst Actions Unsafe Safe Unsafe Safe Personal of People All Safe C4 Equipment I�Eiaf, Ll — Adjusting Personal — Head -to -Toe Check Protective Equipment — Head — Changing Position — Eyes and Face — — Rearranging Job — Ears — Stopping Job — — Respiratory System — — Attaching Grounds -- Arms and Hands — Performing Lockouts — — Trunk — Legs and Feet Tools p's Ali Safe Equipment AIISM� Injury Causes — Right for the Job - - Striking Against or — — Used Correctly — Being Struck by _ In Safe Condition — Objects Caught In, On, or Between Objects — Falling - - Contacting — Available Temperature Extremes — Contacting —Adequate — Electric Current — Known - - Inhaling, Absorbing, — — Understood or Swallowing a — Followed — Hazardous Substance — Repetitive Motions - - Awkward Positions/ — • Static Postures Standards Known — _ Understood - - Followed — STOP00.00L•ENG-0003 THE STOP* SAFETY OBSERVATION CYCLE DECIDE REPORT � e Wrop TOP T OBSERVE Actions Unsafe Safe Unsafe — Adjusting Personal — ea Ho-Toe Check Protective Equipment — Changing Position — yead — -/Eyes and Face Rearranging Job — — Ears 'o — Stopping Job — — Respiratory System I— Attaching Grounds — _ Arms and Hands 2 I— Performing Lockouts — — Trunk — Legs and Feet po!iitions of People Ali SM0 r4 Injury Causes Tools and Eq,,ip,,,nt All Sale — Right for the Job - - Striking Against or — Being Struck by Objects — Used Correctly — — In Safe Condition — _._. Caught In, On, or — Between Objects — Failing — Contacting Temperature Extremes — Available - - Contacting _ Electric Current — Adequate -- .._ Known - - Inhaling, Absorbing, --- — Understood or Swallowing a — Followed — Hazardous Substance — Repetitive Motions — Awkward Positions/ — • Static Postures Standards _Known — Understood - - Followed — STOPMOCL-ENG•W03 EXHIBIT 4 Page 7 of 33 • • Yx. stowu.ttr oNwBwYwamu ELIMINATE UNSAFE CONDITIONS — PREVENT INJURIES Conditions Unsafe Safe Safe acts observed 7AThey the Job — �`^ e.Condition L-11 r Are They Unsafe acts observed — Clean — Orderly — Right for the Job .._ In Safe Condition _ Is It — Clean — Orderly — In Safe Condition Standards Available — Adequate 1 htlpYlwttn.ffaioirre,duppnl.00mf rdeal3toptt:eckl'�.st Additional STCPe Observation C. DuPont. Please visit tp treir g piece an order on - one. o,C pyrig t and the STOP°togo are regtstere 1p ate R�JS•1� site _ Art f� Shin, nJ i!me— sp1 t on observation # of People Contacted # Of People Observed Xists can be obtained by c hwuine or to €TOP" iY.! 6T� V ^n"�f6alw.YMN cYRf ELIMINATE UNSAFE CONDITIONS... % PREVENT INJURIES Conditions , �{' Rfi Unsafe Safe WIIIIIIIIIIIII Safe acts observed Are They — Right for the Job - - in Safe Condition — Are They Unsafe acts observed .— Clean ro I r a..a f K i rS — Orderly — �frcr�.-s�etf'e,Jn Right for the Job _ In Safe Condition — 0'/ S 1, Is It — Clean — Orderly arne — In Safe Condition — ',FA pate o All Sato Site Standards Area I — Available — d !� — Adequate — Shift D.r 0 Time spent on observation # of People Contacted hdp:°wKM'.trainirgAutunl.W m' videeiarop•checdat # of People Observed Additional STOP® Observation Checklists can - obllained1by ro$latt o to fo DuPont Pleese visit www.tr �Sisdnord,rA.rL place an order on-line. CaPW!8'�' 20tt b ,P�fhuPoris eerved. STOP' EXHIBIT 4 Page 8 of 33 • • THE STOP' SAFETY OBSERVATION CYCLE DECIDE REPORT > ` rpu+ j Stop „ ACT DBBERVE Actions Unsafe Safe Unsafe Safe Reaaions Personal Equipment — Adjusting Personal — Head -to -Toe Check Protective Equipment Head — Changing PoaAlon — Eyes and Face — Rearranging Job — Ears _ — Stopping Job — Respiratory System - - Attaching Grounds — —. Arms and Hands — Performing Lockouts — — Trunk _ Legs and Feet Equipment Aft Safe U In)ury Causes — Right for the Job — Striking Against or — Used Correctly Being Struck by Objects — In Safe Condition - - Caught in, On, or Between Objects — Falling — Contacting — Temperature Extremes —Available — ContactingAdequate — Electric Current —Known — Inhaling, Absorbing, — Understood or Swellowing a Followed Hazardous Substance - - Repetitive Motions — Awkward Positions] — Static Postures Standa rds s— Known _ — Understood _ — ST'OP00-0CL-ENG-OOC3 Followed I I I I i I i I" D 70 R£ 3 xR 5 M MC) p on O v C S. a �a �o gD 3.� o i3� c o c n �- O• y °w o �� = c� RO xy. I I I Illy � lilll III ncx� m -nCX>D 2 C;U cNo ? F � a ! I > D ? p 7 j ,fl `D IG, m Ip p MT O ° Cr tlf gg i�i �1 c I l I I l l I= • c d m � mO � V! -ID Ammer$ w a m tv �c yy m EXHIBIT 4 Page 9 of 33 0 ELIMINATE UNSAFE CONDITIONS... ,.a f�. PREVENT INJURIES e1_. _ Conditions Unsafe Safe ` F Safe acts observed e• tttySA> ddtN%. C�Qtwr Are They t�*••t#rr t ukta:_ — Right for the Job u0 iloww. — In Safe Condition N4 �j s �;Cb t- •/ i Are They Unsafe acts observed — Clean — Orderly — Right for the Job — In Safe Condition _ Is it Clean — Orderly ame _ In Safe Condition — Date m=Site 73tandards Area Stil�tttl �er 0 5 ini , Time spent on observation # of People Contacted Q MtpIMww.Gairi�.drponi.carti videastop.chegrsst # of People Observed Q Additional STOPe Observation Checklists 6uPortt Please visity can be obtained tyy eontacttng for Contact infOrrnetion or to PIeCe an ortler ort-line. Copyngnt 0 7 DUPCnt All rights reserved. STOP and the STOPe a aro registered trademarks or DuPaM. In Ta v •r srov^w..,o...unar�ti,. ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES Conditions 7 Unsafe Safe Safe acts observed W#wd ---i ifRtitrVawt: tPi 7They Right for the Job N.rre �s snvpp-� p — In Safe Condition — S° K4'ti_'"a� ti - wtt,L.16 w+rt� J.:sdt. ei I.ft"p cwr tr- J ae Sam Y and All "fe !A Work Are., Are They Unsafe acts observed — Clean — Orderly - - Right for the Job - - In Safe Condition — WM Is It Clean — Orderly Name — in Safe Condition Date e 'T-06 Site Standards — Available _ AAC Area — Adequate — +>�j_._ Shift 51tw+J, Time spent on observation # of People Contacted Q hltph4rww.trammill d.poM,wall "tl°oeto� # at People Observed Q Additional STOPe Observation Checklists DuPont. Please visit u� ptaw an order on-line. Capynpht 2011 and the STOrielogo are reig(stared trademarks can be obtained byy conlacling for contactIMormetlon orto DuPont. All rights reserved. STOP` of DuPont. EXHIBIT 4 Page 10 of 33 THE STOP® SAFETY OBSERVATION CYCLE DECIDR REPORT Cs \TOP\ w _nAC/ t L16'�7,�� YF/3t�N�p[UQii Ic�l►Glli Actions Unsafe Safe Reaction5 Unsafe Safe Personal _ Adjusting Personal — Equipment Head -to -Toe Cheek Protective Equipment — Head — Changing Position — Eyes and Face - - Rearranging Job — — Ears Stopping Job — — Respiratory System — Attaching Grounds — — Arms and Hands — Performing Lockouts — — Trunk _ Legs and Feet Positions Injury Causes ls and —'Right for the Job — Striking Against or — — Used Correctly Being Struck by Objects — in Safe Condition - - Caught In, On, or — Between Objects — Falling - - Contacting - Temperature Extremes —Available - - Contacting — Adequate — Electric Current — Known - - Inhaling, Absorbing, — — Understood — or Swallowing a — Followed Hazardous Substance — Repetitive Motions — Awkward Positions/ — • Static Postures Standards — Known - - Understood — Followed STOPW-OCL-ENG-M EXHIBIT 4 Page 11 of 33 • • M! STOW ew•rr NRM.ON CKLL ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES \ �`` \ / Conditions Unsafe Safe " x r Tool-, and Safe acts observed ny �tr Are They Right for the Job — In Safe Condition s-- — e Are They Unsafe arts observed — Clean — Orderly _ -_ Right for the Job — In Safe Condition I n1101rly ._ amen/ — in Safe. Condition — ,* a2 7 fr Date site Standards Area — Available Adequate ShrR �— �er Time spent on observation 0 htgolh+ww.f"airerg du t.cury t °D C° # of People Contacted # Of People Observed Q Additional S?OF' Observation Checklists DuPont. Please vigil SwrW.trmninv d�vanf place an order on -fine. Uopynght( �1, and the STOP'logo are registered trademarks can be obtained by contacting ccm for contact inforrnabor, cr to DuPont. All rights reserved. STOP° of DuPont. ,re 'ToroK:.ee.L•..,a. ELIMINATE UNSAFE CONDITIONS,.. PREVENT INJURIES Conditions Unsafe Safe F ' Are They — Right for the Job Safe act i observed 7` � �° In Safe Condition f Are They — Clean Unsafe acts observed — Orderly _. Right for the Job — In Safe Condition I CleanOrderly —Name n Safe Condition/� Date Orderliness All Safe Site Standards Area .-_- Available Adequate — R r shift� IF Der Time spent on observation A # of Panpla Contacted Q hdp:btmav,seining.dupont.comf Ydea"slop•ew,li•t # Of People Observed Q Additional STOP' observation Checklists DuPont. Please vitit Y�e an order on-lineGn,�ppjpg,dytggptyprp and the STOP$lo o are rOPYrlgtarredd trradsmark can be obtained bbyy contacting for contact informatlon or to of DuPontt. All ® STOP" fig. 3� I I i .3 ❑❑ h_ t7 ° m m 3 I, a• c �°' O C m f✓ m o. $ _ 2 "imtpp N col �h E a _Qp� LLW C to 0 a G c E`• T� can EXHIBIT 4 Page 12 of 33 • THE STOP® eAFETY OBSERVATION CYCLE DECIDE REPORT STOPOBSERVE enm ao. ACY \ / Actions Unsafe Safe Unsafe Safe Protective Ali Siff. of People Ali Safe [I Equipment _ Adjusting Personal —7Head4o-Tdeheck Protective Equipment — Changing Position —Face— Rearranging Job -- Stopping Job ry System— Attaching Grounds Hands - - Performing Lockouts — — Trunk - -tC Legs and Feet c TooN and A It ot People Injury Causes — Right for the Job Striking Against or — Used Correctly Being Struck by _ in Safe Condition — Objects 1VCaught in, On, or Between Objects — Falling — Contacting — Available Temperature Extremes — Contacting — - Adequate Electric Current — Known — Inhaling, Absorbing, — — Understood — or Swallowing a r- Followed — Hazardous Substance — Repetitive Motions Y Awkward Positions) — Orderliness Static Postures Standards Known Understood - - Followed — STOPOo.oCL.ENG-0003 I I I o CAA X 6if o �Na I I I mn �c� -n �O o m 1 �c) m Mv, m IIv Q pp -=' 3 = �x � �00 A! Go -U 0%'> n`� d� G CKi 3= Q• N 0 pp QQ ��Cp pg 0 � k� 0 `go a �o �Icxba w N � ifl n Or CL THE $TOP• SAFETY OBSERVATION CYCLE DEC`IDE REPORT P ,- ACT i OBSERVE Actions Unsafe Safe Unsafe Safe Rvactiolls personal People All Solo E Protective of — Adjusting Personal — A115afe N EqUipIlletit Mead -to -Toe Check Protective Equipment — Head — Changing Position — — Eyes and Face Z — Rearranging Job — — Ears — Stopping Job — Respiratory System - - Attaching Grounds — Arms and Hands — Performing Lockouts — — Trunk _ — Legs and Feet People. All Safe Injury Causes Tools and Equipment All Safe — Right for the Job — Striking Against or — Used Correctly — Being Struck by Objects — In Safe Condition - -. Caught In, On, or Between Objects — Falling — _. Contacting Temperature Extremes — Available - - Contacting — — Adequate — Eiectric Current Known — inhaling, Absorbing, — -- Understood or Swallowing a — Followed Hazardous Substance — Repetitive Motions - - Awkward Positions/ — Orderliness Static Postures Standards — Known _... Understood — Followed STOPOO-OCL-ENG-0003 �Dc_nM0 aD rC! O N it- 3 am o ao � y C p N• C O 7 2. Cr r � C I I I I I I VD I 1 i �IQ I I Ip � V+ y D1 a y e m m n a s a m \ z f <C EXHIBIT 4 Page 13 of 33 • GLIMINATE UNSAFE CONDITIONS— sroP=, �rcwrm�no �s. PREVENT INJURIES \ C• icy' .�._ Conditions — — Unsafe Safe ` Safe acts observed Are They ,-- Right for the Job — In Safe Condition IItli�! lam`— 2 f� I Are They — Clean Unsafe acts observed — Orderly -- _ _ _ _ y — Right for the Job — -- —�_ — In Safe Condition Is It Clean A11Q + — Orderly Gk _— ame In Safe Condition • e Dat site �— Standards — Available — Adequate — J0.1 %11� http.lrwmv.hakytg d�ponl �aN wdea'ato .'c Ikflst Additional $Tops observation CY DuPont. Pieria visit wW W.tra-ninn place an order orMine. GoCyrght i and the STOPs logo are reoism.e. Time spent n obsen anon # of People Contacted # ofAeople abserved can be obtained by Contacting rfr� r°r `:onteci information or to 3uPont. All rights reserved. STOP= arks er n�.c,.... ��a' • I i I n I D C ,sm Da .� worm @@ m as Q t7 x O 0� a x e vi mr �^�p ❑ C W m? OD d ,� ,? y mz co O o O o Z ;4 a �. a C= mR c a Qr i t I l i I l l i I I z cl xc O# o rA D q t 2 a rr CD EXHIBIT 4 Page 14 of 33 THE .STOP® SAFETY OBSERVATION CYCLE DECIDEE` REPORT m STOP �,., ACT 1 OBSERVE Actions Unsafe Safe Unsafe Safe Personal Eqttipment — Adjusting Personal — Head -to -Toe Check Protective Equipment ,-_ Head — Changing Position — — Eyes and Face — Rearranging Job — — Ears -- Stopping Job — Respiratory System — Attaching Grounds — _. Arms and Hands -- Performing Lockouts — — Trunk _ _. Legs and Feet Position", of 'eupie All Injury Causes Tools and F-rimpment All Sate am — Right for the Job --- Striking Against or — Used Correctly Being Struck by Objects i — n Safe Condition — Caught In. On, or Between Objects — Falling Procedures All Safe — Contacting Temperature Extremes —Available - - Contacting — Adequate — Electric Current — Known — Inhaling Absorbing, — — Understood or Swallowing a — Followed Hazardous Substance — Repetitive Motions - - Awkward Positions/ — •MIT Static Postures Standards ._.- Known - - Understood — Followed STOP00-OCL-ENG-0003 THE STOPS SAFETY OBSERVATION CYCLE 0FICOE REPORT Y csmr STOP-,,.,,, /rACT OBSERVE r i�0t ;C1fC Actions Unsafe Safe Unsafe Safe Protective All Safe E of pLople Alt Safe — Adjusting Personal — Equipment Head -to -Toe Check Protective Equipment — Head - - Changing Position — — Eyes and Face - - Rearranging Job — — Ears - - Stopping Job _- — Respiratory System - - Attaching Grounds — — Arms and Hands -- Performing Lockouts — — Trunk - - Legs and Feet .W Positions Injury Causes Tool-, and — Right for the Job �c — Striking Against or — Used Correctly Being Struck by Objects — In Safe Condition -w- — Caught In, On, or Between Objects — Falling — Contacting — Temperature Extremes — Avaitable — Contacting _ -- Adequate — Electric Current — Known - - Inhaling, Absorbing, — — Understood — or Swallowing a — Followed — Hazardous Substance — Repetitive Motions — — Awkward Positions! — Orderliness All Sato Static Postures — Standards — Known - - Understood - - Followed — STOP00.00L-ENG•0003 EXHIBIT 4 Page 15 of 33 ,. 8to1K.,.n o.,.�..,w..n.e ELIMINATE UNSAFE CONDITIONS,.. PREVENT INJURIES Conditions Unsafe Safe • 61 Are They Safe ac observed t1 ^ Right for the Job — — In Safe Condition — Structures and � t Work Area Ali batc Are They Unsafe acts observed — Clean — Orderly - - Right for the Job — In Safe Condition It Is It — — Orderly — Name _ In Safe Condition — I',2-3" 1K Date Orderlinessr0 Site / Standards '� K — Available — Area _... Adequate — z -- Shift �rr � Jrii+.tn Time spent on observation # of People Contacted ] _� hpp1, viCe515 rvlot}checHirt ooniJ # of People Observed '--t 1 Additional STOPb Observation Chactdists can be obtained by contacting DuPont. Please viswww.trein:no.dudoM.can for contact information or to STOP' ydemarksoof a�Jttia STOP' an Order on -I" o ere stgered tza DuPont.s reserved. A ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES �� ! Conditions Unsafe Safe Safe acts observed 7ATheyr the JobCondition StruCtUres and Work Area Aft S;WIR Are They Unsafe acts observed ---- Clean — Orderly — Right for the Job — in Safe Condition it Is tt — — Orderly Name — In Safe Condition — Date tT- L7{s Site Standards &1r_// t 4- Area - Available — Adequate Q�, Shut irme spent on observation 0' htlpYiwww Vanerc.duportt.00rn! �a410p" eGkhS # of People Contacted # of People Observed Additional STOP' Observation C"okllsts DuPont. Please visit w" Irainlna.dubont.s�tor place an-d;oro-line. CapydghF�+2U11 end the 3TOPx o arc registerad trademarks can be obtained by contacting contact Information or M DuPont. All rights reserved. STOP' of DuPont EXHIBIT 4 Page 16 of 33 0 THE STOP® SAFETY OBSERVATION CYCLE DECIDE REPORT ` n / \ 1 OBSERVE Actions Unsafe Safe Unsafe Safe — Adjusting Personal — Head -to -Too Check Protective Equipment —Head — — Changing Position — Eyes and Face - - Rearranging Job — -.-- Ears — Stopping Job — — Respiratory System - - Attaching Grounds --- Arms and Hands — Performing Lockouts — — Trunk - - Legs and Feet Injury Causes — Right for the Job — Striking Against or — — Used Correctly Being Struck by — In Safe Condition — Objects — Caught In, On, or Between Objects — Falling — Contacting — Temperature Extremes — Available Contacting —Adequate - - Electric Current — Known - — inhaling, Absorbing, — — Understood — or Swallowing a — Followed — Hazardous Substance — Repetitive Motions - - Awkward Positions/ — Static Postures standards — Known - - Understood — Followed -- S70P00-OCL-EN"003 THE STOP" SAFETY OBSERVATION CYCLE DECIDE REPORT 91DP ACT 1 OBSERVE Actions Unsafe Safe Unsafe — Adjusting Personal — Head -to -Toe Cheek Protective Equipment — Head — Changing Position — — Eyes and Face — Rearranging Job — Ears — Stopping Job — _ Respiratory System - - Attaching Grounds — — Arms and Hands — Performing Lockouts — Trunk _ — Legs and Feet Injury Causes — Right for the Job — Striking Against or — — Used Correctly Being Struck by — In Safe Condition Objects — Caught In, On, or — Between Objects — Falling - - Contacting — Temperature Extremes —Available Contacting _ — Adequate Electric Current — Known — Inhaling, Absorbing, — — Understood or Swallowing a — Followed Hazardous Substance — Repetitive. Motions — — Awkward Positions/ — Static Postures STOPOO-OCL-ENG-DO03 Standards -..- Known — Understood — Followed EXHIBIT 4 Page 17 of 33 • • i M rlTOt`4r.lraw.mnprcF_f ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES Conditions Unsafe Safe .. We act observed v//y Are They Right for the Job - - In Safe Condition Structures and Work Area All Slfo N Are They Unsafe acts observed — Clean — Orderly tC Right for the Job In Safe Condition t% Is It — Clean ^- Orderly InSafe.Condition @NOW- -- s - Standards .S% — Available _ — Adequate Area Shift Time spent on observation 0 # ai PaopJe Contacted htlp9."µvm.lra'a;ing.duomLccnJ videa'stop-checkllsf # of People Observed Addihona-: STOW'Obsarvaflotr Checklists DuPont. Piaase visit www training du Pont can be Wamod by contacting I cam for contact information or to j place an order on-line. Copyright, 2Dt l and flit STOW loge a-e registered trademarks DuPonl. Ali rights raserved. STOPQ of DuPont. .n sior...•+. e.wv.iaworue ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES Conditions r d�Y Unsafe Safe Safe acts observed Are They — Right for the Job - - in Safe Condition Structures and — Work Area All Safe Are They Unsafe acts observed — Clean -T - Orderly Right for the Job - - In Safe Condition Environment All Safe _ Is It Clean Orderly — am _. In Safe Condition — t S6>� A Sit ) l,,Z7&Z Standards Available Area Adequate Shia' El MIN Time spent on observation A,. 0 # of People Contacted Q htlp.tNn'tw.Itanirr3 dupanLcotN �dt�t:mp-aheddret # of People Observed Additional STOP" observation Checklists Olin be obtained ay cc testing to DUF'cn,. Please visit Sit ''_�IrO dgpont com for contact inPor"wn or 201t DuPont. All rights reserved. STOW plane an order online. Copyrght (; and the STOP' logo are registered trademarks of DuPont. EXHIBIT 4 Page 18 of 33 • • THE STOP' SAFETY 013SERVATION CYCLE DECIDE REPORT a�® e�'j p % / �'t P STOP A OPKRVE r -L Actions UnsatQ Safe Reactions Unsafe Safe Personal PTOtect've Of People All Sal, — Adjusting Personal — All baf� Head -to -Toe Check Protective Equipment — Head — Changing Position — — Eyes and Face — Rearranging Job — — Ears — Stoppirg Job — __ Respiratory System — Attaching Attaching Grounds _ — Arms and Hands — Performing Lockouts — — Trunk — Legs and Feet — •. -Mtions Injury Causes Tools and _ Right for the Job — Striking Against or —Used Correctly Being Struck by Objects _ In Safe Condition — Caught Caught in, On. or Between Objects — Falling — Contacting — Temperature Extremes —Available — __. Contacting — Adequate Electric Current — Known - - Inhaling, Absorbing, — — Understood or Swallowing a — Followed Hazardous Substance _ — Repetitive Motions - - Awkward Positions/ —Orderliness Static Postures Standards — — — Known — Understood — Followed STOP00.00L-ENC-0003 EXHIBIT 4 Page 19 of 33 • • IM LIMINATE UNSAFE CONDITIONS.., y`n�� " rREVENT INJURIES \ Conditions r Unsafe Safe Safe acts observed Are They _ Right for the Job LZ fn Safe Condition — Are They Unsafe acts 9 serya — Clean — Orderly _ Right for the Job — In Safe Condition Is it _ Clean — Orderly _ Name — In Safe Condition Orderliness Date Site . -- Standards — Available rea • _ — Adequate � tf Shift Orr * '❑ S G' �. Time spent on observat#on Q # of People Contacted ny>Ir H�cYsroP+*Arcoml # of People Observed bser.�a� iC Additional STOAT Oe pg,�uoco cam or cu tack nformaoon g oto Dupont Please v+sit ht 2011 tluPont. All dohts reserved. STOP' ri place an wtler en -line. -opY 9 and the STOP�'logo are registered trademarks of Dupont. _ u I � I'g C, a ID I p y I U U. W N a O C D y� is C OMZ C1 us Q = o U ? o m a c t�01 a c E m m rn m to UMINATE UNSAFE CONDITIONS... 7 Amp' rREVENT INJURIES \/ Conditions U„safe Safe Safe ants observed Are They — Right for the Job — In Safe Condition — Are They Unsafe acts observed — Clean f L1' Orderly rurr+ �/t L Right for the Jo nC — , —LK c — In Safe Condition t— %T. 1sIt l,t/i tht. rs,rrrfr+r _ Clean - — Orderly — Name o?r % -1 In Safe Condition — (,l Date Site Standards Area — Available — a — Adequate Shift �f Q Trrne spent on observation [ej # of people Contacted hltp.!A•mw.ifain!ng.due1.com' mdeustorchx # of people Observed Additional STOP' Observetron rhea !!t can rorocbotrailacttli o nallonding Or to DuponL Please vist wv +,kat,'tith� puPOnt. A1! rights, reserved. STOP* ®2011 place ar. oaisreor._line ,, aPYa�9 r� lradernarks of DUPdnt._ ! yg� o m " Q, g E o oo� � 4 in •2 �l�r= at as � o 5. (i }® 2• w & plc td! @ to to m d 0. to r EXHIBIT 4 Page 20 of 33 THE STD P® SAFETY OBSERVATION CYCLE DECIDE REPORT TOP w. V9 ACT OBSERVE yy��LL MIVIF'ttS�., `. y Actions Unsafe safe Unsafe safe Reactions Personal EquFprncnt — Adjusting Personal — Head -to -Toe Check Protective Equipment — Head — ChengiN Position — Eyes and Face — Rearranging Job — Ears _ — Stopping Job — Respiratory System - - Attaching Grounds — Arms and Hands — Performing Lockouts — — Trunk — Legs and Feet Injury Causes ioofs and — Right for the Job — Striking Against or — Used Correctly — Being Struck by Objects — in Safe Condition — Caught in, On, or — Between Objects — Fatting Procedures— .— Contacting Temperature Extremes — Available - - Contacting — Adequate — Electric Current — Known — Inhaling, Absorbing, — — Understood — or Swallowing a — Followed Hazardous Substance - - Repetitive Motions - - Awkward Positions/ — Static Posturesnownnderstoodollowed !Standards STOP00-OCL-ENG-0003 EXHIBIT 4 Page 21 of 33 • • F" .xs STOW e..nv ae-orra-.ai ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES Conditions Unsafe Safe Safe acts observed 7The ob — on Structures and Are They — Clean Unsafe acts observed Orderly — F r — Right for the Job _ — In Safe Condition — ^ �! A� +mot Is It — Clean - - Orderly — — in Safe Condition — Nam Site , Standards ZE?2` Area — Available — _.._ Adequate — 7f Shift D.r Time spent an observation # of POOPIQ COntaGt&d Q nkplhV=fi in2hC0UGDont com! ualEa"sbp�checklist # of People Observed a Additional STOP- Observation Checklists DuPont Powe visit www tmining dueont place an order on-line. Copyright ® 2011 and the STOP -logo are regisfarod trademarks can be obtained by eontao4ting cc for cor:7act information or to DuPont All rights reserved. STOP' of DuPont. Y .-. aTav^uu+.oeuaw.ao.ae ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES / Conditions , • ;� Unsafe Safe Safe acts observed Are They — Right for the Job - - In Safe Condition — Are They Clean - - Orderly - - Right for the Job - - In Safe Condition — Is — — � Clean Orderly _ Namerr _ In Safe Condition — Z� Standards — Available — Adequate — D.r 0 ,h•tp:trawn.fia�nir.g.du,ro ntwm! rfdea'stop<hecktist Additional STOPSObservation Checks' s ltn pleas on-line. tsine y iw d v1 � Time spent on observation # of people Contacted # of people Observed a can be obtained by contesting j,ggm for contact information or to nrtPont. All rights reserved. STOP' r 1 1 I i O g m y o Vrn IWilli) C $ .Y Q` U a m WZ g o C ° w y r° o z �o c '0 o EXHIBIT 4 Page 22 of 33 THE STOPO SAFETY OBSERVATION CYCLE DECIDE REPORT OBSERVE Actions Unsafe Safe Unsafe safe Reactions All Safe id Equipment - Adjusting Personal — Head -to -Toe Check Protective Equipment Head - - Changing Position — _ Eyes and Face - - Rearranging Job — — Ears - - Stopping Job — — Respiratory System - - Attaching Grounds — Arms and Hands — Performing Lockouts — — Trunk Legs and Feet — Positions Injury Causes — Right for the Job - - Striking Against or — — Used Correctly — Being Struck by Objects — in Safe Condition — — Caught In, On, or — Between Objects — Falling -- - Contacting — Temperature Extremes _ Available — _r Contacting — —Adequate Electric Current —Known — Inhaling, Absorbing, — — Understood — or Swallowing a — Followed Hazardous Substance — Repetitive Motions — Awkward Positions/ —7-5tandards Static Posturesn — stooded — sroPoo-ocL-Enc-woos THE STOPS SAFETY 013SERVATION CYCLE RECCE+ REPORT BTOPf`,,.,..,.,,.,. a ACT �. 1 OBSERVE Actions Unsafe Safe Unsafe Safe — Adjusting Personal — Head -to -Toe Check Protective Equipment — Heed — Changing Position Eyes and Face - -- Rearranging Job — Ears — Stopping Job — Respiratory System - - Attaching Grounds — _- Arms and Hands _ — Performing Lockouts — — Trunk _ — Legs and Feet Injury Causes — Right for the Job — Striking Against or — Used Correctly Being Struck by Objects — In Safe Condition taught In, On, or — Between Objects - _ Falling - Contacting Temperature Extremes Available _ Contacting -- Adequate Electric Current — Known - Inhaling, Absorbing, — — Understood or Swallowing a — Followed Hazardous Substance — Repetitive Motions - - Awkward Positions/ — ' Static Postures Standards Known — Understood Followed sTCPOO-oCL-ENG-0o03 EXHIBIT 4 Page 23 of 33 ++e ST��BAran oxt c ELIMINATE UNSAFE CONDITIONS,.. PREVENT INJURIES Conditions Unsafe sate ..ts and Equipment Ali, 6afe n afe acts observed Are They — Right for the Job —# Ir — In Safe Condition — StRICALarpsand --*0164 co Worlk Area All Safr,. Are They Unsafe acts observed — Clean — Orderly — — Right for the Job In Safe Condition Environment All Sate Is It Clean . — Orderly — — In Safe Condition Name t Da Standards Site A ma — Available — — Adequate — Shift err Time spent on observation Q hhp6waw.trainin .du ont.cam! wdeustop�ek+t # of People Contacted Q # of People Observed ❑ Additional STOW Observation Checklists OuPont. Please visit '"w.traininn.duvont place an order orkne. Copyright 0 2Dt t and the STOPI;ogo are registered trademarks can be obtained by contacting rnm for contact Information or to DuPont. At rights reserved. STOP - of DuPont. the ROP•yucnope0.YlrlfMe,y{ PR VIENT IN URIEUNSAFS CONDITIONS... Conditions rs: Unsafe Safe + + afe acts observed Are They — Right for the Job — In Safe Condition Are They Unsafe acts observed — Clean — IA( A . , — Orderly _. Right for the Job — in Safe Condition Is It — Clean _ — Orderly Name — in Safe Condition — Va 3ite ��Standards — AvaBabi® Area .— Adequate �.r Q Time spent on observation ti # of People Contacted 11117'rw,vx hanir5 dupontramt vidao7stop<nr ,R # of People Observed Add Wnat STOP-'Ubservaton Checklists can be obtalnetl Ayy contacting DuPont. Plamo vlsfl>y� reining d P m..r for contact irdormation nr to place an order on-line, Copyright ®2t171 DuPont AM rights reserved, STOP• and the STEP+logo are regietered fademarka of DuPont. EXHIBIT 4 Page 24 of 33 • THE STOP* SAFETY OBSERVATION CYCLE OWDE L REPORT • TOP ,., AC/ OBSERVE Actions Unsafe Safe Unsafe Safe — Adjusting Personal — Head -to -Toe Check Protective Equipment — Head — YChanging Position — Eyes and Face — Yearranging Job _ — Ears — topping Job — Respiratory System - - Attaching Grounds — Arms and Hands — Performing Lockouts — — Trunk — Legs and Feet — In)dry Causes —Right for the Job — Striking Against or — — Used Correctly — Being Struck by Objects — to Safe Condition — JCaught In, On, or — Between Objects — Falling - - Contacting Temperature Extremes —Available — Contacting — — Adequate — Electric Current Known — Inhaling, Absorbing, — — Understood — or Swallowing a _ Followed — Hazardous Substance Repetitive Motions — Awkward Positions/ — Static Postures 73tandards STOP00-OCL-ENO-0003 THE STOP* SAFETY OBSERVATION CYCLE OECRDE REPORT \ r a • STOP ACT OBSERVE Actions Unsafe Safe Unsafe — Adjusting Personal — He -to-Toe Check Protective Equipment Head — Changing Position — Eyes and Face - - Rearranging Job — Ears — Stopping Job — — Respiratory System - - Attaching Grounds — Arms and Hands — Performing Lockouts — — Trunk — Legs and Feet — Injury Causes — Right for the Job — Striking Against or — Used Correctly — Being Struck by Objects — in Safe Condition — Caught In, On, or — Between Objects — Falling - - C-A �ttng — Temperature Extremes — Available — Contacting — — Adequate — Electric Current _ Known — Inhaling, Absorbing, — — Understood or Swallowing a — Followed — Hazardous Substance — Repetitive Motions - - Awkward Positions/ — Static Postures IStandards Known Understood Followed STOPOO.00L•ENG-0003 EXHIBIT 4 Page 25 of 33 1: • .�"k"�r�rttt�lln �F�s'cktist x ra Vow u�nowcnn nwcrae ELIMINATE UNSAFE CONDITIONS— " PREVENT INJURIES \ ow. Conditions Unsafe Safe Tools- and TV acts observed Equipment All Salo Are They Right for the Job in Safe Condition Structure-s and Are They Unsafe acts observed — Clean — Orderly _ Right for the Job — In Safe Condition — S1 out 00 j it lil awe-.. \ 0 7—Cleen erly _ Name In Safe Condition — q-w _ mmmmmw Date site Standards — Available Area — Adequate fl 5lld 5h' ift Time spent nn observation L Mof,gropr Contacted St�s;i?+nrw.haining.dupan.ca nt ❑ d idea$top`bBclust # of People Observed Addioonal STOP -Observation Checklists can be obtained by contacting r DuPont. Piesse visit b2mjreini for contact infonlation or to Place an order or -line. Copyright ®20 t 1 Ou ont. All this reserved 3T4P'' „ and the STOP' logo are istered hademarAs of DuPont. . .. _ .. STOP - ELIMINATE UNSAFE CONDITIONS... % r PREVENT INJURIES Conditions unsafe seta Safe acts observed Are They — Right for the Job - - in Safe Condition SwOlirp.; and Work Area Ali 61te Are They Unsafe acts observed — Clean } .— Orderly ^ Right for the Job — in Safe Condition jeAyx pa,� i�— Is it _ Clean — - — Orderly — Name i ^ in Safe Condition q - 20- E S Date site s Standards _ Available _ Area — Adequate — �ln:rle� Shift Time spent on observation #' orPeopte Contacted F hllp'IMe'w.lra i^irg.d�orr,coml wdewstopcnecas: # ofPeople Observed Q Additional STOP" Observation Checklists can be obtained br wnwling DuPont. Please visit JfaU}trtQ.Gun�ol.m>rt for contact information or to piece en order on-line. Copyright 0 2011 0 ont. All rights reserved. STOP"' and the STOP°la o are registered tredemarks of DuPont. EXHIBIT 4 Page 26 of 33 n INTEGRATED WELL SERVICE, INC Near Miss Report �i Name: � Date: � -t $— Location of Incident: �p__ 3 /g � Time: Rig # s g �.- Date of Incident: - Describe in Full what you were doing before, during and after the incident: 4nt�+.i��k. Describe in detail what actions or steps will be taken to prevent incident from reoccurring: %Alt- N"' d AANIC hi- Qj'}s r•h �i" S__ Name: _ Name: Name of Supervisor: EXHIBIT 4 Page 27 of 33 INTEGRATED v WELL SERVICES Near Miss Report Narne: "Incident: Date:Location Rig # S Date of Incident: "�-2�- >4` Time: �/Y-*Zamp Describe in Full what you were dloing before, during and after the incident: 1, 51„� % z�iir� -i Describe in detail what actions or steps will be taken to prevent incident from Name:Name. Name of Supervisor: EXHIBIT 4 Page 28 of 33 INTEGRATED WELL SERVICE, INC Near Miss Report Name: Date: g -a.a - kJ Location of Incident: Rig # A S 91 - 1 Date of Incident: 8 - - j Time: PM am/pm Describe in Full what you were doing before, during and after the incident: Describe in detail what actions or steps will be taken to prevent incident from reoccurring: �l ,n Name: _ Name: Name of Supervisor: EXHIBIT 4 Page 29 of 33 • INTEGRATED WELL SERVICE, INC Near Miss Report Name: Date: Location of Incident: je a 14 Rig # s ti i:J ) Date of Incident: W 8'- Z""/I- Time: am/pm Describe in Full what you were doing before, during and after the incident: /� w"►»') C r je*V??,) 1,,e a�-Y* P 'G 4- 4-r4)0PiN ;Y. f%C✓,�prS w c r��0�1 3 H� jr- /., AeA rYioY .y p-r" �o,- u„ 1� )-c4 .di � 4C t k r rfro r -k- y-c /, .k A. c -t ;rft 5 3� ,,` • �) �h-r t> - c k' •.5) v o �» Describe in detail what actions or steps will be taken to prevent incident from reoccurring: Q<q-,k LC/+V Lf 5 0;-O z 3 k Name: Name: Name of Supervisor: EXHIBIT 4 Page 30 of 33 INTEGRATED WELL SERVICE, INC Near Miss Report Name: Date: '8- Ilo - k5 Location of Incident: -arc, Rig # P6?-,- l Date of Incident: S - X X -- 1 S Time: g '. 3LO 2 rn am/pro Describe in Full what you were doing before, during and after the incident: Describe in detail what actions or steps will be taken to prevent incident from reoccurring: Name: Name: Name of Supervisor: EXHIBIT 4 Page 31 of 33 INTEGRATED WELL SERVICE, INC Near Miss Report Name: I Date: 5- — 10— 1 S— Location of Incident: -i — z Rig # 5 Date of Incident: 9— /l/ - Time: am/pm Describ in Full what you were doing before, during and after the incident: 1�-ti 1 e' /* e mee' a P ,5 /Jell ©>, rPir 7L - Oq loe�.- r1l-c j „ a , &,iro!")o, o�nIc I&,1 -i ,-cps- /Y►c..Gy'S Describe in detail what actions or steps will be taken to prevent incident from reoccurring: I l /4 'c .t % 1 ere.,,. c vZ s t .'d I-k-t I- ; c-7 . • led►' O jryL ' 's /'A-�-5 y+, h i �+ pi �Jh 7 d i -f e'a" RKh;oQ.L/ Name: Name: Name of Supervisor: EXHIBIT 4 Page 32 of 33 INTEGRATED WELL SERVICE, INC Near Miss Report Name: Date: Location of Incident: U Rig # Date of IncidentTime: ¢ am,1 Describe in Full what you were doing before, during and after the Describe in detail what actions or steps will be taken to prevent incident from Name: Name: Name of Supervisor: EXHIBIT 4 Page 33 of 33 THE STATE "SA MoRfle', GOVERNOR BILL WALKER Chris Kanyer Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU SB-15 Sundry Number: 315-158 Dear Mr. Kanyer: Alaska nil and Gas Conservation Commission 333 west Seventh Avonuo Anchorage, Alaska 99501 3512 Main: 907.279,1433 Fax: 901.276.7542 www.00gcc.alcskci.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, Cathy P. F crster Chair DATED this day of March, 2015 Encl. EXHIBIT 5 Page 1 of 13 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well Q Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑✓ Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ After Casing ❑ Other: ESP Changeout ❑✓ 2. Operator Name: 4. Current Well Gass: 5. Permit to Nil Number Hiicorp Alaska, LLC Exploratory ❑ Development ❑ Stratigraphic ❑ Service ❑ 202-152 3. Address: 6. API Number. 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 50-029-23106-00-00 7. if perforating. S. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C.O. 477 ? Will planned perforations require a spacing exception? Yes ❑ No Q MILNE PT UNIT SB 1-15' 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0025906 I MILNE POINT FIELD / SCHRADER BLUFF OIL POOL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9,050 4,106 9,050 4,106 N/A WA Casing Length Size MD TVD Burst Collapse Conductor 112' 20" 112' 112' 1,490psi 470psi Surface 3,085' 9-518" 3,085' 2,761' 5,730psi 3,090psi Production 4.949' 7" 4.849' 3,968' 7,240psi 5,410psi Slotted Liner'OA' 4,053' 4-1/2" 8.922' 4,042' Slotted Liner'OB' 3,841' 4-1/2" 9,041' 4,106' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: fff Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-7/8" 6.5# / L-80 / EUE 8rd 4,312 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (it): ZXP Liner Top Packer and WA 5,102'(MD)l 4,026'(IVD) and WA 12. Attachments: Description Summary of Proposal 13. Well Class after proposed work: Detailed Operations Program (J BOP Sketch Exploratory ❑ Stratigraphic ❑ Development ❑✓ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 3/25/2015 Oil Q Gas ❑ WINJ ❑ GINJ ❑ WDSPL ❑ Suspended ❑ WAG ❑ Abandoned ❑ 16. Verbal Approval: Date: Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chris Kanyer Email ckanyer@hilcorp.com Printed Name Chris Kan er Title Operations Engineer Signature C Phone 777-8377 Date 3/2012015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug integrity ❑ BOP Test [P Mechanical integrity Test ❑ Location Clearance L Other: 3 000 ` s, 45 4if 1 P 7tr 4 Lt C4.S;i+7/rc� Spacing Exception Required? Yes ❑ No Subsequent Form Required: 16 APPROVED BY Date: 3 - Z S —1 S Approved by: COMMISSIONER THE COMMISSION D4 AT Submd Form and Form 10-403 (Revised 10/2012) A p i4Gid O months from the date of approval. Attachments in Duplicate EXHIBIT 5 Page 2of13 Well Prognosis Well: MPI-15 Date:3/20/2015 Well Name: MPI-15 API Number: 50-029-23106-00-00 Current Status: SI Producer Pad: I Pad Estimated Start Date: March 25, 2015 Rig: Nordic 3 Reg. Approval Req'd? March 24, 2015 Date Reg. Approval Reevd: Regulatory Contact: Tom Fouts Permit to Drill Number: 202-152 First Call Engineer: Chris Kanyer (907) 777-8377 (0) (907) 250-0374 (M) Second Call Engineer: Bo York (907) 777-8345 (0) (907) 727-9247 (M) AFE Number: Current Bottom Hole Pressure: — 1,249 psi @ 4,000' TVD Maximum Expected BHP: — 1,249 psi @ 4,000' TVD Max. Allowable Surface Pressure: 0 psi Brief Well Summary: (Last BHP measured 3/6/2015) (No new perfs being added) (Based on actual reservoir conditions and water cut of 40% (0.374psi/ft) with an added safety factor of 1000' TVD of oil cap) The Milne Point 1-15 well was drilled as a Schrader Bluff development multi -lateral well that TD'd ran 4-1/2" slotted liners in OB at a depth of 9,050' and in OA at 9,000' in September 2002. The well was initially completed with an ESP. This and subsequent ESPs failed and were replaced in 2008 and 2014. The recent pump failed in February 2015. There is no recent casing pressure test performed and one will be completed during this workover. Due to observed scale issues, a downhole chemical injection line will be run as part of the new completion. No subsidence issues are expected in this well. Notes Regarding Wellbore Condition Current well status is shut in oil producer. No subsidence issue suspected. RWO Objective: Pull ESP & run 2-7/8" ESP completion with downhole chemical injection. Brief Procedure: 1. MIRU Nordic #3 Rig. 2. Attempt to circulate well with 8.5ppg seawater and monitor well. 3. ND tree, NU 11" BOPE and test to 250psi low/3,000psi high, annular to 250psi low/2,500psi high. a. Notify AOGCC 24hrs in advance to witness test. 4. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. b. With stack out of the test path, test choke manifold per standard procedure EXHIBIT 5 Page 3 of 13 Well Prognosis Well: MPI-15 Hilmrp,llaska.ld. Date: 3/20/2015 c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. g. Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. h. If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test ROPE per standard procedure. S. Unseat hanger and pull 2-7/8" ESP completion from 4,312' to surface and lay down same. 6. RIH with tapered cleanout BHA, wash bridges/fill if necessary in OB lateral to +/-9,000'. Contingency: (if unable to gain circulation or solids to surface) a. Circulate well with nitrified fluid, with surfactant and gel sweeps to clear lateral of solids. 7. POOH with tapered cleanout BHA. 8. RIH and set test packer at +/-4,700' (Note: above dual laterals, to test of 7" casing only). 9. Perform a charted casing pressure test to 1,500psi for 30min. Bleed off pressure and POOH with same. 10. MU and RIH with ESP with gas separator and 3/8" chemical injection line on 2-7/8" 8RD EUE L-80 tubing [to be replaced if necessary). Set ESP at +/-4,200'. Land tubing hanger. 11. ND BOP, NU and tree. 12. RDMO workover rig and equipment. 13. Turn well over to production. Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOP Schematic EXHIBIT 5 Page 4 of 13 Milne Point Unit Well: MPI-15 SCHEMATIC Last Completed: 5/7/2014 trlrnn, Ala„ka. LLc PTD: 202-152 CASING DETAIL RKB Elev = 25.7 TD=9,050' (NO) / TD=4,106'(1VD) PEtTD=9,450' (MD) / PB'TD= 4,106'(M) Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 92 / H-40 / Welded 19.124 Surface 112' 9-5/8" surface 40/L-80/Btc. 8.835 Surface 3,085' 7" Production 26 / L-80 / BTC-Mod 6.276 Surface 4,849' 4-1/2" Sltd Liner OA 12.6 / L-80 /IBT 3.958 4,869' 8,922' 4-1/2" Sltd Liner OB 12.6 / L-80 / IBT 3.958 5,200' 9,041' TUBING DETAIL " Tubing 6.5t1 / L-80 /EUE 8rd 1 2..441 1 Surface 4,31Y JEWELRY DETAIL )epth Item 139' GLM - Camco 2-7/8 x 1" Sidepocket KBMM 1,074' GLM - Camco 2-7/8' x 1" Sidepocket K8MM 4,226' HES 2-7/8" XN Nipple, 2.250 ID 4,269' Pump PMSXD/ 98P8 Armor X 4,281' Tandem Gas Separator - GSTHVER M FER 4,286' Tandem Seal Section- GS83DBUT S8/S0 PFSA & GS133D8LT SB/SB PFSA 4,300' Motor -84hp, 2,210 Volt, 23 Amp, Model MSPl /84 1,308' Pumpmate w/ 6 fin Centralizer- Bottom @ 4,312' 4,840' Baker Hook Wall Hanger inside 7" Window (21') 4,861' Baker Hook Wall Hanger outside Window (3') 4,864' Baker Down Swivel -up Lock sub 5,095' Baker Tie Back Sleeve 5,102' Baker ZXP Liner Top Packer 5,108' Baker 7" x 5" HMC Liner Hanger 5,120' 7" Halliburton Float Collar 5,203' 7" Halliburton Float Shoe LATERAL WINDOW DETAIL Top of "OA" Window @ 4,849' - 4,861'; Well Angle @ Window is 72deg WELL INCLINATION DETAIL KOP @ 470' - Max Hole Angle = 47 deg @ 4,120' MD 60deg, + Past 4,500' MD. _ Hole Angle through Perf s= 86 deg + OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset (Approx.) I in 42" Hole 9-5/8" Cmt w/ 919 sx Clas -C,225 sx Class "G" in 12-1/4" Hole 7" Cmt w/ 84 sx AS lire, 189 sx Class "G" in 8-1/2" Hole WELLHEAD Tree 2-9/16"-SMFMC 11" SM Gen w/ 2-7/8" EUE T&B Tubing Hanger with Wellhead CIW "H" BPV Profile GENERAL WELL INFO API: 50-029-23106-00-00 Drilled and Cased Mufti-Lat by Doyon 141 - 9/1/2002 ESP RWO by Nabors 4ES-8/21/2008 ESP Chan Bout by Doyon 16 - 5/7/2014 Created By: TDF 3/10/2015 EXHIBIT 5 Page 5 of 13 • RKS Bev = 25.7 TD = 9,050' (MD) / TD = 4,106'(TVD) PBTD=9,05D' (MD) / PBTD=4,106'(TVD) Milne Point Unit Well: MPI-15 Last Completed: 5/7/2014 PTD:202-152 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 92 / H-40 / Welded 19.124 Surface 112' 9-5/8" Surface 40 / L-80 / Btc. 8.835 Surface 3,085' 7" Production 26/ L-80/ BTC-Mod 6.276 Surface 4,84T 4.1/2" Sitd Liner CA 12.6 / L-80 / IBT 3.958 4,869' 8,92T 4-1/2" Sitd Liner OB 12.6 / L-80 / IBT 1 3.958 5,200' 9,041' TUBING DETAIL Tubing 6.5# / L: 80 /EUE 8rd 1 2..441 1 Surface 1 ±4,200' JEWELRY DETAIL lepth Item L339' GLM 3,974' GLM 4,146' XN Nipple 4,158' Pump 4,165' Gas Separator 4,166' Tandem Seal Section 4,180' Motor 4,194' Pumpmate w/ 6 fin Centralizer — Bottom @+.4,200' 1,840' Baker Hook Wall Hanger inside 7" Window (21') 1,861' Baker Hook Wall Hanger outside Window (3') 1,864' Baker Down Swivel -up Lock sub i,095' Baker Tie Back Sleeve i,102' Baker ZXP Liner Top Packer i,108' Baker 7" x 5" HMC Liner Hanger i,120' 7" Hailiburton Float Collar i,203' 7" Halliburton Float Shoe LATERAL WINDOW DETAIL Top of "OA" Window @ 4 849' - 4 861'• Well Angle @ Window is 72deg WELL INCLINATION DETAIL KOP @ 471Y Max Hole Angie = 47 deg @ 4,120' MD 60deg, + Past 4,500' MD. Hole Angle through Perf s= 86 deg + OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset (Approx.) I in 42" Hole 9-5/8" Cmt w/ 919 sx Clas L",225 sx Class "G" in 12-1/4" Hole 7" Cmt w/ 84 sx AS Lite, 189 sx Class "G" In 8-1/2" Hole WELLHEAD Tree 2.9/16"—SMFMC 11" 5M Gen w/ 2-7/8" EUE T&B Tubing Hanger with Wellhead CIW "H" BPV Profile GENERAL WELL INFO API:50-029-23106.00-00 Drilled and Cased Muni-Lat by Doyon 141 - 9/1/2002 ESP RWO_by Nabors4ES-8/21/2008 ESP Chan eout by Doyon 16-5/7/2014 Created By:TDF 3/10/201S EXHIBIT 5 Page 6 of 13 11" BOP Stack as EXHIBIT 5 Page 7 of 13 EXHIBIT 5 Page 8 of 13 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon ' Repair Well I Plug Perforations __.j Perforate LJ Other LJJ ESP Change -out Performed: Alter Casing ❑ Pull Tubing Stimulate - Frac ❑ Waiver Ll Time Extension ❑ Change Approved Program ❑ Operat. Shutdown;_] Stimulate - Other ❑ Re-enter Suspended Well ❑ 2. Operator Name: Hilcorp Alaska, LLC 4. Well Class Before Work: Development [__� Stratigraphic ❑ Exploratory ❑ Service ❑ 5. Permit to Drill Number: 202-152 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, Alaska 99503 50-029-23106-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0025906 MILNE PT UNIT SB I-151-7 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A MILNE POINT FIELD / SCHRADER BLUFF OIL POOL 11. Present Well Condition Summary: Total Depth measured 9,060 feet Plugs measured N/A feet true vertical 4,106 feet Junk measured N/A feet Effective Depth measured 9,060 feet Packer measured 5,102 feet true vertical 4,1W feet true vertical 4,026 feet Casing Length Size MD TVD Burst Collapse Conductor 112' 20" 112' 112' 1,490psi 470psi Surface 3,085, 9-518" 3,085' 2,761' 5,730psi 3,090psi Production 4,849' 7" 4,849' 3,968' 7,240psi 5,410psi Slotted Liner'OA' 4,053' 4-112" 8,922' 4,042' N/A N/A Slotted Liner'OB' 3,841' 4-112" 9,041' 4,106' N/A N/A Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 2-718" 6.5# / L-80 / EUE 8rd 4,198'MD 3,651'TVD 5,102'MD Packers and SSSV (type, measured and true vertical depth) ZXP Liner Top N/A 4,026 TVD N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data O&Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 0 Subsequent to operation: 150 5 161 240 203 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Explorator/ [i Development ❑ Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil P-1 Gas ❑ WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 315-158 Contact Chris Kanyer Email ckanver(Whilcoro.com Printed Name Chris Kanyer Title Operations Engineer Signature ^' 'nM r = Y Phone 907-777-8377 Date 5/5/2015 Form 10-404 Revised 1012012 Submit Original Only EXHIBIT 5 Page 9 of 13 11W.rp Alaska. 1.1.0 RKB Elev = 25.7 TD = 9,050' (MD) / TD = 4,106'(TVD) PBTD= 9,050' (ND) / PBTD=4,1WOVD) Milne Point Unit Well: MPI-15 SCHEMATIC Last Completed: 5/7/2014 PTD:202-152 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 92 / H-40 /Welded 19.124 Surface 112' 9-5/8" Surface 40 / L-80 / Btc. 8.935 Surface 3,085' 7" Production 26 / L-80 / STC-Mod 6.276 Surface 4,949' 4.1/2" Sltd Liner OA 12.6 / L-80 / IBT 3.958 4,869' 8,922' 4-1/2" Shd Liner OB 12.6 / L-80 / IBT 1 3.958 5,200' 9,041' TUBING DETAIL ":�j Tubing 6.Sft / L-80 /EUE 8rd 2..441 Surface 1 4,198' JEWELRY DETAIL )epth Item 142 GLM 3,966' GLM 4,140' XN Nipple 4,151' Discharge Head 4,151' Upper Tandem Pump 4,160' Lower TandemPump 4,167' Gas Separator 4,172' Upper -Tandem Seal Section 4,179' Lowerer-Tandem Seal Section 4,185' Motor 4,194' Pum mate w/ 6 fin Centralizer - Bottom 4,198' 4,840' Baker Hook Wall Hanger inside 7" Window (21') 4,861' Baker Hook Wall Hanger outside Window (3') 4,864' Baker Down Swivel -up Lock sub 5,095' Baker Tie Back Sleeve 5,102' Baker ZXP Liner Top Packer 5,108' Baker 7" x 5" HMC Liner Hanger 5,120' 7" Halliburton Float Collar 5,203' 7" Halliburton Float Shoe LATERAL WINDOW DETAIL Top of "OA" Window @ 4,849 - 4,861'; Well Angle @ Window is 72deg WELL INCLINATION DETAIL KOP @ 470'~ Max Hole Angle = 47 deg @ 4,120' MD 60deg, + Past 4,500' MD. Hole Angle through Perf s= 86 deg + OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset (Approx.) I in 42" Hole 9-5/8" Cmt w/ 919 sx Clas "L",225 sx Class "G" in 12-1/4" Hole 7" Cmt w/ 84 sx AS Lite, 189 sx Class "G" in 8-1/2" Hole WELLHEAD Tree 2-9/16"-5M FMC Wellhead 11" SM Gen w/ 2-7/8" EUE T&B Tubing Hanger with CIW "H" BPV Profile GENERAL WELL INFO API: SD-029-23106-00-00 _.................--- Drilled and Cased Mufti-Lat by Doyon 141 - 9/1/2002 ESP RIND by Nabors 4ES-8/21/2008 ESP Change -out by Doyon 16-5/7J2014 ESP Change -out by Nordic 3-3/29/2015 Created By:TDF 5/4/2015 EXHIBIT 5 Page 10 of 13 • E Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number JStart Date I End Date M PI-15 50-029-23106-00-00 202-152 3/24/2015 3/29/2015 Daily Operations: 3/18/15 - Wednesday No operations to report. 3/19/15 - Thursday No operations to report. 3/20/15 - Friday No operations to report. 3/21/15 - Saturday No operations to report. 3/22/15 - Sunday No operations to report. 3/23/15 - Monday No operations to report. 3/24/15-Tuesday BOP test waived by AOGCC/Grimaldi. BOP swap from 13-5/8" to 11". Begin rig move, rig off location 1OPM, move to 1-15. MIRU accept rig. Berm cellar, spot tanks, run hardline, pull BPV. PT all lines 250psi low/2,500psi high. SITP 270 psi, SICP 570 psi. Blow down well, line up to kill well and pump 37 bbls 140' 8.5ppg seawater down tubing, no returns. Swap over down csg after 23 bbls quick pressure increase and break over. Intermittent gas/oil returns on tbg. Continue and pump to liner top volume+ total pumped 244 bbl swap over and pump tubing volume 24 bbls. 119 bbls recovered oil water mix. Monitor well is on vacuum both sides install BPV. Blow down Break all Iines.ND Tree, prepare to NU BOPE. EXHIBIT 5 Page 11 of 13 • Hilcorp Alaska, LLC „i,Weekly Operations Summary Well Name JAPI Number lWell Permit Number IStart Date JEnd Date MPI-15 50.029-23106-00-00 202-152 3/24/2015 3/29/2015 Daily Operations: 3/25/15 - Wednesday PJSM. ND tree, inspect hanger and graphite grease surfaces, grooves and recesses. NU ROPE, install TWC. Fill stack, purge lines, shell test ROPE, fix leaks from new NU. BOPE test 250psi low/3,000psi high. Annular 250psi low/2,500psi high. All surface valves 250psi low/3,000psi high perform accumulator draw down test, all OK. Drain stack, remove and seal Bell nipple. Re -install and hydro test. Pull TWC, well still on vacuum. MU LND it, PU 79 K, hanger free. Pull to floor check ESP cable, good. Remove penetrators LD hanger string ESP cable. POOH with completion. LD bad joints identified from caliper log. Continue to POOH. 3/26/15 - Thursday POOH to ESP and examine same. No scale, some pitting on motor body from laying on low side of hole. Assembly is sand packed and froze up. BOLD ESP assy. PU 7" RTTS 7' 26# csg packer. RIH to 4,774' set packer. Fill hole w/ 28 bbis 8.5# SW, test and chart. Test to 1,500psi < 30psi bleed off in 30 minute, good test. POOH BOLD packer. Packer in excellent condition. Clean up floor strap and drift. NU adapter spool 11" 5M x 7-1/16" 5M on top of annular. Install BIW stripping head. PU 2-3/8" pup to set tong torque and function pressure test annular. Strap and caliper x-overs for 2- 7/8" production string. JSA on planned procedure to reach TOL and clean out same. PU run in hole with 2-3/8" PH-6 muleshoe and stinger assembly and stands from derrick of 2-7/8" L-80 production. Continue RIH very light < 2K down through upper window @ 4,840'-5,095' PU 64K down 59k. PU single and RIH lower lateral @ 5,102' did not see liner top light tag and rolling minor junk @ 5,113'. Continue in hole to 5,135'. Secure well for BOP stack centering for stripping head clearance. 3/27/15 - Friday Re -align stack @ 5,135'. RIH to S,'140'— tag hard. Set down 6K PU. Install 2-7/8" Stripping rubber and hook up to top drive. Wash to 5,135' through bridge, partial returns then total losses after bridge was removed. Wash down to 5,264'. Drag to 70K down 58K erratic. Wash down to 5,670' call engineer discuss N2 job. Pull 2 jts install dart valve reinstall 2 its. RU N2 Equipment. Hold PJSM. Secure rig floor. P/T all lines to 2,000psi. SD N2, rig up to pump 35 bbl solvent flush and displace out EOT with 25 bbl 8.5# SW, ICP 1,050psi, FCP 500psi. 150 bbl recovered mostly oil no real visible solids. Allow pill to soak. Hold PJSM identify IA as open and recorded by rig crew. Pump 1,010 gals (106,000 SCF) average rate 1,500 SUM @ 1,500psi. Pressure build to 1,700psi last 10-15 mintes after 100,000 away. Expect lifting fluid column pump additonal 6,000 SCF pressure not dropping. SD N2 pumping. Open annulus and bleed to kill tank. Circ. down tbg 72 bbis, ICP 1,450psi, FCP 60psi. Continue to bleed off annulus slugging fluid recover 98 bbls. Pump 43bbls down tubing, ICP 560psi, FCP 160psi. Annulus 0 psi. Observe well annulus flowing. Pump 200 bbl 8.5# SW down annulus. ICP 180psi, FCP 60psi. Pull/ LD 2 its tubing through stripper to dart and BO. Pump 20 bbl down tubing. Install tubing bleeder verify no pressure under dart, remove same and Install TIW. Annulus building to 40psi. Pump additional 100 bbl 8.5# SW down annulus. Full hole volume of 310 bbis has now been exceeded by160 bbls. SD observe well annulus and tbg pressure rising. Formation is still N2 charged. SI well to stabilize and observe pressure SICP 170 psi SITP 30 psi. 3/28/15 - Saturday PJSM SITP 0-19psi SICP 170 and dropping. Open up tubing light blow then vacuum. Bled casing to 0 psi. Leave open. Monitor pressures while waiting for fluid, awaiting hot SW 8.5# to trip. Offload and pump 21 bbis down tbg and 164 bbls down down csg. Intermittent returns after 112 bbis. POOH slowly standing back 7 stands in derrick and LD 153 its. ND stripping head and spool. NU riser LD excess pipe in derrick. Well appears stable. PU MU ESP assembly. EXHIBIT 5 Page 12 of 13 E 3/29/15 - Sunday PJSM. Resume building and servicing ESP assy. Install connector. Check Cable. RIH 2,100' with ESP and 2-7/8" 6.5# L-80 tubing. Check cable, OK. RIH with ESP 2,100'-4,198'. PU hanger, install penetrator, make connector splice. Meg check same, OK. RIH land hanger, RI lockdown screws, test cable. Remove landing joint install BPV, ND BOP, NU tree. P/T tree 250psi low/ S,OOOpsi. Centralizer 4,198', motor 4,186', Tandem seals 4,171', gas sep 4167', pumps 4,152', discharge head 4,151', PJ, XN nipple 4,139', 5 jts tbg, PJ, GLM 3,966', PJ,121 jts tbg, PJ, GLM 141', 4 jts tbg, pup/hanger. Dress and clean tree and cellar back over well. Rig released @ 1800. 3/30/15 - Monday No operations to report. 3/31/15-Tuesda No operations to report. EXHIBIT 5 Page 13 of 13 • E THE STATE °ALASKA --- (ic)ti'ERNOR BILL WALKER Chris Kanyer Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Milne Point Field, Schrader Bluff Oil Pool, MPU SB J-09A Sundry Number: 315-162 Dear Mr. Kanyer: 333 Wesi Severth Avenije Anchorage, Alaska 9950i-3572 mnlri: 907.279.1433 i'ax: 907.276.7542 www.aogcc:.a1aska.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, Cathy P. Voerster Chair DATED this2-5 day of March, 2015 Encl. EXHIBIT 6 Page 1 of 15 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS on nnr^ �q pan k '' .''ill' 1. Type of Request: Abandon ❑ Plug for Redriil ❑ Perforate New Pool ❑ Repair Well El Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing Q Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other. ESP Changeout Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Hilcorp Alaska, LLC Exploratory ❑ Development ❑ Stratigraphic ❑ Service ❑ 199-114 3. Address: 6. API Number. 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 50-029-22495-01-00 7. if perforating. 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C.O. 477 1 Will planned perforations require a spacing exception? Yes ❑ No ❑ MILNE PT UNIT SB J-09A 9. Property Designation (Lease Number): 10. Field/Pool(s): Milne Point Field J Schrader Bluff Oil ADL0025517 11, PRESENT WELL CONDITION SUMMARY Total Depth MD (it): Total Depth TVD (ft): Effective Depth MO (ft): Effective Depth TVO (ft): Plugs (measured): 1 Junk (measured): 8,235 4,046 8.235 1 4,046 N/A NIA Casing Length Size MD TVD Burst Collapse Conductor 112' 13-318" 112' 112' 1,730psi 740psi Surface 2,936' 9-5/8" 2,936' 2,529' 5,750psi 3,090psi Production 5,334' 7" 5,334' 3,828' 7,240psi 5,410psi Liner 938' 4-1/2" 6,137' 4,060' 8,430psi 7,500psi Slotted Liner j 2,098, 4-112" 8,235' 4,060' NIA N/A Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-7/8" 6.5#/ L-801 EUE 8rd 5,083' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (it): Baker ZXP Liner Top Packer and WA 5,199'(MD)/ 3,749'(TVD) and N/A 12. Attachments: Description Summary of Proposal Q 13. Well Class after proposed work: Detailed Operations Program n BOP Sketch Q Exploratory ❑ Stratigraphic (_] Development 0 Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 41112015 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ WIN ❑ GINJ ❑ WAG El Abandoned ❑ 16. Verbal Approval: Date: Commission Representative: GSTOR ElSPLUG ❑ 17. 1 hereby certity that the foregoing is true and correct to the best of my knowledge. Contact Chris Kanyer Email ckan er a hilcor .com Printed Name Chris Kanyer Title Operations Engineer Signature A,, Phone 777-8377 Date 3/23/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: C- Plug Integrity ❑ BOP Test+ Mechanical Integrity Test ❑ Location Clearance ❑ Other. Spacing Exception Required? Yes ❑ No L' 11 Subsequent Form Required: n APPROVED BY � f COMMISSIONER THE COMMISSION Date: �� Approved by: AT Submit Form and Form 10.403 (Revised 1012012) d a 4�li`Pt i 1 f r 12 months from the date of approval. Attachments in Duplicate EXHIBIT 6 Page 2 of 15 Well Prognosis Well: MPJ-09A Date:3/23/2015 Well Name:_ MPJ-09A API Number: 50-029-22495-01-00 Current Status: SI Producer Pad: J Pad Estimated Start Date: April 1, 2015 Rig: Nordic 3 Reg. Approval Req'd? March_31, 2015 Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts rt Permit to Drill Number: 199-114 First Call Engineer: Chris Kanyer (907) 777-8377 (0) (907) 250-0374 (M) Second Call Engineer: Bo York (907) 777-8345n (0) (907) 727-9247 (M) AFE Number: 1550677 Current Bottom Hole Pressure: — 1,475 psi @ 4,000' TVD Maximum Expected BHP: _ 1,475 psi @ 4,000' TVD Max. Allowable Surface Pressure:46 Brief Well Summary: (Last BHP measured 3/3/2015) (No new perfs being added) (Based on actual reservoir conditions and water cut of 33% (0.366psi/ft) with an added safety factor of 1000' TVD of oil cap) 6 The Milne Point J-09A well was redrilled as a Schrader Bluff development well that TD'd at 8,235' and ran 4.5" slotted liner into open hole in December 1999. The well was initially completed with a through tubing ESPCP (Electrical Submersible Progressive Cavity Pump), but failed immediately upon install. This was replaced with an ESP in January 2000. This failed and subsequent ESPs were replaced in 2003 and 2008. The traditional ESP was replaced with a ESPCP in 2013. This recent pump failed February 9, 2015. The last 7"casing test wasperformed to 2 OOOpsi on,4/2/2013. There are minimal observed scale issues, most failures are related to solids production. No subsidence issues are expected in this well. A caliper was run on the upper 1,000' of 7" casing in April 2013. Notes Regarding Wellbore Condition Current well status is shut in oil producer. No subsidence issues suspected. RWO Obiective: Pull ESP, perform cleanout, & run 2-7/8" ESP completion. Brief Procedure: 1. MIRU Nordic #3 Rig. 2. Attempt to circulate well with 8.5ppg seawater and monitor well. 3. ND tree, NU 11" BOPE and test to 250psi low/3,000psi high, annular to 250psi low/2,500psi high. a. Notify AOGCC 24hrs in advance to witness test. 4. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. b. With stack out of the test path, test choke manifold per standard procedure EXHIBIT 6 Page 3 of 15 Well Prognosis Well: MPJ-09A Hil-rn .aia4rv. M Date: 3/23/2015 c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. g. Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. h. If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. S. Unseat hanger and pull 2-7/8" ESPCP completion from 5,083' to surface and lay down same. 6. RIH with tapered cleanout BHA and circulate well clean to +/-8,200'. POOH with same. 7. MU and RIH with ESPCP with gas separator and +/-2,500' of heat trace on 2-7/8" 8RD EUE L-80 tubing [to be replaced if necessary]. Set ESPCP at +/-5,083'. Land tubing hanger. 8. ND BOP, NU and tree. 9. RDMO workover rig and equipment. 10. Turn well over to production. Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOP Schematic EXHIBIT 6 Page 4 of 15 Milne Point Unit Well: MPU 1-09A SCHEMATIC Last Completed: 4/13/13 PTD:199-114 ff LC CASING DETAIL KB Elev.: 29.6/ GL Elev.:17-Y TD= 8,235' (MD) / TD =4,064 M M) PBTD= 8,235' (MD) / PBTD=4,064 (TVD) Size Type Wt/ Grade/ Conn 10 Top Btm 13-3/8" Conductor 54.5 / H-40 / N/A 12.615 0 112' 9-5/8" Surface 40/ L-80 / Btrc. 8.835 0 2,936' 7" Intermediate 26 / L-80/ NSCC 6.276 0 5,334' 4-1/2" Liner 12.6 / L-80 / I BT 3.958 5,199" 6,137' 4-1/2" Slotted Liner 6.2 / L-80 / SLT 3.958 6,137' 8,235' TUBING DETAIL 2-7/9" 1 Tubing 1 6.5 / L-80 / EUE 8rd 1 2.441 1 0 1 5,083' JEWELRY DETAIL No Depth Item 1 133' 2-7/8" x 1" Side Pocket KBMM w/ DPSOV 2 4,846' 2-7/8" x 1" Side Pocket KBMM Shear Valve set @ 2,0D0 si 3 4,985' 2-7/8" XN Nipple (2.25" ID) 4 5,02T WellLift Discharge Gauge Unit 5 5,030' Wentrilift ESP: PCP 200D 2600 Pump 3.75"/ 22.42' 5,053' Flex Shaft Assemb EUE 8rd Box 5,062' Single Seal Section 5,068' Gear Reduction Unit GRU 538E 11.57:1 5,070' Motor MSP1/ 54 HP, 890 Volt, 39 Amp r 5,079' WellLift MGU w 6 fin Centralizer — Bottom @ 5,083' 5,199' Baker ZXP Liner To Packer w/ 6'Tie Back (5.25" ID) 5,215' Baker 5" x 7" HMC Liner Han er (4.375" 6,013'Baker HMCV Cement Valve 61032' Baker CTC 20' PZP ECP 15 8,190' 4.5" Baker Drillable Pack -Off Bushing 16 8,235' 4.5" Baker Drillable Guide Shoe WELL INCLINATION DETAIL KOP @ 600' Max Hole Angle = 59 deg. @ 3,300 — 3,500 MaxHole Angle = Horizontal nPFN 1-101F ! CEMENT DETAIL 13-3/8"" Cmt w/ 250 sx of Arcticset I in 24" Hole 9-5/8" Cmt w/ 572sx PF "E", 250 sx Class "G" in 12.1/4" Hole 7" Cmt w/ 400 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sks Class "G" in 6-1/9" Hole TREE & WELLHEAD Tree I Cameron 2-9/16" SM WKM 11" x 11" SM, WKM w/ il" x�2-7/8"ing hanger/NSCTthreads Wellhead top and bottom and 3" CIofile GENERAL WELL INFO API:50.029-2249S-OS-00 _ Drilled and Cased by Nabors 22E - 1/14/1995 Coma ion by Nabors 4ES — 2/15/1995 4ES — Schrader Bluff Sand Test #2 — 8/15/1997 Sidetracked By Nordic 3—12/15/1999 RWO b Nabors 4ES—1/24/2000 RWO by Nabors 4ES —12/11/2003 ESP RWO by Nabors 3S-6/16/2008 16— Revised By: TDF 3/23/2014 EXHIBIT 6 Page 5 of 15 • • KB Bev.: 29.6/ GL Elev.:17.0' TD = 8,235' (IVD) /TD= 4,064'(TVD) P81D = 8,235' (MD) / PBTD= 4,064'(M) Milne Point Unit Well: MPU 1-09A PROPOSED Last Completed: 4/13/13 PTD: 199-114 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8" Conductor 54.5 / H-40/ N/A 12.615 0 112' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 0 2,936' 7" Intermediate 26 / L-80 / NSCC 6.276 0 5,334' 4-1/2" Liner 12.6 / L-80 / IBT 3.958 5,199" 6,13T 4.1/2" Slotted liner 6.2 / 1-80 / SLT 3.958 6,137 8,235' TUBING DETAIL 2 7/8" Tubing 6.5 / L-80 / EUE 8rd 2.441 0 ±5,083' JEWELRY DETAIL No Depth Item 1 ±133' 2-1/8" x 1" Side Pocket KBMM w/ DPSOV 2 t4,846' 2-7/8" x 1" Side Pocket KBMM Shear Valve set @ 2,000psi 3 t4,985' 2-7/8" XN Nipple (2.25" ID) 4 ±5,027' WeRLift Discharge Gauge Unit 5 ±5,030' ........-... ZCentrilift ESP: PCP 200D 2600 Pump 3.75'/ 22.42' 6 ±5,053' Flex Shaft Assembly EUE Brd Box 7 ±5,062' Single Seat Section 8 t5,068' Gear Reduction Unit GRU 5388 11,57:1 9 ±5,070' Motor MSP1/ 54 HP, 890 Volt, 39 Amp 10 ±5,079' Weill-ift MGU w 6 fin Centralizer -- Bottom @ tS,083' 11 5,199' Baker ZXP Liner Top Packer w/ 6' Tie Back (5.25" ID) 12 5,215' Baker 5" x 7" HMC Liner Hanger (4.375" ID) 13 6,013' Baker HMCV Cement Valve 14 6,032' Baker CTC 20' PZP ECP 15 8,190' 4.5" Baker Drillable Pack -Off Bushing 16 8,235' 4.5" Baker Drillable Guide Shoe WELL INCLINATION DETAIL KOP @ 600' Max Hole Angle = 59 deg. @ 3,300 — 3,500' MaxHole Angle = Horizontal OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 250 sx of Arcticset I in 24" Hole 9-5/8" Cmt w/ 572sx PF "E", 250 sx Class "G" in 12-1/4" Hole 7" Cmt w/ 400 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sks Class "G" in 6-1/8" Hole TREE & WELLHEAD Tree I Cameron 2-9/16" SM WKM 11" x 11" SM, WKM w/ 11" x 2-7/8" tubing hanger/ NSCT Wellhead threads top and bottom and 3" CIW H PBV Profile GENERAL WELL INFO API: 50-029-2 2495-01-00 Drilled and Cased by Nabors 22E - 1/14/1995 Com letion by Nabors 4ES — 2/15/1915 Schrader Bluff Recompletion by Nabors 4ES—4/19/1997 Schrader Bluff Sand Test p2—8/15/1997 Sidetracked By Nordic 3—12/15/1999 RWO by Nabors 4ES-1/24/2000 RWO by Nabors 4ES—12/11/2003 ESP RWO by Nabors 3S 16/16/2008 RWO PCP Pump by Doyon 16-4/13/2013 Revised By: TDF 3/23/2014 EXHIBIT 6 Page 6 of 15 11" BOP Stack Hydri! 11"' 51V1 5 !s EXHIBIT 6 Page 7 of 15 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing ✓ Operations shutdown Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforale New Pool ❑ Repair Well Q Re-enter Susp Well ❑ Other: ES -PCP Change -out ✓❑ 2. Operator Name: 4. Well Class Before Work: 5. Permit to Drill Number: Hilcorp Alaska, LLC Development Q Exploratory ❑ Stratigraphic ❑ Service ❑ 199.114 3. Address: 6. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 50-029-22495-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0025517 MILNE PT UNIT SB J-09A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Milne Point Field I Schrader Bluff Oil 11. Present Well Condition Summary: Total Depth measured 8,235 feet Plugs measured N/A feet true vertical 4,046 feet Junk measured 7,075 (Fill) feel Effective Depth measured 7,075 feet Packer measured 5,199 feet true vertical 4,050 feet true vertical 3,749 feet Casing Length Size MD TVD Burst Collapse Conductor 112' 13-3/8" 112' 112' Surface 2,936' 9-5/8" 2,936' 2,529' 5,750psi 3,090psi Production 5,334' 7" 5,334' 3,828' 7,240psi 5,410psi Liner 938' 4-112" 6,137' 4,050' 8,430psi 7,500psi Slotted Liner 2,098' 4-1/2" 8,235' 4,046' NIA NIA Perforation depth Measured depth See Attached Schematic feet True Vertical depth See Attached Schematic feet Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5# / L-80 / EUE 8rd 5,063' 3,675' 5,199'MD Packers and SSSV (type, measured and true vertical depth) ZXP Packer N/A 3,749'TVD N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: NIA 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 44 3 26 80 219 Subsequent to operation: 81 2 83 240 232 14, Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: ❑ Daily Report of Well Operations R1 Exploratory ❑ Development❑✓ Service ❑ Stratigraphic 16. Well Status after work: Oil ✓ Gas WDSPL Copies of Logs and Surveys Run ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 315-162 Contact Chris Kanyer Email ckanyerhilcorp.com Printed Name Chris Kanyer Title Operations Engineer Signature Phone 777-8377 Date 6/312015 Submit Original Only Form 10-404 Revised 5/2015 EXHIBIT 6 Page 8 of 15 11ileorp Alaska, LLC KB Elev.: 29.6/ GL Elev.:17.0' TD =8,235' (MD) / TD = 4,064'(TVD) PBTD= 8,235' (MD) / PBTD= 4,064'(TVD) Milne Point Unit Well: MPU J-09A SCHEMATIC Last Completed: 4/29/2015 PTD: 199-114 CASING DETAIL Size I Type Wt/ Grade/ Conn ID Top Btm 13-3/8" Conductor 54.5 / H-40 / N/A 12.615 0 112' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 0 2,936' 7" Intermediate 26/L-80/NSCC 6.276 0 5,334' 4-1/2" Liner 12.6 / L-80 / IBT 3.958 5,199' 6,137' 4-1/2" Slotted Liner 6.2 / L-80 / SLT 1 3.958 1 6,137' 8,235' TUBING DETAIL 2-7/8" 1 Tubing 6.5 / L-80 / EUE 8rd 1 2.441 1 0 1 5,063' 1FWFLRY DETAIL No Depth Item 1 139' 2-7/8" x 1" Side Pocket KBMM w/ DPSOV 2 4,853' 2-7/8" x 1" Side Pocket KBMM Shear Valve set @ 2,000psi 3 4,994' 2-7/8" XN Nipple (2.25" ID) 4 5,006' WellLift Discharge Gauge Unit 5 5,009' ZCentrilift ESP: PCP 200D 2600 Pump 3.75"/ 22.42' 6 5,033' Flex Shaft Assembly EUE 8rd Box 7 5,043 Single Seal Section 8 5,049' Gear Reduction Unit GRU 538B 11.57:1 9 5,05V Motor MSPi/ 54 HP, 890 Volt, 39 Amp 10 5,059' Welllift MGU w 6 fin Centralizer — Bottom @ 5,063' 11 5,199' Baker ZXP Liner Top Packer w/ 6' Tie Back (5.25" ID) 12 5,215' Baker 5" x 7" HMC Liner Hanger (4.375" ID) 13 6,013' Baker HMCV Cement Valve 14 6,032' Baker CTC 20' PZP ECP 15 8,190' 4.5" Baker Drillable Pack -Off Bushing 1 16 8,235' 4.5" Baker Drillable Guide Shoe WELL INCLINATION DETAIL KOP @ 600' Max Hole Angle = 59 deg. @ 3,300—3,500' MaxHole Angle = Horizontal OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 250 sx of Arcticset I in 24" Hole 9-5/8" Cmt w/ 572sx PF "E", 250 sx Class "G" In 12-1/4" Hole 7" Cmt w/ 400 sx Class "G" In 8-1/2" Hole 4-1/2" Cmt w/ 97 sks Class "G" in 6-1/8" Hole TRFF fL WELLHEAD Tree Cameron 2-9/16" SM Wellhead WKM 11" x 11" SM, WKM w/ 11" x 2-71W tubing hanger/ NSCT threads top and bottom and 3" CIW H PBV Profile GENERAL WELL INFO API:50-029-22495-01-00 Drilled and Cased by Nabors 22E-1/14/1995 Completion by Nabors 4ES— 2/15/1995 Schrader Bluff Recompletion by Nabors 4ES — 4/19/1997 Schrader Bluff Sand Test #2 — 8/15/1997 Sidetracked By Nordic 3—12/15/1999 RWO by Nabors 4ES—1/24/2000 RWO by Nabors 4ES—12/11/2003 ESP RWO by Nabors 3S — 6/16/2008 RWO PCP Pump by Doyon 16 — 4/13/2013 ESP Change -out by Nordic 3 — 4/29/2015 Revised By: TDF 3/23/2014 EXHIBIT 6 Page 9 of 15 0 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number ]Well Number Start Date I End Date MP 1-09A 50-029-22495-01-00 199-114 4/26/2015 4/30/2015 Daily Operations: 4/26/15 - Sunday MIRU. Spot tanks, berm cellar MU hardline to kill tanks. Pull BPV, tested lines to 3,000psi-test ok, filled pits with 2 loads of 120deg seawater. SITP 240psi, SICP 240psi, bled csg/tgb down to Opsi, started pumping hot seawater, rev cir @ 3bpm and broke cir at 25 bbbls. Increased rate to 4 bpm, continued circulate kill fliud, with returns clean, SD pump -well on static. 272 bbls pumped, 246 bbls returned, 26 bbls lost. Set BPV and ND tree, NU BOP's and connected lines. Tried pulling BPV and well had pressure. Opened casing with a slight blow. Lined up manifold started pump, circulate 1 well volume casing/tubing slight blow. SI casing and bullhead down tubing, catch 1,800psi after 4 bbls pumped. Bled off to Opsi. Opened casing to kill tank, pulled BPV/installed TWC. Filled BOP stack and performed shell test (250psi-3,000psi). Tested BOPE per sundry, annular 250psi low/ 2,500psi high, rams 250psi low/ 3,000psi high, valves 250psi low/ 3,000psi high, performed kommey drawdown and gas dection. No failures recorded. 4/27/15 - Monday Preped rig floor to TOH w/ completion, opened casing pulled TWC and backed out lockdown pins. MU Landing jt, pulled 85k unseat hanger, pulled hanger to rig floor, meg. cable, good decompleted hanger and L/D same. PU stand and hang cables over sheave to spooler. TOH w/ completion, tallied tbg out, L/D 24 jts indentifed as bad on PDS caliper log plus 6 more with bad pin ends and tong markes, GLV's, xn-nipple and ESP assembly, packed sand small flakes of scale around the pump and intake. Cleaned and cleared rig floor, RD riser NU stripped head and preped to trip cleanout string. PU/MU 2-3/8" mule shoe. Till w/101 jts of 5.8# 2-3/8" PH6 xo 6.5# 2-7/8" EUE 8rd, 5,000' at report time. 4/28/15 - Tuesday Continued Till w/cleanout string, Tag hard @ 5199', PU 10', up weight 65k, down weight 55k. MU wash stand. Started pumping reverse circulate, broke circulation and washed down returns, heavy sand, tag hard @ 5,275' washed thru scale/sand bridge and continued washing down with heavy sand returns to top of slotted liner @ 6135'. Pumping 4bpm 1,300psi, total losses est 190 bbl, Immediate pump pressure 140 psi. RIH with 2 stands full reciprocation, check drag, continue RIH with all pipe in derrick to 7,075'. Install dart bottom jt 3. RU to pump N2 and surfactant, Witness all valves lined up for displacement of N2 to kill tank. Pressue test all lines 250psi low/2,500psi high. Problems with leaking valves on cement manifold. Grease and service same, PT OK. Pump 25 bbl Baraklean surfactant pill and chase with 10 bbls saltwater. Close annular BOP. Initiate pumping N2 500 SUM ICP 850psi, appeared to catch fluid after 45,000 SCF pressure increase to 1,350 psi, bump rate to 1000 SUM pressure 1,500psi increase to 1500 SUM pressure 1,580psi. After 100,000 SCF still no returns continue pumping drop rate to 1,000 SUM pressure maintaining 1,500psi continue pumping to 155,000 SUM (note total hole volume should be approx 240,000) still no returns. Discuss with engineering. Decison to stop pumping N2 205,000 SCF gone no returns. Discussed ESP recovery with vendor, it was noted that tandem seals from recovered ESP assy were bone dry, rest of assembly was sand packed. RD N2 equipment, annulus beginning to unload clean fluid and N2 tbg pressure at 1,300psi, flowing anuulus pressure surging 2-300psi est. Pump tubing volume, tubing on vacuum, annulus still unloading. Continue to flow back annulus and monitor well is flowing slugs of crude and intermittent N2, some saltwater. 154 bbls recovered — 50% oil. Well appears dead. Spot A frame w/crane on rig floor for heat trace ESP run while blowing down well. Check pressure on annulus 0 psi. Tubing has check valve. Open annular BOP, pull 1 stand bleed off check on tubing, 0 psi. Pump 180 bbl 8.6# saltwater down annulus, partial returns after 60 bbls. Pump 40 bbls down tubing, intermittent returns again, monitor well 15 minutes. Well is static light vacuum. Trip BOP drill, rig up to trip, latch on to first stand, pipe stuck no up no down. Work pipe no room to go down. PU single rig up to circulate down annulus pump 2-3 BPM. Work pipe 20K over, no movement, circulation intermittent after 17 bbls pumped. Flip circulation over, MU top drive, circulate down tubing 4 BPM, work 20-25K over, pipe is free. reciprocate pipe during circulation, 1 bottoms up with -50 bbl losses and crude in partial returns. POOH w/ 2-7/8" tbg racking back in derrick. EXHIBIT 6 Page 10 of 15 POOH and rack 42 stands 2-7/8" L- 80 production string. Monitor well, POOH LD 2-3/8" workstring and M/S BHA. Offload 2-3/8" PH6 C/0 string, on load Centrilift gear, GLMs, ND stripping head NU riser/bellNipple. Assemble and service PCP ESP assembly PJ and X-Nipple (ID= 2.313), string cable and cap over sheaves, hook up ESP connection and 3/8" stainless cap w/ Check. Test @ 900 psi. PU RIH tbg, shear valve GLM continued TIH w/ ESP completion testing cable and cap check every 2,000'. Cap check was 1,100psi. 2,525' from surface, string heat trace through sheave, attach/clamp heat trace. Continue RIH time per stand for HT and ESP clamps is 25 minutes. Install upper orifice GLM and final tbg. At report time still 3 stands in derrick and new replacement singles to PU. yy G y y Continue RIH w/ ESP/cap/HT. PU landing joint. Install hanger and penetrators. Test cables, cap string, and heat trace. Cut and splice cable connectors and cap string, install same. Meg check connector. Test heat trace connector. Land string SW 80K up 72K dn. Depths as follow: Hanger, Pup, 3 jts 2-7/8" L-80 6.5# tbg, pup, GLM @ 139',150 jts tbg, pup GLM @ 4,853', 4 jts tbg, XN-Nipple @ 4,994', pup. Head @ 5,005', Pump/Flex Shaft @5,010, EOT Centralizer @ 5,063'. Run in lock down screws. ND BOPS. NU tree. Test all breaks and void 250 5,000 psi. Release Rig. EXHIBIT 6 Page 11 of 15 J • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Plug Perforations Fracture Stimulate 11 Pull Tubing Operations shutdown Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well Q Re-enter Susp Well ❑ Other: ES -PCP Change -out Q 2. Operator Name: 4. Well Class Before Work: 5. Permit to Drill Number: Hilcorp Alaska, LLC Development ❑✓ Exploratory ❑ Stratigraphic ❑ Service ❑ 199-114 3. Address: 6. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 50-029-22495-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0025517 MILNE PT UNIT SB J-09A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Milne Point Field / Schrader Bluff Oil 11. Present Well Condition Summary: Total Depth measured 8,235 feet Plugs measured N/A feet true vertical 4,046 feet Junk measured 7,075 (Fill) feet Effective Depth measured 7,075 feet Packer measured 5,199 feet true vertical 4,050 feet true vertical 3,749 feet Casing Length Size MD TVD Burst Collapse Conductor 112' 13-3/8" 112' 112' Surface 2,936' 9-5/8" 2,936' 2,529' 5,750psi 3,090psi Production 5,334' 7" 5,334' 3,828' 7,240psi 5,410psi Liner 938' 4-112" 6,137' 4,050' 8,430psi 7,500psi Slotted Liner 2,098' 4-1/2" 8,235' 4,046' N/A N/A Perforation depth Measured depth See Attached Schematic feet True Vertical depth See Attached Schematic feet Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5# / L-80 / EUE 8rd 5,063' 3,675' 5,199'MD Packers and SSSV (type, measured and true vertical depth) ZXP Packer N/A 3,749'TVD N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 44 3 26 80 219 Subsequent to operation: 81 2 83 240 1 232 14. Attachments (required per 20 AAC 25.070, 25.071, a 25.2e3) 15. Well Class after work: Daily Report of Well Operations Exploratory❑ Development0 Service ❑ Stratigraphic ❑ 16. Well Status after work: Oil Gas WDSPL Copies of Logs and Surveys Run ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 315-162 Contact Chris Kanyer Email ekanyertcrdit1corp.com Printed Name Chris Kanyer Title Operations Engineer Signature 11411 Phone 777-8377 Date 6/3/2015 'r Form 10-404 Revised 5/2015 Submit Original Only EXHIBIT 6 Page 12 of 15 Milne Point Unit Well: MPU J-09A SCHEMATIC Last Completed: 4/29/2015 PTD: 199-114 Ilileorp Alaska, LI.0 CASING DETAIL KB Nev.: 29.9/ GL Elev.:17.0' TD=8,235 (MD) / TD= 4,064'(TVD) PBTD = 8,235' (MD) / PBTD = 4,064'(TVD) Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8" Conductor 54.5 / H-40 / N/A 12.615 0 112' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 0 2,93V 7" Intermediate 26 / L-80 / NSCC 6.276 0 5,334' 4-1/2" Liner 12.6 / L-80 / IBT 3.958 5,199' 6,137 4-1/2" Slotted Liner 6.2 / L-80/ SLT 1 3.958 1 6,137' 8,235' TUBING DETAIL Tubing I 6.5 / L-80 /EUE 8rd 1 2.441 1 0 1 5,063' JEWELRY DETAIL No Depth Item 1 139' 2-7/8" x 1" Side Pocket KBMM w/ DPSOV 2 4,853' 2-7/8" x 1" Side Pocket KBMM Shear Valve set @ 2,000psi 3 4,994' 2-7/8" XN Nipple (2.25" ID) 4 5,006' WellLift Discharge Gauge Unit 5 5,00V Wentrilift ESP: PCP 200D 2600 Pump 3.75"/ 22.42' 6 5,033' Flex Shaft Assembly EUE 8rd Box 7 5,043 Single Seal Section 8 5,04V Gear Reduction Unit GRU 538E 11.57:1 9 5,051' Motor MSPi/ 54 HP, 890 Volt, 39 Amp 10 5,059' WellUft MGU w 6 fin Centralizer — Bottom @ 5,063' 11 5,199' Baker ZXP Liner Top Packer w/ 6' Tie Back (5.25" 1 D) 12 5,215' Baker 5" x 7" HMC Liner Hanger (4.375" ID) 13 6,013' Baker HMCV Cement Valve 14 6,032' Baker CTC 20' PZP ECP 15 8,190 4.5" Baker Drillable Pack -Off Bushing 16 8,235' 1 4.5" Baker Drillable Guide Shoe WELL INCLINATION DETAIL KOP @ 600' Max Hole Angle = 59 deg. @ 3,300-3,500' MaxHole Angle = Horizontal OPEN HOLE / CEMENT DETAIL 13-3/S"" Cmt w/ 250 sx of Arcticset I in 24" Hole 9-5/8" Cmt w/ 572sx PF "E", 250 sx Class "G" In 12-1/4" Hole 7" Cmt w/ 400 sx Class "G" In 8-1/2" Hole 4-1/2" Cmt w/ 97 sks Class "G" in 6-1/8" Hole TREE & WELLHEAD Tree Cameron 2-9/16" 5M Wellhead WKM 11" x 11" 5M, WKM w/ 11" x 2-7/B" tubing hanger/ NSCT threads top and bottom and 3" CIW H PBV Profile GENERAL WELL INFO API: 50-029-22495-01-00 Drilled and Cased by Nabors 22E-1/14/1995 Completion by Nabors 4ES— 2/15/1995 Schrader Bluff Recompletion by Nabors 4ES — 4/19/1997 Schrader Bluff Sand Test #2 — 8/25/1997 Sidetracked By Nordic 3—12/15/1999 RWO by Nabors 4ES—1/24/2000 RWO by Nabors 4ES—12/11/2003 ESP RWO by Nabors 3S-6/16/2008 RWO PCP Pump by Doyon 16-4/13/2013 ESP Change -out by Nordic 3 — 4/29/2015 Revised By: TDF 3/23/2014 EXHIBIT 6 Page 13 of 15 Hilcorp Alaska, LLC >t1,►�,,,�,,,,►„�k,,,►.►.c Weekly Operations Summary Well Name API Number lWell Permit Number I Start Date jEnd Date MP 1-09A 50-029-22495-01-00 199-114 4/26/2015 4/30/2015 Daily Operations: 4/26/15 - Sunday MIRU. Spot tanks, berm cellar MU hardline to kill tanks. Pull BPV, tested lines to 3,OOOpsi-test ok, filled pits with 2 loads of 120deg seawater. SITP 240psi, SICP 240psi, bled csg/tgb down to Opsi, started pumping hot seawater, rev cir @ 3bpm and broke cir at 25 bbbls. Increased rate to 4 bpm, continued circulate kill fliud, with returns clean, SD pump -well on static. 272 bbls pumped, 246 bbis returned, 26 bbls lost. Set BPV and ND tree, NU BOP's and connected lines. Tried pulling BPV and well had pressure. Opened casing with a slight blow. Lined up manifold started pump, circulate 1 well volume casing/tubing slight blow. SI casing and bullhead down tubing, catch 1,800psi after 4 bbls pumped. Bled off to Opsi. Opened casing to kill tank, pulled BPV/installed TWC. Filled BOP stack and performed shell test (250psi-3,000psi). Tested BOPE per sundry, annular 250psi low/ 2,500psi high, rams 250psi low/ 3,000psi high, valves 250psi low/ 3,OOOpsi high, performed kommey drawdown and gas dection. No failures recorded. 4/27/15 - Monday Preped rig floor to TOH w/ completion, opened casing pulled TWC and backed out lockdown pins. MU Landing jt, pulled 85k unseat hanger, pulled hanger to rig floor, meg. cable, good decompleted hanger and L/D same. PU stand and hang cables over sheave to spooler. TOH w/ completion, tallied tbg out, L/D 24 jts indentifed as bad on PDS caliper log plus 6 more with bad pin ends and tong markes, GLV's, xn-nipple and ESP assembly, packed sand small flakes of scale around the pump and intake. Cleaned and cleared rig floor, RD riser NU stripped head and preped to trip cleanout string. PU/MU 2-3/8" mule shoe. TIH w/101 jts of 5.8# 2-3/8" PH6 xo 6.5# 2-7/8" EUE 8rd, 5,000' at report time. 4/28/15 - Tuesday Continued TIH w/cleanout string, Tag hard @ 5199', PU 10', up weight 65k, down weight 55k. MU wash stand. Started pumping reverse circulate, broke circulation and washed down returns, heavy sand, tag hard @ 5,275' washed thru scale/sand bridge and continued washing down with heavy sand returns to top of slotted liner @ 6135'. Pumping 4bpm 1,300psi, total losses est 190 bbl. Immediate pump pressure 140 psi. RIH with 2 stands full reciprocation, check drag, continue RIH with all pipe in derrick to 7,075'. Install dart bottom jt 3. RU to pump N2 and surfactant. Witness all valves lined up for displacement of N2 to kill tank. Pressue test all lines 250psi low/2,500psi high. Problems with leaking valves on cement manifold. Grease and service same, PT OK. Pump 25 bbl Baraklean surfactant pill and chase with 10 bbls saltwater. Close annular BOP. Initiate pumping N2 500 SUM ICP 850psi, appeared to catch fluid after 45,000 SCF pressure increase to 1,350 psi, bump rate to 1000 SCFM pressure 1,500psi increase to 1500 SUM pressure 1,580psi. After 100,000 SCF still no returns continue pumping drop rate to 1,000 SUM pressure maintaining 1,500psi continue pumping to 155,000 SUM (note total hole volume should be approx 240,000) still no returns. Discuss with engineering. Decison to stop pumping N2 205,000 SCF gone no returns. Discussed ESP recovery with vendor, it was noted that tandem seals from recovered ESP assy were bone dry, rest of assembly was sand packed. RD N2 equipment, annulus beginning to unload clean fluid and N2 tbg pressure at 1,300psi, flowing anuulus pressure surging 2-300psi est. Pump tubing volume, tubing on vacuum, annulus still unloading. Continue to flow back annulus and monitor well is flowing slugs of crude and intermittent N2, some saltwater. 154 bbis recovered — 50% oil. Well appears dead. Spot A frame w/crane on rig floor for heat trace ESP run while blowing down well. Check pressure on annulus 0 psi. Tubing has check valve. Open annular BOP, pull 1 stand bleed off check on tubing, O psi. Pump 180 bbl 8.6# saltwater down annulus, partial returns after 60 bbls. Pump 40 bbls down tubing, intermittent returns again, monitor well 15 minutes. Well is static light vacuum. Trip BOP drill, rig up to trip, latch on to first stand, pipe stuck no up no down. Work pipe no room to go down. PU single rig up to circulate down annulus pump 2-3 BPM. Work pipe 20K over, no movement, circulation intermittent after 17 bbls pumped. Flip circulation over, MU top drive, circulate down tubing 4 BPM, work 20-25K over, pipe is free. reciprocate pipe during circulation, 1 bottoms up with -50 bbl losses and crude in partial returns. POOH w/ 2-7/8" tbg racking back in derrick. EXHIBIT 6 Page 14 of 15 C7 • POOH and rack 42 stands 2-7/8" L- 80 production string. Monitor well, POOH LD 2-3/8" workstring and M/S BHA. Offload 2-3/8" PH6 C/O string, on load Centrilift gear, GLMs, ND stripping head NU riser/bellNipple. Assemble and service PCP ESP assembly PJ and X-Nipple (ID= 2.313), string cable and cap over sheaves, hook up ESP connection and 3/8" stainless cap w/ Check. Test @ 900 psi. PU RIH tbg, shear valve GLM continued TIH w/ ESP completion testing cable and cap check every 2,000'. Cap check was 1,100psi. 2,525' from surface, string heat trace through sheave, attach/clamp heat trace. Continue RIH time per stand for HT and ESP clamps is 25 minutes. Install upper orifice GLM and final tbg. At report time still 3 stands in derrick and new replacement singles to PU. r ii st r Continue RIH w/ ESP/cap/HT. PU landing joint. Install hanger and penetrators. Test cables, cap string, and heat trace. Cut and splice cable connectors and cap string, install same. Meg check connector. Test heat trace connector. Land string SW 80K up 72K dn. Depths as follow: Hanger, Pup, 3 jts 2-7/8" L-80 6.5# tbg, pup, GLM @ 139', 150 jts tbg, pup GLM @ 4,853', 4 jts tbg, XN-Nipple @ 4,994', pup. Head @ 5,005', Pump/Flex Shaft @5,010, EOT Centralizer @ 5,063'. Run in lock down screws. ND BOPE. NU tree. Test all breaks and void 250 5,000 psi. Release Rig. EXHIBIT 6 Page 15 of 15 • • THE STATE °fALASKA. GOVERNOR BILL WALKER Stan Porhola Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Pool, MPU SB J-01 A Sundry Number: 315-459 Dear Mr. Porhola: Alaska OiI and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy . Foerster Chair DATED this 3_v day of July, 2015 Encl. EXHIBIT 7 Page 1 of 12 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 9n AA(' 95 9An II fl 2 `= 1111!i 1. Type of Request: Abandon ❑ Plug for Redril' ❑ Perforate New Pool ❑ Repair Well M C,4Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑✓ Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Wet ❑ Stimulate ❑ Alter Casing ❑ Other: ESP Change -out ❑✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: tlilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 199-111 3. Address: 6. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 50-029-22070-01-00 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 Will planned perforations require a spacing exception? Yes ❑ No ❑✓ MILNE PT UNIT SB J-01A 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0315848 I Milne Point Field / Schrader Bluff Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 8,034 4,141 7,135 4,108 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 105, 13-5/81, 105, 105, 2,730psi 1,130psi Surface 2,40V 9-5/81, 2,409' 2,364' 3,520psi 2,020psi Production 3,640' 7" 3,640' 3,502' 7,240psl 5,410psi Slotted Liner 3,623' 4-1/2" 7,135' 4,154' NIA N/A Slotted Liner 3,142' 2-3/8" 7,709' 4,161' N/A N/A Perforation Depth MD (ft): Perforation Depth TVD (ft): i Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-7/8" 6.5# / L-80 / EUE 8rd 3,469' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): NIA and NIA NIA and N/A 12, Attachments: Description Summary of Proposal ❑✓ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development 0 Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 8/11/2015 Oil ❑✓ Gas ❑ WINJ ❑ GINJ ❑ WDSPL ❑ Suspended ❑ 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 Stan Porhola Email c any er@hilcorp.com Printed Name Stan Porhola Title Operations Engineer Signature Phone 777-8412 Date 7/28/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 315-�(5� Plug Integrity ❑ BOP Test [ Mechanical Integrity Test ❑ Location Clearance ❑ Other. • /.�C�P � r�s- /S Spacing Exception Required? Yes ❑ No I Subsequent Form Required: APPROVED BY a P-3p COMMISSIONER THE COMMISSION Date: 7 . —/,- Approved b G .��a.� ✓ QUEPPLICATEV..th. Submit Form and Form 10-403 (Revised 10/2012) from the date of approval. Attachments in Duplicate EXHIBIT 7 Page 2 of 12 • I filcorlo Alaska. I.0 Well Prognosis Well: MPU J-01A Date;7/28/2015 Well Name: MPU J-01A API Number: 50-029-22070-001 Current Status: SI Oil Well [ESP] Pad: J-Pad Estimated Start Date: August 11th, 2015 _ Rig: ASR #1 Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 199-111 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer:_ Paul Chan (907) 777-8333 (0) (907) 444-2881 (M) AFE Number: Current Bottom Hole Pressure: 1,378 psi @ 4,000' TVD (Last BHP measured 2/02/2015) Maximum Expected BHP: 1.378 psi @ 4,000' TVD (No new perfs being added) Max. Allowable Surf Pressure: 0 psi (Based on SBHP taken 2/02/2015 and water cut of 54% (0.389psi/ft) with an added safety factor of 1,000' TVD of oil cap) Brief Well Summary: The Milne Point J-01A well was sidetracked as a Schrader Bluff development well that TD'd at a depth of 8,034' and ran a slotted 4-1/2" liner in open hole in December 1999. The well was initially completed with an ESP. This ESP was pulled in 2001, a lateral was drilled & lined with a 2-3/8" pre-drilled/slotted liner, and a new ESP installed. Subsequent ESPs failed and were replaced in 2003, 2011, and 2015, Due to observed scale issues, a downhole chemical injection line was run as part of the new completion in 2015. Solids production is assumed to be the cause of the most recent ESP failure in July 2015. Notes Regarding Wellbore Condition • Casing last tested to 1,500 psi for 30 min down to 3,577' on 3/20/2015. Obiective• The purpose of this work/sundry is to pull the existing failed ESP and run a new ESP. Brief Procedure: WO Rig Procedure: 1. MIRU Hilcorp ASR #1 WO Rig. 2. Circulate well with 8.4 ppg lease water down tubing and fill casing. 3. Set BPV. ND Tree. 4. NU 11" BOPE. Test to 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 1,500 psi High (hold each valve and test for 5-min). Record accumulator pre -charge pressures and chart tests. a. Notify AOGCC 24 hrs in advance of BOP test. b. Test VBR rams on 2-7/8" test joint. 5. Bleed any pressure off tubing and casing. Pull BPV. 6. MU landing joint and pull over string weight (65k) on tubing hanger to confirm free. 7. POOH. Lay 2-7/8" tubing on the pipe rack (utilize as workstring). 8. MU 6-1/8" bit and junk baskets and RIH to +/- 3,500'. 9. Circulate bottoms up x 2 with 8.4 ppg lease water. 10. MU 3-3/4" bit and junk baskets and RIH to +/- 3,500' w/ 1-1/2" tubing. EXHIBIT 7 Page 3 of 12 Ililcoru Alaska. LU Well Prognosis Well: MPU J-01A Date:7/28/2015 11, MU XO from 1-1/2" tubing to 2-7/8" tubing. 12. Cleanout fill to +/- 7,000' in A lateral. 13. Circulate bottoms up x 2 with 8.4 ppg lease water. 14. POOH. Lay down bit and junk baskets. Lay down 1-1/2" tubing and 2-7/8" tubing. 15. PU new 475 series ESP and RIH with existing 2-7/8" 8RD EUE L-80 tubing. a. Test 3/8" control line to 2,500 psi. b. RU to use clamps to secure control line to tubing (ensure adequate clamps). 16. Set base of ESP at+/-3,475' (Pump intake around +/- 3,395'). Land tubing hanger. 17. Lay down landing joint. Set BPV, ND BOPE. NU existing 2-7/8" 5,000# tree. Pull BPV, 18. Set TWC. Test tubing hanger to 250/5,000 psi. Test tree to 250/5,000 psi. Pull TWC. 19. RD Hilcorp ASR #1 WO Rig. 20. Replace IA x OA pressure gauge if removed (7" x 9-5/8"). 21. Turn well over to production. Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOPE Schematic EXHIBIT 7 Page 4 of 12 Ifilcorp Alaska. LLC RKB Elev = 35' TD= 7,950' (NID) /TD = 4,165'(TVD) PBTD = 7,95a (MD) / PBTD = 4,16TOw) Milne Point Unit Well: MP1-01AL1 SCHEMATIC Last Completed: 4/24/2014 PTD: 201-021 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 954.5 / K-55 / Welded 12.615 Surface 105' 9-5/8" Surface 36 / K-55 / Btrc. 8.921 Surface 2,409' 7" Intermediate 26 / L-80 / OTC 6.276 Surface 3,640' 4-1/2" Sltd Liner A 12.6 / L-80 / IBT 3.958 3,512' 7,135' 2-3/9" SRd Liner B I N/A / L-80 / N/A I N/A 4,567 7,709' TUBING DETAIL Tubing 9.3 / L-80 / ELIE 8rd 2.867 Surface 3,469' Capstring Stainless Steel N/A Surface 1 3,469' JEWELRY DETAIL Depth Item 171' GLM 3,253' GLM 3,394' 2-7/8" XN Nipple, 2.2501D 3,405' Discharge Head — FPHVDIS 3,406' Dual Tandem Pump Section — 71 Flex 10 SXD (2) 3,435' Gas Separator — GRSFTXAR H6 3,44Y Tandem Seal Section - GSBDBUT SB/SB PFSA : GSBDBIT SB/SB PFSA 3,454' Motor—MSPI-250126HP/2,44SW33A 3,465' Sensor / Centralizer —±Bottom@ 3,469' 3,512' Baker 5" x 7" HMC Liner Hanger 4,567' 2-3/8" Liner Top w/ 3.70" Deploy Sleeve 4,682' Baker HMCV Cementing Valve 4,704' Baker CTC 20' PZP ECP WELL INCLINATION DETAIL KOP @ 1,500' MD Max Hole Angle = 26 deg @ 2,500' MD Hole Angle through Perf = 20 deg OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 500 sx Permafrost'C' in 30" hole 9-5/8" Cmt w/ 1,145 sx Permafrost'E' in 12-1/4" Hole 7" Cmt w/ 293 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sx Class'G' in 6-1/8" Hole TREE & WELLHEAD INFO Tree I WKM 2-911V SM 11" x 11" 5M Tubing Spool,11" x 2-7/8" 8rd (Top & Wellhead Bottom) WKM tbg. w/ 2.5"'H' BPV Profile i= 8,034' )= 7,90S' GENERAL WELL INFO AP1:50-029-22070-60-00 Drilled and Cased by Nabors 27E—12/15/1990 RWO/ Multiple Frac Packs — 4/4/1995 ESP Re lacement by Nabors 4ES — 2/21/1997 S/T & Comp. Nabors 4ES &Completion—10/05/99 2" Lateral 3S, Nabors S-ES & Nordic N3 — 5/27/2001 Replace ESP -Nabors 4ES — 8120/2003 Re lace ESP — Do on 16 — 8/20/2003 Replace ESP - Doyon 16-4/24/2011 Created By: TDF 4/29/2015 EXHIBIT 7 Page 5 of 12 • Ifileorn ALisku. LLC RKB Elev=35' TD = 7,950' (MD) / TD = 4,165'(TVD) PBTD = 7,950' (MD) / PBTD = 4,165'(TVD) PROPOSED Milne Point Unit Well: MP1-01AL1 Last Completed: Proposed PTD: 201-021 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 954.5 / K-55 / Welded 12.615 Surface 105, 9-5/8" Surface 36 / K-55 / Btrc. 8.921 Surface 2,409' 7" Intermediate 26 / L-80 ( BTC 6.276 Surface 3,640' 4-1/2" Slid Liner A 12.6/L-80/IBT 3,958 3,512' 7,135' 2-3/8" Sltd Liner 8 I N/A / L-80 / N/A I N/A 4,567 7,709' TUBING DETAIL I" Tubing 1 6.5 / L-80 / EUE 8rd 1 2.867 1 Surface JEWELRY DETAIL I Depth Item ±200' GLM ±3,250' _ GLM ±3,400' 2-7/8" XN Nipple, 2.250 ID ±3,411' Discharge Head — FPHVDIS ±3,412' Dual Tandem Pump Section — 71 Flex 10 SXD (2) ±3,441' Gas Separator— GRSFTXAR H6 ±3,446' Tandem Seal Section - GSBDBUT SB/SB PFSA : GSBDBIT SB/SB PFSA ±3,460' Motor— MSPI-25D 126HP/ 2,445 V/ 31A ±3,471' 3/8" Stainless Steel External Capstring ±3,471' Sensor / Centralizer —±Bottom@3,475' 3,512' Baker 5" x 7" HMC Liner Hanger 4,567' 2-3/8" Liner Top w/ 3.70" Deploy Sleeve 4,684' Baker HMCV Cementing Valve 4,70 1Baker CFC 20' PZP ECP WELL INCLINATION DETAIL KOP @ 1,500MD Max Hole Angle = 26 deg @ 2,500' MD Hole Angle through Pert = 20 deg OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 500 sx Permafrost 'C' in 30" hole 9-5/8" Cmt w/ 1,145 sx Permafrost'E' in 12-1/4" Hole 7" Cmt w/ 293 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sx Class'G' in 6-118" Hole TREE & WELLHEAD INFO Tree ------------- WKM 2-9/16" SM Wellhead 11" x 11" SM Tubing Spool, 11" x 2-7/8" 8rd (Top & Bottom) WKM tbg. w/ 2.5"'H' BPV Profile >= 8,034' )= 7,905' GENERAL WELL INFO API: 50-029-22070-60-00 Drilled and Cased by Nabors 27E—12/15/1990 RWO/ Multiple Frac Packs — 4/4/1995 ESP Replacement by Nabors 4ES — 2/21/1997 S/T & Comp. Nabors 4ES &Completion—10/05/99 2" Latera135, Nabors $-ES & Nordic #3 — 5/27/2001 Replace ESP - Nabors 4ES — 8/20/2003 Replace ESP — Doyon 16 — 8/20/2003 Replace ESP - Doyon 16 — 4/24/2011 Created By: STP 7/27/2015 EXHIBIT 7 Page 6 of 12 Milne Point 2015 ASR Rig 1 ►�,� ��� ���}�� ►►►. Knight Oil Tools BOP I V BOPE 7/8 -5 variables ind es Updated 7/23/15 EXHIBIT 7 Page 7 of 12 • EXHIBIT 7 Page 8 of 12 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Plug PerforationsEl Fracture StimulateEl Pull Tubing 1A Operations shutdown Performed: Suspend ElPerforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑✓ Re-enter Susp Well ❑ Other: ESP Change -out ❑� 2. Operator Name: 4. Well Class Before Work: 5. Permit to Drill Number: Hilcorp Alaska, LLC Development Q Exploratory ❑ Stratigraphic ❑ Service ❑ 199-111 3. Address: 6. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 50-029-22070-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0315848 MILNE PT UNIT SB J-01A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): NIA Milne Point Field / Schrader Bluff Oil Pool 11. Present Well Condition Summary: Total Depth measured 8,034 feet Plugs measured NIA feet true vertical 4,141 feet Junk measured N/A feet Effective Depth measured 7,135 feet Packer measured NIA feet true vertical 4,108 feet true vertical NIA feet Casing Length Size MD TVD Burst Collapse Conductor 105, 13-5/8" 105, 105' 2,730psi 1,130psi Surface 2,409' 9-5/8" 2,409' 2,346' 3,520ps1 2,020psi Production 3,640' 7" 3,640' 3,502' 7,240psi 5,410psi Slotted Liner 3,623' 4-112" 7,135' 4,154' N/A NIA Slotted Liner 3,142' 2-3/8" 7,709' 4,161' N/A NIA Perforation depth Measured depth See Attached Schematic feet True Vertical depth See Attached Schematic feet Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5#/ L-801 EUE 8rd 3,496' 3,368' Packers and SSSV (type, measured and true vertical depth) N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: NIA 13 Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbi Casing Pressure I Tubing Pressure Prior to well operation: 19 54 54 300 1 223 Subsequent to operation: 59 0 103 340 1 226 14. Attachments (required per20 AAC 25.07Q 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations Q Exploratory❑ Development0 Service ❑ Stratigraphic ❑ 16, Well Status after work: Oil ❑✓ Gas WDSPL Copies of Logs and Surveys Run ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 315-459 Contact Stan Porhola Email sporholaphilcorp.com Printed Name Stan Porhola Title Operations Engineer Signature Phone 777-8412 Date 10/3012015 Form 10-404 Revised 512015 Submit Original Only EXHIBIT 7 Page 9 of 12 Milne Point Unit Well: MPJ-01AL1 ACTUAL SCHEMATIC Last Completed:8/11/2015 MCorp Alaska, t,t.c PTD: 201-021 CASING DETAIL RKB Elev = 35' TD=7,950' (MD) /TD= 4,165'(TVD) PBTD= 7,950' (MD) / PBTD = 4,165'(ND) Size Type Wt/ Grade/ Conn Drift ID Top Btm 13-3/8" Conductor 954.5 / K-55 / Welded 12.615 Surface 105' 9-5/8" Surface 36 / K-55 / Btrc. 8.921 Surface 2,409' 7" Intermediate 26/L-80/BTC 6.276 Surface 3,640' 4-1/2" Slid Liner A 12.6 / L-80 / IBT 3.958 3,512' 7,135' 2-3/8" Slid Liner B N/A / L-80 / N/A I N/A 4,567 7,709 TUBING DETAIL _ Tubing 1 6.5 / L-80 / EUE 8rd 1 2.867 1 Surface 1 3,496'� JEWELRY DETAIL Depth Item 205' GLM 3,252' GLM 3,428' 2-7/8" XN Nipple, 2.2501D 3,440' Discharge Head — FPHVDIS 3,441' Pump Section —119-Flex 10 SXD 3,464' Gas Separator — GRSFTXAR H6 3,469' Tandem Seal Section - GSBDBUT SB/SB PFSA : GSBDBIT SB/SB PFSA 3,483' Motor—MSP3-250 84HP/2,210V/23A 3,491' 3/8" Stainless Steel External Capstring 3,491' Sensor XT-150 / Centralizer— Bottom@ 3,496' 3,51T Baker 5" x 7" HMC Liner Hanger 41567' 2-3/8" Liner Top w/ 3.70" Deploy Sleeve 4,682' Baker HMCV Cementing Valve 4,704' Baker CTC 20' PZP ECP WELL INCLINATION DETAIL KOP @ 1,500' MD Max Hole Angle = 26 deg @ 2,500' MD Hole Angle through Perf = 20 deg OPEN HOLE / CEMENT DETAIL 133/8"" Cmt w/ 500 sx Permafrost'C' in 30" hole 9-5/8" Cmt w/ 1,145 sx Permafrost'E' in 12-1/4" Hole 7" Cmt w/ 293 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 97 sx Class'G' in 6-1/8" Hole TREE & WELLHEAD INFO Tree WKM 2-9/16" 5M Wellhead 11" x IV 5M Tubing Spool, 11" x 2-7/8" 8rd (Top & Bottom) WKIVI tb . w/ 2.5''H' BPV Profile )= 9,034' )= 7,905' GENERAL WELL INFO API:50-029-22070-60-00 Drilled and Cased by Nabors 27E—12/15/1990 RWO/ Multiple Frac Packs-4/4/1995 ESP Replacement by Nabors 4ES — 2/21/1997 S/T & Comp. Nabors 4ES &Completion—10/05/99 2" Lateral 3S, Nabors $-ES & Nordic #3 — 5/27/2001 Replace ESP - Nabors 4ES—8/20/2003 Replace ESP — Doyon 16 — 8/20/2003 Replace ESP -Doyon 16-4/24/2011 Created By:STP 10/29/2015 EXHIBIT 7 Page 10 of 12 • Hilcorp Alaska, LLC IfilcurloAlaska, LU: Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date MPJ-01A 50-029-22070-01-00 199-111 7/16/2015 8/12/2015 Daily Operations: 8/5/15 - Wednesday MIRU ASR #1. 8/6/15 -Thursday PJSM Continue moving ASR and kill tank. PJSM Blow down well SICP 250 psi SITP 600 psi. RU LRS PT lines line up to reverse circ. Pump 150" Seawater 8.5 ppg 30 bbls down annuluus to catch fluid. 51 bbls gone. Caught circulation 1st tbg volume — 20 bbls all water, turned to oil. Continue pumping 80 bbls until oil returns clean@ 4BPM with 50-60% losses. Pump additional 20 bbls to clean pipe and cable. Annulus on vacuum. Light blow on tubing. Pump 5 BBIs down tubing. New gas system arrived, begin installation and continue RU of ASR. Total pumped 175 bbls total recovery 65 bbls, est oil recovery 50%. RD LRS install BPV. ND Tree NU BOPE. Spot Mud boat, Rig and Tank. Raise Derrick. Run all pump lines and hydraulic hoses. Lower floor to slip height, install containment. AOGCC rep Johnnie Hill on location. Arrival of Total Safety hands. MPU electricians on sight to plan Gas Monitor System installation. Continuing BOPE test, Function test BOPS. Install stairs. RU LRS. PT all lines. Prepare to BOP Test. Test BOPE 250/3,000 psi. Continue alarm system install and calibration. Test all Alarms Low and Hi limits. All audio and visual good. AOGCC concurs. Release Total safety technicians. Techs to Train Electricians before return to ANC. 8/7/15 - Friday PJSM complete BOPE Test. RD LRS test unit. OK on test by Johnnie Hill AOGCC. PJSM intoduction to ESP recovery, assign duties, goals, discuss hazards. Remove TWC well on Vac. RU floor for ESP and Cap recovery, Hang sheave w/snorkel for containment PJSM pre pull. BOLDS. PU to 30 K and pull completion to rig floor. Pump 20 bbls down annulus, decomplete Hanger. Thread spooler snakes for CAP and ESP. Crew change. PJSM and handover individual positions and teams and training. POOH w 2-7/8" ESP Cap completion. 16 jts /base line 6.5 jph. Also recovered 1st GLM. BOLD top pup and XN Top of pump shows no sand or solids. Continue POOH to top of pump 90 jts and 1 GLM recovered average speed - 15 jph. BOLD pump assy. 2 bad jts LD from thread damage. Pump failure identifies snap rig off of spacer bushings (Pies to S. porhola) to drive assembly. Motor spins free was not being engaged. Off Load ESP gear ready floor for running cleanout. MU 2-7/8" Mule shoe 't 22,10'. RIH w 2-7/8" L-80 to clean out to TOL, 8/8/15 - Saturday PJSM continue RIH w 2-7/8" muleshoe and 110 jts 2-7/8" L-80. Tag up 24' in on jt 110 at 3,507'. Halliburton N2 on location 1000 hrs. Order swivel sub for top drive and Mill and bootbasket. Wait on same, rig service. Work/rock pipe and muleshoe rig cannot spud or rotate in this position. Rig up to reverse circulate 8.S ppg SW. Pump 24 bbls caught returns at 33 bbls pump failure. MU x-overs. Swivel still at factory settings reset recalibrate. Hook up to top drive , reset torque values. PU 22K SW rotating 27 RPM pass through liner top. (Completion depth 3,S12') Rig measured depth 3,507'. Tagged up again 3,529'. Hook up to swivel again. Continue in hole liner top an issue with most all tool jts. Tag fill @ 3,970'. 6K over to pull free. PU is 22K. Wait on LRS Pump Truck. Begin pumping 2 bpm @ 340 psi gained circulation. Increase to 3 bpm 500-800 psi returns fluctuating solids heavy gravel and some sand. 88 bbl in/ 78 bbls out 9% losses 10% oil. Depth is 3983'. Let well equalize. U tubing oil. Pump 1 tubing volume 20 bbls. Make connection wash down to 4015' again heavy particle trash and O/W 58 in /50 out. Work to — 4,018' will not wash off and muleshoe light rotation no progress. Pump 20 bbls down annulus, 20 bbls down tbg. Hole is standing full. Open annular. Check flow. Break Swivel. POOH LD 2- 7/8". EXHIBIT 7 Page 11 of 12 • Hilcorp Alaska, LLC tfikeorpAtnsk,,,1.IA: Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date MPJ-01A 50-029-22070-01-00 199-111 7/16/2015 8/12/2015 8/9/15 - Sunday PJSM and resume TOOK LD muleshoe. No liner top evidence on shoe but there is evidence and scarring on the downhole side of the tubing collars. Clean up rig floor, repair tong hose, prepare for conventional circ, spot cuttings tank, send 290 bbls O/W mix to B-50. MU BHA with 4-1/8" mill. Repair leak on Hydraulic system. PJSM crew change, detailed plans on fluid/N2/ losses. RIH with singles off rack to 3490'. POOH LD singles. Mill looks OK light groove on OD. LD jt 112 bad pin. MU JT 111 to swivel, work down to TOL. Walked in with light rotation after tag. Work/clean up liner to bottom of extension @ 3,521'. Circ 1.5 x hole volume. B/O swivel. Pull Stripping rubber. PU new 3.6" BN and 3.5" bootbasket. TOAL 4.65' RIH to 3,490'. Install Stripping head rubber. 8/10/15 - Monday PJSM continue fill DEF and resume RIH through TOL @ 3,507'. Top of liner in good shape. Continue in hole. Swivel up on jt 127. Tag sand @— 4,000'. Rig up to circ, change stripping rubber. PJSM Ref: Ann 106 bbls Tbg 25 bbl Halliburton N2 is preheated. LRS Is tied in for pump. Broke fitting on slips trying to B/O single repair same. Losses steadily increasing. Pump rate reduced to 2 bpm @ —200 psi w spikes to 600psi through bridges on sand plugs. Continue Mill and circ ops. Begin washing down 2 BPM 200 psi 3 bpm @ 500psi connection times start @ 23 minutes. Saver Sub MU is difficult. 4,059' broke thru bridge total loss for short period, slow down rate circ regain. Returns averaging 25 bbls losses per connection. Depth is 4,123'. Circ 30 minutes. Attempt to run a joint without swivel no go. PJSM Crew Change. Resume operations @ 4,281'- 4,409' getting sticky fluctate rate 1-3 BPM and work pipe. Broke through total losses could not regain circulation. BOLD single. Total losses for clean out — 350 bbis SW. RU N2. PJSM PT all lines to 3,500psi. PUMP 100,000 SCF @ 1,000 scfm and 1.25 bpm—1,600psi. Good returns after 16,000 SCF. Plentiful fine sand mix w oil/water. Clean returns for 20 minutes. FCP 1,400psi. Fluid Pumped 125 bbl SW. Recovered 227 bbls. BOLD milling assy. Sort Floor to Assemble ESP. RD N2 and release. Blow down annulus. Pump 130 bbl SW, started losses after 110 bbls. Rig down pump lines and pump in sub. POOH with cleanout assembly and LD 2-7/8" L-80. 8/11/15 - Tuesday PJSM Crew Change. Rig up for ESP RIH w 2-7/8" L-80 EUE production. Final depth and BHA are centralizer bottom @ 3,496'. Sensor sub 3,491', Motor 3,460, Tandem seals 3,469', Gas separator 3,463', Pump 3,440', XN 2.251D @ 3,428', 5 jts tbg GLM (blank) 3,252', 95 jts tbg, GLM (orificed) 205'. 5 jts tbg. PJSM Install hanger and 4' pup. All depths are 35' Original KB adjusted. Build ESP spice install and check same. Issue Hot work Permit and Meg Check ESP cable. Land Hanger. PU weight 29K. SO 22.3 K. RILD LD landing jt. Install BPV. Rig Down ASR 1. 8/12/15 - Wednesday ND BOPS NU Tree and test 250/5,000 psi RDMO turn well to production. EXHIBIT 7 Page 12 of 12 • is THE STATE °fI-I — — GOVERNOR BILL WALKER Stan Porhola Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 95503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU SB J-08A Sundry Number: 315-527 Dear Mr. Porhola: 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 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. foerster Chair DATED this :J &day of August, 2015 Encl. EXHIBIT 8 Page 1 of 15 • STATE OF ALASKA AU6 2 7 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCG 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing 0 Change Approved Plan Q Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Fill Clean -out 0 Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑Q Re-enter Susp Well ❑ Other. ESP Change -out 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Hiicorp Alaska, LLC Exploratory ❑ Development Stratigraphic ❑ Service ❑ 199-117 3. Address: 6. API Number. 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 50-029-22497-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 Will planned perforations require a spacing exception? Yes ❑ No MILNE PT UNIT SB J-08A 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0025515 I MILNE POINT / SCHRADER BLUFF OIL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 8,495 4.107 8,495 4,107 NIA N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 112' 13-3/8" 112' 112' 3,730psi 1,130psi Surface 2,516' 9-5/8" 2,516' 2,476' 5,750psi 3,090psi Production 4,866' 7" 4,866' 3,850' 7,240psi 5,410psi Liner 3,766' 4-1/2" 8,495' 4,107' 8,430psl 7,500ps1 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-7/8" 6.5# / L-80 / EUE 8rd 4,687 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (it): ZXP Liner Top Packer and N/A 4,714 MD / 3,810 TVD and NIA 12. Attachments: Description Summary of Proposal ❑� 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: 9/15/2015 OIL Q WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: N/A Commission Representative: N/A GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing Is true and correct to the best of my knowledge. Contact Stan Porhola Email s orhola hilcor .com Printed Name Stan Porhola Title Operations Engineer l / Signature Phone 777-8412 Date 812612015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 \ C7 S 2_1 Plug Integrity ❑ BOP Test [if Mechanical Integrity Test ❑ Location Clearance ❑ Other: f �G,L?v pc'�1�5f' r �77 S. �� Spacing Exception Required? Yes ❑ No Subsequent Form Required: `% C>it APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: D ry� T Submit Form and Form 10.403 Revised 5/2015 p .,{(�_�ap I eN0 lir r 12 months from the date of approval. Attachments in Duplicate EXHIBIT 8 Page 2 of 15 • • Well Prognosis Well: MPU J-08A Date:8/26/2015 Well Name: MPU J-08A API Number: 50-029-22497-01 Current Status: _ SI Oil Well [ESP] Pad: J-Pad Estimated Start Date: September 15'h, 2015 Rig: ASR #1 Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 199-117 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Paul Chan (907) 777-8333 (0) (907) 444-2881 (M) AFE Number: Current Bottom Hole Pressure: 1,717 psi @ 4,000' TVD (Last BHP measured 11/11/2013) Maximum Expected BHP: 1,717 psi @ 4,000' TVD (No new perfs being added) Max. Allowable Surf Pressure: 177 psi (Based on SBHP taken 11/11/2013 and water cut of 50% (0.385psi/ft) with an added safety factor of 1,000' TVD of oil cap) Brief Well Summary: The Milne Point 1-08A well was redrilled as a Schrader Bluff development well that TD'd at 8,495' and ran a slotted 4-1/2" liner in December 1999. The well was initially completed with an ESP in December 1999. This ESP failed and was replaced in 2007. The recent pump failed June 15, 2015 during a restart, following recent TAPS proration. The most recent casing pressure test performed prior to sidetracking the well was in 1999. A casing pressure test to 1,500 psi was completed in July 2015 during a recent ESP change -out with Nordic #3. No subsidence issues are expected in this well. Notes Regarding Wellbore Condition • Casing last tested to 1,500 psi for 30 min down to 4,700' MD on 7/04/2015. Obiective: The purpose of this work/sundry is to pull the existing failed ESP and run a new ESP. Brief Procedure: WO Rig Procedure: 1. Circulate well with 8.5 ppg seawater down tubing and fill casing. 2. RU crane. Set BPV. ND Tree. NU 11" BOPE. 3. MIRU Hilcorp ASR #1 WO Rig. 4. Test to 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 2,500 psi High (hold each valve and test for 5-min). Record accumulator pre -charge pressures and chart tests. a. Notify AOGCC 24 hrs in advance of BOP test. b. Test VBR rams on 2-7/8" test joint. 5. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. b. With stack out of the test path, test choke manifold per standard procedure EXHIBIT 8 Page 3 of 15 Well Prognosis Well: MPU 1-08A Ilileorp Alaska, LL Date' 8/26/2015 c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. g. Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 6. If a rolling test was conducted, rernove the old hanger, MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test ROPE per standard procedure. 7. Bleed any pressure off tubing and casing. Pull BPV. 8. MU landing joint (2-7/8" EUE 8RD hanger thread) and pull over string weight (previous rig string weight 30k UWT with Nordic #3 does not include block weight of 23K) on tubing haner to confirm free. ` �., rr % 4,6a-' 3/ k 9. POOH. Lay 2-7/8" tubing on the pipe rack (utilize as workstring). (A,. w+ } a. Drift ID of 2-7/8" tubing is 2.347". 10. MU 6-1/8" bit and junk baskets. 11. RIH w/ 2-7/8" tubing to liner top packer +/- 4,714' MD. 12. POOH. Lay down bit and junk baskets. Lay down 2-7/8" tubing. 13. MU 3-3/4" mill and junk baskets. 14. RIH w/ 2-3/8" workstring to liner top packer +/- 4,714' MD. 15. Cleanout fill inside screens down to PBTD +/- 8,450' MD. a. Min ID is 3.844" at Indicator Subs at +/- 5,768' and 5,787' MD. b. Drift ID of liner is 3.833". 16. Circulate bottoms up x 2 with 8.5 ppg seawater. 17. POOH. Lay down mill and junk baskets. Lay down 2-3/8" workstring. 18. PU new 475 series ESP and RIH with new 2-7/8" 8RD EUE L-80 tubing. 19. Set base of ESP at +/-4,700' MD (Pump intake around +/- 4,660' MD). Land tubing hanger. a. Re -run 3/8" control line w/ clamps down to pump gauge centralizer. b. Re -run heat trace to +/- 3,000' MD. 20. Lay down landing joint. Set BPV. ND BOPE. NU existing 3-1/8" 5,000# tree. Pull BPV. 21. Set TWC. Test tubing hanger to 250/5,000 psi. Test tree to 250/5,000 psi. Pull TWC. 22. RD Hilcorp ASR #1 WO Rig. 23. Replace IA x OA pressure gauge if removed (7" x 9-5/8"). 24. Turn well over to production. Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOPE Schematic EXHIBIT 8 Page 4 of 15 Milne Point Unit Well: MPU J-08A SCHEMATIC Last Completed: 7/5/2015 ua�•, �„ Al—ku, I'm: PTD: 199-117 CASING DETAIL Orig. KB Elev.: 65.2 / GL Elev.: 35.7' (N22E) TD = 8,495' (MD) / TD = 4,107(TVD) PBTD = 8,495' (MO) / PBTD= 4,107'(TVD) Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8" Conductor 54.5 / L-80 / N/A 12.615 0 112' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 0 2,516' 7" Intermediate 26 / L-80 / Btrc 6.276 0 4,866' 4-1/2" Liner 12.6 / L-80 / IBT 3.958 4,729' 5,901' 4-1/2" Slotted Liner 6.2 / L-80 / SLT 3.958 5,901' 8,451' TUBING DETAIL 2-7/8" 1 Tubing 1 6.5 / L-80 / EUE 8rd 1 2.441 1 0 1 4,687' JEWELRY DETAIL No Depth Item 1 178' GLM 2 4,491' GLM 3 4,634' 2-7/8" XN Nipple 2.313 ID: 2.205 no-go 4 4,645' Discharge Head 5 4,646 Pump 6 4,656' Gas Separator 7 4,661' Upper Tandem Seal Section 8 4,668' Lower Tandem Seal Section 9 4,680' Motor 10 4,689' 3/8" External Capillwy String 11 4,689' Pumpmate & Centralizer/Downhole Gauge: Bottom @ 4,687' 12 4,714' Baker ZXP Liner Top Packer w/ 6' Tie Back (5.25" ID) 13 4,729' Baker 5" x 7" HMC Liner Hanger (4.375" ID) 14 5,776' HMCV Cement Valve 15 5,794' _Baker Baker CTC 20' PZP ECP 16 8,451' 4.5" Baker Drillable Pack -off Bushing 17 8,495' 4.5" Baker Drillable Guide Shoe WELL INCLINATION DETAIL KOP @ 1,500' MaxHole Angle = Horizontal OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 250 sx of Arcticset I in 24" Hole 9-5/8" Cmt w/ 504sx PF "E", 250 sx Class "G" in 12-1/4" Hole 7" Cmt w/ 220 sx Class "G" In 8-1/2" Hole 4-1/2" Cmt w/ 84 sks Class "G" in 6-1/8" Hole TREE & WELLHEAD Tree 3-1/8"C05M WKM 11" x 11" 5M, WKM w/ 11" x 3.5" tubing hanger/ NSCT Wellhead threads top and bottom and 3" CIW H PBV Profile GENERAL WELL INFO API:50-029-22497-01-00 - Sidetracked & Completed by Nabors_22E - 12/29/1999 Recom letion—1/28/2000 Schrader Bluff Recompletion by Nabors 4ES — 4/19/1997 ESP Replacement byNabors 3S — 2/11/2007 Revised By: STP 8/19/2015 EXHIBIT 8 Page 5 of 15 Milne Point Unit Well: MPU J-08A PROPOSED Last Completed: 7/5/2015 Ililcoep Alaska, 1AX PTD: 199-117 CASING DETAIL Orig. KB Elev.: 65.2'/ GL Elev.: 35.7' (N22E) TD= 8,495' (MD) / TD = 4,107(TVD) PBTD = 8,495'(MD) / PBTD=4,107'(TVD) Type Wt/ Grade/ Conn ID Top Btm Conductor 54.5 / L-80 / N/A 12.615 0 112' V42 Surface 40 / L-80 / Btrc. 8.835 0 2,516' Intermediate 26/L-80/Btrc 6.276 0 4,866' Liner 12.6 / L-80 / IBT 3.958 4,729' 5,901' Slotted Llner 6.2 / L-80 / SILT 3.958 1 5,901' 8,4S1' TUBING DETAIL 2-7/8" 1 Tubing 1 6.5 / L-80 / EUE 8rd 1 2.441 1 0 ±4,68T JEWELRY DETAIL No Depth Item 1 ±178' GLM 2 ±4,491' GLM 3 ±4,634' 2-7/8" XN Nipple — 2.31310: 2.205 no-go 4 ±4,645' Discharge Head 5 ±4,646' Pump 6 ±4,656' Gas Separator 7 ±4,661' Upper Tandem Seal Section 8 ±4,668' Lower Tandem Seal Section 9 ±4,680' Motor 10 ±4,689' 3/8" External Capillary String 11 ±4,689' Pumpmate & Centralizer/Oownhole Gauge: Bottom @ ±4,687' 12 4,714' Baker ZXP Liner Top Packer w/ 6' Tie Back (5.25" ID) 13 4,729' Baker 5" x 7" HMC Liner Hanger (4.375" ID) 14 5,776' Baker HMCV Cement Valve 15 5,794' Baker CTC 20' PZP ECP 16 8,451' 4.5" Baker Drillable Pack -off Bushing 17 8,495' 4.5" Baker Drillable Guide Shoe WELL INCLINATION DETAIL KOP @ 1,500' MaxHole Angle = Horizontal OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 250 sx of Arcticset I In 24" Hole 9 5/8" Cmt w/ 504sx PE "E", 250 sx Class "G" in 12-1/4" Hole 7" Cmt w/ 220 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 84 sks Class "G" in 6-1/8" Hole TREE & WELLHEAD Tree 5M 3-1/8" CIW SM 3-KM 11" x SM, WKM w/ 11" x 3.5" tubing hanger/ NSCT Wellhead threads top and bottom and 3" CIW H PBV Profile GENERAL WELL INFO API: 50-029 -2 2497-01- 00 Sidetracked & Completed by Nabors 22E - 12/29/1999 Recompletion—1/28/2000 -- Schrader Bluff Recompletion by Nabors 4ES — 4/19/1997 ESP Replacement bNabors 3S — 2/11/2007 Revised By: STIR 8/19/2015 EXHIBIT 8 Page 6 of 15 Milne Point 2015 ASR Rig 1 Knight Oil Tools BOP 11" BOPE 7/8 -5 variables ind Updated 8/19/15 EXHIBIT 8 Page 7 of 15 • EXHIBIT 8 Page 8 of 15 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Ll Plug Perforations L1 Fracture Stimulate Ll Pull Tubing H Operations shutdown Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program n Plug for Redrill ❑ erforate New Pool ❑ Repair Well E Re-enter Susp Well ❑ Other: ESP Change -out E 2. Operator Name: 4. Well Class Before Work: 5. Permit to Drill Number: Hilcorp Alaska, LLC Development Q Exploratory ❑ Stratigraphic ❑ Service ❑ 199-117 3. Address: 6. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99603 50-029-22497-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0025515 MILNE PT UNIT SB J-08A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A MILNE POINT / SCHRADER BLUFF OIL 11. Present Well Condition Summary: Total Depth measured 8,495 feet Plugs measured N/A feet true vertical 4,107 feet Junk measured N/A feet Effective Depth measured 8,495 feet Packer measured 4,714 feet true vertical 4,107 feet true vertical 3,810 feet Casing Length Size MD TVD Burst Collapse Conductor 112' 13-318" 112' 112' 3,730psi 1,130psi Surface 2,516' 9-5/8" 2,516' 2,476' 5,750psi 3,090psi Production 4,866' 7" 4,866' 3,850' 7,240psi 5,410psi Liner 3,766' 4-1/2" 8,495' 4,107' 8,430psi 7,500psi Perforation depth Measured depth See Attached Schematic feet True Vertical depth See Attached Schematic feet Tubing (size, grade, measured and true vertical depth) 2-7/8" 6.5# / L-80 / EUE 8rd 4,602' 3,776' Packers and SSSV (type, measured and true vertical depth) ZXP Liner Top N/A 4,714'MD / 3,810'TVD N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 350 224 Subsequent to operation. 58 0 523 230 225 14. Attachments (required per 20 AAc 25.070, 25.071, a 25.283) 15. Well Class after work: Daily Report of Well Operations 21 Exploratory❑ Development 0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ✓ Gas U WDSPL Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 315-527 Contact Stan Porhola Email sporhola(Whilcoracom Printed Name Stan Porhola Title Operations Engineer Signature Phone 777-8412 Date 10119/2015 Form 10-404 Revised 5/2015 Submit Original Only EXHIBIT 8 Page 9 of 15 • • Orig. KB Elev.: 651/ GL Elev.: 35.7 (N22E) TD=8,495' (MD) /TD=4,107'(TVD) PBTD = 8,495' (MD) / PBTD = 4,107'(ND) SCHEMATIC CASING DETAIL Milne Point Unit Well: MPU J-08A Last Completed: 10/3/2015 PTD:199-117 Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8" Conductor 54.5 / L-80 / N/A 12.615 0 112' 9-5/8" Surface 40 / L-80 / Btrc. 8.835 0 2,516' 7" Intermediate 26 / L-80 / Btrc 6.276 0 4,866' 4-1/2" Liner 12.6 / L-80 / IBT 3.958 4,729' 5,901, 4-1/2" Slotted Liner 6.2 / L-80 / SLT 1 3.958 5,901' 8,451' TUBING DETAIL 2-7/8" 1 Tubing 1 6.5 / L-80 / EUE Srd 1 2.441 1 0 1 4,602' JEWELRY DETAIL No Depth Item 1 174' GLM 2 4,395' GLM 3 4,537' 2-7/8" XN Nipple — 2.313 ID: 2,205 no-go 4 4,548.7' Discharge Head 5 4,549' Pump 6 4,573' Gas Separator 7 4,578' Upper Tandem Seal Section 8 4,585' Lower Tandem Seal Section 9 4,592' Motor 10 4,600' Centralizer/Downhole Gauge: Bottom @ 4,602' 11 4,714' Baker ZXP Liner Top Packer w/ 6' Tie Back 5.25" ID) 12 4,729' Baker 5" x 7" HMC Liner Hanger 4.375" ID) 13 5,776' Baker HMCV Cement Valve 14 5,794' Baker CTC 20' PZP ECP 15 8,451' 4.5" Baker Drillable Pack -off Bushing 16 8,495' 4.5" Baker Drillable Guide Shoe WELL INCLINATION DETAIL KOP @ 1,500' MaxHole Angle = Horizontal OPEN HOLE / CEMENT DETAIL 13-3/8"" Cmt w/ 250 sx of Arcticset I in 24" Hole 9-5/8" Cmt w/ 504sx PF "E", 250 sx Class "G" in 12-1/4" Hole 7" Cmt w/ 220 sx Class "G" in 8-1/2" Hole 4-1/2" Cmt w/ 84 sks Class "G" in 6-1/8" Hole TREE & WELLHEAD Tree 3-1/8" CIW SM 5M Wellhead WKM 11" x SM, WKM w/ 11" x 3.5" tubing hanger/ NSCT 1 threads top and bottom and 3" CIW H PBV Profile GENERAL WELL INFO API:50-029-22497-01-00 Sidetracked & Completed by Nabors 22E-12/29/1999 Recom letion—1/28/2000 Schrader Bluff Recom letion by Nabors 4ES—4/19/1997 ESP Replacement by Nabors 35 — 2/11/2007 ESP Change -out by Nordic #3 — 7/5/2015 ESP Change -out by ASR 41-10/3/2015 Revised By: TOF 10/20/2015 EXHIBIT 8 Page 10 of 15 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date MP J-09A 50-029-22495-01-00 199-114 9/13/2015 10/3/2015 Daily Operations: 9/9/15 - Wednesday No operations to report. 9/10/15 - Thursday No operations to report. 9/11/15 - Friday No operations to report. 9/12/15 - Saturday MIRU Coil Unit. 9/13/15 - Sunday PJSM. Raised lubricator and BOP's. Connected BOPE hoses. LD flow cross off lubricator, made up 5k to 10k xo spool and 10k to 15k xo spool. RU 50bbl freeze protect tank to CT pump. Stabbed injector head onto riser, RU riser wellhead and secured. Offloaded 40bbis of 60/40. Pumped 35 bbls of 60/40 and broke circulation. SD Pump. Lined valves to perform full body Test. Performed shell test 250-3,500psi-test ok. Performed BOPE per AOGCC Reg: Valves 250-3,500psi, Rams 250 3,500psi, Blinds 250-3,500psi and held for 5 mins. Performed drawdown- 0 failures recorded. LD lubricator and injector head SDFN, 9/14/15 - Monday PJSM and discuss job to be performed. ND night ACID, MU injector to lubricator and PU off mass truck. MU CT connector and pull tested to 20k-Test Good. RD lubricator and injector head to BOP's, PT 4,OOOpsi- test good. Circulated 35 bbls of 60/40 of freeze protect out of the coil to the 50bbl open top tank. Opened SSV with fuseable cap, pressured up coil to 500psi and opened well. SITP Opsi. RIH at 50 fpm, rolled over pump. 5bpm at 500'. Continued in hole and tagged pump @ 4,998 CTM, pumped bottoms -up, returns crude, PW and trace of sand. PU 20' then RIH and comfirmed tag at 4,998'CTM. Lost curculation. PU CT 50' and parked. Started ESP and monitored well, no returns or BHP decrease. SD ESP pump. SI the choke and tried pressuring up the the production tubing with no luck. Confirmed shear valve was ruptured. Open choke back up and POOH with CT. RDMO CT Unit and associated equipment. 9/15/15 - Tuesday MIRU CTU on 1-08. EXHIBIT 8 Page 11 of 15 • Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date JEnd Date MP J-08A 50-029-22497-00-00 199-117 9/16/2015 10/3/2015 Daily Operations: 9/16/15 - Wednesday Held PJSM. Finish RU, PU/MU Injector Head and Lubricator and BOP's. Circulated 60/40 thru coil and lines. Performed Body Test 250-3,500psi. Test ok. Test ROPE as follows: Valves 250-3,500psi, Rams 250-3,500psi, Blinds 250-3,500psi. Function and drawdown. No failures recorded. MU 1-11/16" washout BHA and RIH. Kicked pump in 1.5bpm at 500'. Conitinued in hole to 3,300' with min returns. 40bbls in 2bbls out. With no returns, Discuss plan with Anchorage, continued RIH pumping .4bpm and tagged the Discharged Head at 4,651. Increased rate to lbpm pumped away 10 bbls back flushing thru ESP. 140 bbis pumped, 8bbls returned. POOH pumping 20 bbls 60/40 freeze protestion. Blow lubricator and lines dry. L/D Injectorhead, Lubricator and BOP's. Secured well and SDFN. 9/17/15 - Thursday No operations to report. 9/18/15 - Friday No operations to report. 9/19/15 - Saturday No operations to report. 9/20/15 - Sunday No operations to report. 9/21/15 - Monday Demob and disconnect. Psi test surface lines 1,000 psi, SITP 100 psi, SICP 250 psi, Blow down well, Reverse circulate 190 bbl 8.5# hot sea water. Pump 30 bbl hot sea water down tbg 68 bbl heavy oil and water return, 84 bbl lost. 9/22/15 - Tuesday Pending Report. EXHIBIT 8 Page 12 of 15 Hilcorp Alaska, LLC , �; Weekly Operations Summary ,,;,,.,,,.,, r,,,,„k,, , Well Name JAPI Number lWell Permit Number IStart Date I End Date M P 1-08A 50-029-22497-00-00 199-117 9/16/2015 10/3/2015 Daily Operations: 9/23/15 - Wednesday PJSM, Continue RU prepare for BOP test. BOPE test waived by John Crisp 0530 AM by E-mail. PJSM, Test all lines 3,500psi, Test gas detectors Test BOPE, 250/3,000psi, Annular 250/2,500psi. Accumulator draw down test, offload 225 8.5# 150' sea water. PJSM, Pump 42 bbl down csg, 150°F sea water, pump 11 bbl down tbg caught psi, hang sheaves, Pick up landing jt, BO lock downs & pull hanger SW 43K. PJSM, BO landing jt & hanger, POOH, w/ESP, heat trace, and cap. Continue POOH through end of heat trace continue POOH to -450'. 9/24/15 - Thursday PJSM. Continue POOH 11 jts BO/LD ESP motor and pump assy. Close Blind rams LD Baker equipment. Organize floor for standard tubing operations rack 109 jts 2-3/8" PH-6 5.7# P-110 , 1 mule shoe 30.24, x-over to 2-7/8" eue 1.45'. Pu MU 2- 3/8" PH6 Mule shoe RIH w 65jts 2-3/8" PH-6 5.7# P-110, 1 mules shoe and 109 jts 3,395.10' -. Change out floor hardware to 2-7/8". PJSM Continue RIH w 2-7/8" to TOL of 4,716' TMD. RIH to 6,567' PU SO change +/- 5K. Repeat 4 times check drag. Cannot interpret load cell weight indicator. RU pump lines to reverse circ. Pump 9 bbl catch fluid 48 bbl get returns oil, pump 42 bbis cleaned up after 20 bbis total pumped 100 bbis. 28 recovered losses at 70%. Blow down/drain up PU single make connection cannot go any further. LD single rig up to circulate non rotating connection. PJSM RU to reverse circ. previous circ was conventional. Catch pressure at 21 bbls attempt to work down tag is solid@ 6,567'. Pump total 33 bbis 3 BPM at 600 psi. No returns obstruction not washing off. LD 2 singles depth of muleshoe is 6,535'. RU Halliburton N2 to pump down annulus, returns plumbed to pigging tank, JSA P/T all lines to 3,500 psi. Mix 2 drums Baraklean w/ seawater 8.5 ppg temp 100"F. Initial pump rate .5 bpm /500 scf work to 1.25bpm/1500 scf @ —1,300psi pump 1.75 hrs, heavy sand returns, develop leak in downstream connections, SD/SI ops, 107.6 bbls/ 113 mscf away, repair down 27 minutes SITP "'1,150psi. Resume ops 1.25bpm/1000scf @ "'1,200psi. Off loading seawater, pump total 200 mcsf 207 bbis seawater chase w 50 bbis seawater. Total 4.5" clean is 1,800' total slotted liner clean is 634'. 9/25/15 - Friday PJSM. Blow down N2 pressure. 227 bbis recovered. Tubing light blow annulus at 300psi. Open annulus bleed down. Line up to pump 50 bbls down annulus, after 4 bbis casing pressure climbed to 1,100 psi. Shut down pump begin to bleed off pressure. Pressure bleeding off slow. Discuss w/ pusher and proceed to evaluate. 0915 Operator met co man enroute to pits preceeded by pusher. Disoriented operator explained he had gotten dizzy and fell down stairs and that 2 other men on the pits were down but he had gotten 1 man out. Notified security an dispatched rescue and ambulance a 0915. Mud hopper door was opened from the outside and the pusher was rescued by superintendent and other crew mewbers. Rescue and ambulance medical team arrived and administered air/ firstaid as needed and all 3 individuals were taken to MPU medical center. Operator had shut in the well with the manual valves. Well is secured with annular, manual valves, & TIW. Operations suspended until further notice. Three personnel from incident have been released to work. SICP is 173 psi. 9/26/15 - Saturday Operations on standby. EXHIBIT 8 Page 13 of 15 • • Well is SI and rig is secured awaiting AOGCC permission to freeze protect well. Investigation continues- safety and Investigation team on location 0800. Break down unnecessary lines and organize location monitor well. AOGCC permission to Freeze protect well. Rig up lines to blow down well, bypassing all lines still in place from N2 operation. Bleed off trapped pressure in choke manifold " 100 psi. SITP 0 psi SICP 640 psi. Bleed off annulus pressure to light blow no fluid in returns. PJSM RU LRS PT lines Pump 65 bbis Freeze protect down 7" annulus. Annulus on vac. Close and lock pipe rams, open annular. Pump 20 bbls freeze protect down tubing tbg on vac. Secure TIW valve. 3 rig crew members working. break down all cellar lines, kill lines choke lines and drain up same to prevent freezing. drain up all lines to return tank. Perform housekeeping and RD halliburton pumping HP hose and hardline. Investigation continues Investigation team returns to site. Night crew resumes schedule. NO WELL WORK. Work on maintenaince and storage facilities. on erations on EXHIBIT 8 Page 14 of 15 Hilcorp Alaska, LLC Weekly Operations Summary Well Name 1API Number JWell Permit Number I Start Date I End Date M P 1-08A 50-029-22497-00-00 199-117 9/16/2015 10/3/2015 Dally Operations: 9/30/15 - Wednesday Approval from the AOGCC to resume operation. Held PJSM, MIRU LRS and tested to 3,000psi-test ok. Pumped 15bbls of 60/40 methanol down tbg broke circulation up the csg to the external 500bbis kill tank. With tbg under balanced with methanol bullheaded 20 bbls of seawater down tbg and monitored tbg on a vac. Resend BOPE test notice with estimated test time. Held PJSM with night crew. Notified by the state that no waiver will be given for Rig avitivties until BOPE test is completed. BO/LD TIW valve, MU/PU Landing Jt, Tbg Hanged with TWC installed and landed, secured hanged with LDS. Prep for BOPE Testing, Performed Shell Test, Function tested BOP's and gas detection system. Notified Inspector that we are ready to begin testing at 06:00. 10/1/15 -Thursday Held PJSM, Waited on State Inspector to arrive. Prep for BOP Test. Performed BOPE Testing with AOGCC Inspector Chuck Scheve as follows; Valves 250-3,000psi, Rams 250-3,000psi, Annular 250-2,500psi, Gas Detection and Accumulator drawdown test. 1 FP was recorded on C-12. PJSM, Pulled TWC MU landing jt and pulled hanger to rig floor BO/LD same. TOH/LD 149 jts of 2-7/8" 8rd 105 jts of 2-3/8" PH6 and mule shoe using charge pump to keep hole full. PU/MU and serviced new ESP assembly. String cable over sheave, made motor and cap connection. TIH w/new ESP on 2-7/8" 8rd Tbg with xn-nipple and lower GLM (dummy), continued RIH. 10/2/15 - Friday Held PJSM and walk through with change -out crew. Continued TIH with ESP completion. PU Heat Trace at 2,992'. PU top GLM continued TIH w/ ESP completion from Hanger depth, Top of Tool Depths as following: Hanger, Pup, 4 jts 2-7/8" L-80 6.54 tbg, pup, GLM @ 174', jts tbg, pup GLM @ 4,395', 4jts tbg, XN Nipple @ 4,537', Head @ 4,548', Pump @ 4,549', Gas Separator @ 4,572', Tandem Seals @ 4,577', Motor @ 4,591', Pumpmate @ 4,598', Centralizer @ 4,600', EOC @ 4,602'. Heat Trace Spool was 40' short of 3,000'. Made splice 2' jts down from hanger. Continued splice at report time. 10/3/15 - Saturday Held PJSM and walk thru with crew. Completed Heat Trace splice, Continued TIH w/ESP Completion. PU landing joint. Install hanger and penetrators. Test cable, Cut and splice cable connector install same. Meg check connector. Land string SW 43K up 41k down. Run in lock down screws. Set BPV. RDMO ASR 1 and associated equipment and stacked on A Pad. ND BOP's and NU Production Tree and tested-ok. Well transferred over to production. 10/4/15 - Sunday No operations to report. 10/5/15 - Monday No operations to report. 10/6/15 - Tuesday No operations to report. EXHIBIT 8 Page 15 of 15 • H %I-L.. MA PART 1: GENERAL INFORMATION NAME OF EMPLOYEE INVOLVED: ASR Rig Integrated Well Services Crew REGION: Alaska North Slope FIELD: Milne Point Unit COMPANY: Integrated Well Services POSITION TITLE: Operators (2) and Tool PusherSUPERVISOR: , Owner EMPLOYMENT STATUS: ❑P/T NF/T ❑TEMP CONTRACTOR GENDER: ®M OF TYPE OF INCIDENT: ®INJURY ❑ SPILL ❑ PROPERTY DAMAGE PART 2: DESCRIPTION OF INCIDENT DATE OF INCIDENT: 9/25/2015 TIME EMPLOYEE BEGAN WORK: 1X12:00 NA.M. and 2X06:00 NA.M. TIME OF INCIDENT: 09:12 NA.M. ❑P.M. ❑UNKNOWN DATE INVESTIGATION BEGAN: 9/25/2014 TIME INVESTIGATION BEGAN: 09:50 NA.M. ❑P.M. AMOUNT OF PROPERTY DAMAGE (IF ANY): N/A INCIDENT OCCURRED: ®INSIDE ❑OUTSIDE CONDITIONS (IF OUTSIDE): ❑CLEAR ❑RAINING ❑SNOWING ❑OTHER: Weather was mild. Temperature was 30 deg. Fahrenheit. JOB ACTIVITY AT TIME OF INCIDENT: Three Integrated Well Services Employees lost consciousness at approximately 9:12 am the morning of September 25th, 2015 while attempting to bleed pressure off the J-08 workstring by casing annulus. 1.) What happened at the time of the accident? Describe the sequence of events prior to, during and immediately after the accident (attach extra page if necessary): See attached timeline for a detailed sequence of the timing of events associated with this incident. The ASR rig was rigged up on the well. A nitrified cleanout had been completed in which nitrogen and seawater was circulated down the backside (annulus) with returns taken off the tubing/work string to an exteriorflow back tank. One 50 bbl seawater pill had been successfully pumped following the nitrogen treatment. Employees registered unexpected annulus pressure of just over 1,000 psig on a pressure gauge while beginning to pump the second 50 bbl seawater pill. Employees shutdown pumping operations and began to bleed off the pressure through the choke manifold located in the ASR tank trailer; operator 1 and the tool pusher were in the tank trailer manifold EXHIBIT 9 Page 1 of 5 room performing this activity. Returns were directed to a gas buster and interior tank located inside the ASR tank trailer. Readings taken at the choke indicated pressure was initially at 1,100 psi. At that point the tool pusher left the manifold room. Shortly after, Operator 2 went to the manifold room to communicate with Operator 1 since he could not reach him via radio due to the noise level inside the manifold room from the gas flowing through the manifold. Operators 1 and 2 left the manifold room in order to have a conversation outside the room where they could hear each other. Upon leaving Operators 1 and 2 noted an unusual order, acknowledged to each other sensations of dizziness and agreed to report the conditions. Operator 1 returned to the manifold room and waited outside the room on the landing on the opposite side of the driller's console. Operator 2 went to report the conditions to the tool pusher. The tool pusher was informed of the unusual smell in the tank trailer but it is unclear if the symptoms of dizziness were mentioned. Operator 2 and the tool pusher returned to the tank trailer. The tool pusher immediately entered the tank room through the manifold room in order to open a wall hatch in the rear of the tank room to increase ventilation in the room. Operator 1 and 2 waited in the manifold room or on the landing outside the room. After a brief period of time, Operator 2 entered the tank room to check on the tool pusher. He could not see the tool pusher from the door way so he entered the room and stepped up one step into the room. From there he could see the tool pusher slumped in the back corner of the tank room immediately adjacent to the wall hatch. Operator 2 took a deep breath and started across the tank room to render assistance. Operator 2 made it half way and started to be affected. Operator 2 immediately turned around and just managed to exit the tank trailer. It is presumed he became unconscious upon exiting and slumped down the exterior steps. Shortly thereafter (1 minute), Operator 1 entered the tank room to check on Operator 2 and the tool pusher. When entering, Operator 1 did not notice Operator 2 unconscious on the exterior steps. Same as Operator 2, Operator 1 noticed the tool pusher slumped at the far end of the tank room. Although Operator 1 does not remember doing so, it is believed he closed the choke valve before entering the room since the choke valve was discovered closed immediately after the incident. However, no one remembers closing it. Operator 1 made it all the way across the tank room to the tool pusher and managed to unlatch and partially open the wall hatch. He then repositioned the tool pusher against the exterior wall before starting to feel the affects of the oxygen deficient environment. Operator 1 then attempted to exit the tank room but became unconsciousness somewhere near the exterior threshold. Operator 2 (located on the exterior stairs) regained consciousness shortly after, observed Operator 1 uncoinscious in the exterior threshold, and pulled Operator 1 outside. Operator 1 regained consciousness and Operator 2 went to manual shut in the well and then summoned help. Operator 2 met the Wellsite Supervisor exiting the office trailer on the pad. Supervision initiated a emergency radio call for man down. The Integrated Well Services (IWS) owner arrived on site at this time and immediately determined that the tool pusher was located inside the tank trailer near the wall hatch. The IWS owner opened the hatch from the outside and extricated the tool pusher through the wall hatch. Milne Point personnel nearby responded with available rescue equipment in pick-up trucks, fire trucks and the ambulance. Milne Point Emergency Response/Medical were on location within 10 minutes of the call. All personnel were fully revived on location, treated with oxygen, and transported to the clinic for further treatment and evaluation. 2.) What were the employees doing immediately prior to performing the task in which the accident occurred? Bleeding down annulus pressure on J-08 well through a choke manifold. 3.) What object or substance directly harmed the employee/contributed to the event? A low oxygen atmosphere created by the presence of nitrogen. 4.) Please provide any witness statement/ observations available (attach extra page if necessary): Attached. EXHIBIT 9 Page 2 of 5 • • Driller 1 (131) and Driller 2 (132) smelled something funny (1) D2 leaves to notify Supervisor (S1) while D1 goes to Rig S1 enters Manifold Room (2) D2 enters Mud Pit (3) and discovers S1 slumped against wall (4) D2 turns back and loses consciousness (5) D1 discovers S1 unconscious and attempts rescue. D1 crawls back out and loses consciousness (5) D2 regains consciousness on stairs (6) D2 drags D1 down stairs (6) D2 goes to BOP room and shuts in well, notifies ASR man down S1 is removed from Mud Pit via pallet door window (7) EXHIBIT 9 Page 3 of 5 • *ry i e e , t r Mud Pits w/View toward Far End -40001, Interior of Wall Hatch at Far End PART 3: ANALYZING CAUSE Determine the cause of the accident by analyzing contributing factors. Consider all personnel, machinery and physical conditions present in an effort to find out HOW and WHY the accident occurred. 1.) Describe any unsafe acts that contributed to the accident: See attached Root Cause Analysis. 2.) Describe any unsafe conditions and personal factors that contributed to the accident: See attached Root Cause Analysis. 3.) Describe the fundamental accident cause: The gas buster was not operationally ready for receiving gases bled from the well through the choke manifold. The tank trailer was not adequately walked down and valves aligned properly prior to taking returns to the interior tank trailer tanks. 4.) Was the injury/incident caused by employees' willful misconduct, intoxication or intent to injure self or others, or damage property? If so, please explain: No 5.) Was the incident a result of violation of established safety policies? If so, please explain: No. No violations of safety policies contributed to the incident. 6.) Was adequate personal protective equipment provided for the task being performed? Yes, adequate personal protective equipment was available. Was the employee using the PPE appropriately? If not, please explain: Respiratory hazard of low oxygen atmosphere was not recognized as a possible hazard. 7.) Are changes necessary in the operations and procedures pertaining to the task to prevent this type of incident in the future? Yes If so, please explain: See attached Root Cause Analysis 8.) Please discuss any other policies, personal factors or environmental factors that may have contributed to the hazardous condition or unsafe act: See attached Root Cause Analysis 4 EXHIBIT 9 Page 4 of 5 9.) After considering the information gathered above, please summarize main contributing factors that led to the accident: ROOT CAUSE # 1: Rig Set-up Procedure Not Properly Implemented/Equipment Not Operationally Ready: The dump valve on the gas buster was left in open position during well bleed down activities. ROOT CAUSE # 2: STOP WORK Authority/Procedure Implementation Less Than Adequate (LTA): There were four recognizable instances where STOP Work Authority should have been implemented: (1) unexpected registering of pressure on backside/annulus; (2) when Operator 1 and Operator 2 were initially affected by the atmosphere in the tank room after minimal exposure. (3) when Operator 2 observed the tool pusher in a non -responsive state; (4) when Operator 1 saw the tool pusher in a non -responsive state Personnel rushed into finding solutions to emergency situations they did not fully understand instead of implementing STOP Work procedures and emergency action procedures. PART 4: CORRECTIVE ACTIONS 1.) What have you done, or what do you recommend changing or modifying, to prevent the recurrence of a similar accident? How will these changes help prevent the contributing factors in Part 3?: See attached Root Cause Analysis 2.) Would specific training curtail future accidents such as this? If so, what kind of training is needed? If not, why? Please explain. Rig Emergency Action Plan training for all Operators. EH&S REPRESENTATIVE COMPLETING INVESTIGATION: Carl A. Jones, Safety Manager SIGNATURE: ea)d a. DATE: 10/1/2015 INJURED EMPLOYEE (if applicable): Click here to enter text. SIGNATURE: DATE: Click here to enter a date. INJURED EMPLOYEE'S SUPERVISOR: Click here to enter text. SIGNATURE: DATE: Click here to enter a date. ` cftioa .'F�W8a5: �'Owo Succcx" t EXHIBIT 9 Page 5 of 5 Automated Service Rig 1 (ASR 1) 25 September 2015 Incident Investigation Events Sequencing Chart Monitor sys. j Rig & Crew meets industry Operationally � Design Ready \ Adequate \ Adequate j Halliburton N2 clean - out. Leak and pause of 27 mins after 133 ASR Rig and crew mscf. ASR night shift ASR Rig Constructed by ASR arrived at MPU deployed to Well S-27 ASR Mobe in and rig ASR BOPE tested on J- on duty. Flowback Rangeland Drilling and assembled. Crew and began first well up on J-08A. 08A. Witness waived. hardlined to exterior Automation. Inc. in training on rig. work Commence work over. tanks. Alberta, CA 20150531 20150610 20150719 20150923 20:00 20150924 12:00 20150925 02:30 \ / \ Enclosed mud pit Crew trained and designed w/new gas deemed qualified to monitoring system operate ASR. After 5- (LEL and H2S 27, ASR WOs 5 wells I, detectors) (including J-01A nitrogen) i ASR day shift began ASR day shift began. crew change Halliburton in final activities.. Walked stages of N2 clean. Halliburton finished down job, reviewed Flowing back to N2 clean -out. Total hookup, performed outside tanks. 200mscf and 207 bbls 1SA, discussed N2. seawater pumped. 20150925 05:30 20150925 06:00 20150925 06:30 Abbreviations: LTA - Less Than Adequate NI - Needs Improvement SPAC -Standards, Procedures & Controls Halliburton blew down lines, disconnected truck, stand by on site. 20150925 06:30 ASR crew began well flowback/blow down of N2 to exterior tanks. 20150925 06:35 EXHIBIT 10 Page 1 of 5 Pumped 50bbls Completed pumping seawater via ASR 50 bbls seawater. 227 pump at 3.5 bbls/min bbls recovered in down annulus exterior tanks 20150925 06:40 20150925 07:00 OP2 opened HCR valve. Tool pusher Tool pusher and OP 1 heads to WSM trailer. meet in tank module OP1 started to bleed manifold room to align pressure via auto Tool pusher radioed valves to bleed choke to interior tanks. pressure from annulus OP2 from manifold Reading pressure on to tank module gas room to open HCR annulus. Noted 50 psig buster and interior valve to bleed annulus drop within minutes. tanks pressure. 20150925 - 08:53 20150925 - 08:56 20150925 ^' 08:55 Door between tank manifold room and interior tank room is closed. Abbreviations: LTA - Less Than Adequate NI - Needs Improvement SPAC -Standards, Procedures & Controls Once HCR opened, first time annulus pressure was being read. Start of gas bleed off through choke manifold into interior tank Bleeding pressure from work string to Pressure in tubing exterior tanks. noted to be 0 psig. Pumped 4.1 bbls, Observed A P from Annulus reading of 300 noted immediate 1,000 to 300 psig in psig (incorrect pressure bump from annulus. However reading). ASR directed "nothing" to 1,000 pressure reading not to pump 2nd 50 bbls of psig. Ceased pumping. indicative of annulus seawater 20150925 08:50 pressure. Was reading . trapped pressure 20150925 08:48 between ASR pump WSM stated on and check valve. radio from WSM trailer "I'm confused 20150925 07:00 fellas, let's sit down and talk" OP2 notes extreme OP2 (in drillers console OP2 walks down stairs noise in manifold on rig radios OP1 ri to manifold room to room (gas flowing (choke manifold check on OP1 through choke room) m) to check status. activities. Passes manifold). Motions for OPI does not hear call through -8 ft of tank OP1 to follow him back due noise of fluid room to enter up stairs to drillers (gas)flowing through manifold room. console. Both pass choke manifold through tank room on • 20150925 - 08:59 way out. 20150925 - 08:58 201SO92S - 09:00 OP1 and OP2 l OP2 exposed to tank exposed to tank room for 10 room for -30 seconds. Noted seconds while weird smell. motioning to go outside where they could talk. f EXHIBIT 10 Page 2 of 5 OP2 descends stairs and walks to WSM trailer to find Tool OP1 and OP2 felt dizzy Pusher. OP1 goes back and light headed after through tank room —45 seconds of through manifold OP2 meets tool pusher exposure to tank room and waits in yard outside WSM room. Had hard time outside on landing to trailer. Communicates climbing stairs. manifold room. odd feeling and smell. 20150925 —09:00 I 1 20150925 "' 09:03 1 1 20150925 — 09:05 Workers started feeling better once Crew recognized they got outside to Worker did not "something was not top of steps Door recognize hazard and right" btwn manifold and great risk \ mud rooms closed / OP1 walks through manifold room and enters tank room to check on OP2 and tool pusher. Does not notice OP2 on outside stairs. Sees tool pusher slumped in tank room. Shuts manual choke valve. Makes way to tool pusher and manages to open hatch adjacent to tool pusher. Repositions tool pusher against exterior wall. Gets "wobbly" and tries to get out of tank room. Loses consciousness at outside threshold. 20150925 -09:11 Gas flow through choke stopped. Abbreviations: LTA - Less Than Adequate NI - Needs Improvement SPAC - Standards, Procedures & Controls OP2 Regains consciousness on outside stairs . Sees OP1, drags him down stairs. Shuts in well at tree with manual valves. Goes to sound man down alarm. 20150925 —09:11 Tool pusher enters OP2 steps into tank tank room to open room to check on Tool hatch to increase Pusher. Sees him ventilation. No alarms slumped in far corner. sounding in module Takes deep breath, since monitors did not tries to walk across detect any hazardous the room, makes it half OP 2 and tool pusher conditions; unknown way and turns around. join OP 1 at manifold 02 Deficient Loses consciousness room. atmosphere existed on outside stairs on ri drillers console side of 20150925 09:07 20150925 09:09 the tank module. Well still bleeding gas through choke manifold to tank room for `13 minutes. Unconscious tool OP 1, OP2, and tool Mandown call made, P usher extricated from pusher received Incident reported to Emergency Response tank room b IWS y oxygen on site and external agencies; initiated owner via hatch transported to MPU investigation g began opening. clinic for evaluation. 20150925 09:12 20150925 09:14 20150925 09:20 20150925 10:10 EXHIBIT 10 Page 3 of 5 • Automated Service Rig 1 (ASR 1) 25 September 2015 Incident P&ID and Valve Status at time of Pumping Second 50 bbls of Seawater-0848 hrs g 7 6 5 M 3 2 1 1 Status of valve C7 Valve open — -- -- -- -- -- -- -- NU C3 Valve closed n Valve status o obtained through I .eia L-717 interviews, no photo evidence ----"'°— of valve status at 0848 hrs on 25 r — — — — — -----� I MUM September 2015 ( I 1 I c I i II 1 I C 1 s ror Wo _ .m. am IAWW p Y I ' I e� rw mu h� na ur g I I aars.e�e I swe *ran _ N am W A 5Y�L A rs �n ITV CEN PROCESS m aNa ca n PIPING B INStRVMENT DIAGRAM ASR-1 RIG " nwr: rvao.o sm xN PI-10100-000M 00 001 i g 7 6 5 32 1 EXHIBIT 10 Page 4 of 5 is • Automated Service Rig 1 (ASR 1) 25 September 2015 Incident P&ID and Valve Status at time of Incident - - 0856 hours, Started to Bleed Annulus Pressure g 7 6 5 4 3 21 1 Status of valve O Valve open — — — — — — — — — i= Valve closed F-- Not confirmed in n I ,can IT+1 N� T I I I n� photo ------ -----1 I auto _ 7- S c i I II I I � � £ I � NIf �. —�` m Mc im - -- r ■ral -- ro aew — — 0 � I i our tr stm LIS g Q MMXLmt slewc A4 'A I I NAM — N m Tw rrElt A A Em MPV GEN PROCESS m w 6 A8�N1 RUl PIPING Ac INSTRUMENT 04AGRAM ASR-1 RIG �... �r •..,�. •. � ew.sn � rt a As PI—MGG—WQX% W Wi I g 7 6 4 EXHIBIT 10 Page 5 of 5 • • • September 25, 2015 Incident Root Cause Analysis (RCA) Comprehensive List of Causes (CLQ ACTIONS 1. 1-4 Operation of equipment without authority a. Decision to bleed pressure through the gas buster to the interior tank room tanks was not made by Wellsite Supervisor. 2. 2-1 Improper use of equipment a. Job was not walked down prior to initiating the bleed off of pressure through the gas buster. b. Practice on the rig was to take returns which may contain nitrogen to outside bleed tank, not through gas buster to internal tank room tanks. c. "Open" dump valve on gas buster was not correct operational practice and did not allow the gas buster to operate as designed and vent all gas to the atmosphere outside the tank room. 3. 3-1 Lack of knowledge of hazards present a. First crew member entered tank room assuming there was no risk as no alarms were noted. Explosive atmosphere and H2S sensors do not alarm on N2 or low oxygen. Crew members did not understand the technical capabilities of the atmospheric monitors. 4. 4-1 Improper decision making or lack of judgement a. Wellsite Supervisor and IWS personnel believed the pressure noted when beginning to pump the second 50 bbl water pill was indication of pumping into closed system, against a closed valve, or against a plug. Wellsite Supervisor and IWS personnel did not recognize that a check valve prevented the pressure gauge being monitored from reading annular pressure. The check valve was appropriately placed for the N2 scope of work. However, the pressure indicator was reading pressure between the ASR pump and the check valve (-300 psig ). The check valve was pumped off seat when the pump discharge pressure reached the shut-in casing pressure which was over 1000 psig. b. Crew members ceased pumping activities but did not shutdown the job and reassess the situation when pumping pressure increased rapidly to over 1000 psig. c. Crew members did not associate the noted pressure increase with the nitrogen cleanout pumped earlier. d. Crew members decided to bleed off what was presumed to be trapped pressure due to pumping against a closed valve or plug. e. Crew members continued to bleed off pressure when it became apparent gas was being bled off rather than the expected fluid. EXHIBIT 11 Page 1 of 2 Conditions 5. 5-5 Inadequate warning systems a. Alarm system did not alarm on low oxygen or N2. Crew members were familiar with operation of the alarm system, but did not understand the technical capabilities of the atmospheric monitors. Personal Factors 6. 2-1 Fatigue a. Wellsite supervisor was operating with minimal sleep in previous 40 hours which may have resulted in delayed decision making and lack of direct supervision of activities. Job Factors 7. 15-6 Inadequate communication methods a. Operator 2 (in driller's console) or anyone else could not communicate with Operator 1 (in tank module manifold room) due to noise in manifold room. CLC CORRECTIVE ACTIONS 1. Have replaced Wellsite Supervisor. We will additionally now have a day and night supervisor for future well work. (1 and 6a.) 2. All Integrated Well Services employees onsite have been retrained in the proper use of the gas buster.(2) 3. Prior to any change in well operations, the job will be discussed and all lines walked down. (2a and 2c) 4. All future nitrogen job set ups will include hardline from both the annulus and work string to the external flow back tank. (2b) 5. The dump valve has been closed and locked out and will only be used for cleanout of the gas buster or other operational purposes (2c) 6. All onsite personnel have and will be trained in the technical capabilities of alarm system. (3a and 5a) 7. Stop work authority has been reviewed, emphasizing the importance of stopping all work when conditions change.(4a, b, c and d) 8. Review of alarm system underway to potentially include additional atmospheric monitors. (5a) 9. Day and Night Wellsite Supervisors will be on location. (6a) 10. Radio ear buds embedded in protective ear muffs will be provided to the rig crew (7a) 11. All Hilcorp Operations Engineers and Wellsite Supervisors are expected to assure well procedures match that included in the Sundry Notice. Any deviation will require AOGCC approval. EXHIBIT 11 Page 2 of 2 0 • HHilcorp Alaska, LLC Safety - Sharingtheexperience Incident: ASR 1 Oxygen Deficient Atmosphere Type of Incident: Recordable Location: Milne Point, North Slope, Alaska Date: 25 September 2015. What happened? Milne Point Automated Service Rig 1 (ASR 1) Incident Lessons Learned Summary Three Integrated Well Services (IWS) ASR 1 crew members lost consciousness at approximately 0912 hrs on 25 September 2015 while attempting to bleed pressure off the J-08 workstring by casing annulus. The ASR 1 crew had completed a nitrified cleanout in which nitrogen and seawater was circulated down the backside with returns taken off the tubing string to an exterior flowback tank. The ASR 1 crew successfully pumped one 50 bbl seawater pill following the nitrogen treatment. On the second seawater pill they encountered unexpected pressure on the backside after pumping 4.1 bbls. The crew attributed this to a block flow condition. The IWS rig crew lined up the choke manifold to bleed the pressure to the ASR 1 tank module interior tanks via the module's gas buster. They expected to bleed off minimal fluids but instead received nitrogen gas returns. The dump valve on the gas buster was in the open position which allowed the nitrogen to vent into the tank module for —15 minutes instead of exiting the stack of the gas buster. Nitrogen displaced oxygen within the tank module. The module HVAC system was operating as designed at six air changes an hour but was overwhelmed by the amount of nitrogen entering the room through the gas buster dump valve. The first IWS employee entered the tank module and lost consciousness while attempting to open a rear wall hatch to increase ventilation. The second and third IWS employees were overcome by the oxygen deficient environment while attempting to extricate the first employee, but were able to exit the room before losing consciounsess. When the second and third IWS employees regained consciousness, they immediately shut in the well and activated emergency response. Another IWS crew member opened the rear wall hatch and retrieved the first IWS employee. Milne emergency response were on scene within minutes of receiving the call. All personnel were administered oxygen and recovered fully. What Went Wrong? 1) Valves were not properly aligned to allow annulus pressure readings. The unexpected pressure bump attributed to a block condition was actually the result of pressuring up against and opening a check valve thereby exposing the pressure gauge to actual annular pressure. 2) Valve alignment and flow path not verified through system resulting in gas buster valve being left open during pressure bleed down. 3) Job was not stopped and changed conditions assessed when pressure bleed down operation yielded gas rather than the expected liquid. 4) Employees attempted rescue instead of sounding alarm. 5) Atmospheric hazard was not recognized. The crew did not realize the installed atmospheric alarms would only detect 1-12S and flammable vapors. They were not designed to detect N2 or low oxygen. In the absence of the alarms, they assumed the atmosphere was safe. 6) Radio comms was difficult in a high noise area (noise due to nitrogen gas flowing through choke manifold). What Went Well? 1) Third IWS employee shut manual choke valve prior to entering room. 2) Room HVAC operated as designed and provided sufficient air changes to prevent a fatality. 3) Milne emergency response was immediate and effective. Learningsto share 1) Walk down valves and lines as part of JSA and crew changes. 2) Immediately stop work and reassess when conditions change or unexpected events are encountered. 3) Train all personnel not only in the operation, but also in the technical capabilities of the installed safety systems (e.g., atmospheric monitors). 4) Use appropriate communication devices in high noise areas. 5) Identify, mitigate and communicate potential hazards prior to working with nitrogen. Integrity, Urgency, Ownership, Alignment, Innovation EXHIBIT 12 Page 1 of 1 • 0 ante rated Well Service, Inc. Dail Tail at Meeting/ Job Safe Anal sis JSA Form Date: �• Cam n Representative: Time: Re resenatIva Phone#: ICam an Attendees SI nature:0112 n AAA,ftendeesnaturo:Com Hazards Check A I'cable Hazards Check Applicable Hazards Check Appll-Ms- {1 PincA Points (13)Lock Out Tag Out (25) Temperature Ezatremes (2)Etoctncal iq PPE 26 H' h Winds (3) Elevated 7 suspended Toads (16) Spec(al PPE Required (2T Communlcewo (4) Hot Walk pennii (16) PmswreTesting (26 Rotatin E Ipmant (5j Confined Space En ry 07) Slick / Uneven sues= OTHER: 6) Equipment Handling & Dlsjointi (18) Dmng Conditions 29 Simultaneous o milans (19) Working at Heights (30 B Stored Pnmw. Systems (,/- (20) Shod SeMoo Empioyeo 131) (s) High Noise Levels 21 House KOP1,9 (32 00 Hea LJM 22 MoNleEquipment 33) 11 TraffC Pettems around Rig 23 3rd Pa vmrk 34 (12 Tdppvg hazards 24)Dess natedAreas amoklrq•atc.} 35 $ite S ' Iflc"JSA':`::. :v • :} _: Job Steps t Equipment, Tools, & Material! PPE Hazards Controls fit` y tF,1c� Gtcr h� pc .. ^-+•r. . {x 5i,4zi 6e-6weerl '6.A4— y oo L 'Fra— •/ }� dCUJS Loak.U� S�ci �(,t t;}' •w/G FSc {to,r � c UY �.,� .�+cs� 'or oot ad- ( the tfc d QtcJO f1Ct V,,+o� 5�0 tttir G pj S'alc }k SOP # reviewed a Tailgate ! Pro4ob Meeting F,mergency N ISuperylsor Name: I Iftone 8 5 EXHIBIT 13 Page 1 of 2 Integrated Well Service, Inc. Daily Tailgate Meetin / Job Safety Analysis (JSA) Form Date: Cf 2S r' / Com an Re resentative: Time: Re resenatWe Phone #: Attendees Signature: company Attendees Signature: Corn an 1) 2 3) 7 8 4 10 5 11 ti 12 HazardsNPAppliqm4le,Hazards Check Check Applicable Hazards Check Applicable (1) Pinch Points 13) Lack Out Tag Out 25 Temperature Fatremes ✓ (2) Electrical 14 PPE 26) High Winds ✓ 31 Elevated / su ended loads 15 S lal PPE Required 27 Communication ✓ 4 Hot Work ermd 16 Pressure Test (28) Rotating Equipment 5 Confined Space En 17 Slick ( Uneven surfaces OTHER: 8 Equipment Handling & Disjointing 08 Driving Conditions 29 7 Simuhaneous operations 19 Working at Heights 30) 8) Stored Pressure Systems 20) Short Service Employee 31) (9) High Noise Levels (21) House Keeping 32 10 Heavy Lifting (22) Mobile Equipment 33 11 Traffic Patterns around Rig 23 3rd Party work (34) (12) Tripping hazards 24 Designated Areas smoking, -tc,) 35) Site Specific JSA Job Steps / Equipment, Tools, & Material 1 PPE Hazards Controls Pk -lam%Row, rr`35 �P�"5 j.ne5 fasSG�a f 7h d.-7>< / u•..^y-F.'<.. � �/o�.l�. to-d 5, sl. p5-r5,.Poi T. y. N. 5).•y SOP # reviewed Tailgate / Pr"ob Meeting Emergency ISupervisor Name: I lPhone# No._ EXHIBIT 13 Page 2 of 2 JOB LOG TEKET 902780922 TICI ET MTE 09/24/16 NM/COUNTW Alaska EM /$TALE Alaska COI"T" North Slope Borough HE.6 EHPLOYPE /NPAM E.6 £1640Vff fUAE PBL O�ARTIEH� OGTgN COMPANY Hiilco 1450 a AW 1562207 Pumping Work over Milne Point amPOW Cone 363672 N2 pumpina Date Time N2 VOLUME Job Description / Remarks HES GAL HR. SAFETY 09124116 16:30 Depart with Pumper# 11280516 with 2,499 gal. 18:00 X Arrive on location; Safety meeting; Spot Equipment Day 2 09/26/15 0:02 lRig up 2:00 Cool Down 2:10 X Sammy meting 2:30 Pressure Test to 3,5W psi 2:40 Online 600 scfm; 140 psi 2:41 760 scfm; 276 psi 2:46 1,000 scfm; 577 psi 2:67 1,200 scfm; 936 psi 3:30 1,200 scfm; 1,263 psi 4:30 Offilne; N2 hose started to leak. Replaced hose. 4:66 Online 1,000 sctm; 1,181 psi 6:30 1,000 scfm; 1,280 psi 6:30 2499Wine; 1,327 psi. Pumped 200,000 scf. Pump has 0 gal left Standby. Rig Is pumping 50 bbls fluid to kill the well. 8:00 X Partial rig down. Standby. 11:00 Left location. 16:00 Arrive at yard 24" Gals used 2 days pumping EXHIBIT 14 Page 1 of 1 NITROGEN UNIT ................................... ••• NITROGEN PUMP KILL MANIFOLD Standpipe ASR RIG •••••• MUD PUMP K7 K8 Y K3 K4 K5 Vent PIT SYSTEM GAS BUSTER CIRC K2 K1 Kill Line Open Open 90 BBL CUTTINGS TANK Updated 1/21/16 uid F ASR Rig #1 Fluid Flow Diagram 3-08A Incident 500 BBL KILL TANK 500 BBL PIGGING TANK CHOKE MANIFOLD • C3 Cl-ed A B a+ v a0 0 BOPE Panic Line C12� C13W i C15 Open U l~J Open M Cl HCR PO Choke Line Open *4 Casing Valve Gas Buster Line • LEGEND: Fluids Pumped . Fluids Returned Q Valve Open Valve Closed Gate Valve Ball Valve W4 Butterfly Valve Lo Torq Valve VM Automatic Choke Manual Choke j Pressure Gauge Qp Check Valve N Bleeder Tee 0I4 EXHIBIT 15 Page 1 of 1 • • 149`34'55"W 149°34'50"W 149"34'45"W 149°34'40"W 149°34'35"W 149 34'30"W z z - y. { n Co r - � r kRr i d A. « 1 -1•`y Y { F' f h -W kh Alaska State Plane Zone 4 NAD 1983 (Feet) Milne Point Unit Aerial Photography: 0 10 20 30 ao s Meters ASR #1 J-08 Quantum 20Spatial Inc D 100 200 3ooeet Map Date 1/21/2016 Site Map EXHIBIT 16 Page 1 of 1 Rear ASR #1 TANK TRAILER PASSENGER SIDE VIEW Valve Front EXHIBIT 17 Page 1 of 1 J Front ASR #1 TANK TRAILER DRIVER SIDE VIEW V11U1y v'Door • Rear EXHIBIT 18 Page 1 of 1 _ 9/25/2015 ASR Rig — CLC Corrective Actions CA# Descri tion CL # Res onsible Part Due Date_ Completed DONE, Lock Lock the dump valve on the gas buster system in the closed position following the 2014 and training Alaska Safety Handbook's Energy Isolation Standard. The valve shall be locked in the closed on valve has position using a control lock (white with company name) and tagged with "DANGER" highest Immediately been done 1 level of hazard awareness tag. The Integrated Well Services ToolPusher will be responsible 2c upon rig up and for control of the lock and will assess all situations prior to removing the lock to orient the current valve to a position other than closed Review and revise the Integrated Well Services SOP for nitrogen cleanouts. Revisions shall include requiring hardline from both the annulus and work string to the external flow back DONE, SOP tank, language directing employees to %isualfy verify the orientation of the gas buster dump wrote and 2 valve prior to initiating flowback activities. This standard shall also be required to review the 2b 11/1/15 reviewed. SOP each time prior to initiating nitrogen activities. The revised SOP will be reviewed and SOP is approved by the HAK company man, HAK Field Foreman, and Integrated Well Services lemen ToolPusher. Develop a schematic of the ASR #1 Tank Trailer/Manifold Room which identifies all valves and associated equipment to include the gas buster. Once schematic is developed all DONE, Integrated Well Services employees will review the schematic and be trained on proper posters are operation of the manifold and gas buster during a field walk down with the HAK Company posted, all Man and Integrated Well Services Toolpusher. During the walk down all personnel will fines are 3 receive a specific briefing regarding the proper orientation of the dump valve (closed) on the 2a,b,c 11/15/15 marked with gas buster along with a detailed explanation of how the gas buster is designed to work and high visual the effects of improper orientation of the dump valve. The review and walk down of all stickers and equipment shall be documented and all Integrated Well Services employees will sign a roster once completed. arrows Design and produce a poster of the manifold and gas buster systems schematics. Poster DONE, should be in detail to allow manifold operators to help trace systems down while walking MPtf 4 down lines prior to flowback and pumping activities. 3 posters should be printed and hung in 2a,b,c -/ 11/15/15 posters are the manifold trailer, pusher shack, and company man office. posted Review the design of the current gas detection system and identify additional equipment to New sensors are Installed, but be added to the system. This will include oxygen sensing equipment to alarm during oxygen wiring and deficient atmospheres below 19.S% as well as carbon monoxide sensing equipment set to — / HAK Programing not finishetl. alarm at 25 parts per million. Equipment shall be installed and function tested after 3a, 5a 12/1/15 All ASR 5 installation and each time the rig performs workover activities. In addition all Integrated Instrumentation employees have Well Services employees and HAK company men supervising the ASR activities will be trained been trained on System on the mechanical capabilities and limitations of the gas detection equipment. All trainees documented. will acknowledge completion and understanding of the system by signing a training roster to I Iw Nn and EXHIBIT 19 Page 1 of 2 be maintained on site by the ToolPusher. In the interim of gas detection upgrades, personal pr amming to a place when four gas monitors will be used by employees performing work activities within the confines crew is on days off of the pit/manifold skid fi stweek in rebus . DONE, SOP Develop a restart protocol or SOP for reset/restart of gas detection alarms and HVAC and policy. 6 equipment. It was noted after the investigation was concluded that power interruption to NA 11/15 Policy is alarms and HVAC system requires each system to be reset/restarted manually after daily ted in checks (maintenance/oiling) ofthe generator that supplies power to the unit generator room Procure in ear and over the ear headsets for rig employees working in high noise areas and within the pit/manifold trailer. Headsets shall be Intrinsically safe and provide adequate NRR Done, ear (noise reduction rating). Headsets should be designed to be compatible with currently used plugs are in HAK Motorola radios. Once in place, headsets will be evaluated for effectiveness, durability, 8a 11/1115 use for hands 7 and ease of use. Once evaluated Integrated Well Services ToolPusher will purchase adequate in high noise stock to ensure communications can be maintained between employees in high noise environments. are one, air Review the pit/manifold trailer ventilation systems capabilities and ensure that ventilation system is functioning adequately to exhaust gases as necessary. If the system is adequate system 8 and functioning as designed the number of air exchanges per hour will then be increased 6a TBD 11/1/15 turned to from 6 to 12 exchanges per hour to ensure maximum air flow through the tank trailer. I maximum Additional Actions / Lessons Learned: Investigation findings determined that improper decision making or lack of judgment took place while pumping the 2"d fluid pill. (See CLC 4a,b,c,d and 1a) As an immediate action, stop work authority was reviewed with all Integrated Well Service employees. The review emphasized the importance and expectation to stop work when conditions change and discuss current conditions with Company Man and Tool Pusher before proceeding with the job. It was also emphasized that the discussion should identify hazards associated with the changed conditions, and the mitigations that should be implemented prior to restarting the work activity. During follow up discussion with ASR crew members regarding corrective actions the topic of "Knowledge, Skills and Abilities Competencies came up. Moving forward it is recommended that the HAK Company Man and IWS Toolpusher develop a list of rig equipment and positions for which competency evaluations are required. These competencies could then be generated and used to mentor and sign off employees similar to the TOP process HAK North Slope operators use to qualify for operations positions and progressions. EXHIBIT 19 Page 2 of 2 ■ From: Bo York Sent: Monday, November 30, 2015 10:36 AM To: Alaska NS - Milne - Field Foreman; Cc: Subject: Compliance with Well Work Sundry Procedures - Coil Tubing, ASR, Nordic, Doyon All - We have had issues in the past 8 months with following AOGCC regulations and explicitly following the procedures detailed in our AOGCC approved sundries. We must do better. If we do not, it will impact our ability to continue to operate and develop our fields in Alaska and our ability to continue to grow. In order to meet our goal I drafted the following steps to ensure we develop better procedures and ensure we strictly implement the procedures approved by AOGCC via the sundry process. Our Goal: Utilize the resources and experience in our team to execute well work safely and efficiently, within AOGCC regulations and requirements. Prior to Initiating Well Work: 1. Operations engineer responsible for the well work will develop the procedure with adequate detail to ensure field execution may occur within the steps included in the procedure and all AOGCC requirements are addressed. 2. Regulatory Tech (Tom Fouts) will generate Form 10-403 to accompany the procedure. 3. Operations engineer that developed the procedure will review the procedure with the Field Foremen and Well Site Manager that will be performing the work. Intent is to obtain their comments and input on the steps and to leverage their 20+ years of performing well work. 4. Operations engineer will provide the reviewed procedure and Form 10-403 to the operations manager for review and schedule a peer review meeting with the other operations engineers in town. Typically this meeting will occur on Friday after the AFE review meeting but can be scheduled at any time. Field Foreman and WSMs should also be invited to this meeting. 5. After the changes are incoroporated from the peer review, the operations engineer will initial the Form 10-403 and the operations manager will sign it. 6. The Reg Tech will submit the 10-403, procedure, and all attachments to AOGCC two weeks prior to performing the work. 7. The Reg Tech will track the submittal and let the operations engineer know once approval is received. Work Execution: 1. The operations engineer and WSM are responsible for executing the work. 2. Prior to starting the work, a kick off meeting will be held by the WSM with the rig crew. The entire procedure will be walked through and any special safety considerations will be addressed. The rig crew should understand the procedure and the approved steps. This meeting will be documented on a safety meeting sign in sheet. 3. ANY deviation from the approved procedures will be discussed with the operations engineer and in turn the AOGCC representative. Work will not proceed until the deviation is approved by AOGCC. EXHIBIT 20 Page 1 of 2 4. ANY step or detail not included in the approved procedure but is discovered during well work activities and needs to be added will be discussed with the operations engineer and in turn the AOGCC representative. Work will not proceed until the addition is approved by AOGCC. 5. 1 repeat this .... If the step is not included in the approved procedure or if a detail is added/changed, work will stop until the operations engineer notifies the AOGCC and the change/added step is approved. The operations engineer may get verbal approval but ALWAYS followed up with written confirmation via email. This process will be strictly enforced and I need everyone's help and cooperation to ensure we do not continue to have communication problems with AOGCC. Following these steps will lead to better quality procedures, safer operations, and a better run operations team. Go team. Thanks Bo York Operations Manager, Milne Point bvork@Hilcorp.com 907.777.8345 907.727.9247 cell EXHIBIT 20 Page 2 of 2 From: Sent: To: Subject: Follow Up Flag: Flag Status: Always on top of it. Chris Chris Kanyer <ckanyer@hilcorp.com> Saturday, May 02, 2015 2:33 PM Re:1-03 Follow up Flagged Sent from my iPhone On May 2, 2015, at 1:24 PM, hilcorp.com> wrote: Ha they were already closed! Regards From: Chris Kanyer Sent: Saturday, May 02, 2015 7:28 AM To: Subject: Re: 1-03 I'm not trying to butt in, but please make sure that you notify AOGCC of closure of BOPs due to well control within 24hrs. Looks like you have everything under control. Chris Sent from my iPhone On May 2, 2015, at 5:43 AM, hilcor .com> wrote: Typo on the update folks forgot the change the subject line. Sorry Regards From: Sent: Saturday, May 02, 2015 4:36 AM To: Chris Kanyer; Cc: Alaska NS - Milne - Field Foreman; Alaska NS - Milne - Wellsite Supervisors; Subject: Update J-09 i EXHIBIT 21 Page 1 of 2 0430 Successfully straddled hole incasing. GP depth was 14' high. Test Annulus to 1500 psi after packer set all good. Upon releasing off packer well immediately started flowing with oil to surface almost immediately. Vented flowed monitored and circulated with no losses. 138 bbls Oil recovered w 138 bbl SW pumped. Surface pressures recorded SITP 50 psi SICP 60 psi. Have ordered 9.2 brine to displace and kill. Moving forward, Kill, POOH, S/L runs x 2 to retrieve bar and plug, run production. Won't begin killing until probably around 0900. Good example of why all casing repairs should be considered. Regards EXHIBIT 21 Page 2 of 2 • • From: @hilcorp.com> Sent: Saturday, May 02, 2015 6:23 PM To: Regg, James B (DOA) Subject: Re: AOGCC Test Witness Notification Request: BOPE, Nordic 3 MPU 1-03 Thanks, engineering wanted to be sure all bases covered. Thanks Jim. Hilcorp Alaska LLC WSM Milne Point Email `@hilcorp.com USA Cell +1 Rig Office Direct 907-� From:, "James B (DOA)" <aim.regg@alaska.gov> Reply -To: "Regg, James B (DOA)" <iim.reRR@alaska.gov> Date: Saturday, May 2, 2015 at 6:17 PM To: hilcorp.com> Subject: RE: AOGCC Test Witness Notification Request: BOPE, Nordic 3 MPU 1-03 If planned step in your operation report is not required Jim Regg AOGCC Sent from Samsung Mobile -------- Original message -------- From: hilcor .com> Date: 05/02/2015 12:31 PM (GMT-09:00) To: "Ogclnspector (DOA sponsored)" <doa.ogc.Inspector@alaska.gov> Cc: "Jones, Jeffery B (DOA)" <ieff.iones@alaska.gov>,DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe. bay@alaska.gov>,"Regg, James B (DOA)" <Lm.regg@alaska.gov> Subject: RE: AOGCC Test Witness Notification Request: BOPE, Nordic 3 MPU 1-03 Utilized Annular BOP for Shut In while waiting to weight up after successful straddle isolation. Weighting up fluid density .5 ppg• Not sure if notification required in this situation. Thanks Regards 1 EXHIBIT 22 Page 1 of 3 From: Ogclnspector (DOA sponsored)[mailto:doa.ogc.lnsoector@alaska.gov] Sent: Thursday, April 30, 2015 7:03 PM To: -� Cc: Jones, Jeffery B (DOA); DOA AOGCC Prudhoe Bay Subject: Re: AOGCC Test Witness Notification Request: ROPE, Nordic 3 MPU 1-03 Witness waived Chuck Do not reply directly to this e-mail or doa.Ogc.insnectorkAlaska.P'ov Please reply to AOGCC.inspectors@Alaska.gov or Doa AOGCC prudhoe.baya,Alaska.gov Alternate contact numbers 907-659-2714 (NS office) 907-793-1236 (Jim Regg) On Apr 30, 2015, at 18:46, hilco .com> wrote: Jeff, BOP Test will be 0800 5/1 we are preparing to rig down on J-09 now. Thanks Regards From: Jones, Jeffery B (DOA) [mailto:ieff.iones@alaska.gov] Sent: Wednesday, April 29, 2015 7:47 PM To: ; DOA AOGCC Prudhoe Bay Subject: RE: AOGCC Test Witness Notification Request: BOPE, Nordic 3 MPU 1-03 Please update @ 6 am tomorrow morning. Thanks, Jeff B. Jones Petroleum Inspector Alaska Oil & Gas Conservation Commission N. Slope Ofc: 907-659-2714 Mobile: 907-448-1228 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 Jeff B. Jones at 907-659-2714 or Jeff Tones@alaska gov From: �[mailto:noreply(o)formresoonse com] Sent: Wednesday, April 29, 2015 7:39 AM To: DOA AOGCC Prudhoe Bay Subject: AOGCC Test Witness Notification Request: ROPE, Nordic 3 MPU I-03 2 EXHIBIT 22 Page 2 of 3 • • uestion Answer Type of Test Requested: BOPE Requested Time for 04-30-2015 8:00 AM Inspection Location Nordic 3 MPU I-03 Name - E-mail j jWhilcorp.com Phone Number (907)- Company Hilcorp we should be moving off J-09 tonight, this is a best guess today Other Information: could go really well, but there are possible glitches. Thanks for the patience.Will update again when we land tubing. Submission ID: 306131130242441965 3 EXHIBIT 22 Page 3 of 3 • Pressure Test Procedures Set Your Kick -Outs Your kick -outs are located on your Uni-Pro II screen. To get to the kick -out page.... 1. Press ...... then "T'.... To set the kick -outs.... 2. Press "Menu 3", then "Menu 4" for the left side. 3. Enter desired pressure & press "Enter". 4. Press "Menu 8" for the right side. 5. Enter desired pressure & press "Enter". 6. Press ...... then "3" to return to main pumping screen. Test Your Kick -outs 1. Set your kick -outs for 500 psi. 2. Open your prime -up & start stroking your pump. 3. When your saturation falls below 10 psi, close your prime up valve. 4. When your pressure reaches 500 psi, your pump should kick -out. 5. Open up your prime -up to relieve pressure. Pressure Test Iron 1. Set your kick -outs for 1000 psi over max pressure. 2. Walk your lines & ensure your to-torc valve at the end of your line is closed, your blow down is closed & both autoclave bleeder tees are closed. 3. Clear the ground of all personnel & announce that pressure testing will commence. • 4. Once the ground is clear & all valves have been verified, start priming your pump. EXHIBIT 23 Page 1 of 3 • • LJ 5. Open discharge valve & start to close prime -up valve as saturation starts to fall. 6. When saturation drops below 10 psi, close in prime -up valve all the way & run pump at 500-600 scf/m until you reach your desired pressure. 7. Turn off rate control knob, open prime -up & close discharge valve when pressure test is complete. 8. Walk the line listening for leaks & run an empty glove over each union to check for leaks. 9. If no leaks are found, bleed off the pressure & return to the pump. 10. If leaks are found, bleed off pressure, fix leaks & repeat last step. NOTE- For winter operations, leave discharge valve open. This will prevent freezing closed. EXHIBIT 23 Page 2 of 3 0 • N2 Pumping iob Procedure Pre- Job 1. Start generator 2. Start engine, open vents 3. Open blow down to condition the N2 4. Rig up Job 1. Cool down cold ends, open both isolation valve and suction valves 2. Open prime up valve 3. Close road relief valve 4. Close blow down, open pressure builder valve. 5. Set kick outs 6. Pressure test 7. Get saturation down before pumping 8. Open isolation valve to entry point 9. Open discharge valve 10. Close prime up valve 11. Bring rpms up to desired number 12. Bring up rate to desired number 13. Bring up hydraulic heat pressure '14. Keep heat at 85 deg 15. Monitor pressure Bring off line 1. Bring rate to zero 2. Crack blow down 3. Close isolation valve 4. Bring hydraulic pressure to zero 5. Bring rpms to idle 6. Close pressure builder 7. Open blow down to bleed pressure off tank Post iob 1. Turn off engine, generator 2. Close blow down 3. Open road relief valve, rig down 'JEXHIBIT 23 Page 3 of 3 THE STATE ofALS GOVERNOR BILL WALKER December 15, 2015 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7015 0640 0006 0779 5890 Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Re: Docket Numbers: OTH-15-024, OTH-15-025, OTH-15-029, OTH-15-030, and OTH-15- 031 Notices of Proposed Enforcement Action — Informal Review Dear Mr. Wilkins: As part of the informal review process, Hilcorp Alaska, LLC (Hilcorp) has the opportunity to submit documentary material and make written and oral statements regarding the Notices of Proposed Enforcement Actions for: o Docket Number OTH-15-024, Rig Operations with Failed Gas Detection System, Hilcorp ASR-1, MPU F-96 (PTD 2081860) o Docket Number OTH-15-025, Failure to Notify of Changes to an Approved Permit, Failure to Maintain a Safe Work Environment, Hilcorp Rig ASR1, MPU J-08A (PTD 1991170); o Docket Number OTH-15-029, Failure to Test BOPE After Use, Nordic Rig 3, MPU I-03 (PTD 1900920) o Docket Number OTH-15-030, Failure to Notify of Changes to an Approved Permit, Hilcorp Rig ASR1, MPU J-01A (PTD 1991110); o Docket Number OTH-15-031, Failure to Notify of Changes to an Approved Permit, Nordic Rig 3, MPU J-09A (PTD 1991140). There will be no formal record kept of the review and the review will not involve the presence of counsel, either for the AOGCC or the operator. The informal review is scheduled for February 18, 2016 at 10:00 a.m. in the AOGCC's Anchorage office located at 333 West 7th Avenue. Copies of all written submissions and summaries of any oral statements planned by Hilcorp should be provided to the AOGCC no later than January 29, 2016. Docket Numbers: OTH-15-02AL-15-025, OTH-15-029, OTH-15-030, and 00-15-031 Notices of Proposed Enforcement — Informal Review December 15, 2015 Page 2 of 2 Prior to the January 29, 2016 deadline Hilcorp may request to incorporate any other enforcement actions to be included in this informal review. Pursuant to 20 AAC 25.535 any additional requests must be submitted in writing. Sincerely, /141'elv� Cathy . Foerster Chair, Commissioner Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Tuesday, December 15, 2015 11:30 AM To: David Wilkins Subject: Informal Review Attachments: Hilcorp Informal Review 021816.pdf Importance: High Mr. Wilkins, Please see the attached regarding an informal review. A hard copy is in the mail. Please let me know if you have questions. Thank you, Samantha CarCisCe Execlrtive Secretary 11 ACaska OdandGas Conservation Commission 333 1,Vest 71" Aveniw, An,ch.crrage, AX 9,9501 (907) 793-1223 saman.tha.c a.rtistPCa)afaskc qov 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: in 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 Samantha Carlisle at (907) 793-1223 or Samantina.Cnrlisle@alaska. Say. U.S. Postal Service" CERTIFIED MAIL° RECEIPT Domestic Mail Only For delivery information, visit our website at www.usps.com'. r� ;`Certified Mail Fee --- — -- 17- $ ® 'Extra Services & Fees (check box, add fee as appropriate) ❑ Return Receipt (hardcopy) $ ® i ❑ Retum Receipt (electronic) $ Postmark ® I❑ Ce ified Mail Restricted Delivery $ Here ❑Adult Signature Required $ EjAdult Signature Restricted Delivery $ ED ( Postage Mr. David Wilkins 'n Senior Vice President a o Hilcorp Alaska, LLC r� 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 1 d6mplete items 1, 2, and 3. ■ Print your name and address on the reverse so that we can return the card to you. ■ Attach this card to the back of the mailpiece, or on the front if space permits. Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 A. Signature ❑ Agent X tReceived ❑ Addressee B. by (Printed Name�Dateofdelivery address different fro ;YES, enter delivery address below: ❑ No EEIV` SFr' 1 P- 9015 a. aerviCe Type Priority Mail Express El® ®El Signature El Registered Mail - I) I III III I'I I III I I I I I I I I �� 11111111111 (III III I III El Adult Signature Restricted Delivery El Registered Mail Restricted 9590 9403 0910 5223 5231 57 (a'Certified MailO ❑ Certified Mail Restricted Delivery Delivery Receipt for ❑ Collect on Delivery ❑ Collect on Delivery Restricted Delivery Merchandise Signature ContirmationT"' 2. Article Number ()"ransfer from service label) (red Mail ❑ Signature Confirmation 7 015 ®6 4 0 0006, 0779 5890 (red Mail Restricted Delivery Restricted Delivery a $500) PS Form 3811, July 2015 PSN 7530-02-000-9053 Domestic Return Receipt 0 Hilcorp Alaska, LLC NOV 25 2015 November 25, 2015 Cathy Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3572 • David Wilkins Senior Vice President Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone:907/777-8397 Fax:907/777-8580 dwilkins@hilcorp.com Re: AOGCC Docket Nos. OTH-15-025; OTH-15-029; OTH-15-030; and OTH-15-031 Notices of Proposed Enforcement Action Dear Chair Foerster, Thank you for your letter dated November 23, 2015. We continue to request an informal review as originally proposed. We want to make sure that you know we take these matters very seriously. Instead of just reviewing this matter internally, we engaged an outside party to be certain that a full and independent investigation of this matter would be conducted. We informed you of Mr. Jamieson's efforts simply to let you know how we are proceeding with the investigation. He has already begun interviewing witnesses and collecting and reviewing documents, and we are facilitating his review by providing him access to all personnel and relevant documents. There were many participants in these events, and the volume of written material to review is substantial. In addition, the notices set out prior events which the Commission has stated are similar to the events cited in the notices. All of these events are subject to investigation. Of course, this increases the time it will take to adequately prepare for an informal review. And now the Holidays are upon us, and several key individuals will be taking leave over the next five weeks, decreasing the pace at which the investigation can be completed. Accordingly, we propose that the informal review occur in mid -February, with our written submission to be due January 29, 2016. We look forward to the opportunity to confer on the matters in an informal setting, as we believe that will be the best forum for an open and full discussion and exchange of information and thoughts. We believe this will allow the Commission to frame a well-informed proposed order. Sincerely, HILCORP ALASKA, LLC >�R David Wi ins Senior Vice President THE STATE GOVERNOR BILL WALKER November 23, 2015 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7015 0640 0006 0779 5838 Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Numbers: OTH-15-025, OTH-15-029, OTH-15-030, and OTH-15-031 Notices of Proposed Enforcement Action Dear Mr. Wilkins: This letter is the Alaska Oil and Gas Conservation Commission (AOGCC)'s response to Hilcorp Alaska LLC (Hilcorp)'s November 20, 2015 letter regarding various AOGCC enforcement actions pending against Hilcorp. Although Hilcorp's letter requests informal review, by virtue of your reference to retaining counsel and presenting the results of your lawyer's internal investigation in "proceedings," the letter also appears to contemplate a hearing. The AOGCC's informal review process is intended to afford an operator the opportunity to meet with AOGCC staff in an effort to resolve pending enforcement actions. There is no formal record kept of the review and the review does not generally involve the presence of counsel, either for the AOGCC or the operator. Consequently, if Hilcorp desires to proceed by having counsel present the results of his review and investigation, the matter should be set for public hearing. The AOGCC has no objection to addressing all pending enforcement actions at a single hearing. Please advise the AOGCC as to how Hilcorp prefers to proceed. Sincerely, Cathy V Foerster Chair, Commissioner cc: Brewster H. Jamieson, Lane Powell, LLC • • Carlisle, Samantha J (DOA) From: Sent: To: Cc: Subject: Attachments: Mr. Wilkins, Please see the attached. Thank you, Samantha Carti'Ae Carlisle, Samantha J (DOA) Monday, November 23, 2015 1:05 PM David Wilkins Foerster, Catherine P (DOA); Seamount, Dan T (DOA); 'Regg, James B (DOA) oim.regg@alaska.gov)' Response to informal review request AOGCC response to informal review request by Hilcorp OTH-15-025, 029, 030, 031_ 11232015.pdf 'Executive Secretary IT .Alaska Odandjas (onservat%on Commission 333 147est 7 " Avenue Anchorage, .SIX 9 )_Sot (907) 793-1223 (phone) (007) 276-7s42 (fax) 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 Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.gov. C0 .. m Ln t ir'.. f` Certified Mail Fee' Iti $ Oc. — ce..,;,.,,.. o. -- as appropriate) ❑ Return Receipt (hardcopy) $ O ❑Retum Receipt (electronic) $ O ❑ Certified Mail Restricted Delivery $ ❑ ❑Adult Signature Required $ ❑ Adult Signature Restricted Delivery $ O Postage $ Total Postage and Fees S Lr) Sent To r-i Street and Apt No., jjj Ply §ox IVo. 17*1- U, �;' State, ZIP+4b ----------------- Postmark Here Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 ® Complete items 1, 2, and 3. ■ Print your name and address on the reverse so that we can return the card to you. ® Attach this card to the back of the mailpiece, or on the front if space permits. Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 SECTIONCOMPLETE THIS . A. Signature B. Received by (Printed Name) T>L CaYGe' D.-is delivery address differentirQ waddress Mv 2 5 2015 ❑ Agent ❑ Addressee C. Date of Delivery item 1? U Yes ;low: ❑ No 3. Service Type ❑ Priority Mail Expresso II I IIIIII IIII III I I I I I I I I II Illlll 111 I II III II III ❑ Adult Signature ❑Registered MaiIT"' Signature Restricted Delivery ❑ Registered Mail Restricted 9590 9403 0910 5223 5233 55 Wodult ertified MailO ❑ Certified Mail Restricted Delivery Delivery ET-Fletu n Receipt for ❑ Collect on Delivery Merchandise 2. Article Number (Transfer from service label) ❑ Collect on Delivery Restricted Delivery red Mail ❑ Signature ConfirmationTM ❑ Signature Confirmation 7 015 0640 0006 0779 5838 -ed Mail Restricted Delivery Restricted Delivery $soo) PS Form 3811, July 2015 PSN 7530-02-000-9053 Domestic Return Receipt € L� • Hilcorp Alaska, LLC n November 20, 2015 NOV 2 0 201; AOGCC David Wilkins Senior Vice President Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8397 Cathy Foerster Fax:907/777-8580 y dwilkins@hilcorp.com Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3572 Re: AOGCC Docket Nos. OTH-15-025; OTH-15-029; OTH-15-030; and OTH-15-031 Notices of Proposed Enforcement Action Dear Chair Foerster, We acknowledge receipt of the four letters referenced above, dated November 12 and November 16, 2015, providing Hilcorp Notices of Proposed Enforcement Action pursuant to 20 AAC 25.535 ("the Notices"). The Notices express concerns that Hilcorp takes very seriously as part of our commitment to good oilfield practices and safe operations. We will fully address the Commission's concerns. Our goal remains full compliance with the AOGCC's regulations and permits. Hilcorp has retained the services of Brewster Jamieson of Lane Powell, LLC, to represent us in connection with the Notices. We have asked him to conduct a thorough review of the evidence and circumstances that led to the issuance of the Notices, and to present the results of that investigation to the Commission and staff in an informal review. He will be contacting the AOGCC staff in due course with suggestions of timing and potential consolidation of some or all of the Notices in order to address all of the Commission's concerns in a single proceeding. Pursuant to 20 AAC 25.535(c), Hilcorp requests an informal review of the Notices, the opportunity to submit written documentation prior to that informal review, and to make both written and oral statements to the Commission and staff at the informal review. Hilcorp is committed to engaging in this process fully and cooperatively, and we consider full compliance with the AOGCC regulations and permits a priority of the highest order. Sincerely, HILCORP ALASKA, LLC Davi ilkins Senior Vice President cc: Brewster H. Jamieson CJ • IN LANE POWELL ATTORNEYS & COUNSELORS BREWSTER H. JAMIESON 907,264,3325 jamiesonb@tanepowell.com November 18, 2015 Cathy P. Foerster, B.S.M.E. Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 W Seventh Avenue, Suite 100 Anchorage, AK 99501-3572 Re: Hilcorp Alaska, LLC AOGCC Docket Nos. OTH-15-025; OTH-15-029; OTH-15-030; and OTH-15-031 Dear Ms. Foerster: The law firm of Lane Powell LLC enters its appearance as attorneys of record on behalf of Hilcorp Alaska, LLC, in the above -captioned four matters, and requests that copies of all pleadings filed in this action be mailed or delivered to its offices at Suite 301, 301 W. Northern Lights Blvd., Anchorage, Alaska 99503-2648, Very truly yours, LANE POWELL LLC 7� Brewster H. I ieson BHJ:lg 1293 87,0002/6491743.1 www.lanepowell.com A PROFESSIONAL CORPORATION LAW OFFICES T. 907.277.9511 SUITE 301 ANCHORAGE, AK. PORTLAND, OR F. 907.276.2631 301 W. NORTHERN LIGHTS BLVD. SEATTLE, WA. LONDON, ENGLAND ANCHORAGE, ALASKA 99503-2648 THE STATE VAI,1 11 WMA Fe 45 GOVERNOR BILL WALKER November 16, 2015 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7015 0640 0006 0779 5975 Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket No. OTH-15-029 Failure to Test BOPE After Use Nordic Rig 3 MPU I-03 (PTD 1900920) Dear Mr. Wilkins: Alaska Gil and Gas Conservation Commission 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Pursuant to 20 AAC 25.535, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby notifies Hilcorp Alaska, LLC (Hilcorp) of a proposed enforcement action. Nature of the Apparent Violation or Noncompliance (20 AAC 25.535(b)(1)). Hilcorp has violated the provisions of 20 AAC 25.285 ("Secondary well control for tubing workover operations: blowout prevention equipment requirements") while performing workover operations with Nordic Rig 3 at Milne Point Unit (MPU) well I-03. Basis for Finding the Violation or Noncompliance (20 AAC 25.535(b)(2)). Hilcorp conducted workover operations at MPU I-03 from April 30 through May 3, 2015 with Nordic Rig 3. Sundry approval 315-233 dated April 23, 2015 authorized Hilcorp to pull a failed electric submersible pump (ESP), isolate a casing leak with a straddle assembly, and rerun a new ESP completion. The Weekly Operations Summary reports that MPU I-03 began to flow after setting the straddle assembly. Hilcorp shut in the well with a floor safety valve in the tubing and unknown other blowout prevention equipment (BOPE) components and ordered kill weight fluid (insufficient volume available at the location to displace and kill the well). The first trip to surface after displacing and killing the well (static wellbore conditions) occurred on May 2, 2015. Hilcorp reentered the well to run the new ESP completion later that same day, and Docket No. OTH-15-029 • 0 Notice of Proposed Enforcement November 16, 2015 Page 2 of 3 completed installation on May 3, 2015. The production tree was installed and tested on MPU I- 03 after the BOPE was rigged down and Nordic 3 was demobilized, also on May 3, 2015. Workover regulations at 20 AAC 25.285 require an operator to report to AOGCC within 24 hours any instance of BOPE use to prevent the flow of fluids from a well — 20 AAC 25.285(f)(8). The BOPE components used must be function -pressure tested before the next wellbore entry, using a non -compressible fluid, to the required working pressure specified in an approved Application for Sundry Approval. Hilcorp failed to notify AOGCC of the use of BOPE and failed to test the BOPE components used during well control operations prior to reentering MPU I-03 to run the ESP completion. The MPU I-03 violation is neither isolated nor innocent and is emblematic of ongoing compliance problems with Hilcorp rig workover operations. Hilcorp's compliance history in conducting hydrocarbon development activities in Alaska includes ongoing failures to obtain necessary approvals; failures to install, maintain, and test required well control safety systems; failures to perform required tests; and use of equipment that is unsuitable for the operating environment. Recent examples of noncompliant activities include: 1) Rig Operations with Failed Gas Detection System — On September 4, 2015 AOGCC sent a notice of investigation to Hilcorp questioning the decision to pull the tubing hanger off its seat in MPU F-96. Activities leading up to this were marked by operational problems and system faults in the gas detection equipment, culminating in the system failing to operate properly during performance testing of the blowout prevention equipment on August 4, 2015. Hilcorp notified AOGCC and stated the rig — Hilcorp ASR1 — would not pull the completion until the gas system was operational". Less than one hour after providing that notice to AOGCC, Hilcorp made a unilateral decision to test if it was possible for ASR1 to pull the completion. Hilcorp's unapproved experiment successfully lifted the tubing hanger off seat and confirmed the rig's inability to pull the completion to surface in violation of AOGCC regulations (operating without approval; compromising a barrier that is in place to prevent the release of wellbore fluids from the well). 2) Hilcorp Rig Workovers Employing Nitrogen Well Cleanouts — A review of well workovers performed at MPU by Hilcorp-operated rigs reveal three wells that have performed fill cleanout operations using nitrogen without AOGCC approval. The disregard for regulatory compliance is endemic to Hilcorp's approach to its Alaska operations and virtually assured the occurrence of this violation. Hilcorp's conduct is inexcusable.) Proposed Action (20 AAC 25.535(b)(3)). For violating 20 AAC 25.285 the AOGCC intends to impose a civil penalty on Hilcorp under AS 31.05.150(a) in the amount of $20,000 for the initial violation of failing to notify AOGCC of the use of BOPE to prevent the flow of fluids from MPU I-03, and $20,000 for the initial violation of ' Other Order 80 Docket No. OTH-15-029 0 0 Notice of Proposed Enforcement November 16, 2015 Page 3 of 3 failing to test BOPE used to prevent the flow of fluids from MPU I-03. The history of compliance issues and the need to deter are additional factors in the AOGCC's analysis. 2 In addition to the imposed civil penalty, AOGCC intends to require Hilcorp to provide - a detailed description and example of its regulatory compliance tracking program; - written management of change procedures that correct the violations noted in this enforcement action; - a detailed written explanation that describes how Hilcorp intends to prevent recurrence of this violation. The total proposed civil penalty is $40,000. In imposing this this penalty, the AOGCC notes a prior civil penalty (Other Order 80) imposed upon Hilcorp for violations of essentially the same nature has had no significant impact on Hilcorp's conduct. Rights and Liabilities (20 AAC 25.535(b)(4)) Within 15 days after receipt of this notification — unless the AOGCC, in its discretion, grants an extension for good cause shown — Hilcorp may file with the AOGCC a written response that concurs in whole or in part with the proposed action described herein, requests informal review, or requests a hearing under 20 AAC 25.540. If a timely response is not filed, the proposed action will be deemed accepted by default. If informal review is requested, the AOGCC will provide Hilcorp an opportunity to submit documentary material and make a written or oral statement. If Hilcorp disagrees with the AOGCC's proposed decision or order after that review, it may file a written request for a hearing within 10 days after the proposed decision or order is issued. If such a request is not filed within that 10-day period, the proposed decision or order will become final on the 1 lth day after it was issued. If such a request is timely filed, the AOGCC will hold its decision in abeyance and schedule a hearing. If Hilcorp does not concur in the proposed action described herein, and the AOGCC finds that Hilcorp violated a provision of AS 31.05, 20 AAC 25, or an AOGCC order, permit or other approval, then the AOGCC may take any action authorized by the applicable law including ordering one or more of the following: (i) corrective action; (ii) suspension or revocation of a permit or other approval; and (iii) imposition of penalties under AS 31.05.150. In taking action after an informal review or hearing, the AOGCC is not limited to ordering the proposed action described herein, as long as Hilcorp received reasonable notice and opportunity to be heard with respect to the AOGCC's action. Any action described herein or taken after an informal review or hearing does not limit the action the AOGCC may take under AS 31.05.160. Sincerely, Cathy . Foerster Chair, Commissioner 2 AS 31.05.150(g) requires AOGCC to consider nine criteria in setting the amount of a civil penalty. uI .� e Domestic thailOnly N Er- For delivery visit our website at . ur ,.: `° 117 Certified Mail Fee r� $ r-3 Extra ServiCeS& Fees (check box, add fee as appropriate) ❑ Retum Receipt (hardcopy) $ ...11 ❑ Retum Receipt (elecdonic) $ Postmark r-3 ❑ Certified Mail Restricted Delivery $ Here I-3 ❑ Adult Signature Required $ C3 ❑ Adult Signature Restricted Delivery $ Postage C3 $ Total Pos to and Fees o Mr. David Wilkins $ g u7 sent To Senior Vice President r-q pHilcor Alaska, LLC p Sliest andAvt. No., or PC7 Box ------------ 3800 Centerpoint Dr., Ste. 1400 City State, ZIP+4a Anchorage, AK 99503 ■ Complete items 1, 2, and 3. A. ` ■ Print your name and address on the reverse rture ❑ Agent so that we can return the card to you. ❑ Addressee v ri d N C. Date of Delivery ■ Attach this card to the back of the mailpiece, or on the front if space permits. 0 011 fro item 1? El Yes �I Wad: I Eft t addres below: ❑ No Mr. David Wilkins Senior Vice President M DV 19 Z015 Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 OGGC Anchorage, AK 99503 3. Service Type ❑ Priority Mail Express@ El Adult Signature ❑ Registered MaiIT Il I I II I'll �I II ll I II I (l II I II I INI'I I I ❑ Adult Signature Restricted Delivery Certified Mail@ ❑ Registered Mail Restricted Delivery 9590 9401 0057 5071 0132 39 Certified Mail Restricted Delivery NI Return Receipt for ❑ Collect on Delivery Merchandise 2. Article Numher (Transfer from service lapel) ❑ Collect on Delivery Restricted Delivery d Mail El Signature Confirmation"' ❑ Signature Confirmation 7 015 0640 0006 0779 5975 d Mail Restricted Delivery Restricted Delivery WO) PS Form 3811, April 2015 PSN 7530-02-000-9053 Domestic Return Receipt • • Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Monday, November 16, 2015 2:53 PM To: David Wilkins Cc: Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Regg, James B (DOA) Subject: Notices of Proposed Enforcement OTH-15-029, OTH-15-030, OTH-15-031 Attachments: Hilcorp OTH-15-029 Failure to Test BOPE After Use (PTD 1900920).pdf; Hilcorp OTH-15-031 Failure to Notify of Changes to an Approved Permit (PTD 1991140).pdf; Hilcorp OTH-15-030 Failure to Notify of Changes to an Approved Permit (PTD 1991110).pdf Importance: High Dear Mr. Wilkins, Please see the attached regarding Docket Numbers: OTH-15-029, OTH-15-030, and OTH-15-031, Notices of Proposed Enforcement Action. Thank you, sam,antha Cartisle £xec'utive Secretary 11 Akiska. Oil ancQ7. as (A)nse-rvation Commission. 333 11Vest. ; -'Avenue _Anchorage, .✓'LK g95oi (907) 793-I223 (phone) (907) 276-7542 (f.-ax) 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 Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.gov. THE STATE °rAI.ASKA GC)VE,RN0R BILL NVALKhR Chris Kanyer Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU SB I-03 Sundry Number: 315-233 Dear Mr. Kanyer: Alaska Oil and Gas 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.aiaska.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, Cathy P Foerster Chair J- DATED this day of April, 2015 Encl. RECEIVED STATE OF ALASKA GA OIL AND ALA KA CONSERVATION COMMISSION S S APPLICATION FOR SUNDRY APPROVALS 20 AAC25.280 W �, MM 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well Q Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing Q - Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: ESP Changeout QQ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number, Hilcorp Alaska, LLC Exploratory ❑ Development n Stratigraphic ❑ Service ❑ 190-092 3. Address: 6. API Number. 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 50-029-22067-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477 Will planned perforations require a spacing exception? Yes ❑ No 2] MILNE PT UNIT SB I-03 ' 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0025906 I Milne Point Field / Schrader Bluff Oil Pool - 11 • PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (it): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 4,750 4,271 - 4,659 4,184 ' N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 105, 13-3/8" 105, 105, 1,730psi 740psi Surface 2,633' 9-5/8" 2,633' 2,399' 3,520psi 2,020psi Intermediate Production 4,741• 7" 4,741' 4,262' 7,240psi 5,410psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-7/8" 6.5# ! L-80 / EUE 8rd 4,054' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 7" HES 'VTA' Retrievable & 7" 'AWD' Sump Packer and N/A - 4,191(MD)/ 3,667(TVD) & 4,398(MD)/ 3,934(TVD) and N/A 12, Attachments: Description Summary of Proposal 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Q Exploratory ❑ Stratigraphic ❑ Development ❑J Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 4/30/2015 Oil Q 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 Chris Kan er Email ckan er hilcor .com Printed Name Chris Kanyer Title Operations Engineer 101/ Signature v Phone 777-8377 Date 4/20/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness ISundry Number: 3t5-233 Plug Integrity ❑ SOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: � SOQ �? �Sv JJ o io /e-xl'- % �� Spacing Exception Required? Yes ❑ No [0 Subsequent Form Required: J 0 APPROVED BY COMMISSIONER THE COMMISSION Date: ¢ G� Approved by: .S T-I'�0 '71 J-q rJ ~r L// Submit Form and Form 10-403 -",-ad 10/2012) j GpRv[�GAALrid for 12 months from the date of approval. (< Attachments in Duplicate IlileorP Alaska, Ld. Well Prognosis Well: MPI-03 Date: 4/20/2015 Well Name: MPI-03 API Number: 50-029-22067_-00-00 i _ Current Status: Sl Producer Pad: I Pad Estimated Start Date: April 30, 2015 Rig: Nordic 3 Reg. Approval Req'd? April 29, 2015 Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 190-092 First Call Engineer: Chris Kanyer (907) 777-8377 (0) (907) 250-0374 (M) Second Call Engineer: Bo York (907) 777_8345 (0) (907) 727-9247 (M) - - — . - AFE Number: _ _.... _...... -- - -- .-- 1550807 Current Bottom Hole Pressure: - 1,247 psi @ 4,000' TVD (Last BHP measured 3/16/2015) Maximum Expected BHP: - 1,247 psi @ 4,000' TVD (No new perfs being added) Max. Allowable Surface Pressure: 0 psi (Based on actual reservoir conditions and water cut of 8% (0.339psi/ft) with an added safety factor of 1000' TVD of oil cap) Brief Well Summary: The Milne Point 1-15 well was drilled as a Schrader Bluff development well that TD'd at 4,750' and ran and cemented 7" casing in November 1990. The well was initially completed with an ESP. This and subsequent ESPs failed and were replaced in 1995, 1997, 2002, 2003, 2006, 2009, and 2013. The most recent pump failed March 3, 2015. There most recent casing pressure test performed from 4 020' to 1 500psi indicated good casing to surface on 3/31/2015. The test at 4 054' indicated a casing leak. It is the intent of this workover to isolate this leak. No additional casing tests will be performed during this workover. There are minimal observed scale issues, most failures are related to solids production. Source of sand issues may be addressed with the isolation of the casing leak. A caliper was run on the upper 1,000' of 7" casing during the March 2015 RWO and found no issues. No subsidence issues expected. Notes Regarding Wellbore Condition Current well status is shut in oil producer. Possible subsidence issues suspected. Ica RWO Obiective: 51 rLa- Pull ESP, run casing caliper, perform cleanout, test casing, & run 2-7/8" ESP completion. Brief Procedure: 1. MIRU Nordic #3 Rig. 2. Attempt to circulate well with 8.5ppg seawater and monitor well. 3. ND tree, NU 11" BOPE and test to 250psi low/3,O�qpsi high, annular to 250psi low/2,500psi high. a. Notify AOGCC 24hrs in advance to witness test. 4. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) 0 Ililcarp Alaska, f,L • Well Prognosis Well: MPI-03 Date: 4/20/2015 a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. g. Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. h. If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion _ tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard procedure. 5. Unseat hanger and pull 2-7/8" kill string from 4,054' to surface and lay down same. 6. RIH with straddle assembly (3-1/2", seal assembly, tubing, & retrievable packer), locate into the upper gravel pack packer at 4,191', set upper retrievable straddle packer at +/-4,000'. POOH with setting tool. 7. MU and RIH with ESP with gas separator on 2-7/8" 8RD EUE L-80 tubing (to be replaced if necessary]. Set ESP at +/-3,980'. Land tubing hanger. 8. ND BOP, NU and tree. 9. RDMO workover rig and equipment. 10. Turn well over to production. Attachments: 1. As -built Schematic 2. Proposed Schematic 3. BOP Schematic llilcorp Alaska, LLC 13-3/8' 9 5/8 Orig. KB Elev.: 37 3 4 2,060' to 2,067 *Milne Point Unit Well: MP 1-03 SCHEMATIC Last Completed: 4/5/2013 PTD: 190-092 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8" Conductor 54.5 / K-55 / N/A 12.615 Surface 105, 9-5/8" Surface 36 / K-55 / Btrc. 8,921 Surface 2,633' 7" Production 26 / L-80 / Btrc 6.276 Surface 4,741' TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / Btrc 2.441 1 Surf---[- urf 4,054' JEWELRY DETAIL No Depth Item I 4,19V 7"HES "VTA" Retrievable Packer 2 4,234' 3.5" HES 250 Micron Poroplus Screens (4-Joints) - Bottom @ 4,359' 3 4,422' HES Collet Guide & Seal Assembly 4 4,398' 7" Otis "AWD" Sump Packer (4.0"ID) 5 4,415' 3.5" Otis X-Nipple (2.313" ID) 6 1 4,426' WLEG PERFORATION DETAIL Kuparuk Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status N Sands 4,260' 4,280' 3,802' 3,821' 20 2/23/1991 Open N Sands 4,292' 4,304' 3,832' 3,844' 12 2/23/1991 Open N Sands 4,322' 4,328' 3,861' 3,867' 6 2/23/1991 Open N Sands 4,344' 4,378' 3,882' 3,915' 34 2/23/1991 Open O Sands 4,424' 4,455' 3,959' 3,988' 31 2/23/1991 Open O Sands 4,486' 1 4,510 4,018' 4,041' 24 2/23/1991 O en 'N' Sands Perfs: 245PF & 24GM. 'O' Sands Perfs: SSPF & 37GM NOTE; Ong leak sorr wAwe betvoeen 4,020 to Ciavei Packer @4,191' N Sands j O Santis TD = 4,750 (MD) / TD = 4,271'M) PBTD = 4,659' (MD) / PBTD = 4,W(TVD) OPEN HOLE / CEMENT DETAIL 13-3/8" 485sx Permafrost "C' 9-5/8" 247sx of Class "E", 942 sx of Class "G" in a 12.25" Hole 7" 307sx of 15.8 ppg Class "G" a 8.5" Hole WELL INCLINATION DETAIL KOP @ 500' Max Hole Angle = 37 deg. @ 3,170' TREE & WELLHEAD Tree WKM 2-9/16"5M WKM 21" 5M w/ �"H�' Wellhead Connection 2-1/2" STIMULATION DETAIL Interval: 4,424' to 4,510" - 26,862 lbs. 16/20 mesh Propant GENERAL WELL INFO API: 50-029-22067-00-00 Drilled and Cased by Nabors 27-11/14/1990 ESP Completion-3/7/1991 ESP RWO by Nabors 4ES-10/5/1995 ESP RWO by Nabors 5S-12/14/1997 ESP RWO by Nabors 4ES - 7/30/2002 RWO & Replace Screens by Nabors 4ES - 5/6/2003 ESP/ HT Changeout by Nabors 4ES-10/7/2006 ESP RWO by Nabors 3S-5/2/2009 ESP Changeout by Doyon 16 - 4/5/2013 Created By: TDF 4/20/2015 • Ifilcorn Alaska, LLC Orig. KB Elev.: 37' TD = 4,750 (NU) / TD = 4,271'(TVD) PBTD = 4,65Y (MD) / PBTD = 4,184 MM) A *Milne Point Unit Well: MP 1-03 PROPOSED Last Completed: 4/5/2013 PTD: 190-092 CASING DETAIL Size Type Wt/ Grade/ Conn ID Tap Btm 13-3/8" Conductor 54.5 / K-55 / N/A 12,615 Surface 105' 9-5/8" Surface 36 / K-55 / Btrc. 8.921 Surface 2,633' 7" Production 26 / L-80 / Btrc 6.276 Surface 4,741' TUBING DETAIL 2 7/8 Tubing 6.5 / L-80 / Btrc 1 2.441 1 Surf ± 3,980' JEWELRY DETAIL No Depth Item 1 t135' GLM 2 ±3,756' GLM 3 ±3,898' XN-Nipple (2,25" No-go ID) 4 ±3,940' Pump 5 t3,956' Gas Separator 6 13,961' Tandem Seal Section 7 t3,975' Motor 8 ±3,978' Centralizer w/ Phoenix Sensor- Bottom @v 9 ±4,000` Packer _^ 10 ±4,000' Top of 2-7/8" Blank Pipe 11 4,19V 7"HES "VTA" Retrievable Packer 12 4,234' 3.5" HES 250 Micron Poroplus Screens (4-Joints) - Bottom @ 4,359' 13 4,422' HES Collet Guide & Seal Assembly 14 4,398' 7" Otis "AWD" Sump Packer (4.0"ID) 15 4,415' 3.5" Otis X-Nipple (2.313" ID) 16 4,426' WLEG PERFORATION DETAIL Kuparuk Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status N Sands 4,260' 4,280 3,802' 3,82V 20 2/23/1991 Open N Sands 4,292' Q304' 3,832' 3,844' 12 2/23/1991 Open N Sands 4,322' 4,328' 3,86V 3,867' 6 2/23/1991 Open N Sands 4,344' 4,378' 3,882' 3,915' 34 2/23/1991 Open 0 Sands 4,424' 4,455' 3,959' 3,988' 31 2/23/1991 1 Open 0 Sands 4,486' 4,510 1 4,018' 4,041' 24 1 2/23/1991 1 Open 'N' Sands Perfs: 24SPF & 24GM. 'O' Sands Perfs: 55PF & 37GM OPEN HOLE / CEMENT DETAIL 13-3/8" 4855x Permafrost "C" 9-5/8" 247sx of Class "E", 942 sx of Class "G" in a 12,25" Hole 7" 307sx of 15.8 ppg Class "G" a 8.5" Hole WELL INCLINATION DETAIL KOP @ 500' Max Hole Angle = 37 deg. @ 3,170' TREE & WELLHEAD Tree WKM 2-9/16"5M _ W KM 11" 5M w/ 2-7/8" 8rd Tree Top Wellhead Connection 2-1/2" "H" Profile STIMULATION DETAIL Interval: 4,424' to 4,510" - 26,802 Ibs.16/20 mesh Propant GENERAL WELL INFO API: 50-029-22067-00-00 Drilied and Cased by Nabors 27 - 11/14/1990 ESP Completion-3/7/1991 ESP RWO by Nabors 4ES-10/5/1995 ESP RWO by Nabors SS-12/14/1997 ESP RWO by Nabors 4ES - 7/30/2002 RWO & Replace Screens bV Nabors 4ES - 5/6/2003 ESP/ HT Changeout by Nabors 4ES-10/7/2006 ESP RWO by Nabors 35 - 5/2/2009 ESP Changeout by Doyon 16 - 4/5/2013 Created By: TDF 4/20/2015 11" BOP Stack ams je port
